General
Natural Gas, also known as methane, is a colourless, odourless fuel that burns cleaner than many other traditional fossil fuels. It is used for heating, cooling, production of electricity and it finds many uses in industry. Once the gas is brought to the surface, it is refined to remove impurities, like water, other gasses, and sand. Then it is transported through large pipelines that span the continent and delivered to your local utility.

The Search for Natural Gas
When people first began to search out gas and petroleum, the only way available was to look for surface evidence of a formation. This usually took the form of surface oil seeps in the ground. In the early days, people had little idea of what such formations looked like, much less on how or why they formed where they did. Today, geologists have given the industry much more information about petroleum formations and their history. This information, along with new technology that allows us to ‘see’ into the ground, provides gas exploration companies with a much better chance of finding gas and other petroleum resources when they drill wells.

How Does Natural Gas Form?
Today, most believe that petroleum products and natural gas come from ancient plants and animals that have died and their bodies have decomposed. This process includes conversion of organic material by microorganisms; thermal decomposition of buried organic matter, and deep crustal processes.

As organic particles deposited in mud and other sediment become deeply buried and compressed, higher temperatures cause carbon bonds in organic compounds to break down and form oil with minor amounts of gas. At increased temperatures (caused by increased burial depth), methane becomes the dominant product until it eventually replaces oil altogether. The simultaneous formation of both oil and gas in the early stage of the thermal decomposition process is the principal reason for the association of oil and gas in accumulations present in the upper 2 to 3 km of the Earth’s crust.

Exploration
The search for natural gas begins with geologists finding an area of the country where natural gas and oil are most likely to be found. This involves the evaluation of the earth’s history, and comparison with other areas where natural gas and oil are known to be present.

Once such an area is designated for exploration, the geologist begins to conduct more specific tests to determine the likelihood that gas and oil are indeed present in the area. They may study above-ground rock formations to determine the precise area where the folding of layers may have caused traps to form. In areas where wells are already present, as well as information acquired from logs, or instruments lowered into wellbores to measure the properties of rock layers.

One of the most exciting and effective technological advances that has aided geologists in finding natural gas deposits is seismology. Seismology is the study of how sound or seismic waves move through the earth’s crust. It was first used to study earthquakes, and it still is today.

The idea behind seismology is that earthquakes, or other sources of vibrations in the crust, interact with different kinds of rock differently; by recording how a wave of vibration is reflected by a certain layer of rock, the geologist can make an educated guess regarding what kind of rock is present, and approximately how deep in the crust it can be found.

In the earlier uses of seismology, dynamite was used to create predictable vibrations from known locations. Seismographs then recorded these vibrations, and by placing these electronic devices over a large area, geologists were able to create a model of the rock layers beneath the earth’s crust. Today, exploration companies often use specialized trucks, rather than explosions of dynamite, to produce vibrations on the surface. The trucks produce more reliable and less obtrusive vibrations than dynamite explosions.

In off-shore exploration, ships often pull arrays of sensors, along with an ‘airgun’ that shoots out highly pressurized air into the water. The shots create vibrations that can be measured by the sensors, which in turn produce profiles of the rock layers beneath the surface.

Recently, computer technology has increased the value of seismic data by allowing geologists to construct what is known as a 3-D Seismic, essentially a three-dimensional map of the rock layers beneath the surface. In order to create this type of detailed map, thousands of seismic measurements need to be taken. All of the data from these measurements is entered into a computer, which analyses the data and constructs a 3-D model.

Even with all this advanced technology, the only way to be sure whether or not gas and oil are to be found at a certain site is to drill. However, these days, exploration companies are conducting as much research as possible prior to drilling because the costs associated with drilling are high.

Onshore drilling
Once an exploration team has determined a site for drilling, the location of the trap will determine, to a large extent, the equipment used on the surface for drilling the well. If the target is a relatively shallow formation, then a cable-drilling rig might be used to dig the well. However, deeper formations require the use of rotary drilling rigs. The nature of the rock formations that must be drilled through will also be a determining factor in the kind of drilling equipment that is chosen for a certain well.

