Biogas Upgrading Solutions

Transcription

1 Biogas Upgrading Solutions Small Scale Integrated Biogas to CNG Systems Xebec Adsorption Inc. 730 Boul. Industriel, Blainville, Québec Canada J7C 3V4 Sans Frais/Toll Free Tel Xebec Adsorption (USA) Inc Katy Freeway, Suite 320, Houston, TX US Toll Free Tel Fax

2 1. Introduction Diminishing fossil fuel reserves, concerns over energy security, and elevated greenhouse gas (GHG) emissions due to fossil fuel combustion have led to a move toward more sustainable, clean, and affordable energy resources. Biofuels are considered green fuels, with a near zero net carbon dioxide emission (Figure 1). Biogas is a type of biofuel. It typically refers to a mixture of different gases produced in anaerobic digesters by the breakdown of organic matter in the absence of oxygen. Biogas can be produced from raw materials such as agricultural waste, manure, municipal waste, plant material, sewage, green waste or food waste. Anaerobic Digesters In projecting the biogas yield from a particular feedstock or substrate, components of interest are: organic content (fat, protein, and carbohydrates), inorganic content (minerals or ash), and water. Figure 1. Greenhouse gas emission rates by different types of fuel (German Energy Agency). 2

3 A sample of feedstock is weighed before and after drying to determine volatile solid (VS), total solid (TS) and water content. Only biologically degradable organics can be converted into biogas, so VS content is a key measure of the maximum biogas-generation potential of a substrate. (Figure 2). The end-products are a gas containing mainly methane (CH4) and carbon dioxide (CO2), referred to as biogas. The substrate, the production technology, and the collection of the gas all affect its composition. Landfill gas is produced during anaerobic digestion of organic materials in landfills and is very similar to biogas. Its methane content is generally lower than that of biogas, and usually contains nitrogen (N2) and oxygen (O2) from air that seeps into the landfill gas during recovery. Landfill gas, in contrast to farm biogas, can contain a great number of trace gases. Depending on the source and type of digestion, biogas or landfill gas streams could contain impurities such as hydrogen sulfide (H2S), volatile organic compounds (VOCs), ammonia, & siloxanes. Biomethane or renewable natural gas (RNG), also known simply as methane, is a purified form of biogas that meets pipeline natural gas quality specifications. It can be distributed and sold by injection into existing gas utility pipelines (Figure 3). RNG is a renewable fuel that provides significant GHG reduction benefits through the displacement of a carbon-positive fuel, such as natural gas. Capturing biogas from organic wastes reduces GHG emissions by preventing methane from directly entering the atmosphere. The carbon dioxide that is generated during the production and combustion of RNG is used in the regeneration of new biomass, representing a closed-loop cycle. Figure 2. Biogas yields from different wastes (Data from CROPGEN). Courtesy of Canadian Biogas Association. 3

4 For these reasons, RNG is considered to be a carbon-neutral fuel and energy source since no net GHGs are released into the atmosphere through either the combustion or the lifecycle emissions of RNG. How the process works Wastewater Treatment Plant Organic Waste Methane can also be used as a carbon-neutral compressed natural gas (CNG) or compressed biomethane (CBM) fuel for vehicles including farm vehicles, refuse trucks, heavy duty transportation trucks, transit buses and passenger cars. Landfill RAW BIOGAS Gas Conditioning Xebec s BGX product series provides a reliable solution for biogas purification to pure methane. Each biogas upgrading plant designed by Xebec includes a pre-treatment unit followed by a CO2/N2/O2 removal step which is performed by either a kinetic pressure swing adsorption (kpsa) machine or a two-stage membrane system. Xebec s integrated biogas plants provide customers with a fully packaged solution including all the equipment necessary to upgrade biogas to purified methane for a sustainable future. Membrane Upgrading Plant PSA Upgrading Plant BIOMETHANE Heating & Electricity CHP Natural Gas Grid LNG CNG Renewable Hydrogen Figure 3. Biomethane production from biogas source to end-use applications. N2/O2/CO2 Removal Pre-treatment Figure 4. Xebec biogas upgrading plant. 4

5 BG SOLUTIONS 2. Biogas Upgrading at Xebec 3. Gas Pre-Treatment Raw biogas must be upgraded and pressurized before injection into the natural gas grid or for use in CNG vehicles. Biogas upgrading mainly consists of two steps: a pre-treatment step and a CO 2 /N 2 /O2 removal step (Figure 4). In the pre-treatment step, which is also called conditioning or cleaning, water, H2S, and other contaminants (ammonia, VOCs, siloxanes, etc.) are removed. In the second step, depending on the source of the biogas, Xebec uses two methods to remove CO2 and other gases such as O2 and N2: A) Kinetic Pressure Swing Adsorption (kpsa): This method is suitable for upgrading biogas streams produced from landfills. CH4 and CO2 are the primary components of landfill gas; however, high levels of N2 and O2 could be present in this type of gas. kpsa is a proven technology to remove N2/O2/CO2 in a single step process. A detailed description of this technology is explained in section 4.1. B) Hollow fiber membrane technology: For biogas feed streams which are obtained from bio-digesters or sewage, a membrane technology is a proven method to remove CO2 from methane. With this type of gas, N2 and O2 are not present or are at very low levels ([N2+O2] <1.5%), so N2/O2 separation is not required. The details of membrane technology are further explained in section 4.2. Based on the nature of the biogas and customer requirements, either technology can be used. In the following sections, the characteristics of each technology will be explained. Further on, their features are compared Collected biogas must be treated to remove impurities before it enters the CO 2 /N2/O2 removal process. Impurities include corrosive hydrogen compounds, ammonia, low concentrations (parts per million) of VOCs, siloxanes, and water. Landfill gas may contain more than 500 different contaminants such as halogenated hydrocarbons, higher hydrocarbons and aromatic compounds. 3.1 Sulfur Gases Biogas produced from bio-digesters and landfills can contain a variety of sulfur compounds. The major contaminant in biogas is H2S which is both poisonous and corrosive, and causes significant damage to piping, equipment and instrumentation.h2s is always present in biogas, although concentrations vary with the feedstock. The concentration of H2S in the gas is a function of the digester feed substrate and inorganic sulphate content. Wastes which are high in proteins containing sulfur-based amino acids can significantly influence biogas hydrogen sulphide levels. Moreover, H2S is malodorous and toxic, even at very low levels. It is extremely reactive with most metals and the reactivity is enhanced by concentration and pressure, the presence of water and elevated temperatures. When the biogas stream contains H2S levels of more than 50 kg/day, desulphurization of biogas should be performed by micro-organisms. This process is called biological H2S removal and it uses a type of bacteria to oxidize the hydrogen sulfide. These bacteria grow very fast and are known to be highly resistant to varying process conditions. In Xebec s process, H2S is absorbed and oxidized into elemental sulfur at a highly efficient removal rate with low operational cost. The exit stream of biological H2S typically contains between 50 to 200 PPMV of H2S. 5

