REMOVAL OF HYDROGEN SULFIDE FROM BIOGAS
USING COW-MANURE COMPOST
A Thesis
Presented to the Faculty of the Graduate School
of Cornell University
in Partial Fulfillment of the Requirements for the Degree of
Master of Science
by
Steven McKinsey Zicari
January 2003
2003 Steven McKinsey Zicari
ABSTRACT
The two-part objective of this study was to determine currently available H2S
removal technologies suitable for use with farm biogas systems, and to test the
feasibility of utilizing on-farm cow-manure compost as an H2S adsorption medium.
Integrated farm energy systems utilize anaerobic digesters to provide a waste
treatment solution, improved nutrient recovery, and energy generation potential in the
form of biogas, which consists mostly of methane and carbon dioxide, with smaller
amounts of water vapor, and trace amounts of H2S and other impurities. Hydrogen
sulfide usually must be removed before the gas can be used for generation of
electricity or heat. Biogas has remained a virtually untapped resource in the United
States due to many factors, including relatively high gas processing costs.
There are many chemical, physical, and biological methods currently available
for removal of H2S from an energy gas stream. Dry based chemical processes have
traditionally been used for biogas applications and remain competitive based on
capital and media costs. Iron Sponge, Media-G2, and potassium-hydroxide-
impregnated activated-carbon systems are the most attractive, with estimated capital
costs of $10,000-$50,000 and media costs of $0.35-$3.00/kg H2S removed. These
processes are simple and effective, but also incur relatively high labor costs for
materials handling and disposal. Other significant drawbacks include a continually
produced solid waste stream and growing environmental concern over appropriate
disposal methods. Additions of air (2-6%) to the digester headspace, or iron
compounds introduced directly in the digester, show promise as partial H2S abatement
methods, but have limited and inconsistent operational histories. Liquid based and
membrane processes require significantly higher capital, energy and media costs, and
do not appear economically competitive for selective H2S removal from biogas at this
time. Commercial biological processes for H2S removal are available (Biopuric and
Thiopaq) that boast reduced operating, chemical, and energy costs, but require higher
capital costs than dry based processes.
Initial testing of cow-manure compost indicates that it has potential as an
effective and economic matrix for H2S removal. Polyvinyl-chloride (PVC) test
columns were constructed and a 2:1 biogas-to-air mixture passed through the columns
containing anaerobically digested cow-manure compost. The most significant trials
ran for 1057 hours with an empty-bed gas residence time near 100 seconds and inlet
H2S concentrations averaging 1500 ppm, as measured by an electrochemical sensor
with 40:1 sample dilution.
Removal efficiencies over 80% were observed for a majority of the run time.
Elimination capacities recorded were between 16 118 g H2S/m3 bed/hr. This is
significant considering only minimal moisture, and no temperature or pH controls
were implemented. Temperature in the bed varied from 19-43C and the moisture contents in the spent column ranged from 41-70%, with pH values from 4.6 to 6.9. It
is not clear whether the major mechanism for sulfur removal from the gas stream was
biological, chemical or physical, but it is known that the sulfur content in the packing
increased by over 1400%, verifying sequestration of sulfur in the compost.
These initial results indicate that future work is warranted for examining the
suitability of cow-manure compost as a biofiltration medium for use with biogas.
BIOGRAPHICAL SKETCH
Steven McKinsey Zicari was born in Rochester, New York, to Richard E. and
D. June Zicari. He grew up with his older brother, Zev, and attended West
Irondequoit public schools through the 12th grade. Steven enrolled at Cornell
University in the fall of 1995, and focused his studies on biological engineering. He
graduated with a Bachelor of Science degree in Agricultural and Biological
Engineering in May, 1999, Cum Laude. As an undergraduate, he also participated in
the alpine ski team, symphonic band, and the engineering co-op program. His co-op
experiences were with Genencor International in Rochester, NY, and Nestle R&D in
New Milford, CT.
After working briefly for the New York State Department of Agriculture and
Markets as a farm products inspector, and also as a ski instructor in Vail, Colorado,
Steven decided to return to Cornell for graduate school in the Fall of 2000. He has
held teaching and research assistant positions in the Department of Biological and
Environmental Engineering and his current research interests include sustainable
development, alternative and renewable energy systems, and biological processes.
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To my family
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ACKNOWLEDGMENTS
I would like to thank my major advisor, Dr. Norman Scott, for his guidance,
creativity, and tireless effort in researching sustainable development. I have learned a
great deal by working closely with him. I am also grateful to my minor advisor, Dr.
A. Brad Anton, for his helpful insights, positive encouragement, and superb technical
competence. I also extend thanks to committee member Dr. Anthony Hay for his
continual enthusiasm, willingness to help, and for sharing his exceptional
understanding of biological systems.
I acknowledge the Biological and Environmental Engineering department,
especially Dr. Dan Aneshansley and Dr. Michael Walter, for supporting me with
teaching opportunities and sound advice during my studies here. Also the knowledge
and cooperation of Dr. Larry Walker, Doug Caveny and Peter Wright are greatly
valued. Additionally, I greatly appreciate the cooperation of Robert, Wayne, and
Aaron Aman for allowing me to perform tests at AA Dairy.
Special thanks are also given to fellow graduate student John Poe Tyler. His
expert mechanical and engineering skills, as well as determination, were invaluable. I
also thank Tina Jeoh for her constant motivation, encouragement and assistance.
The support of my fellow research-group members, officemates and fellow
graduate students are also greatly appreciated, especially Kristy Graf, Jianguo Ma,
Stefan Minott, Scott Pryor, and Kelly Saikkonen.
Lastly, I would like to thank all of my family and friends for their support,
without which, this would not have been possible.
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TABLE OF CONTENTS BIOGRAPHICAL SKETCH.........................................................................................iii ACKNOWLEDGMENTS..............................................................................................v 1. INTRODUCTION......................................................................................................1 2. BACKGROUND........................................................................................................3
2.1. INTEGRATED FARM ENERGY SYSTEMS .......................................3 2.1.1. AA Dairy ..........................................................................................4
2.2. ANAEROBIC DIGESTION ...................................................................6 2.3. BIOGAS COMPOSITION......................................................................9 2.4. QUALITY REQUIREMENTS FOR BIOGAS UTILIZATION ..........10 2.5. TRADITIONAL H2S GAS-PHASE REMOVAL METHODS ............12
2.5.1. Dry H2S Removal Processes ..........................................................13 2.5.1.1. Iron Oxides ..............................................................................14 2.5.1.2. Zinc Oxides .............................................................................22 2.5.1.3. Alkaline Solids ........................................................................24 2.5.1.4. Adsorbents...............................................................................24
2.5.2. Liquid H2S Removal Processes ......................................................30 2.5.2.1. Liquid-Phase Oxidation Processes ..........................................31 2.5.2.2. Alkaline Salt Solutions ............................................................35 2.5.2.3. Amine Solutions ......................................................................36
2.5.3. Physical Solvents............................................................................38 2.5.3.1. Water Washing ........................................................................39 2.5.3.2. Other Physical Solvents...........................................................39
2.5.4. Membrane Processes ......................................................................40 2.6. ALTERNATIVE H2S CONTROL METHODS....................................41
2.6.1. In-Situ (Digester) Sulfide Abatement.............................................41 2.6.2. Dietary Adjustment ........................................................................42 2.6.3. Aeration ..........................................................................................43
2.7. BIOLOGICAL H2S REMOVAL METHODS ......................................43 2.7.1. History and Development...............................................................43 2.7.2. Biological Sulfur Cycles.................................................................45 2.7.3. Example Applications ....................................................................50
2.8. RESEARCH STATEMENT .................................................................54 3. MATERIALS AND METHODS .............................................................................55
3.1. REACTORS ..........................................................................................55 3.1.1. Small Reactors................................................................................55 3.1.2. Large Reactors................................................................................58
3.2. EXPERIMENTAL SETUP ON SITE ...................................................60 3.3. GAS SAMPLING AND MEASUREMENT.........................................64
3.3.1. Electrochemical Sensor ..................................................................64 3.3.2. Gas Sampling Tubes.......................................................................66
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3.3.3. Gas Chromatography......................................................................67 3.4. TEMPERATURE MEASUREMENT...................................................67 3.5. PRESSURE MEASUREMENT............................................................68 3.6. COMPOST CHARACTERIZATION...................................................68
3.6.1. Moisture Content ............................................................................68 3.6.2. Void Fraction:.................................................................................69 3.6.3. Bulk Density...................................................................................69 3.6.4. Particle Size Distribution................................................................69 3.6.5. pH ...................................................................................................70 3.6.6. Trace Element Analysis..................................................................70 3.6.7. Sulfate Content ...............................................................................70
3.7. OPERATIONAL PROCEDURES ........................................................70 4. RESULTS AND DISCUSSION...............................................................................72
4.1. ORIGINAL COMPOST CHARACTERISTICS ..................................72 4.2. OPERATIONAL SUMMARY .............................................................74 4.3. PRESSURE MEASUREMENTS..........................................................75 4.4. TEMPERATURE MEASUREMENTS ................................................77 4.5. HYDROGEN SULFIDE MEASUREMENTS......................................84
