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Natural Gas Assets
www.NaturalGasAssets.com

Natural Gas Ventures is a new company presently being formed for the purpose of acquiring natural gas assets for use as a fuel in our related company's cogeneration and trigeneration energy systems for their commercial and industrial clients. 

Expressions of interest have been received from companies wanting to sign 10-20 year Power Purchase Agreements (PPA) for purchasing the power and thermal energy from our cogeneration or trigeneration energy systems - installed at their facilities.  One of these is with a major hospital chain. 

As natural gas is now in abundant supply with prices expected to remain relatively flat over the next 10 - 20 years, our business model is designed to maximize and exploit this new paradigm.  We will accomplish this by "upgrading" our natural gas into power (electricity) plus thermal energy - which can be any or all of the following;  hot water, steam and/or chilled water for air-conditioning - through our related company's cogeneration or trigeneration energy systems. We will be a preferred "private utility" for our commercial and industrial clients, providing them power and energy at prices less than what they are paying now in nearly all cases. 

We are uniquely positioned for long term success via multiple core competencies and our "durable competitive advantage."  One of these includes the fact that there will be an ever-greater demand for onsite cogeneration and trigeneration energy systems as a result of the EPA's requirements to reduce greenhouse gas emissions and increase energy efficiency.  

From our customer's vantage point, we;

• reduce their greenhouse gas emissions  

• increase their energy efficiency

• reduce their energy costs via a 10-20 year Power Purchase Agreement (or energy service agreement) at 10% less than their present energy costs.

Cogeneration and trigeneration energy systems are anywhere from 200% to nearly 300% more efficient over the utility company's central power plants.  As a result, we expect to pass on these savings to our customers and expect to reduce our customers energy costs by a minimum of 10%. 

We will provide the following cogeneration and trigeneration project development services for our qualified commercial and industrial clients (some through partner or affiliated companies):

• Design

• Build

• Finance

• Own

• Operation

• Maintenance

From our customer's utility company's vantage point, our cogeneration or trigeneration are viewed as a "demand side management" solution which will generate even more savings (and possible rebates as well) as we will eliminate or greatly reduce our customer's monthly demand charges for their power.  Demand charges can be very expensive.  Our company has seen many company's electric rates wherein their demand charge was 50% or more of their monthly electric bills.

What is Cogeneration?

Cogeneration, also called "combined heat and power," is the simultaneous production of electricity (power) and thermal energy. Thermal energy may be in the form of one or more of the following; hot water, chilled water (for air-conditioning) and/or steam. Cogeneration energy systems essentially provide 2 useful forms of energy - typically hot water and electricity - for the price of one.

Cogeneration power plants are anywhere from 2 times to 3 times more efficient than typical "central power plants" and produce more energy with less fuel.  Central power plants operate at around 28% to 40% total system efficiency, wasting vast amounts of "waste heat."  Cogeneration power plants integrate "waste heat recovery" technologies that recover this waste heat and convert this waste heat into useful heat energy. Cogeneration power plants operate at anywhere from 80% to 90% efficiency.

The benefits of cogeneration include:

• Significant reductions in the cost of power and thermal energy (hot water, chilled water and/or steam)

• Lower carbon emissions/greenhouse gas emissions

• Increased power reliability - fewer to no blackouts compared with the electric grid.

What is Trigeneration?

Trigeneration takes cogeneration one additional step by providing 3 energies for the price of one, with the addition of absorption chillers or adsorption chillers. 

Our company's CEO has expertise in developing cogeneration and trigeneration energy systems (while employed at 2 Fortune 100 utility companies) for hospitals, universities, office buildings and other commercial clients. 

More about Trigeneration:

As previously described, 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.

Our company's trigeneration energy systems 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

Trigeneration plants are installed at locations that can benefit from all three forms of energy. These types of installations that install trigeneration energy systems are called "onsite power generation" also referred to as "decentralized energy."

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 the trigeneration development team started out by conducting a "cogeneration" feasibility study.

The EPC (Engineering Procurement Construction) contractor installed a 4.0 MW Ruston gas turbine for the power plant. Rice University selected an EPC company that installed the trigeneration 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.

We partner and collaborate with other forward thinking companies and communities that are interested in changing the outdated power and energy model of the past - inefficient and highly-polluting central power plants that average 33% efficiency - to a new paradigm and model for the future - community-based cogeneration and trigeneration energy systems at more than 90% efficiency - and therefore provides power and energy at lower prices while significantly reducing and even eliminating typical power plant emissions and greenhouse gas emissions.

Call/email us for more information about community-based cogeneration and trigeneration energy systems or about making your community, hospital, university or other commercial facility a model for the future.

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 smallest cogeneration or trigeneration power plant "basic" power plant is a 200 kW trigeneration system.

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What is Gas Gathering?

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.

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 We represent private investors that are interested in acquiring natural gas assets to include midstream and upstream oil and gas properties. 

If you are interested in selling your midstream oil and gas / upstream oil and gas property or natural gas assets (must be located in U.S.), send information by email to: 

info(@)NaturalGasAssets .com

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More About Gas Gathering

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:

• Gas Processing Plant – This operation extracts natural gas liquids and impurities from the natural gas stream.

• Mainline Transmission Systems – These wide-diameter, long-distance pipelines transport natural gas from the producing area to market areas.

• Market Hubs/Centers – Locations where pipelines intersect and flows are transferred. 

• Underground Storage Facilities – Natural gas is stored in depleted oil and gas reservoirs, aquifers, and salt caverns for future use.

• Peak Shaving – System design methodology permitting a natural gas pipeline to meet short-term surges in customer demands with minimal infrastructure. Peaks can be handled by using gas from storage or by short-term line-packing.  

The Natural Gas Gathering System

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.

The Natural Gas Processing Plant

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 Transmission Grid and Compressor Stations

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/Hubs

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).

Underground Storage Facilities

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.

Peak Shaving

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 service, 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 peaking facilities, 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 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.

More about Gas Gathering

The corporate reorganizations brought about under the influence of FERC Order 636 caused a shift in the jurisdictional entities regulating the various facilities and services. The Federal Energy Regulatory Commission (FERC) had once regulated the entire integrated interstate pipeline system, but after the reorganizations, FERC became the regulating entity for only the interstate pipeline transportation and processing facilities and services. The spun-off or affiliated gathering facilities and services generally fell under state jurisdiction or other Federal agencies, such as the Department of the Interior, but in some cases FERC maintained jurisdiction. Especially unclear, and still contested in 2004, is the jurisdictional status of some Gulf of Mexico gathering systems.