the Technologies of Natural Gas Sweetening

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Natural Gas Sweetening

Natural gas may contain high quantities of hydrogen sulfide H2S and/or carbon dioxide CO2. The presence of these compounds renders the gas a sour gas. This is specially because sulfur has such negative effects on the quality of the produced gas, that the concentration of both components have to be reduced from the gas flow before being put into the distribution conducts for the users. The regulations allow a maximum of H2S equal to 0,002 gr./Nmc (1,31 PPM).The amount of CO2 in the gas produced will depend in the amount required by the regulations. Typical values allow a maximum concentration of carbon dioxide and other inerts to 4% molar of the gas. If the content of CO2 is within these values the process selected to remove the hydrogen sulfide has to avoid the removal of the carbon dioxide. The necessity of a efficient natural gas sweetening process is due to the following reasons:
– the toxicity of the hydrogen sulfide.
– sulfur dioxide is formed after the gas combustion;
– the corrosive action of sulfur compounds in metals especially with the presence of water even under the form of steam.
– the corrosive action of carbon dioxide
– the problem of hydrogen embrittlement of the vessels containing the gas.
– to reduce corrosion in pipelines and processing equipment
– for economic transportation of gas over long distances
Normally, the natural gas desulphurization processes can be grouped into 9 technology categories. These technology categories are as follows:
1- Chemical Solvents
2- Physical Solvents
3- Combination Chemical and Physical Solvents (Hybrids)
4- Fixed Beds (Adsorption)
5- Cryogenic Distillation
6- Membranes
7- Direct Conversion (Liquid Redox)
8- Scavenging technology
9- New Processes – Hybrid (Membrane and Amine, Liquid Redox and Amine)
The first six are used for bulk removal of acid gas and can be tailored to a wide range of outlet concentrations, direct conversion is used for low amounts of H2S and scavenging is used for small throughputs or trace removal. A combination of processes can be used to full fill particular processing requirements.
Chemical solvent processes involve the absorption by chemical solutions at preferably high pressure and near ambient temperature. The solvent in an aqueous solution, bonds with the acid gas component and removes them from the feed gas, the sour gas components are then released when the temperature of the solvent is increased or/and the pressure is reduced. Common chemical solvents include aqueous solutions of amines, inorganic salts or mixtures of them. The amines more commonly used are Monoethanolamine (MEA), Diethanolamine (DEA), Methyldiethanolamine (MDEA) and Diglycolamine (DGA). The inorganic salts are mostly basic carbonate solutions and caustic soda.

In general, selection of a proper gas treating process involves consideration of the following factors:
– Gas composition, including CO2, H2S and trace sulphur components.
– Inlet pressure and temperature.
– Treated gas purity specification. Avoid removing more CO2 than required to meet specs.
– Need for selectivity.
– Co-absorption of hydrocarbons.
– Process Capital and Operating costs including cost of solvents and their availability.
– Process royalty fees if any.
– Corrosion/Metallurgy Requirements.
– Process experience with similar treating requirements.
– Chemical degradation and evaporation losses.
– Process support from the licenser, availability of chemicals/spares at location.
– Environmental performance, disposal of effluents.
– Water content for raw and treated gas.

Process Advantages and Disadvantages Chemical Solvent Process
Monoethanolamine (MEA) Process
– High reactivity.
– Low solvent cost.
– Good thermal stability.
– Ease of reclamation.
– Low hydrocarbon content of acid gas produced.
– Lower plant investment compared to other amine processes.

