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Natural Gas is gaseous fossil fuel consisting primarily of Methane. It may also content other gaseous heavier hydro carbon namely , Ethane, Propane Butane etc .Some time Nitrogen, helium, Carbon dioxide, Traces of Hydrogen sulfide & water is also present in Natural gas . Mercury is also present in small amount in some field .
The natural gas produced from geological formation comes in a wide array of composition . The presence of these components differ from source to source, the most of the components present in natural gas are:
A. Organics Substances:-
i. Methane (CH4) - (82-96) %
ii. Ethane (C2H6) - (4-10) %
iii. Propane (C3H8) - (2-6) %
iv Butane (C4H10) - (2-4) %
v. Pantene (C5H12) - (0-1) %
vi.Hexane (C6 H14) - (0-1) %
vii.Higher Hydrocarbons- (0-1) %
B. Other Inorganic Substances:-
i. Nitrogen (N2) - (0-25) %
ii. Carbon Dioxide (CO2)- (0-5) %
iii. Sulphur Components (H2S & Other) - 4-50 ppm
iv. Helium - Traces
v. Mercury - Traces
The varieties of gas s compositions can be broadly categorised into i)Non Associated gas ii) Associated Gas
Non Associated Gas sometimes called as " Gas well gas" is produced from geological formation that typically do not contain much higher hydrocarbon than Methane .Non associated gas can contain non -hydrocarbon gases such as carbon dioxide , hydrogen sulphide etc. The reservoirs of Non associated Gas that contains only gas but no oil. It may be dry and wet . Wet non associated gas is in equilibrium with condensate in the reservoirs normally at higher pressure. However a significant proportion of reservoirs of Non Associated but wet gas or condensate gas are just as rich as ethane other liquid hydrocarbons The gas flows up the well under its own pressure through the well head control valves and along the flow line to the treatment plants.
Natural Gas is often found dissolved in oil at the high pressure existing in a reservoir and it may be present as a Gas Cap above the oils. Natural Gas available from such sources is known as Associated Gas. An associated gas may contain more heavy fractions (Ethane & Higher Hydrocarbons) than non associated gas .The production of associated gas is un-avoidably tried up to that of Crude oils, which generally represent the priority. Good reservoir management are used to minimise the production of associated gas so as to retain the maximum energy in the reservoir and thus increase ultimate crude oil recovery .The gas phase fluid are brought to the surface . They are separated into i) Hydrocarbon liquid stream ii) produced water stream iii) gaseous stream. The gaseous stream is traditionally rich with higher hydrocarbon . Depending on its contents of heavy components , natural gas can be considered as rich or lean. Rich gas or lean gases are not precise indicator of quality but only indicate the relative amount of natural gas liquid in the gas stream.
The associated gas is sometimes flared or injected back in the wells while awaiting commercial outlet or to maintain the pressure in the oil reservoirs.
Roughly about 70% of world gas production is non associated, 20 % is dissolved gas & 10 % is Gas Cap gas. However these % vary to a considerable extent in different countries./ regions
Both Associated and Non Associated Gas however can be sweet or sour . Natural gas containing significant amount of hydrogen sulphide (more than 5.7mg per cubic metre / more than 4 ppm by volume) is considered Sour gas. On the other hand Natural Gas that does not contain significant amount of hydrogen sulphide is called Sweet gas .Hydrogen sulphide is a toxic gas , accordingly places restriction on the material that can be used for piping and other equipments handling sour gas , as many metals are sensitive to sulphide stress cracking .
Sometime the term acid gas and sour gas are used interchangeably. Strictly speaking a sour gas contains significant amount of hydrogen sulphide where as acid gas is any gas that contains significant amount of acid gas such as carbon dioxide or hydrogen sulphide.
Raw natural gas containing hydrogen sulphide, carbon dioxide etc are generally treated to remove these impurities to acceptable level before industrial used.