4.5.1. Electrochemical Sensor ..................................................................84 4.5.2. Gas Detector Tubes ........................................................................90 4.5.3. Gas Chromatography......................................................................91
4.6. BIOGAS-EXPOSED-COMPOST ASSESSMENT ..............................93 4.6.1. Moisture..........................................................................................93 4.6.2. pH ...................................................................................................95 4.6.3. Trace Element Analysis..................................................................95
4.7. DISCUSSION........................................................................................97 4.8. SCALE-UP CONSIDERATIONS ........................................................98
5. SUMMARY AND CONCLUSIONS.....................................................................102
5.1. CURRENTLY AVAILABLE H2S REMOVAL METHODS.............102 5.1.1. Dry-Based Processes ....................................................................102 5.1.2. Liquid-Based Chemical and Physical Processes ..........................105 5.1.3. Membrane Separation...................................................................105 5.1.4. In-Situ Digester Sulfide Control...................................................105 5.1.5. Biogas Aeration ............................................................................106 5.1.6. Biological Removal Techniques...................................................106 5.1.7. Comparison of Characteristics of H2S Removal Processes..........106
5.2. TESTING OF COW-MANURE COMPOST .....................................108 6. FUTURE WORK AND RECOMMENDATIONS................................................109 APPENDIX A: H2S Scavenger Media Disposal ........................................................111 REFERENCES...........................................................................................................112
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LIST OF TABLES Table 2.1: Characteristics of Typical Agricultural Anaerobic Digesters .......................7 Table 2.2: Physical, Chemical and Safety Characteristics of Hydrogen Sulfide .........10 Table 2.3: Biogas Utilization Technologies and Gas Processing Requirements..........11 Table 2.4: Principal Gas Phase Impurities ...................................................................12 Table 2.5: Assumed Biogas Characteristics for Process Comparisons ........................13 Table 2.6: Typical Specifications for 15-lb Iron Sponge .............................................15 Table 2.7: Iron Sponge Design Parameter Guidelines .................................................17 Table 2.8: System Characteristics of 15-lb Iron Sponge Design at AA Dairy.............18 Table 2.9: System Characteristics of SulfaTreat Design at AA Dairy .......................20 Table 2.10: System Characteristics of Sulfur-Rite Design at AA Dairy....................21 Table 2.11: System Characteristics of Media-G2 Design at AA Dairy .....................22 Table 2.12: Processes for Adsorbent Regeneration......................................................25 Table 2.13: Basic Types of Commercial Molecular Sieves .........................................26 Table 2.14: Summary of 5A Molecular Sieve Design at AA Dairy.............................28 Table 2.15: System Characteristics for KOH-Impregnated Activated Carbon at AA
Dairy .....................................................................................................................29 Table 2.16: Henrys Law Constants at 25 C and 1-Atmosphere ................................39 Table 2.17: Specific Microorganisms Studied for Biofiltration of H2S .......................49 Table 2.18: Media Tested for Biofiltration of Hydrogen Sulfide.................................50 Table 3.1: Cross Sensitivity Data for Electrochemical H2S Sensor .............................65 Table 3.2: Summary of Experimental Trial Conditions ...............................................71 Table 4.1: Cow-Manure Compost Characterization.....................................................73 Table 4.2: Summary of Temperature Extremes for Trials 3-6 .....................................81 Table 4.3: H2S Gas Detector Tube Readings for AA Dairy Raw Digester Gas...........90 Table 4.4: GC-MS Results for AA Dairy Digester Gas ...............................................91 Table 4.5: Moisture Contents Along Bed Depth ..........................................................94 Table 4.6: pH Levels Along Bed Depth .......................................................................95 Table 4.7: Elemental Analysis of Raw and Tested Compost .......................................96 Table 4.8: Estimated Comparison of Cow-Manure Compost and Iron-Sponge H2S-
Removal Systems at AA Dairy...........................................................................101 Table 5.1: Summary Table Comparing Dry-Based H2S Removal Processes for Farm
Biogas .................................................................................................................103 Table 5.2: Summary Table Comparing Dry-Based H2S Removal Processes for AA
Dairy ...................................................................................................................104 Table 5.3: Summary of H2S Removal Process Characteristics ..................................107 Table A.1. Approximate Media Change-out and Disposal Costs (1996 est.) ............111
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LIST OF FIGURES
Figure 2.1: Schematic of AA Dairy Integrated Farm Energy System............................5 Figure 2.2: Anaerobic Digestion Process .......................................................................8 Figure 2.3: Equilibrium Constant for the Reaction ZnO + H2S = ZnS + H2O.............23 Figure 2.4: Adsorption Zones in a Molecular Sieve Bed, Adsorbing Both Water Vapor
and Mercaptans from Natural Gas........................................................................27 Figure 2.5: Generic Absorber/Stripper Schematic .......................................................30 Figure 2.6: Reduction-Oxidation Cycle of Quinones...................................................32 Figure 2.7: Conventional Flow Diagram for LO-CAT Process .................................33 Figure 2.8: Flow Scheme for Alkanolamine Acid-gas Removal Processes.................38 Figure 2.9: Biofiltration System Schematic .................................................................45 Figure 2.10: The Global Sulfur Cycle. .........................................................................46 Figure 2.11: Biological Redox Cycle for Sulfur ..........................................................47 Figure 2.12: Steps in the Oxidation of Sulfur Compounds by Thiobacillus Species. ..48 Figure 3.1: Schematic of Small Columns.....................................................................56 Figure 3.2: Schematic of Small Columns with Leachate Recycle ...............................57 Figure 3.3: Schematic of Large Columns.....................................................................59 Figure 3.4: Experimental Setup at AA Dairy ...............................................................61 Figure 3.5: Humidifier and Air/Biogas Mixing Vessel ................................................63 Figure 4.1: AA-Dairy Field of Dreams Cow-Manure Compost ...............................72 Figure 4.2: Pressure Drop Across Bed for Trials 3-6...................................................76 Figure 4.3: Temperatures (15-Minute Average) for Column 3....................................78 Figure 4.4: Temperatures (15-Minute Average) for Column 4....................................78 Figure 4.5: Temperatures (15-Minute Average) for Column 5....................................79 Figure 4.6: Temperatures (15-Minute Average) for Column 6....................................79 Figure 4.7: Temperature Difference Between Bed and Inlet-gas for Columns 3-6 .....80 Figure 4.8: H2S Concentrations for Trial 3 ..................................................................85 Figure 4.9: H2S Removal Efficiency During Trial 3....................................................86 Figure 4.10: H2S Concentrations for Trial 4 ................................................................86 Figure 4.11: H2S Removal Efficiency During Trial 4..................................................87 Figure 4.12: H2S Concentrations and Removal Efficiency for Column 5 ...................89 Figure 4.13: H2S Concentrations and Removal Efficiency for Column 6 ...................89 Figure 4.14: GC-MS Results for AA Dairy Digester Gas............................................92 Figure 4.15: Pictures of Columns after Exposure to Biogas for 1057 hours................93
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CHAPTER
1. INTRODUCTION
Anaerobic digestion (AD) of agricultural waste has been practiced for many
years and provides a waste treatment solution, improved nutrient recovery, and energy
generation potential. Because of growing environmental constraints, an increase in the
average dairy farm herd size, and rising energy costs from increased demand, dairy
farmers are looking to AD coupled with on-site cogeneration of heat and power in
response to these pressures. However, there are hurdles to implementation of these
systems, including high capital costs, availability of economic and environmentally
acceptable methods of gas processing, and economic means for biogas utilization.
Because of these limitations, agricultural biogas production has remained a virtually
untapped resource in the United States.
Biogas consists mainly of methane (CH4) and carbon dioxide (CO2), with
smaller amounts of water vapor and trace amounts of hydrogen sulfide (H2S), and
other impurities. Various degrees of gas processing are necessary depending on the
desired gas utilization process. Hydrogen sulfide is typically the most problematic
contaminant because it is toxic and corrosive to most equipment. Additionally,
combustion of H2S leads to sulfur dioxide emissions, which have harmful
environmental effects. Removing H2S as soon as possible is recommended to protect
downstream equipment, increase safety, and enable possible utilization of more
efficient technologies such as microturbines and fuel cells.
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2
The most commonly used method for H2S removal from biogas involves
adsorption onto chemically active solid media. Though this process is effective, it is
labor intensive and generates a waste stream that poses environmental disposal risks.
These factors led to the identification of an opportunity for testing on-farm
manure compost as the adsorption medium. A similar process, known as biofiltration,
has shown its ability to remove H2S through the microbial action of naturally
occurring bacteria. Biofilters show promise as environmentally friendly, alternative
air pollution control technologies with lower capital, labor, and disposal costs.
The following objectives were specifically addressed in this study:
1) Survey currently available chemical, physical, and biological methods of
H2S removal from agricultural digester biogas.
2) Test the feasibility of utilizing on-farm cow-manure compost for H2S
removal.
AA Dairy farm in Candor, NY, which has produced biogas since 1998,
served as the site for experimental testing. Although removal of water vapor, carbon
dioxide, and other contaminants is also desirable, assessing all of the technologies
required for removal of these compounds is beyond the scope of this project.
It is hoped that this research not only benefits farmers who are looking to
install integrated farm energy systems, but also designers and operators of other
agricultural facilities, landfills, wastewater treatment plants, food-processing facilities,
and pulp and paper mills, where renewable, bio-based energy can be produced.
