Gas Processing | Natural Gas Processing

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Gas Processing & Midstream Oil and Gas
Engineering, Products and Services

Gas Processing

Midstream Oil and Gas
Engineering Services * New & Used Equipment Sales

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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.”

~ R. James Woolsey, Jr., former Director of the CIA

Price of Addiction
###
to Foreign Oil

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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 downstream sector usually refers to crude oil refineries and the selling and distribution of natural gas and products derived from crude oil. These products include Liquefied Petroleum Gas or "LPG," gasoline, jet fuel, diesel fuel, and other fuel oils, as well as asphalt and petroleum coke.

The Upstream Oil and Gas segment is a term that refers to the searching, drilling and production of crude oil and natural gas. The Upstream Oil and Gas segment is also known as the "exploration and production" or "E&P" segment.

The Upstream Oil and Gas segment includes; exploring for potential underground (or underwater) oil and natural gas fields (or reservoirs), drilling of exploratory wells, and operating/producing the oil and natural gas wells that "pay" with crude oil and/or natural gas

Master Limited Partnership (MLPs) are limited partnerships that are publicly traded on a securities exchange.

MLPs combine the tax benefits of Limited Partnerships with the liquidity and protection/oversight of a publicly traded security.

Master Limited Partnerships are limited by regulation to apply to specific businesses - most notably - natural resources, including; oil and natural gas extraction and transportation.

To qualify for MLP status, a partnership must generate at least 90 percent of its income from "qualifying" sources/resources. For many Master Limited Partnerships, this includes activities related to the production, processing or transportation of oil, natural gas and coal.

Master Limited Partnerships pay their investors through Quarterly Required Distributions or QRDs. The amount of the QRDs is stated in the contract between the Limited Partners (the investors) and the General Partner (the managers). Failure of the General Partner to pay the quarterly required distributions constitutes a default of the MLP Agreement.

Due to the stringent provisions on Master Limited Partnerships and the QRD, the majority of all Master Limited Partnerships are pipeline businesses, and natural gas companies engaged in the "midstream" oil and natural gas sector, which generated a reliable and steady income from the oil and natural gas sector.

Because MLPs are a partnership, there is no corporate income tax at either the state or federal level. The Limited Partners (investors) are able to record a pro-rated share of the investment in the Master Limited Partnership's depreciation on their personal income tax filings which further reduces their (that year's) tax liabilities. This is the primary benefit of Master Limited Partnerships and provides MLPs relatively inexpensive funding and capital costs. Simultaneously, this makes Master Limited Partnerships unattractive to "tax-deferred funds" that are unable to utilize this tax savings advantage. To encourage tax-deferred investors, MLPs set up new corporation holding companies for their Limited Partner's claims which can then issue equity.

In most new Master Limited Partnerships, the General Partner starts out with a small stake or position in the company - typically in the 2% to 5% range. However, the MLP receives "incentive distributions" from the net income after the Quarterly Required Distributions. As the incentive distributions are normally paid in the form of increased equity claims this allows the General Partner to attain an increasingly greater percentage of ownership in the company over time.

There are periods of time in peak periods of natural gas use, that a natural gas company (pipeline or LDC) may not be able to keep up with these peak demand periods. Natural gas storage is a way to help provide for the natural gas reserves or natural gas supplies that are needed during these peak demand periods. Having strategically-located natural gas storage capabilities can assist natural gas pipelines or LDCs provide the natural gas supply when their customers demand.

Recent governments studies conclude that demand for clean-burning natural gas has continued to rise. In the last 20 years, natural gas consumption has risen nearly 25%.

The Energy Information Administration (EIA) estimates there are over 2,100 Trillion cubic feet (Tcf) of "technically recoverable natural gas" reserves in the United States, as reported in the EIA's 2010 Annual Energy Outlook. In 2009, the United States used just over 22 Trillion cubic feet of natural gas, making the U.S. one of the global leaders in natural gas consumption. This means the U.S. has enough natural gas supply to last about 100 years.

With greater demand comes greater need to be able to store natural gas. In the past 20 years, natural gas storage has increased less than 5%. This creates a serious constraint that can impact our nation by failing to keep up with natural gas supply and demand. Existing natural gas storage facilities will not be able to keep up with the demand for natural gas during increasingly greater periods of increasing demand, which could cost all consumers of natural gas billions of dollars.

