REMOVAL OF HYDROGEN SULFIDE FROM BIOGAS USING COW-MANURE COMPOST
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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
Transcript of REMOVAL OF HYDROGEN SULFIDE FROM BIOGAS USING COW-MANURE COMPOST
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 19-43°C 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: Henry’s 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 EPA’s 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 1970’s and
1980’s 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/SOLISEPARATOR
(Used todigester te
(~60% CH4, ~40% CO2
<4000ppm H2S)
(500 cow free-stall milking facility) Hea
(60-8contin
Elec
Irrigated Nutrients
ENGINE/GENERATOR
COMPOSTING FACILITY(Open windrow system)
LIQUID STORAGE LAGOON (9000 m3 capacity)
ANAEROBIC DIGESTER(1330 m3 plug flow
Biogas (1100-1400 m3/day)
Liquids Solids
Manure
LIVESTOCK
Figure 2.1: Schematic of AA Dairy Integrated Farm Energy System
D
maintain mperature)
t
0 kW uously)
tricity
Compost
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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.
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•
•
•
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 tank
Level of Technology Low Medium Low
Additional Heat No Yes Yes Total Solids 0.5-1.5% 3-11% <11% HRT (days) 40-60 15+ 15+ Farm Type Dairy/Hog Dairy/Hog Dairy only
Optimum Climate Temperate/Warm All All Source: Roos and Moser (2000), AgSTAR Handbook, pgs.1-2
There are two ways to derive methane from biomass, thermally and
biologically. Although thermal conversion is rapid and complete, it is limited in its
application to materials of low water content. This is because large amounts of energy
are needed to vaporize water before reaching substrate-gasification temperature.
Biological conversions, utilizing methanogenic bacteria, are advantageous because
they require less energy and can be applied to wet or dry feedstock on a variety of
scales. Unfortunately, anaerobic digestion is often slow, requires precise solids
loading and an anoxic environment, and is only about 50% effective in its conversion
of organic matter.
The microbial process of anaerobic digestion and methane production occurs
through the complex action of interdependent microbial communities as depicted in
Figure 2.2. The first step involves the hydrolysis of organic compounds, including
carbohydrates, proteins, and lipids, via hydrolytic bacteria. Here, the substrate is
broken down into usable-sized molecules such as organic acids, alcohols, neutral
compounds, hydrogen and carbon dioxide. The second stage, carried out by
transitional bacteria, consists of converting soluble organic matter into methanogenic
substrates such as hydrogen, carbon dioxide and acetate. Lastly, methanogenic
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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 (VOC’s) 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: ~ 25°C 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 Huntington’s 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 GAC’s, which have a highly porous adsorptive
surface. Utilization of GAC’s 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, GAC’s impregnated with alkaline or oxide coatings are utilized.
Impregnated Activated Carbons
Coating GAC’s 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.) 6.3×10-6 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
2.19–2.23 (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 5.3×10-6 - 6.7×10-6 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 Dairy’s. 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 Henry’s law constants for biogas
components in water.
Table 2.16: Henry’s 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 25°C, 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
25°C –35°C. 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 <5% air with a simple air pump. Yellow
clusters of sulfur are deposited on surfaces, increasing chances of corrosion. Care
must also be taken to avoid explosive gas mixtures (Nijssen, et al. 1997).
2.7. BIOLOGICAL H2S REMOVAL METHODS
2.7.1. History and Development
To biologically address the problem of malodorous air, open-bed soil filters
began to be used in the 1920’s and industrial soil biofilters first appeared in the United
44
States during the 1950’s, 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 of inorganic compounds (such
as sulfides), which supply energy to cells and produce odorless compounds like
elemental sulfur and sulfate in the process (Ottengraf 1986).
Biologically active agents have since been used in a variety of process
arrangements, such as biofilters, fixed-film bioscrubbers, and suspended-growth
bioscrubbers (Dawson 1993). These processes may also be effective at removing
multiple contaminants from a gas stream, increasing their functionality. Fluidized-bed
bioreactors have recently been tested for simultaneous removal of H2S and NH3 with
promising results (Chung, et al. 2001). It is also possible to achieve co-treatment of
volatile organic compounds and H2S in the same biofilter (Devinny, et al. 1999).
Reviews on exhaust gas purification for odor control, microbiological
treatment of H2S containing gases, and biofiltration for air pollution control have been
published that summarize the current state of the art (Ottengraf 1986, Jensen and
Webb 1995, Devinny, et al. 1999). A general biofiltration process may include the
elements illustrated in Figure 2.9.
45
Figure 2.9: Biofiltration System Schematic Source: Swanson and Loehr (1997)
There are many companies specializing in the design and operation of
biofilters for pollution control, including TRG biofilters, Bohn Biofilter Corporation,
Biorem Technologies, Biocube, Inc., and Envirogen, among others.
2.7.2. Biological Sulfur Cycles
Sulfur exists in many oxidation states from +6 (SO4) to –2 (H2S).
Transformations take place at significant rates both chemically and biologically. The
global balance of sulfur is depicted in the Figure 2.10.
46
Figure 2.10: The Global Sulfur Cycle. (Artificial emissions are derived from human activities. An asterisk indicates a
process that is partially or solely due to microbial action.) Source: Madigan, et al.(2000), pg 688.
Most sulfur in the Earth’s crust is contained in sulfate minerals, such as
gypsum, and sulfide minerals, such as iron pyrite. The oceans constitute the most
significant reservoir for sulfur, mostly in the form of inorganic sulfate. The biological
sulfur-cycle due to microbial involvement is depicted in Figure 2.11.
47
Figure 2.11: Biological Redox Cycle for Sulfur Source: Madigan, et al. (2000), pg 687.
H2S is produced from bacterial sulfate-reduction in Desulfovibrio,
Desulfobacter, Desulfuromonas, and many other hyperthermophilic Archaea, via the
overall pathway shown in Equation 2.26.
SO42- + 8 H H2S + 2 H2O + 2 OH- (2.26)
Once present, other microorganisms can use H2S oxidation to gain energy.
Various groups of organisms can oxidize reduced sulfur compounds under aerobic or
anaerobic conditions, including:
• Colorless sulfur bacteria (aerobic, i.e.: Thiobacillus, Beggiatoa, Thiothrix, etc.)
• Green sulfur bacteria (anaerobic, phototrophic, i.e.: Chlorobium, etc.)
• Purple sulfur bacteria (anaerobic, phototrophic, i.e.: Chromatium, Thiocapsa, etc.)
48
Colorless sulfur-oxidizing bacteria are most widely used to oxidize H2S using
oxygen as an electron acceptor. This process is preferred because growth rates are
significantly higher and there are no light intensity requirements. Thiobacillus species
are thought to account for a majority of sulfide oxidation, via the sulfite-oxidase
pathway as described in Figure 2.12 below.
Figure 2.12: Steps in the Oxidation of Sulfur Compounds by Thiobacillus Species.
The most energy is released when sulfide is oxidized completely to sulfate as
seen in Equation 2.27. Sulfide oxidation often occurs in steps with elemental sulfur as
an intermediate product, as seen with Equations 2.28-2.29, and in oxygen-limited
environments, oxidation may proceed only to elemental sulfur, producing less energy.
Cells can either deposit sulfur inside or outside of their cell membranes. Other
reduced sulfur compounds, such as thiosulfate, can also be oxidized for energy as seen
in Equation 2.30.
Source: Yang (1992), pg 24.
49
H2S + 2 O2 SO42- + 2 H+ (∆G0’ = -798.2 kJ/rxn) (2.27)
HS- + ½ O2 + H+ S0 + H2O (∆G0’ = -209.4 kJ/rxn) (2.28)
H+
Table 2.17 references several studies on biofiltration of H S with specific
bacterial populations.
cific Microorganisms Studied for Biofiltration of H
S0 + H2O + 1½ O2 SO42- +2 (∆G0’ = -587.1 kJ/rxn) (2.29)
½ S2O32- + ½ H2O + O2 SO4
2- + H+ (∆G0’ = -409.1 kJ/rxn) (2.30)
2
Table 2.17: Spe 2S
MICROORGANISM REFERENCE
T Degorce-Dumas, et al. (1997), Nishimura and Yoda hiobacillus species (1997), Koe and Yang (2000), Oh, et al. (1998) Thiobacillus thioxidans
Sublette, et al. (1994), Sublette and Sylvester (1987a, 1987b)
Thiobacillus thioparus Cho, et al. (1992), Cadenhead and Sublette (1990) Jensen and Webb (1995)
Thiobacillus novellas Chung, et al. (1998) Thiobacillus versutus Cadenhead and Sublette (1990)
Thiobacillus neopolitanus Cadenhead and Sublette (1990) Pseudomonas putida Chung, et al. (1996, 2001)
Hyphomicrobium Zhang, et al. (1991) Cho, et al. (1992)
Reaction products from m ganisms include sulfates and H+,
which form sulfuric acid in the leachate and reduce the pH. Some Thiobacillus
species
drop.
any of these microor
Cho, et al. (2000), Cadenhead and Sublette (1990)
Thiobacillus denitrificans
Thiobacillus ferrooxidans
Xanthamonas species DY44
are acidophilic and therefore function adequately at low pH, but organic media
tends to degrade under these conditions causing plugging and increased pressure
Investigations of different media have been done with respect to H2S removal in
biofilters, as summarized in Table 2.18.
50
Table 2.18: Media Tested for Biofiltration of Hydrogen Sulfide
ORGANIC MEDIA REFERENCE Soil Carlson and Leiser (1966)
Peat Furusawa, et al. (1984), Hartikainen, et al. (2001), Kim, et al. (1998 991), Degorce-
t al. (1992) ), Zhang, et al. (1
Dumas, et al. (1997), Cho, eRands, et al. (1981), Yang (1992), Wani, et al. (1999), Sun, et al. (2000) Yang (1992), Degorce-Dumas, et al. (1997) Elias, et al. (2002) Langenhove, et al. (1986),Oh, et al. (1998)
Rock Wool Kim, et al. (1998) NORGANIC MEDIA REFERENCE
Lava Rock Cho, et al. (2000)Koe and Yang (200
Calcium-alginate Beads Chung, et al. (1996) ite and Cera Kim, et al. (1998)
Desirable attributes for bio clude high surface area, low
pressure-drop characteristics, good moisture retention properties, durable in their
active e
and
A comprehensive study of operational parameters, design, and basic kinetic
modeling for removing H2S from air with composted sewage sludge and yard waste
was co
filter support media in
Compost
Sludge Pig Manure/Sawdust
Wood Bark and Waste (Wani, et al. (1999) Activated Carbon
I
Poly-propylene Rings 0)
Fuyol mics
nvironment, can provide a source of nutrients for an active biolayer, and
support a diverse community of microbes. The trade-off between organic and
inorganic media is traditionally that organic composts have vibrant microbial
populations and form extremely active biolayers, but degrade quickly at low pH
have higher pressure-drops than some inorganic carriers.
2.7.3. Example Applications
nducted by Yang and Allen (1994). Variables studied include temperature,
residence time, concentration, loading rate, compost sulfate level, acidity, and water
51
content. H2S removal efficiencies greater than 99.9% were noted using yard waste
composts and inlet concentrations ranging from 5 to 2650 ppm. Maximum
elimination capacities for the composts ranged from 11.5 to 130 g S/m3-solids/hr
(Yang and Allen 1994a, 1994b).