CHAPTER
2. BACKGROUND
2.1. INTEGRATED FARM ENERGY SYSTEMS
The concept of an integrated farm energy (IFE) system is an embodiment of
principals of industrial ecology, which attempt to improve on the efficiency and
sustainability of a system by optimizing energy and material usage while minimizing
pollution and waste. IFE systems, as referred to here, use anaerobic digestion (AD) to
treat the volatile organic fraction of animal manures, thereby producing biogas and an
improved waste stream. The biogas is then used for on-site heat and/or power
generation, and the digested material is either applied back to the land or processed
further into value-added compost. In 1995, a study estimated that three to five
thousand such systems could be economically installed throughout the next decade in
the U.S. (Lusk 1996). In 1999, there were only 34 operating farm-digester sites
registered with the EPAs AgSTAR program, though this number has since grown
(Roos and Moser 2000). According to one estimate, if all of the dairy manure biomass
in New York state could be collected and processed using anaerobic digestion and
diesel engine generation, an annual energy potential of 280 GWh, enough to support
the electricity demand of about 47,000 households, would be produced in addition to
providing all of the electricity for the farms (Ma 2002).
Extensive research on these integrated systems was done during the 1970s and
1980s by Cornell University researchers, and further information on their
3
4
development and design can be found in Jewell, et al. (1978), Walker, et al. (1985),
and Pellerin, et al. (1988). The integrated farm energy system used in this study is
operating at AA Dairy in Candor, NY.
2.1.1. AA Dairy
AA Dairy is a 2,200-acre, 500-head milking facility, which installed an
anaerobic digester in 1997. Resource recovery is achieved in part through use of an
anaerobic digester, diesel-engine cogenerator, liquid-solid separator, liquid-waste
storage lagoon, composting process and land application of effluent, as depicted in
Figure 2.1. Most of the cows are housed in a free-stall facility equipped with alley
scrapers for manure collection. A 1330 m3 concrete plug-flow digester, designed by
Resource Conservation Management, operates with approximately a 40-day retention
time and 1300 m3 per day of biogas produced on average. The digested solids are
separated and composted aerobically for a period of 60 days and sold to consumers as
a specialty organic fertilizer. The liquid portion is stored in a lagoon until land
application for nutrient value and water are needed. The biogas is combusted in a
converted Caterpillar 3306B diesel engine, which powers a generator continuously
producing 65 to 75 kW. Electricity unused by the farm (~535 kWh/day average) is
then sold to the local utility (NYSEG). Heat from the engine is currently used to
maintain the digester in its desired mesophillc operating range. The current method
for dealing with biogas impurities, such as hydrogen sulfide, is to perform a 70-quart
oil change weekly. No other gas processing technologies are employed, and the
annual operating cost for the resource recovery system, including labor and engine
maintenance, is estimate as $17,500 (Minott 2002).
LIQUID/SOLID SEPARATOR
(Used to maintain digester temperature)
(~60% CH4, ~40% CO2
6
There are many benefits to such farm systems, which include (RDA 2000):
Waste treatment benefits: Natural waste treatment process that requires less
land than composting, reduces solid waste volume and weight, and reduces
contaminant runoff.
Energy benefits: Generates a high-quality renewable fuel, which has numerous
end-use applications.
Environmental benefits: Potential to reduce carbon dioxide and methane
emissions, eliminates odors, produces a bio-available nutrient stream, and
maximizes recycling benefits. Reduces dependence on fossil fuels.
Economic benefits: More cost effective than many other treatment options
when viewed from a life-cycle analysis. Typical payback periods of 4-8 years.
2.2. ANAEROBIC DIGESTION
Six to eight million family-sized low-technology digesters are used in China
and India to provide biogas for cooking and lighting. Also, there are over 800 farm-
based digesters operating in Europe and North America (Wellinger and Linberg 2000).
Farm-based anaerobic digestion in the U.S. has mainly focused on manures from dairy
and swine operations because they are often liquid or slurry based. Systems have been
designed for poultry manures, but the higher solids content results in precipitation of
solids unless constantly mixed. There are many types of anaerobic digestion systems
for manure, which include batch, mixed-tank, plug-flow, fixed-film, and lagoon
digesters. Table 2.1 describes the different characteristics of 3 typical farm digesters.
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Table 2.1: Characteristics of Typical Agricultural Anaerobic Digesters
Covered Lagoon Complete Mix Plug Flow
Vessel Deep lagoon Round/Square In/Above ground Tank In ground
rectangular tankLevel of
Technology Low Medium Low
Additional Heat No Yes Yes Total Solids 0.5-1.5% 3-11%
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bacteria utilize these intermediates for conversion to methane and carbon dioxide
(Chynoweth and Issacson 1987).
Hydrogen Producing Acetogenic Bacteria
Complex Organic Carbons
Organic Acids, Neutral
Compounds
H2, CO2, One-Carbon
Compounds
Acetic Acid
HYDROLYTIC BACTERIA
Homoacetogenic Bacteria
METHANOGENIC BACTERIA
TRANSITIONAL BACTERIA
CH4 + CO2
Figure 2.2: Anaerobic Digestion Process
Source: Chynoweth and Issacson (1987), pg. 3
There are a number of factors which influence the digestion process, including,
temperature, bacterial consortium, nutrient composition, moisture content, pH, and
residence time.
Sulfur is an essential nutrient for methanogens but sulfur levels too high may
limit methanogenesis. Sulfur can enter the digester in the feedstock itself or from
chemicals used in an agricultural environment, such as copper and zinc sulfate
solutions that are used to prevent dairy cow foot-rot, and are inadvertently washed into
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the digester. Farm animals consume sulfur either in their food source, mostly in the
form of sulfur-containing amino acids such as cystine and methionine, or from their
drinking water source, which may contain significant amounts of sulfate. Sulfur that
is not used by the animal for nutrition is excreted in the manure.
Sulfate-reducing bacteria actually can out-compete methanogens during the
anaerobic digestion process. Therefore, sulfide production generally proceeds to
completion before methanogenesis occurs. The energetics of sulfate reduction with H2
is favorable to the reduction of CO2 with H2, forming either CH4 or acetate (Madigan,
et al. 2000).
The toxic level of total dissolved sulfide in anaerobic digestion is reported as
200-300 mg/l. Also, a head gas concentration of 6% H2S is the upper limit for
methanogenesis, while 0.5% H2S (11.5 mg/l) is optimum (Chynoweth and Issacson
1987).
2.3. BIOGAS COMPOSITION
Biogas composition depends heavily on the feedstock, but mainly consists of
methane and carbon dioxide, with smaller amounts (ppm) of hydrogen sulfide and
ammonia. Trace amounts of organic sulfur compounds, halogenated hydrocarbons,
hydrogen, nitrogen, carbon monoxide, and oxygen are also occasionally present.
Usually, the mixed gas is saturated with water vapor and may contain dust particles
and siloxanes (Wellinger and Linberg 2000). Water-saturated biogas from dairy-
manure digesters consists primarily of 50-60% methane, 40-50% carbon dioxide, and
less than 1% sulfur impurities, of which the majority exists as hydrogen sulfide
(Pellerin, et al. 1987).
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Hydrogen sulfide is poisonous, odorous, and highly corrosive. Some
characteristics of H2S are described in Table 2.2. Because of these characteristics,
hydrogen sulfide removal is usually performed directly at the gas-production site.
Table 2.2: Physical, Chemical and Safety Characteristics of Hydrogen Sulfide Molecular Weight 34.08 Specific Gravity (relative to air) 1.192 Auto Ignition Temperature 250 C Explosive Range in Air 4.5 to 45.5 % Odor Threshold 0.47 ppb 8-hour time weighted average (TWA) (OSHA) 10 ppm 15-minute short term exposure limit (STEL) (OSHA) 15 ppm Immediately Dangerous to Life of Health (IDLH) (OSHA) 300 ppm
Source: OSHA (2002), Occupational Safety and Health Administration, www.OSHA.gov
The actual amount of water vapor entrained in the gas depends on the gas
composition, pressure, and temperature. Approximately 25 kg of water is present in
1400 m3 of saturated natural gas at 21 C and atmospheric pressure (Kohl and Neilsen 1997).
2.4. QUALITY REQUIREMENTS FOR BIOGAS UTILIZATION
Biogas can be used for all applications designed for natural gas, assuming
sufficient purification. On-site, stationary biogas applications generally have fewer
gas processing requirements. A summary of potential biogas utilization technologies
and their gas processing requirements are given in Table 2.3.
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Table 2.3: Biogas Utilization Technologies and Gas Processing Requirements Technology Recommended Gas Processing Requirements Heating (Boilers)1
H2S < 1000 ppm, 0.8-2.5 kPa pressure, remove condensate (kitchen stoves: H2S < 10 ppm)
Internal Combustion Engines1
H2S < 100 ppm, 0.8-2.5 kPar pressure, remove condensate, remove siloxanes (Otto cycle engines more susceptible to H2S than diesel engines)
Microturbines2 H2S tolerant to 70,000 ppm, > 350 BTU/scf, 520 kPa pressure, remove condensate, remove siloxanes
Fuel Cells3
PEM: CO < 10 ppm, remove H2S PAFC: H2S < 20 ppm, CO < 10 ppm, Halogens < 4 ppm MCFC: H2S < 10 ppm in fuel (H2S < 0.5 ppm to stack),
Halogens < 1 ppm SOFC: H2S < 1 ppm, Halogens < 1 ppm
Stirling Engines4 Similar to boilers for H2S, 1-14 kPa pressure
Natural Gas Upgrade1,5
H2S < 4 ppm, CH4 > 95%, CO2 < 2 % volume, H2O < (1*10-4) kg/MMscf, remove siloxanes and particulates, > 3000 kPa pressure
Sources: 1 Wellinger and Linberg (2000) 2 Capstone Turbine Corp.(2002) 3 XENERGY (2002) 4 STM Power (2002)
5 Kohl and Neilsen (1997)
Technologies such as boilers and Stirling engines have the least stringent gas
processing requirements because of their external combustion configurations. Internal
combustion engines and microturbines are the next most tolerant to contaminants.
