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California Senate Bill 700 Update

Overview of California SB 700

In the past, agricultural operations have been exempt from obtaining air quality permits from local air districts. However, in September 2003, the governor signed into law Senate Bill 700 (SB 700). This bill amended air pollution control requirements in the California Health and Safety Code to include regulatory requirements for agriculture.

SB 700 targeted agriculture and air pollution for two main reasons. First, California’s previous agriculture exemption conflicted with federal law. California would have lost billions of dollars in federal transportation funding, as well as faced other sanctions if the bill had not passed. Secondly, in some parts of the state -including the Sacramento air basin - air quality is poor and agricultural activities contribute to the problem. Poor air quality harms public health - causing and/or exacerbating asthma, respiratory illness, heart and lung disease, and early mortality.

SB 700 eliminated the agricultural operation permit exemption in the California Health and Safety Code in its entirety. As a result, agricultural operations may now be required to obtain air quality permits from the local air district. The bill sets up more specific guidance and required elements, but ultimately it will be up to individual air districts to determine how to implement the bill.

Permitting Structure - The Yolo-Solano Air Quality Management District is in the process of determining the best solutions to address SB 700 requirements for agricultural operations within our jurisdiction. SB 700, however, does require - at a minimum - a general three tiered permitting structure:

1. Title V Permits - Large agricultural operations, whose potential to emit (see definitions section) exceeds the District’s “major source threshold.”

2. Local Permits - Large agricultural operations, whose actual emissions (see definitions section) exceeds one-half (˝) the District’s “major source threshold.”

3. CAFO Permits - “Large” confined animal feeding operations will require a CAFO permit. The definition of a “large” CAFO has not been determined yet. SB 700 requires the California Air Resources Board to review all available scientific information, including but not limited to emissions factors for CAFO’s, and the effect of those facilities on air quality in the basin and other relevant scientific information, and develop a definition for the source category of “large” CAFO (see definitions section). The definition must be adopted in a public hearing, and the hearing must occur on or before July 1, 2005.

EPA Part 71 program 

Some farm owners/operators may remember applying for a Title V permit last year. In October 2002, the Environment Protection Agency (EPA) partially withdrew the Title V operating permit program from California air districts since California’s agricultural exemption conflicted with federal law. EPA started a federal Part 71operating permit program for major agricultural operations in the state of California. Under this program, EPA required agricultural operations to submit their Part 71 permit applications to the Agency by May 14, 2003. 

When SB 700 was signed into law, EPA withdrew the Part 71 program and restored the full Title V operating permit program to California air districts. Since EPA’s Part 71 program has dissolved, those who applied for the program are now required to re-apply for a Title V permit through the District. This may be frustrating to farm owners/operators who had applied for the Part 71 program, however, the District is committed to providing assistance to applicants throughout the permitting process.

Working with the Agricultural Community.

The goal of the District is to ensure that new SB 700 permitting requirements can be implemented and to make sure that everyone understands their responsibilities under this new law. District staff is ready to work with the agricultural community during the development of new agricultural permitting programs, as well as the permitting process. After decades of exemptions, the District has limited experience permitting agricultural operations. Therefore, to aid in the development of these new programs, the District has established the Agricultural Permitting Advisory Committee (APAC). 

The idea behind APAC is to bring together the local agricultural community, agricultural officials, and other interested parties, to share their expertise and comments with the District. TheAPAC will ensure the District develops new rules that fulfill the required elements of SB 700 while remaining fair to the agricultural community. The diversity of this committee will bring different perspectives from eachparticipant - helping the District create effective permitting programs.

APAC participants were identified by the District as leaders within the local agricultural community orpossessing a strong interest in SB 700 regulations. 

Potential candidates targeted for APAC participation include: the Yolo and Solano County Agricultural Commissioners, Yolo and Solano County Farm Bureau representatives, Sierra Club representatives and local grower’s groups/associations.

Application Forms and Outreach Current District application forms are not designed for agricultural permitting. Therefore, the District plans on creating new agricultural specific forms to help streamline the application process. The District is aiming for these forms to be available by October 2004.The District understands that these new rules and requirements are new to everyone. The District has a tentative plan to hold workshops between October-December 2004 to aid farm owners/operators in understanding the new requirements, determine which permitting program their operation falls into, and help fill out application forms. 


Source - The term “source” may refer to an individual piece of equipment such as an internal combustion engine or to a group of emitting equipment.

Agricultural Source (Operation) - SB700 generally defines “agricultural source” as a source, or group of sources, used in the production of crops or the raising of fowl or animals located on contiguous property (see below) and under common ownership or control (see below).