6 For pipeline natural gas end-use, however, the level of H 2 S must be further reduced to less than 5 PPMV (or 0.3 g/100 SCF). In that case, an additional adsorption bed is installed after biological H 2 S removal. Depending on country regulations, product contaminant limits may vary. 3.2 Siloxanes Siloxanes are volatile compounds bonded by organic radicals. They occur in landfill gas and gas from digestion of sewage sludge. They originate from different kinds of consumer products (e.g. shampoos, detergents and cosmetics). Siloxanes are converted during combustion into inorganic siliceous deposits in downstream applications. The amount of silica has to be reduced to a minimum, especially in engine applications. Siliceous deposits on valves, cylinder walls and liners are the cause of extensive damage by erosion or blockage. Silicones may also reach the lubrication oil, requiring more frequent oil changes. Because of the increased use of silicone-containing products, more frequent siloxane monitoring in the fuel gas is required. Siloxanes are removed through a highly efficient adsorption bed before entering the kpsa or membranes. 3.3 Ammonia Another unwanted constituent of biogas is ammonia, which in turn is converted to nitrogen oxide (NOx) in boilers and combined heat and power (CHP) units. The amount of ammonia in the biogas will depend on the amount of nitrogen in the feed, the ph, and the temperature of the digester. The combustion of ammonia leads to the formation of NOx which can react to form other oxides of nitrogen in the atmosphere. Ammonia is removed in Xebec s adsorption beds before the CO 2 /N 2 /O 2 removal step. 3.4 VOCs Biogas produced by fermentation of organic sources contains VOCs, either from by-products of the fermentation or by the sources directly. The presence of these VOCs can produce a significant odour which can mask the effects of required odorants, thereby causing safety issues. VOCs are organic compounds containing one or more carbon atoms that have high vapour pressures that evaporate readily into the atmosphere. There are thousands of compounds that meet this definition, but most programs focus on the 50 to 150 most abundant compounds containing two to twelve carbon atoms. The common examples of VOCs are BTX (benzene, toluene xylene), dichloromethane, and trichloroethylene. The emissions of VOCs have primary as well as secondary harmful impacts. VOCs are a significant contributing factor in the creation of air pollution in urban areas. These emissions contribute to the formation of ground-level ozone and fine particulate matter which forms smog. The adsorption of gaseous VOCs onto porous adsorbents has been suggested as an innovative treatment process in environmental applications. In general, methods (especially condensation) other than adsorption are effective when VOC concentrations are at relatively high levels (>1%). In contrast, adsorption has been found to be most effective for low concentration levels (i.e. parts per million (ppm)). Xebec s solution removes VOCs in the feed biogas through both condensation and adsorption. 3.5 Dust and Particles All biogas plants must be equipped with some kind of filter or cyclone for particulate reduction in the gas. Filters not only remove particulates but also reduce the content of droplets of water or oil. Filters with a 2-5 micron mesh size are normally regarded as appropriate for most downstream applications. 6

7 4. CO 2 /N 2 /O2 Removal The energy content of the biogas has to be elevated for the gas to be usable as vehicle fuel. This is accomplished by removal of CO 2 /N 2 /O 2. For landfill gas streams, Xebec offers its kpsa technology in order to remove N 2, /O 2 / CO 2 in a single step. On the other hand, for biogas streams (e.g. biogas from digesters) where N 2 and O 2 are not present, membranes are a suitable technology to remove CO Kinetic PSA (kpsa) Xebec offers a unique proprietary technology for biogas upgrading plants. kpsa is a simple and cost-effective method where raw biogas is pressurized ( psig / 5-10 barg), and then fed into an adsorption bed filled with adsorbents like carbon molecular sieves (CMS). Xebec s BGX solution works under the principle of adsorption equilibrium and kinetic theory. Xebec s kinetic adsorbent is highly selective to landfill gas components such as CO 2, N 2, and O 2, while allowing methane molecules to pass through the adsorbent bed. CO 2, N 2, and O 2 molecules easily diffuse inside the adsorbent pores when the bed pressurizes (adsorption). Methane molecules, which are larger in comparison, cannot diffuse inside. The result is a purified methane stream in the product (Figure 5). Upon depressurization (desorption), these impurities are released under vacuum conditions and exit through the exhaust port. Xebec s kpsa machine consists of nine identical beds (Figures 5 & 6), filled with proprietary adsorbents and connected together via a single rotary valve. Biogas feed enters the bottom of each bed. As CO 2, N 2, O 2, H 2 O, and other trace contaminants stick to the adsorbents, the product stream leaves from the top of the bed. When the bed reaches the saturation point, the rotating valve opens and connects two beds together. Gas molecules Greengas / Biomethane Absorber Carbon molecular sieve Biogas Off gas Figure 5. Nine-bed kpsa and the adsorption process in each bed. 7