Fuel cells are generally less tolerant to contaminants due to the potential for catalytic
poisoning. Upgrading to natural-gas quality usually requires expensive and complex
processing and must be done when injection into a natural-gas pipeline or production
of vehicle fuel is desired.
Although not covered in this study, techniques for removal of CO2 may also
simultaneously reduce H2S levels. Many facilities in Europe have utilized water
scrubbing, polyethylene glycol scrubbing, carbon molecular-sieves or membranes for
upgrading of biogas to natural gas or vehicle fuel. Readers are directed to the
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following references for more information on these systems: Kohl and Neilsen (1997),
Wellinger and Linberg (2000), CADDET (2001), Eriksen, et al. (1999), (Schomaker,
et al. (2000), and Jensen and Jensen (2000).
2.5. TRADITIONAL H2S GAS-PHASE REMOVAL METHODS
Since biogas is similar in composition to raw natural gas, purification
techniques developed and used in the natural-gas industry can be evaluated for their
suitability with biogas systems. The ultimate process chosen is dependent on the gas
use, composition, physical characteristics, energy and resources available, byproducts
generated, and the volume of gas to be treated.
Principal gas phase impurities that may be present are listed in Table 2.4
below. Other constituents that may be problematic include water or other
condensates, and particulate matter. Hydrocarbons, such as methane, are the desired
product gases.
Table 2.4: Principal Gas Phase Impurities
1. Hydrogen sulfide 2. Carbon dioxide 3. Water vapor 4. Sulfur dioxide 5. Nitrogen oxides 6. Volatile organic compounds (VOCs) 7. Volatile chlorine compounds (e.g., HCl, Cl2) 8. Volatile fluorine compounds (e.g., HF, SiF4) 9. Basic nitrogen compounds 10. Carbon monoxide 11. Carbonyl sulfide 12. Carbon disulfide 13. Organic sulfur compounds 14. Hydrogen cyanide
Source:Kohl and Neilsen (1997), pg 3
13
Gas purification processes generally fall into one of the following five
categories: 1) Absorption into a liquid; 2) Adsorption on a solid; 3) Permeation
through a membrane; 4) Chemical conversion to another compound; or 5)
Condensation (Kohl and Neilsen 1997).
For the purposes of process comparison, gas characteristics similar to those at
AA Dairy, which are typical for a farm digester treating waste from around 500 dairy
cows, will be assumed and summarized as shown in Table 2.5.
Table 2.5: Assumed Biogas Characteristics for Process Comparisons Gas composition: ~60% CH4 ~40% CO2 1000-4000 ppm H2S Gas flow rate: ~1400 m3/day Gas pressure: < 2 kPa Gas temperature: ~ 25C Water saturated: Yes
With the flow rate and sulfur levels above, 1.9 7.7 kg of H2S are present in
the gas stream daily, or 690 2,815 kg yearly. Desirable attributes for a gas
purification system include low capital and operating costs, ease of operation and
media disposal, and minimal material and energy inputs. H2S removal processes will
be divided into dry-based, liquid-based, physical-solvent, membrane, alternative, and
biological processes for this summary. Media disposal costs are not discussed here
but very well may be the most significant costs for a project. For a further discussion
of this point, see Appendix A.
2.5.1. Dry H2S Removal Processes
Dry H2S removal techniques have historically been used at facilities with less
than 200kg S/day in the U.S. All of the dry sorption processes discussed here are
14
configured with the dry media in box or tower type vessels where gas can flow
upwards or downwards through the media. Since all of the dry-sorption media to be
discussed eventually becomes saturated with contaminant and inactive, it is common
to have two vessels operated in parallel so one vessel can remain in service while the
other is offline for media replacement.
2.5.1.1. Iron Oxides
As one of the oldest methods still in practice, iron oxides remove sulfur by
forming insoluble iron sulfides. It is possible to extend bed life by admitting air,
thereby forming elemental sulfur and regenerating the iron oxide, but eventually the
media becomes clogged with elemental sulfur and must be replaced. The most well-
known iron oxide product is called iron sponge. Recently, proprietary iron-oxide
media such as SulfaTreat, Sulfur-Rite, and Media-G2 have been offered as
improved alternatives to iron sponge.
Iron Sponge
Iron-oxide-impregnated wood-chips (generally pine) are used to selectively
interact with H2S and mercaptans. The primary active ingredients are hydrated iron-
oxides (Fe2O3) of alpha and gamma crystalline structures. Lesser amounts of Fe3O4
(Fe2O3.FeO) also contribute to the activity (Anerousis and Whitman 1985). Typical
specifications for iron sponge are listed below in Table 2.6. Grades of iron sponge
with 100, 140, 190, 240 and 320 kg Fe2O3/m3 are traditionally available, with the 190
kg Fe2O3/m3 (15-lb/bushel) grade being the most common. Bulk density for this grade
is consistently around 800 kg/m3 (50 lb/ft3) in place (Revell 2001).
15
Table 2.6: Typical Specifications for 15-lb Iron Sponge Source: Kohl and Neilsen,(1997), pg. 1302
The chemical reactions involved are shown in Equations 2.1-2.2:(Crynes 1978)
Fe2O3 + 3H2S Fe2S3 + 3H2O H= -22 kJ/g-mol H2S (2.1)
2Fe2S3 + O2 2Fe2O3 + 3S2 H= -198 kJ/g-mol H2S (2.2)
As seen from Equation 2.1, one kg of Fe2O3 stochiometrically removes 0.64 kg
of H2S. Equation 2.2 represents the highly exothermic regeneration of iron oxide and
16
formation of elemental sulfur upon exposure to air. Iron sponge is also capable of
removing mercaptans via Equation 2.3: (Zapffe 1963)
Fe203 + 6RSH = 2Fe(RS)3 + 3H20 (2.3)
Iron sponge can be operated in batch mode with separate regeneration, or with
a small flow of air in the gas stream for continuous revification. In batch mode,
operational experience indicates that only about 85% (0.56 kg H2S/ kg Fe2O3) of the
theoretical efficiency can be achieved (Taylor 1956).
Spent iron sponge can be regenerated in place by recirculation of the gas in the
vessel adjusted to 8% O2 concentration and 0.3-0.6 m3/m3bed/min space velocity
(Taylor 1956). Alternatively, the sponge can be removed, spread out into a layer 0.15-
m thick, and kept continually wetted for 10 days. It is imperative to manage the heat
buildup in the sponge during regeneration to maintain activity and prevent combustion
(Revell 1997). Due to buildup of elemental sulfur and loss of hydration water, iron
sponge activity is reduced by 1/3 after every regeneration. Therefore, regeneration is
only practical once or twice before new iron sponge is needed.
Removal rates as high as 2.5 kg H2S/ kg Fe2O3 have been reported in
continuous-revivification mode with a feed-gas stream containing only a few tenths of
a percent of oxygen (Taylor 1956). Equation 2.4 can be used to calculate percent air
recirculation necessary for optimum performance, dependent on inlet H2S
concentration in the gas (Vetter et al. 1990).
% Air recirculation required = 1.90 +(mg/m3 H2S measured)/3024 (2.4)
17
At Huntingtons farm in Cooperstown, N.Y., a removal level of 1.84 kg
H2S/kg Fe2O3 was reported using 140 kg Fe2O3/m3 (12 lb/bushel)-grade sponge and
continuous revivification with 2.29% air recirculation (Vetter et al. 1990).
Because iron sponge is a mature technology, there are design parameter
guidelines that have been determined for optimum operation. Table 2.7, below, is a
comprehensive collection of published design criteria for iron sponge systems.
Table 2.7: Iron Sponge Design Parameter Guidelines
Vessels: Stainless-steel box or tower geometries are recommended for ease of handling and to prevent corrosion. Two vessels, arranged in series are suggested to ensure sufficient bed length and ease of handling (Lead/Lag).
Gas Flow: Down-flow of gas is recommended for maintaining bed moisture. Gas should flow through the most fouled bed first.
Gas Residence Time: A residence time of greater than 60 seconds, calculated using the empty bed volume and total gas flow, is recommended.1
Temperature: Temperature should be maintained between 18 C and 46 C in order to enhance reaction kinetics without drying out the media.2
Bed Height: A minimum 3 m (10 ft) bed height is recommended for optimum H2S removal. A 6 m bed is suggested if mercaptans are present.3 A more conservative estimate recommends a bed height of 1.2 to 3 meters.4
Superficial Gas Velocity: The optimum range for linear velocity is reported as 0.6-3 m/minute.3
Mass Loading: Surface contaminant loading should be maintained below 10 g S/min/m2 bed.4
Moisture Content: In order to maintain activity, 40% moisture content, plus or minus 15%, is necessary. Saturating the inlet gas helps to maintain this.2
pH: Addition of sodium carbonate can maintain pH between 8-10. Some sources suggest addition of 16 kg sodium carbonate per m3 of sponge initially to ensure an alkaline environment.2
Pressure: While not always practiced, 140 kPa is the minimum pressure recommended for consistent operation.3
Sources: 1 Revell (2001), 2 Kohl and Neilsen (1997), 3 Anerousis and Whitman (1985), 4 Maddox and Burns (1968), 5 Taylor (1956)
Using the design constraints described in Table 2.7, a suitable iron sponge
system can be designed for a generic farm biogas application with characteristics
shown in Table 2.5. These results are presented in Table 2.8 below.