– Inability to cope with and gas containing O2, CS2.
– Will remove all the CO2.
– Higher vaporization losses than DEA, MDEA.
– Ineffective for removing mercaptans.
– High residual acid gas concentration in lean amine.
– Non-selectivity for removing H2S in the presence of CO2.
– Higher utilities than hot pot and most physical solvent processes.
– Most corrosive amine.
– Freeze point 50ºF – Transportation of 15% water solution may be required (Freeze point 9ºF).
– If gas is not saturated reverse osmosis water or equivalent is needed to maintain amine concentration, it will re-hydrate dry gas. This is a general point for amines.
Diethanolamine (DEA) Process
– Resistance to degradation by COS and CS2.
– Lower vaporization losses and regeneration energy required.
– Less corrosive.
– Lower reactivity.
– Higher recirculation rates.
– Higher solvent costs.
– In CO2 only services it will degrade and be very corrosive.
– Lack of selectivity for H2S and CO2.
– If gas is not saturated reverse osmosis water or equivalent is needed to maintain amine concentration, it will re-hydrate dry gas.
– Freeze point 80ºF – Transportation of 15% water solution may be required (Freeze point 28ºF).
– Difficult to reclaim – Vacuum distillation, ion exchange.

Methyldiethanolamine (MDEA)
– High selectivity of H2S over CO2.
– High acid gas loading per mole of solvent.
– High solvent concentration.
– Low regeneration energy.
– Low solvent circulation.
– Low degradation due to contaminants.
– Selectivity not affected by low pressure
– Higher solvent cost.
– Loss of selectivity for H2S over CO2 as the concentration of H2S is increased.
– Little increase in allowable loading with increase of pressure.
– Tends to be foamy due to hydrocarbon co-absorption.
– If gas is not saturated reverse osmosis water or equivalent is needed to maintain amine concentration, it will re-hydrate dry gas.
– Reclamation process more complicated.
Diglycolamine (DGA) -Econoamine
– High reactivity
– Solution is resistant to freezing better for cold climates
– Effective in removing RSH components
– Very high concentration solution, lower circulation rates

– Absorbs heavy or aromatic hydrocarbons (an advantage in processes were traces of heavy hydrocarbons will cause problems i.e. Benzene removal for LNG production)
– Proprietary process
– If gas is not saturated reverse osmosis water or equivalent is needed to maintain amine concentration, it will re-hydrate dry gas

In a chemical solvent process, the acid gas components are chemically attached to the solvent. With chemical solvents, a CO2 rich gas can be treated to low levels of CO2 without deep regeneration of the solvent. However, there is a limit to the CO2 removal capacity of these solvents. This limit is independent of CO2 partial pressure, as it is determined by stoichiometry and corrosion prevention. The reaction rate H2S with amine is much faster due to its higher acidity and is readily removed from the feed gas.
Chemical solvents are most suitable for handling gases with relatively low partial pressures of CO2 or where a very low level of CO2 in the treated gas is required. Usually, energy requirements for chemical solvents are relatively higher.
Most chemical solvent sweetening processes involve absorption by chemical solutions at high pressure and at low temperature. A solvent in the aqueous solution will react with the acid gas components to form a complex. The solvent bonds with the acid gas components in a chemical manner until the temperature of the solvent is increased and/or the pressure is reduced at which time the complex is decomposed and the sour components released.

A sweetening plant operation on amine consists mainly of two pieces of equipment, i.e.:
– the packed absorber or plate absorber where the gas is washed with an absorbent;
– the distillation column (de-absorber) where the absorbed substances (hydrogen sulfide, carbon dioxide) are separated from the absorbent until regeneration.
With reference to the scheme, the gas containing hydrogen sulfide and carbon dioxide enters the lower part of the absorption tower whereas the aqueous amine solution enters at the top in a counter current fashion. The sweet gas comes out of the tower top, whereas the amine rich solution, now saturated with hydrogen sulfide and/or carbon dioxide, is gathered at the bottom of the tower. The rich solution is warmed up the heat contained in the regenerated solution, its pressure reduced to allow the removal of the acid gases and then is sent to the top of a distillation tower The rich solution is regenerated with the steam developed by the re-boiler.
After the regeneration process, the solution of amine passes, as mentioned before in heat exchangers where it is cooled. Then it goes back into circulation through a pump. To cool the solution to an ideal absorption temperature, a water or air exchanger is installed between the pump and the absorption tower. The acid gases, that is hydrogen sulfide and/or carbon dioxide, exit at the top part of the regeneration tower and after having been cooled off, in a water or air exchanger. After the cooling water is formed, and , is pumped into the regeneration tower to create reflux to limit the losses of amine.

Amine Gas Treatment