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 Natural gas processing is a complex industrial process designed to clean raw natural gas by separating impurities and various non-methane hydrocarbons and fluids to process what is known as pipeline quality dry natural gas (^ Fact sheet: Natural gas processing). Natural gas processing begins at the well head. The composition of the raw natural gas extracted from producing wells depends on the type, depth and location of the underground deposit and the geology of the area. Oil and natural gas are often found together in the same reservoir. The natural gas produced from oil wells is generally classified as associated- dissolved, meaning that the natural gas is associated with or dissolved in crude oil. Natural gas production absent any association with crude oil is classified as “non-associated”.

Natural gas processing plants purify raw natural gas by removing common contaminants such as water, carbon dioxide (CO2 ) and hydrogen sulfide (H2s). Some of the substances which contaminate natural gas have economic value and are further processed or sold. A fully operational plant delivers pipeline-quality dry natural gas that can be used as fuel by residential, commercial and industrial consumers. The raw natural gas must be purified to meet the quality standard specified by the major pipeline transmission and distribution companies. These quality standards vary from pipeline to pipeline and are usually a function of a pipeline system design and the markets that it serves. In general, the standards specify that the natural gas:

§     Be within a specific range of heating value(caloric value) for example, in the united states, it should be about 1035±5% BTU per cubic feet of the gas at 1 atmosphere and 600 (41 MJ ±5% per cubic meter of gas at 1 atmosphere and 15.60 c).

§     Be delivered at or above a specified hydrocarbon dew point temperature (below which some of the hydrocarbons in the gas might condense at pipeline pressure forming liquid slugs that could damage the pipeline).

§     Dew-point adjustment serves the reduction of the concentration of water and heavy hydrocarbons in natural gas to such an extent that no condensation occurs during ensuing transport in the pipelines.

§     Be free of particulate solids and liquids water to prevent erosion, corrosion or other damages to the pipeline.

§     Be dehydrated of water vapor sufficiently to prevent the formation of methane hydrate within the gas processing plant or subsequently within the sales gas transmission pipeline. A typical water content specification in the U.S. is that gas must contain no more seven pounds of water per million standard cubic feet (MMSCF) of gas. (Prof. Jon Steiner Gudmundsson)

§    Contain no more than trace amounts of components such as hydrogen sulfide, carbon dioxide, mercaptans and nitrogen. The most common specification for hydrogen sulfide content is 0.25 grain H2S per 100 cubic feet of gas, or approximately 4 ppm. Specification for C02 typically limit the content to no more than two or three percent.

§  Maintain mercury at less than detectable limits (approximately 0.001 ppb by volume) primarily to avoid damaging equipment in the gas processing plant or the pipeline transmission system from mercury amalgamation and embrittlement of aluminum and other metals.

The natural gas product fed into the mainline gas transportation system must    meet specific quality measures in order for the pipeline grid to operate properly. Natural gas produced at the wellhead, which in most cases contains contaminants and natural gas liquids, must be processed and cleaned, before it can be safely delivered to the high-pressure, long-distance pipelines that transport the product to the consumers. Natural gas that is not within certain specific gravities, pressures, Btu content range, or water content levels will cause operational problems, pipeline deterioration, or can even cause pipeline rupture. Gas processing equipment, whether in the field or at processing/treatment plants, assures that these tariff requirements can be met. While in most cases processing facilities extract contaminants and heavy hydrocarbons from the gas stream, in some cases they instead blend some heavy hydrocarbons into the gas stream in order to
bring it within acceptable Btu levels. Natural gas processing begins at the wellhead. The composition of the raw natural gas extracted from producing wells depends on the type, depth, and location of the underground deposit and the geology of the area. Oil and natural gas are often found together in the same reservoir. Natural gas production absent any association with crude oil is classified as “Non-associated”. Most natural gas production contains, to varying degrees, small (two to eight carbons) hydrocarbon molecules in addition to methane. Although they exist in a gaseous state at underground pressures, these molecules will become liquid (condense) at normal atmospheric pressure. Collectively, they are called condensates or natural gas liquids (NGLs).


Natural gas usually contains significant quantities of water vapor. Changes in temperature and pressure condense this vapor altering the physical state from gas to liquid to solid.A dehydration process is needed to eliminate water which may cause the formation of hydrates. Hydrates form when a gas or liquid containing free water experiences specific temperature/pressure conditions. Dehydration is the removal of this water from the produced natural gas and is accomplished by several methods. Among these is the use of ethylene glycol (glycol injection) systems as an absorption mechanism to remove water and other solids from the gas stream. Alternatively, adsorption dehydration may be used, utilizing dry-bed dehydrators towers, which contain desiccants such as silica gel and activated alumina, to perform the extraction.

                             In 1810, an English scientist by the name John Dalton stated the total pressure of a gaseous mixture is equal to the sum of the partial pressure of the components. This statement, now known as Dalton’s law of partial pressure, allows us to compute the maximum volume of water vapor that natural gas can hold for a given temperature and pressure. The wet inlet gas temperature and supply pressure are the most important factors in the accurate design of a gas dehydration system. Without this basic information the sizing of an adequate dehydrator is impossible. There are many other important pieces of design information required to accurately size a dehydration system. These include pressures flow rate and volumes.