18
Table 2.8: System Characteristics of 15-lb Iron Sponge Design at AA Dairy Number of Vessels 2 in series (Lead/Lag) Vessel Dimensions 0.91 m diameter x 1.52 m high
Empty Bed Residence Time 120 seconds total Gas Flow Rate 0.94 m3/min Mass of Sponge 800 kg each
Air Recirculation Rate 2.4% - 3.7% Performance Estimates
Low Loading (1000 ppm H2S) High Loading
(4000 ppm H2S)
Expected Bed Life 72-315 days 18-79 days Annual Sponge Consumed 930-4070 kg 3,710 16,300 kg
Annual Sponge Costs $250 -$1,075 $985-$4,300
Biogas operations currently using iron sponge are located in Cooperstown,
NY, Little York, NY, and Chino, CA, among others. H2S levels at one farm digester
were consistently reduced from as high as 3600 ppm (average 1350 ppm) to below 1
ppm using a 1.5 m diameter x 2.4 m deep iron sponge reactor (Vetter et al. 1990).
Commercial sources for iron sponge include Connelly GPM, Inc., of Chicago,
IL, and Physichem Technologies, Inc., of Welder, TX. Both companies provide media
for around $6 per bushel (~50 lb), and note that shipping costs may be more
significant than actual media costs. Varec Vapor Controls, Inc., sells their Model-235
treatment units for around $50,000, including the cost of initial media. Such a unit
could last up to two years before change-out would be necessary (Wang 2000).
While the benefits of using iron sponge include simple and effective operation,
there are critical drawbacks to this technology that have lead to decreased usage in
recent years. The process is highly chemical intensive, the operating costs can be
high, and a continuous stream of spent waste material is accumulated. Additionally,
the change-out process is labor intensive and can be troublesome if heat is not
dissipated during regeneration. Perhaps most importantly, safe disposal of spent iron
sponge has become problematic, and in some instances, spent media may be
19
considered hazardous waste and require special disposal procedures. Landfilling on-
site is still practiced, but has become riskier due to fear of the need for future
remediation.
SulfaTreat
SulfaTreat is a proprietary sulfur scavenger, consisting mainly of Fe2O3 or
Fe3O4 compounds coated onto a proprietary granulated support and marketed by the
SulfaTreat Company of St. Louis, MO. SulfaTreat is used similarly to iron sponge
in a low-pressure vessel with down-flow of gas and is effective with partially or fully
hydrated gas streams.
Conversion efficiency in commercial systems is in the range of 0.55 - 0.72 kg
H2S/kg iron oxide, which is similar to, or slightly higher than, values reported for
batch operation of iron sponge (Kohl and Neilsen 1997). Particles range in size from
4 to 30 mesh with a bulk density of 1120 kg/m3 in place, and sell for roughly $0.88/kg
(Taphorn 2000).
Multiple benefits over iron sponge are claimed due to uniform structure and
free-flowing nature. SulfaTreat is reportedly easier to handle than iron sponge, thus
reducing operating costs, labor for change-out, and pressure drops in the bed. Also,
SulfaTreat claims to be non-pyrophoric when exposed to air and thus does not pose a
safety hazard during change-out. Buffering of pH and addition of moisture are not
necessary as long as the inlet gas is saturated.
Drawbacks associated with this product are similar to iron sponge; the process
is non-regenerable, chemically intensive, and spent product can be problematic or
expensive to dispose of properly. The manufacturer has suggested that spent product
may be used as a soil amendment or as a raw material in road or brick making, but
20
they state that every customer must devise a spent-product disposal plan in accordance
with local and state regulations.
For AA Dairy, a two-vessel arrangement (series) is proposed by the SulfaTreat
Company to ensure maximum removal while maintaining manageable bed sizes.
Proprietary rectangular vessels in a Lead/Lag arrangement, with the most fouled bed
contacting the gas first, are used (Taphorn 2000). Transportation, installation, and
disposal costs are not included in the system as described in Table 2.9 below.
Table 2.9: System Characteristics of SulfaTreat Design at AA Dairy Number of Vessels 2 in series (Lead/Lag) Vessel Dimensions 1.22 m x 1.65 m x 1.83 m
Vessel Costs $8,000 for two Gas Flow Rate 0.94 m3/min
Mass of SulfaTreat 3,636 kg each Air Recirculation Rate 2.4%
Performance Estimates
Low Loading (1000 ppm H2S) High Loading
(4000 ppm H2S) Expected Bed Life (one vessel) 345 days 86 days
Total Pressure Drop (kPa) 0.4 0.4 Annual SulfaTreat Consumed 3,850 kg 15,450 kg
Annual SulfaTreat Costs $3,400 $13,500
Sulfur-Rite
Sulfur-Rite is also a dry-based iron-oxide product offered by GTP-Merichem.
Sulfur-Rite is unique in their claim that insoluble iron pyrite is the final end product.
Sulfur-Rite systems come in prepackaged cylindrical units that are recommended for
installations with less than 180 kg sulfur/day in the gas and flow rates below 70
m3/min. Company literature claims spent product is non-pyrophoric and landfillable
and has 3-5 times the effectiveness of iron sponge. Sulfur-Rite also has many of the
21
disadvantages of the iron-oxide scavengers previously mentioned. System design and
cost estimates for an installation similar to AA dairy are presented in Table 2.10.
Table 2.10: System Characteristics of Sulfur-Rite Design at AA Dairy Number of Vessels 1-Carbon Steel unit Vessel Dimensions 2.29 m diameter x 3.43 m high
Vessel Costs $43,600 (vessel only) Gas Flow Rate 0.94 m3/min
Mass of Sulfur-Rite 9,100 kg Performance Estimates
Low Loading (1000 ppm H2S) High Loading
(4000 ppm H2S) Expected Bed Life 420 days 98 days
Annual Product Consumption 7,900 kg 33,900 kg Annual Sulfur-Rite Costs $5,560 $23,840
Media-G2
Media-G2 is an iron-oxide-based adsorption technology originally developed
by ADI International, Inc., for removal of arsenic from drinking water. Recently ADI
has begun testing Media-G2 for the removal of H2S from gas streams with promising
results. Landfill gas and biogas installations will serve as the primary market for their
technology, which incorporates iron oxides onto a diatomaceous support.
Lab scale and pilot scale trials indicate that treatment of up to 30,000 ppm H2S
is possible, spent product is non-hazardous, and Media-G2 can remove up to 560 mg
H2S/g solid. This is achieved by being able to regenerate the matrix with air up to 15
times. Each adsorption cycle removes about 35-40 mg H2S/g media. A two-vessel
system design (parallel) is recommended for continuous operation, as 8-hour
regeneration cycles are estimated at full scale. Vessels are designed for approximately
60-second empty-bed residence times. Approximate product costs are estimated at
$1060/m3.
22
Only two full-scale plants have been installed to date; Brookhaven Landfill in
NY, and a farm based anaerobic digester installed by Enviro-Energy Corporation in
Tillamook, OR (McMullin 2002). Although no full scale operational results were
available, a system design summary is proposed in Table 2.11 below.
Table 2.11: System Characteristics of Media-G2 Design at AA Dairy Number of Vessels 2 in parallel Vessel Dimensions 0.91 m diameter x 1.52 m high
Gas Flowrate 0.94 m3/min Empty Bed Residence Time 62 seconds (with one offline)
Mass of Media-G2 760 kg each Air Recirculation Rate 2.4%
Performance Estimates
Low Loading (1000 ppm H2S) High Loading
(4000 ppm H2S) Expected Bed Life (one vessel) 190 days 47 days
Annual Media-G2 Consumption 1,460 kg 5,900 kg Annual Media-G2 Costs $2,050 $8,290
2.5.1.2. Zinc Oxides
Zinc oxides are preferred for removal of trace amounts of hydrogen sulfide
from gases at elevated temperatures due to their increased selectivity over iron oxide
(Chiang and Chen 1987). Typically in the form of cylindrical extrudates 3-4 mm in
diameter and 8-10 mm in length, zinc oxides are used in dry-box or fluidized-bed
configurations. Hydrogen sulfide reacts with zinc oxide to form an insoluble zinc
sulfide via Equation 2.5 (Kohl and Neilsen 1997).
ZnO + H2S = ZnS + H2O (2.5)
The equilibrium constant for the reaction is given with Equation 2.6.
23
Kp = PH2O/PH2S (2.6)
Where: PH2O is the partial pressure of water vapor in the gas phase PH2S is the partial pressure of hydrogen sulfide in the gas phase
As shown in Figure 2.3, the equilibrium constant decreases rapidly with
temperature. Therefore, at very high temperatures equilibrium is approached, but as
temperature decreases, reaction kinetics are drastically reduced to impractical levels.
Figure 2.3: Equilibrium Constant for the Reaction ZnO + H2S = ZnS + H2O. Source: Kohl and Neilsen (1997) pg. 1307.
