#H2S Removal

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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

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H2S REMOVAL

Transcript of #H2S Removal

  • 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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    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

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    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

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    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

  • 12

    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