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Sour natural gas compositions can vary over a wide concentration of H<sub>2</sub>S and CO<sub>2</sub> and a wide concentration of hydrocarbon components. If the H<sub>2</sub>S content exceeds the sales gas specification limit, the excess H<sub>2</sub>S must be separated from the sour gas. The removal of H<sub>2</sub>S from sour gas is called “sweetening.”
Sour natural gas compositions can vary over a wide concentration of H<sub>2</sub>S and CO<sub>2</sub> and a wide concentration of hydrocarbon components. If the H<sub>2</sub>S content exceeds the sales gas specification limit, the excess H<sub>2</sub>S must be separated from the sour gas. The removal of H<sub>2</sub>S from sour gas is called “sweetening.”


==Overview of sweetening process==
== Overview of sweetening process ==
The process selected for sweetening a sour gas depends on the general conditions:  
 
The process selected for sweetening a sour gas depends on the general conditions:
 
*H<sub>2</sub>S and mercaptan concentration in the sour gas, and sales gas H<sub>2</sub>S and total sulfur limits
*H<sub>2</sub>S and mercaptan concentration in the sour gas, and sales gas H<sub>2</sub>S and total sulfur limits
*maximum design flow rate
*maximum design flow rate
Line 9: Line 11:
*acceptable method of waste products disposal
*acceptable method of waste products disposal


===Cost considerations===
=== Cost considerations ===
The selected process must be cost effective in meeting the various specifications and requirements. Throughout the world, regulations generally limit the flaring of H<sub>2</sub>S. Sweetening of gas streams containing very low concentrations of H<sub>2</sub>S can be done in many ways, depending on the general conditions. If the sour gas stream contains more than 70 to 100 pounds of sulfur/day in the form of H<sub>2</sub>S in the inlet gas to a sour plant, a regenerative chemical solvent is usually selected for the sweetening of the sour gas stream. For very low H<sub>2</sub>S content sour gas, a scavenger chemical is usually used. In such cases, the chemical is consumed, and the method for ultimate disposal of the spent chemical is a consideration.  
 
The selected process must be cost effective in meeting the various specifications and requirements. Throughout the world, regulations generally limit the flaring of H<sub>2</sub>S. Sweetening of gas streams containing very low concentrations of H<sub>2</sub>S can be done in many ways, depending on the general conditions. If the sour gas stream contains more than 70 to 100 pounds of sulfur/day in the form of H<sub>2</sub>S in the inlet gas to a sour plant, a regenerative chemical solvent is usually selected for the sweetening of the sour gas stream. For very low H<sub>2</sub>S content sour gas, a scavenger chemical is usually used. In such cases, the chemical is consumed, and the method for ultimate disposal of the spent chemical is a consideration.
 
=== Typical process equipment for sweetening sour gas with a regenerative solvent ===


===Typical process equipment for sweetening sour gas with a regenerative solvent===
A schematic drawing of typical process equipment for sweetening sour gas with regenerative solvent is shown in '''Fig. 1'''. The first vessel is the inlet separator, which performs the important function of separating the fluid phases on the basis of density difference between the liquid and the gas. The sour gas flows from the separator into the lower part of the absorber or contactor. This vessel usually contains 20 to 24 trays, but for small units, it could be a column containing packing. Lean solution containing the sweetening solvent in water is pumped into the absorber near the top. As the solution flows down from tray to tray, it is in intimate contact with the sour gas as the gas flows upward through the liquid on each tray. When the gas reaches the top of the vessel, virtually all the H<sub>2</sub>S and, depending on the solvent used, all the CO<sub>2</sub> have been removed from the gas stream. The gas is now sweet and meets the specifications for:
A schematic drawing of typical process equipment for sweetening sour gas with regenerative solvent is shown in '''Fig. 1'''. The first vessel is the inlet separator, which performs the important function of separating the fluid phases on the basis of density difference between the liquid and the gas. The sour gas flows from the separator into the lower part of the absorber or contactor. This vessel usually contains 20 to 24 trays, but for small units, it could be a column containing packing. Lean solution containing the sweetening solvent in water is pumped into the absorber near the top. As the solution flows down from tray to tray, it is in intimate contact with the sour gas as the gas flows upward through the liquid on each tray. When the gas reaches the top of the vessel, virtually all the H<sub>2</sub>S and, depending on the solvent used, all the CO<sub>2</sub> have been removed from the gas stream. The gas is now sweet and meets the specifications for:
*H<sub>2</sub>S
*H<sub>2</sub>S
*CO<sub>2</sub>
*CO<sub>2</sub>
*total sulfur content
*total sulfur content


<gallery widths=300px heights=200px>
<gallery widths="300px" heights="200px">
File:Vol3 Page 188 Image 0001.png|'''Fig. 1—Schematic drawing of sweetening process equipment.'''
File:Vol3 Page 188 Image 0001.png|'''Fig. 1—Schematic drawing of sweetening process equipment.'''
</gallery>
</gallery>
<br>


The rich solution leaves the contactor at the bottom and is flowed through a pressure letdown valve, allowing the pressure to drop to about 60 psig. In some major gas plants, the pressure reduction is accomplished through turbines recovering power.<ref name="r1"/> Upon reduction of the pressure, the rich solution is flowed into a flash drum, where most dissolved hydrocarbon gas and some acid gas flash off. The solution then flows through a heat exchanger, picking up heat from the hot, regenerated lean solution stream. The rich solution then flows into the still, where the regeneration of the solvent occurs at a pressure of about 12 to 15 psig and at the solution boiling temperature. Heat is applied from an external source, such as a steam reboiler. The liberated acid gas and any hydrocarbon gas not flashed off in the flash drum leave the still at the top, together with some solvent and a lot of water vapor. This stream of vapors is flowed through a condenser, usually an aerial cooler, to condense the solvent and water vapors. The liquid and gas mixture is flowed into a separator, normally referred to as a reflux drum, where the acid gas is separated from the condensed liquids. The liquids are pumped back into the top of the still as reflux. The gas stream, consisting mainly of H<sub>2</sub>S and CO<sub>2</sub>, is generally piped to a sulfur recovery unit. The regenerated solution is flowed from the reboiler or the bottom of the still through the rich/lean solution heat exchanger to a surge tank. From here, the solution is pumped through a cooler to adjust the temperature to the appropriate treating temperature in the absorber. The stream is then pumped with a high-pressure pump back into the top of the absorber, to continue the sweetening of the sour gas.  
The rich solution leaves the contactor at the bottom and is flowed through a pressure letdown valve, allowing the pressure to drop to about 60 psig. In some major gas plants, the pressure reduction is accomplished through turbines recovering power.<ref name="r1">Smith, R.S. 1975. Improve Economics of Acid-Gas Treatment. Oil & Gas J 73(March): 78-79.</ref> Upon reduction of the pressure, the rich solution is flowed into a flash drum, where most dissolved hydrocarbon gas and some acid gas flash off. The solution then flows through a heat exchanger, picking up heat from the hot, regenerated lean solution stream. The rich solution then flows into the still, where the regeneration of the solvent occurs at a pressure of about 12 to 15 psig and at the solution boiling temperature. Heat is applied from an external source, such as a steam reboiler. The liberated acid gas and any hydrocarbon gas not flashed off in the flash drum leave the still at the top, together with some solvent and a lot of water vapor. This stream of vapors is flowed through a condenser, usually an aerial cooler, to condense the solvent and water vapors. The liquid and gas mixture is flowed into a separator, normally referred to as a reflux drum, where the acid gas is separated from the condensed liquids. The liquids are pumped back into the top of the still as reflux. The gas stream, consisting mainly of H<sub>2</sub>S and CO<sub>2</sub>, is generally piped to a sulfur recovery unit. The regenerated solution is flowed from the reboiler or the bottom of the still through the rich/lean solution heat exchanger to a surge tank. From here, the solution is pumped through a cooler to adjust the temperature to the appropriate treating temperature in the absorber. The stream is then pumped with a high-pressure pump back into the top of the absorber, to continue the sweetening of the sour gas.