There is a critical need for new high-volume natural gas storage facilities to meet the escalating demand for natural gas which will provide predictability of natural gas supply and reduce or eliminate volatility of natural gas prices during peak periods. Natural gas storage "balance" the load - or supply and demand requirements of all natural gas consumers and provides the "cushion" needed for large supplies of natural gas to serve all consumers during periods of peak demand.

Natural gas storage can take place in a number of underground natural gas facilities. From the time the natural gas is produced, it may be stored temporarily in underground natural gas storage facilities that may be one or more of the following; depleted oil or natural gas fields/reservoirs, salt dome caverns/salt dome storage or former aquifers.

Most of the natural gas storage in the U.S. takes place in naturally-occurring natural gas or oil reservoirs that have been depleted through production. An underground gas storage facility must contain enough “base gas” or “cushion gas” that provides adequate pressure to re-produce and extract the natural gas.

The principal service provided by a natural gas processing plant to the natural gas mainline transmission network is that it produces pipeline quality natural gas. Natural gas mainline transmission systems are designed to operate within certain tolerances. Natural gas entering the system that is not within certain specific gravities, pressures, Btu content range, or water content level will cause operational problems, pipeline deterioration, or even cause pipeline rupture.

Natural gas processing plants are also facilities designed to recover natural gas liquids from a stream of natural gas that may or may not have passed through lease separators and/or field separation facilities. These facilities also control the quality of the natural gas to be marketed. Several types of natural gas processing plants, employing various techniques and technologies to extract contaminants and natural gas liquids, are used to produce pipeline quality "dry" gas. At many processing plants the primary objective is the production of dry gas (demethanizing). Any remaining natural gas liquids extraction stream is directed to a separate plant to undergo what is referred to as a "gas fractionation" process.

But a number of natural gas processing plants do include these gas fractionation plants where saturated hydrocarbons are removed from natural gas and separated into distinct parts, or "fractions," such as propane, butane, and ethane. Essentially, natural gas is methane, a colorless, odorless, flammable hydrocarbon gas (CH₄). Also present in natural gas production, especially that in association with oil production, are a number of petroleum gases. They include (in addition to ethane, propane and butane) ethylene, propylene, butylene, isobutane, and isobutylene. They are derived from crude oil refining or natural gas fractionation and are liquefied through pressurization.

The natural gas mainline (transmission line) is a wide-diameter, often-times long-distance, portion of a natural gas pipeline system, excluding laterals, located between the gathering system (production area), natural gas processing plant, other receipt points, and the principal customer service area(s). The lateral, usually of smaller diameter, branches off the mainline natural gas pipeline to connect with or serve a specific customer or group of customers.

A natural gas mainline system will tend to be designed as either a grid or a trunkline system. The latter is usually a long-distance, wide-diameter pipeline system that generally links a major supply source with a market area or with a large pipeline/LDC serving a market area. Trunklines tend to have fewer receipt points (usually at the beginning of its route), fewer delivery points, interconnections with other pipelines, and associated lateral lines.

A grid type transmission system is usually characterized by a large number of laterals or branches from the mainline, which tend to form a network of integrated receipt, delivery and pipeline interconnections that operate in, and serve major market areas. In form, they are similar to a local distribution company (LDC) network configuration, but on a much larger scale.

Between the producing area, or supply source, and the market area, a number of compressor stations are located along the transmission system. These stations contain one or more compressor units whose purpose is to receive the transmission flow (which has decreased in pressure since the previous compressor station) at an intake point, increase the pressure and rate of flow, and thus, maintain the movement of natural gas along the pipeline.

Gas compressors are used on a natural gas mainline transmission system are usually rated at 1,000 horsepower or more and are of the centrifugal (turbine) or reciprocating (piston) type. The larger gas compression stations may have as many as 10-16 units with an overall horsepower rating of from 50,000 to 80,000 HP and a throughput capacity exceeding three billion cubic feet of natural gas per day. Most compressor units operate on natural gas (extracted from the pipeline flow); but in recent years, and mainly for environmental reasons, the use of electricity driven compressor units has been growing.

Many of the larger mainline transmission routes are what is generally referred to as "looped." Looping is when one pipeline is laid parallel to another and is often used as a way to increase capacity along a right-of-way beyond what is possible on one line, or an expansion of an existing pipeline(s). These lines are connected to move a larger flow along a single segment of the pipeline system. Some very large pipeline systems have 5 or 6 large diameter pipes laid along the same right-of-way. Looped pipes may extend the distance between compressor stations, where they can transfer part of their flow, or the looping may be limited to only a portion of the line between stations. In the latter case, the looping often serves as essentially a storage device, where natural gas can be line-packed as a way to increase deliveries to local customers during certain peak periods.

