Natural gas treatment processes, Chemistry tutorial

Introduction:

Similar to crude oil, natural gas is as well found in the complex mixture by other gases like carbon-dioxide, hydrogen sulphide and water vapor, the presence of such gases is undesirable, for  example the presence of hydrogen sulphide in natural gas is poisonous, more significantly if the gas is for domestic use.

Natural Gas Treatment Processes:

Raw natural gases have variable amounts of carbon-dioxide, hydrogen sulphide and water vapour.  The presence of hydrogen sulphide in natural gas for domestic utilization can't be tolerated as it is poisonous. It as well corrodes the metallic equipment. Carbon-dioxide is undesirable, as it reduces the heating value of the gas and solidifies under high pressure and low temperatures employed for transporting natural gas. For getting a sweet, dry natural gas, acid gases should be eliminated and water vapor reduced. Moreover, natural gas having appreciable amounts of heavy hydrocarbons must be treated for their recovery as the natural gas liquids.

Acid Gas Treatment:

Acid gases can be reduced or eliminated by one or more of the given methods: 

1) Physical absorption by employing a selective absorption solvent.

2) Physical adsorption by employing a solid adsorbent.

3) Chemical absorption where a solvent (that is, a chemical) capable of reacting reversibly by the acid gases is employed.

Physical Absorption:

Selexol, sulphinol and rectisol are the most significant methods employed for physical absorption of gases. Moreover, they are as well commercially viable. In such methods, no chemical reaction takes place between the acid gas and the solvent. The solvent or absorbent is a liquid which selectively absorbs the acid gases and leaves out the hydrocarbons. In the Selexol method for illustration, the solvent is dimethyl ether of polyethylene glycol. Raw natural gas passes counter presently to the descending solvent. Whenever the solvent becomes saturated by the acid gases, the pressure is reduced, and hydrogen sulphide and carbon-dioxide are desorbed. The solvent is then recycled to the absorption tower. Figure illustrates the Selexol method.

Fig: The Selexol Process for Acid Gas Removal: (1) Absorber, (2) Flash Drum, (3) Compressor,  (4)  Low-pressure  Drum, (5) Stripper, (6) Coole

Physical Adsorption:

In these methods, a solid having a high surface area is employed. Molecular sieves (zeolites) are broadly employed and are capable of adsorbing large amounts of gases. In practice, more than one adsorption bed is employed for continuous operation.  One bed is in use whereas the other is being regenerated. Regeneration is achieved via passing hot dry fuel gas via the bed. Molecular sieves are competitive merely if the quantities of hydrogen sulphide and carbon disulphide are low. Molecular sieves are as well able of adsorbing water in addition to the acid gases.

Chemical Absorption (Chemisorption):

This method is characterized via a high capability of absorbing big amounts of acid gases. A solution of a relatively weak base such as monoethanolamine is employed. The acid gas makes a weak bond with the base that can be regenerated simply. Mono and diethanolamine are often employed for this aim. The amine concentration generally ranges between 15 and 30%. Natural gas is passed via the amine solution where sulphides, carbonates and bicarbonates are made. Diethanolamine is a favored absorbent because of its lower corrosion rate, smaller amine loss potential, fewer utility needs and minimal reclaiming requirements. Diethanolamine as well reacts reversibly by 75% of carbonyl sulphides (COS), whereas the monoethanolamine reacts irreversibly with 95% of the COS and makes a degradation product that should be disposed of. Diglycolamine (DGA), is the other amine solvent employed in the econamine procedure (figure shown below). Absorption of acid gases takes place in an absorber having an aqueous solution of DGA and the heated rich solution (saturated by acid gases) is pumped to the regenerator. Diglycolamine solutions are characterized by low freezing points that make them appropriate for employ in cold climates. Strong basic solutions are efficient solvents for acid gases. Though, such solutions are not generally employed for treating large volumes of natural gas as the acid gases from stable salts that are not simply regenerated. For illustration, carbon-dioxide and hydrogen sulphide react by aqueous sodium hydroxide to yield sodium carbonate and sodium sulphide, correspondingly.