Contiguous Property: The simplest definition of “contiguous” is when two property parcels are actually touching at a boundary. There are other situations that the courts have determined to be “contiguous” for the purposes of determining what emitting activities are part of the source. Some examples include parcels that are divided by roadways, or which are separated by some distance but are functionally interconnected. Generally, the courts have ruled that artificial separations between related activities do not create separate sources.

Common Ownership or Control - Property is under “common ownership or control” if the same person owns both parcels or operations. Contractual agreements between two parties can also constitute “commonownership or control.” This is another area that has been defined over time by court rulings.

Potential to Emit - An operation’s potential to emit is generally considered to be the maximum amount of air pollution it can emit, considering physical and other enforceable limitations.

Actual Emissions - The emissions produced by a source based on its normal operating conditions. 

This may be derived from actual measurements or emissions testing, or historical records of activities which can be used to estimate emissions. 

Confined Animal Feeding Operation (CAFO) - SB700 defines “confined animal feeding operation” to include essentially any type of confinement for animals or fowl that restricts them to a specific area, and involves feeding the animals by any method other than grazing. This specifically includes barns, pens, corrals, and coops, but should be interpreted broadly. The definition also specifically lists other markers of CAFs, including feed storage, milking parlors, and systems to collect, store, treat, and distribute liquid or solid manure from the confined animals.

What 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 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. 

The U.S. EPA AgSTAR Program Background

The 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 systems, including:

  • Conducting farm digester extension events and conferences
  • Providing “How-To” project development tools and industry listings
  • Conducting performance characterizations for digesters and conventional waste management systems
  • Operating a toll free hotline
  • Providing farm recognition for voluntary environmental initiatives
  • Collaborating with federal and state renewable energy, agricultural, and environmental programs

Methane Emissions from Animal Waste Management

Methane 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 U.S. 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 Analyses.

Emission Reduction Technology: Anaerobic Digestion

For 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 MB


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 waste management.

Chart showing how many farms have biogas recovery systems in place.

The 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 markets.

In the past 2 years alone, the number of operational digester systems has increased by 30%. For more detailed information on anaerobic digester use in the U.S. , go to the Guide to Operational Systems or see the AgSTAR 2003 Digest

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. 

Technology assessment

This section 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.

Anaerobic 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 include:

  • Odor reduction;
  • Reduction in the biological oxygen demand of treated effluent by up to 90 percent, reducing the risk for water contamination;
  • Improved nutrient application control, because up to 70 percent of the nitrogen in the waste is converted to ammonia, the primary nitrogen constituent of fertilizer;
  • Reduced pathogens, viruses, protozoa and other disease-causing organisms in lagoon water, resulting in improved herd health and possible reduced water requirements; and
  • Potential 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.

Digester technologies that can be used to collect biogas from swine facilities include:

  • Covered anaerobic lagoons,
  • Complete mix digesters and
  • Sequencing batch reactors.

Although a sequencing batch reactor has been used for AD at one swine facility in the United States , 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.

Covered lagoon 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 United States . EPA 430-B-97-015. Washington , DC . pp. 1-3.

Figure 1 . Covered anaerobic lagoon digester

Covered lagoon 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.

Complete mix 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 Colorado that recovers methane for energy use is a complete mix digester, located at Colorado Pork LLC near Lamar , Colorado .

Source: EPA. (February 1997). AgStar Technical Series: Complete Mix Digesters – A Methane Recovery
Option for All Climates. EPA 430-F-97-004.
Washington , DC .

Figure 2 . Complete mix digester schematic

Complete mix 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.

System Requirements

This section 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:

  • Simultaneously house at least 2,000 animals with a total live animal weight of at least 110,000 pounds,
  • Have no more than 20 percent variation in animal population throughout the year,
  • Collect waste at one central location such as an underfloor pit,
  • Collect waste daily or every other day, or can convert to an equivalent collection system,
  • Have manure free of large amounts of bedding or other foreign materials, and
  • Have some manure storage capability to maintain a steady digester feedstock supply

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 United States 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 Colorado

Source: EPA. (July 1997). AgStar Handbook: A Manual for Developing Biogas Systems
at Commercial Farms in the United States . 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.

Table 2 . Matching a digester to existing waste collection practices

Collection system

Percent TS required

Digester type

Suitable climate



Complete mix

Warm or cold

Pit storage


Complete mix

Warm or cold



Covered lagoon


Pit recharge


Covered lagoon


Gravity drainage




Pull plug


Covered lagoon


Managed pull-plug


Complete mix

Warm or cold

Source – Adapted from: EPA. (July 1997). AgStar Handbook: A Manual for Developing Biogas Systems at Commercial
Farms in the United States . EPA 430-B-97-015. pp. 4-15.