Elias, et al. (2002), operated an H2S biofilter using compressed composted
manure and sawdust for 2500 hou
pig
rs with over 90% removal efficiency. H2S loading
in air w
ed pig- and cow-manure media, mixed with
woodch
ard-
e horse-
0% CO2, and
0.5-2.0
s.
ome
as in the range of 10–45 g H2S/m3-solids/hr with empty-bed residence times of
13-27 seconds. No chemical additions were needed for buffering or nutritive reasons
during operation. Elemental sulfur was the main sulfur product accumulated (87.5%
of sulfur) in the bed. Only a small pH drop was noticed, so leaching of heavy metals
was not significant (Elias, et al. 2002).
Manure composts have been used for biofiltration of other compounds as well.
Chou and Cheng (1997) tested compost
ips and activated sludge, for removing methyl ethyl ketone (MEK), and
achieved removal rates of around 50 g/m3-solids/hr (Chou and Cheng 1997).
Cardenas-Gonzalez, et al. (1995), compared properties of immature and mature y
waste and horse-manure composts for biofiltration of VOC’s and found that th
manure compost had higher microbial activity and shorter acclimation time, but was
not as stable for long term operation (Cardenas-Gonzalez, et al. 1999).
Degorce-Dumas, et al. (1997), tested biofilter columns with peat and dry
wastewater sludge on actual biogas (characterized as 50-60% CH4, 40-5
% H2S), mixed 2:1 with air. The H2S concentration in the gas stream was
measured at 3260 mg/m3 (2375 ppm), and the column maintained 100% removal
efficiency for 10 days at a loading rate of 129 g H2S/m3-solids/hr. Autoclaved
compost, used as a control, showed only 60% H2S removal under similar condition
A Henry’s law calculation indicated that the abiotic removal efficiency cannot c
52
only from H2S absorption into water, but must also be from chemisorption (Degorce-
Dumas, et al. 1997).
Gadre (1989) also passed actual biogas from a lab scale anaerobic digester
(~55% CH4, ~42.5% CO2, and 2.04% H2S) through a 50-mL glass-bead-packed
biotrick
h
9.5%
for
lizing Thiobacillus ferooxidans in a packed bed of peat
or refus
%
llus thioxidans on
porous
s study,
ling filter washed with innoculum isolated from distillery wastewater. The
collection vessel for the wastewater was open to the atmosphere and assumed to
contain aerobic Thiobacillus species due to a pronounced drop in pH to 3.0. 69.5%
H2S removal was achieved at a loading rate of 187 mg H2S/day (Gadre 1989).
Nishimura and Yoda (1997) performed a similar experiment with a more methane ric
biogas (~80% CH4, ~20% CO2, and 2000 ppm H2S), and were able to achieve 9
reduction in H2S with a gas flow of 40 m3/hr in a 3 m3 bubble column reactor
(Nishimura and Yoda 1997).
A German patent issued to Neumann, et al. (1990), describes a method
removal of H2S from biogas uti
e-compost. Although flow rates and oxidation rates are not mentioned,
experimental results indicate a product gas with 59.8% CH4, 30.8% CO2, undetectable
H2S, 9.1% N2, and 0.5% O2, was produced from an inlet gas with 65% CH4, 34.0
CO2, 1.0% H2S, 0.0% N2, and 0.0% O2 (Jensen and Webb 1995).
To investigate inorganic media supports for durability during low-pH H2S
biofiltration, Cho, et al. (2000), specifically immobilized Thiobaci
lava rock. The rock showed favorable moisture retention and resisted
excessive pressure drops. Increased removal capacities up to 428 g S/m3-solids/hr
were reported with space velocities of 300-hr-1 (Cho, et al. 2000). In a previou
Cho, et. al. (1992), reported 89%+ removal of dimethyl-sulfide, methanethiol,
dimethyl-disulfide, and H2S with a Thiobacillus thioparus biofilter treating exhaust
gas from a night-soil (septic sludge) treatment plant (Cho, et al. 1992).
53
Koe and Yang (2000) also tested Thiobacillus thioxidans with plastic packing
and found that for gas-retention times greater than five seconds and a loa
ding rate
below 9
conditi
ue to
.
tration of photoautotrophic growth of a
Chloro
nd
.
ested
system
aq
al scrubber with
0 g S/m3-solids/hr, 99% H2S removal was obtained (Koe and Yang 2000).
H2S levels up to 10,000 ppm were oxidized by Sublette, et. al. (1994), with
pure cultures of Thiobacillus denitrificans in less than 2 seconds under anoxic
ons. Here, added nitrate, rather than oxygen, served as the terminal electron
acceptor. These reaction times indicated that limitations in H2S removal were d
mass transfer rather than biological limitations. Up to 97% reduction in inlet H2S
levels were achieved (Sublette, et al. 1994).
Anaerobic bacteria have also been used for H2S oxidation from gas streams
Cork, et al. (1983), provided the first demons
bium species with continuous inorganic gas feed (3.9% H2S, 9.2% CO2, 86.4%
N2, and 0.5% H2). The reaction was completed in a 1-L clear vessel with an external
light source. With a removal efficiency of 99.6% H2S, elemental sulfur and biomass
were the main reaction products (Cork, et al. 1983). Subsequent work with
Chlorobium species has been done (Kim, et al. 1997; Henshaw and Zhu 2001;
Kobayashi, et al. 1983) and an economic estimate of $2.82–$4.24 per thousa
standard cubic meters for gas desulfurization has been made (Basu, et al. 1996)
A few commercial biological processes exist specifically for energy gas
desulfurization. The Biopuric process (Biothane Corporation) has designed and t
s for H2S removal from gas streams similar to those found at agricultural
anaerobic-digestion facilities (1500–7000 m3 gas/day and 1000–27000 ppm H2S) with
consistent removal efficiencies over 97%. These systems generally cost $75,000–
$100,000 for capital investments alone (Lanting and Shah 1992).
Another biological process targeted at sour gas desulfurization is the Thiop
Process (UOP). SO2 and H2S are absorbed in a traditional chemic
54
sodium
r
With integrated farm energy systems, the opportunity exists for improvements
in gas processing by utilizing on-farm compost and biological processes for H2S
remova
n
n
m
bicarbonate solution (Ruitenberg, et al. 1999). Pressures in the scrubber are
often elevated to 6000 kPa to enhance absorption (Janssen, et al. 2000). The spent
liquid is then regenerated in a separate bioreactor, producing elemental sulfur. 99%
H2S removal is reported and 90-95% of the sulfur is recoverable. A $1.7 million
Thiopaq installation removed 2.76% H2S from 2000 m3 gas/hr to less than 10 ppm,
while recovering 96% of the sulfur. Operating costs were estimated at $65/day fo
nutrients, 75 kWh/hr of electricity, and 180 kg/day of NaOH (UOP 2000).
2.8. RESEARCH STATEMENT
l. While there is a wealth of operational and research experience on
biofiltration for odor control, there is a relatively limited amount of information o
biofiltration for gas processing to purify biogas. No studies, to this author’s
knowledge, exist where anaerobically digested and composted dairy-manure has bee
tested for its capability to selectively remove H2S, often at elevated levels, fro
biogas. The following research directly addresses this need.
CHAPTER
3. MATERIALS AND METHODS
An experimental approach was used to investigate the suitability of digested
cow-manure compost for removal of H2S from biogas. Test reactors were constructed,
packed with compost, and exposed to actual biogas on-site at AA Dairy. The
experimental setup was located in the enclosed, but non-environmentally controlled,
engine room.
3.1. REACTORS
3.1.1. Small Reactors
Four reactor columns were built using 0.10 m (4 inch) ID, schedule-40 white
polyvinyl chloride (PVC) pipe. Each reactor is 0.5 m in length with female adapters
and male cleanout plugs on each end. Although clear pipe would have been desirable
for observing the compost, white pipe was used due to budget limitations. Type 316
stainless steel woven wire discs (0.032 inch wire with 8 x 8 wires per inch) were glued
into the columns 0.1 m from the end for packing support. Plastic 6.35 mm (¼ inch)
barbed fittings were placed in the center of each cleanout plug and 0.05 m from the
column ends for gas delivery and sampling with 6.35 mm flexible PVC tubing. The
small reactors are depicted in Figure 3.1. Two of the small reactors were equipped
with liquid leachate recycle capability using a Cole-Parmer peristaltic pump with dual
heads, as shown in Figure 3.2. Three-millimeter holes were drilled in all small
columns at 0.05, 0.25, and 0.45 m lengths for thermocouple insertion.
55
56
4
3
0.5 m
0.3 m
1
1
2
LEGEND:
T = Thermocouple 1 - PVC End Caps G = Gas Sampling Port 2 - Top of Bed IN = Gas Sample Inlet 3 – PVC Pipe OUT = Gas Sample Outlet 4 – Wire Screen
0.1 m
OUT
IN
T
T
G
G
T
0.05 m
0.05 m
Figure 3.1: Schematic of Small Columns
57
0.05 m
G
T
IN
OUT 4 1
0.5 m
OU
Figure 3.2
T
G
3
0.3 m
0.1 m
LEGEND:
T = Thermocouple 1 G = Gas Sampling Port 2 IN = Gas Sample Inlet 3T = Gas Sample Outlet 4
5
: Schematic of Small Co
T
- PV - Top - PVC- Wir – Per
lumn
0.05 m
4
2
1
5
C End Caps of Bed Pipe
e Screen istaltic Pump
s with Leachate Recycle
58
3.1.2. Large Reactors
Two identical 0.16 m (6.355 inch) ID by 1.5 m length clear PVC (ALSCO
Industrial Products, Inc.) columns were constructed with 3.175 mm wall thickness.
Each column was divided into three sections for easy inter-column gas sampling,
accessible compost loading, and to prevent compaction, as seen in Figure 3.3.
Specially constructed couplers lathed from 0.15 m (6 inch) ID schedule-40 white-PVC
pipe were used in conjunction with plastic draw latches and neoprene O-rings (size
362) to seal the sections. The same stainless steel screen used in the small reactors
were reinforced with 6.35 mm aluminum bars and glued into place as a bed support.
Silicone sealant was used to seal any leaks because of insufficient o-ring seating.
Barbed plastic fittings (6.35 mm) were installed before and after each bed
section for gas sampling with 6.35 mm clear-PVC flexible tubing. Inlet and outlet gas
ports were 6.35 mm plastic ball valve fittings. Thermocouples were inserted into the
center of each bed section and near the gas inlet and outlet ports for temperature
measurement.
PVC and 316 stainless steel materials were chosen because they are not
affected by exposure to methane, carbon dioxide, hydrogen sulfide, or dilute
concentrations (<75%) of sulfuric acid (Cole Parmer 2002). All reactors were
pressure tested in the laboratory to 34.5 kPa using compressed air, and no leaks were
detected.