All gases have the capacity to hold water in a vapor state. This water vapor must be removed from the gas stream in order to prevent the formation of solid ice like crystals called hydrates. Hydrates can block pipelines, valves and other process equipment. The dehydration of natural gas must begin at the source of the gas in order to protect the transmission system.

                 The source of the gas moved through the transmission lines may be producing wells or developed storage pools. Pipelines drips installed near well heads and at strategic locations along gathering and trunk lines will eliminate most of the free water lifted from the wells in the gas stream. Multi stage separators can also be deployed to insure the reduction of free water that may be present. Water vapor moved through the system must be reduced to acceptable industry level. Typically, the allowable water content in gas transmission lines ranges from 41b. to 7lb. per MMSCF.

Dehydration systems used in the natural gas industry fall into four categories in principle:

·                     Direct cooling

·                     Indirect cooling (Expander or Joule-Thomson valve)

·                     Adsorption

·                     Absorption

 Direct cooling: The ability of natural gas to contain water vapor decreases as the temperature is lowered at constant pressure. During the cooling process, the excess water in the vapor state becomes liquid and is removed from the system. Natural gas containing less water vapor at low temperature is output from the cooling unit. The gas dehydrated by cooling is still at its water dew point unless the temperature is raised again or the pressure is decreased. It is often a good practice that cooling is used in conjunction with other dehydration processes. Glycol may be injected into the gas stream ahead of the heat exchanger for instance to reach lower temperatures before expansion into a low temperature separator.

 Indirect cooling: Expansion is a second way of natural gas cooling. It can be achieved by the expander or Joule-Thomson valve. These processes are characterized by a temperature drop to remove condensed water to yield dehydrated natural gas. The principal is the similar to the removal of humidity from outside air as a result of air conditioning. Gas is forced through a constriction called an expansion valve into space with a lower pressure. As a gas expands, the average distance between molecules grows. Because of intermolecular attractive forces, expansion causes an increase in the potential energy of the gas. If no external work is extracted in the process and no heat is transferred, the total energy of the gas remains the same. The increase in potential energy thus implies a decrease in kinetic energy and therefore in temperature.
 Adsorption: Solid desiccant dehydration, also known as solid bed, utilizes the adsorption principles for removing water vapor. Adsorbents used include silica gel (most commonly used), molecular - 8 - sieve (common in natural gas vehicle dryers), activated alumina and activated carbon. The wet gas enters into an inlet separator to ensure removal of contaminants and free water. The gas stream is then directed into an adsorption tower where the water is adsorbed by the desiccant. When the adsorption tower approaches maximum loading, the gas stream is automatically switched to another tower allowing the first tower to be regenerated. Heating a portion of the mainstream gas flow and passing it through the desiccant bed regenerates the loaded adsorbent bed. The regeneration gas is typically heated in an indirect heater. The undersaturated regeneration gas is then passed through the bed removing water and liquid hydrocarbons. These liquid components have to be removing from gas for two main reasons. First reason is present the water can allow natural gas hydrates forming. Second reason is a lot of corrosive and aggressive compounds (H2S, CO2) can be absorbed in this liquid phase. The regeneration gas exits the top of the tower and is cooled most commonly with an air-cooled heat exchanger. Condensed water and hydrocarbons are separated and the gas is recycled back into the wet gas inlet for processing.

Absorption: The fourth method of dehydration utilizes liquid desiccant and it is the most commonly used for dehydrating natural gas moved through transmission lines. Method removes water from the gas stream by counter current contact, in a tray type contactor tower, with tri-ethylene glycol (TEG). Natural gas enters the unit at the bottom of the adsorber tower and rises through the tower where it contacted with the TEG solution flowing downward across bubble trays. Through the contact, the gas gives up its water vapor to the TEG. The water laden TEG is circulated in a closed system, where the water is boiled from the TEG. The regenerated TEG then is recirculated to the contacting tower.


Natural gas that comes from oil wells is not totally pure but there are contaminants or mixtures in gas or typically termed 'associated gas’ like water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other. These mixtures in natural gas can cause the problems for the production operation, transportation, storage and use of the gas. One of those contaminants is water content. This water can result in corrosion of pipeline and fittings in gas transmission systems and the formation of ice or hydrates that causing flow restriction, with resulting consequences in terms of plant operating efficiency.


This project work would seek to;

1.      Determine gas dehydration process when tri-ethylene glycol (TEG) is used as the dehydrating agent using HYSYS.

2.      Compare tri-ethylene glycol (TEG) with other dehydrating agents


The research question of this project is based on the following;

·                     How is gas dehydration carried out on an FPSO?

·                     What is the best method to employ while dehydrating gas?

·                     How can loss of tri-ethylene glycol be controlled?


All raw natural gas is fully saturated with water vapor when produced from an underground reservoir. Because most of the water vapor has to be removed from natural gas before it can be commercially marketed, all natural gas is subjected to a dehydration process. This project work discusses the types of glycols that may be used and the process used to re  move water with glycol (TEG).


The project work involves the fabrication of the dehydration unit on the Floating, production, storage and offloading vessel (FPSO) and Simulation of the natural gas dehydration using the of Aspen hysys. This work was limited due to financial constraint, difficulty arising from the software used (hysys).


Aspen hysys software was used as a simulation tool for the dehydration of the gas using triethylene glycol (TEG) as an absorbent for the removal of water vapour.

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