Appendix C describes each of the various waste collection technologies listed in Table 2.

Biogas Utilization Options

This section 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 applications.

Electricity Generation

Commercial 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.

Biogas engines 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 percent.

Emerging new 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 Wisconsin 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 Colorado , 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 Viejo , California 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 , California 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 California Polytechnic State University ’s demonstration farm.

Direct Combustion

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.

System 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:

  • Odor control,
  • Water quality protection
  • Energy production.

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 Colorado . 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.

Table 3 . Odor control effectiveness of management strategies for anaerobic lagoons

Odor control technology

Percent (%) odorous gas emissions reduction

Feed processing/additives


Grinding feed


Wet-feeding hogs (3:1 water to feed)


Reducing sulfur-containing amino acids


Adding fiber (soybeans, hulls to diet)

Up to 68



Solids separation


Soil injection of waste upon land application

50-80 (land application odors only)

Surface aeration

Up to 85

Aerobic cap

Up to 90

Lagoon additives

Up to 90

Lagoon covers


Anaerobic digestion



Up to 100 for well-managed systems

Source: Iversen, Kirk and Jessica Davis. (February 1999). Innovations in odor management technology. Colorado State University . Agricultural and Resource Policy Report. APR-99-02. Fort Collins , CO .

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,
  • Solids separation,
  • AD and
  • Composting.

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 considers experimental.

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 Colorado .

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.

System Reliability

System reliability 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 Europe when energy supplies were reduced. Today there are over 600 digesters in Europe alone. Farm-based anaerobic digesters are the most common application of AD technology worldwide. In the U.S. , 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 U.S. , 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.

Table 4 . Status of farm-based digesters at swine facilities in the United States


Covered lagoon digesters

Complete mix digesters






Not operating




Facility closed




Planned/Under construction




Planned but not built








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 essentially free.  

Again, unlike the price of natural gas, which has been around $6.00/mmbtu for the past year. 

More About Biomass 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 renewable fuel.

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 as NOx , 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.

Methane Gas Recovery 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 associated "biogases" 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. 

Additionally, if 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, environmentally-friendly solutions.

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). 

Our turn-key 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.

For more 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.).

  • Chromatograph 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. 

  • Total amount of gas available, from all sources, at the facility.  

Anaerobic Digester Lagoon with
Methane Gas Recovery: First year
Management and Economics

By Leland M. Seale, Environmental Engineer, USDA-NRCS

Anaerobic 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 industry.

AgSTAR 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.

In 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 3/97.

The 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.


Use 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

Feasibility 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.

Verify 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.

Secure 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.


Experienced 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.

Complete 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.

Operation 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.

Regulations 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.


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.


Initial 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.

Patience - 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.

Be 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.


Year 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.

Phase 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.

Consider odor control an economic benefit. Public opinion on odor is becoming more vocal and without proper control, producers could be forced out of business.

Systems 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.


1 RCM Inc., Berkely, CA

2 Reef Industries, Houston, TX

3 AgSTAR Handbook, A Manual For Developing Biogas Systems at Commercial Farms in the US, EPA

Picture 1

Barham Farm, 4000 sow, farrow-to-wean, anaerobic lagoon. Picture taken in January 1997, one month after the cover installation.

Figure 1

Biogas produced by the lagoon during the first year of operation measured 35 to 45% of the predicted gas yield.





* Waste Heat Recovery

Many industrial processes generate large amounts of waste energy that simply pass out of plant stacks and into the atmosphere or are otherwise lost. Most industrial waste heat streams are liquid, gaseous, or a combination of the two and have temperatures from slightly above ambient to over 2000 degrees F. Stack exhaust losses are inherent in all fuel-fired processes and increase with the exhaust temperature and the amount of excess air the exhaust contains. At stack gas temperatures greater than 1000 degrees F, the heat going up the stack is likely to be the single biggest loss in the process. Above 1800 degrees F, stack losses will consume at least half of the total fuel input to the process. Yet, the energy that is recovered from waste heat streams could displace part or all of the energy input needs for a unit operation within a plant. Therefore, waste heat recovery offers a great opportunity to productively use this energy, reducing overall plant energy consumption and greenhouse gas emissions. 

Waste heat recovery methods used with industrial process heating operations intercept the waste gases before they leave the process, extract some of the heat they contain, and recycle that heat back to the process. 