59
T 0.05 m 1
OUT
T
G
G
G
G
0.3 m
1.5 m
N
4
5
3
2
1
LEGEND:
T = Thermocouple 1 - G = Gas Sampling Port 2 IN = Gas Sample Inlet 3 -OUT = Gas Sample Outlet 4 –
5 –
Figure 3.3: Schematic o
T
0.4 m
TT
IPV- W PV PlPV
f L
0.05 m
C End Capsire Screen C Pipe
astic Latches C Couplers
arge Columns
60
3.2. EXPERIMENTAL SETUP ON SITE
Piping was established so that a small portion of biogas could be diverted to
the test columns and returned to the original pipeline upstream of the engine, as shown
in Figure 3.4. Existing piping enabled digester gas at 0.75–1 .0 kPa to enter three 250-
W blowers, boosting the pressure to around 3 kPa. From here gas passed through a
solenoid valve that regulated the positive pressure of the engine intake to about 1.5
kPa. As shown in Figure 3.4, a 5 cm (2 inch) PVC tee was installed with a ball valve
(Banjo Corporation) between the blowers and the solenoid valve. 5 cm ID PVC
piping was run approximately 5 m to the column test area and terminated with an end-
cap with 6.35 mm barbed fitting installed. From here, pumps were used to boost gas
pressure and the biogas stream could be split, as needed, depending on the
experimental configuration.
An exhaust manifold consisting of 3 m of 3.173 mm (1.25 inch) ID, schedule-
40, white PVC pipe was installed. A specially constructed steel box, containing a
rectangular automobile air filter element, was placed downstream of the manifold to
protect the engine from any particulate blow-over from the experimental columns.
The tested biogas was then returned to the main biogas pipeline downstream of the
solenoid valve. Another Banjo™ ball valve was placed at the return intersection to
enable complete shut-off of the experiment stream when not in use.
Figure 3.4: Experimental Setup at AA Dairy
62
Two vacuum pumps were used to provide the additional head needed for the
experimental columns; a larger pump and a smaller pump for use with respective
columns. The larger pump was a 370-W Sargent-Welch 1402 Duoseal single-phase
pump. Biogas was fed to the vacuum inlet of the pump through a 3 m length of 6.35
mm ID brass tubing and exhausted to a multi-ported manifold on the positive pressure
side of the pump. A Speedaire airline oil-removal filter and pre-filter were installed
on the inlet side of the pump to remove oil, particulates and some moisture. The pump
is specified to deliver 9.5 m3/hr at standard temperature and pressure, but only
delivered 3.3 m3/hr due to resistance on the inlet side. The original pump configuration
produced a significant amount of oil mist in the outgoing gas stream. A mist
eliminator was designed, constructed, and installed on the outlet side of the pump by
John Poe Tyler (Tyler 2001). The smaller pump was a “Neptune Dyna-Pump” vacuum
diaphragm pump and was operated without inlet or outlet filters.
Compressed air was available at the test site and regulated by a single-stage
Speedaire regulator before being delivered to a block of multiple,variable-area flow-
meters, or “rotameters” (Dwyer Instruments, Inc.). Biogas and air were mixed
together at a tee connector on the inlet side of the humidification vessels.
To humidify the incoming gas, all inlet gas streams were bubbled through 1-L
plastic Nalgene bottles initially filled with 750 ml of distilled and deionized water. A
schematic of the simple humidification and mixing vessel is provided in Figure 3.5.
63
Biogas Inlet
Air Inlet
Figure 3.5: Humidifier and Air/Biog
Two of the smaller columns were outfitted wi
consisting of a Cole-Parmer peristaltic pump with dua
With a tubing size of 1/16”, flow rates up to 7 ml/min
forced liquid to the top of the column where a drop w
steel screen was placed 0.05 m below the recycle inle
fell across the top of the media.
Gas flow rates were controlled with Gilmont A
meters (Barnant Company). Rates are measured by v
the float with a graduated scale, calibrated for liters p
temperature and pressure. Correction Equations 3.1-3
measuring gases other than air under non-standard co
000 00120.0
GAG qq
ρ=
∑=i
iiG x1
00 ρρ
TPqq GG
530760
0' ⋅=
Mixed Sample Gas Outlet
as Mixing Vessel
th a leachate recycle loop
l heads, as shown in Figure 3.2.
were achievable. The pump
ould form. Another stainless
t port to disperse the droplet as it
ccucal™ variable-area flow-
isually correlating the center of
er minute of air at standard
.3 can be applied when
nditions: (Gilmont 1993)
(3.1)
(3.2)
(3.3)
64
Where q = Standard gas flow 0G
= Standard air flow reading from meter 0Aq'Gq = Gas flow at P (operating pressure) and T (operating temperature)
with volume corrected to measurement at standard conditions 0Gρ = Density of gas in g/ml at standard conditions
ix = Mole fraction of ith gas component 0iρ = Density of ith gas component in g/ml at standard conditions
Assuming measurement at standard temperature and pressure, and
approximating biogas as 60% methane ( = 0.00072 gm/ml), and 40% carbon
dioxide ( = 0.00198 gm/ml), the corrected rotameter value calculated with
Equation 3.1, for biogas, becomes = 0.992 . Therefore, readings for air and
biogas are nearly the same.
04CHρ
02COρ
0Gq 0
Aq
3.3. GAS SAMPLING AND MEASUREMENT
Flexible PVC sample lines (6.35 mm ID) were run from the column gas
sampling ports to the inlet ports of a 16-channel multi-position valve (Valco
Instruments Co., Inc.). The desired sample line was selected with a digital controller,
and the outlet line from the switching valve was connected through a rotameter to the
H2S detector. Since the columns were operated under slight positive pressure, opening
the appropriate sample path allowed gas flow to the detector.
3.3.1. Electrochemical Sensor
An electrochemical, Toxi-Plus single gas detector (Biosystems, Inc.) was used
for H2S monitoring. The detector was equipped with a 0-100 ppm 4HS CiTiceL® H2S
65
sensor (City Instruments, Inc.). A plastic calibration adapter provided by Biosystems,
Inc., enabled direct sampling of a gas stream, provided a flow rate near 1 liter per
minute.
The electrochemical sensor has been carefully designed to minimize the effects
of common interfering gases, but some interfering gases may still have either a
positive or negative effect on the sensor readings. Table 3.1 indicates deviation of
measured H2S values with respect to a number of substances. The table is not meant
to be complete, as there may be other gases to which the sensor responds.
Table 3.1: Cross Sensitivity Data for Electrochemical H2S Sensor
(Number reported is sensor response to 100 ppm of selected test gas)
Compound Response CH4 0 CO2 0 CO < 2 Cl2 -20
(CH3)S 10 CH3SH 45
H2 < 0.5 NO2 -20 O3 -30 SO2 < 20
Source:City Technolgy Limited (2002)
Calibration of the sensor is recommended on a daily basis and was done with
certified-standard 24.7 ppm H2S in nitrogen (Empire AirGas, Elmira, NY) supplied in
a size-33A cylinder containing 850 liters of product. A dual-stage, stainless-steel
regulator (CGA #330: Matheson Tri-Gas) delivered calibration gas to the sensor.
Since H2S concentrations in the biogas were outside the range of the sensor, an
air dilution method was developed and utilized. Compressed air delivered through a
rotameter at 3.9 liters per minute was continuously combined with 0.1 liters per
minute of sample gas at a plastic tee, creating a 40-fold dilution of the sample stream.
66
The gas mixture then entered a 1-liter sealed plastic mixing vessel similar to the
humidification vessel depicted in Figure 3.5, but without water. The effluent from the
mixing vessel was sent directly to the electrochemical sensor for measurement.
The H2S measurement protocol with the electrochemical sensor was as
follows:
1) Select desired sample channel from multi-position valve
2) Adjust gas sample flow rate from outlet of multi-position valve to 0.1 lpm
3) Adjust air flow rate to 3.9 lpm
4) Let gas mix and allow meter reading to stabilize (~4 minutes)
5) Repeat steps 1-4 for additional sample streams
3.3.2. Gas Sampling Tubes
Gas detection tubes employing chemical reaction with lead acetate (Sensidyne)
were used for additional measurement of H2S in the sample streams. The reaction in
Equation 3.4 occurs in the detector tube, causing a brown stain to form that can be
directly read for H2S concentration.
H2S + Pb(CH3COO)2 PbS + 2CH3COOH (3.4)
A model 8014-400A (Matheson-Kitagawa) hand aspirated pump was used to
draw known volumes of sample through the detector tubes. Hydrogen-sulfide
detector-tubes (Kitagawa type 120SA) with a measuring range from 100-2000 ppm
were utilized. The scale on the detector tube is calibrated for 20°C and atmospheric
pressure. The manufacturer provides a temperature correction table and pressure
correction equation for measurements at non-standard conditions. H2S gas detector
tubes also exhibit cross-sensitivity interferences similar to those described for the
electrochemical sensor.
67
3.3.3. Gas Chromatography
The Mass Spectrometry Facility, Department of Chemistry and Chemical
Biology, at Cornell University performed gas chromatography/mass spectrometry
analysis on one sample of raw digester gas. The sample was delivered in a 0.3 liter
Tedlar® gas sampling bag with a rubber septum valve (Cole-Parmer).
3.4. TEMPERATURE MEASUREMENT
Gas temperatures before and after each column, bed temperatures, and ambient
air temperatures were monitored with thermocouples and a computerized data
acquisition system. The hardware and software systems used are modified versions of
those described by Hall (1998).
Data acquisition hardware components from Computer Boards, Inc., were
utilized. Type-T (copper-constantan) thermocouples with welded and silicone coated
ends were inserted into the center of the reactor cylinders at locations previously
displayed Figures 3.1-3.3. Thermocouple wires were then connected to an EXP-32
thermocouple multiplexor board capable of handling 32 differential inputs and
equipped with onboard amplification and cold junction compensation. A CIO-DAS-
08, 12-bit analog-to-digital conversion board was installed in a Gateway PC with
Pentium I processor for multiplexor control and data acquisition.
A software program was written in Pascal 6.0, using the DOS 3.1 operating
system, to display and log desired temperatures. Temperatures are recorded into
temporary storage every 15 seconds for 15 minute periods. After each period, the
average, standard deviation, maximum, and minimum for each input channel are
stored into a computer data file and the cycle is repeated. Further documentation of the
software is provided in the program itself.
68
3.5. PRESSURE MEASUREMENT
Pressure measurements were made using Magnehelic® analog pressure sensors
(Dwyer Instruments, Inc.) with 0-1” H2O, 0-2” H20, and 0-5 psi ranges. Pressure drop
across a bed section was easily measured by disconnecting the appropriate sample
lines entering the multi-position valve and connecting them across the pressure sensor,
as shown in Figure 3.4.
3.6. COMPOST CHARACTERIZATION
The compost tested in this study was taken from the “finished compost” pile
on-site at AA Dairy. This medium consists only of anaerobically-digested separated-
solids that have been composted, using an outdoor windrow system, for at least 60
days. Samples from three spots around the pile were mixed together in a 15-liter
plastic pail to create representative samples. Tests performed on compost after
exposure to biogas may be from a specific part of the test column or from a well-
mixed sample of the entire contents, as stated in each method.
3.6.1. Moisture Content
Approximately 10 grams of sample were placed in aluminum weighing dishes,
and then into an 85°C oven for 24 hours. Weights of the samples before and after
were compared to determine percent moisture content. Samples from the tested
columns were taken from the external surface of the column cores at 0.05 m, 0.15 m,
and 0.25 m along its length.
69
3.6.2. Void Fraction:
A modified version of the “5-gallon pail” method, as described by Nicolai and
Janni (2001), was utilized to determine percent void fraction. The following
procedure was used to test the fresh compost:
1) A plastic pail was filled with 5 liters of water and a “full” line marked on
the inside of the pail. The water was then removed.
2) The pail was filled about 1/3 full with compost and dropped ten times from
a height of 15 cm onto the floor.