Most solvent systems have a means of filtering the solution. This is accomplished by flowing a portion of the lean solution through a particle filter and sometimes a carbon filter as well. The purpose is to maintain a high degree of solution cleanliness to avoid solution foaming. Some solvent systems also have a means of removing degradation products that involves maintaining an additional reboiler for this purpose in the regeneration equipment hook-up. In some designs, the rich solution is filtered after it leaves the surge drum.  
Most solvent systems have a means of filtering the solution. This is accomplished by flowing a portion of the lean solution through a particle filter and sometimes a carbon filter as well. The purpose is to maintain a high degree of solution cleanliness to avoid solution foaming. Some solvent systems also have a means of removing degradation products that involves maintaining an additional reboiler for this purpose in the regeneration equipment hook-up. In some designs, the rich solution is filtered after it leaves the surge drum.
 
=== Sweetening solvents ===


===Sweetening solvents===
The desirable characteristics of a sweetening solvent are:
The desirable characteristics of a sweetening solvent are:


*Required removal of H<sub>2</sub>S and other sulfur compounds must be achieved.  
*Required removal of H<sub>2</sub>S and other sulfur compounds must be achieved.
*Pickup of hydrocarbons must be low.  
*Pickup of hydrocarbons must be low.
*Solvent vapor pressure must be low to minimize solvent losses.  
*Solvent vapor pressure must be low to minimize solvent losses.
*Reactions between solvent and acid gases must be reversible to prevent solvent degradation.  
*Reactions between solvent and acid gases must be reversible to prevent solvent degradation.
*Solvent must be thermally stable.  
*Solvent must be thermally stable.
*Removal of degradation products must be simple.  
*Removal of degradation products must be simple.
*The acid gas pickup per unit of solvent circulated must be high.  
*The acid gas pickup per unit of solvent circulated must be high.
*Heat requirement for solvent regeneration or stripping must be low.  
*Heat requirement for solvent regeneration or stripping must be low.
*The solvent should be noncorrosive.  
*The solvent should be noncorrosive.
*The solvent should not foam in the contactor or still.  
*The solvent should not foam in the contactor or still.
*Selective removal of acid gases is desirable.  
*Selective removal of acid gases is desirable.
*The solvent should be cheap and readily available.  
*The solvent should be cheap and readily available.
 
Unfortunately, there is no one solvent that has all the desirable characteristics. This makes it necessary to select the solvent that is best suited for treating the particular sour gas mixture from the various solvents that are available.<ref name="r2">Tennyson, R.N. and Schaaf, R.P. 1977. Guidelines Can Help Choose Proper Process for Gas-Treating Plants. Oil & Gas J 75 (2): 78.</ref> The sour natural gas mixtures vary in:


Unfortunately, there is no one solvent that has all the desirable characteristics. This makes it necessary to select the solvent that is best suited for treating the particular sour gas mixture from the various solvents that are available.<ref name="r2"/> The sour natural gas mixtures vary in:
*H<sub>2</sub>S and CO<sub>2</sub> content and ratio
*H<sub>2</sub>S and CO<sub>2</sub> content and ratio
*content of heavy or aromatic compounds
*content of heavy or aromatic compounds
*content of COS, CS<sub>2</sub>, and mercaptans
*content of COS, CS<sub>2</sub>, and mercaptans


While most of the sour gas is sweetened with regenerative solvents, for slightly sour gas, it may be more economical to use scavenger solvents or solid agents.<ref name="r3"/> In such processes, the compound reacts chemically with the H<sub>2</sub>S and is consumed in the sweetening process, requiring the sweetening agent to be periodically replaced.  
While most of the sour gas is sweetened with regenerative solvents, for slightly sour gas, it may be more economical to use scavenger solvents or solid agents.<ref name="r3">King, J.C. et al. 1986. Rigorous Screening Selects Sour-Gas Plant Process. Oil & Gas J 84 (36): 101-110.</ref> In such processes, the compound reacts chemically with the H<sub>2</sub>S and is consumed in the sweetening process, requiring the sweetening agent to be periodically replaced.
 
=== Regenerative chemical solvents ===


===Regenerative chemical solvents===
Most of the regenerative chemical sweetening solvents are alkanolamines, which are compounds formed by replacing one, two, or three hydrogen atoms of the ammonia molecule with radicals of other compounds to form primary, secondary, or tertiary amines respectively.<ref name="r4">Butwell, K.F., Kubek, D.J., and Sigmund, P.W. 1982. Alkanolamine Treating. Hydrocarbon Processing (March): 108.</ref> Amines are weak organic bases that have been used for many years in gas treating to remove CO<sub>2</sub> and H<sub>2</sub>S from natural gas as well as from synthesis gas. These compounds combine chemically with the acid gases in the contactor to form unstable salts. The salts break down under the elevated temperature and low pressure in the still.
Most of the regenerative chemical sweetening solvents are alkanolamines, which are compounds formed by replacing one, two, or three hydrogen atoms of the ammonia molecule with radicals of other compounds to form primary, secondary, or tertiary amines respectively.<ref name="r4"/> Amines are weak organic bases that have been used for many years in gas treating to remove CO<sub>2</sub> and H<sub>2</sub>S from natural gas as well as from synthesis gas. These compounds combine chemically with the acid gases in the contactor to form unstable salts. The salts break down under the elevated temperature and low pressure in the still.  


Because the chemical reactions are reversible by changing the physical conditions of temperature and pressure between absorber and still, amines are highly suitable for removing the acid gases from the hydrocarbon gas stream. However, sometimes nonreversible reactions take place to a minor degree, forming degradation compounds. Such degradation compounds must be periodically removed by distillation. This occurs in a reclaimer vessel. Primary amines are more prone to forming degradation compounds than the other solvents.  
Because the chemical reactions are reversible by changing the physical conditions of temperature and pressure between absorber and still, amines are highly suitable for removing the acid gases from the hydrocarbon gas stream. However, sometimes nonreversible reactions take place to a minor degree, forming degradation compounds. Such degradation compounds must be periodically removed by distillation. This occurs in a reclaimer vessel. Primary amines are more prone to forming degradation compounds than the other solvents.


Another chemical solvent, potassium carbonate (K<sub>2</sub>CO<sub>3</sub>), has also been used for removing H<sub>2</sub>S and CO<sub>2</sub> from manufactured or natural gas. It is not widely accepted in the sour natural gas industry, but it is periodically mentioned in the literature as finding some application under specific conditions. This chemical solvent was originally developed by the U.S. Bureau of Mines for removing CO<sub>2</sub> from manufactured gas. '''Table 1''' lists the regenerative chemical solvents generally used for sweetening sour gas and gives the acronyms, chemical formulas, and molecular weights.  
Another chemical solvent, potassium carbonate (K<sub>2</sub>CO<sub>3</sub>), has also been used for removing H<sub>2</sub>S and CO<sub>2</sub> from manufactured or natural gas. It is not widely accepted in the sour natural gas industry, but it is periodically mentioned in the literature as finding some application under specific conditions. This chemical solvent was originally developed by the U.S. Bureau of Mines for removing CO<sub>2</sub> from manufactured gas. '''Table 1''' lists the regenerative chemical solvents generally used for sweetening sour gas and gives the acronyms, chemical formulas, and molecular weights.