Zinc-oxide processes are available in several forms for operation at
temperatures from about 200 C to 400 C. Maximum sulfur loading is typically in the range of 30-40 kg sulfur/100 kg sorbent for these processes. Puraspec, marketed
by IC Industries of Great Britain, is a proprietary combination of zinc oxides that
boasts more effective performance in the temperature range of 40 C to 200 C. Nevertheless, performance is preferable at 200 C to 40 C, so operation below 150 C is rarely practiced. Spent product may also contain over 20% sulfur (by weight).
Formation of zinc sulfide is irreversible and zinc oxide is not very reactive with
24
organic sulfur compounds. If removal of mercaptans is also desired, catalytic
hydrodesulfurization to convert these compounds to the more reactive hydrogen
sulfide is needed first (Kohl and Neilsen 1997).
2.5.1.3. Alkaline Solids
Alkaline substances, such as hydrated lime, will react with acid gases like H2S,
SO2, CO2, carbonyl sulfides and mercaptans in neutralization reactions. Usually
liquid-based scrubbers are used, but fixed-beds of alkaline granular solid can also be
used in a standard dry box arrangement with up-flow of gas. Molecular Products Ltd.,
of Great Britain, markets a product called Sofnolime-RG, which is claimed to be a
synergistic mixture of hydroxides that react with acid gases. Predominant reactions
are shown in Equations 2.7-2.8 (Kohl and Neilsen 1997)
2NaOH + H2S Na2S +2H20 (2.7)
Ca(OH)2 + CO2 CaCO3 + H2O (2.8)
To achieve significant removal of H2S, CO2 must also be concurrently reduced
at the cost of extremely high product utilization. Sofnolime can remove about 180 L
of CO2/kg of media. At this efficiency, it would require over 3,020 kg/day of
Sofnolime to remove all of the CO2 from 1350 m3 biogas/day, assuming 40% CO2
concentration by volume.
2.5.1.4. Adsorbents
Adsorbents rely on physical adsorption of a gas-phase particle onto a solid
surface, rather than chemical transformation as discussed with the previous dry
sorbents. High porosity and large surface areas are desirable characteristics, enabling
25
more physical area for adsorption to occur. Media eventually becomes saturated and
must be replaced or regenerated. If regeneration of the media is economical or
desirable, it can be achieved by using one of the processes described in Table 2.12
below. During regeneration, H2S rich gas is released and must be exhausted
appropriately or subjected to another process for sulfur recovery (Yang 1987).
Table 2.12: Processes for Adsorbent Regeneration
Regeneration Process Description
Temperature Swing Adsorption
(TSA)
Regeneration takes place primarily through heating. The differences between the equilibrium loadings at the two
temperatures represent net removal capacity. Considerable energy and time are required to heat and cool the bed. TSA is
often achieved by preheating a purge gas.
Pressure Swing Adsorption (PSA)
Regeneration is achieved by lowering the pressure of the bed and allowing the adsorbate to desorb. Typically adsorption takes place at elevated pressures to allow for regeneration at
atmospheric pressure or under slight vacuum. PSA is relatively fast compared to TSA
Inert Purge A non-adsorbing gas containing very little of the impurity is
passed through the bed, reducing the partial pressure of adsorbate in the gas-phase so that desorption occurs.
Displacement Purge
A purge gas that is more strongly adsorbed than the impurity is used to desorb the original contaminant. Steam regeneration,
while mostly a thermal process, also regenerates through displacing some of the original adsorbate.
Molecular Sieves (Zeolites)
Zeolites are naturally occurring or synthetic silicates with extremely uniform
pore sizes and dimensions and are especially useful for dehydration or purification of
gas streams. Polar compounds, such as water, H2S, SO2, NH3, carbonyl sulfide, and
mercaptans, are very strongly adsorbed and can be removed from such non-polar
systems as methane. About 40 different zeolite structures have been discovered and
properties of the four most common ones are described in the Table 2.13.
26
Table 2.13: Basic Types of Commercial Molecular Sieves
Source: Kohl and Neilsen, (1997), pg. 1043
Adsorption preference, from high to low, is: H2O, mercaptans, H2S, and CO2.
Not all mercaptans are adsorbable on type 4A or 5A molecular sieves because of pore
size limitations. Consequently, 13X is preferred for complete sulfur removal from
natural-gas streams. Because contaminants are essentially competing for the same
active adsorption spots, a graphical representation of multiple adsorption zones in a
molecular sieve bed might occur as in Figure 2.4.
27
Figure 2.4: Adsorption Zones in a Molecular Sieve Bed, Adsorbing Both Water
Vapor and Mercaptans from Natural Gas. Source: Kohl and Nielsen, (1997), pg 1071
A design method for natural-gas purification by 5A molecular sieves,
developed by Chi and Lee (1973), can be used to estimate approximate bed-sizes and
media-life for a zeolites process at AA Dairy. Minimum pressures of 3500 kPa, and
maximum CO2 concentration of 5%, were verified for their model, but for the
following calculations a 40% CO2 concentration is used (Chi and Lee 1973). Table
2.14 shows characteristics for a sample 5A-molecular-sieve system for AA Dairy.
28
Table 2.14: Summary of 5A Molecular Sieve Design at AA Dairy
Low Loading (1000 ppm H2S) High Loading
(4000 ppm H2S) (units)
Gas Flow rate 1,400 1,400 m3/day Operating Pressure 500 500 psig
Operating Temp. 25 25 C Bed Life 24 24 hours
Bed Height 1.4 2.0 m Bed Diameter 0.6 0.6 m Bed Volume 0.39 0.58 m3
Bed Wt. 262 391 kg
As calculated, roughly 250-400 kg of zeolite would be needed on a daily basis,
and therefore would not be economical without a regeneration process.
Activated Carbon
Granular activated carbon (GAC) is a preferred method for removal of volatile
organic compounds from industrial gas streams. Heating carbon-containing materials
to drive off volatile components forms GACs, which have a highly porous adsorptive
surface. Utilization of GACs for removal of H2S has been limited to removing small
amounts, and primarily from drinking water. If H2S is the selected contaminant to be
removed, GACs impregnated with alkaline or oxide coatings are utilized.
Impregnated Activated Carbons
Coating GACs with alkaline or oxide solids enhance the physical adsorptive
characteristics of the carbon with chemical reaction. Sodium hydroxide, sodium
carbonate, potassium hydroxide (KOH), potassium iodide, and metal oxides are the
most common coatings employed.
Distributors of impregnated activated carbon include Calgon Carbon
Corporation (Type FCA carbon), Molecular Products, Ltd. (Sofnocarb KC), US
29
Filter-Westates, and Bay Products, Inc. Typically, 20-25% loading by weight of H2S
can be achieved, which is up from 10% as seen with regular GAC.
An example of particular interest was the use of a non-regenerable KOH-
activated-carbon bed (Westates) for removal of H2S from anaerobic-digester and
landfill gas for use in a fuel cell. Oxygen (0.3-0.5% by volume) was added to facilitate
conversion of H2S to elemental sulfur. Two beds, 0.6 m in diameter by 1.5 m high,
were piped in series and run with space velocities of 5300/hr. Inlet H2S concentration
ranged from 0.7-50 ppm, averaging 24.1 ppm, and 98+% removal was demonstrated.
A loading capacity of 0.51 g S/g carbon was reported, which is substantially greater
than the normally reported range of 0.15 - 0.35 g S/g carbon for KOH-carbon. Media
costs were estimated at $5/kg for the adsorbent. Pretreatment system capital costs
(including sulfur removal, blowers and coalescing filters) were estimated to be
$500/kW (Spiegel, et al. 1997; Spiegel and Preston 2000).
Assuming loading capability of 25% and design with a 100 kW generator,
costs and performance might appear as represented in Table 2.15.
Table 2.15: System Characteristics for KOH-Impregnated
Activated Carbon at AA Dairy Number of Vessels 2 in series (Lead/Lag) Vessel Dimensions 0.6 m diameter x 1.5 m high
System Capital Cost $50,000 Gas Flow Rate 0.94 m3/min Mass of Carbon 250 kg each
O2 Recirculation Rate 0.3% Performance Estimates
Low Loading (1000 ppm H2S) High Loading
(4000 ppm H2S) Expected Bed Life (one vessel) 340 days 85 days Annual Carbon Consumption 270 kg 1075 kg
Annual Carbon Costs $1,250 $5,435
30
2.5.2. Liquid H2S Removal Processes
Liquid-based H2S removal processes have replaced many dry-based
technologies for natural-gas purification due to reduced ground-space requirements,
reduced labor costs, and increased potential for elemental-sulfur recovery. Gas-liquid
contactors, or absorbers, are used which increase surface area and optimize gas contact
time. If a reversible reaction is employed, regeneration columns are operated in
conjunction with the absorber to facilitate continuous processing. A generic
absorber/regenerator flow scheme is presented in Figure 2.5.
Stripping Solution
Stripping Gas Out
Clean Gas Out
Stripping Gas In
Sour Gas In
Figure 2.5: Generic Absorber/Stripper Schematic
As indicated, the stripper gas contains the displaced H2S if it has not been
converted to elemental sulfur in the process. When the sulfide level is high, the sour
stripping gas can be sent to a Claus plant for elemental-sulfur recovery. When the
reaction is irreversible, a simpler bubble column may be used in place of an absorber.