2440_Econamine Process.jpg

Fig: Econamine Process (1) Absorption Tower, (2) Regeneration

CO2 + 2NaOH (aq) → Na2CO3 + H2O

H2S + 2NaOH (aq) → Na2S + 2H2O

Though, a strong caustic solution is employed to eliminate mercaptans from gas and liquid streams. In the Merox process, for illustration, a caustic solvent having a catalyst like cobalt, that is capable of transforming mercaptans (RSH) to the caustic insoluble disulphides (RSSR), is employed for streams rich in mercaptans after elimination of H2S. Air is employed to oxidize the mercaptans to disulphides. The caustic solution is then recycled for regeneration. The Merox process (figure shown below) is mostly employed for treatment of refinery gas streams. In common, primary raw materials are naturally occurring substances which have not been subjected to the chemical changes after being recovered. The natural gas and crude oil are the fundamental raw materials for the manufacture of petrochemicals. Secondary raw materials or intermediates are obtained from the natural gas and crude oil via various processing schemes. The intermediates might be light hydrocarbon compounds like methane and ethane, or heavier hydrocarbon mixtures like naphtha or gas oil. Both naphtha and gas oil are crude oil fractions having different boiling ranges. Coal, oil shale, and tar sand are complex carbonaceous raw materials and possible future energy and chemical sources.  However, they should undergo lengthy and widespread processing before they yield fuels and chemicals identical to those generated from crude oil [Substitute Natural Gas (SNG) and synthetic crudes from coal, tar sand and oil shale)].

984_The Merox Process.jpg

Fig: The Merox Process: (1) Extractor, (2) Oxidation Reactor

Water Removal:

Moisture should be eliminated from natural gas to decrease corrosion problems and to prevent the hydrate formation. The hydrates are solid white compounds made up from a physical chemical reaction between hydrocarbons and water under high pressures and low temperatures employed to transport the natural gas through pipeline. Hydrates decrease pipeline efficiency, to prevent hydrate formation; natural gas might be treated by glycols that dissolve water efficiently. Ethylene glycol (EG), diethylene glycol (DEG) and triethylene glycol (TEG) are typical solvents for the removal of water. Triethylene glycol is preferable in vapor stage processes due to its low vapor pressure that results in less glycol loss. The TEG absorber generally includes 6 to 12 bubble-cap trays to achieve the water absorption. Though, more contact phases might be needed to reach dew points beneath -40° F. Computations to find out the number of trays or feet of packing, the required glycol concentration or the glycol circulation rate need vapor-liquid equilibrium  data. Predicting the interaction between TEG and water-vapor in natural gas over a wide range lets the designs for ultra-low dew point applications to be made. The computer program was introduced by Grandhidsan et al. (1999), to find out the number of trays and the circulation rate of lean TEG required to dry natural gas. It was found out that more precise predictions of the rate could be accomplished by using this program than by using hand computation. The figure below illustrates the Dehydrate process in which EG, DEG or TEG could be employed as an absorbent. One alternative to employing bubble-cap trays is structural packing that enhances control of mass transfer. Flow passages direct the gas and liquid flow countercurrent to one other. The other way to dehydrate natural gas is via injecting methanol to gas lines to lower the hydrate- formation temperature beneath ambient. Water can as well be reduced or eliminated from natural gas via using the solid adsorbents like molecular sieves or silica gel.

1231_Flow Diagram of the Dehydrate Process.jpg

Fig: Flow Diagram of the Dehydrate Process: (1) Absorption Column, (2) Glycol Sill, (3) Vacuum Drum Condensable Hydrocarbon Recovery 

Hydrocarbons heavier than methane which are present in natural gases are valuable raw materials and imperative fuels. They can be recovered via lean oil extraction. The first step in this method is to cool the treated gas via exchange with liquid propane. The cooled gas is then washed by a cold hydrocarbon liquid that dissolves most of the condensable hydrocarbons. The uncondensed gas is dry natural gas and is composed mostly of methane having small amounts of ethane and heavier hydrocarbons. The condensed hydrocarbons or natural gas liquids (NGL) are stripped from the rich solvent that is recycled. The table below compares the analysis of natural gas before and after the treatment. Dry natural gas might then be employed either as a fuel or as a chemical feedstock. The other way to recover NGL is via cryogenic cooling to very low temperatures (-15 to -180°F), which are accomplished mainly through adiabatic expansion of the inlet gas.

Table: Components of a typical natural gas before and after treatment

Pipeline Gas       Feed        Components Mole (%)

N2                     0.45                   0.62

CO2                   27.85                 3.50

H2S                  0.0013                  -

C1                     70.35                  94.85

C2                     0.83                    0.99

C3                     0.22                    0.003

C4                     0.13                    0.004

C5                     0.006                  0.004

C64                   0.11                    0.014

The inlet gas is first treated to eliminate water and acid gases, and then cooled through heat exchange and refrigeration. Further cooling of the gas is achieved via turbo expanders, and the gas is sent to a demethaniser to separate methane from NGL. Enhanced NGL recovery could be accomplished via better control strategies and make use of on-line gas chromatographic analysis.