<gallery widths=300px heights=200px>
<gallery widths="300px" heights="200px">
File:Vol3 Page 190 Image 0001.png|'''Table 1'''
File:Vol3 Page 190 Image 0001.png|'''Table 1'''
</gallery>
</gallery>


===Primary amines===
=== Primary amines ===
====Monoethanolamine (MEA)====
 
<ref name="r5"/> MEA was the earliest amine used for sweetening sour gas. It is a stronger base than diethanolamine (DEA) and also has a higher vapor pressure than DEA; therefore, vapor losses are higher than for DEA. MEA forms nonregenerative (degradation) compounds with:
==== Monoethanolamine (MEA) ====
 
<ref name="r5">Fitzgerald, K.J. and Richardson, J.A. 1966. New Correlations Enhance Value of Monoethanolamine Process. Oil & Gas J 64 (43): 110-118.</ref> MEA was the earliest amine used for sweetening sour gas. It is a stronger base than diethanolamine (DEA) and also has a higher vapor pressure than DEA; therefore, vapor losses are higher than for DEA. MEA forms nonregenerative (degradation) compounds with:
 
*CO<sub>2</sub>
*CO<sub>2</sub>
*COS
*COS
*CS<sub>2</sub>
*CS<sub>2</sub>


This is a disadvantage, as the degradation compounds must be removed periodically to lessen the corrosion rate. A reclaimer is usually incorporated in an MEA sweetening train to periodically remove the degradation products from the solution by distillation. MEA has been used for more than 60 years in process applications, and the process operation and problem areas are well understood. Solution strengths of MEA are usually in the range of 15 to 22% by weight MEA in water. Mol loadings (moles of acid gas picked up in the contactor per mole of solvent circulated) are generally in the range of 0.25 to 0.33 moles acid gas per mol of MEA.  
This is a disadvantage, as the degradation compounds must be removed periodically to lessen the corrosion rate. A reclaimer is usually incorporated in an MEA sweetening train to periodically remove the degradation products from the solution by distillation. MEA has been used for more than 60 years in process applications, and the process operation and problem areas are well understood. Solution strengths of MEA are usually in the range of 15 to 22% by weight MEA in water. Mol loadings (moles of acid gas picked up in the contactor per mole of solvent circulated) are generally in the range of 0.25 to 0.33 moles acid gas per mol of MEA.


====Diglycolamine (DGA)====
==== Diglycolamine (DGA) ====
The DGA process was developed by The Fluor Corp. in the 1950s, which called the process the Econamine Process. The advantage of DGA over MEA appears to be the lower solution circulation rate owing to the higher solvent concentration, resulting in higher acid gas pickup per volume of solution circulated.<ref name="r6"/> This yields capital savings, as the regeneration equipment is smaller for DGA than for MEA. Disadvantages appear to be degradation of the chemical with CO<sub>2</sub> and greater solubility of heavier hydrocarbons in the solution, as compared to MEA. This is a serious drawback if the acid gas stream is fed to a Claus plant, as additional air is required for the combustion of the hydrocarbons. Also, this dilutes the sulfur compounds in the sulfur recovery train. Solution strength is on the order of 50 to 70% by weight of DGA in water, with mol loadings in the range of 0.3 to 0.4 moles of acid gas per mole of DGA circulated. The DGA process train usually includes a reclaimer.


===Secondary armines===
The DGA process was developed by The Fluor Corp. in the 1950s, which called the process the Econamine Process. The advantage of DGA over MEA appears to be the lower solution circulation rate owing to the higher solvent concentration, resulting in higher acid gas pickup per volume of solution circulated.<ref name="r6">Freireich, E. and Tennyson, R.N. 1976. Process Improves Acid Gas Removal, Trims Costs, and Reduces Effluents. Oil & Gas J 74 (34): 130-132.</ref> This yields capital savings, as the regeneration equipment is smaller for DGA than for MEA. Disadvantages appear to be degradation of the chemical with CO<sub>2</sub> and greater solubility of heavier hydrocarbons in the solution, as compared to MEA. This is a serious drawback if the acid gas stream is fed to a Claus plant, as additional air is required for the combustion of the hydrocarbons. Also, this dilutes the sulfur compounds in the sulfur recovery train. Solution strength is on the order of 50 to 70% by weight of DGA in water, with mol loadings in the range of 0.3 to 0.4 moles of acid gas per mole of DGA circulated. The DGA process train usually includes a reclaimer.
====Diethanolamine (DEA)====
 
<ref name="r7"/> DEA became a popular sour gas treating solvent in the 1960s after it was developed for such application in France. It can be used at higher concentrations than MEA. DEA has the advantage of picking up more acid gas per solution volume circulated, thus effecting some energy saving in circulation and regeneration. It does not form the nonregenerative products with COS and CS<sub>2</sub> as is the case with MEA, which is another advantage over MEA. DEA is also generally less corrosive than MEA. Solution strength is usually in the 25 to 40% range, with mol loadings of 0.35 to 0.63.  
=== Secondary armines ===
 
==== Diethanolamine (DEA) ====
 
<ref name="r7">Love, D. 1972. Quick Design Charts For Diethanolamine Plants. Oil & Gas J 70 (January): 88.</ref> DEA became a popular sour gas treating solvent in the 1960s after it was developed for such application in France. It can be used at higher concentrations than MEA. DEA has the advantage of picking up more acid gas per solution volume circulated, thus effecting some energy saving in circulation and regeneration. It does not form the nonregenerative products with COS and CS<sub>2</sub> as is the case with MEA, which is another advantage over MEA. DEA is also generally less corrosive than MEA. Solution strength is usually in the 25 to 40% range, with mol loadings of 0.35 to 0.63.
 
==== Diisopropanolamine (DIPA) ====


====Diisopropanolamine (DIPA)====
This secondary amine is not used by itself as a sweetening solvent but is part of the Sulfinol solvent formulation.
This secondary amine is not used by itself as a sweetening solvent but is part of the Sulfinol solvent formulation.


===Tertiary armines===
=== Tertiary armines ===
====Triethanolamine (TEA)====
 
TEA is not in general use for gas sweetening.  
==== Triethanolamine (TEA) ====
 
TEA is not in general use for gas sweetening.


====Methyldiethanolamine (MDEA)====
==== Methyldiethanolamine (MDEA) ====
<ref name="r8"/> MDEA reacts more slowly with CO<sub>2</sub> than the previously described amines. It forms a slightly different salt with CO<sub>2</sub> from those of the other amines, at a lower rate of reaction. The difference in the rates of reaction with H<sub>2</sub>S and CO<sub>2</sub> gives MDEA a desirable feature over other amines, namely selectivity of H<sub>2</sub>S over CO<sub>2</sub>. This is an attractive feature in cases where it is not necessary to remove all the CO<sub>2</sub> from the gas stream. By leaving some of the CO<sub>2</sub> in the natural gas, the circulation rate of the solution can be reduced, or the treating capacity of an existing unit can be increased with MDEA as compared with DEA.  
 