3) Compost was added to fill the pail 2/3 full. The pail was again dropped ten
times from 15 cm onto the floor.
4) Compost was added to the full line and dropped ten times again.
5) Compost was added to the full line once more.
6) Water was added to saturate the compost to the “full” line and the volume
of water was recorded.
The void fraction is calculated by dividing the volume of water added by the
original solids volume.
3.6.3. Bulk Density
Similarly, the density of 5-liters of fresh compost was determined by weighing
it in an unpacked form and packed form, as described above.
3.6.4. Particle Size Distribution
Distributions of particles were determined by passing them through a stack of
sieves arranged in decreasing mesh-size order and recording the weight retained on
70
each sieve. The mesh-sizes of each sieve were 9.52 mm, 2.36 mm, 1.168 mm, and 0.5
mm. The compost was placed in the largest sieve first and shaken for 2 minutes.
3.6.5. pH
The pH value for the compost was determined by mixing 20 ml of sample with
20 ml of distilled and deionized water in a 100 ml beaker and using a calibrated
Beckman Φ200 pH meter to determine the pH of the solution. As with moisture
analysis, samples from the biogas-exposed compost were taken from the external
surface of the column cores at 0.05 m, 0.15 m, and 0.25 m along the length.
3.6.6. Trace Element Analysis
The Cornell Nutrient Analysis Laboratory (CNAL) performed trace element
analyses by total microwave digestion on 1-liter media samples. For analysis of
biogas-exposed compost, representative mixtures of the entire column contents were
submitted.
3.6.7. Sulfate Content
Samples of fresh compost were tested for sulfate concentrations by ProDairy
(Syracuse, NY).
3.7. OPERATIONAL PROCEDURES
Columns were packed with compost according to steps 2-5 in the “void
fraction” measurement protocol. Each section of bed was filled to 30.5 cm (12
inches), creating bed volumes of 2.47 liters for the small columns and 6.24 liters for
each section of the larger columns, or 18.71 liters for the entire large columns.
71
In all of the trials, a 2:1 mixture of biogas-to-air was used as the test gas for the
columns. This formulation, similar to that tested in peat biofilters by Degorce-Dumas,
et al. (1997), was chosen for two major reasons: 1) To ensure an aerobic environment
to facilitate microbial oxidation with thiobacillus, pseudomonas, or other species that
may exist in composts, and 2) To maintain safe operation outside of the explosion
limits for methane (5-15% in air) and hydrogen sulfide (4-45% in air).
Six different trials were run in these experiments, as described in Table 3.2.
Table 3.2: Summary of Experimental Trial Conditions
Trial Bed
Volume (l)
Total Flow (lpm)
Biogas Flow (lpm)
Air Flow (lpm)
Empty Bed Residence Time (sec)
Linear Velocity (m/min)
Leachate Recycle
1 18.7 11.2 7.5 3.7 98 0.55 No 2 18.7 11.2 7.5 3.7 98 0.55 No 3 2.45 1.5 1.0 0.5 98 0.19 No 4 2.45 1.5 1.0 0.5 98 0.19 No 5 2.45 1.5 1.0 0.5 98 0.19 Yes 6 2.45 1.5 1.0 0.5 98 0.19 Yes
These flow rates and empty-bed residence times were picked to maintain H2S
contaminant loading between 50 – 150 g/m3-solids/hr with expected H2S inlet
concentrations varying from 1000 – 3000 ppm.
In order to test the dilution method and column apparatus, a smaller column
without packing was run with 2:1 biogas-to-air mixture at 1.5 liters per minute for
three hours. Inlet and outlet H2S concentrations were compared using the
electrochemical sensor method previously described.
CHAPTER
4. RESULTS AND DISCUSSION
4.1. ORIGINAL COMPOST CHARACTERISTICS
The finished manure compost was dark brown in color and moist, but not
dripping, when squeezed by hand. The particles of fresh compost crumbled apart like
wet soil when touched. The odor characteristics changed from pungent and offensive
as fresh manure to earthy and soil-like as finished compost.
Figure 4.1: AA-Dairy “Field of Dreams” Cow-Manure Compost
Table 4.1 summarizes the results from characterization of the manure compost
as used in the columns.
72
73
Table 4.1: Cow-Manure Compost Characterization Specification Value Std. Dev.Water Content (Loss on drying, wt%) 72.9% 0.9% Void Fraction 0.35 0.05 Density (g/L)
Unpacked 604 13 Packed 757 18
Particle Size Distribution (wt % retained on sieves) Sieve Sieve Size (mm) 3/8 in. 9.52 16% #7 2.8 62% #8 2.36 9% #14 1.168 10% #35 0.5 3%
pH (in solution) 7.19 0.04 Trace Element Analysis (µg/g dry basis)
Sulfur 7,316 Aluminum 2,145 Arsenic < det. Boron 67 Cadmium < det. Calcium 49,910 Chromium 2 Cobalt 2 Copper 479 Iron 5,487 Lead < det. Magnesium 13,615 Manganese 500 Molybdenum 11 Nickel 39 Phosphorous 11,869 Potassium 13,548 Sodium 3,277 Vanadium 7 Zinc 347 Note: <det = below analyte detection limit Std. Deviations below 1% of reading for all values.
Sulfur Analysis (µg/g dry basis) Sulfate 73 Sulfide as S2
= 579
74
4.2. OPERATIONAL SUMMARY
Trials 1 and 2, using the larger columns, were run for 16 hours during June 10-
12, 2002. Trials 3 and 4, utilizing the smaller columns with no leachate recycle, were
operated for 1,057 continuous hours from July 5 through August 19, 2002. Trials5
and 6, using the smaller columns with leachate recycle, were also started July 5, 2002,
and run for 50.5 and 216.5 hours, respectively.
Due to safety concerns during trials 1 and 2, the 370-W pump was not operated
while unattended. The high output of the pump could create an asphyxiating or
explosive air safety problem in the event of a leak. During operation, moisture would
accumulate in the pump’s inlet oil-filter bowl and have to be emptied every 4 hours.
Moisture also quickly appeared in all of the variable-area flow meters, causing
oscillation of flow. The flow meters were left at their original setting during this
oscillation. Despite attempts to seal large reactor joints with silicone sealant, gas and
liquid leaks were noticed at various times during operation. Because of this
observation, no data is reported for trials 1 and 2.
Trials 3-6 were started simultaneously using the 370-W vacuum pump, but, in
order to allow unattended operation, it was replaced with the smaller Neptune Dyna-
Pump after 10 hours of operation. Results from trials 3 and 4 are the major focus of
the following discussion because prolonged and consistent operation was logged.
Additionally, only compost from trials 3 and 4 were analyzed for chemical
composition after the trials. Trials 5 and 6, which included leachate recycle, were both
terminated prematurely due to increasing pressure drop in the bed and the inability to
provide sufficient flow to all columns with the smaller pump.
Moisture also condensed in the variable-area flow meters within the first hour
of trials 3-6. Flow rates were double-checked daily by temporarily inserting a clean,
75
dry, flow meter into the sample line. A small and unmeasured amount of liquid was
periodically lost during manual removal of sample lines to attach pressure sensors or
flow meters. The moisture was in the form of water vapor expelled due to the sudden
drop in column pressure to atmospheric, and estimated to be a less than a milliliter per
day per column.
The humidification flasks had to be replenished with 500 ml of water only
once after 700 hours of operation. Condensation was also evident in the clear PVC
lines to and from the columns.
4.3. PRESSURE MEASUREMENTS
For both columns 3 and 4, the pressure drop measured across the bed was
consistently 0.1 inches of H2O, the smallest graduation on the analog pressure scale.
Maximum pressure drops of 0.25 inches of H2O were recorded during the first few
hours only. Column 5, which included leachate recycle, displayed an increase in
pressure drop across the bed from 0.1 to 2.0 inches of H2O during operation.
Similarly, column 6 also displayed an increase in pressure loss from 0.1 to 3.0 inches
of H2O during the first 50 hours of operation. The pressure difference then receded to
around 1.0 inch of H2O for the rest of the trial. Pressure drops across beds are
depicted in Figure 4.2.
76
Pressure Drop Across Bed - Trials 3-6
0
0.5
1
1.5
2
2.5
3
3.5
0 200 400 600 800 1000
Run Time (total hrs)
Pres
sure
(in.
H2O
)
Column 3 - No leachate Recycle
Column 4 - No leachate Recycle
Column 5 - Leachate Recycle
Column 6 - Leachate Recycle
Figure 4.2: Pressure Drop Across Bed for Trials 3-6
The decreases in observed pressure drops are most likely due to the
development of preferential flow patterns within the bed. The pressure range of 0.1-3
inches H20/ft for a 0.2 m/mim linear gas velocity corresponds with published compost
pressure drop data (Yang 1992); Nicolai and Janni 2001).
The following physical factors determine pressure drop across the filter bed:
1) Particle size distribution
2) Porosity
3) Particle shape and orientation
4) Gas viscosity and density
5) Superficial gas velocity
6) Height of the bed
77
Many empirical models have been developed to predict pressure drop through
a stationary bed of particles. The most well know models include the Ergun, Hukill,
and Shedd relations (McGuckin, et al. 1999). The Ergun equation, Equation 4.1
below, can be used to calculate expected pressure drop, including associated values.
( )( )
( )( )pp D
vD
vLP
Φ−
+Φ
−=
∆3
20
230
2 175.11150ε
ρεε
εµ (4.1)
Where LP∆ = Pressure drop per unit length
µ = Gas viscosity ≈ 1240x10-7 Poise @ 20°C ε = Porosity ≈ 0.35
0v = Superficial gas velocity ≈ 0.19 m/min Dp = Characteristic dimension of particle ≈ 2.5 mm
Φ = Particle sphericity ≈ 0.7 for activated carbon ρ = Gas density ≈ 1.16 kg/m3 @ 20°C
With these parameters, the calculated pressure drop for compost is 19.4 Pa/m,
or 0.078 inches of H20/m. This is lower than pressure drops measured experimentally.
Using a characteristic dimension (Dp) of 1.0 mm for particle size resulted in a
calculated pressure drop of 0.15 inches H20/ft, which is in closer agreement with the
measured data. The relatively low gas velocities used here resulted in minimal
pressure drops and did not require the use of bulking agents, as might be necessary in
larger reactors or those with decreased gas residence times.
4.4. TEMPERATURE MEASUREMENTS
The temperature measurement system logged data every 15 minutes when
operating properly. Unfortunately, interruptions to the power supply caused data loss
on multiple occasions and prevented any data collection after hour 431. The
temperature data collected for each column are in Figures 4.3-4.6.