Natural Gas is found in Oil Fields , Natural Gas Fields and in Coal Bed . It is colourless, odourless clean gas, It is lighter than Air so tend to dissipate into the atmosphere .Properties of natural gas vary to some extent with the actual composition of gas .Methane has lower explosive limit of 5% and an upper explosive limit of 15% in air .Explosive concerns of compressed natural gas are almost non-existent due to escaping nature of the gas. Processed natural gas is, in itself, harmless to human body but natural gas is a simple asphyxiant particularly in confined place and can kill if it displaces air to the point where oxygen content will not support life.
Appearance-- Clear Gas , burn with Blue Flame
Density &Phase-0.717 kg/ m3,Gaseous state
Boiling Point -------(-) 161.6 degree C
Flash Points ---------(-)188 Degree C
Explosive Limit ---- 5% to 15% in air
Maximum Flame Temp.---2148 Degree C
Adding odorant to Natural Gas began in US after 1937 (New London School Explosion) . The build up of gas in the School remain unnoticed, killing 300 students and faculty it ignited. Odorants are considered non-toxic in the extremely low concentration of occurrence in Natural Gas. Concentration of odorant is about 10-20 ppm.
Natural Gas molecules smaller than n-butane can react with liquid or free water to form crystalline , snow like solid solution called Hydrate. Hydrate have specific gravity ranging from 0.96 to 0.98 and therefore float in water but sink in liquid hydrocarbon . Hydrate are 90% water and remaing 10 % is composed of one or more of following component, methane, ethane , propane , iso-butane ,n-butane, nitrogen , carbon dioxide and hydrogen sulphide.
Smaller molecule such as Methane, Ethane and Hydrogen Sulfide , form a body centred Cubic lattice , called Structure -I. Structure -II is a Diamond lattice, formed by larger molecule such as propane and Iso- Butane . Gas mixture form both type of hydrate . The number of water molecule associated with each molecule of gaseous component included in the hydrate is known as Hydrate Number .
i)CH4, 6H2O ii) C2H6, 8H2O iii) C3H8, 17H2O iv)i- C4H10, 17H2O v ) N2, 6H2O 17H2O vi) CO2, 6H2O vii) H2S, 6H2O
N- butane alone does not form Hydrate but can contribute in mixture. In solid hydrate, the water and host molecules are linked together by hydrogen bonding into a cage like structure . Smaller natural gas molecule C1, C2, H2S and CO2 form more stable body centred cubic structure while small quantity of longer molecules (C3, iC4)usually produce less stable diamond lattice .Hydrate formation is accelerated by agitation , turbulence, pressure pulsation , hydrate crystals (seed) suitable sites for crystal formation like elbows, orifice plates, thermowells, scales and solid corrosion products favour hydrate formation.
For a gas to be a hydrate former , it must satisfy two criteria . i) it should be of covelent bond type , with molecule smaller than 8 0 A.ii) Gas in the liquid state must be immissible with water .
Hydrates cause severe operational problems in natural gas pipelines by freezing and causing blockage. This blockage may reduce or stop gas flow.
Natural gas hydrates are solid crystalline compounds of snow appearance with densities smaller than that of ice. Natural gas hydrates are formed when natural gas components, for instance methane, ethane, propane, isobutene, hydrogen sulfide, carbon dioxide, and nitrogen, occupy empty lattice positions in the water structure. In this case, it seems like water solidifying at temperatures considerably higher than the freezing point of water.
Gas hydrates constitute a solid solution-gas being the solute and water the solvent-where the two main constituents are not chemically bounded. Figure presents a typical phase diagram for a mixture of water with a light pure hydrocarbon.
Contact your instructor if you are unable to see or interpret this graphic.