Liquid-based H2S removal processes can be grouped into liquid-phase oxidation
processes, alkaline-salt solutions, and amine solutions. Physical adsorption of H2S
into a liquid, such as water, is discussed in the next section.
31
2.5.2.1. Liquid-Phase Oxidation Processes
Iron- and Zinc-Oxide Slurries
Iron-oxide slurry processes historically mark the transition between dry-box
technologies and modern liquid-redox processes. The basic chemistry is similar to
that for the dry oxide reactions. H2S is reacted with an alkaline compound in solution
and then iron oxide to form iron sulfide, as shown in Equations 2.9-2.10.
Regeneration is achieved by aeration, converting the sulfide to elemental sulfur, as
shown in Equation 2.11 (Kohl and Neilsen 1997).
H2S + Na2CO3 = NaHS + NaHCO3 (2.9)
Fe2O3.3H2O + 3NaHS + 3 NaHCO3 = Fe2S2.3H2O + 3 Na2CO3 + 3H2O (2.10)
2Fe2S2.3H2O +3O2 = 2Fe2O3.3H2O + 6S (2.11)
Several side reactions can occur, forming thiosulfates and thiocyanates, which
continually deplete the active iron oxide supply. Commercial processes that were
available in the past include the Ferrox (1926), Gluud (1927), Burkheiser (1953),
Manchester (1953), and Slurrisweet (1982) processes (Kohl and Neilsen 1997).
A zinc-oxide liquid-based process, known as Chemsweet (Natco, Inc.), has
achieved some success in more recent years. The proprietary powder, consisting of
zinc oxide, zinc acetate, and dispersant, is mixed with water and used in a simple
bubble column. The reaction mechanisms are presented in Equations 2.12-2.14 below
(Kohl and Neilsen 1997).
ZnAc2 + H2S = ZnS +2HAc (2.12)
ZnO + 2HAc = ZnAc2 + H2O (2.13)
ZnO + H2S = ZnS +H2O (2.14)
32
Low pH is maintained to avoid CO2 absorption and vessel corrosion while
encouraging RSH and COS removal. Pipeline-gas specifications are easily met, but
the high cost of non-regenerable reactant usually limits use of this process to removing
trace amounts of sulfur.
Quinone and Vanadium Metal Processes
The redox cycle shown in Figure 2.6 depicts how hydrogen sulfide is
converted to elemental sulfur using quinones.(Kohl and Neilsen 1997)
+ H2S + S Reduction
Oxidation+ O2 + H2O
Figure 2.6: Reduction-Oxidation Cycle of Quinones
Processes using quinones with vanadium salts, such as the Stretford process,
account for a large portion of the liquid-based natural-gas purification market today,
although chelated-iron processes are surpassing them. Because of high capital and
operating costs and significant thiosulfate byproduct formation, quinone-based H2S
technologies are generally not used for smaller gas streams.
Chelated-Iron Solutions
Chelated-iron solutions utilize iron ions bound to a chelating agent and are
gaining popularity for H2S removal. The LO-CAT (US Filter/Merichem) and
SulFerox (Shell) processes currently dominate the chelated-iron H2S removal market.
Basic redox reactions employed for adsorption and regeneration are as shown in
Equations 2.15-2.16.
33
2Fe3+ + H2S = 2Fe2+ + S + 2H+ (2.15)
2Fe2+ +(1/2)O2 + H2O = 2Fe3+ + 2OH- (2.16)
The LO-CAT process is potentially attractive for biogas applications because
it is 99+% effective, the catalyst solution is nontoxic, and it operates at ambient
temperatures, requiring no heating or cooling of the media. Multiple configurations of
the LO-CAT process are available and Figure 2.7 below depicts a standard system.
Figure 2.7: Conventional Flow Diagram for LO-CAT Process Source: Kohl and Nielsen (1997), pg 809.
LO-CAT systems are currently only recommended and economical for
facilities with over 200 kg S/day. Landfills and wastewater treatment plant digesters
have implemented LO-CAT H2S removal systems successfully, and LO-CAT plants
producing less than 500 kg of S/day are designed to produce thickened slurry, so use
of a separate thickener vessel is not required. The thickened slurry may have some
value as a fertilizer amendment in certain agricultural applications. The two principal
34
operating costs are for power for pumps and blowers, and chemicals for catalyst
replacement due to losses via thiosulfate and bicarbonate production (Kohl and
Neilsen 1997).
Le Gaz Integral Enterprise of France markets the Sulfint and SulFerox iron-
chelate processes targeted for gas streams with 100-20,000 kg S/day and high
CO2/H2S ratios. CO2 will not be removed significantly and 50% -90% of mercaptans
can be removed with either low or high-pressure applications. Sulfur removal with
SulFerox costs around $0.24-$0.3 per kg, and filtration using a plate-and-frame filter
is sufficient to recover elemental sulfur (Smit and Heyman 1999).
Other Liquid-Based Processes
Nitrite solutions are sometimes used when simple process configurations are
desired, requiring only a bubble-column contactor and mist eliminator. An overall
reaction is represented with Equation 2.17.
3H2S + NaNO2 = NH3 + 3S + NaOH + some NOx (2.17)
In the presence of CO2, the NaOH is neutralized to produce sodium carbonate
and bicarbonate. As seen, the reaction products are ammonia and NOx, which may be
just as problematic as H2S to deal with. Nevertheless, the spent slurry is non-
hazardous and non-corrosive, the equipment is simple and low cost, and change-out of
spent adsorbent is easy. Sulfa-Check (NL Industries, Inc.) and Hondo HS-100
(Hondo Chemicals, Inc.) are two commercially available nitrite-based media. Design
guidelines include: (Kohl and Neilsen 1997)
1.) Optimum efficiency in the temperature range of 24 C to 43 C. 2.) Maximum superficial velocity of gas should be below 0.05 m/sec.
3.) 6.310-6 liters of solution are required per m3 of gas per ppm of H2S.
35
4.) Liquid height in meters should be 0.76 times the logarithm of H2S
concentration in ppm.
Using these criteria and gas characteristics described in Table 2.5, a vessel 0.61
meters in diameter, and 2.3 2.7 meters in liquid height should be employed.
Permanganate and dichromate solutions can also be used to completely remove
traces of H2S. Spent media is also non-regenerable and the high costs of chemicals
limit the use of this process.
2.5.2.2. Alkaline Salt Solutions
As with alkaline solids, acid gases such as H2S and CO2 react readily with
alkaline salts in solution. Regenerative processes employ alkaline salts including
sodium and potassium carbonate, phosphate, borate, aresenite, and phenolate, as well
as salts of weak organic acids. Since H2S is adsorbed more rapidly than CO2 by
aqueous alkaline solutions, some partial selectivity can be attained when both gases
are present by ensuring fast contact times at low temperatures (Kohl and Neilsen
1997).
Caustic Scrubbing
Hydroxide solutions are very effective at removing CO2 and H2S, but are non-
regenerable. Mercaptans form less-strongly-bound mercaptides, which are
regenerable at high temperatures, and commercial caustic-plants have operated with
this specialty.
The Dow Chemical Company developed a low-residence-time absorber for the
selective removal of H2S. Tests indicated reduction of 1000 ppm H2S to less than 100
ppm (in the presence of 3.5% CO2 @ 1400 m3/day), with a gas-residence time of 0.02
sec, pressure drop of 14 kPa, and liquid-to-gas ratio of 0.004 l/m3. Disposal of the
36
liquid effluent was a major problem. Also, the presence of higher CO2 concentrations
would lead to higher chemical utilization.
Other Alkaline Salt Processes
The Seaboard process (ICF Kaiser) was the first commercially applied liquid
process for H2S removal and used a sodium-carbonate absorbing-solution with air
regeneration. The overall chemical reaction is shown in Equation 2.18:
Na2CO3 + H2S = NaHCO3 + NaHS (2.18)
Removal efficiencies of 85% 95% were realized, but the occurrence of side
reactions and problems with disposal of the foul air, containing H2S, has restricted use
of this process. Variations on the Vacuum Carbonate process (ICF Kaiser), which also
employ carbonates, have replaced the Seaboard process by enabling vacuum capture
of the foul stripping-gas and reducing the steam requirement needed for regeneration.
Many other processes are available at ambient and elevated temperatures that
use alkaline-salt solutions for removal of CO2 and H2S from gas streams. However,
the complexity of these processes makes them unattractive for H2S removal from
small biogas streams.
2.5.2.3. Amine Solutions
Amine processes constitute the largest portion of liquid-based natural-gas
purification technologies for removal of acid gases. They are attractive because they
can be configured with high removal efficiencies, designed to be selective for H2S or
both CO2 and H2S, and are regenerable. Drawbacks of using an amine system, as with
most liquid-based systems, are more complicated flow schemes, foaming problems,
chemical losses, higher energy demands, and how to dispose of foul regeneration air.
37
Alkanolamines generally contain a hydroxl group on one end and an amino
group on the other. The hydroxyl group lowers the vapor pressure and increases water
solubility, while the amine group provides the alkalinity required for absorption of
acid gases. The dominant chemical reactions occurring are as shown in Equations
2.192.23 (Kohl and Neilsen 1997).