To address the potential for pipeline rupture, safety cutoff meters are installed along a mainline transmission system route. Devices located at strategic points are designed to detect a drop in pressure that would result from a downstream or upstream pipeline rupture and automatically stop the flow of natural gas beyond its location. Monitoring the pipeline as a whole are apparatus known as SCADA which means Supervisory Control and Data Acquisition. SCADA systems provide monitoring staff the ability to direct and control pipeline flows, maintaining pipeline integrity and pressures as natural gas is received and delivered along numerous points on the system, including flows into and out of storage facilities.

Natural gas market centers and hubs evolved, beginning in the late 1980s, as an outgrowth of natural gas market restructuring and the execution of a number of Federal Energy Regulatory Commission’s (FERC) Orders culminating in Order 636 issued in 1992. Order 636 mandated that interstate natural gas pipeline companies transform themselves from buyers and sellers of natural gas to strictly natural gas transporters. Market centers and hubs were developed to provide new natural gas shippers with many of the physical capabilities and administrative support services formally handled by the interstate pipeline company as “bundled” sales services.

Two key services offered by market centers/hubs are transportation between and interconnections with other pipelines and the physical coverage of short-term receipt/delivery balancing needs. Many of these centers also provide unique services that help expedite and improve the natural gas transportation process overall, such as Internet-based access to natural gas trading platforms and capacity release programs. Most also provide title transfer services between parties that buy, sell, or move their natural gas through the center.

As of the end of 2008, there were a total of 33 operational market centers in the United States (24) and Canada (9).

At the end of the mainline transmission system, and sometimes at its beginning and in between, underground natural gas storage and LNG (liquefied natural gas) facilities provide for inventory management, supply backup, and the access to natural gas to maintain the balance of the system. There are three principal types of underground storage sites used in the United States today: depleted reservoirs in oil and/or gas fields, aquifers, and salt cavern formations. In one or two cases mine caverns have been used. Two of the most important characteristics of an underground storage reservoir are the capability to hold natural gas for future use, and the rate at which natural gas inventory can be injected and withdrawn (its deliverability rate).

Most underground storage facilities, 327 out of 399 at the beginning of 2008, are depleted reservoirs, which are close to consumption centers and which were relatively easy to convert to storage service. In some areas, however, most notably the Midwestern United States, some natural aquifers have been converted to natural gas storage reservoirs. An aquifer is suitable for natural gas storage if the water-bearing sedimentary rock formation is overlaid with an impermeable cap rock. While the geology of aquifers is similar to that of depleted production fields, their use in natural gas storage usually requires more base (cushion) gas and greater monitoring of withdrawal and injection performance. Deliverability rates may be enhanced by the presence of an active water drive.

During the past 20 years, the number of salt cavern storage sites has grown significantly because of its rapid cycling (inventory turnover) capability coupled with its ability to respond to daily, even hourly, variations in customer needs. The large majority of salt cavern storage facilities have been developed in salt dome formations located in the Gulf Coast States. Salt caverns leached from bedded salt formations in Northeastern, Midwestern, and Western States have also been developed but the number has been limited due to a lack of suitable geology. Cavern construction is more costly than depleted field conversions when measured on the basis of dollars per thousand cubic feet of working gas capacity, but the ability to perform several withdrawal and injection cycles each year reduces the per-unit cost of each thousand cubic feet of natural gas injected and withdrawn.

Underground natural gas storage inventories provide suppliers with the means to meet peak customer requirements up to a point. Beyond that point the distribution system still must be capable of meeting customer short-term peaking and volatile swing demands that occur on a daily and even hourly basis. During periods of extreme usage, peaking facilities, as well as other sources of temporary storage, are relied upon to supplement system and underground storage supplies.

Peaking needs are met in several ways. Some underground storage sites are designed to provide peaking and peak shaving services, but most often LNG (liquefied natural gas) in storage and liquefied petroleum gas such as propane are vaporized and injected into the natural gas distribution system supply to meet instant requirements. Short-term linepacking is also used to meet anticipated surge requirements.

The use of peak shaving, as well as underground storage, is essentially a risk-management calculation, known as peak-shaving. The cost of installing these facilities is such that the incremental cost per unit is expensive. However, the cost of a service interruption, as well as the cost to an industrial customer in lost production, may be much higher. In the case of underground storage, a suitable site may not be locally available. The only other alternative might be to build or reserve the needed additional capacity on the pipeline network. Each alternative entails a cost.