78
Temperature - Column 3
10
15
20
25
30
35
40
45
0 50 100 150 200 250 300 350 400 450
Run Time (hrs)
Tem
p. (C
) (15
min
ute
aver
age)
Inlet Gas Media
Outlet Gas Ambient
Figure 4.3: Temperatures (15-Minute Average) for Column 3
Temperature - Column 4
10
15
20
25
30
35
40
45
0 50 100 150 200 250 300 350 400 450
Run Time (hrs)
Tem
p (C
) (15
min
ute
aver
age)
Inlet Gas Media
Outlet Gas Ambient
Figure 4.4: Temperatures (15-Minute Average) for Column 4
79
Temperature - Column 5
15
20
25
30
35
40
45
0 5 10 15 20 25 30 35 40 45 50
Run Time (hrs)
Tem
p (C
) (15
min
ute
aver
age)
Inlet Media
Outlet Ambient
Figure 4.5: Temperatures (15-Minute Average) for Column 5
Temperature - Column 6
15
20
25
30
35
40
0 20 40 60 80 100 120 140 160 180 200
Run Time (hrs)
Tem
p (C
) (15
min
ute
aver
age)
Inlet Media
Outlet Ambient
Figure 4.6: Temperatures (15-Minute Average) for Column 6
80
The cyclical variation is due to diurnal temperature fluctuation. The ambient
temperature was recorded inside of the engine room and is different than actual
outdoor temperatures. Outdoor temperature, as well as the digester temperature,
influences the inlet-gas temperature, which is why it is possible to observe an inlet-gas
temperature lower than ambient temperature. In all trials, it is observed that the bed
temperature is typically between 0-12°C higher than the inlet temperatures, as shown
in Figure 4.7. This is an indication of heat being generated in the bed, which may be
attributed to an exothermic biological, chemical, or physical adsorption reaction, and
could potentially be used to track bed activity or viability.
Difference Between Bed Temperature and Inlet-Gas Temperature For Trials 3-6
-4
-2
0
2
4
6
8
10
12
14
0 5000 10000 15000 20000 25000
Time (minutes)
Tem
p. D
iff. (
Bed
-Inl
et) [
C]
.
Column 5Column 6Column 3Column 4
Figure 4.7: Temperature Difference Between Bed and Inlet-gas for Columns 3-6
81
Table 4.2 below summarizes the maximum and minimum temperatures seen in
each trial.
Table 4.2: Summary of Temperature Extremes for Trials 3-6
Trial Ambient Temperature Inlet Temperature Bed Temperature # Min(°C) Max(°C) Min(°C) Max(°C) Min(°C) Max(°C)
Column 3 16.7 36.5 13.9 37.8 20.6 42.0 Column 4 16.7 36.5 15.4 38.9 21.5 43.3 Column 5 22.5 33.6 21.4 35.0 24.7 41.9 Column 6 16.7 33.6 14.8 34.5 19.1 39.5
Literature indicates that the optimum range for biological H2S oxidation is in
the range of 30 – 40°C. In general, severe reduction in activity occurs below 10°C and
more moderate reduction of activity above 50°C (Yang 1992). Therefore, these
experiments were operated in the mid-to-high range of known optimum temperature
conditions.
A simplified heat balance can be written to estimate the heat generation in the
bed. Heat accumulation within a packed bed can be written as the sum of the
individual conductive, convective, evaporative and metabolic heat contributions.
Radiation losses are neglected and the media is assumed to maintain its uniform
structure. The overall relation is described by Equation 4.2.
Qaccumulation = Qconduction + Qconvection + Qevaporation - Qgeneration (4.2)
Considering only maximal gradients, unsteady-state heat accumulation can be
written as Equation 4.3 (Gutierrez-Rojas, et al. 1996).
+−+−=
)()( '
outoutininbedambpbed
p hhGTTUAdt
dTC ρρρ
QyyQGA
(4.3)
−− )( genoutinwo
82
Where: ρb = Bulk comp0st density, packed ≈ 750 g L-1 Cp = Medium heat capacity U = Overall heat transfer coefficient Ap = Specific heat transfer area parallel to gas flow ≈ 104 m2 m-3
media Tamb = Ambient Temperature of air ≈ 30°C Tbed = Bed Temperature ≈ 33°C G’ = Specific gas flow rate ≈ 0.01 m3
gas m-3bed s-1
ρin = Inlet gas density ≈ 1.09 kg m-3 @ 30°C ρout = Outlet gas density ≈ 1.08 kg m-3 @ 33°C hin = Inlet gas enthalpy (@ Tin = 30°C) ≈ 744,080 J kg-1 hout = Outlet gas enthalpy (@ Tout = 33°C) ≈ 744,302 J kg-1 G = Gas mass velocity ≈ 0.0023 kg m-2 s-1 A0 = Specific heat transfer perpendicular to gas flow ≈ Ap ≈ 104 m2 m-3
media Qw = Latent heat of vaporization ≈ 2430 kJ kg-1 @ 30°C yin = Water mass fraction of inlet gas ≈ 0.028 kgwater kg-1
gas yout = Water mass fraction of outlet gas ≈ 0.028 kgwater kg-1
gas
Qgen = Heat generation from reaction in the bed t = Time, seconds
Assuming heat accumulation is zero at steady state, and representative steady-
state temperatures (Tamb and Tbed) are grossly estimated from the temperature data for
column 6 (hour 50), many of the physical parameters can be determined. The overall
heat transfer coefficient (U) can be calculated with Equation 4.4 and stated values.
1-1-2- K s m J 29.211
1≈
++=
khh
U
oi
δ (4.4) Where hi = Inside film coefficient ho = Outside film coefficient δ = Reactor wall thickness ≈ 0.00635 m k = Reactor wall thermal conductivity ≈ 0.17 J m-1 s-1 K-1
The inside film coefficient (hi) for packed bed columns with laminar
airflow (Re<2000) was calculated with Equation 4.5-4.6 (Perry, et al. 1997)
83
1-1-2-
365.0
K s m J 65.426.3 ≈
=
εµλ
g
pgi
GDh (4.5)
pD Where λg = Gas thermal conductivity ≈ 0.027 J m-1 s-1 K-1 @ 30°C µg = Gas viscosity ≈ 1275x10-7 Poise @ 30°C
ε = Porosity ≈ 0.35 G = Gas mass velocity ≈ 0.0023 kg m-2 s-1 Dp = Characteristic dimension of particle ≈ 2.5 mm
g
rGDµ
=Re ≈ 1.8 (4.6)
Where Re = Reynolds number, dimensionless
Dr = Reactor diameter ≈ 0.1 m
The outside film coefficient (ho) for a vertical cylinder exposed to natural
convection is determined with Equations 4.7-4.9 (Perry, et al. 1997).
( ) 1-1-2- K s m J 66.2Pr59.0 41
≈= GrL
kh airo (4.7)
Where kair = Thermal conductivity of air ≈ 0.26 J m-1 s-1 K-1
L = Length of heat transfer surface = 0.3 m
2
23
air
air TgLGr
µβρ ∆
= ≈ 1.02x107 (4.8) Where Gr = Grashoff number, dimensionless
ρair = Ambient air density ≈ 1.16 kg m-3 @ 30°C g = Acceleration due to gravity ≈ 9.81 m s-2 β = Volumetric coefficient of Thermal Expansion
= Tamb-1 ≈ 0.0033 K-1
∆T = Temperature difference ≈ 33°C – 30°C = 3°C µair = Viscosity of ambient air ≈1860x10-7 Poise @ 30°C
72.0Pr ≈=air
airpCair
µ (4.9)
k Where Pr = Pandtl number, dimensionless
Cpair = Heat capacity of air ≈ 1.007 J g-1 K-1
Plugging these calculated and assumed values into Equation 4.3, the heat
generated by reaction can be estimated as:
84
Qgen =7.68x104 J s-1 m3bed
Equation 2.27, in chapter 2, gives the theoretical maximum energy produced
from stoichiometric oxidation of H2S. Assuming that all of this energy is given off to
the bed (which is clearly an over-assumption, as 60% of energy is typically utilized by
the cell for growth and maintenance), it is estimated that a maximum of 4.85x102 J s-1
m3bed may be generated solely from oxidation of 1500 ppm H2S to sulfate. This is
much lower than the calculated heat generation value and indicates that there are likely
additional or different exothermic reactions occurring. This is expected since compost
and other organic compounds in the gas are known to degrade in aerobic
environments. Assuming a worst-case scenario where all of this heat is derived from
the oxidation of methane (∆Hrxn = -8.9x105 J/mol CH4), 47% of the methane would be
consumed. This calculation indicates that there is the potential for significant methane
reduction, but further testing is needed to determine the fate of CH4 as methane was
not monitored and no temperature controls were practiced in this experiment.
4.5. HYDROGEN SULFIDE MEASUREMENTS
4.5.1. Electrochemical Sensor
To quantify the error attributed to the electrochemical sensor and dilution
method, linear error propagation can be done. Summing the variances from the sensor
reading and the flow-meter readings for air and gas entering the dilution chamber, the
cumulative standard deviation, neglecting any cross sensitivity interference, given by
Equation 4.10.
40 Reading)Sensor )(1042.2(1600 242
±≅⋅+= −SHσ [ppm] (4.10)
85
Interference would likely raise this error, but the actual amount is difficult to
calculate without knowing all biogas components.
Results from testing the column without packing showed that the inlet and
outlet concentrations remained equal, indicating no apparent interference from the
column materials.
Columns 3 and 4 operated continuously for 1057 hours with an average inlet
H2S concentration around 1500 ppm. Removal efficiency is calculated by dividing the
difference between the inlet and outlet concentrations by the inlet concentration (in
ppm). Similarly, linear error analysis including only instrument variances indicates
that standard deviation for removal efficiency is less than 1.41%. The concentrations
and removal efficiencies for columns 3 and 4 (with associated error bars) are given
with Figures 4.8-4.11.
H2S Concentrations - Column 3
0
500
1000
1500
2000
2500
0 200 400 600 800 1000
Run Time (total hrs)
H2S
(ppm
)
H2S in
H2S out
Figure 4.8: H2S Concentrations for Trial 3 (lines are polynomial fits meant only to guide the eye)
86
Removal Efficiency - Column 3
0%10%20%30%40%50%60%70%80%90%
100%
0 200 400 600 800 1000
Run Time (total hrs)
Rem
oval
Eff
. (%
)
Figure 4.9: H2S Removal Efficiency During Trial 3 (line is polynomial fit meant only to guide the eye)
H2S Concentrations - Column 4
0
500
1000
1500
2000
2500
0 200 400 600 800 1000
Run Time (total hrs)
H2S
(ppm
)
H2S in
H2S out
Figure 4.10: H2S Concentrations for Trial 4 (lines are polynomial fits meant only to guide the eye)
87
Removal Efficiency - Column 4
0%
20%
40%
60%
80%
100%
0 200 400 600 800 1000
Run Time (total hrs)
Rem
oval
Eff
. (%
)
Figure 4.11: H2S Removal Efficiency During Trial 4 (line is polynomial fit meant only to guide the eye)
Column 3 operated consistently above 80% removal efficiency until the last
150 hours when efficiencies declined to 50%. Column 4 started off with high removal
efficiency for the first 250 hours but then dipped to around 50% efficiency by 500
hours. Expecting to see a continued reduction, column 4 was allowed to continue
running but displayed a temporary rebound in removal efficiency to 80% by hour 900.
Similarly to column 3, a drop in efficiency occurred for the last 150 hours of operation
and both columns were shut down for media inspection when the removal efficiency
of both columns dropped below 50%.
The elimination capacity of columns 3 and 4 ranged from 24 – 112 and 16 –
118 g H2S/m3-solids/hr, respectively, as calculated assuming atmospheric pressure and
25°C. The total mass of H2S removed from the gas during these experiments are 135
and 127 g H2S, respectively for columns 3 and 4. An average flowrate and
concentration per sampling interval were used for calculation. This elimination
88
capacity approaches the maximum of 130 g H2S/m3-solids/hr reported for organi
media (Yang and Allen 1994; Degorce-Dumas, et al. 1997).
