March 23, 2010 | General

Biogas Conditioning And Upgrading In Action

BioCycle March 2010, Vol. 51, No. 3, p. 53
Case studies highlight the range of systems used in the U.S. and Canada to remove impurities in biogas prior to conversion into electricity, pipeline gas or vehicle fuel. Part II
Diane Greer

LAST month’s article on biogas conditioning and upgrading discussed how biogas quality and energy content specifications vary by application and looked at a range of biogas treatment technologies. This month, we interviewed biogas producers and industry experts to get their insights on the design, integration and application of these treatment technologies in the field.
Biogas is most commonly used in boilers or electrical generators to produce heat and power. For these applications, the main biogas constituents of concern are moisture, hydrogen sulfide (H2S) and siloxanes. “All biogas projects have pressure and humidity issues because biogas is saturated with water,” says Paul Greene, vice president of O’Brien & Gere.
Typically moisture is removed from biogas using refrigeration. Heat exchangers chill the gas causing the moisture to condense. Further drying can be achieved by pressurizing the biogas. The dried gas is then reheated with the waste heat from the heat exchanger.
The level of H2S in biogas is dependent on sulfur levels in the feedstock. Acceptable levels of H2S in biogas vary by the type of equipment and its manufacturer. Boilers typically require H2S concentrations under 1,000 parts per million (ppm). Specifications for reciprocating engines vary between 200 to 1,000 ppm. Some microturbines specifically designed for biogas applications can tolerate H2S up to 5,000 ppm.
For boiler applications that require H2S removal, the two main strategies are iron sponge and carbon, says Greene. Both run the biogas through a vessel containing a fixed bed of iron oxide or activated carbon coated with alkaline or oxide solids. The media reduces the H2S to elemental sulfur. “It is cheap and it’s easy,” he notes.
Scenic View Dairy in Fennville, Michigan initially used natural bacteria to reduce H2S levels in its biogas but later switched to an iron sponge. The dairy processes manure from 2,200 cows in two 870,000-gallon complete mix anaerobic digesters. Biogas produced by the digesters fuels two 350-kW Caterpillar reciprocating engines that generate power for the dairy. Excess electricity is sold to Consumers Electric Company. (As described later, Scienic View also upgrades biogas to biomethane.).
Injecting air into the headspace of the digesters caused bacteria that convert H2S into elemental sulfur to grow on exposed walls and roof beams in the digester. “This approach was guaranteed by the original biogas plant provider (Biogas-Nord),” explains Norma McDonald, North American sales manager for Belgium-based Organic Waste Systems, who at the time worked for Phase 3 Renewables. “While the approach was successful in reducing the parts per million of H2S somewhat, it was not sufficient for a typical dairy biogas where initial levels can be 1,500 to 3,600 ppm. Precipitated sulfur accumulated on roof structures inside the tank, and then dropped back into the slurry and increased the inherent H2S potential of the digesting material to more than 4,000 ppm.”
When Phase 3 started working with Scenic View, it removed the air injection system and installed Sulfatreat, a proprietary iron oxide scavenger system, to remove H2S. The new system kept the level of H2S below 500 ppm for the electric generators, McDonald says.

Tollenaar Dairy in Elk Grove, California installed complete mix digesters to process manure from its dairy cows. The biogas fuels two 212-kW generators producing electricity. The dairy needed to lower the sulfur content in its biogas to meet local air quality regulations and to make the generators last longer, explains Jon Tollenaar, the dairy’s owner. It installed Energy Cube’s Bioscrub system to remove H2S from the biogas. The installation passed compliance testing for the Sacramento Metropolitan Air Quality Management District in August 2009 with a posttreatment fuel analysis of 210 ppm H2S.
Bioscrub uses oxygenated effluent to remove H2S. The system is composed of two chambers. In the first chamber, ambient air is mixed with and dissolved into effluent from the digester, explains Jere Martin of Energy Cube LLC. The oxygenated effluent is then transferred to a second chamber. When biogas is pumped through the oxygenated effluent, the H2S in the gas reacts with the dissolved oxygen in the effluent and oxidizes to elemental sulfur. The sulfur-laden effluent is then drained to the lagoon, adding fertilizer value.
Sunnyside Farms in Scipio Center, New York has a modified plug flow digester to process manure from 2,600 cows. The biogas supplies a 500 kW Guascor engine with future potential of an additional 500 kW. Sunnyside Farms installed a BioScrub 300 H2S removal system in September 2009. Pretreated biogas H2S levels are around 3,000 ppm; posttreatment H2S levels are less than 300 ppm, says Martin. Because the scrubber utilizes digester effluent, the only cost to operate the Energy Cube is electricity.)