A local natural gas distribution company (LDC) relies on supplemental supply sources (underground storage, LNG, and propane) and uses linepacking to "shave" as much of the difference between the total maximum user requirements (on a peak day or shorter period) and the baseload customer requirements (the normal or average) daily usage. Each unit "shaved" represents less demand charges (for reserving pipeline capacity on the trunklines between supply and market areas) that the LDC must pay. The objective is to maintain sufficient local underground natural gas storage capacity and have in place additional supply sources such as liquefied natural gas or "LNG" and propane air to meet large shifts in daily demand, thereby minimizing capacity reservation costs on the supplying pipeline.

Prior to FERC Order 636 in 1992, many interstate pipeline companies had a completely integrated supply system that was capable of delivering natural gas from the wellhead to the ultimate retail gas consumer. But, following Order 636, which separated gathering, marketing, and transmission operations, many pipeline companies reorganized and broke up this system into discrete parts and assigned them to affiliated companies.

The facilities, functions, and services required for gathering, processing, and transportation were placed in affiliated companies or were spun off or sold to other companies. Since most gas prices were no longer regulated, gas gathering service charges became subject to market forces and were a function of buyer/seller negotiation, isolated from the transmission charges imposed by the pipeline transporter.

What is an Amine Plant?

Amine plants provide H2S removal as well as CO2 removal from natural gas and liquid hydrocarbons. The process involves both absorption and chemical reactions.

We provide amine plant sales and natural gas processing and engineering services.

Gas compressors are mechanical device that increase the pressure of a gas by reducing its volume. Gas compressors are responsible for moving the natural gas from the oil or natural gas production well to homes and businesses via natural gas pipelines and gas compression stations.

Gas Gathering systems are the physical facilities that accumulate and transport natural gas from a well to an acceptance point of a transportation pipeline are called a gas gathering system.

Gas Gathering lines are small-diameter pipelines move natural gas from the wellhead to the natural gas processing plant or to an interconnection with a larger mainline pipeline. Transporting natural gas from the wellhead to the final customer involves several physical transfers of custody and multiple processing steps. A natural gas pipeline system begins at the natural gas producing well or field. Once the gas leaves the producing well, a gas gathering system directs the flow either to a natural gas processing plant or directly to the mainline transmission grid, depending upon the initial quality of the wellhead product.

The processing plant produces pipeline-quality natural gas. This gas is then transported by pipeline to consumers or is put into underground storage for future use. Storage helps to maintain pipeline system operational integrity and/or to meet customer requirements during peak-usage periods.

Transporting natural gas from wellhead to market involves a series of processes and an array of physical facilities. Among these are:

A natural gas pipeline system begins at a natural gas producing well or field. In the producing area many of the pipeline systems are primarily involved in "gas gathering" operations. That is, a pipeline is connected to a producing well, converging with pipes from other wells where the natural gas stream may be subjected to an extraction process to remove water and other impurities if needed. Natural gas exiting the production field is usually referred to as "wet" natural gas if it still contain significant amounts of hydrocarbon liquids and contaminants.

Under certain conditions some or all of the natural gas produced at a well may be returned to the reservoir in cycling, repressuring, or conservation operations and/or vented and flared. At this stage it is a mixture of methane and other hydrocarbons, as well as some non-hydrocarbons, existing in the gaseous phase or in a solution with crude oil. The principal hydrocarbons normally contained in the natural gas mixture are methane, ethane, propane, butane, and pentane. Typical non-hydrocarbon gases that may be present in reservoir natural gas are water vapor, carbon dioxide, helium, hydrogen sulfide, and nitrogen.

In proximity to the well are facilities that produce what is referred to as "lease condensate", that is, a mixture consisting primarily of pentanes and heavier hydrocarbons which is recovered as a liquid from natural gas. Other natural gas liquids, such as butane and propane, are recovered at downstream natural gas processing plants or facilities

Once it leaves the producing area, a pipeline system directs flow either to a natural gas processing plant or directly to the mainline transmission grid. Non-associated natural gas, that is, natural gas that is not in contact with significant quantities of crude oil in the reservoir, is sometimes of pipeline quality after undergoing a decontamination process in the production area, and does not need to flow through a processing plant prior to entering the mainline transmission system.

