Engineering, Products, Services and Information
Biomethane and Methane
Gas Recovery products and services which provide fuel for
generating power as well as cogeneration and
trigeneration systems. BioMethane is
generated from Anaerobic
Recovery, BioMethane, Concentrated
Animal Feeding Operations, and Landfill
Gas to Energy.
Unlike most companies,
we are equipment
supplier/vendor neutral. This means we help our clients
select the best equipment for their specific application. This
approach provides our customers with superior performance, decreased
operating expenses and increased return on investment.
provide Anaerobic Digester, Anaerobic
Lagoon, Biogas Recovery, BioMethane,
Biomass Gasification, and Landfill
Gas To Energy, project development services.
Technologies, located in Houston, Texas, provides the following power
and energy project development services:
Engineering Feasibility & Economic Analysis Studies
Procurement and Construction
Engineering & Permitting
Funding & Financing Options; including Equity Investment, Debt
Financing, Lease and Municipal Lease
Savings Program with No Capital Investment from Qualified Clients
Party Ownership and Project Development
Tag (Renewable Energy Credit, Carbon Dioxide Credits, Emission
Reduction Credits) Brokerage Services; Application and Permitting
are Renewable Energy
Technologies specialists and develop clean power and energy
projects that will generate a "Renewable
Energy Credit," Carbon
Dioxide Credits and Emission
Reduction Credits. Some of our products and services
solutions and technologies include; Absorption
Chillers, Adsorption Chillers,
Automated Demand Response,
Biodiesel Refineries, Biofuel
Gasification, BioMethane, Canola
Biodiesel, Coconut Biodiesel,
Solar Power, Demand
Response Programs, Demand
Side Management, Energy
Conservation Measures, Energy
Master Planning, Engine
Driven Chillers, Solar CHP, Solar
Cogeneration, Rapeseed Biodiesel,
Solar Electric Heat Pumps,
Solar Electric Power
Systems, Solar Heating
and Cooling, Solar
Trigeneration, Soy Biodiesel, and
For more information: call us at: 832-758-0027
is an Anaerobic Lagoon?
An anaerobic lagoon is an earthen impoundment receiving manure from an animal feeding operation in which manure is stored and stabilized by bacterial activity operating without oxygen (compare with an aerobic structure). The statute specifically provides that an anaerobic lagoon does not include a confinement feeding operation structure such as an earthen manure storage basin; a basin connected to unroofed operations (feedlots) which collects and stores runoff produced by rain or a system which collects and treats off gases.
is an Anaerobic Digester?
An Anaerobic Digester is a device for optimizing the anaerobic digestion of biomass and/or animal manure, and possibly to recover biogas
also referred to as BioMethane for energy production. Digester types include batch, complete mix, continuous flow (horizontal or plug-flow, multiple-tank, and vertical tank), and covered lagoon.
What is Anaerobic Digestion?
Anaerobic digestion is a biological process that produces a gas principally composed of methane (CH4) and carbon dioxide (CO2) otherwise known as biogas. These gases are produced from organic wastes such as livestock manure, food processing waste, etc.
Anaerobic processes could either occur naturally or in a controlled environment such as a biogas plant. Organic waste such as livestock manure and various types of bacteria are put in an airtight container called digester so the process could occur. Depending on the waste feedstock and the system design, biogas is typically 55 to 75 percent pure methane. State-of-the-art systems report producing biogas that is more than 95 percent pure methane.
EPA AgSTAR Program Background
U.S. EPA AgSTAR is an outreach program designed to reduce methane emissions
from livestock waste management operations by promoting the use of biogas
recovery systems. A biogas recovery system is an anaerobic digester with
biogas capture and combustion to produce electricity, heat or hot water.
Biogas recovery systems are effective at confined livestock facilities that
handle manure as liquids and slurries, typically swine and dairy farms.
Anaerobic digester technologies provide enhanced environmental and financial
performance when compared to traditional waste management systems such as
manure storages and lagoons. Anaerobic digesters are particularly effective
in reducing methane emissions but also provide other air and water pollution
control opportunities. AgSTAR provides an array of information and tools
designed to assist producers in the evaluation and implementation these
digester extension events and conferences
project development tools and industry listings
characterizations for digesters and conventional waste management
Operating a toll free
recognition for voluntary environmental initiatives
federal and state renewable energy, agricultural, and environmental
Methane Emissions from Animal Waste
emissions occur whenever animal waste is managed in anaerobic conditions.
Liquid manure management systems, such as ponds, anaerobic lagoons, and
holding tanks create oxygen free environments that promote methane
production. Manure deposited on fields and pastures, or otherwise handled in
a dry form, produces insignificant amounts of methane. Currently, livestock
waste contributes about 8 percent of human-related methane emissions in the
Given the trend toward larger farms, liquid manure management is expected to
increase. For more information on international emissions, projections, and
mitigation costs, see International
Emission Reduction Technology: Anaerobic
more detailed information on commercially available anaerobic digestion
technologies and their costs, download Managing
Manure with Biogas Recovery Systems: Improved Performance at Competitive
Costs (PDF, 4 pp., 4.4
The AgSTAR Program has been very successful in encouraging the development
and adoption of anaerobic digestion technology. Since the establishment of
the program in 1994, the number of operational digester systems has doubled.
This has produced significant environmental and energy benefits, including
methane emission reductions of approximately 124,000 metric tons of carbon
equivalent and annual energy generation of about 30 million kWh. The graph
below shows the historical use of biogas recovery technology for animal
development of anaerobic digesters for livestock manure treatment and energy
production has accelerated at a very fast pace over the past few years.