8 Figure 6. Examples of Xebec s nine-bed kpsa The first bed depressurizes and lets the desorbed methane move to the next bed. This is called equalization as it pressurizes that bed. Three equalization steps help to increase the methane recovery and save energy for the pressurization step (reducing compressor duty). The last step in the kpsa process is blow-down where the exhaust stream, which is rich in contaminants and contains small amounts of CH 4, leaves the bottom of the bed. In order to increase the overall recovery, the first exhaust stream, which leaves the vessel at ambient pressure, recycles back to the plant inlet to be mixed with the feed gas. The flow rate of the recycled stream is less than 15% of the feed flow so it does not increase the load of the feed compressor too much. However, it does increase overall methane recovery by 6-8%. After this step, an exhaust vacuum blower helps to desorb contaminants from the adsorbent and finishes the regeneration step. At the end of the regeneration step, the valve rotates to pressurize the bed (taking advantage of the first equalization steps to pressurize the vessel). This is followed by advance feeding the bed to start another gas separation cycle. Advanced feeding saves significant compressor load. All the steps occur via the single proprietary rotary valve. The valve rotation speed controls product purity. The methane recovery in the product stream is a function of the inlet N 2 concentration. Adding a second kpsa in series with the first one (called two-stage kpsa) boosts the total recovery. Xebec s two-stage kpsa system is beneficial when treating high N 2 content biogas streams, particularly when elevated methane recoveries are desired. Apart from the inherent characteristics of conventional PSAs which use no process water or chemicals for gas purification and generate no wastewater in the exhaust stream, Xebec s advanced kpsa system has numerous advantages over its competitors: Xebec s kpsa proprietary rotary valve technology makes it possible to use nine adsorption beds simultaneously. This results in a significant increase in production rate and overall recovery. The plant foot-print is minimized which allows for a fully skid-mounted plant. When the feed composition or flow rate varies within an established gas purification plant, Xebec s kpsa machine is totally flexible, allowing customers to maintain the same product purity by controlling the rotary valve speed. 8

9 In addition to removing CO 2 from biogas feed, Xebec s kpsa system is capable of removing up to 95% of N 2 and O 2 from the feed, especially beneficial when treating landfill biogas (due to the air suction, the landfill biogas feed contains up to 30% of N 2 and O 2 ). Xebec s kpsa is advantageous over other biogas treatment technologies since purification methods such as an amine system, chemical scrubbing, or membrane technology are not able to remove N 2 /O 2. Since at least two of the nine kpsa beds are in a continuous production step, product stream pressure does not show significant fluctuations. This eliminates the need for adding a surge tank in the product stream and makes the system more economical. When treating a biogas stream with typical contaminant levels, Xebec s kpsa is able, in a single pre-treatment step, to simultaneously remove water vapour, N 2, O 2, CO 2, NH 3, siloxanes, VOCs, and the remains of H 2 S. kpsa operates at ambient temperatures of 40 to 104 F / 5 to 40 C, and the operational pressure range is between 70 to 150 psig / 5-10 barg. kpsa single rotary valves have been tested to ensure their durability in conditions similar to those encountered in real operating projects. All durability tests have been successfully conducted between 2003 and Currently Xebec has more than 200 PSA projects operating worldwide, utilizing its proprietary rotary valve, and there have been no reported technical issues or breakages. 4.2 Hollow Fiber Membranes Xebec s membrane solution is another proven technology for biogas purification. When CO 2 is the only contaminant to be removed (after the pre-treatment step) and the product stream must be delivered at higher pressures (typically higher than 250 psig / 17 barg), Xebec offers high-performance, hollow fiber polymer membranes for biogas upgrading (Figure 7). The principle of membrane separation is based on the difference between the permeation rates of various gas molecules through the membrane microscopic pores. The gas molecule sizes do not dictate the rate of separation; rather, it is the difference in gas molecule diffusivities onto the membrane surface. When pressurized biogas feed enters the membrane modules, CO 2 has a much stronger preference to diffuse and permeate through the polymer-based membrane than CH 4 molecules (Figure 8). As a result, a product stream which is rich in CH 4 is retained in the pressurized side and can be directly sent to the natural gas grid. The driving force for separation is the partial gas pressure difference between permeate and retentate. Based on the desired degree of product purity and methane recovery, Xebec employs a two-stage or three-stage membrane system for biogas upgrading. These advanced membrane separation techniques are superior to market competitors in several ways: The high methane recovery rate (up to 99.5%) generates very small amounts of CH 4 (between 0.2-1%) in the exhaust stream. 9