Common methods of recovering heat include direct heat recovery to the process, recuperators/regenerators, and waste heat boilers. Unfortunately, the economic benefits of waste heat recovery do not justify the cost of these systems in every application. For example, heat recovery from lower temperature waste streams (e.g., hot water or low-temperature flue gas) is thermodynamically limited. Equipment fouling, occurring during the handling of “dirty” waste streams, is another barrier to more widespread use of heat recovery systems. Innovative, affordable waste heat recovery methods that are ultra-efficient, are applicable to low-temperature streams, or are suitable for use with corrosive or “dirty” wastes could expand the number of viable applications of waste heat recovery, as well as improve the performance of existing applications. 

Various Methods for Recovery of Waste Heat

Low-Temperature Waste Heat Recovery Methods – A large amount of energy in the form of medium- to low-temperature gases or low-temperature liquids (less than about 250 degrees F) is released from process heating equipment, and much of this energy is wasted. 

Conversion of Low Temperature Exhaust Waste Heat – making efficient use of the low temperature waste heat generated by prime movers such as micro-turbines, IC engines, fuel cells and other electricity producing technologies. The energy content of the waste heat must be high enough to be able to operate equipment found in cogeneration and trigeneration power and energy systems such as absorption chillers, refrigeration applications, heat amplifiers, dehumidifiers, heat pumps for hot water, turbine inlet air cooling and other similar devices. 

Conversion of Low Temperature Waste Heat into Power –The steam-Rankine cycle is the principle method used for producing electric power from high temperature fluid streams. For the conversion of low temperature heat into power, the steam-Rankine cycle may be a possibility, along with other known power cycles, such as the organic-Rankine cycle. 

Small to Medium Air-Cooled Commercial Chillers – All existing commercial chillers, whether using waste heat, steam or natural gas, are water-cooled (i.e., they must be connected to cooling towers which evaporate water into the atmosphere to aid in cooling). This requirement generally limits the market to large commercial-sized units (150 tons or larger), because of the maintenance requirements for the cooling towers. Additionally, such units consume water for cooling, limiting their application in arid regions of the U.S. No suitable small-to-medium size (15 tons to 200 tons) air-cooled absorption chillers are commercially available for these U.S. climates. A small number of prototype air-cooled absorption chillers have been developed in Japan, but they use “hardware” technology that is not suited to the hotter temperatures experienced in most locations in the United States. Although developed to work with natural gas firing, these prototype air-cooled absorption chillers would also be suited to use waste heat as the fuel. 

Recovery of Waste Heat in Cogeneration 
and Trigeneration Power Plants

In most cogeneration and trigeneration power and energy systems, the exhaust gas from the electric generation equipment is ducted to a heat exchanger to recover the thermal energy in the gas. These heat exchangers are air-to-water heat exchangers, where the exhaust gas flows over some form of tube and fin heat exchange surface and the heat from the exhaust gas is transferred to make hot water or steam. The hot water or steam is then used to provide hot water or steam heating and/or to operate thermally activated equipment, such as an absorption chiller for cooling or a desiccant dehumidifer for dehumidification.

Many of the waste heat recovery technologies used in building co/trigeneration systems require hot water, some at moderate pressures of 15 to 150 psig. In the cases where additional steam or pressurized hot water is needed, it may be necessary to provide supplemental heat to the exhaust gas with a duct burner.

In some applications air-to-air heat exchangers can be used. In other instances, if the emissions from the generation equipment are low enough, such as is with many of the microturbine technologies, the hot exhaust gases can be mixed with make-up air and vented directly into the heating system for building heating.

In the majority of installations, a flapper damper or "diverter" is employed to vary flow across the heat transfer surfaces of the heat exchanger to maintain a specific design temperature of the hot water or steam generation rate. 

Typical Waste Heat Recovery Installation

In some co/trigeneration designs, the exhaust gases can be used to activate a thermal wheel or a desiccant dehumidifier.  Thermal wheels use the exhaust gas to heat a wheel with a medium that absorbs the heat and then transfers the heat when the wheel is rotated into the incoming airflow.

A professional engineer should be involved in designing and sizing of the waste heat recovery section. For a proper and economical operation, the design of the heat recovery section involves consideration of many related factors, such as the thermal capacity of the exhaust gases, the exhaust flow rate, the sizing and type of heat exchanger, and the desired parameters over a various range of operating conditions of the co/trigeneration system — all of which need to be considered for proper and economical operation.

For more information on Publicly Owned Treatment Works & Wastewater Treatment Systems, Flare Gas Recovery, Vapor Recovery Units, Waste To Fuel/Waste To Energy systems, and Waste Heat Recovery and Waste Heat Boilers,

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