Phase Diagram for a Water/Hydrocarbon (HC) System
There are a number of points on the diagram that are noteworthy. First of all, hydrate formation is clearly favoured by low temperature and high pressure. The three-phase critical point is point C on the diagram that represents the condition where the liquid and gas hydrocarbon merge into a single hydrocarbon phase in equilibrium with liquid water. Point OQ2 is the upper quadruple point, where four phases (liquid water, liquid hydrocarbon, gaseous hydrocarbon, and solid hydrate) are found in equilibrium. Point Q1, the lower quadruple point, typically occurs at 32 °F (ice freezing point) where four phases (ice, hydrate, liquid water, and hydrocarbon gas) are found in equilibrium. In this context, phases are not pure as they contain some amount of the other substances according to their mutual solubility.
For practical applications, the most important equilibrium line is the Q1Q2 segment. It represents the conditions for hydrate formation or dissociation, a critical piece of information for most industrial applications where hydrates are involved. When we focus on this zone, the phase behaviour of water/hydrocarbon system is simplified to the schematics shown in Figure .
Contact your instructor if you are unable to see or interpret this graphic.
Phase Behaviours of Water/Hydrocarbon System (Q1-Q2 segment)
Phase Behaviours thermodynamics is usually invoked for the prediction of the Q1-Q2 hydrate formation/dissociation line. The first two methods of prediction were proposed by Katz and coworkers, and are known as the Gas Gravity Method (Katz, 1945) and the Ki-value Method (Carson and Katz, 1942). Both methods allow calculating the P-T equilibrium curves for three phases: liquid water, hydrate and natural gas. These methods yield initial estimates for the calculation and provide qualitative understanding of the equilibrium; the latter method being the more accurate of the two.
The key circumstances that are essential for hydrate formation can be summarized as:
Presence of "free" water. No hydrate formation is possible if "free" water is not present. Here, we understand the importance of removal of water vapor from natural gas, so that in case of free water occurrence there is likelihood of hydrate formation.
Low temperatures, at or below the hydrate formation temperature for a given pressure and gas composition.
High operating pressures.
High velocities, or agitation, or pressure pulsations, in other words turbulence can serve as catalyst.
Presence of H2S and CO2 promotes hydrate formation because both these acid gases are more soluble in water than the hydrocarbons.
The best and permanent remedy for the hydrate formation problems is the dehydration of the gas. Sometimes, it is quite possible that hydrates will form at the well site or in the pipeline carrying natural gas to the dehydration unit, so that the need for well head techniques arises. At well site, two techniques are appropriate:
Heating the gas stream and maintaining flow lines and equipment at temperature above the hydrate point,
In cases where liquid water is present and the flow lines and equipment cannot be maintained above hydrate temperature, inhibiting hydrate formation by injecting additives that depress both hydrate and freezing temperatures.
The most common additives are methanol, ethylene glycol, and diethylene glycol. Methanol injection is very beneficial in cases where a low gas volume does not permit the dehydration processing. It is also extremely useful in cases where hydrate problems are relatively mild, infrequent, or periodic, in cases where inhibitor injection is only a temporary phase in the field development program, or where inhibition is done in conjunction with a primary dehydration system.
THE DEHYDRATION AND SWEETENING OF NATURAL GAS
Natural gases either from natural production or storage reservoirs contain water, which condense and form solid gas hydrates to block pipeline flow and especially control systems. Natural gas in transit to market should be dehydrated to controll water content to avoid hydrate as well as to minimize the corrosion
Dehydration of natural gas is the removal of the water that is associated with natural gases in vapor form.The natural gas industry has recognized that dehydration is necessary to ensure smooth operation of gas transmission lines. Dehydration prevents the formation of gas hydrates and reduces corrosion. Unless gases are dehydrated, liquid water may condense in pipelines and accumulate at low points along the line, reducing its flow capacity.
The water content of the gas depend on
Pressure -Water content decreases with increasing pressure .
Temperature - water content Increases with increase in Temperature.
Salt content - water content decreases with increasing salt content of associated reservoir water .
Gas composition - Higher Gr . gas have less water
Dew Point - Is defined as the temperature at which the gas is saturated with water vapour at that pressure .