It is not clear why one column behaved differently tha
c
n the other under similar
conditi
lumn
accompanied by a
lesser d
y
f both
column gas
s
moval efficiencies for columns 5
and 6 (
ut
ons. One possible explanation could assume inherent variability due to
biological systems. The fact that a rebound in removal efficiency occurred in co
4 may support the idea of biological system upset and recovery. A purely chemical
breakthrough would not be expected to behave in this manner.
The dip in efficiency in column 4 around hour 500 is also
ip in efficiency in column 3. The exact reason for these reductions are not
known, but maximum bed-temperatures during this time exceeded 40°C, which ma
have disrupted a biological or physical adsorption mechanism. Temporarily
insufficient moisture availability may also be a possible explanation.
It appears that the simultaneous decline in removal efficiencies o
s after hour 900 occurs in conjunction with a measured increase in inlet
H2S concentration. At hour 900, a minimum inlet H2S concentration of 480 ppm wa
recorded, followed by an increase to over 2000 ppm in 6 days. This quick increase in
loading may also have had the effect of upsetting the system and leading to decreased
removal efficiency. It is also possible that the chemical or physical reaction
mechanism was becoming exhausted at this point.
The inlet and outlet H2S concentrations and re
with associated error bars) are represented in Figures 4.12-4.13. Removal
efficiencies were above 90% and 87% for columns 5 and 6, respectively, througho
their operation.
89
Figure 4.12:H2S Concentrations and Removal Efficiency for Column 5 (lines are polynomial fits meant only to guide the eye)
2
0
500
1000
1500
2000
2500
0 10 20 30 40 50
Run Time (total hrs)
H2S
(ppm
)
0%
20%
40%
60%
80%
100%
Rem
oval
Eff
. (%
)H2S inH2S outRemoval Eff
H S Concentrations and Removal Efficiency - Column 5
Figure 4.13:H2S Concentrations and Removal Efficiency for Column 6 (lines are polynomial fits meant only to guide the eye)
2
0
500
1000
1500
2000
2500
3000
0 50 100 150 200Run Time (total hrs)
H2S
(ppm
)
0%
20%
40%
60%
80%
100%
Rem
oval
Eff
. (%
)H2S inH2S outRemoval Eff.
H S Concentrations ad Removal Efficiency - Column 6
90
4.5.2. Gas Detector Tubes
Diary were sporadically tested for H2S using lead-
acetate in the
Table 4.3: H
Gas samples from AA
H2S detector tubes since November 2000. Table 4.3 shows H2S readings
gas prior to the experiments, and more frequently during the experiments (July-Aug.).
2S Gas Detector Tube Readings for AA Dairy Raw Digester Gas
November 13, 2000 3600 March 4, 2001 2200 July 1, 2001 3400 July 13, 2002 1400 (660)
1400 (1380)
August 5, 2002 August 19, 2002
Note eses) are H2S levels determine ical ogas:air sample. Provided f
July 15, 2002 July 20, 2002 1300 (1680) July 27, 2002 1150 (1440)
1200 (1280) 1700 (1900)
August 22, 2002 1900 : Numbers in (parenth d by the electr
or compochem
sensor on a 2:1 bi arison.
high as 3600 ppm have been measured. H2S levels i
Levels as n the digester
gas dur e
detector tubes are consistently lower that expected
when c
ctor
as
tube itself, allowing for gas to bypass the tube, resulting in a lower reading.
ing the experiment appear significantly lower than in the past. This differenc
may be due to seasonal variation, variability in the feedstock, chemical differences in
the digester, or sampling error.
The readings from the gas
ompared with the electrochemical sensor method. One would expect the
electrochemical sensor method to produce a reading value 2/3 lower than the dete
tube, because the gas sample measured by the electrochemical sensor is diluted with
air, and the H2S detector tubes are always used to measure raw biogas. The low
readings might be attributed to normal error within the reported +/- 25% for the g
detector tubes, or additionally from an incomplete seal from the sampling port to the
91
4.5.3. Gas Chromatography
A calibration standard gas was not tested with the biogas sample so
component are not accessible. Rather, a qualitative
assessment of the major gas components in biogas was completed, as follows.
ates of
quantitative levels of each gas
By taking the relative contributions of the peak readings, rough estim
gas composition can be determined, as presented in Table 4.4.
Table 4.4: GC-MS Results for AA Dairy Digester Gas
Total 1.80*108 -- Component Peak Height % Total % Dry Basis
-- 8 56.24% 62.49%
Carbon dioxide 6.00*107 33.33% 37.04% Hydrogen 0.36%
NH3 pes Dime lfide <0 <0.01%
Methane 1.01*10
sulfide 5.90*105 0.33% and CH iso4
thyl Suto 1.75*105 0.10% 0.11%
6.60*102 .01%Water 1.80*107 10.00% --
As seen here, the relat re content s in this samp out
10%. On a dry-basis, the methane and carbon dioxide concentrations are about what
was expected, ~60% and ~40%, respectively. The H2S content is also in the range of
a few te
2 2
ctively. Similar results for dimethyl sulfide and
ammon
ive moistu of the ga le is ab
nths of a percent, which is in agreement with the other testing methods used
here. Other compounds were not identified due to the absence of specific calibration
gases for testing these compounds.
Figure 4.14 depicts the actual GC-MS results for the digester gas. Each graph
is for a specific mass element. Results for H S, CO , total gas, and water are
represented from top to bottom, respe
ia are not shown here. Each graph is scaled to 100% of the signal intensity,
and the peak height value is given with the scales to the right.
Figure 4.14: GC-MS Results for AA Dairy Digester Gas.
H2S
CO2
Total
H2O
93
4.6. BIOGAS-EXPOSED-COMPOST ASSESSMENT
Columns 3 and 4 were opened 7 days after shutdown for compost inspection.
The solids slid out of the columns easily and appeared dry and whitish-yellow in color
as see Figure 4.15. No testing was done to determine if this coloration had any
correlation to sulfur content. The smell of rotten eggs was evident during opening.
Figure 4.15: Pictures of Columns aft
4.6.1. Moisture
The outer layers of the colum
signs of drying. Both compost volumes were sliced lengthwise for examination. In
er Exposure to Biogas for 1057 hours.
ns were crumbly to the touch and showed definite
n in
94
both instances, the cores of the columns were darker brown in color, moist to the
touch, and appeared similar to the original compost.
Moisture measurements from 0.05, 0.15, and 0.25 m along the column lengths
are shown in the Table 4.5.
Table 4.5: Moisture Contents Along Bed Depth
Sample / Location Bottom Middle Top Fresh Compost 73% 73% 73%
Column 3 44% 63% 76% Column 4 41% 69% 60%
As seen, there is moisture loss near the inlet, down from an original content of
~70%. As expected with a temperature rise in the bed, humidification of the inlet gas
was not sufficient for maintaining moisture in the compost. Also, the evidence of
localized drying indicates preferential gas flow around the edges of the column.
Water content is an indirect measurement of water availability, whereas water
activity measurements are more useful, but difficult to obtain. Sufficient water
availability is critical for proper biological function and may have the greatest
detrimental effect on biofilter performance if inadequate (Mysliwiec, et al. 2001).
Studies by Yang and Allen (1994) indicate that removal efficiency drops linearly
below 30% wet weight water content in H2S biofilters. Although no water content this
low was measured, it is reasonable to assume that better performance could be
achieved with more uniform and increased wetting. Additionally, an improved water
man
hydrophobic when dried, making them hard to rewet and maintain acceptable water
and Bohn 1999).
agement technique is desirable because organic media are known to become
potentials (Bohn
95
4.6.2. pH
As with the moisture content, pH samples from 0.05, 0.15 and 0.25 m along
the column lengths were recorded and Table 4.6 shows these results.
Table 4.6: pH Levels Along Bed Depth
Sample / Location Bottom Middle Top Fresh Compost 7.2 7.2
9 .9 7 .1
7.2Column 3 6. 4 4.6Column 4 6. 7 4.6
The most significant pH drops are noticed in the upper half of the beds. The
largest pH decreases are noticed where moisture contents remained higher. A drop in
pH is an indication of possible sulfate formation in the bed, which is a major
biological pathway for sulfide oxidation. One possible explanation for this might be
that biological activity, and thus sulfate formation, was curtailed by low moisture
content.
An extreme pH drop, as seen with some H2S biofilters (Devinny, et al. 1999),
was not noticed here. This may be due to the incomplete oxidation to elemental sulfur
or natural buffering capacity of the compost. Additional buffering to maintain a
neutral pH was not practiced, but could easily be achieved via crushed limetone
addition in the bed.
4.6.3. Trace Element Analysis
The results for the trace element analysis are shown in the Table 4.7.
96
Table 4.7: Elemental Analysis of Raw and Tested Compost Element Compost* Sample 3* Sample 4* Sulfur 7,316 103,752 121,490
Boron 67 43 47 Cadmium < det. Calcium 35,858
Chrom 0.1 Cobal 2 < det. < det. Copper 479 332 359
Iron 5,487 2,160 2,481 Lead < det. < det. < det.
Molybdenum 11 15 21
Sodium 3,277 2,356 2,528 Vanadium 7 3 3
* all values in ug/g dry basis
Aluminum 2,145 774 849 Arsenic < det. < det. < det.
< det. < det. 49,910 28,884
ium t
2 < det.
Magnesium 13,615 8,892 11,934 Manganese 500 320 353
Nickel 39 25 28 Phosphorous 11,869 7,261 8,068
Potassium 13,548 9,412 10,020
Zinc 347 236 256
< det. = below analyte detection limit
As seen, the original total sulfur content of the compost is about 7000 µg/
(0.7%) on a dry basi
g
s. Columns 3 and 4 average around 110,000 µg/g for total sulfur
content. This indicates a net increase of about 100,000 µg/g of total sulfur in the
final sulfur content over 10% dry basis. These
results are encouraging because they confirm that sulfur is being removed from the gas
stream and being sequestered in the bed through biological, chemical or physical
mechanisms.
Besides an average 1440% increase in sulfur, molybdenum is the only other
element with a measured increase (66% average). All the remaining measured
media itself during operation, and
97
elements de is
expected to occur in acidic biolo nvironments, but was not measured here.
Yang and Allen (1994) have shown that su levels above 3
H2S biofilter performance. The o al level in the compost (<100 µg/g) was well
below this threshold. Sulfate lev he used c s were not m .
An accurate sulfur balance is hard to acc because the f dry mass of
the column lfur levels in le ate were no red. The am sulfur
removed from the gas stream using the electroche easurement d is
calculated a 15 g for colu nd 120 ± r column 4. ing that
the dry m lumns sta ame throughout operation, the trace element
analysis would predict an expected removal of 175 and 207 g S for columns 3 and 4,
respectively. The discrepancy ma due to a decrease in total dry m during
operation, or significant loss of sulfur in the leach lso, the dete 2S
during column opening might be an indication of reduction occ and re-
generation o while the colu ere no long posed to an ox source.