<ref name="r8">Goar, B.G. 1980. Selective Gas Treating Produces Better Claus Feeds. Oil & Gas J 78 (18): 239-242.</ref> MDEA reacts more slowly with CO<sub>2</sub> than the previously described amines. It forms a slightly different salt with CO<sub>2</sub> from those of the other amines, at a lower rate of reaction. The difference in the rates of reaction with H<sub>2</sub>S and CO<sub>2</sub> gives MDEA a desirable feature over other amines, namely selectivity of H<sub>2</sub>S over CO<sub>2</sub>. This is an attractive feature in cases where it is not necessary to remove all the CO<sub>2</sub> from the gas stream. By leaving some of the CO<sub>2</sub> in the natural gas, the circulation rate of the solution can be reduced, or the treating capacity of an existing unit can be increased with MDEA as compared with DEA.


MDEA concentrations are on the order of 30 to 50% by weight, with mol loadings of 0.40 to 0.55 moles acid gas per mol of amine. As a tertiary amine, MDEA is naturally a weaker base and is therefore less corrosive than the primary and secondary amines. The energy required for regeneration is also less than the requirement for the other amines.
MDEA concentrations are on the order of 30 to 50% by weight, with mol loadings of 0.40 to 0.55 moles acid gas per mol of amine. As a tertiary amine, MDEA is naturally a weaker base and is therefore less corrosive than the primary and secondary amines. The energy required for regeneration is also less than the requirement for the other amines.


===Proprietary armine solvent formulations===
=== Proprietary armine solvent formulations ===
By making use of the difference in the rates of reaction between MDEA and the acid gases, several proprietary solvents have been developed that are suited for preferential extraction of H<sub>2</sub>S, with only partial removal of CO<sub>2</sub> . These proprietary formulations usually contain MDEA plus other amines at various concentrations in aqueous solutions to tailor them for specific applications. Several chemical companies have developed such proprietary solvents.<ref name="r3"/>


===Hot potassium carbonate (K<sub>2</sub>CO<sub>3</sub>) (Hot Pot)===
By making use of the difference in the rates of reaction between MDEA and the acid gases, several proprietary solvents have been developed that are suited for preferential extraction of H<sub>2</sub>S, with only partial removal of CO<sub>2</sub> . These proprietary formulations usually contain MDEA plus other amines at various concentrations in aqueous solutions to tailor them for specific applications. Several chemical companies have developed such proprietary solvents.<ref name="r3">King, J.C. et al. 1986. Rigorous Screening Selects Sour-Gas Plant Process. Oil & Gas J 84 (36): 101-110.</ref>
<ref name="r9"/>The potassium carbonate process was developed for removing CO<sub>2</sub> from manufactured gas. It reacts with both acid gases. Because the contacting of the sour gas occurs at very high temperatures, such as 195 to 230°F in this process, it is sometimes referred to as the “hot pot” process. It requires lower heat input for regeneration and is therefore somewhat less costly to operate than some amine processes. Also, no heat exchanger is required in the regeneration equipment. The process has difficulty in meeting the H<sub>2</sub>S specification of the treated gas if the H<sub>2</sub>S/CO<sub>2</sub> ratio is not extremely small. This process is significant for treating gas with a large concentration of CO<sub>2</sub>. The chemistry of the process can be enhanced by the addition of various catalysts, and this has resulted in the process being referred to by various trade names.


===Computer simulation of sweetening processes===
=== Hot potassium carbonate (K<sub>2</sub>CO<sub>3</sub>) (Hot Pot) ===
The design and optimization of sweetening processes can be done by computer, using programs such as HYSIM from Hyprotech of Calgary, which contains AMSIM from D.B. Robinson and Associates Ltd. of Edmonton, Alberta; ProTreat from Optimized Gas Treating Inc. of Houston; TSWEET from Bryan Research and Engineering Inc. of Bryan, Texas; and proprietary programs from the chemical supplier.


===Estimating solution circulation rate===
<ref name="r9">Maddox, R.N. 1967. Hot Carbonate—Another Possibility. Oil & Gas J (October): 167-173.</ref>The potassium carbonate process was developed for removing CO<sub>2</sub> from manufactured gas. It reacts with both acid gases. Because the contacting of the sour gas occurs at very high temperatures, such as 195 to 230°F in this process, it is sometimes referred to as the “hot pot” process. It requires lower heat input for regeneration and is therefore somewhat less costly to operate than some amine processes. Also, no heat exchanger is required in the regeneration equipment. The process has difficulty in meeting the H<sub>2</sub>S specification of the treated gas if the H<sub>2</sub>S/CO<sub>2</sub> ratio is not extremely small. This process is significant for treating gas with a large concentration of CO<sub>2</sub>. The chemistry of the process can be enhanced by the addition of various catalysts, and this has resulted in the process being referred to by various trade names.
The circulation rate or the acid gas pickup by the solution can be estimated with the next two formulas.  


[[File:Vol3_page_192_eq_001.PNG]]
=== Computer simulation of sweetening processes ===


[[File:Vol3_page_192_eq_002.PNG]]
The design and optimization of sweetening processes can be done by computer, using programs such as HYSIM from Hyprotech of Calgary, which contains AMSIM from D.B. Robinson and Associates Ltd. of Edmonton, Alberta; ProTreat from Optimized Gas Treating Inc. of Houston; TSWEET from Bryan Research and Engineering Inc. of Bryan, Texas; and proprietary programs from the chemical supplier.
<br>


The specific gravity of the amine solutions is shown in '''Fig. 2'''.<ref name="r10"/> The specific gravity of potassium carbonate may be approximated by 1 + weight fraction K<sub>2</sub>CO<sub>3</sub> in solution.
=== Estimating solution circulation rate ===


<gallery widths=300px heights=200px>
The circulation rate or the acid gas pickup by the solution can be estimated with the next two formulas.
 
[[File:Vol3 page 192 eq 001.PNG|RTENOTITLE]]
 
[[File:Vol3 page 192 eq 002.PNG|RTENOTITLE]]
 
The specific gravity of the amine solutions is shown in '''Fig. 2'''.<ref name="r10">Dehydration. 1998. In GPSA Engineering Data Book, 11th edition, Sec. 19, 20, and 21. Tulsa, Oklahoma: Gas Processors Suppliers Association.</ref> The specific gravity of potassium carbonate may be approximated by 1 + weight fraction K<sub>2</sub>CO<sub>3</sub> in solution.
 