10 The flexible membrane technology has the ability to produce product gas streams with different methane contents. Figure 7. Xebec membrane system for biogas upgrading. Apart from the high purity product gas, a portion of the recycle stream, which contains about 40% CH 4, can be withdrawn and used as a heating and electricity resource within the plant. Following the upgrading process with membranes, the biomethane is already dry and satisfies the dew-point requirement for feeding into the grid. The flow rate of the recycle stream from the multi-stage membrane system is about 30-60% less than that of other available membrane systems. This leads to enormous energy savings in the compressor section of the unit. CO 2 /O 2 /H 2 O/H 2 S Biomethane (CH 4 ) up to 99% The membrane technology is easily scalable; it can be used for small plants (10 NCMH) as well as larger ones (several hundred to several thousand NCMH). Biogas Direct feeding (via a transmission pipeline) into the natural gas grid is possible without an additional compressor. Figure 8. Hollow fiber membrane element. 10

11 5. Advanced Process and Control Design The Xebec biogas upgrading plant is entirely automated by a programmable logic controller (PLC). The end user can operate and monitor the complete system with a simple-touse operator interface (HMI), equipped with a touch screen. The operator interface has many functions such as starting and stopping the plant, and monitoring operation properties. Different instruments within the plant are used to measure the feed and product flow rates, pressure, and temperature in the plant entrance and end-product. Xebec uses different types of component analyzers to continuously measure and monitor the amount of H 2 S, CH 4, N 2, O 2, and CO 2 in the feed and the final product stream. Therefore, any small changes in the plant can be easily and immediately identified and appropriate measures can be put into place to turn the system back to normal. The plant s operational sequences are also controlled by the PLC, so there is no need for manual intervention by the operator at any time. The operator simply selects the desired mode, such as starting the plant, from the operator interface and it will automatically reach Normal Operating Mode within twenty minutes. The control system can also include an advanced performance and data analyzing tool accessible remotely via Xebec s cloud server through a computer or smart device, such as a tablet or smart phone. 6. Exhaust Gas Treatment Step (Methane slip) The exhaust gas leaving the PSA/membrane during the biogas upgrading mainly consists of biogas impurities (i.e., CO 2, N 2, and O 2 ), and also some amounts of unrecovered methane. Depending on the biogas upgrading method (PSA or membrane), methane in the exhaust stream (methane slip) can range from 0.1 to 25% (vol). Due to the low heating value of the methane slip, it cannot be fed into the natural gas grid or be used as CNG. Moreover, due to the strong greenhouse effect of methane, which has 25 times higher global warming potential than CO 2, methane slip should be treated before being emitted into the atmosphere. In some European countries the amount of methane emissions from biogas plants is regulated by law (Table 1). An effective integration of the exhaust treatment unit into the biogas plant is an essential step to protect the environment and extract the maximum amount of energy from the biogas. Certain biogas purification systems (i.e. three stage membrane configuration) have very high methane yield resulting in very low methane content in the exhaust gas which can be directly released into the atmosphere without any further treatment. Country Maximum methane content in the exhaust stream (% vol) Germany 0.2 Italy France UK No obligation No obligation No obligation Sweden Austria No obligation Table 1. Maximum methane content in the exhaust stream in selected European countries (2015) Methane slip is usually flared when an alternate combustion technology is not available. However, trapped methane in the exhaust stream could be a source of energy for gas engines, combined heat and power (CHP) generation engines, and micro-turbines. High-efficiency electricity production enables the end user to optimize the economic performance of the anaerobic digestion plant. The electricity can be used to power the surrounding equipment or be exported to the electrical grid. CHP systems are designed to generate electricity and produce heat as a byproduct. Digesters like to operate at constant temperature and, whether the system is mesophilic or thermophilic, it is good practice to ensure that the digester temperature does not change by more than 33 F (1 C) per day. Anaerobic digesters in combination with a CHP system can produce a continuous heat source to warm the digesters in winter, and the gas produced by the digester is a free source of fuel for the CHP system. In order to achieve high biogas production rates, the digester must be kept at a constant temperature, usually between 86 and 104⁰F (30 to 40⁰C). Figure 9: Biogas upgrading unit. 11

12 A heating method (direct heating, floor heating, in-vessel, on-vessel, or ex-vessel heat exchanger) is used to transfer the captured heat from the CHP system to the digester. The methane concentration in the exhaust stream is controlled by adjusting the PSA valve speed, or the membrane permeate stream. In winter when the bio-digester requires more heat, the exhaust stream in the PSA must be richer in methane compared to the summer. During summer there is no need to use the exhaust gas for heating the digester, so the heat is used for making hot water in buildings, or other heating applications. The PSA or membrane exhaust stream seldom contains enough methane for stable combustion and often requires the addition of raw biogas or natural gas to be able to be used in gas and CHP engines. The treatment of exhaust streams with low methane content (less than 4% (vol)) is extremely difficult. During combustion there is not enough energy delivered for the maintenance of the oxidation reaction. Therefore, the addition of raw biogas or biomethane for stabilizing combustion is required. As a result, various methods (e.g., catalytic systems and cyclic heat storage systems) have been developed to maintain an auto-thermal operation without further addition of higher caloric supporting gas even at lower methane contents. Xebec uses different methods to utilize methane in the exhaust stream and increase the overall recovery. The methods of practical relevance are explained in the following paragraphs. air biogas compressor exhaust gas heatextraction CHPgas engine G generator 6.1 Gas Engines The combustion of methane rich gases in internal combustion engines is a common way of using the energy content of biogas. Electrical power can be generated with efficiencies ranging from 35% to 40%. By using the waste heat in the exhaust gas of the gas engine, the overall efficiency can be as high as 88%. The ignition of a gas, and thus its usefulness in a gas engine, depends crucially on the methane content of the gas. The combustion reaction of methane is less efficient when the energy content of the gas decreases while the carbon dioxide levels increase. Under ideal conditions, the absolute minimum methane content that can be burned in a gas engine in a continuous and stable operation is around 21% (vol). But in real gas engines a stable combustion requires at least 35% (vol) of methane. Methane slip with low methane concentrations (5-20% (vol)) should be upgraded to 35% (vol) methane before it can be sent to a gas engine. Figure 10: Schematic of a gas engine for the combined generation of electricity and heat and a picture of a gas engine. 6.2 Micro-Turbines Micro-turbines are a simple form of gas turbine, usually featuring a radial compressor and turbine rotors, often using just one stage of each. They typically recover exhaust energy to preheat compressed inlet air, thereby increasing electrical efficiency compared to a simple-cycle machine. The air-toair heat exchanger is termed a recuperator, and the entire system is typically called a recuperated cycle. Micro gas turbines are characterized by their simple engineering as well as their attractive power range (30 to 4000 kwel) for biogas plants. Due to the low inlet temperature of the turbine (about 1472 F or 800 C), cooled turbine blades can be avoided. Efficiency is increased through recuperative pre-heating of the compressed air prior to entry into the combustion chamber with the exiting exhaust heat. The exhaust gas is thereby cooled from 1112 to 572 F (600 to 300 C). 12