Factors influencing this market demand include: increased technical
reliability of anaerobic digesters through the deployment of successful
operating systems over the past five years; growing concern of farm owners
about environmental quality; an increasing number of state and federal
programs designed to cost share in the development of these systems; and the
emergence of new state energy policies (such as net metering legislation)
designed to expand growth in reliable renewable energy and green power
the past 2 years alone, the number of operational digester systems has
increased by 30%. For more detailed information on anaerobic digester use in
go to the Guide
to Operational Systems or see the AgSTAR
The process of anaerobic digestion consists of three steps.
The first step is the decomposition (hydrolysis) of plant or animal matter. This step breaks down the organic material to usable-sized molecules such as sugar. The second step is the conversion of decomposed matter to organic acids. And finally, the acids are converted to methane gas.
Process temperature affects the rate of digestion and should be maintained in the mesophillic range (95 to 105 degrees Fahrenheit) with an optimum of 100 degrees F. It is possible to operate in the thermophillic range (135 to 145 degrees F), but the digestion process is subject to upset if not closely monitored.
Many anaerobic digestion technologies are commercially available and have been demonstrated for use with agricultural wastes and for treating municipal and industrial wastewater.
At Royal Farms No. 1 in Tulare, California, hog manure is slurried and sent to a Hypalon-covered lagoon for biogas generation. The collected biogas fuels a 70 kilowatt (kW) engine-generator and a 100 kW engine-generator. The electricity generated on the farm is able to meet monthly electric and heat energy demand.
Given the success of this project, three other swine farms (Sharp Ranch, Fresno and Prison Farm) have also installed floating covers on lagoons. The Knudsen and Sons project in Chico, California, treated wastewater which contained organic matter from fruit crushing and wash down in a covered and lined lagoon. The biogas produce is burned in a boiler. And at Langerwerf Dairy in Durham, California, cow manure is scraped and fed into a plug flow digester. The biogas produced is used to fire an 85 kW gas engine. The engine operates at 35 kW capacity level and drives a generator to produce electricity. Electricity and heat generated is able to offest all dairy energy demand. The system has been in operation since 1982.
Most anaerobic digestion technologies are commercially available. Where unprocessed wastes cause odor and water pollution such as in large dairies, anaerobic digestion reduces the odor and liquid waste disposal problems and produces a biogas fuel that can be used for process heating and/or electricity generation.
describes the anaerobic digestion (AD) process, outlines guidelines for
assessing the feasibility of AD and biogas usage at a swine facility and
provides summary information on AD system performance and reliability.
Digestion Technology Description
AD promotes the
bacterial decomposition of the volatile solids (VS) in animal wastes to
biogas, thereby reducing lagoon loading rates and odor. The primary
component of an AD system is the anaerobic digester, a waste vessel
containing bacteria that digest the organic matter in waste streams under
controlled conditions to produce biogas. As an effluent, AD yields nearly
all of the liquid that is fed to the digester. This remaining fluid
consists of mostly water and is allowed to evaporate from a secondary
lagoon, land-applied for irrigation and fertilizer value or recycled to
flush manure from the swine building to the digester.
The benefits of AD
in the biological oxygen demand of treated effluent by up to 90
percent, reducing the risk for water contamination;
nutrient application control, because up to 70 percent of the nitrogen
in the waste is converted to ammonia, the primary nitrogen constituent
pathogens, viruses, protozoa and other disease-causing organisms in
lagoon water, resulting in improved herd health and possible reduced
water requirements; and
to generate electricity and process heat.
AD takes place in
three steps: hydrolysis, acid formation, and methane generation. During
the first step, hydrolysis, bacterial enzymes break down proteins, fats
and sugars in the waste to simple sugars. During acid formation, bacteria
convert the sugars to acetic acid, carbon dioxide and hydrogen. Then the
bacteria convert the acetic acid to methane and carbon dioxide, and
combine carbon dioxide and hydrogen to form methane and water.
technologies that can be used to collect biogas from swine facilities
mix digesters and
sequencing batch reactor has been used for AD at one swine facility in the
, this technology is considered to be experimental, and thus is not
included in this report. This report focuses on technologies that have
verifiable performance characteristics, namely, covered anaerobic lagoons
and complete mix digesters.
Appendix B provides
contact information that can help producers find AD system
designers/installers, odor control technologies, generators, heating and
cooling equipment, and other information to help manage air and water
quality at hog facilities.
digesters are the simplest AD system. These systems typically consist of
an anaerobic combined storage and treatment lagoon, an anaerobic lagoon
cover, an evaporative pond for the digester effluent, and a gas treatment
and/or energy conversion system. Figure 1 shows a typical schematic for a
floating covered anaerobic lagoon.
Source: EPA. (July 1997). AgStar Handbook: A Manual for Developing Biogas
Systems at Commercial Farms in the
. EPA 430-B-97-015.
. pp. 1-3.
Figure 1 .
Covered anaerobic lagoon digester
digesters typically have a hydraulic retention time (HRT) of 40 to 60
days. The HRT is the amount of time a given volume of waste remains in the
treatment lagoon. A collection pipe leading from the digester carries the
biogas to either a gas treatment system such as a combustion flare, or to
an engine/generator or boiler that uses the biogas to produce electricity
and heat. Following treatment, the digester effluent is often transferred
to an evaporative pond or to a storage lagoon prior to land application.
Climate affects the
feasibility of using covered lagoon digesters to generate electricity.