The City of Cambridge, Ontario will be installing an H2S removal system at its Preston wastewater treatment plant (WWTP) in order to evaluate the best available options for utilizing the biogas from its anaerobic digester. The biogas currently is flared. The city plans on using biotrickling filter technology provided by Biorem, Inc. for the demonstration. The system is under design with an early spring delivery anticipated. “The biogas stream has an inlet H2S concentration of 4,000 ppm which will be reduced to below 50 ppm in a single stage reactor,” says Derek Webb of Biorem, Inc. The Preston facility processes 10,000 m3/day of wastewater.
The biotrickling filter uses a proprietary organic synthetic media designed for high level H2S removal. Microbes on the surface of the packing media consume the H2S, breaking it down into elemental sulfur and sulfuric acid (SO4). Water cycles over the media, removing the elemental sulfur and SO4. “Most of the water is recycled back through the filter,” adds Webb. “A small amount gets discharged to a drain or to the head of a WWTP. The biological approach is reliable and has low operating costs.”
Biogas produced by breweries, food processing and municipal wastewater digesters may contain high sulfur levels. At City Brewing Company in La Crosse, Wisconsin, H2S levels in biogas produced by digesting wastewater from its beverage packaging operations ranged from 2,600 ppm to almost 19,000 ppm. The high sulfur levels are attributed to chemical reactions between the ingredients from various beverage products reacting in the digester and chemicals used to adjust product pH and clean the equipment.
The biogas from City Brewing is used by Gundersen Lutheran Health Systems in La Crosse to drive a 633-kW Jenbacher generator. (See “Brewery Digesters As Power Source For Healthcare Network,” December 2009 for project profile.) Gundersen evaluated several treatment techniques for removing H2S before deciding on SulfrStrip, developed by Applied Filter Technology (AFT).
SulfrStrip employs a wet scrubbing process with a liquid catalyst to remove H2S. The first stage in the process dissolves H2S into solution to create hydrosulfide ions. The second stage oxidizes the hydrosulfide ion into elemental sulfur, which precipitates in solution. The catalyst can be regenerated with small amounts of hydrogen peroxide or enriched oxygen.

Biogas from wastewater treatment plants contains siloxanes, chemical compounds found in personal care products, pharmaceuticals, foods and lubricants. Combusting biogas with siloxanes can result in fouling and abrasions in boiler, engines and turbines. As described in Part I, siloxanes in biogas produced by digesters at the Madison (WI) Metropolitan Sewerage District (MMSD) plant caused major damage to cylinder and crank shaft areas in one of the plant’s Waukesha internal combustion engines.
To prevent further problems, Unison Solutions and AFT put together a biogas treatment system for MMSD. The system first removes the H2S using AFT’s proprietary iron oxide media (Sulfpack). The gas is then chilled and compressed to eliminate moisture. In the final step siloxanes are removed using SAGMedia, which employs a combination of carbon- and silicon-based molecular sieves to remove VOCs (volatile organic compounds) and siloxanes. Biogas is passed through a vessel with a fixed bed of the media. When it becomes saturated, it can be replaced or regenerated.
Applications that regenerate media are generally not used in this market due to higher capital costs and the parasitic electrical load to operate the system, says Jan Scott, president of Unison Solutions. “Where you see regenerable systems is typically in landfills with huge gas volumes.”


Scenic View Dairy expanded its anaerobic digestion capacity by adding a third 870,000 gallon digester to process additional manure from 1,450 heifers and 9,200 hogs. It installed a system to upgrade excess biogas to biomethane for injections into Michigan Gas Utilities’ (MGU) pipeline. The system allows Scenic View to optimize revenues from excess biogas by either producing electricity for sale to the grid or biomethane for sale to MGU, depending on the rates paid by the respective utilities.
Specifications for pipeline quality gas are quite stringent and vary by utility. MGU requires CO2 levels of two percent or less by volume, 5.72 ppm or less of H2S and total sulfur of less than 114.4 ppm. Oxygen must be reduced to one percent or less by volume and nitrogen to eight percent or less. The gas must also be free of water, dust and other impurities.
The biogas conditioning system only operates when it is economical to use excess biogas to produce biomethane for pipeline injection. “They wanted a system that would be reliable in spite of being turned on and off frequently,” McDonald explains. The system also needed to handle variable gas flows and to be energy efficient and robust enough to operate at 30 percent capacity. It normally operates at less than 4 ppm H2S and less than 75 ppm total sulfur, she adds.
Scenic View installed two small pressure swing adsorption (PSA) units manufactured by Quest Air (now Xebec Adsorption, Inc.) to provide more flexibility for handling the variable gas flows. The two-train system first compresses the biogas and feeds it into the bottom of the two PSA units; each unit contains nine beds consisting of adsorbent materials. As the biogas flows upward under pressure in one of beds within a PSA unit, CO2 and water vapor are adsorbed. Impurities are separated from the methane, and bio-methane is produced at the top of the bed.
When the adsorbent materials of the production bed approach near saturation with impurities, the pressure is then released to remove them, which allows the bed to regenerate and become ready for the next production cycle. Scenic View retained the Sulfatreat system to remove H2S, but instead of reducing H2S levels to below 500 ppm, the system now reduces H2S to below 75 ppm to meet the more stringent requirements for pipeline injection.