Percussion, or cable-tool drilling, is characterized by repeatedly raising and dropping a heavy metal bit into the Earth’s surface- eventually pounding a hole downwards into the ground. This process is still widely used today for drilling water wells. Periodically, bailers, or containers that remove debris, must be lowered into the shaft to clear out loose soil and rock chips so that the bit will have a clear shot at the bottom of the well.

David and Joseph Ruffner are credited with an important development in well-drilling technology: the first well to use casings on the sides to prevent collapse. They were drilling for brine near Charleston, West Virginia but their holes kept collapsing in and ruining their wells. To remedy the situation, they used hollow tree trunks to reinforce the sidewalls of the well. Today, steel pipe serves the same purpose.

Egyptians are credited with another first in drilling technology: they used rotary drilling mechanisms to drill into the Earth as early as 3000 BC. Much later, in 1500, Leonardo Da Vinci developed a design for a drilling rig that is similar to many of today’s rigs. Today, about 85% of the wells drilled use conventional rotary drilling rigs to dig their deep wells.

The rotary drilling method differs from the percussion method in that it relies on a sharp bit to drill through layers of earth and rock. It is also used to lift waste materials out of the wellbore. On the surface, a complex system of cables, engines, support mechanisms, lubricating devices and pulleys control the rotation of the bit below the surface, as well as keep the bit lubricated and bring debris out of the wellbore.

Underneath the surface, the bit is attached to a long drill pipe. Its job is to break up the bottom layer of rock or Earth to allow the well to progress deeper into the crust. There are many different varieties of drilling bits, each with a different specialty. Some major varieties are Steel Tooth Rotary Bits, Insert Bits, Polycrystalline Diamond Compact Bits, and Diamond Bits. In addition there are hybrid bits that combine features from different variations. When drilling deep wells through different layers of rock, several different bits might be used on a single well. The decision to change bits is not made easily, however, because it takes time and extra equipment to remove the entire drill pipe and bit, and then to reassemble it using a different bit. Sometimes, changing a bit could involve removing almost a mile of drill piping.

Drilling fluids also play an important role in rotary drilling. These fluids cool the bit, remove cuttings and debris, and coat the wellbore with a cake. Most fluids have a clay base, and are customized for the specific formations that are encountered at a given site. The cake that forms from the fluids serves to coat the walls of the wellbore until a steel casting can be put in place to prevent collapse.

Offshore Drilling
T.F. Rowland owned one of the earliest offshore drilling rigs in 1869. it was used in shallow water, but its anchored, four-legged tower was the grandfather of today’s modern platforms. Offshore technology surged shortly after World War II, when technology was sufficient to make such operations profitable.

The biggest difference between onshore and offshore drilling is that the base where the rig is placed is man-made for offshore wells, while the land provides this base on land. The first step in drilling an offshore well is to establish a mechanism that attaches the floating drilling platform to the base of the ocean, but at the same time allow for pitching and rolling caused by the ocean’s surface. In order to provide such a base, an underwater guided base is moved into precise position using Long Range Navigation (LORAN) and satellite technology. Next, a wide, relatively shallow hole (about 100ft deep) is drilled into the ocean floor. This hole is filled with a casting, which serves as a permanent base for the drilling template. The drilling template looks a bit like a cookie cutter: a box with several large, round holes cut into it. This template will eventually serve as the guide for multiple wells. Several other pieces of equipment are also attached to the drilling template, including a blowout preventer, which prevents oil or other pollutants from flowing out into open water.

Several kinds of platforms can be attached to the drilling base, once it is in place. The type of platform varies according to the depth of water, distance from shore, and the turbidity of the waters over the well. For inland drilling, a drilling barge can serve as a suitable platform, while other, larger rigs are needed for open water drilling. Near shore, submersible or semi-submersible rigs are generally used. These rigs can be moved from site to site by pushing air into a lower hull, which causes them to float high on the water. However, when they are in place, the lower hull is flooded, which causes the platform to sink partially into the sea, thus becoming more stable.

These platforms are also held in place by heavy weights, and anchor cables, which anchor them to the sea floor. Drill ships can also be used to drill in deeper waters. They appear similar to ordinary ships, but they have a drilling rig located in the centre of their hull. While drilling, these ships are kept in position by dynamic positioning, where the ship uses satellite navigation and multi-directional propulsion to remain directly above the well site.