Dew Point Depression -The difference between the dew point temp. Of a gas stream before and after the dehydration is called Dew point Depression .
Hydrate Inhibition by Additive Injection
Additive injection is generally required for gas stream in order to prevent corrosion and hydrate formation . The most common additive are methanol, Ethylene Glycol, & Di -Ethylene Glycol . Methanol is used the most. , because it disperses well in the gas stream , is usually available in bulk, is least expensive and consequently does not require recovery. Where as most additives are recovered and recycled , however Methanol recovery is often un-economical .Methanol is preferable in cases where hydrate problem are relatively mild , infrequent and periodic. EG & DEG are used primarily at low temperature processing plants for extracting Natural Gas Liquids. The water phase of the process liquid contains the EG or DEG , which can be recovered and regenerated . Injection is done through variable speed Injection pump of Positive displacement type with suitable metering facility to inject measured quantity of additive.
Several methods have been developed to dehydrate gases on an industrial scale.
The three major methods of dehydration are 1) direct cooling, 2) adsorption, and 3) absorption. Molecular sieves (zeolites), silica gel, and bauxite are the desiccants used in adsorption processes. In absorption processes, the most frequently used desiccants are diethylene and triethylene glycols. Usually, the absorption/stripping cycle is used for removing large amounts of water, and adsorption is used for cryogenic systems to reach low moisture contents.
The wet inlet gas temperature and supply pressures 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.
As an example, one MMSCF (million standard cubic feet) of natural gas saturated @ 80 degree F. and 600 PSIG (pound per square inch gauge) will hold 49 pounds of water. At the same pressure (600 PSIG) one MMSCF @ 120 degree F will hold 155 pounds of water.
Common allowable water content of transmission gas ranges from 4 to 7 pounds per MMSCF. Based upon the above examples, we would have two very different dehydration problems as a result of temperature alone.
The saturated vapor content of natural gas decreases with increased pressure or decreased temperature. Thus, hot gases saturated with water may be partially dehydrated by direct cooling. Gases subjected to compression are normally "after cooled", and this cooling may well remove water from the gas. The cooling process must reduce the temperature to the lowest value that the gas will encounter at the prevailing pressure to prevent further condensation of water.
Adsorption of Water by a Solid
Adsorption (or solid bed) dehydration is the process where a solid desiccant is used for the removal of water vapor from a gas stream. The solid desiccants commonly used for gas dehydration are those that can be regenerated and, consequently, used over several adsorption-desorption cycles.
The mechanisms of adsorption on a surface are of two types; physical and chemical. The latter process, involving a chemical reaction, is termed "chemisorption". Chemical adsorbents find very limited application in gas processing. Adsorbents that allow physical adsorption hold the adsorbate on their surface by surfaceforces. For physical adsorbents used in gas dehydration, the following properties are desirable.
1. Large surface area for high capacity. Commercial adsorbents have a surface area of 500-800 m2/g.
2. Good "activity" for the components to be removed, and good activity retention with time/use.
3. High mass transfer rate, i.e., a high rate of removal.
4. Easy, economic regeneration.
5. Small resistance to gas flow, so that the pressure drop through the dehydration system is small.
6. High mechanical strength to resist crushing and dust formation. The adsorbent also must retain
enough strength when "wet".
7. Cheap, non-corrosive, non-toxic, chemically inert, high bulk density, and small volume changes
upon adsorption and desorption of water.
Some materials that satisfy these criteria, in the order of increasing cost are; bauxite ore, consisting primarily of alumina ((Al2O3. x H2O); alumina; silica gels and silica-alumina gels; and molecular sieves. Activated carbon, a widely used adsorbent, possesses no capacity for water adsorption and is therefore not used for dehydration purposes, though it may be used for the removal of certain impurities. Bauxite also is not used much because it contains iron and is thus unsuitable for sour gases.