<gallery widths="300px" heights="200px">
File:Vol3 Page 192 Image 0001.png|'''Fig. 2—Specific gravity of aqueous armine solutions (after ''Engineering Data Book of Gas Processors Suppliers and Gas Processors Association'').'''<ref name="r10" />
File:Vol3 Page 192 Image 0001.png|'''Fig. 2—Specific gravity of aqueous armine solutions (after ''Engineering Data Book of Gas Processors Suppliers and Gas Processors Association'').'''<ref name="r10" />
</gallery>
</gallery>
<br>


===Types of operating problems===
=== Types of operating problems ===
The main problems that can be encountered in the operation of sour gas treating facilities using chemical solvents are as follows:<ref name="r11"/>
 
The main problems that can be encountered in the operation of sour gas treating facilities using chemical solvents are as follows:<ref name="r11">Abry, R.G.F. and DuPart, M.S. 1995. Amine Plant Troubleshooting and Optimization. Hydrocarbon Processing (April): 41-50. http://www.ineosllc.com/pdf/Hc%20Processing%20April%201995.pdf.</ref>
 
*failure to meet H<sub>2</sub>S specification for sales gas
*failure to meet H<sub>2</sub>S specification for sales gas
*solution foaming in the contactor or regenerator
*solution foaming in the contactor or regenerator
Line 121: Line 142:


Failure to Meet H<sub>2</sub>S Sales-Gas Specifications. Treated gas that does not meet the H<sub>2</sub>S specifications is not admitted into the sales-gas transmission lines. Potential causes for “going sour” are:
Failure to Meet H<sub>2</sub>S Sales-Gas Specifications. Treated gas that does not meet the H<sub>2</sub>S specifications is not admitted into the sales-gas transmission lines. Potential causes for “going sour” are:
*a change in the acid gas concentration of feed gas
*a change in the acid gas concentration of feed gas
*a change in the feed gas temperature
*a change in the feed gas temperature
Line 134: Line 156:
*foaming
*foaming


====Solution Foaming====
==== Solution Foaming ====
Solution foaming occurs when gas is mechanically entrained in liquid as bubbles.<ref name="r12"/> The tendency to form bubbles increases with decreasing surface tension of the solution owing to interference of foreign substance at the surface of the solution on the tray. Foaming is thought to be caused by factors such as:  
 
Solution foaming occurs when gas is mechanically entrained in liquid as bubbles.<ref name="r12">Pauley, C.R., Hashemi, R., and Caothien, S. 1989. Ways to Control Amine Unit Foaming Offered. Oil & Gas J 87 (50): 67-75.</ref> The tendency to form bubbles increases with decreasing surface tension of the solution owing to interference of foreign substance at the surface of the solution on the tray. Foaming is thought to be caused by factors such as:
 
*liquid hydrocarbons entering the contactor with the sour gas
*liquid hydrocarbons entering the contactor with the sour gas
*acidic amine-degradation products
*acidic amine-degradation products
Line 144: Line 168:


While solids suspended in the solution by themselves might not cause foaming, it is thought that they tend to stabilize the foam. The results from foaming can be:
While solids suspended in the solution by themselves might not cause foaming, it is thought that they tend to stabilize the foam. The results from foaming can be:
*severe upsets in the process tower
*severe upsets in the process tower
*leading to carryover and loss of chemical
*leading to carryover and loss of chemical
*possible damage to downstream process equipment or material
*possible damage to downstream process equipment or material


The best way to reduce the propensity for foaming is to ensure that the sour gas entering the contactor is clean, free of condensed liquids, and that the solution is cleaned up by mechanical and carbon filtration. The addition to the solution of antifoam agents is sometimes effective in controlling the foaming tendency of the solution. However, this does not solve the basic problem. Too much antifoam in the solution can actually add to the foaming problem.  
The best way to reduce the propensity for foaming is to ensure that the sour gas entering the contactor is clean, free of condensed liquids, and that the solution is cleaned up by mechanical and carbon filtration. The addition to the solution of antifoam agents is sometimes effective in controlling the foaming tendency of the solution. However, this does not solve the basic problem. Too much antifoam in the solution can actually add to the foaming problem.
 
==== Corrosion ====
 
Corrosion is common in most amine plants. It is necessary to control the corrosion rate by the addition of corrosion inhibitor and by use of stainless steel in certain pieces of process equipment. In the case of MEA solutions, corrosion rates tend to increase with increasing solution strengths beyond about 22% MEA, as well as with high levels of amine degradation products in the solution. Most of the process piping and vessels in amine plants are built with carbon steel, meeting NACE MR0175 guidelines.


====Corrosion====
It is not possible to predict with certainty where corrosive attack will take place. Experience has shown that the most likely areas for corrosive attack are those where the temperatures are high, such as in:
Corrosion is common in most amine plants. It is necessary to control the corrosion rate by the addition of corrosion inhibitor and by use of stainless steel in certain pieces of process equipment. In the case of MEA solutions, corrosion rates tend to increase with increasing solution strengths beyond about 22% MEA, as well as with high levels of amine degradation products in the solution. Most of the process piping and vessels in amine plants are built with carbon steel, meeting NACE MR0175 guidelines.


It is not possible to predict with certainty where corrosive attack will take place. Experience has shown that the most likely areas for corrosive attack are those where the temperatures are high, such as in:
*the top part of the still
*the top part of the still
*the reboiler tubes
*the reboiler tubes
Line 160: Line 187:


Hydrogen blisters are sometimes evident after many years of service in the shell of the contactor or still. Hydrogen-induced cracking can also occur in welds in the vessels or piping after many years of service. Corrosion/erosion can occur in areas where fluid velocities are high, such as:
Hydrogen blisters are sometimes evident after many years of service in the shell of the contactor or still. Hydrogen-induced cracking can also occur in welds in the vessels or piping after many years of service. Corrosion/erosion can occur in areas where fluid velocities are high, such as:
*in the return line from the reboiler
*in the return line from the reboiler
*at the point of entry of the reboiler vapors into the still
*at the point of entry of the reboiler vapors into the still
*downstream of pressure letdown valves
*downstream of pressure letdown valves


As compared with CO<sub>2</sub> and H<sub>2</sub>S mixtures, corrosion rates in amine systems, especially MEA systems, generally increase with: <ref name="r13"/>
As compared with CO<sub>2</sub> and H<sub>2</sub>S mixtures, corrosion rates in amine systems, especially MEA systems, generally increase with: <ref name="r13">DuPart, M.S., Bacon, T.R., and Edwards, D.J. 1963. Understanding Corrosion in Alkanolamine Gas Treating Plants, Part 1. Hydrocarbon Processing (April): 80.</ref>
 
*increasing temperature
*increasing temperature
*increasing amine concentration
*increasing amine concentration
Line 170: Line 199:
*pure acid gas
*pure acid gas


MEA is generally much more corrosive than DEA, and MDEA is only slightly corrosive.  
MEA is generally much more corrosive than DEA, and MDEA is only slightly corrosive.
 
Use of Corrosion Inhibitors. The use of corrosion inhibitors is a common practice to reduce the attack on steel by H<sub>2</sub>S and CO<sub>2</sub> in aqueous environments. In most sour gas sweetening installations, a corrosion inhibitor is continuously injected into the sweetening solution.
 
==== Solvent Loss ====


Use of Corrosion Inhibitors. The use of corrosion inhibitors is a common practice to reduce the attack on steel by H<sub>2</sub>S and CO<sub>2</sub> in aqueous environments. In most sour gas sweetening installations, a corrosion inhibitor is continuously injected into the sweetening solution.  
In all regenerative solvent systems, it is necessary to periodically add pure solvent to the solution because of the loss of solvent during operation. Solvent losses in gas treating systems can occur because of:


====Solvent Loss====
In all regenerative solvent systems, it is necessary to periodically add pure solvent to the solution because of the loss of solvent during operation. Solvent losses in gas treating systems can occur because of:
*vaporization
*vaporization
*entrainment
*entrainment
Line 181: Line 212:
*mechanical losses
*mechanical losses


Solvents used in gas treating, like any other liquids, have a vapor pressure that increases with temperature. In a gas sweetening system, there are three vessels where gas and liquid streams separate:  
Solvents used in gas treating, like any other liquids, have a vapor pressure that increases with temperature. In a gas sweetening system, there are three vessels where gas and liquid streams separate:
 