Permanent platforms are the largest and most complex offshore structures. These massive platforms are placed in areas where multiple wells will be drilled, and production is high. Offshore permanent platforms built for use in the North Sea are some of the largest structures ever built. They can be constructed in over 500ft of water because of their massive size. They must be durable, able to withstand waves over 60ft high, and winds in excess of 90 knots. Often, these giants are constructed in part while they are being towed to the well site. Some of the larger platforms are 455ft in diameter at their base, weigh over 550 000 tons, and rise some 770 ft from the seabed to the tip of the derrick (200ft taller than the Washington Monument). The cost of these platforms routinely exceeds 1 billion dollars. Permanent rigs are held in place by concrete, steel, or tension legs. Tension legs are hollow steel tendons that allow no vertical platform movement, but some minor horizontal movement. They can be less expensive than other forms of support.

Lastly, in the arctic territories, other specially modified rigs are needed. Some rigs have been built into large floating sections of ice in areas where there was no danger of the ice melting. Others have been built on man made islands of sand and gravel.

Technology in Drilling
Advances in the latter part of the century have allowed drilling companies to cut costs, gather more information about well holes, and increase the value of wells through a variety of technologies. In the past, all information about the depth and conditions at any point below the surface in a well had to be obtained from the surface analysis of materials that were brought up by the drilling rig. This was unsatisfactory for deeper wells due to the often-considerable delay between the time when a bit contacted a new layer of rock, or new conditions, and when evidence of this contact came to the surface.

A new class of technology, known as measurement while drilling (MWD), includes all devices that help drilling crews by providing information about down-hole conditions. They often provide constant information to crews at the surface, thus eliminating the need to cease drilling operations in order to take measurements, and they also eliminate the amount of lag time between contact with new conditions and the surface crew’s awareness of the change in drilling environment. These technologies have increased drilling safety, as well as efficiency.

One of the most exciting and productive new technologies is horizontal drilling. It is heralded today as, “…causing the greatest change in the industry since the invention of the rotary bit.” The first patent for horizontal drilling tools was issued in 1891 to Robert E. Lee (the Civil War general). Lee drilled a horizontal drain for a vertical oil well.

The notion of drilling wells that are not aligned vertically with the surface is not new. For years, companies have been employing slant drilling to drill wells at an angle in order to reach areas where rigs could not feasibly be placed. Slant or deviation drilling has also been traditionally utilized in offshore sites where the expense of platforms prohibits the construction of multiple platforms. In order to reduce costs, several slanted wells are drilled from a single platform, reaching several different traps or oil fields. In some cases 20 or more slanted wells can be drilled from a single platform. The difference between slant wells and today’s horizontal wells is that slant wells would take as much as 2000 ft or more to bend from vertical to horizontal. Today’s technology allows a 90° shift within a few feet. The benefits of horizontal drilling include:

• 1. A horizontal well can penetrate more than one reservoir, and can produce up to six or seven times as much gas or oil from as an equivalent vertical well.
• 2. Salt-water production can be minimized.
• 3. The ‘traditional’ primary recovery life of a well can be increased from 25% of the oil in place to 50 to 75%.
• 4. Oil and gas can be taken from a well, even while drilling horizontally continues.
• 5. Lastly, automation of drilling rigs has reduced the cost of manpower for a given drilling operation. Automated rigs are safer and less expensive to operate than traditional drilling rigs because people no longer have to do many of the hazardous jobs involved in drilling a well. Automated rigs also reduce drilling by 12 to 15%, saving time and money for the gas or oil producer.

Natural Gas Production
Once drilling has come into contact with a productive petroleum formation, it is important to test the formation in order to determine whether or not a company will be able to profit from extracting gas and oil from the formation, as well as the proper rate of extraction and other production issues. Information that needs to be obtained includes the depth and type of formation, the gas to oil ratio, the viscosity of the oil, and the overall economic outlook for the project.

In the past, oil and gas producers were intent on extracting the most oil and gas in the least possible time from a given well. Today, the climate is much different. Much more emphasis is placed on the most efficient recovery performance of a well. Efficient recovery takes planning and the right kind of equipment. Excessive production rates can cause a well to be damaged, leading to less oil and gas in the long run.