Sulfur exists in natural gas and is known as hydrogen sulfide (H2S). Natural gas is usually considered "sour" if hydrogen sulfides content exceeds 5.7 milligrams of H2S per cubic meter of natural gas. The process hydrogen sulfide removal from sour gas is commonly referred to as "gas sweetening."

The primary process for gas sweetening - or turning sour natural gas to sweet natural gas - is similar to the processes of glycol dehydration and NGL absorption. In this case, however, amine solutions are used to remove the hydrogen sulfide (H2S) through amine plants. This process is known simply as the 'amine process', or alternatively as the Girdler process, and is used in 95 percent of U.S. gas sweetening operations. The sour gas is run through a tower, which contains the amine solution. This solution has an affinity for sulfur, and absorbs it much like glycol absorbing water. There are two principle amine solutions used, monoethanolamine (MEA) and diethanolamine (DEA). Either of these compounds, in liquid form, will absorb sulfur compounds from natural gas as it passes through. The effluent gas is virtually free of sulfur compounds, and thus loses its sour gas status. Like the process for NGL extraction and glycol dehydration, the amine solution used can be regenerated (that is, the absorbed sulfur is removed), allowing it to be reused to treat more sour gas.

Although most sour gas sweetening involves the amine absorption process, it is also possible to use solid desiccants like iron sponges to remove the sulfide and carbon dioxide.

Sulfur can be sold and used if reduced to its elemental form. Elemental sulfur is a bright yellow powder like material, and can often be seen in large piles near gas treatment plants, as is shown. In order to recover elemental sulfur from the gas processing plant, the sulfur containing discharge from a gas sweetening process must be further treated. The process used to recover sulfur is known as the Claus process, and involves using thermal and catalytic reactions to extract the elemental sulfur from the hydrogen sulfide solution.

Glycol dehydration is used in the production and processing of natural gas by using a liquid desiccant that removes water from natural gas and natural gas liquids (NGL).

H2S, or Hydrogen Sulfide, is a hazardous and corrosive element found in oil and natural gas which needs to be removed from the hydrocarbon before the oil or natural gas can be sold. The hydrogen sulfides are usually removed in a mid-stream gas processing facility by either iron sponges or amine plants.

What is a Heater Treater?

A "Heater Treater" is used in the oil and gas production process and is used to removes water and gas from the produced oil - and to improve its quality for sale into a crude oil pipeline or for other transport. A heater treater typically combines the following components inside the heater treater: a heater, free-water knockout, and oil and gas separator.

Midstream Assets include those assets and services that link the supply side of the value chain within the industry, to the demand side for for these energy commodities.

The Midstream Assets and the Midstream Oil and Gas sector is the bridge between the energy producers and the energy end-users and - therefore, can only be as strong as the weakest link or bridge within the midstream oil and gas sector.

As natural gas is produced from either a natural gas well, or from an oilwell which contains "associated gas," the natural gas must be treated or processed before it can be used at a home or business as a fuel.

Natural gas treating or natural gas processing, takes place at gas processing plants to remove the impurities and other hydrocarbons other than the methane itself, or CH4.

The by-products and impurities of natural gas that must be treated or processed include; ethane, propane, butane, isobutane, pentane, isopentane and higher molecular weight hydrocarbons, as well as H2S or elemental sulfur, carbon dioxide (CO2), water vapor and sometimes helium and nitrogen.

NGL, or natural gas liquids fractionation plants purpose is to separate the mixed natural gas liquids stream into separated products. These natural gas liquids that are separated by heat at NGL Fractionation plants include; ethane, propane, normal butane, isobutane and natural gasoline.

The carbon clock tracks total carbon dioxide emissions in metric tons since 1750.

Since 1750, humans have emitted over 5 trillion pounds of carbon emissions into the atmosphere. Roughly half of this has ended up in the oceans where it is beginning to damage the coral reefs. The other half is still in the atmosphere and causing global warming. Each pound of CO2 takes up as much space as a 500 pound person.

The formula (which should be good for a year or two) is:
C(t) = 2.58 ×1012 + 1240×t, where t is seconds since the start of 2007.

C is tonnes (metric tons) of carbon dioxide emissions.
2205 x C gives pounds of carbon dioxide emissions.

That comes to over 43 billion tons/year or over 86 trillion pounds/year.

Carbon dioxide (2) = 1 carbon atom with 2 oxygen atoms.
Carbon has relative weight 12 and Oxygen 16.
So it takes only 12 pounds of carbon to make 12+16+16 = 44 pounds of CO2.

Did you know that 10% of our nation's electricity now comes from "cogeneration" plants?