Engine/generator systems typically do not produce sufficient waste heat to
maintain temperatures high enough in covered lagoon digesters in the
winter to sustain consistently high biogas production rates. Using propane
or natural gas to provide additional heat for the lagoon contents is
typically not an economically viable option. Without that additional heat,
most covered lagoon digesters produce less biogas in colder temperatures,
and little or no gas below 39 FACE= "Symbol">° F. As a
result, covered lagoon digesters are most appropriate for use in warm
climates if the biogas is to be used for energy or heating purposes.
digester systems consist of a mix tank, a complete mix digester and a
secondary storage or evaporative pond. The mix tank is either an
aboveground tank or concrete in-ground tank that is fed regularly from
underfloor waste storage below the animal feedlot. Waste is stirred in the
mix tank to prevent solids from settling in the waste prior to being fed
to the digester. The complete mix digester is essentially a
constant-volume aboveground tank or in-ground covered lagoon that is fed
daily from the mix tank. Complete mix digesters with in-ground lagoons
often employ covers similar to those used in covered lagoon digesters. In
the digester, a mix pump circulates waste material slowly around the
heater to maintain a uniform temperature. Hot water from an
engine/generator cogeneration water jacket or boiler is used to heat the
digester. A cylindrical aboveground tank, such as that shown in Figure 2,
optimizes biogas production, but is more capital intensive than in-ground
tanks. The only operating AD system in
that recovers methane for energy use is a complete mix digester, located
at Colorado Pork LLC near
EPA. (February 1997). AgStar Technical Series: Complete Mix Digesters –
A Methane Recovery
Option for All Climates. EPA 430-F-97-004.
Figure 2 . Complete
mix digester schematic
digesters have an HRT of 15 to 20 days, which means that complete mix
digesters can reduce the overall lagoon volume required for waste storage
and treatment. This makes complete mix digesters comparable to covered
lagoon digesters in cost, despite the increased complexity of stirring,
mixing and plumbing components. In addition, biogas production rates, and
therefore heat and electricity production, are greater and more consistent
than for covered lagoons. This can help reduce system payback periods
compared to covered lagoon systems. Like covered lagoon systems, digester
effluent from complete mix digesters is frequently stored in evaporative
ponds or storage lagoons.
provides guidelines for conducting a preliminary assessment of the
feasibility of using AD at a swine facility. Although AD system
requirements will vary depending on the application and system design,
there are some rule-of-thumb measures that should be noted when assessing
the feasibility of AD at a given location. For AD to potentially be
technically feasible and cost-effective, a swine facility should:
house at least 2,000 animals with a total live animal weight of at
least 110,000 pounds,
no more than 20 percent variation in animal population throughout the
waste at one central location such as an underfloor pit,
waste daily or every other day, or can convert to an equivalent
manure free of large amounts of bedding or other foreign materials,
some manure storage capability to maintain a steady digester feedstock
If the above
characteristics are present, the facility is a possible candidate for AD.
Many pre-existing waste storage and treatment lagoons are too large to
practically or cost-effectively employ covers over their entire area.
Partial covers may be an option to recover methane from these older
systems, as an alternative to installing a completely new storage and
treatment lagoon system.
If energy recovery
is to be employed, methane production and gas quality should be considered
and compared to energy requirements at the facility. Daily biogas
production at installed farm-based anaerobic digesters in the
varies from 24,000 to 75,000 cubic feet, or an energy equivalent of 13 to
42 million British thermal units (Btu) (assuming 55 percent methane
content for biogas). Covered lagoon digesters and complete mix digesters
differ in their methane production characteristics, and energy conversion
systems that rely on methane from anaerobic digesters should be chosen
according to the end-use objective for the system. Complete mix digesters
can produce heat and electricity at a constant rate throughout the year
because heat recovery can be used to heat the digesters in the winter.
Covered lagoon digesters can consistently produce biogas only in months
when the temperature exceeds 39 degrees Fahrenheit.
Facilities that are
located south of the line of climate limitation in Figure 3 are usually
warm enough for cost-effective energy recovery from covered lagoon
digesters. In most cases, facilities north of the climate line in Figure 3
are too cold for cost-effective energy recovery from covered lagoon
digesters. Complete mix digesters can be used in cold or warm climates. If
odor control is the only objective, either covered lagoon or complete mix
digesters may be used, but odor control will be less effective in the
winter for covered lagoon digesters south of the line of climate
limitation in Figure 3. In general, complete mix digesters are the most
appropriate choice for use in
Source: EPA. (July 1997). AgStar Handbook: A Manual for Developing Biogas
at Commercial Farms in the
. EPA 430-B-97-015. pp. 4-12.
Figure 3 . Line of
climate limitation for biogas energy recovery
Table 2 shows which
digesters are appropriate for the waste collection strategies at covered
swine facilities. Complete mix digesters can operate with a waste total
solids (TS) percentage between 3 and 10 percent, while covered lagoon
digesters can use waste with a TS percentage less than 2 percent.
2 . Matching a digester to existing waste collection practices
Warm or cold
Warm or cold
Warm or cold
Source – Adapted
from: EPA. (July 1997). AgStar Handbook: A Manual for Developing Biogas
Systems at Commercial
Farms in the
. EPA 430-B-97-015. pp. 4-15.
Appendix C describes
each of the various waste collection technologies listed in Table 2.
discusses some of the biogas utilization options that are available for
use with AD. Electricity generation with waste heat recovery
(cogeneration) and direct combustion and use in equipment that normally
uses propane or natural gas are the two primary options for biogas
utilization. Electricity generated using biogas can be generated for
on-farm use or for sale to the electric power grid if an economically
attractive power purchase agreement can be negotiated through the local
utility or rural electric cooperative. Direct combustion allows the gas to
be used in existing equipment that normally uses propane or natural gas
such as boilers or forced air furnaces with minor equipment modifications.