13 The combustion chamber pressure is at 44 to 58 psig (3 to 4 bar), and the turbine rotates at speeds of 30,000 to 100,000 rpm. With such a system, electrical efficiencies of 30 to 35% can be achieved. With the use of a waste heat utilization system, efficiencies of 85% can be achieved. Commercially available micro gas turbines require minimum methane contents of 35% (vol) to ensure stable operation, approximately the same range as gas engines. Compared to gas engines, gas turbines are more expensive in the initial investment; however, they have significantly low operating costs. air biogas exhaust gas heatextraction CHPgas turbine G generator 6.3 Flameless Oxidizers A flameless oxidizer is a special lean gas burner which can be operated with low methane content. A complete oxidation of the gas, unaffected by issues like flame stability, is a major benefit of the flameless oxidation technology. The methane slip and air are preheated in ceramic recuperators, which are integrated in the burners, before entering the combustion chamber. The required minimum methane content in the combustion air is 6% (vol). If the exhaust stream carries lower than 6% methane content, a higher caloric gas (raw biogas or biomethane) must be added to maintain the ignitability. A second possibility is that the treatment plant is intentionally designed and operated at a higher methane slip. The operating temperature of 1652 F (900 C) is significantly higher than the other methods. The method is based on the recirculation of large quantities of hot exhaust gases into the reaction zone and intense air preheating respectively. The exhaust gas of the burner has a temperature of 1112 to 1292 F (600 to 700 C), making the method suitable for the provision of process heat (for example to heat the digester) or external heat utilization (space heating). Flameless oxidizers, which are commercially available as a complete system, could be the most economical option when treating PSA/membrane exhaust gas. Figure 11: Schematic of a gas turbine for the combined production of electricity and heat; picture of a micro-turbine system and sectional drawing of a micro-gas turbine. Figure 12: Functional diagram of a flameless oxidizer and view of a burner head. 13

14 6.4 Regenerative Thermal Oxidizer (RTO) Regenerative thermal oxidation is another suitable treatment method for methane slip with low methane concentrations. The operation temperature inside the RTO system is 1472 F (800 C). To guarantee complete oxidation, an oxygen concentration of minimum 10% (vol) should be maintained. To decrease the heat losses, heat is stored in ceramic materials and the flow direction is alternated continuously (Figure 13). 6.5 Catalytic Oxidation Catalytic oxidation is another methane slip treatment method using catalysts. Because impurities such as H 2 S act as a catalytic poison, there are increased limitations on the gas composition compared with other treatment technologies. Common catalyst materials used in this method are platinum and palladium, but cobalt may be used as well. Autothermal operation is possible with methane concentrations as low as 0.4% (vol). However, the startup phase needs heating with higher calorific gases or electricity. Due to the reduced activation energy, the operation temperature inside the reactor is only 752 F (400 C). Minimum oxygen concentration of 2% should be maintained to ensure continuous operations. Figure 14: Illustration of a catalytic oxidation unit. Figure 13: Illustration of a two-chamber regenerative thermal oxidation unit and a picture of a RTO system in a biogas plant. This process works with a number of very well isolated heat storages (usually 2 to 3) which can absorb the heat of oxidation in the methane combustion. With this heat the lean gas of the biogas upgrading plant can be heated up to the reaction temperature necessary, followed by the exothermic reaction. The heat released is, in turn, stored in the heat storage. A sufficiently high temperature level for the oxidation reaction can be obtained in the entire plant by cyclic switching of the lean gas stream between the tempered heat storages. In contrast to the catalytic oxidation, the process is insensitive to H 2 S. 6.6 CO2 Upgrading The exhaust gas (flue) exiting the PSA, membrane, or gas engines could be treated to recover CO 2. Carbon capture and storage (CCS) is one of the most prominent technologies to decrease CO 2 emission to the atmosphere. Pure CO 2 has many applications in food, beverage and different chemical industries such as urea and fertilizer production, foam blowing, carbonation of beverages and dry ice production. Xebec offers its Temperature Swing Adsorption (TSA) technology for CO 2 recovery from the flue gas. The TSA process is based on adsorption at operating conditions and regeneration at an elevated temperature. The adsorption capacity of an adsorbent decreases at higher temperature, so CO 2 separation is possible by alternating between low and high temperature with molecular sieves. Figure 15: CO2 purification by TSA and photo of a Xebec Gas Dryer 14