A hydrated form of aluminum oxide (Al2O3), alumina is the least expensive adsorbent. It is activated by driving off some of the water associated with it in its hydrated form ((Al2O3.3H2O) by heating. It produces an excellent dew point depression values as low as -100 °F, but requires much more heat for regeneration. Also, it is alkaline and cannot be used in the presence of acid gases, or acidic chemicals used for well treating. The tendency to adsorb heavy hydrocarbons is high, and it is difficult to remove these during regeneration. It has good resistance to liquids, but little resistance to disintegration due to mechanical agitation by the flowing gas.
Silica Gel and Silica-Alumina Gel
Gels are granular, amorphous solids manufactered by chemical reaction. Gels manufactured from sulphuric acid and sodium silicate reaction are called silica gels, and consist almost solely of silicon dioxide (SiO2). Alumina gels consist primarily of some hydrated form of Al2O3. Silica-alumina gels are a combination of silica and alumina gel. Gels can dehydrate gas to as low as 10 ppm, and have the greatest ease of regeneration of all desiccants.They adsorb heavy hydrocarbons, but release them relatively more easily during regeneration. Since they are acidic, they can handle sour gases, but not alkaline materials such as caustic or ammonia. Although there is no reaction with H2S, sulfur that can deposit and block their surface. Therefore, gels are useful if the H2S content is less than 5-6%.
These are a crystalline form of alkali metal (calcium or sodium) alumina-silicates, very similar to natural clays. They are highly porous, with a very narrow range of pore sizes, and very high surface area. Manufactured by ion-exchange, molecular sieves are the most expensive adsorbents. They possess highly localized polar charges on their surface that act as extremely effective adsorption sites for polar compounds such as water and hydrogen sulfide. Molecular sieves are alkaline and subject to attack by acids. Special acid-resistant sieves are available for very sour gases. Since the pore size range is narrow, molecular sieves exhibit selectivity towards adsorbates on the basis of their molecular size, and tend not to adsorb bigger molecules such as the heavy hydrocarbons. The regeneration temperature is very high. They can produce a water content as low as 1 ppm. Molecular sieves offer a means of simultaneous dehydration and desulfurization and are therefore the best choice for sour gases. Solid desiccants or absorbents are commonly used for dehydrating gases in cryogenic processes. The use of solid adsorbent has been extended to the dehydration of liquid. Solid adsorbents remove water from the hydrocarbon stream and release it to another stream at higher temperatures in a regeneration step.
In a dry desiccant bed, the adsorbate components are adsorbed at different rates. A short while after the process has begun, a series of adsorption zones appear, The distance between successive adsorption zone fronts is indicative of the length of the bed involved in the adsorption of a given component. Behind the zone, all of the entering component has been removed from the gas; ahead of the zone, the concentration of that component is zero. Note the adsorption sequence: C1 and C2 are adsorbed almost instantaneously, followed by the heavier hydrocarbons, and finally by water that constitutes the last zone. Almost all the hydrocarbons are removed after 30-40 min and dehydration begins. Water displaces the hydrocarbons on the adsorbent surface if enough time is allowed. At the start of dehydration cycle, the bed is saturated with methane as the gas flows through the bed. Then ethane replaces methane, and propane is adsorbed next. Finally, water will replace all the hydrocarbons. For good dehydration, the bed should be switched to regeneration just before the water content of outlet gas reaches an unacceptable level. The regeneration of the bed consists of circulating hot dehydrated gas to strip the adsorbed water, then circulating cold gas to cool the bed down.
Process Flow Diagram
A flow diagram for adsorption is shown
The adsorption process is cyclic. Two beds are used in parallel. Most adsorbends tend to adsorb heavy hydrocarbon , Glycols, Methanol, resulting in contamination and reduction in desiceant capacity. For efficient desiceacant performance and for longer life , the inlet gas streamis thoroughly cleaned to remove all liquid and solid.
The clean gas flows downward during dehydration through one bed while other bed will be under regeneratio . Gas flow is downward for dehydration so as to lessen bed disturbance due to high gas velocity. Regeneration gas on the other hand is sent upward through the adsorber to ensure through regeneration of the bottom of the bed. Most contamination occur at the top of the bed so during regeneration this contamination can be removed without flushing them through the entire bed.