Combustion is usually a seasonal use for biogas, as most boiler and
furnace applications are only required during the winter. The EPA FarmWare
manual describes some characteristics of engine/generator and direct
combustion systems that can be used with biogas. The following subsections
draw from the FarmWare manual to provide some basic information about the
use of these systems at covered swine facilities and other farm
electricity generation systems that use biogas typically consist of an
internal combustion (IC) engine, a generator, a control system and an
optional heat recovery system.
IC engines designed
to burn propane or natural gas are easily converted to burn biogas by
adjusting carburation and ignition systems. Such engines are available in
nearly any capacity, but the most successful varieties are industrial
engines that are designed to work with wellhead natural gas. A
biogas-fueled engine will normally convert 18 to 25 percent of the biogas
Btu value to electricity.
Two types of
generators are used on farms: induction generators and synchronous
generators. Induction generators operate in parallel with the utility and
cannot operate as a stand-alone power source. Induction generators derive
their phase, frequency and voltage from the utility. Synchronous
generators operate as an isolated system or in parallel to the utility,
and require more sophisticated intertie systems to match output to utility
phase, frequency and voltage.
Control systems are
required to protect the engine and the utility. Control packages are
available that can shut the engine off due to mechanical problems, utility
power outage or utility voltage and frequency fluctuations, or in the
event that excess power is generated that the utility will not accept.
Generators that operate in parallel with the utility system, such as
induction generators, require an intertie system with safety relays to
shut off the engine and disconnect from the utility in the event of a
problem. Intertie negotiations with a utility for induction generators are
typically much easier than for a synchronous generator, due to the level
of control the utility has over the characteristics of power entering the
grid from an induction generator. The primary advantage of a synchronous
generator is its ability to act as a stand-alone power source. However, if
operated as an isolated system, a synchronous generator must be oversized
to meet the highest electrical demand, while operating less efficiently at
average or partial loads. Due to the system size and more complicated
control requirements, a synchronous generator operating as an isolated
system is typically more expensive than an induction generator.
reject approximately 75 to 82 percent of the energy input as waste heat.
This waste heat can be used to heat the digester and/or provide water or
space heat to the facility. Commercial heat exchangers can recover waste
heat from the engine water cooling system and the engine exhaust,
recovering up to 7,000 Btu/hour for each kW of generator load. Waste heat
recovery increases the energy efficiency of the system to 40 to 50
digester and distributed electricity generation technologies could create
new opportunities for on-farm electricity generation using biogas. Microgy
Cogeneration Systems (Microgy), based in Colorado, has a new digester
technology coupled with a cogeneration technology that Microgy claims
increases the useful energy yield from digesters and can improve the
economics of coupling digesters with energy recovery. Microgy will be
demonstrating the technology at a
dairy farm, using a 1 MW generator to turn the methane from decomposing
cow manure into power. This demonstration is partially funded in part by
the Wisconsin Focus on Energy program. The plant will be built, owned, and
run by Microgy who will sell the power to Wisconsin Energy. A key element
to the Microgy business concept is that the farm owner will not need to
make the capital investment in the digester plant, but will still reap the
odor control and other waste treatment benefits of the digester. Microgy
will be selling the power generated back to the utility. In
, the CDPHE negotiated a settlement with National Hog Farms in August,
2000 whereby the CDPHE would reduce the size of fines for violations of
waste quality and odor quality standards in exchange for evaluating the
use of Microgy technology at their facility.
Ongoing research and
development is focusing on the use of microturbines and fuel cells for
converting biogas to electricity. Microturbines are high-speed,
small-scale (typically less than 100 kW) gas-driven turbine systems that
produce electricity efficiently, have low emissions and require little
maintenance. Reflective Energies in
in partnership with Capstone Microturbine Corporation is working on
developing the Flex-Microturbine, a power generation technology that can
use biogas from animal waste, landfill gas and biomass gasification as its
fuel source. Fuel cells are an emerging technology that operate, in
principle, like a battery, but do not run out of charge. Instead, fuel
cells equipped with a fuel reformer can use any type of hydrocarbon fuel,
and run continuously as long as fuel is available. Fuel cells can convert
fuel to electricity at efficiencies close to 40 percent, compared to 30
percent for the most efficient engine. In addition, fuel cell emissions
include heat, some of which can be recovered for other applications,
water, and carbon dioxide.
The Department of
Energy’s WRBEP funded a project in fiscal year 2000 in
San Luis Obispo
that will demonstrate electricity generation from methane using a
prototype microturbine at a 350-cow farm. The project will be using a 25
kW Capstone microturbine prototype to generate electricity at the
’s demonstration farm.
Direct combustion of
biogas on-site in a boiler or forced air furnace can provide seasonal heat
to nurseries, farrowing rooms and other facilities at a swine facility. A
cast iron natural gas boiler can be used for most farm boiler
applications. The air-fuel mixture will require adjustment and burner jets
will need to be enlarged for use with low-Btu gas. Cast iron boilers are
available in many sizes, from 45,000 Btu/hour and up. Untreated biogas may
be used, but all metal surfaces of the boiler housing should be painted to
prevent corrosion. Flame tube boilers with heavy gauge flame tubes may be
used if the exhaust temperature is maintained above 300 FACE=
"Symbol">° F to prevent condensation. Forced air furnaces
can be used in place of direct fire room heaters, but biogas must be
treated to remove hydrogen sulfide because of potential corrosion problems
in metal ductwork.
Performance and Benefits of AD
There are several
measures of waste management system performance that are relevant for
producers considering the use of AD. These include:
AD is the only waste
management strategy available that provides the option to recover methane
for energy production.