*contactor
*contactor
*flash tank
*flash tank
*reflux drum
*reflux drum


By far the largest gas stream is the one leaving the contactor. To reduce the solvent losses from this source, a water wash process is usually applied to the treated gas downstream of the contactor. Solvent losses from the flash tank are usually quite small, as the amount of gas leaving this vessel is usually small when compared to the total plant stream. When the solution is regenerated in the still, some solvent leaves the still overhead with the acid gas stream and the water vapor. Upon cooling the still overhead stream and condensing most of the water and amine, the liquid is returned to the top of the still as reflux, which also recovers most of the solvent. Nevertheless, some solvent vapor leaves the top of the reflux drum with the acid gas stream. Lower reflux drum temperatures reduce solvent losses at this point.  
By far the largest gas stream is the one leaving the contactor. To reduce the solvent losses from this source, a water wash process is usually applied to the treated gas downstream of the contactor. Solvent losses from the flash tank are usually quite small, as the amount of gas leaving this vessel is usually small when compared to the total plant stream. When the solution is regenerated in the still, some solvent leaves the still overhead with the acid gas stream and the water vapor. Upon cooling the still overhead stream and condensing most of the water and amine, the liquid is returned to the top of the still as reflux, which also recovers most of the solvent. Nevertheless, some solvent vapor leaves the top of the reflux drum with the acid gas stream. Lower reflux drum temperatures reduce solvent losses at this point.


Entrainment of solvent occurs during foaming or under high gas velocity situations. By preventing foaming and by staying within design throughput, entrainment losses can be avoided.  
Entrainment of solvent occurs during foaming or under high gas velocity situations. By preventing foaming and by staying within design throughput, entrainment losses can be avoided.


In amine systems, some degradation of the solvent occurs. Primary amines are most susceptible to this problem, and such systems require special separation equipment to periodically remove the degradation products that contribute to corrosion. The degradation products are mainly caused by irreversible reactions between the solvent and CO<sub>2</sub>.  
In amine systems, some degradation of the solvent occurs. Primary amines are most susceptible to this problem, and such systems require special separation equipment to periodically remove the degradation products that contribute to corrosion. The degradation products are mainly caused by irreversible reactions between the solvent and CO<sub>2</sub>.
 
The most serious losses of solvent usually result from mechanical actions or problems. These include:


The most serious losses of solvent usually result from mechanical actions or problems. These include:
*filter changeouts
*filter changeouts
*drips from pumps or flanges
*drips from pumps or flanges
*vessel cleaning and draining
*vessel cleaning and draining


==Physical solvents==
== Physical solvents ==
In addition to the chemical solvents, there are also physical solvents available for extracting the acid gases from natural gas. Physical solvents do not react chemically with acid gases but have a high physical absorptive capacity. The amount of acid gas absorbed is proportional to the partial pressure of the solute, and no upper limit, owing to saturation, is evident, as is the case with chemical solvents. Hence, they are mainly suited for sour gases with high acid gas content at high contacting pressures. The physical absorption solvents have the advantage of regeneration by flashing upon reduction of pressure and, therefore, do not require much heat in the stripping column. This makes physical solvents useful as bulk-removal processes, followed by final cleanup using a chemical solvent because physical solvents have difficulty in achieving the H<sub>2</sub>S limit specified for sales gas. Unfortunately, they also tend to absorb heavier hydrocarbons, which is a disadvantage if the acid gas is fed to a Claus plant for sulfur recovery.


There are several physical solvents mentioned in the literature. '''Fig. 3''' is a process schematic of a typical physical solvent process. A brief description of the more prominent physical solvent processes is discussed next.  
In addition to the chemical solvents, there are also physical solvents available for extracting the acid gases from natural gas. Physical solvents do not react chemically with acid gases but have a high physical absorptive capacity. The amount of acid gas absorbed is proportional to the partial pressure of the solute, and no upper limit, owing to saturation, is evident, as is the case with chemical solvents. Hence, they are mainly suited for sour gases with high acid gas content at high contacting pressures. The physical absorption solvents have the advantage of regeneration by flashing upon reduction of pressure and, therefore, do not require much heat in the stripping column. This makes physical solvents useful as bulk-removal processes, followed by final cleanup using a chemical solvent because physical solvents have difficulty in achieving the H<sub>2</sub>S limit specified for sales gas. Unfortunately, they also tend to absorb heavier hydrocarbons, which is a disadvantage if the acid gas is fed to a Claus plant for sulfur recovery.


<gallery widths=300px heights=200px>
There are several physical solvents mentioned in the literature. '''Fig. 3''' is a process schematic of a typical physical solvent process. A brief description of the more prominent physical solvent processes is discussed next.
 
<gallery widths="300px" heights="200px">
File:Vol3 Page 195 Image 0001.png|'''Fig. 3—Schematic drawing of physical solvent process equipment.'''
File:Vol3 Page 195 Image 0001.png|'''Fig. 3—Schematic drawing of physical solvent process equipment.'''
</gallery>
</gallery>
<br>


===Selexol process===
=== Selexol process ===
The Selexol<ref name="r14"/> process was developed by Allied Chemical Corp. The solvent is dimethyl ether of polyethylene glycol and is usually used in its pure form. It has a preference for H<sub>2</sub>S over CO<sub>2</sub>, and, therefore, some CO<sub>2</sub> remains in the gas stream, depending on the mole loading of the solvent. Several stages of flashing are provided for in the regeneration step, to allow the absorbed hydrocarbons to evolve from the solution. The flashed gases from the initial flash stages are compressed and returned to the inlet of the absorber. Selexol is noncorrosive and also removes water vapor from the gas stream.


===Fluor solvent process===
The Selexol<ref name="r14">Kutsher, G.S., Smith, G.A., and Greene, P.A. 1967. NOW—Sour-Gas Scrubbing by the Solvent Process. Oil & Gas J (March): 116.</ref> process was developed by Allied Chemical Corp. The solvent is dimethyl ether of polyethylene glycol and is usually used in its pure form. It has a preference for H<sub>2</sub>S over CO<sub>2</sub>, and, therefore, some CO<sub>2</sub> remains in the gas stream, depending on the mole loading of the solvent. Several stages of flashing are provided for in the regeneration step, to allow the absorbed hydrocarbons to evolve from the solution. The flashed gases from the initial flash stages are compressed and returned to the inlet of the absorber. Selexol is noncorrosive and also removes water vapor from the gas stream.
The solvent<ref name="r15"/> in this process is propylene carbonate and was developed in the late 1950s by The Fluor Corp. This solvent also has a greater affinity for H<sub>2</sub>S than for CO<sub>2</sub> and also dehydrates the feed gas. Absorptive capacity is highly temperature dependent, favoring the lower temperature.


===Purisol===
=== Fluor solvent process ===
The Purisol<ref name="r16"/> solvent process was developed in Germany by Lurgi. The solvent used is N-methylpyrrolidone, which has a high absorptive capacity for the acid gases.
 
The solvent<ref name="r15">Buckingham, P.A. 1964. Fluor Solvent Process Plants: How They Are Working. Hydrocarbon Processing (April): 113.</ref> in this process is propylene carbonate and was developed in the late 1950s by The Fluor Corp. This solvent also has a greater affinity for H<sub>2</sub>S than for CO<sub>2</sub> and also dehydrates the feed gas. Absorptive capacity is highly temperature dependent, favoring the lower temperature.
 
=== Purisol ===
 
The Purisol<ref name="r16">Purisol. 2000. Hydrocarbon Processing (April) 84.</ref> solvent process was developed in Germany by Lurgi. The solvent used is N-methylpyrrolidone, which has a high absorptive capacity for the acid gases.
 