When a new well begins production, a potential test is run on it to determine the most oil and gas it can produce in a 24-hour period. The most efficient recovery rate (MER) is based on the most oil and gas that can be extracted for a sustained period of time without harming the formation. Other tests are also performed to measure pressure, heat and other variables at the bottom of the well.

Some wells are under enough pressure that the oil and gas will flow freely from them without any need for a pump or lifting system. There are only a small number of these formations, and even these usually require a lifting system at some point in their active lives. Flowing wells only require a “Christmas Tree’ or a series of valves and pipes at the surface in order to produce gas and oil.

Most wells, however, require some sort of lifting method to extract the oil and gas present in their formations. The lifting method depends on the depth of the well and whether or not the well has multiple completions. The most common lifting method is rod pumping. Rod pumping involves a surface pump that is run by a cable and rod that move up and down, pumping oil and gas out of a well. The most common engine for a rod pump is the horse head, or conventional beam, pump. This pump uses weights to help the motor lift and drop the rod in the rod pumping mechanism. They are aptly nicknamed horse head pumps because the fixture, which feeds cable into the well, is shaped like a horse head. Other lifting mechanisms are also in use that lies under the surface of the Earth. These subsurface units sit nearer to the petroleum deposit, and pump the oil and gas to the surface. Some formations also require some sort of treatment to improve the flow of gas or oil.

Pumping Off
When driving through the country, often people see oil and gas wells where the pumps are not moving, and this leads them to think that the well is not currently active. This is seldom true. Producers use a technique known as pumping off to produce oil and gas more efficiently. At any one time, there is only so much oil and gas present in a given formation. It takes time for these products to seep through the rock layer and beneath the well. The length of time, or interval of rest, for these wells is determined by the well engineer. In the past, because the well operators were unaware of this principle, they often abandoned wells before they had extracted all the oil and gas present.

Processing
The gas processing industry is a major segment of the oil and gas industry, distinct from either crude oil or natural gas production, separate from oil refining or gas distribution, yet indispensable to all. As a separate and identifiable function, it is probably the last known and least understood part of the petroleum industry.

Whether or not the gas processing function is understood, even in the petroleum industry, gas plant production provides about 20% of total U.S> petroleum liquids production. Including liquefied refinery gases, natural gas liquids (NGL’s) account for about 24% of total U.S. production of liquid petroleum. Given the inevitable trend to increased natural gas consumption, coupled with a continuing decline in crude oil production, NGL’s will, by the end of the decade of the 1990’s, account for 25-35% of total U.S. production of liquid hydrocarbons.

In addition, the gas processing function gathers, treats, conditions, and delivers over 18 trillion cubic feet of natural gas per year into the U.S. energy economy the equivalent of about 3 billion barrels of crude oil.

In simple terms, the gas processing industry gathers, conditions and refines raw natural gas from the earth into saleable, useful energy forms for use in a wide variety of applications. Through the gas processing industry’s plants flows approximately 61% of total U.S. petroleum energy production (Fig. 1), ; this emerges in the form of merchantable natural gas, liquefied petroleum gases, motor fuel components, and raw materials for a myriad of basic petrochemicals.

Natural gas occurs deep below the surface of the earth in three principal forms: associated gas, non-associated gas, and as a gas condensate.

Associated gas is found in crude oil reservoirs, either dissolved in the crude oil, or in conjunction with crude oil deposits. It is produced from oil wells along with the crude. It separates, or is separated from the oil at the casinghead of the well, which leads to the synonymous term “casinghead gas.” It may also be called “oilwell gas” or “dissolved gas.” In the industry’s beginning, virtually all processed gas was from oil wells.

Non-associated gas occurs in reservoirs separate from crude oil. Its production is not incidental to the production of crude oil. It is commonly called “gas-well gas” or “dry gas.” Today about 75% of all U.S. natural gas produced is non-associated gas.

In addition, the reservoirs of many oil fields found since 1935 produce neither true gases nor true liquids. The material might properly be called a “two-phase fluid.” It is neither a gas because of its high density, nor a liquid because no surface boundary exists between gas and liquid. These reservoirs, called “gas condensate” reservoirs, are usually deeper with higher pressures, which pose special problems in production, processing and recycling of the gas for maintenance of reservoir pressure.