15 6.7 Xebec Experiences Xebec has experience in performing methane slip treatment in the following projects: 1. SKS, Steinfeld, Austria Biogas source: Manure Digester Feed flow rate: 100 SCFM Methane slip treatment method: Micro-turbine Build date: Why Choose Xebec? Xebec continuously improves its biogas upgrading solutions, allowing for a competitive package on performance, CAPEX and OPEX. In countries where power consumption is a point of concern, kpsas are a lower cost option because the energy consumption of the compressor is lower than that of membrane systems. Since the membrane system works at a higher pressure (around 300 psig / 20 barg), it consumes more energy than a kpsa, which operates around 120 psig / 8 barg. On the other hand, membrane systems offer a higher recovery rate than the kpsa so the two systems need to be compared in regards to performance and cost before making an appropriate technology decision. Figure 16: Plant in Austria is using a micro-turbine to treat the exhaust gas leaving the PSA, providing electricity and heat for digester and building. The micro-turbine operating in SKS requires the gas quality to be above 33-34% CH 4. The set point used at the plant is 36-37% (vol) methane. The micro-turbine is more efficient in cooler temperatures. When cooling air is around 32 F (0 C), the turbine can produce 65 kw. If the ambient temperature is too hot, then the turbine production decreases to 45kW. The micro-turbine is 30% efficient and requires 6 hours per year of maintenance, and does not require any oil changes (air bearing). The turbine is not sensitive to H 2 S levels. During start-up, feed gas to the turbine is by-passed and re-circulated to the inlet of the plant via a by-pass valve until the CH 4 level has reached its set point. 2. Agribiomethane, Nantes, France Biogas source: Manure Digester Feed flow rate: 200 SCFM Methane slip treatment method: Flameless-oxidizer Build date: 2014 Whether a customer chooses a kpsa or a membrane system, Xebec offers numerous advantages over competing upgrading vendors. To name a few: Extensive experience with biogas pre-treatment: Xebec is able to remove a majority of contaminants such as H 2 S, water, VOCs, siloxanes, ammonia, etc. Quick start/stop: Starting and stopping of the plant is possible at short intervals, ensuring high flexibility; ideally suited for operation of a methane filling station on site. Easy monitoring and control: Xebec offers remote monitoring (via internet/satellite). Proven performance and reliability: 96% unit availability Low consumable consumption: No additional ancillary materials such as water or sorbents (amines, glycols) are required, eliminating environmental emissions. Extensive experience with gas upgrading plants: Xebec has built 250 kpsa units and 25 biogas upgrading plants worldwide including all types of biogas, landfill gas, food digester gas, organic farm waste gas, palm oil mill effluent (POME) gas, mixed waste gas, wastewater treatment plant gas. Full aftermarket support: Xebec s dedicated After-market Department offers service and parts support in all its operating markets. Figure 17: Verdemobil Agribiomethane biogas upgrading plant in Nantes, France. Competitive price: Xebec offers nine (9) standard systems at different flow rates, and four (4) standard micro-bgx systems for small scale upgrading applications. 15

16 7.1 Xebec Standard Biogas Upgrading Systems Xebec offers six standard plant sizes for its BGX solutions (Table 2). The plant sizes are only a function of feed flow rate. The feed composition has standard biogas concentrations (57% CH 4, 38% CO 2, and 5% water) which are obtained from a bio-digester. 7.2 Xebec Small Scale Integrated Biogas to CNG Solutions Farm Fuel The biogas stream which comes from animal manure could be the ultimate win-win energy source, allowing farmers to produce their own energy while reducing water contamination, odor pollution, and global warming emissions caused by animal waste. Table 3 shows the biogas production rate in four types of farm (beef, hog, dairy, and poultry farms). Table 2. Xebec standard sized biogas upgrading plants. Product name Wet biogas (NCMH) Wet biogas 1 (SCFM) Power usage (kw) CNG production Litre Gasoline Equivalent per year(lge/yr) CNG production Gallon Gasoline Equivalent per year(gge/yr) BGX ,400, ,000 BGX ,000, ,000 BGX ,500, ,000 BGX ,100, ,000 BGX ,000,000 1,050,000 BGX ,600,000 1,500,000 1For biogas composition of: 57% CH 4, 38% CO 2, and 5% water. Table 3. Potential biogas production in average sized farms. Farm Type Number of Animals Potential Biogas from Manure (m3/ton(manure) Biogas Production NCMH (GGE/yr) (DGE/yr) Cow (Beef farm) Hog Cow (Dairy Farm) Poultry

17 Typical energy usage for biogas produced on farms is electricity, boiler fuel, space and water heating. However, a stream of raw biogas could be withdrawn from the bio-digester and purified into biomethane, compressed to CNG at 3,600 psig, stored and dispensed. This renewable compressed natural gas could then be used by the farmers as vehicle or tractor fuel, or could be sold at stationary fuel systems located on those farms (Figure 18 & 19). guarantees from agricultural producers and rural small businesses that want to purchase renewable energy systems and/or improve their energy efficiency. Eligible systems include anaerobic digesters that use animal waste and other substrates to produce thermal or electrical energy. LARGE FARMS AD SMALLER FARMS AD Since methane is one of the most potent GHGs (21 times as powerful as carbon dioxide in trapping heat), farmers in some countries who use a bio-digestion system are paid by a carbon offset company. Carbon offset companies sell carbon credits to interested parties, and use the proceeds to pay others to reduce their global warming pollution. UPGRADE OR BIOMETHANE UPGRADE In the United States, farmers and utilities are showing increasing interest in selling carbon credits and meeting renewable portfolio standards which have now been adopted by more than 30 states. A renewable portfolio standard is a government mandate, usually at the state level, for electricity supply companies to produce a specified fraction of their electricity from renewable energy sources. Certified renewable energy generators earn certificates (known as renewable energy credits) for every unit of electricity they produce. They can sell these, along with their electricity, to supply companies. Moreover, the USDA Rural Business-Cooperative Service (RBS) accepts applications for grants and loan PIPELINE Compress REFUELING STATION Compress OR OR STORAGE TANKS REFUELING STATION CNG VEHICLE CNG VEHICLE Figure 18. CNG production from farms to CNG vehicles. Courtesy of Canadian Biogas Association. Figure 19. BGX-40 Biogas upgrading unit with a CNG fueling and payment option in France. 17