== Hybrid process ==
 
=== Sulfinol ===
 
The Shell Sulfinol<ref name="r17">Goar, B.G. 1969. Sulfinol Process Has Several Key Advantages. Oil & Gas J (30 June): 117.</ref> process is a hybrid process using a combination of a physical solvent, sulfolane, and a chemical solvent, Diisopropanolamine (DIPA) or Methyl diethanolamine MDEA. The physical solvent and one of the chemical solvents each make up about 35 to 45% of the solution with the balance being water. The sulfinol process is economically attractive for treating gases with a high partial pressure of the acid gases, and it also removes:


==Hybrid process==
===Sulfinol===
The Shell Sulfinol<ref name="r17"/> process is a hybrid process using a combination of a physical solvent, sulfolane, and a chemical solvent, Diisopropanolamine (DIPA) or Methyl diethanolamine MDEA. The physical solvent and one of the chemical solvents each make up about 35 to 45% of the solution with the balance being water. The sulfinol process is economically attractive for treating gases with a high partial pressure of the acid gases, and it also removes:
*COS
*COS
*CS<sub>2</sub>
*CS<sub>2</sub>
Line 224: Line 263:


Other advantages are:
Other advantages are:
*good heat economy
*good heat economy
*low losses because of low vapor pressure
*low losses because of low vapor pressure
Line 230: Line 270:
A disadvantage of this process is that the sulfolane absorbs heavier hydrocarbons from the gas, some of which are then contained in the acid gas feed stream to the sulfur plant. Thus, the Sulfinol process is best suited for very sour, lean gas.
A disadvantage of this process is that the sulfolane absorbs heavier hydrocarbons from the gas, some of which are then contained in the acid gas feed stream to the sulfur plant. Thus, the Sulfinol process is best suited for very sour, lean gas.


==Reduction/oxidation (Redox) process==
== Reduction/oxidation (Redox) process ==
===Sluferox===
Typical Sulferox<ref name="r18"/> process equipment is illustrated in '''Fig. 4'''. In this process, the sour gas is contacted in a small contactor in cocurrent flow with a water solution containing about 4% ferric iron ions, held in solution by proprietary chelate ligand. The H<sub>2</sub>S ionizes in the solution, and the ferric iron ions exchange electrons with the sulfur ions to form ferrous iron ions and elemental sulfur. The gas and the solution leave the contactor and are flowed into a separator. The gas out of the separator is sweet and requires further treating for dewpoint control. The solution is flowed into additional vessels for separating the elemental sulfur and for restoring the ferrous iron ions back to the active ferric iron state by contacting the solution with air. The chemistry is illustrated next.


<gallery widths=300px heights=200px>
== Nonregenerative chemical solvent (Scavenger) processes ==
File:Vol3 Page 196 Image 0001.png|'''Fig. 4—Schematic drawing of typical Sulferox process equipment.'''
 
When the gas is only slightly sour, that is to say, contains only a few ppm of H<sub>2</sub>S above the specification limit, a simpler sweetening process might have economic advantages over the typical processes described in the previous sections.<ref name="r19">Schaack, J.P. and Chan, F. 1989. H2S Scavenging, 4-part series. Oil & Gas J (23 January): 51; (30 January): 81; (20 February): 45; (27 February): 90.</ref> These processes scavenge the H<sub>2</sub>S from the sour gas, with the chemical being consumed in the process. It is, therefore, necessary to periodically replenish the chemical, as well as dispose of the end product of reaction containing the sulfur. '''Table 2''' gives a summary of some common chemicals used for this purpose. The process equipment consists of a tower containing a solution of the chemical, or the chemical is in suspension in water. The sour gas is bubbled through the solution, and the chemical reacts with the H<sub>2</sub>S. The chemicals do not react with CO<sub>2</sub>.
 
<gallery widths="300px" heights="200px">
File:Vol3 Page 196 Image 0002.png|'''Table 2'''
</gallery>
</gallery>
<br>


[[File:Vol3_page_195_eq_001.PNG]]
The Sulfa-scrub process development.<ref name="r20">Dillon, E.T. 1991. Triazines Sweeten Gas Easier. Hydrocarbon Processing (December): 65.</ref> The chemical used in this process is triazine. The end product is beneficial as a corrosion inhibitor and is water soluble. As a result, disposal of the end product is convenient, as it is simply added to a water-disposal system. Sulfa-scrub can be injected into the flowline at the well, and it reacts with the H<sub>2</sub>S while the gas is flowing to the plant. Thus, there might not be a requirement for a treating tower.


==Nonregenerative chemical solvent (Scavenger) processes==
== Dry sweetening processes ==
When the gas is only slightly sour, that is to say, contains only a few ppm of H<sub>2</sub>S above the specification limit, a simpler sweetening process might have economic advantages over the typical processes described in the previous sections.<ref name="r19"/> These processes scavenge the H<sub>2</sub>S from the sour gas, with the chemical being consumed in the process. It is, therefore, necessary to periodically replenish the chemical, as well as dispose of the end product of reaction containing the sulfur. '''Table 2''' gives a summary of some common chemicals used for this purpose. The process equipment consists of a tower containing a solution of the chemical, or the chemical is in suspension in water. The sour gas is bubbled through the solution, and the chemical reacts with the H<sub>2</sub>S. The chemicals do not react with CO<sub>2</sub>.


<gallery widths=300px heights=200px>
While the sweetening of sour gas is predominantly done with regenerative solvents, there are also some dry processes that can be used for this purpose. Because these processes are batch processes, two or more towers are usually used, so that one tower can be taken out of service for chemical charge replacement without interruption of gas flow.
File:Vol3 Page 196 Image 0002.png|'''Table 2'''
</gallery>


The Sulfa-scrub process development.<ref name="r20"/> The chemical used in this process is triazine. The end product is beneficial as a corrosion inhibitor and is water soluble. As a result, disposal of the end product is convenient, as it is simply added to a water-disposal system. Sulfa-scrub can be injected into the flowline at the well, and it reacts with the H<sub>2</sub>S while the gas is flowing to the plant. Thus, there might not be a requirement for a treating tower.
=== Iron sponge (Iron Oxide) ===


==Dry sweetening processes==
Iron sponge<ref name="r21">Anerousis, J.P. and Whitman, S.K. 1985. Iron Sponge: Still a Top Option for Sour Gas Sweetening. Oil & Gas J (18 February): 71.</ref> consists of wood chips that have been impregnated with a hydrated form of iron oxide. The material is placed in a pressure vessel through which the sour gas is flowed. Because this is a batch process, usually two vessels are installed—one in service and the other on standby. The H<sub>2</sub>S reacts with the iron oxide to form iron sulfide. In due course, the iron oxide is consumed. While it is possible to regenerate the iron sulfide with air to restore the iron oxide, in practice this is not done. Instead, the tower containing the spent iron sponge is taken out of service, and the standby tower is placed in service. The spent iron sponge is moistened with water, removed, and disposed of at an approved disposal site, and the tower is filled with a new charge of iron sponge. Care has to be exercised in handling the spent material in the dry state, as it is pyrophoric. When dry iron sulfide is exposed to air, a spontaneous chemical reaction between the iron sulfide and oxygen takes place—oxidizing the iron sulfide to iron oxide and emitting sulfur dioxide into the air.
While the sweetening of sour gas is predominantly done with regenerative solvents, there are also some dry processes that can be used for this purpose. Because these processes are batch processes, two or more towers are usually used, so that one tower can be taken out of service for chemical charge replacement without interruption of gas flow.  