The regeneration cycle consists of two parts , heating and cooling. First regeneration gas is heated to a temperature of 400-600 0 F .The hot regeneration gas & cooling gas , after flowing through the beds are sent to the regeneration gas cooler to remove any adsorbed water .
Oxygen , even in traces can react with HC during the regeneration cycle forming water and Carbon Dioxide which are adsorbed and lead to insufficient dehydration .
Absorption of Water in Glycols
Glycol dehydration is a liquid desiccant system for the removal of water from natural gas and natural gas liquids (NGL). It is the most common and economic means of water removal from these streams. Absorption dehydration involves the use of a liquid desiccant to remove water vapor from the gas.
Although many liquids possess the ability to absorb water from gas, the liquid that is most desirable to use for commercial dehydration purposes are the glycols, particularly ethylene glycol (EG), diethylene glycol (DEG), triethylene glycol (TEG), and Tetraethylene glycol (T4EG). Water and the glycols show complete mutual solubility in the liquid phase due to hydrogen-oxygen bonds, and their water
vapor pressures are very low. One frequently used glycol for dehydration is triethylene glycol, or TEG:
The Liquid Absorbent should possess the following properties:
1. High absorption efficiency.
2. Easy and economic regeneration.
3. Non-corrosive and non-toxic.
4. No operational problems when used in high concentrations.
5. No interaction with the hydrocarbon portion of the gas, and no contamination by acid gases.
An example process flow diagram for this system is shown below:
Lean, water-free glycol (purity >99%) is fed to the top of an absorber where it is contacted with the wet natural gas stream. The glycol removes water from the natural gas by physical absorption and is carried out the bottom of the column. Upon exiting the absorber the glycol stream is often referred to as "rich glycol". The dry natural gas leaves the top of the absorption column and is fed either to a pipeline system or to a gas plant.
After leaving the absorber, the rich glycol is fed to a flash vessel where hydrocarbon vapors are removed and any liquid hydrocarbons are skimmed from the glycol. This step is necessary as the absorber is typically operated at high pressure and the pressure must be reduced before the regeneration step. Due to the composition of the rich glycol, a vapor phase will form when the pressure is lowered having a high hydrocarbon content.
After leaving the flash vessel, the rich glycol is heated in a cross-exchanger and fed to the stripper (also known as a regenerator). The glycol stripper consists of a column, an overhead condenser, and a reboiler. The glycol is thermally regenerated to remove excess water and regain the high glycol purity.
The hot, lean glycol is cooled by cross-exchange with rich glycol entering the stripper. It is then fed to a lean pump where its pressure is elevated to that of the glycol absorber. After raising the pressure, the lean solvent is cooled again with a trim cooler before being fed back into the absorber. This trim cooler can either be a cross-exchanger with the dry gas leaving the absorber or an aerial type cooler.
Enhanced Stripping Methods
Most glycol units are fairly uniform except for the regeneration step. Several methods are used to enhance the stripping of the glycol to higher purities (higher purities are required for dryer gas out of the absorber). Since the reboiler temperature is limited to 400F or less to prevent thermal degradation of the glycol, almost all of the enhanced systems center on lowering the partial pressure of water in the system to increase stripping.
Common enhanced methods include the use of stripping gas, the use of a vacuum system (lowering the entire stripper pressure), the DRIZO process, which is similar to the use of stripping gas but uses a recoverable hydrocarbon solvent, and the Coldfinger process where the vapors in the reboiler are partially condensed and drawn out separately from the bulk liquid.
Normal operating temperatures range from 50 to 135 F. 50 F is considered to be the minimum operating temperature due to the high viscosity of glycol at lower temperatures. 135 F. is the upper practical temperature limit for TEG dehydrators because of the increased TEG vaporization losses at higher temperatures.