18 Xebec offers upgrading technology for small biogas streams (5-60 NCMH) and converts them into high quality compressed biomethane. The systems produce fuel with a methane concentration of +95% (by volume), which is suitable for use on-site or sale. Table 4 shows Xebec s standard small-scale plant sizes for biogas upgrading to CBM, designed especially for operators of farm-based digesters. A small containerized farm biogas-cng plant consists of the following processing components: Biogas pre-treatment (H 2 S and H2O removal) CO2 separation Product gas compression up to 3600 psig /248 barg (CNG) CNG storage different sizes depending on fueling needs CNG dispensing (slow, fast or combination fill, depending on fueling needs) Figure 20. Containerized Micro-BGX. Figure 21. BGX-20 small scale containerized biogas to CBM upgrading unit in Austria. 18

19 Table 4. Xebec small scale integrated biogas to CBM systems. Product name Wet biogas (NCMH) Wet biogas 1 (SCFM) CNG production Litres of gasoline equivalent per year GLE/yr 80,000 CNG production Gallons of gasoline equivalent per year GGE/yr BGX ,550 BGX ,000 41,000 BGX ,000 82,000 BGX , ,000 1For biogas composition of: 57% CH 4, 38% CO 2, and 5% water Fueling Stations Unlike gasoline or diesel stations, CNG stations are not one size fits all. Building a CNG station for a retail application or a fleet requires calculating the right combination of pressure and storage needed for the types of vehicles being fueled. Making the right choices about the size of compressor and the amount of storage at the station will make a big difference in the cost of fuel and range for vehicles. There are three options for refueling (Figure 22): Figure 22. CNG dispensers: from left to right: fast fill, slow fill (2), and combination fill. 19

20 Slow or time-fill: Return-to-base fleet vehicles most commonly use slow fill CNG refueling stations. At these refueling stations, all vehicles are plugged in at filling posts and refuelled simultaneously overnight. Time fill stations send the CNG directly into your vehicle and use the vehicle tank for storage. The complete refueling process takes approximately eight hours. There are several advantages of slow fill. The primary advantage is lower capital expenditure by using a smaller compressor and little or no storage. There can also be benefits from off-peak electricity for compression if time-of-use rates are available. In addition, the heat of compression dissipates over time, making it easier to achieve a true full fill. Fast fill: Fast fill refueling is best suited for relatively small volumes (less than 13 gals or 50 litres at a time), and in cases where fueling is intermittent and a fast turn-around time is desired (e.g., six minutes or less). A retail facility that services vehicles that arrive throughout the day might consider fast-fill capacity. Combination fill: Combination fast and slow fill systems are typically employed by facilities that can take advantage of the benefits that slow fill fueling provides, but that also provide fueling services to external fleets, or to vehicles of their own that may routinely require quick fueling. Partnering with other organizations that operate fleets to share fueling infrastructure can be highly beneficial for fast fill facilities as it allows the infrastructure to be used regularly High Pressure Gas Storage One of the key components in a fast-fill Natural Gas Vehicle (NGV) Refueling Station is the CNG storage. In fact, the inclusion of American Society of Mechanical Engineers (ASME)-coded ground storage vessels really defines a fast-fill refueling application. How much storage you need depends on the amount of vehicles, the amount of gas each vehicle requires, and the time frame in which the vehicles need to be filled. Fast-Fill stations allow vehicles to pull up and refuel in a short period of time. In order to fuel vehicles quickly, gas must be drawn from pre-pressurized storage vessels. Unlike gasoline stations, natural gas must be stored above ground. And because it is stored at high pressures it must be contained in ASME-coded vessels. They are arranged in cascading banks, meaning that there is a low bank vessel, a medium bank vessel and a high bank vessel (Figure 23). Figure 23. CNG storage for small scale applications As a general rule of thumb, only 40% of the stored gas in a three bank cascade arrangement is available for refueling. This means that a 30,000 cubic foot storage cascade will deliver about 12,000 cubic feet of natural gas quickly. This equates to about 96 equivalent gallons of gasoline. A priority sequential panel is used to direct compressor discharge to the high, then medium, then low bank. When filling, a vehicle will draw first from the low bank, then the medium bank and top off from the high bank. The compressor will replenish the cascade by filling the high bank first, then the medium bank and finally the low bank High Pressure Gas Compression The main component of a CNG fuelling station is the compressor. Dynamic characteristics, thermodynamic performance, operation availability, and reliability have significant influence on CNG station operation. 20