4.7. DISCUSSION
These results indicate that a simple and minimally managed system, comprised
of passing a mixture of 2:1 biogas-to-air through cow-manure compost, can be
effective in removing sulfur from a biogas stream. Although using an electrochemical
sensor is affordable and good for tracking relative changes in concentration, it is
limited in measuring absolute concentrations because of cross-sensitivity interference
and dilution error. H2S gas detector tubes and a GC-MS analysis corroborate the
readings from the electrochemical sensor.
creased by less than 100% on a dry basis. Some metal leaching
gical e
lfate 0 mg/g inhibit
rigin
els in t ompost easured
omplish inal
s and su ach t measu ount of
mical m metho
s 127 ± mn 3, a 15 g fo Assum
ass of the co yed the s
y be atter
ate. A cted smell of H
sulfur urring
f H2S mns w er ex ygen
98
It is not clear from this study whether sulfur removal is due mostly to
biological, chemical, or physical phenomena, but sulfur is clearly being removed from
the gas
.
at
NSIDERATIONS
mpty-
ions.
stream and accumulated in the compost. The upset and recovery trend in
removal efficiency for column 4, noticeable pH drops, prolonged performance, and
relatively high elimination capacities are suggestive of a biological mechanism
The fact that significant removal rates were achieved with minimal moisture
control and no temperature or pH controls indicate that further research on system
capacity and optimization are warranted. Initial progress is predicted simply by
maintaining temperature between 30-40°C and moisture contents above 50%. Other
researchers have achieved biological H2S removal with residence times as low as 1.6
seconds, indicating that higher elimination capacities may be possible with lower gas
residence times (Gabriel, et al. 2002). Major questions to be answered include: Wh
happens to methane during this process? What is the upper elimination capacity? What
sulfur products are formed? How does the compost change during the process? What
is the microbial makeup? And what are the optimum operating conditions?
4.8. SCALE-UP CO
These experiments were conducted on biogas side-streams containing roughly
1/1000 of the full-scale gas flow. 2.5-liter reaction columns with 100-second e
bed residence times for 2:1 biogas-to-air mixtures produced the aforementioned
results. Assuming linear scale-up for discussion, a 2500 L, or 2.5 m3, bed volume
might produce similar results. Although linear scaling would most likely not apply,
there are many reasons to believe that performance can be improved by optimizing
temperature, moisture, loading, and pH condit
99
Additionally, in these experiments, excess oxygen (in air) was added, b
critical amount of air required may be substantially less. Reduced oxygenation levels
and empty-bed residence times, as determined with further testing, would decreas
size, as long as the maximum H2S elimination capacity was not exceeded.
Unfortunately, lower gas-residence times may require bulking of the compost to ke
ut the
e bed
ep
pressur
ith
fresh compost as a batch process. The loss in efficacy may be from exhaustion of
loss of biological activity from insufficient
nutrients, or because of increased pressure drop from compost degradation or plugging
of the void spaces with sulfur or biomass.
A comparison of these compost-based processes with an iron sponge system,
sized for AA Dairy, is included in Table 4.8. Media costs for the compost are based
on the average market value of $0.02/kg for AA Dairy cow-manure compost.
Transportation costs are zero for the compost, whereas the iron sponge has a
transportation cost for shipping from Chicago, IL. As seen, both manure processes
show potential for improvement over iron sponge. The Equivalent Uniform Annual
Cost (EUAC) is calculated assuming a $30,000 capital cost for all systems, 20-year
e drops reasonable, and bed sizes would then need to be increased.
In scaling-up, there are two potential process-configurations that can be
envisioned with cow-manure compost. Ideally, a biological process with a stable
microbial environment would be established to promote continuous and prolonged
H2S removal. In this scenario, required nutrients are available in the compost or gas,
or added periodically, and sulfates and other metabolites are removed, when
necessary, with a water-rinse. Labor and media costs are lower because bed change-
outs would only be necessary less than once a year. A second configuration is
envisioned where the cow-manure compost is placed in a vessel with relatively few
process controls, operated until the bed is completely ineffective, and replaced w
chemical or physical adsorption capacity,
100
system
oved.
evel (1500
ppm H
t
in
n sponge
life cycle, and 8% interest rate and including all other annual costs (Newnan
2000). The iron sponge system has an EUAC from $4,437 - $15,057 per year or $5.35
- $6.43 per kg H2S removed. The cow-manure systems have estimated EUAC’s of
$6,527 and $3,832 per year, respectively, or $6.30 and $3.70 per kg H2S rem
There is a range of costs for the iron sponge system due to variations from low (1000
ppm H2S) to high (4000 ppm H2S) loading. Since only one concentration l
2S average) was tested here, it is not clear how the cow-manure compost
systems would respond, and subsequently how costs would vary, based on differen
loadings. Therefore, the symbol “±” is used to remind the reader of this variability
Table 4.8. As indicated here and in the table, the continuous cow-manure system
appears to provide the most significant improvement and savings over the iro
system.
101
Table 4.8: Estimated Comparison of Cow-Manure-Compost and Iron-Sponge
H2S-Removal Systems at AA Dairy
Iron Sponge Cow-Manure Cow-Manure
CHARACTERISTICS
Vessel Sizes high (0.99 m3 each) high (1.15 m3 each) high (1.15 m3 ea.)
Biogas Flow Rate 0.94 m3/min 0.94 m3/min 0.94 m3/mAir Addition Rate 2.4 – 3.7 % < 33 % < 33 %
Empty-Bed Residence Time
60 sec (1-bed) 120 sec (both beds)
49 sec (1-bed) 98 sec (both beds)
49 sec (1-bed) 98 sec (both bed
Annu
(Batch) (Continuous)
# Vessels 2 (Lead/Lag) 2 (Lead/Lag) 2 (Series)
0.91 m ID x 1.52 m 0.91 m ID x 1.77 m 0.91 m ID x1.77 m
in
Total Flow Rate 0.97 m3/min 1.41 m3/min 1.41 m3/min
s) Mass of Bed 800 kg each 860 kg each 860 kg
Bed Life 18 - 315 days 40 days ± > 1 year al Media
Utilization 930 – 16,300 kg 15,480 kg ± < 1720 kg
COSTS $10,000-$50,000 $10,000-$50,000 $10,000-$50,000
Media (per year) $250 - $4,300 $300 ± $35 ± Transportation
(per year) $500 - $2,500 0 0
Operating and
Labor (per year)
$500 - $3,000 (1-20 change-outs
@ 12 hrs. ea. + blower electric)
$1,000 ± (9 ± change-outs @ 8 hrs. ea. + blower
electric + H2O)
$500 ± (1 change-out @ 8
hrs. + blower electric + H2O +
nutrients) Media Disposal
(per year)* $130 - $2,200 ± $2,170 ± $240 ±
TOTALS
Capital
Total EUAC**
($/kg H2S removed)
$5.35-6.43 $6.30 ± $3.70 ±
* Kellog (1996) estimated disposal costs of $0.14/kg-spent media. It is assumed here that disposal costs fo all three processes would be the same. Costs may be higher or lower depending on whether the material is disposed of on-site or if it is transported to a landfill and treated as hazardous waste. (See Appendix A). ** EUAC = Equivalent Uniform Annual Cost assuming $30,000 capital cost, 8% interest rate, and 20 year life-cycle.
r
CHAPTER
5. SUMMARY AND CONCLUSIONS
The two-part o w ren 2
re suit ith farm s, and t
fe g on- adsorp
There are many chemical, physical, and biologi rently
rem om an e am, as su low.
5.1 AV EMO ODS
5.1.1. d Proc
y, dry-based chemical methods have been used for sulfur removal
from y, and still appear to be competitive
because they are simpl mated c s for f
around $10,000-$50,000 est -$
Relatively high labor costs for materials handling and disposal are incu
drawbacks include a con waste s pent media, and growing
env ern over appropriate waste disposal methods. The most
comp ucts appe sponge, Me
a
d s
a
bjective of this study as to determine cur tly available H S
moval technologies able for use w biogas system o test the
asibility of utilizin farm cow-manure compost as an H2S tion medium.
cal methods cur available for
oval of H2S fr nergy gas stre mmarized be
. CURRENTLY AILABLE H2S R VAL METH
Dry-Base esses
Traditionall
gas streams with less than 200 kg S/da
e and effective. Esti
and media costs
apital cost arm systems are
23,840 per year.
rred. Major
imated between $250
tinually produced tream of s
ironmental conc
etitive prod ar to be Iron dia-G2®, and KOH-impregnated
ctivated carbon. Molecular sieves may be competitive with an appropriately
esigned regeneration step. Table 5.1 summarizes dry-based, H2S removal processe
nd Table 5.2 summarizes estimated costs for application at AA Dairy.
102
T e y b o aring D Basedabl 5.1: Summar Ta le C mp ry- H2S Removal Processes for Farm Biogas
Packing Operating Con itio sd n
omC pounds Removed
Regen- ?
rablee
Med oia C sts($/ 2re
Noteskg H S moved)
Iron Sponge ron xid )
Am ient Tem . (6 -115 F), Wet gas, 60
i enc tim
H2 anderc ptan(I O e
b p 5
sec res d e e
S m a s
timch m only
0.3 .
ha eo an be labor intensive. ri it process efficiency but m p tical experience with
igester gas
2-3bat
es in ode
5 - 1 55
C ng ut cVa abil y in
uch racd
Sulfa Treat (I O e
b p 5
sec res d e e
S m a s No 4.8 .
n o ric and easi andling h t tics compared to iron
sponge
® ron xid )
Am ient Tem . (6 -115 F), Wet gas, 60
i enc tim
H2 anderc ptan 5 - 5 00
No -pyr phoc arac eris
er h
S r e® (I O e
b p 5
sec res d e e
S m a s No 7.9 . a le prepackage odules,
ms iron pyrulfu Rit ron xid )
Am ient Tem . (6 -115 F), Wet gas, 60
i enc tim
H2 anderc ptan 5 - 8 50 Av ilab in
Ford mite
M ia ® (I O e
b p 5
sec res d e e
S m a s
15 time batch m
only2.9 . ltiple regen ions to
ted removal efficiency ed -G2
ron xid )
Am ient Tem . (6 -115 F), Wet gas, 60
i enc tim
H2 anderc ptan
s inode
0 - 3 00 Requires muobtain estima
erat
Molecu ar S eve
bie t Temp.,High Pressure (500
p g+)
W ter,mercans H2Sligh CO
l i(Adsorbent)
Am n
si
a ap-t , , s t 2
Yes
e v ll water bef sulfur un The propo design
ul av 1-day bed l operated at 500 psi
R mo es acompo ds.
wo d h e a
ore sed ife
ImActivated Carbon
(Adsorbent)
b t p des e
S m a s No 1.7 . H bon has be sed
s e ll r anaerobic ester gas
pregnated
Am ien Tem . an Pr sur
H2 anderc ptan 5 - 2 00 KO car
ucc ssfu y foen u dig
Es mated Cow-ure om ost Am ien Tem . an
Pr sur H S ti
Man C pProcesses
b t p des e 2 No 0.03 – 0.
on u or batch processes are is ed able 4.8). It is not clear
pounds are oxidized in addition to H2S.