And because cogeneration is so efficient, it saves its customers up to 40% on their energy expenses, and provides even greater savings to our environment through significant reductions in fuel usage and much lower greenhouse gas emissions.

Cogeneration - also known as “combined heat and power” (CHP), cogen, district energy, total energy, and combined cycle, is the simultaneous production of heat (usually in the form of hot water and/or steam) and power, utilizing one primary fuel such as natural gas, or a renewable fuel, such as Biomethane, B100 Biodiesel, or Synthesis Gas.

Cogeneration technology is not the latest industry buzz-word being touted as the solution to our nation's energy woes. Cogeneration is a proven technology that has been around for over 120 years!

Our nation's first commercial power plant was a cogeneration plant that was designed and built by Thomas Edison in 1882 in New York. Our nation's first commercial power plant was called the "Pearl Street Station."

Trigeneration is the simultaneous production of three forms of energy - typically, Cooling, Heating and Power - from only one fuel input. Put another way, our trigeneration power plants produce three different types of energy for the price of one.

Trigeneration energy systems can reach overall system efficiencies of 86% to 93%. Typical "central" power plants, that do not need the heat generated from the combustion and power generation process, are only about 33% efficient.

Trigeneration Diagram & Description
Trigeneration Power Plants' Have the Highest System Efficiencies and are
About 300 % More Efficient than Typical Central Power Plants

One of our company's principal's first experience with the design and development of a trigeneration power plant was the trigeneration power plant installation at Rice University in 1987 where our trigeneration development team started out by conducting a "cogeneration" feasibility study. The EPC contractor that Rice University selected installed the trigeneration power which included a 4.0 MW Ruston gas turbine power plant, along with waste heat recovery boilers and Absorption Chillers. A "waste heat recovery boiler" captures the heat from the exhaust of the gas turbine. From there, the recovered energy was converted to chilled water - originally from (3) Hitachi Absorption Chillers - 2 were rated at 1,000 tons each, and the third Hitachi Absorption Chiller was rated at 1,500 tons. The Hitachi Absorption Chillers were replaced shortly after their installation by the EPC company. The first trigeneration plant at Rice University was so successful, they added a second 5.0 MW trigeneration plant so today, Rice University is now generating about 9.0 MW of electricity, and also producing the cooling and heating the university needs from the trigeneration plant and circulating the trigeneration energy around its campus.

Trigeneration Chart
Trigeneration's "Super-Efficiency" compared
with other competing technologies
As you can see, there is No Competition for Trigeneration!

Our trigeneration power plants are the ideal onsite power and energy solution for customers that include: Data Centers, Hospitals, Universities, Airports, Central Plants, Colleges & Universities, Dairies, Server Farms, District Heating & Cooling Plants, Food Processing Plants, Golf/Country Clubs, Government Buildings, Grocery Stores, Hotels, Manufacturing Plants, Nursing Homes, Office Buildings / Campuses, Radio Stations, Refrigerated Warehouses, Resorts, Restaurants, Schools, Server Farms, Shopping Centers, Supermarkets, Television Stations, Theatres and Military Bases.

At about 86% to 93% net system efficiency, our trigeneration power plants are about 300% more efficient at providing energy than your current electric utility. That's because the typical electric utility's power plants are only about 33% efficient - they waste 2/3 of the fuel in generating electricity in the enormous amount of waste heat energy that they exhaust through their smokestacks.

Trigeneration is defined as the simultaneous production of three energies: Cooling, Heating and Power. Our trigeneration energy systems use the same amount of fuel in producing three energies that would normally only produce just one type of energy. This means our customers that have our trigeneration power plants have significantly lower energy expenses, and a lower carbon footprint.

Our New "Integrated" Trigeneration Plants Have
Very High Efficiencies & Low Fuel Costs

The Effective Heat Rate is Approximately
4050 btu/kW & System Efficiency is 92% Plants Have
Very High Efficiencies & Low Fuel Costs

Pictures (below) of a Cogeneration Plant Presently Being Built for New Customer.

This Cogeneration Plant is Rated at 900 kW and Features:
(2) Natural Gas Engines @ 450 kW each on one Skid with Optional
Selective Catalytic Reduction system that removes Nitrogen Oxides to "non-detect."

Our onsite trigeneration power and energy system can be an ideal solution for customers wanting increased power reliability and decreased energy and environmental costs. A few of the types of buildings and businesses that would benefit from an onsite trigeneration plant include the following: