Concentrated Animal Feeding Operation | CAFO | Animal | Waste to Fuel | Livestock | Feeding Operation

Concentrated Animal Feeding Operation
www.ConcentratedAnimalFeedingOperation.com

Concentrated Animal Feeding Operation - CAFO

Anaerobic Digesters * Biogas Development * Biogas Plant * Biogas Recovery * Biogas to Biomethane

Biomethane * Cogeneration * CHP System * Emissions Abatement * Waste to Energy * Waste to Fuel

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Renewable Energy Institute

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Biogas Plants Generate "Biomethane"

Biomethane = Renewable Natural Gas = Carbon Free Energy

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“spending hundreds and hundreds and hundreds of billions of dollars every year for oil, much of it from the Middle East, is just about the single stupidest thing that modern society could possibly do. It’s very difficult to think of anything more idiotic than that.”
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For more information, call/email
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info@ConcentratedAnimalFeedingOperation.com

A Concentrated Animal Feeding Operation or CAFO is an agricultural operation where animals are located, kept and raised in "confined" locations.

The purpose of a Concentrated Animal Feeding Operation is to congregate and contain and feed the livestock, as well as to contain the manure and urine, any animals that may die, and associated production operations in a small land area. The animal's feed is brought to them instead of the animals grazing pastures, fields, or on nearby rangeland.

How does my livestock operation get the designation of an Animal Feeding Operation?

The Renewable Energy Institute is the Publisher for the Leading Sites
for Anaerobic Digesters and Protecting Public Health, including;

Biogas is the "crude methane" that is generated from landfills (landfill gas) or from anaerobic digesters (also called "methane digesters"). In both landfills and anaerobic digesters, the biogas is generated without oxygen, hence the name, "anaerobic."

It should be pointed out that the biogas or "crude methane" generated from anaerobic digesters has zero value and cannot be used as a fuel, or sold to a gas company. This is due to the fact that the biogas produced from the anaerobic digesters contains a large number of contaminants including H2S, siloxanes, carbon dioxide and nitrogen. If used as a fuel in an engine or turbine, the engine or turbine would quickly fail. So, the crude biogas, must be cleaned to "pipeline quality gas" through the use of "natural gas treating" equipment, also referred to as "biogas to biomethane" equipment, that upgrades the biogas into biomethane, which is then a useful product that can be sold as pipeline quality gas or used as a fuel in engines or turbines.

Methane Recovery (and Biogas Recovery) is the process of recovering methane, also referred to as natural gas or CH4.

Biogas, a "crude" form of methane, can be recovered from a number of facilities and locations, including; dairy farms, landfills wastewater treatment plants using Anaerobic Digesters and cleaned up to "pipeline quality gas" with "biogas to biomethane" equipment.

Biogas Processing, also referred to as Biogas Conditioning is the process of purifying "biogas to biomethane" and removes the impurities of raw biogas, such as; H2S, CO2, nitrogen, siloxanes, H20, and other impurities.

Natural Gas Processing plants separate the various hydrocarbons and natural gas liquids from the pure natural gas (methane or CH4) to produce what is known as 'pipeline quality' natural gas. Natural gas pipeline companies have requirements on natural gas they buy from producers which is why the natural gas processing plants are located where they are, and why they separate the ethane, propane, butane, and pentanes from the methane. Natural gas liquids or NGLs include ethane, propane, butane, iso-butane, and natural gasoline.

The synthesis gas (syngas) produced from biomass gasification and plasma gasification plants contains a wide and varying number of pollutants and contaminants before the synthesis gas can be used as a "fuel gas." These pollutants and contaminants include;

To meet environmental emission regulations, as well as to protect downstream processes, the owner/operator of biomass gasification and plasma gasification plants must insure these are removed in a "syngas cleanup" process.

Depending on the application, the synthesis gas may also require "conditioning" to adjust the hydrogen-to-carbon monoxide (H2-to-CO) ratio to meet downstream process requirements.

In applications where very low sulfur (<10 ppmv) synthesis gas is required, converting the carbonyl sulfide (COS) to hydrogen sulfide (H2S) before sulfur removal may also be required.

Fine Particulate Removal

The synthesis gas leaving today’s biomass gasification plants and tomorrow's plasma gasification plants is normally quenched and scrubbed with water in a trayed column for fine char and ash particulate removal prior to recycle to the slurry-fed biomass gasifiers.

For dry feed biomass gasification, cyclones and candle filters are used to recover most of the fine particulate for recycle to the biomass gasifiers before final cleanup with water quenching and scrubbing. In addition, fine particulates, chlorides, ammonia, some H2S, and other trace contaminants are also removed from the synthesis gas during the scrubbing process. The "scrubbed" synthesis gas is then either reheated for COS hydrolysis and/or a sour WGS when required, or cooled in the low temperature gas cooling (LTGC) system by generating low pressure steam, preheating boiler feed water, and heat exchanged with cooling water before further processing.

Spent water from the scrubber column is directed to the sour water treatment system, where it is depressurized and decanted in a gravity settler to remove fine particulates. Solid-concentrated underflows from the settler bottom are filtered to recover the fine particulate as the filter cake, which is then either discarded or recycled to the biomass gasifiers depending on its carbon content. Water from the settler is recycled for biomass gasification uses with the excess being sent to the wastewater treatment system for disposal.

COS Hydrolysis and Water-Gas-Shift

Most of the sulfur in the coal is converted to H2S during the biomass gasification process. Depending on the specific biomass gasification temperature and moisture content, approximately 3 to 10% of the sulfur is converted to COS. To generate low sulfur synthesis gas, the COS in the product gas needs to be converted to H2S before sulfur removal via current commercial AGR processes. This is done by passing the synthesis gas from the water scrubber through a catalytic hydrolysis reactor where over 99% of the COS is converted to H2S. The scrubbed synthesis gas feed is normally re-heated to 30 to 50 °F above saturation to avoid catalyst damage by liquid water.

In applications where a high synthesis gas H2-to-CO ratio is needed, synthesis gas from the water scrubber is passed through a multi-stage reactor containing sulfur-tolerant shift catalysts to convert CO and water into additional H2 and CO2. Normally, excess moisture is present in the scrubber synthesis gas from slurry-fed gasifiers to drive the shift reaction to achieve the required H2-to-CO ratio. For most slurry-fed biomass gasification systems, a portion of the synthesis gas feed may need to be bypassed around the sour shift reactor to avoid exceeding the required product H2-to-CO ratio. Depending on the gasification process and the required H2-to-CO ratio, additional steam injection before the sour shift may be needed for dry-fed biomass gasifiers. The scrubber synthesis gas feed is normally re-heated to 30 to 50 °F above saturation to avoid catalyst damage by liquid water. Shifted synthesis gas is cooled in the LTGC system by generating low pressure steam, preheating boiler feed water, and heat exchanging it against cooling water before going through the AGR system for sulfur removal.

Mercury and Trace Elements

Current commercial practice is to pass cooled synthesis gas from LTGC through sulfided, activated carbon beds to remove over 90% of the mercury and a significant amount of other heavy metal contaminants. Due to the sulfur in the activated carbon, these beds are normally placed ahead of the AGR system to minimize the possibility of sulfur slipping back into and contaminating the cleaned synthesis gas.

Acid Gas Removal (AGR)

Raw synthesis gas exiting the particulate removal and gas conditioning systems, typically near ambient temperature at 100°F, is routed to the AGR system where H2S removal and CO2 removal from the synthesis gas occurs using either physical or chemical solvent absorption. For chemical synthesis applications which require synthesis gas with less than 1 ppmv sulfur, physical solvent processes such as Rectisol and Selexol are normally used. For power generation applications, which allow higher sulfur levels (approximately 10 to 30 ppmv sulfur), chemical solvent processes such as Methyl diethanolamine (MDEA) and Sulfinol are normally used. The physical solvent absorption processes operate under cryogenic temperatures while the chemical solvent absorption processes operate slightly above ambient temperature.

In both physical and chemical absorption processes, the synthesis gas is washed with lean solvent in the absorber for H2S removal. Cleaned synthesis gas from the Acid Gas Removal process is then sent to downstream systems for further processing. Rich solvent leaving the bottom of the absorber is sent to the regenerator, where the solvent is stripped with steam under low pressure to remove the absorbed sulfur. The concentrated acid gas stream exits the top of the stripper and is sent to the Sulfur Recovery Unit (SRU) for sulfur recovery. The regenerated lean solvent from the bottom of the stripper is cooled by a heat exchanger against the rich solvent, followed by water cooling before being sent back to the absorber to start the absorption process again. The physical solvent processes tend to co-absorb more CO2 than MDEA. Multiple step depressurization of the rich solvent, supplemented with nitrogen stripping, is employed by the physical solvent processes to reject sufficient CO2 to concentrate the acid gas from the regenerator overhead to at least 15 to 25 Vol% H2S in order to feed the Claus SRU.

Because of the need for refrigeration, as well as more complex solution flashing arrangements, physical solvent processes are two to four times more costly than MDEA-based chemical solvent processes. While the physical solvent processes have higher power consumption than the chemical solvent processes, the chemical processes have higher steam consumption which translates to reduced power output from the power train. Thus overall net power output may be similar between the two types of AGR processes.