The APCD has
determined that the minimum standard for compliance with odor control
regulations for waste vessels and impoundments is an 80 percent reduction
in all odor-causing gases, including hydrogen sulfide, ammonia and
volatile organic compounds from waste vessels or impoundments. Table 3
compares the effectiveness of some of the odor control methods being
implemented at covered swine facilities in
. Lagoon covers and AD are among the most effective means of reducing
odors from waste storage and treatment systems. However, several
strategies may be combined to increase the effectiveness of individual
odor control strategies at a facility. As an example, feed additives can
be used in conjunction with biofilters, surface aeration or solids
separation to increase overall odor control from waste storage and
treatment lagoons. In addition, any lagoon odor control technology should
be accompanied by an overall odor management program using best management
practices as described in Appendix D.
3 . Odor control effectiveness of management strategies for
odorous gas emissions reduction
hogs (3:1 water to feed)
sulfur-containing amino acids
fiber (soybeans, hulls to diet)
of waste upon land application
(land application odors only)
to 100 for well-managed systems
Kirk and Jessica Davis. (February 1999). Innovations in odor management
. Agricultural and Resource Policy Report. APR-99-02.
In addition to
regulating odors from waste lagoons, the new odor control regulations have
requirements for waste that is applied to agricultural land. The new
regulations for waste treatment at covered swine facilities require that
waste applied to agricultural land and not injected be treated to remove
at least 65 percent of the TS and over 90 percent of the total volatile
fatty acids or 60 percent of total VS. If not treated, waste applied to
agricultural land must be injected or knifed into the soil upon
application. Land application is not permitted between November 1 and
February 28. Of the waste management strategies in Table 3, four will help
reduce the TS and VS content prior to land application.
Wet feeding can
reduce the TS and VS by a value equal to the dilution rate of the feed
(i.e., 3:1 ratio of water to feed). However, introducing this type of
feeding system increases water requirements and may increase required
anaerobic lagoon volumes. Solids separation can reduce TS by 30 to 45
percent. Solids separation methods include screen separators, mechanical
presses, settling tanks, settling basins, vacuum filters and many other
means. An efficient AD installation will reduce the TS percentage by up to
76 percent and VS by up to 90 percent. Of the above technologies, AD with
covered anaerobic lagoons is the only one the APCD considers a proven
technology because of their odor control effectiveness. Therefore, unlike
the other options above, covered anaerobic digesters do not have to meet
the additional testing requirements for technologies that the APCD
Composting may or
may not meet the TS requirement because it often involves the addition of
a bulking agent to increase TS to optimize waste decomposition. However,
composting can be effective at controlling odors and reducing pathogens.
The APCD is presently reviewing the compliance status of one facility that
uses composting. Composting has applications besides manure treatment for
livestock facilities. The Colorado Governor’s Office of Energy
Management and Conservation is currently supporting the demonstration of
composting technology for hog mortality disposal at a hog farm in
In an AD system,
most of the organic nitrogen (N) from the digester is converted to
ammonium, an easily manageable fertilizer with slow release properties
when compared to mineralized fertilizers. This is an advantage over
anaerobic lagoons alone. Organic N in the form of protein and urea is
mineralized in soil solution after land application. This mineralized N
can pose a groundwater problem when land-applied because mineralized N can
be converted to nitrates and leach into groundwater in the spring and fall
when plant uptake of N is low.
A disadvantage of
reducing the nutrient content of lagoon effluent via AD is the loss of the
value of nutrients. Reducing the use of lagoon effluent as fertilizer
increases the need for industrial fertilizers, the manufacture and
transportation of which uses significant quantities of petroleum. However,
this loss is balanced by the benefits of increased control farmers have
over the nutrient content of effluent used for irrigation purposes.
is a key concern for swine producers that are considering AD with energy
recovery as an objective. AD systems first began to be used extensively
after World War II in
when energy supplies were reduced. Today there are over 600 digesters in
alone. Farm-based anaerobic digesters are the most common application of
AD technology worldwide. In the
, livestock producers have less experience working with anaerobic
digesters, with a total of approximately 160 digesters either planned or
installed in 1998. Of these, 36 employ technology that is suitable for use
at swine facilities.
A recent survey of
anaerobic digesters yielded mixed results for system reliability (Table
4). At farms across the
, the percentage of installed digesters that are not operating is nearly
46 percent. However, one encouraging note is that the reliability of
digesters constructed since 1984 is much greater than for those
constructed between 1972 and 1984.
4 . Status of farm-based digesters at swine facilities in the
Source: Lusk, Phil
(September 1998). Methane Recovery from Animal Manures: the Current
Opportunities Casebook. NREL/SR-25145. NREL. Golden, CO. pp. 1-2.
The most common
reasons that systems are not operating include poor design and
installation and poor equipment specification. The lessons learned that
should be kept in mind for future systems include the need to select
qualified contractors and the fact that amortizing the cost of appropriate
equipment is less costly than a system failure. The improved reliability
of newer systems and increased understanding of the biological systems
that operate in an anaerobic digester suggest that the reliability of
systems will continue to improve as long as the lessons of past system
failures are heeded.
What is BioMethane?
BioMethane is a renewable energy/fuel, with properties similar to natural
gas, produced from "biomass." Unlike natural gas, BioMethane is a renewable energy.
The cost of producing
BioMethane, after installation of the
BioMass Gasification equipment used to produce BioMethane (the process of
making BioMethane is called "BioMethanation") is called is
Again, unlike the price of natural gas, which has been around $6.00/mmbtu
for the past year.