H2O = H+ + OH- (2.19)
H2S = H+ + HS- (2.20)
CO2 + H2O = HCO3- + H+ (2.21)
RNH2 + H+ = RNH3+ (2.22)
RNH2 + CO2 = RNHCOO- + H+ (2.23)
Typically used amines include monothanolamine (MEA), diethanolamine
(DEA), methyldiethanloamine (MDEA), and diisopropanolamine (DIPA). Adsorption
is typically conducted at high pressures with heat regeneration in the stripper. Glycol
solutions, mentioned in the next section, are also employed to enhance physical
absorption characteristics of the acid gases. The basic flow-scheme for an
alkanolamine acid-gas removal process is depicted in Figure 2.8.
38
Figure 2.8: Flow Scheme for Alkanolamine Acid-gas Removal Processes Source: Kohl and Nielsen (1997), pg 58
Sulfa-Scrub (Quaker Chemical Company) is a triazine-based sorbent
developed to selectively remove H2S from gas streams with minimal corrosion and
non-hazardous spent media. Sulfa-Scrub has been used in scavenging applications
without regeneration, and media consumption was around 5.310-6 - 6.710-6 l/m3 per ppm of H2S in the feed gas. This corresponds to generation of 10-40 liters per day of
spent non-regenerable slurry from an operation similar to AA Dairys. Further
information on the design and operation of alkanolamine plants can be found in Gas
Purification, Kohl and Nielsen (1997).
2.5.3. Physical Solvents
When acid gases make up a large proportion of the total gas stream, the cost of
removing them with heat-regenerable processes, such as amines, may be out of line
with the value of the treated gas. Physical solvents, where the acid gases are simply
39
dissolved in a liquid and flashed off elsewhere by reducing the pressure, have been
employed with limited success. Since these processes depend on partial-pressure
driving forces, some product will invariably be lost, especially at higher pressures.
2.5.3.1. Water Washing
Liquids with increased solubilities for CO2 and H2S are typically chosen over
water, but the principal advantages of water as an absorbent are its availability and low
cost. Absorption of acid gas produces mildly corrosive solutions that can be damaging
to equipment if not controlled. Table 2.16 indicates Henrys law constants for biogas
components in water.
Table 2.16: Henrys Law Constants at 25 C and 1-Atmosphere
CH4 1.5 x 10-4 M/atm CO2 3.6 x 10-2 M/atm H2S 8.7 x 10-2 M/atm
As seen, H2S has a slightly higher solubility than CO2, but costs associated
with selective removal of H2S using water scrubbing have not yet shown competitive
with other methods. Therefore, water scrubbing will probably only be considered for
the simultaneous removal of both H2S and CO2. Experimentally derived equilibrium
constants for mixtures of CH4, CO2, and H2S have been determined and can be used to
calculate water and gas flow rates, as well as vessel dimensions (Froning, et al. 1964).
2.5.3.2. Other Physical Solvents
Solvents such as methanol, propylene carbonate, and ethers of polyethylene
glycol, among others, are offered as improved physical solvents. Criteria for solvent
selection include high absorption capacity, low reactivity with equipment and gas
40
constituents, and low viscosity. Thermal regeneration techniques are still needed in
most cases to achieve pipeline-quality gas. Additionally, loss of product can be higher
with these solvents, as levels as high as 10% have been reported (Kohl and Neilsen
1997).
The Selexol process (Union Carbide) utilizes dimethylether of polyethylene
glycol (DMPEG) as a purely physical solvent. In 1992, Union Carbide reported 53
Selexol plants operating, of which 15 were designed for selective removal of H2S and
8 were in service for landfill-gas purification. Like water scrubbing, the cost for
selective H2S removal has not yet shown to be competitive and this process will most
likely only be considered for applications in which upgrading to relatively pure
methane is desired (Wellinger and Linberg 2000).
The Sulfinol Process (Shell Oil Company) is unique because it couples
improved physical solvents with chemical amine agents to boost removal efficiencies.
This method can easily produce pipeline-quality gas, but has yet to be demonstrated as
economical for small-scale biogas H2S removal.
2.5.4. Membrane Processes
Membranes operate based on differing rates of permeation through a thin
membrane, as dictated by partial pressure. Because of this, 100% removal efficiency
is not possible in one stage, and some product will inevitably be lost. Two types of
membrane systems exist: high pressure with gas phase on both sides, and low pressure
with a liquid adsorbent on one side. Membranes are generally not used for selective
removal of H2S from biogas but are becoming more attractive for upgrading of biogas
to natural-gas standards because of attributes such as reduced capital investment, ease
of operation, low environmental impact, gas dehydration capability, and high
reliability.
41
Kayhanian and Hills (1987) studied high-pressure membrane purification
specifically for the purification of anaerobic-digester gas. Cellulose acetate
membranes operating at 25C, 550 kPa, and a stage cut (ratio of permeate flow rate to non-permeate flow rate) of 0.45 performed the best for removal of CO2 and H2S, and
reduced 1000 ppm H2S to 430 ppm (Kayhanian and Hills 1988). Three-stage units
treating landfill gas have achieved product gases with over 96% CH4 but utilize
separate H2S removal systems to extend the membrane life, which is typically in the
range of three to five years (Wellinger and Linberg 2000).
Low-pressure gas-liquid membrane processes have recently been developed
specifically for upgrading of biogas and operate at around atmospheric pressure and
25C 35C. Initial trials indicate that 2% H2S concentrations can be reduced to less than 250 ppm using NaOH or coral solutions for the liquid. Amine solutions can be
employed for preferential CO2 removal and traditional liquid regeneration techniques
employed for the solvent. This process is still in a developmental stage but may prove
to be desirable in the future (Eriksen, et al. 1999).
2.6. ALTERNATIVE H2S CONTROL METHODS
2.6.1. In-Situ (Digester) Sulfide Abatement
Iron chlorides, phosphates, and oxides can be added directly to the digester to
bind with H2S and form insoluble iron sulfides. McFarland and Jewell (1989) studied
the effects of digester pH and addition of insoluble iron phosphate directly to
digesters, pointing out that addition of FeCl3, although regularly practiced, is often
inconsistent and inconclusive for reducing H2S. Lab studies showed that increasing
pH from 6.7 to 8.2 through the addition of phosphate buffers reduced gaseous sulfide
emissions from 2900 to 100 ppm, while increasing soluble sulfide concentrations from
42
18 to 61 mg/l. Soluble sulfide levels around 120 mg/l begin to inhibit CH4 production.
Addition of insoluble iron (3+) phosphate up to FePO4-Fe:SO42--S ratios of 3.5,
reduced gaseous sulfide levels from 2400 to 100 ppm (McFarland and Jewell 1989).
Ferric phosphate (FePO4) and ferric oxide (Fe2O3) are able to lower HS-
concentrations in the digester via Equations 2.24 and 2.25 (Jewell, et al. 1993).
2 FePO4 H2O + 3 H2S Fe2S3 + 2 H3PO4 + 2 H2O (2.24) Fe2O3 H2O + 3 H2S Fe2S3 + 4 H2O (2.25)
This method may be effective as a partial removal process for reducing high
H2S levels, but usually must be used in conjunction with another technology for
removal down to about 10 ppm H2S. Concern also exists that accumulation of
insoluble iron sulfides might cause premature buildup in a digester (Jewell, et al.
1993).
Richards, et al. (1994), studied a unique, in-situ, method for methane
enrichment whereby the leachate from a semi-continuously fed and mixed (SCFM)
reactor was purged of CO2 in an external, air-purged, stripper. This process took
advantage of differing solubilities for CO2 and methane, and it produced gas with over
98% CH4. No monitoring of H2S was conducted. This process has limited application
to SCFM or CSTR reactors, and further testing is needed to determine practical design
and operating requirements for larger-scale operation (Richards, et al. 1994).
2.6.2. Dietary Adjustment
Diet composition influences sulfur content in animal wastes, which directly
impact sulfides emitted from anaerobically digested manure. Sulfur is a required
nutrient for animal health and cannot be completely eliminated from a diet. Shurson,
et al. (1998), have reduced H2S levels from anaerobic swine-manure lagoons by 30%
43
through careful manipulation of a nutritional swine diet. Animal performance and
ammonia emissions were not studied in this experiment. Dietary adjustment is
generally not used for sulfide reduction because diets are typically optimized for
product yields and animal health, rather than sulfur levels in the excrement.
Furthermore, a complete reduction in H2S can never be effected, so additional H2S
abatement processes are needed (Shurson, et al. 1998). However, limiting sulfur
containing chemicals or high sulfate content waters from inadvertently entering the
digester could be a simple way to reduce H2S emissions somewhat.
2.6.3. Aeration
A simple technique for H2S reduction, now practiced in Europe, includes
air/oxygen dosing into the biogas. Air is carefully admitted to the digester or biogas
storage tank at levels corresponding to 2-6% air in biogas. It is believed effectiveness
is based on biological aerobic oxidation of H2S to elemental sulfur and sulfates.
Inoculation is not required, as Thiobacillus species are naturally occurring at aerobic
liquid-manure-wetted surfaces. Full scale digesters have claimed 80-99% H2S
reduction, down to 20-100 ppm, by adding
44
States during the 1950s, but operation was not well understood (Carlson and Leiser
1966). Sulfur compounds are a major component of malodor in gases and are
produced during biochemical reduction of inorganic or organic sulfur compounds.
Many soils do exhibit a small chemical adsorption capacity for H2S that is heavily
dependent on the iron content of the soil (Bohn and Fu-Yong 1989). It has since been
determined that sustained effectiveness of soil or other biofiltration beds arises
primarily from microbial oxidation of organic compounds, leading to biomass
formation and nontoxic odorless products, or oxidation
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