From whatever reservoir, natural gas as produced from the earth has widely varying composition, depending on the field, the formation, or the reservoir from which it is produced. Table 1 is a summary of “typical” raw gas compositions from different types of reservoirs, although it should be noted that there is no “typical” raw natural gas. The principal constituents of natural gas are methane and ethane, but most gases contain varying amounts of heavier components, such as propane, butane, pentane, and heavier hydrocarbons that may be removed by any number of processing methods.

The removal and separation of individual hydrocarbons by processing is possible because of the differences in physical properties. As shown in Table 2, each component has a distinctive weight, boiling point, vapour pressure and other physical characteristics, making its separation from other components a relatively simple physical operation.

Gas processors describe gas as “rich” (wet), or “lean (dry) depending on its content of heavy components. These are relative terms, but as used in the industry, a rich gas may contain five or six gallons or more of recoverable hydrocarbons per thousand cubic feet; a lean gas usually contains less than one gallon of recoverable liquids per thousand/cubic/feet.

Natural gas may also contain water, hydrogen sulphide, carbon dioxide, nitrogen, helium, or other components that may be diluents and/or contaminants. In any case, natural gas as produced rarely is suitable for pipeline transportation or commercial use. Natural gas in commercial distribution systems is composed nearly entirely of methane and ethane, with moisture and other contaminants removed to very low concentrations.

Although there are no industry specifications for pipeline quality gas, Table 3 is a summary of typical requirements; each pipeline may impose other specification parameters, depending on its system requirements.

Therefore, all natural gas is processed in some manner to remove unwanted water vapour, solids and/or other contaminants that would interfere with pipeline transportation or marketing of the gas. In addition, and equally important, most natural gas is processed to separate from the gas those hydrocarbon liquids that have higher value as separate products.

These natural gas liquids (NGLs) are part of a family of saturated hydrocarbons called paraffins. Each compound has a chemical formula CnH2n+2, and each has distinctive physical properties. The principal natural gas liquids include:

• Ethane: Exists as a liquid only under very high pressures (800psi) or at extremely low temperatures (-135°F). It is recovered and transported in either the liquid or gaseous state principally for use as feedstock for ethylene, the most important basic petrochemical produced today.
• Propane: Recovered and handled as a liquid at pressures over 200 pounds, or at temperatures below -44°F. Its principal uses are as feedstock for production of ethylene and propylene, and as LP-gas for heating fuel, engine fuel, and industrial fuel.
• Butane: Recovered and handled as a liquid under moderate pressure. Its principal uses are to provide needed volatility to gasoline motor fuel; as LP-gas fuel, either alone or in mixtures with propane; and as a feedstock for the manufacture of ethylene and butadiene key ingredient of synthetic rubber. It is also isomerized to produce iso-butane.
• Iso-butane: The chemical isomer of butane, it is fractionated from “field grade” butanes or derived by isomerization of normal butane and produced as a separate product, principally for the manufacture of alkylate, a vital ingredient of high-octane motor gasoline. It has become an increasingly important product for production of methyl tertiary butyl ether (MTBE) for use as a high octane oxygenate ingredient of reformulated motor gasoline.
• Natural Gasoline: A mixture of pentanes and heavier hydrocarbons, with small amounts of butane and iso-butane. Industry specifications define its physical properties in terms of vapour pressure at 100°F (10 to 34 psi), and percentage evaporated at 140°F (25 to 85%). It is recovered as a liquid, principally for use as a motor fuel component

If the gas contains hydrogen sulphide, a poisonous and corrosive gas, it is removed and further processed for recovery of elemental sulphur. Most carbon dioxide is removed to prevent destructive corrosion and to inject into crude oil reservoirs for enhanced oil recovery (EOR). Some helium is extracted for its unique properties as an inert gas.

In addition to gas conditioning and liquids production, gas processing performs vital functions, both economically and technically, in the recovery of crude oil through reservoir pressure maintenance, miscible floods, and other secondary recovery methods. Many of these projects would be neither technically possible nor economically feasible except for gas processing technology and the revenues from extracted gas liquids.

Processing and Manufacture
The gas processing function begins at the wellhead with the production of crude oil or raw natural gas. Crude oil must be stabilized by removal of the casinghead gas and other volatile components to facilitate pipeline transportation of the oil. The casinghead gas and/or gas-well gas must be gathered, treated in the field, compressed and pipelined to a central facility for the final processing that will produce pipeline quality natural gas and marketable natural gas liquids.