Natural Gas Liquid (NGL):

Natural gas liquids (that is, condensable hydrocarbons) are those hydrocarbons heavier than methane which is recovered from the natural gas.

The quantity of NGL based mostly on the percentage of the heavier hydrocarbons present in the gas and on the efficiency of the procedure employed to recover them. (A high percentage is generally expected from associated gas.) Natural gas liquids are generally fractionated to separate them to three streams:

1) An ethane-rich stream that is employed for producing ethylene.

2) Liquefied petroleum gas (LPG) that is a propane-butane mixture. This is mostly employed as a fuel or a chemical feedstock. Liquefied petroleum gas is evolving to a significant feedstock for olefin production. It has been predicted that the world (LPG) market for chemicals will grow from 23.1 million tons used in the year 1988 to 36.0 million tons by the year 2000.

3) Natural gasoline (NG) comprises of C5+ hydrocarbons and is added to gasoline to increase its vapor pressure. Natural gasoline is generally sold according to its vapor pressure.

Natural gas liquids might have significant amounts of cyclohexane, a precursor for nylon recovery of cyclohexane from NGL through conventional distillation is hard and not economical as heptane isomers are as well  present that boil at temperatures almost similar to that of cyclohexane. The extractive distillation procedure has been recently developed via Phillips Petroleum Company to separate the cyclohexane.

Liquefied Natural Gas (LNG):

After the recovery of natural gas liquids, sweet dry natural gas might be liquefied for transportation via cryogenic tankers. Further treatment might be needed to decrease the water vapor beneath 10 ppm and carbon-dioxide and hydrogen sulphide to less than 100 and 50 ppm, correspondingly. Two processes are usually employed to liquefy natural gas: the expander cycle and mechanical refrigeration. In the expander cycle, portion of the gas is expanded from a high transmission pressure to a lower pressure. This lowers the temperature of gas. Through heat exchange, the cold gas cools the incoming gas that in a similar manner cools more incoming gas until the liquefaction temperature of methane is reached. In mechanical refrigeration, a multi-component refrigerant comprising of nitrogen, methane, ethane and propane is employed via a cascade cycle. When such liquids evaporate, the heat needed is obtained from natural gas, that loses energy or temperature till it is liquefied. The refrigerant gases are recompressed and recycled. The table shown below lists significant properties of a representative liquefied natural gas mixture.

Table: Important properties of a representative Liquefied Natural Gas mixture

Density, lb/cf                       27.00

Boiling point, °C                 -158

Calorific value, Btu/lb          21200

Specific volume, cf/lb           0.037

Critical temperature, °C*   -82.3

Critical pressure, psi*         -673

Properties of Natural Gas:

Treated natural gas comprises mostly of methane; the properties of both gases (natural gas and methane) are nearly similar. However, natural gas is not pure methane and its properties are modified through the presence of impurities, like N2 and CO2 and small amounts of unrecovered heavier hydrocarbons.

A significant property of natural gas is its heating value. The relatively high amounts of nitrogen and/or carbon-dioxide reduce the heating value of the gas. Pure methane consists of a heating value of 1,009 Btu/ft3. This value is reduced to around 900 Btu/ft3 if the gas includes around 10% N2 and CO2. (The heating value of either nitrogen or carbon-dioxide is zero.) On the other hand, the heating value of natural gas could surpass methane's because of the presence of higher-molecular weight hydrocarbons that have higher heating values. For illustration, ethane's heating value is 1,800 Btu/ft3, as compared to 1,009 Btu/ft3 for methane. Heating values of hydrocarbons generally present in natural gas are illustrated in a table. Natural gas is generally sold according to its heating values. The heating value of a product gas is a function of the constituents present in the mixture. In the natural gas trade, a heating value of one million Btu is roughly equivalent to 1,000 ft3 of natural gas.

Gas Hydrates:

Gas hydrates are ice-like materials that comprise of methane molecules encaged in a cluster of water molecules and held altogether by hydrogen bonds. This material takes place in large underground deposits found below the ocean floor on continental margins and in places north of the Arctic Circle like Siberia. It is anticipated that gas hydrate deposits have twice as much carbon as all other fossil fuels on earth. This source, if proven feasible for recovery, could be a future energy and also chemical source for petrochemicals. Because of its physical nature (a solid material only under high pressure and low temperature), it can't be processed via conventional processes employed for natural gas and crude oil. One approach is via dissociating this cluster to methane and water via injecting a warmer fluid like sea water. The other approach is through drilling into the deposit. This decreases the pressure and frees methane from water. Though, the environmental effects of these drilling should still be assessed.

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