21 8. Case Studies Xebec has more than 25 references for its biogas upgrading plants: Figure 24. High pressure compressors: adjusted for suction pressure and flow sizes for small scale applications. 1. Golden Green, Anshan, China Biogas source: Landfill Feed flow rate: 820 SCFM PSA bed Size: 36 x 150 Build date: 2015 In order to maximize the vehicle tank capacity (and resultant driving range), a multiple-stage compressor is required to compress low-pressure RNG from the available biogas upgrading pressure (45 to 290 psig / 3-20 barg) to high pressure (approximately 3600 / 248 barg). In addition, due to the low gravity and flammable properties of RNG, the compressor requires a very high sealing efficiency. In such applications, the reciprocating piston type compressor is the most suitable type of compressor for CNG stations. After compression of RNG it becomes CBM which has less than 1 percent of the volume it occupies at standard atmospheric pressure. It can then be stored and distributed in storage cascades at pressures between 2900 and 3600 psig / barg, usually in cylindrical or spherical shapes. CBM s volumetric energy density is estimated to be 42 percent of liquefied natural gas (because it is not liquefied), and 25 percent of diesel fuel. Compressed biomethane (CBM) can be used in place of gasoline (petrol), diesel fuel and propane/lpg. As stated previously, CBM combustion produces significantly fewer undesirable gases than fossil fuels. It is safer than other fuels in the event of a spill, because natural gas is lighter than air and disperses quickly when released. CBM can be used in traditional gasoline/internal combustion engine automobiles that have been modified or in vehicles which were manufactured for CNG use, either alone ( dedicated ), with a segregated gasoline system to extend range (dual fuel) or in conjunction with another fuel such as diesel (bi-fuel). Figure 25. Golden Green landfill gas upgrading plant in Anshan, China. 2. Waste Management, Ohio, United States Biogas source: Landfill Gas Feed flow rate: 3,000 SCFM Build date: 2014 Figure 26. Waste Management upgrading plant in Waynesburg, Ohio, United States. 21

22 3. Agribiomethane, Nantes, France Biogas source: Manure Digester Feed flow rate: 200 SCFM Build date: Potlatch in Daegu City, South Korea Biogas source: Digester Feed flow rate: 870 SCFM PSA bed Size: 32 x 90 Build date: 2013 Figure 27. Agribiomethane biogas upgrading plant in Nantes, France. Figure 29. Potlatch biogas upgrading plant. 4. Fortis in British Columbia, Canada Biogas source: Landfill Feed flow rate: 180 SCFM PSA bed size: 28 x 150 Build date: Verdemobil, Trifyl, France Biogas source: Landfill Feed flow rate: 250 SCFM Build date: 2011 Figure 28. Fortis landfill gas upgrading plant in British Columbia, Canada. Figure 30. Small scale biogas upgrading with onsite H2 generation in Trifyl, France. 22

23 7. Halla Environmental, Seoul, South Korea Biogas source: Food waste digester Feed flow rate: 410 SCFM PSA bed Size: 12 x 90 Build date: 2011 Figure 31. Halla Environmental biogas upgrading plant. 8. Swiss Farm Collective, Inwil, Switzerland Biogas source: Farm waste digester/ Food waste Feed flow rate: 225 SCFM PSA bed Size: 12 x 90 Build date: 2008 Figure 32. Swiss Farm Collective biogas upgrading plant. 9.Rumpke Landfill, Ohio, USA Biogas source: Landfill Feed flow rate: 6,500 SCFM PSA bed size: 42 x 120 Build date: 2006 Figure 33. Rumpke landfill gas upgrading plant. 23

24 9. Process Block Diagram Product (biomethane) Biogas Biological H2S Removal Compression Seperator H2S Removal (pre-treatment) Seperator PSA Machine Recycle Vacuum pump Cooling & drying Exhaust Figure 34. Simplified process flow diagram for a PSA system. Biogas Biological H2S Removal Compression Seperator H2S Removal (pre-treatment) Seperator Membrane 1 Membrane 2 Product (biomethane) Cooling & drying Exhaust Recycle Figure 35. Simplified process flow diagram for a two-stage membrane system. 24

25 ANNEX 1: VOLUME AND ENERGY CONVERSION TABLE Convert from Convert to Multiplied by cubic foot cubic meter cubic meter cubic foot gigajoule cubic meter 26.8 million cubic feet 1,000 cubic meters ,000 cubic meters million cubic feet BTUs Joule Joule BTUs million BTUs gigajoule gigajoule million BTUs

26 ANNEX 2: FUEL ENERGY EQUIVALENTS Fuel type Equals to 1 NCM bomethane (97% methane) 9.67 kwh 1 NCM natural gas 11.0 kwh 1 litre petrole 9.06 kwh 1 kg methane 1.39 litres diesel 1 litre diesel 9.8 kwh 1 litre E kwh 1 NCM biomethane 1.1 litres petrol 1 NCM natural gas 1.2 litres petrol 1 litre CNG (95% methane at 250 barg) litres diesel 1 litre CNG (95% methane at 250 barg) litres gasoline 26

27 ANNEX 3: PROPERTIES OF LANDFILL GAS, BIOGAS AND NATURAL GAS. Properties Unit Landfill gas Biogas from AD Natural gas MJ/NCM Calorific value, lower kwh/ncm MJ/kg Density kg/ncm Wobbe index, upper MJ/NCM methane number >130 > Methane vol% Methane, range vol% Long-chain hydrocarbons vol% Hydrogen vol% Carbon monoxide vol% Carbon dioxide vol% Carbon dioxide, range vol% Nitrogen vol% Nitrogen, range vol% 2-40 Oxygen vol% Oxygen, range vol% 0-5 Hydrogen sulfide PPM <100 <500 3 Hydrogen sulphide, range PPM Ammonia PPM Total chlorines as Cl mg/n

28 For more information please contact: Xebec Adsorption Inc. 730 boul. Industriel Blainville, Quebec J7C 3V4, Canada Toll-Free GOXEBEC ( ) Phone Fax Bireme Group Pte Ltd No.63 Ubi Ave 1 # @UBI Singapore Phone: sales@biremegroup.com 28