A typical large gas gathering system may involve thousands of miles of gathering lines connected to a hundred or more oil or gas wells in a single field. Total U.S. gathering systems exceed 300 000 miles of pipeline, together with attendant treating and compression facilities.

Final processing in the gas plant involves two basic operations: (1) extraction of the natural gas liquids from the gas stream; and (2) fractionation of the natural gas liquids into their separate components. Additional processing is usually required to treat and condition both the natural gas and the gas liquids.

Natural gas processing may be as simple as drying the gas by passing it through a fixed bed of a desiccant material, or it may be as complex as complete liquefaction of the total gas stream by cooling to extremely low temperatures. Extraction of heavier gas liquids (pentane and heavier) can be achieved by simple compression and moderate cooling of the natural gas stream.

However, the modern gas processing industry uses a variety of sophisticated processes to treat natural gas and extract natural gas liquids from the gas stream. The two most important extraction processes are the absorption and cryogenic expander processes. Together, these processes account for an estimated 90% of total natural gas liquids production.

The basic step in the absorption process is removal of NGL components from the natural gas by contact with absorbing oil. Refrigerating the absorption oil enhances liquid recovery. Lowering the molecular weight of the absorption oil may also increase recovery levels. Depending on operating conditions, approximately 85% of the propane and essentially all of the heavier natural gas liquids are absorbed in the oil. The lighter fractions (methane, ethane, and some of the propane) are not recovered in the absorbing oil and pass through the absorber tower as merchantable pipeline quality natural gas.

The bottoms effluent from the absorption tower consists of rich absorption oil mixed with absorbed propane, butanes, pentanes, and other heavier natural gas liquids. This stream is then fed to lean oil stills where the absorbed liquids are distilled from the absorber oil by heating the mixture to a temperature above the boiling point of the natural gas liquids, but below that of the absorber oil. The stripped absorber oil is then recirculated to the absorption tower, and the mixed stream of natural gas liquids is piped to the fractionation system for further separation into individual NGL components.

The fractionation system may be an integral part of the gas processing plant, or it may be a “central fractionator” many miles from the primary production. A central fractionator may receive mixed streams of natural gas liquids from many plants.

Turbo Expander Process
In recent years, ethane has become increasingly desirable as a petrochemical feedstock. This has resulted in the construction of many plants that recover ethane and heavier hydrocarbons from natural gas at temperatures ranging down to minus 150°F.

Combinations of external refrigeration and liquid flash-expansion refrigeration with gas turbo expansion cycles are employed to attain the low temperatures desired for high ethane recovery. In the turbo-expander process the absorber and still facilities are replaced by an expansion turbine, which accomplishes the separation of gas liquids from the natural gas stream by auto-refrigeration to extremely low temperatures.

Recoveries of 90-95% ethane and all of the heavier hydrocarbons have been achieved with the expander process. The mixed liquid product from the expander plant is then fractionated or may be delivered by pipeline to a central fractionation facility for fractionation into separate NGL components.

Fractionation
Fractionation of a mixed NGL stream into separate components is accomplished by controlling the temperature of the stream in a fractionator to take advantage of the difference in boiling points of separate products. Fractionators are usually named for the overhead or top product. Therefore, a deethanizer implies that the top product is ethane; a depropanizer indicates that the top product is propane, etc. Boiling the lighter products from the heavier products in the following order normally fractionates natural gas liquids.

• Deethanizer: The first step in the fractionating sequence is to separate the ethane and propane, with the ethane going overhead and the propane and heavier components passing from the bottom of the fractionator.
• Depropanizer: The next step in the processing sequence is to separate the propane and the isobutene, with the propane going overhead and the isobutane and heavier components passing from the bottom of the depropanizer.
• Debutaniser: The next fractionation step is separation of the butanes from the pentanes plus stream. The butanes (both iso and normal) pass overhead and the pentanes plus pass from the bottom of the fractionator.
• Butane Splitter or Deisobutaniser: When it is desirable to do so, the butanes, which pass overhead from the butanises, may be separated into iso and normal butanes. The isobutane goes overhead and the normal butane is drawn from the bottom of the tower.