Gasification and BioMethanation Technology
The production and disposal of large quantities of organic and biodegradable waste without adequate
or proper treatment results in widespread environmental pollution. Some waste streams can be treated by conventional methods like aeration. Compared to the aerobic method,
the use of anaerobic digesters in processing these waste streams provides
greater economic and environmental benefits and advantages.
As previously stated,
Biomethanation is the process of conversion of organic matter in the waste (liquid or solid) to
BioMethane (sometimes referred to as "BioGas) and manure by microbial action in the absence of
air, known as "anaerobic digestion."
Conventional digesters such as sludge digesters and anaerobic CSTR (Continuous Stirred Tank
Reactors) have been used for many decades in sewage treatment plants for stabilizing the activated sludge and sewage solids.
Interest in BioMethanation as an
economic, environmental and energy-saving waste treatment continues to gain
greater interest world-wide and has led to the development of a range of anaerobic reactor designs. These high-rate,
high-efficiency anaerobic digesters are also referred to as "retained biomass reactors" since they are based on the concept of retaining viable biomass by sludge immobilization.
Biomass Gasification and the Production of BioMethane
Biomass is a renewable energy resource which includes a wide variety if organic resources. A few of these include wood, agricultural residue/waste, and animal manure.
Biomass Gasification is the process in which BioMethane is produced in the BioMass Gasification process. The BioMethane is then used like any other fuel, such as natural gas, which is not a
Historically, biomass use has been characterized by low btu and low efficiencies. However, today biomass gasification is gaining world-wide recognition and favor due to the economic and environmental benefits. In terms of economic benefits, the cost of the
BioMethane is essentially free, after the cost of the equipment is installed.
BioMethane, probably the most important and efficient energy-conversion technology for a wide variety of biomass fuels.
The large-scale deployment of efficient technology along with interventions to enhance the sustainable supply of biomass fuels can transform the energy supply situation in rural areas.
It has the potential to become the growth engine for rural development in the country.
Principles of Biomass Gasification
Biomass fuels such as firewood and agriculture-generated residues and wastes
are generally organic. They contain carbon, hydrogen, and oxygen along with some moisture. Under controlled conditions, characterized by low oxygen supply and high temperatures, most biomass materials can be converted into a gaseous fuel known as producer gas, which consists of carbon monoxide, hydrogen,
carbon dioxide, methane and nitrogen. This thermo-chemical conversion of solid biomass into gaseous fuel is called biomass gasification. The producer gas so produced has low a calorific
value (1000-1200 Kcal/Nm3), but can be burned with a high efficiency and a good degree of control without emitting smoke. Each kilogram of air-dry biomass (10% moisture content) yields
about 2.5 Nm3 of producer gas. In energy terms, the conversion efficiency of the gasification process is in the range of 60%-70%.
Multiple Advantages of Biomass Gasification
Conversion of solid biomass into combustible gas has all the advantages associated with using gaseous and liquid fuels such as clean combustion, compact burning equipment,
high thermal efficiency and a good degree of control. In locations, where biomass is already available at reasonable low prices (e.g. rice mills) or in industries using fuel wood,
gasifier systems offer definite economic advantages. Biomass gasification technology is also environment-friendly, because of the firewood savings and reduction in CO2 emissions.
Biomass gasification technology has the potential to replace diesel and other petroleum products in several applications, foreign exchange.
Applications for Biomass Gasification
Thermal applications: cooking, water boiling, steam generation, drying etc.
Motive power applications: Using producer gas as a fuel in IC engines for applications such as water pumping
Electricity generation: Using producer gas in dual-fuel mode in diesel engines/as the only fuel in spark ignition engines/in gas turbines.
Publicly Owned Treatment Works ("POTW's")
or Wastewater Treatment Systems
More and more,
cities, counties and
municipalities are faced with greater environmental compliance issues relating
to their municipally-owned landfills, Publicly Owned Treatment Works ("POTW's")
or Wastewater Treatment Systems. A city's landfill and/or POTW provides an excellent
opportunity for cities to reduce their emissions as well as provide an
additional revenue stream. These facilities may have valuable gases
that our company recovers and pipes to one of our clean,
environmentally-friendly cogeneration or trigeneration energy
systems. We solve a city's environmental liabilities (air emissions)
and provide a new cash flow simultaneously. We offer turn-key
solutions for cities that includes the preliminary feasibility analysis,
engineering and design, project management, permitting and
commissioning. We provide very attractive financing packages for
cities that does not add to a city's liability, yet provides a valuable
new revenue stream. And, we are also able to offer a turn-key
solution for qualified municipalities that includes our company owning,
operating and maintaining the onsite power and energy plant.
At the heart of
the system is a (Bio) Methane Gas Recovery system similar those used in Flare Gas Recovery or Vapor Recovery
Units. Methane Gas Recovery, Flare Gas Recovery,
Vapor Recovery, Waste to Energy and Vapor Recovery Units all recover valuable
"waste" or vented fuels that can be used to provide fuel for an
onsite power generation plant. Our waste-to-energy and waste to fuel
systems significantly or entirely, reduces your facility's emissions (such
SOx, H2S, CO
, CO2 and other Hazardous Air Pollutants/Greenhouse Gases) and convert
these valuable emissions from an environmental problem into a new cash
revenue stream and profit center.
and vapor recovery units can be located in hundreds of applications and
locations. At a landfill, Wastewaster Treatment System (or Publicly Owned
Treatment Works - "POTW") gases from the facility can be
captured from the anaerobic digesters, and manifolded/piped to one of our
onsite power generation plants, and make, essentially, "free"
electricity for your facility's use. These
that are generated from municipally owned landfills or wastewater
treatment plants have low btu content or heating values, ranging around
550-650 btu's. This makes them
unsuitable for use in natural gas applications. When burned as fuel to
generate electricity, however, these gases become a valuable source of
"renewable" power and energy for the facility's use or resale to
the electric grid.
heat (steam and/or hot water) is required, we will incorporate our
cogeneration or trigeneration system into the project and provide some, or
all, of your hot water/steam requirements. Similarly, at crude oil
refineries, gas processing plants, exploration and production sites, and
gasoline storage/tank farm site, we convert your facility's "waste
fuel" and environmental liabilities into profitable,
Our Methane Gas
Recovery systems are designed and engineered for
these specific applications. It is important to note that there are
many internal combustion engines or combustion turbines that are NOT
suited for these applications. Our systems are engineered precisely
for your facility's application, and our engineers know the engines and
turbines that will work as well as those that don't. More
importantly, we are vendor and supplier neutral! Our only
concerns are for the optimum system solution
for your company, and we look past brand names and sales propaganda to
determine the optimum system, which may incorporate either one or more;
gas engine genset(s) or gas turbine genset(s), in cogeneration or
trigeneration mode - in trigeneration mode, we incorporate absorption
chillers to make chilled water for process or air-conditioning, fuel
gas conditioning equipment and gas compressor(s).
systems includes design, engineering, permitting, project management,
commissioning, as well as financing for our qualified customers.
Additionally, we may be interested in owning and operating the flare gas
recovery or vapor recovery units. For these applications, there is no
investment required from the customer.
information, please provide us with the following information about the
flare gas or vapor:
Type of gas
being flared or vented (methane, bio-gas, digester, landfill, etc.).
Fuel/Gas analysis which provides us with the btu's (heating value) and
the composition of the gas and its' impurities such as methane (and
the percentage of methane), soloxanes, carbon dioxide, hydrogen,
hydrogen sulfide, and any other hydrocarbons.
of gas available, from all sources, at the facility.
Digester Lagoon with
Methane Gas Recovery: First year
Management and Economics
By Leland M. Seale,
Environmental Engineer, USDA-NRCS
lagoons are perhaps the most trouble free, low maintenance systems
available for treatment of animal waste. This is particularly true in the
southern U.S.where winter temperatures are mild, permitting anaerobic
digestion the year around. The effluent from the digester is a valuable
source of nitrogen for plants that can be field applied for improved crop
production. Placing a cover over the lagoon for collecting biogas
virtually eliminates odor from the lagoon. The collected biogas, a
byproduct of the digestion process, is typically 60 to 70 percent methane
that can be utilized as a valuable energy resource. Limited experience
indicates that odor from field application of effluent from two cell
covered lagoons is much reduced from what might be expected when applying
untreated or uncovered lagoon effluent. A properly designed, constructed
and operated anaerobic digester is a low maintenance system that is very
forgiving and not likely to create emergency situations that can be
expected with many alternative waste management systems. Adding methane
recovery to the anaerobic digester increases maintenance but even in the
event of failure of the gas collection system, it will not interrupt the
waste stream and digestion process. It is well suited to the livestock
is a voluntary program developed by the Environmental Protection Agency
(EPA) to encourage livestock producers to consider methane gas recovery as
part of their animal waste management system. Working in partnership with
the U.S.Department of Energy (DOE) and Department of Agriculture (USDA),
products, technical information and services are available to producers
through the AgSTAR program. For general information on the AgSTAR program
contact the AgSTAR hot line by dialing 1-800-95AgSTAR (952-4787). Natural
Resources Conservation Service (NRCS) is the agency under USDA working
with the AgSTAR program to assist producers with technical information.
1996, Julian Barham, a producer in Johnston County, NC, entered into an
agreement with EPA for a pilot project on his farm show casing the
technology and economic benefits of methane recovery from animal waste.
Mr. Barham's operation consisted of a modern 4000 sow, farrow to wean,
swine farm with an existing, 6 surface acre, anaerobic lagoon. A
feasibility study using AgSTAR technical information and software
indicated a five year pay back for a capital investment of approximately
$250,000. This included a new, 20 foot deep, 1.6 surface acre anaerobic
lagoon, a lagoon cover with gas collection system, and engine generator
with heat exchanger for heat recovery and cogeneration. The anaerobic
lagoon was designed and constructed in accordance with NRCS interim
standards and criteria. The lagoon cover was designed by RCM Digesters1
and manufactured by Reef Industries2 using permalon, (a 20 mil
reinforced HDPE material). The engine generator consisted of a CAT 3406
engine with a 120 KW induction generator. The lagoon was completed in the
fall of 1996 and filled with effluent from the existing lagoon. The
installation of the lagoon floating cover was completed in December 1996
and all gas system components including the engine generator installed by
start up experiences with the Barham project have shown that even with
knowledgeable consultants and technical expertise, problems do occur. Two
were significant: 1) An expensive engine generator (40% of capitol
investment) sits idle while waiting for the lagoon to mature and reach
predicted gas yields. 2) A manufacturing defect in the lagoon cover
material resulted in having to replace the cover. On the positive side, we
were surprised to find essentially no odor from the digester effluent,
even during field application. Based on this first year of experience,
this paper addresses measures in planning, design, operation and economics
that I believe could help avoid similar problems for livestock producers
considering methane gas recovery systems.
the AgSTAR Handbook3! "This handbook is for livestock
producers, developers, and others considering biogas recovery systems as a
livestock manure management and odor control option. The handbook provides
a step-by-step method to determine whether a particular biogas recovery
system is appropriate for your livestock facility. This handbook
complements the guidance and other materials provided by the AgSTAR
program towards promoting biogas recovery at commercial farms in the
United States." 3
study - The feasibility assessment is an evaluation of the producers
livestock facility and the key to determining the economic benefits of
methane recovery. Computer software developed under the AgSTAR program
facilitates this process. Although relatively simple and straight forward
to use, first time users are advised to review results with those
experienced with the program. How the biogas will be utilized and the
economic analysis to determine benefits is an important part of the
process. A completed feasibility study should include a preliminary cost
estimate, general layout of proposed operation, predicted biogas yields
and identified economic returns.
Feasibility - Compare the results of your study with experience of others.
If feasibility is based on economic returns of biogas utilization, compare
the predicted biogas yield with other similar operations. This can best be
accomplished by visiting farms where existing methane recovery systems are
functional and discussing with experienced operators. A list of known
farms is available by contacting the AgSTAR hot line noted above. If there
are no systems of the type proposed, either in operation or that you can
visit, be very cautious before proceeding.
contracts - When economic returns are based on assumed sales such as the
sale of power to a utility company, contracts should be obtained prior to
expenditure of funds. Don't assume this will happen after construction.
engineer - Hire an engineer with a proven track record. Ask for a list of
jobs completed. Check them out by telephone or site visit or both. Be sure
the design for your operation is similar to referenced work. Experience
with one type of digester does not mean the person is knowledgeable in
other types. Each system must be a site specific design. Lagoon cover
design is still experimental. The manufacturer should provide a
material/fabrication warranty in writing. One year is not be enough. Often
times consultants are trying to make improvements or to improve the
economics. Be sure you understand the purpose and function of each
component and understand what it does in your system. Improvements may or
may not work. It may cost you extra to correct if it does not work.
drawings - The consultant or designer should provide a complete set of
drawings and specifications for the work. The drawings should show each
component of the system. It is important for the owner/operator go over
the drawings and specifications prior to the beginning of construction,
identify each component and its function. This is also a good time to ask
the consultant if the specific component has been used on one of his jobs
before. This might be something as simple as the type of joints in the gas
pipe. The drawings and specifications should be accompanied by a design
report that explains how the system works and the design assumptions and
parameters. If these assumptions to not match the owner/operators
intentions or farm operation, one or the other will require modification.
and maintenance manual - Each job should come with a complete operation
and maintenance manual. The manual should address startup operation,
normal operation and emergency operations. It should address all elements
of the system and any special precautions.
and certifications - Since this will be a change to your livestock waste
management system, it may need to be certified or approved by state and/or
local jurisdictions. If cogeneration is part of the project, a licensed
electrician will need to certify design for interconnection to the
utility. Verify any cogeneration agreements with utility company prior to
start of construction.
is often accomplished by a combination of available farm labor and hired
contractors. Consultants will usually provide some assistance. It is
recommended that consultants or manufacturer's representative provide
onsite supervision for installation of the lagoon cover. Electrical wiring
and connection to utility must be done under the supervision of licensed
electricians and with approval of utility company.
start up - Operation should be in accordance with the guidelines provided
by the consultant. Expect the consultants to oversee the initial startup
and stabilization of the system. If it is a new livestock operation,
initial startup will be delayed while the lagoon matures. A temporary
flare may be installed near the lagoon to burn off biogas while waiting
for the lagoon to mature or completing construction on other elements of
the system. Each system is unique and will require adjustments as the
operator becomes familiar with peculiarities of the system.
- Methane is one of the byproducts of anaerobic digestion (a biological
process) in a lagoon. There are many variables that can affect the rate of
production. The makeup of the waste stream and the temperature are the
most critical. Both affect the rate of bacteria growth. More important, a
new lagoon requires a number of cycles before the bacterial colony is
sufficiently developed to produce the predicted volume of biogas. It is
not unreasonable to wait 1 to 2 years for the lagoon to mature and methane
production to reach predicted levels.
prepared for the unexpected - Methane recovery systems are still
experimental and do not always perform as predicted. The objective is to
collect the biogas from the lagoon surface and deliver it to the end use
point without the presence of atmospheric air. The introduction of air can
disrupt the performance of burners and more importantly engines in
cogeneration operations. An air leak anywhere in the system can be time
consuming to locate. This is particularly true if the problem is the
lagoon cover and it can be even more difficult to fix.
one - don't expect a return the first year. It will take at least one year
to get the bugs out and obtain consistent results. Also, there likely will
be changes, this will cost money and could offset any revenue.
capital investment - if cogeneration is part of the proposed system, begin
the first year with only the gas collection components and flare the gas
or burn for heat. Cogeneration systems are expensive (as much as 50
percent of the cost of construction) and adequate gas yield is critical to
successful operation. Monitor the lagoon and gas production the first year
to determine biogas yield (figure 1). After the first year, a cogeneration
unit can be purchased that matches the gas production or less expensive
alternatives can be pursued if the gas yield is limited.
odor control an economic benefit. Public opinion on odor is becoming more
vocal and without proper control, producers could be forced out of
are experimental, look for and expect financial assistance. Methane is a
renewable energy source and a greenhouse gas that contributes to global
warming. Federal and state agencies often will provide financial
assistance to promote alternative waste systems that reduce greenhouse
gases and or utilize renewable energy. The AgSTAR Handbook provides
guidance in looking for financial resources.
RCM Inc., Berkely, CA
Reef Industries, Houston, TX
AgSTAR Handbook, A Manual For Developing Biogas Systems at Commercial
Farms in the US, EPA
Farm, 4000 sow, farrow-to-wean, anaerobic lagoon. Picture taken in January
1997, one month after the cover installation.
produced by the lagoon during the first year of operation measured 35 to
45% ofthe predicted gas yield.