At Vintage Dairy in Riverdale, California, Bioenergy Solutions is conditioning and upgrading biogas produced by the dairy’s covered lagoon digesters for injection into Pacific Gas & Electric’s (PG&E) natural gas pipeline. The facility produces about 250,000-cf of biogas a day (91,250 MMBtus/year).
PG&E’s gas quality specifications restrict H2S content to no more than 4 ppm, water vapor to 7 lbs/million-cubic-square-feet at 800 psig or less, and no more than one percent CO2 by volume. There are also tight limits on oxygen and other types of sulfur and the gas must be free of particulate matter.
Vintage installed a Natco desulfurization mini-Paques bioreactor to remove H2S. The Paques system employs naturally occurring thiobacillus bacteria to biologically convert H2S into elemental sulfur, which settles without the use of chemicals.
“We went with that technology because of scale,” explains David Albers of Bioenergy Solutions. “Our business model is to have a centralized biogas upgrade plant and pipe gas from a number of dairies.” The first project will take biogas from nine neighboring dairies. “Analysis showed that we are better off spending the money on capital expenditures for the equipment and decreasing our operational costs,” he adds.
Industry experts say biological systems can be more sensitive to operating parameters, such as heat and temperature and swings in H2S levels, since they use live organisms. Albers agrees but has had a good experience with his system. “It takes an operator to know how to care for it,” Albers says. “I analogize it to feeding cows versus feeding calves. With feeding cows it is all about volume, speed and just getting the mix right. With feeding calves you got to love on them to help them grow. This is the same. You got to love on the thing a little bit.”
The biogas is upgraded and scrubbed to remove the remaining contaminants by a Guild PSA system. To date, the system is working well with very few issues. “They have a lot of moving parts with all those valves and we wonder if over time there will be any issues,” he notes. “But we have seen a lot of systems in operation for a long time, so our comfort level continues to grow.”


Hilarides Dairy in Lindsay, California was producing more biogas from its lagoons than required to meet the electrical demands of the dairy. Any biogas not utilized to drive six 125 kW Caterpillar G342 reciprocating engines was flared. Installing additional generators to use excess biogas to produce power for sale to the grid or upgrading the biogas for pipeline injection was not economically viable. Instead Hilarides decided to produce compressed biomethane (CBM) for vehicle fuel (see “Biomethane Fuels Dairy Fleet,” June 2009). The CBM could be used by the dairy’s fleet of trucks that haul its products to market.
Like pipeline injection, upgrading biogas to CBM requires removing H2S and other impurities, but there is more latitude in CO2, oxygen and nitrogen levels. Although specifications vary by engine supplier, the most prevalent specification is for a minimum of 90 percent methane, McDonald explains.
The dairy installed a biogas conditioning and upgrading system that uses an iron oxide scavenger system to remove H2S. Carbon dioxide and water vapor are removed by a QuestAir (now Xebec) M-3200 PSA unit. Exhaust gas from the PSA system is not flared, but instead remixed with biogas from the lagoons and used to generate electricity.
“We went with a single PSA because the intent of the system was to run it at full capacity for as many hours per day as needed for vehicle consumption,” says McDonald. “The technology allows for fluctuations in the incoming gas quality and that allows us to fully leverage the flexibility in the truck engine specification.”
The ability to modify the methane content is important since the quantity and methane content of biogas produced by the lagoons vary. Hilarides prefers to produce biomethane with 97 percent methane to increase vehicle mileage. (CO2 is inert and does not contain any energy value.) CBM at 970 BTU/cubic-foot is the equivalent of 112 to 115 gallons of diesel fuel equivalent in the dairy’s heavy-duty trucks, adds McDonald. During periods when the methane content in the biogas is low, the dairy has the flexibility to produce CBM at the minimum 90 percent methane specification. Mileage then drops to the diesel fuel equivalent of 100 gallons.


In Lille, France, a wastewater treatment plant is using water scrubbing in conjunction with pressure and temperature swing adsorption units (PSA/TSA) for digester biogas conditioning to produce 4 million cubic meters of biomethane to fuel 180 buses. The system, produced by New Zealand and Swedish-based Greenlane, a subsidiary of the Flotech Group, feeds pressurized biogas into the bottom of a vessel in a counter-flow to pressurized water sprayed into the top. Biomethane exiting the top of the tank goes through a PSA/TSA unit for drying and to remove impurities that made it through the water scrubbing process, explains Sean Mezei, North American president of Flotech Services.
CO2 and contaminant-rich water is recycled by sending it to a second vessel where it is regenerated with air. “At low pressure we inject air in order to remove contaminants,” he adds. “The effluent can be filtered to get rid of the sulfur.” The company claims methane yields of 99 percent and the reduction of H2S down to 0.1-ppm.
Greenlane’s technology is also used to upgrade biogas to biomethane for pipeline injection. The world’s largest biogas upgrading plant in Güstrow, Germany is using five Greenlane CSFR 2000 units with a capacity of 10,000-cubic meters of gas per hour. The first system in Canada will be installed by Catalyst Power at a dairy in Abbotsford, British Columbia. The system will condition and upgrade biogas – produced by digesting cow and poultry manure – into pipeline quality biomethane.

Diane Greer is a Contributing Editor to BioCycle.

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