29
C tin ous env ion (T
whether other com
Table 5.2: Summary Table Comparing Dry-Based H2S Removal Processes for AA Dairy AA DAIRY ESTIMATES (all costs do not include tax stallation or operation) es, shipping, in
Packing # of Vessels s Bed L s) Annu Media
(kg)Annual Media
Costs ($ Cost (D=d
H=tw
iH
Highoa
w g
Low lo
Highd
Iron Sponge (Ir
o - 0D x 1. 8 - 79 930 -
70 16,300 250 - 1,075
985-4,30
10,000 -
ameter, eight)
Low loading L
.91 m
ding
Loloadin
High Loading
3,710 -
ading Loa
ing (Vessels Only) ($)
(Low loading=1000ppm High loading=4000 ppm)
Connelly GPM,
on Oxide) e52 m H ach
72 - 315 1 4,0 0 50,000 Physichem, Varec Vapor Control
Sulfa Treat® t
(Ir
wo -x1.6
86 3,850 15,450 3,400 13,500 12,000 ulfaTreat on Oxide) m
1.2 m m x 1.8 each
345 S
lfur Rite® o 2.3 m 420 .4 m H 98 7,900 43,600 US Filter/ M
edia-G2® (Iron Oxide)
two -D
0.91 m 52 m H ch
190 7 1,460 5,900 2,050 8,290 10,000 - 50,000 ADI International
Molecular Sieve
(Adsorbent)
one –D x 2 m 4 ho ay n/a n/a 0.6 m
H 24 hours 2 urs 250/d 400/day n/a Many - See Thomasregister.com
pregnated Activated Carbon dsorbent)
tD x
0.6 m .5 m H 340 5 270 075 250 54 5 <50,000 Many - See
Thomasregister.com
Estimated Cow-Manure
mpost
one0.91
CoProcesses
o
1.77 m H each
360 1720 15480 00 us )
r two – m D x 40 35 3 10,000 –
50,000
Note: (low and high loading values are for batch and continuoprocess, respectively
and Size ife (dayal
Consumption )
Estimated Capital Suppliers
Su(Iron Oxide)
ne –D x 3 33,900 5,560 23,840 erichem
M x 1.
ea4
Im
(A
wo –1each
8 1 1 3
105
5.1.2. Liquid-Based Chemical and Physical Processes
These processes have not traditionally been used for low-flow and low-
cost of ati gh e, -
ments f rculation pumps a generation ve s, and e
or being viable with small
the th kene
Also, nitra olutions, such as Sulfa-Scrub®, should be investigated for system
al gas but do not appear economically competitive for selective H2S
his
a n
S removal from biogas is not yet pr l with this technology,
atu as em brane p sses.
embrane systems are in the developmental stage and show
c n i p to est ely
ova e a te rem ow ou m.
Also, there is concern about solids buildup in the dige
pressure app
req
costs. The LO-CAT
biogas sys
valu
suitability. Water scrubbing and the Sele
biog
rem
5.1.
but
Low-pressure gas-liquid m
prom
5.1.4. In-Situ Digester Sulfide Control
inh
rem
lications due to increased s
nd re
oper ng at hi
ssel
pressur
high
high energy
r media uire
e.
as
ova
3. M
upg
ise f
ibits
or reci® iron-chelate process shows potential f
tems, especially if ic d sulfur-slurry produced has agricultural
te s
xol Process are both used for upgrading of
to natur
l at t time.
embr ne Separatio
Selective H
rading
2
of biog
actica
arket for mas to n ral g is an erging m em roce
or the future.
Resear h has
2S production, but this m
ss, r
show
quiring
that add
nother
tion of
ethod m
chnolo
iron com
ay only be considered a partial
gy for
ounds
oval d
the dig
n to ab
er effectiv
t 10 pp
some H
l proce
ster using this method.
106
5.1.5. Biogas Aeration
Digestion facilities in Europe have reported significant H2S removal by adding
small a remely
2
Operational experience with biological oxidation of H2S from gas streams is
growing and there are companies, such as Biothane and UOP, who specialize in this
area. Currently available systems are more capital intensive than available dry-based
f lower labor costs and improved environmental
impact. The research in the second part of this study examined the feasibility of using
cow-m 2 ed
aracteristics of H2S Removal Processes
ristics of available H2S removal processes
from biogas.
mounts of air (2-6%) to the digester headspace or storage tank. This ext
simple and affordable technique is believed to be biological in nature, and may reduce
initial H S levels to around 100 ppm. This process requires further testing in the
United States as it shows great promise.
5.1.6. Biological Removal Techniques
systems, but offer advantages o
anure compost as an economic and effective H S removal process for integrat
farm energy systems.
5.1.7. Comparison of Ch
Table 5.3 summarizes the characte
107
Table 5.3: Summary of H2S Removal Process Characteristics
Removal Technique
Applicability for farm Capital
Costs
Operating/Media Ease of
operation Regen-erable
H2S < 250
Environ-mental
biogas Costs ppm impact
Iron Oxides + + +/- +/- +/- + - Zinc Oxides - + - +/- - + -
Impregnated
Carbons
(+=high) (+=low) (+=low) (+=easy) (+=yes) (+=yes) (+=low)
Alkaline Solids - + - +/- - + -
Activated + + +/- +/- - + -
Molecular Sieves +/- +/- - - + + - Chelated Iron +/- - Solutions - - +/- + +/-
Nitrite Solutions +/- + - + - + - line Salt
Solutions
Water Scrubbing +/- +/- +/- +/- + +/- - Physical Solvent +/- +/- +/- +/- + +/- Scrubbing -
Membrane: Low Pressure +/- - - - +/- +/- +/-
Membrane: High Pressure
Alka - - - - - + -
Amine Solutions - - - - + + -
- - - +/- n/a +/- +
Digester pH Control +/- + +/- +/- n/a - +/-
Digester Iron + + + + n/a Addition - +/-
Dietary Adjustment +/- + + +/- n/a - +
Air Dosing to Biogas + + + + n/a +/- +
Commercial Biological Processes
+/- - +/- +/- +/- + +
Estim e Cow-Manure Compost
Processes + + + + n/a + +
at
n/a = not applicable desirable +/- = neutral - = undesirable
108
5.2. TEST
Initial testing -manure com ndicates that it has pote s
effective and economic medium for H2S r val. P est co s we const ted
an -to-air xture passed through the columns containing anaerobically
di nure compost. The tests of most significance were run for 1057
hours with an empty-bed gas-residence time near 100 seconds and inlet H2S
rag 500 p as measured by e ctroche
40 tion.
ffic es over 80% were recorded for the m rity o e tria
Elim pacities orded were between 16–118 g H2S/m3 olids/h This
ring ly mini l moisture and no temperature or pH controls were
perature in the bed varied from 19-43°C 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 is
biological, chemical or physical, but it is known that ulfur ent e com st
increased by over 1400%, verifying sequestration of r in t lid. ese initial
re at fut work is warranted for exam ing the abilit f co
manu ost as a biofiltration medium for use with biogas.
ntial process-configurations are envisioned for scale-up with cow-
manure compost. In one, continuous biological activity is promoted by optimizing
process conditions for long-term eratio the ot a rela y sim r bat
s r process controls is established, where the compost is used for its
, or lected biological activity, and changed-out mo frequ ly.
Both processes compar favorably t rocess, as d in Ta les
4.8, 5.1, 5.2, and 5.3, assuming minimal methane oxidation.
ING OF COW-MANURE COMPOST
of cow post i ntial a an
emo VC t lumn re ruc
d a 2:1 biogas mi
gested cow-ma
concentrations ave ing 1 pm, le mical sensor with a
:1 sample dilu
Removal e ienci ajo f th l.
ination ca rec -s r. is
significant conside on ma
implemented. Tem
the s cont in th po
sulfu he so Th
sults indicate th ure in suit y o w-
re comp
Two pote
op n. In her, tivel ple ch
ystem with fewe
chemical, physical neg re ent
e o other dry-based p illustrate b
CHAPTER
6. FUTURE WORK AND RECOMMENDATIONS
Although the present study partially fulfills its objectives, there are limitations
that should be addressed and new directions to be explored in future research. The
biogas summary completed in the background section of this study could be expanded
in the following areas:
• A Life Cycle Assessment (LCA) comparison of the economic, environmental
and social impacts for the most competitive H2S removal technologies should
be performed. Operation and maintenance costs, as well as appropriate
disposal costs, should be included.
• Alternative disposal and reuse techniques for spent adsorption media should be
studied. The agricultural nutrient-value of spent media and biological
regeneration techniques for sulfur clogged iron sponge should be investigated.
• An LCA for other biogas purification processes, such as CO2 reduction, water
removal, particulate filtration and removal of other gas contaminants, should
be conducted.
• The processing requirements for specific gas-utilization technologies should be
compiled. Specific uses should include biogas in boilers, engines,
microturbines, fuel cells, Stirling engines, upgrading biogas to natural-gas
quality or using biogas for hydrogen production, among others
This study was also effective as a proof-of-concept, indicating that cow-
manure compost can be used as economical and effective H2S adsorption media.
109
110
Further testing and verification of th ecessary and the following
experim ntal modifications are recommended:
• Me
chromatography with a flame photometric detector for increased accuracy.
• Experiments should take place in a controlled temperature environment to
of
ting in the bed.
reaction should be performed.
• nd
.
• aeration of the biogas should be quantified.
• tal
for
determining overall economic and environmental benefits.
ese results are n
e
asurement of gaseous sulfur compounds should be done via gas
minimize variation due to temperature fluctuations.
• Moisture should be maintained around 50% wet basis. The implementation
downward water flush could maintain bed moisture and serve to rinse out any
sulfur accumula
• Clear columns should be used to observe any drying or microbial plugging that
might be occurring.
Additional testing needs to be done to better determine and quantify the
s taking place. The following tests
• The fate of methane during operation should be monitored and determined.
The sulfur species in the medium and effluent gas, including sulfates a
elemental sulfur, should be measured to account for sulfur reactions.
• Jar tests should be performed on abiotic samples of cow-manure compost in
order to assess the purely physical and chemical adsorption capacity for H2S
The effect of
• A biological assessment of the major active microbial communities should be
performed.
An assessment of the agricultural nutrient value, compost stability, and me
leaching in the spent filter media could be performed.
Further long-term operation and bench-scale optimization are desired before
scale-up to pilot and full scales. A life cycle assessment should then be conducted
APPENDIX A: H2S Scavenger Media Disposal
A study by the Gas Research Institute estimated 1996 change-out and disposal
costs for various media as follows (Kellog 1996). These costs are merely given in
Table A.1. to show that disposal costs can easily exceed media costs, as are expected
for transportation, installation and operating costs.
Table A.1. Approximate Media Change-out and Disposal Costs (1996 est.)
Caustic $0.25/gal Triazines $1.00-2.00/gal
Non-regenerable Amines $1.00-2.00/gal SulfaTreat $0.10-0.30/lb Iron Sponge $0.10-0.30/lb
Source: Kellog (1996)
SulfaScrub(Nitrates) $0.10-0.20/lb
The Gas Research Institute sponsored extensive research on economic analysis
of sulfur scavenging processes for gas streams with low sulfur production in the early
to mid 1990’s. The reader is directed to three papers for further information: 1)
Evaluation of H S Scavenger Technologies, (Foral and Al-Ubaidi 1994). 2) GRI Field
Evaluation of Liquid-Based H S Scavengers in Tower Applications at a Natural-Gas
Production Plant in South Texas, (Fisher and Dalrymple 1994). 3) Field Evaluation of
Solid-Based H S Scavengers for Treating Sour Natural Gas, (Fisher and Shires 1995).
These works resulted in a design program, GRI-CalcBase, which can be used
for economic evaluation of different scavengers with various plant configurations.
Results of running the program with the system parameters from AA Dairy indicated
that dry scavengers such as Iron Sponge and SulfaTreat were the most promising to
investigate further.
2
2
2
111
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