Pressure appears to have little effect on dew point depression in the dehydration process. Existing data indicates that the dew point depression is essentially constant over a range of 0 to at least 3000 PSIG. Pressure does however affect the water vapor capacity of the gas. At lower pressures the gas can absorb more water per unit volume.
Typically, increasing the number of trays, the glycol circulation rate or the lean TEG concentration will increase the dew point depression. Increasing glycol rates above 4 to 6 gallons per pound does not usually have an appreciable effect on dew point depression. Increasing TEG concentration or the number of trays is usually more effective than increasing glycol circulation rate in maximizing dew point suppression
Foaming refers to the expansion of liquid due to passage of vapour or gas. Although it provides high interfacial liquid-vapour contact, excessive foaming often leads to liquid build up on trays. In some cases, foaming may be so bad that the foam mixes with liquid on the tray above. Whether foaming will occur depends primarily on physical properties of the liquid mixtures, but is sometimes due to tray designs and condition. Whatever the cause, separation efficiency is always reduced.
Entrainment refers to the liquid carried by vapour up to the tray above and is again caused by high vapour flow rates. It is detrimental because tray efficiency is reduced: lower volatile material is carried to a plate holding liquid of higher volatility. It could also contaminate high purity distillate. Excessive entrainment can lead to flooding.
This phenomenon is caused by low vapour flow. The pressure exerted by the vapour is insufficient to hold up the liquid on the tray. Therefore, liquid starts to leak through perforations. Excessive weeping will lead to dumping. That is the liquid on all trays will crash (dump) through to the base of the column (via a domino effect) and the column will have to be re-started. Weeping is indicated by a sharp pressure drop in the column and reduced separation efficiency.
Flooding is brought about by excessive vapour flow, causing liquid to be entrained in the vapour up the column. The increased pressure from excessive vapour also backs up the liquid in the downcomer, causing an increase in liquid holdup on the plate above. Depending on the degree of flooding, the maximum capacity of the column may be severely reduced. Flooding is detected by sharp increases in column differential pressure and significant decrease in separation efficiency
Many natural gases contain hydrogen sulfide (H2S) in concentration ranging from barely detectable quantities to over 30 mole percent. Gases containing H2S or CO2 are classified as sour, and gases free from H2S and CO2 are called sweet. With increasing demands to natural gas, natural gases containing H2S are also being tapped for utilization after purification. Natural gas that is transported to the fuel market must meet legal requirements, which specify a maximum H2S content less than 4 ppm in the gas.
These requirements are justified, since H2S is a toxic gas, and its combustion product is sulfur dioxide ortrioxide. Besides emitting a bad odor at low concentrations, H2S is deadly poisonous and at concentrations above 600 ppm it can be fatal in just three to five minutes. Its toxicity is comparable to cyanide. Thus, itcannot be tolerated in gas that would be used as domestic fuel. Further, H2S is corrosive to all metals normally associated with gas transporting, processing and handling systems, and may lead to premature failure of most such systems. The removal of H2S from natural gas is accompanied by the removal of CO2 and COS if present, since these have similar acid characteristics.Like dehydration processes, desulfurization processes are primarily of two types: adsorption on a solid (dry process), and absorption into a liquid (wet process). Both the adsorption and absorption processes may be of the physical or chemical type. These processes may also be classified into the following categories:
1. Non-regenerative. The materials used in treating the gas are not recovered in these processes.
2. Regenerative processes with recovery as H2S. These include the physical absorption processes, the amine processes, molecular sieves, etc.
3. Regenerative processes with recovery as elemental sulfur. With growing environmental concerns regarding sulfur emission, these processes have acquired a prominent role in desulfurization operations.
Often hydrogen sulfide is present in field gases and has to be removed to a specific level (0.1 to 0.25 grain per 100 scf) because of its toxicity. Carbon dioxide is a corrosive diluent, but it has a value for some enhanced oil recovery processes and is included in acid gas removal processes