Other Routine Gas Processing
As noted earlier, both natural gas and natural gas liquids may require additional treating or processing, either before or after extraction of liquids.

The most common treatment of natural gas is removal of excess water vapour, which is necessary to prevent formation of hydrates and freezing in pipeline transmission systems. Techniques for dehydrating natural gas include:

• Absorption using liquid desiccants, usually a glycol compound.
• Adsorption, using solid desiccants such as silica gel, activated alumina, or molecular sieves.
• Dew point depression by injection of anti-freeze compounds such as glycol or alcohol.
• Expansion refrigeration that cools the gas stream below the dew point of entraned water vapour.

Removal of excess moisture from some natural gas liquids, principally propane, is also necessary and is accomplished most often with solid desiccants or molecular sieves.

Additional treatment of both natural gas and natural gas liquids is usually required to remove hydrogen sulphide and carbon dioxide. This process in the industry is called “sweetening.” Many process methods are used, most of which rely on either chemical reactions, physical solution, or adsorption. Each process has unique advantages, depending on the concentration of hydrogen sulphide, carbon dioxide, and other conditions.

The most common chemical processes are based on contact with amine solutions. These solutions react with unwanted acid gas constituents to form other compounds, which can then be removed.

Physical solvent processes include a number of patented chemicals and processing schemes which function much the same as the oil absorption process for removal of liquids from gas.

Adsorption processes involve the removal of unwanted components by passing the gas or liquid through a bed of solid material that has been designed or treated to selectively extract carbon dioxide, hydrogen sulphide, or other contaminants.

Sulphur Recovery
The sour gas effluent from a sweetening unit must be further treated, either for disposal or for recovery of sulphur contained in the gas. At plants where hydrogen sulphide concentrations are very low, it is not economical to install sulphur recovery facilities. In these cases, the sour gas is disposed of by incineration.

At higher concentrations, the sour gas is usually processed in a sulphur recovery facility to recover elemental sulphur. The Claus process is the most widely used process for converting hydrogen sulphide into elemental sulphur. The process utilizes thermal and catalytic reactions to achieve conversion of up to 97% of hydrogen sulphide to elemental sulphur. “Tail gas clean up” processes reduce sulphur emissions significantly and boost overall efficiency of sulphur recovery to 98+%.

Current U.S. sulphur production from gas processing plants is approximately 6000 metric tons per day, about 40% of total U.S. production.

How are prices established?
How is it that one company can offer a fixed price for a period of time on a commodity like natural gas that moves up and down in price as capriciously as the wind? The answer: through trading on the futures market.

The frantic shouting and signaling of bids and offers on the trading floor of a futures exchange undeniably convey an impression of chaos. The reality, however, is that chaos is what futures market replace.

The history of modern futures trading was tied closely to the development of commerce in Chicago and the grain trade in the Midwest. The Chicago Board of Trade was formed in 1848 to promote the commerce of the city and to provide a place where buyers and sellers could meet to exchange commodities. During the early years, forward contracts, agreements in which sellers agree to deliver a specific cash commodity to buyers sometime in the future, were used. These forwards were the forerunners of present day futures contracts.

The price of a futures contract is determined by the free marketplace competition executed on the floor of the exchange, where traders announce by open outcry (or an electronic book system) their desire to buy or sell a certain number of contracts at a certain price. The highest bid (offer to buy) and lowest ask (offer to sell) constitute the market at any point in time. The integrity of the contract, the free competition of bids and asks in the trading ring, the openness of the trading floor to any trader without favour, the anonymity of buyers and sellers, and the worldwide dissemination of prices and volumes result in prices that reflect the true market value of the commodity and the transparency of the price.

Perhaps the most important reason for the existence of futures trading is “not to buy or sell physical goods, but to manage price risks. Commodity prices, share prices, and interest rates can change drastically over time. Those who may be affected by these fluctuations can use the futures market to protect themselves from this uncertainty of price.

For most people that do not participate in the financial markets on a daily basis it is the role of ETNA and other physical suppliers to combine the futures price certainty with the delivery of the physical molecules.

The physical supply comes from a large variety of producers found throughout North America and even the world. ETNA’s relationships span the globe, allowing us to source from the best for our customers.