===Iron sponge (Iron Oxide)===
=== SulfaTreat (Iron Oxide) ===
Iron sponge<ref name="r21"/> consists of wood chips that have been impregnated with a hydrated form of iron oxide. The material is placed in a pressure vessel through which the sour gas is flowed. Because this is a batch process, usually two vessels are installed—one in service and the other on standby. The H<sub>2</sub>S reacts with the iron oxide to form iron sulfide. In due course, the iron oxide is consumed. While it is possible to regenerate the iron sulfide with air to restore the iron oxide, in practice this is not done. Instead, the tower containing the spent iron sponge is taken out of service, and the standby tower is placed in service. The spent iron sponge is moistened with water, removed, and disposed of at an approved disposal site, and the tower is filled with a new charge of iron sponge. Care has to be exercised in handling the spent material in the dry state, as it is pyrophoric. When dry iron sulfide is exposed to air, a spontaneous chemical reaction between the iron sulfide and oxygen takes place—oxidizing the iron sulfide to iron oxide and emitting sulfur dioxide into the air.


===SulfaTreat (Iron Oxide)===
Several years ago, a new iron-oxide-based dry product with the trade name of SulfaTreat<ref name="r22">Samuels, A. 1990. H2S Removal System Shows Promise Over Iron Sponge. Oil & Gas J (5 February): 44.</ref> was introduced for sweetening sour gas. The product is placed in towers, as illustrated in '''Fig. 5''', through which the sour gas is flowed. The gas stream should have a superficial gas velocity of no more than 10 ft/minute, and the temperature of the gas should be between 70 and 110°F. The gas must be water saturated at the tower conditions of temperature and pressure. SulfaTreat has a different molecular structure from that of iron sponge and, upon reaction with H<sub>2</sub>S, forms iron pyrite instead of iron sulfide. The charge of SulfaTreat is replaced when consumed.
Several years ago, a new iron-oxide-based dry product with the trade name of SulfaTreat<ref name="r22"/> was introduced for sweetening sour gas. The product is placed in towers, as illustrated in '''Fig. 5''', through which the sour gas is flowed. The gas stream should have a superficial gas velocity of no more than 10 ft/minute, and the temperature of the gas should be between 70 and 110°F. The gas must be water saturated at the tower conditions of temperature and pressure. SulfaTreat has a different molecular structure from that of iron sponge and, upon reaction with H<sub>2</sub>S, forms iron pyrite instead of iron sulfide. The charge of SulfaTreat is replaced when consumed.  


<gallery widths=300px heights=200px>
<gallery widths="300px" heights="200px">
File:Vol3 Page 198 Image 0001.png|'''Fig. 5—Schematic drawing of typical SulfaTreat process equipment.'''
File:Vol3 Page 198 Image 0001.png|'''Fig. 5—Schematic drawing of typical SulfaTreat process equipment.'''
</gallery>
</gallery>
<br>


This process is usually installed in a two-tower configuration, as shown in '''Fig. 5'''. The slightly sour gas is flowed through both towers in series. The H<sub>2</sub>S content is monitored in the gas between the two towers. When the concentration of H<sub>2</sub>S starts to increase in this gas, it is an indication that the SulfaTreat chemical in the first tower is consumed. This tower is then temporarily bypassed, and a fresh charge of chemical is installed. The tower containing the new chemical charge becomes the second tower in the continuation of the operation.
This process is usually installed in a two-tower configuration, as shown in '''Fig. 5'''. The slightly sour gas is flowed through both towers in series. The H<sub>2</sub>S content is monitored in the gas between the two towers. When the concentration of H<sub>2</sub>S starts to increase in this gas, it is an indication that the SulfaTreat chemical in the first tower is consumed. This tower is then temporarily bypassed, and a fresh charge of chemical is installed. The tower containing the new chemical charge becomes the second tower in the continuation of the operation.


===Molecular sieves===
=== Molecular sieves ===
Molecular sieves<ref name="r23"/> are crystalline compounds created from alumina silicates, with controlled and precise structures, which contain pores of uniform size. These compounds have an affinity for various molecules, especially for polar compounds such as water, H<sub>2</sub>S, and CO<sub>2</sub>. The pore size can be controlled during the manufacturing process and can be tailor-made for specific molecules, such as H<sub>2</sub>S. Molecular sieves can therefore be used for removing water from sour gas, or they can also be used for sweetening sour gas that exceeds the H<sub>2</sub>S specification by a few ppm. The process requires two or three towers filled with molecular sieves, one of which is used for adsorption, while the others are being regenerated by the application of a hot gas stream. Sweetening with molecular sieves is suitable for large volume, very low H<sub>2</sub>S concentration gas.
 
Molecular sieves<ref name="r23">Maddox, R.N. and Burns, M.D. 1968. Solids Processes for Gas Sweetening. Oil & Gas J (17 June): 90.</ref> are crystalline compounds created from alumina silicates, with controlled and precise structures, which contain pores of uniform size. These compounds have an affinity for various molecules, especially for polar compounds such as water, H<sub>2</sub>S, and CO<sub>2</sub>. The pore size can be controlled during the manufacturing process and can be tailor-made for specific molecules, such as H<sub>2</sub>S. Molecular sieves can therefore be used for removing water from sour gas, or they can also be used for sweetening sour gas that exceeds the H<sub>2</sub>S specification by a few ppm. The process requires two or three towers filled with molecular sieves, one of which is used for adsorption, while the others are being regenerated by the application of a hot gas stream. Sweetening with molecular sieves is suitable for large volume, very low H<sub>2</sub>S concentration gas.
 
== Screening program for optimum process selection ==


==Screening program for optimum process selection==
The Gas Research Institute (GRI) of Chicago, now called the Gas Technology Institute (GTI), has performed large scale investigations of redox and scavenger sweetening processes. The results have been compiled in reports and papers, which are available from GTI. Furthermore, computer screening programs have been prepared, and these are also available for a nominal fee. The two programs dealing with scavenger process selection are CalcBase™ and SeleXpert™. Information on these programs can be accessed on the GTI website, [http://griweb.gastechnology.org/ http://griweb.gastechnology.org/], by searching for the term “H<sub>2</sub>S scavenger.”
The Gas Research Institute (GRI) of Chicago, now called the Gas Technology Institute (GTI), has performed large scale investigations of redox and scavenger sweetening processes. The results have been compiled in reports and papers, which are available from GTI. Furthermore, computer screening programs have been prepared, and these are also available for a nominal fee. The two programs dealing with scavenger process selection are CalcBase™ and SeleXpert™. Information on these programs can be accessed on the GTI website, http://griweb.gastechnology.org/, by searching for the term “H<sub>2</sub>S scavenger.”


==Nomenclature==
== Nomenclature ==


{|
{|
|''AG''
|=
|percent acid gas, %
|-
|-
|''ML''  
| ''AG''
|=  
| =
|mole loading, moles/mole  
| percent acid gas,&nbsp;%
|-
| ''ML''
| =
| mole loading, moles/mole
|-
|-
|''MW''  
| ''MW''
|=  
| =
|molecular weight, lbm/mole  
| molecular weight, lbm/mole
|-
|-
|''Q''  
| ''Q''
|=  
| =
|gas flow rate, MMscf/d  
| gas flow rate, MMscf/d
|-
|-
|''SG''  
| ''SG''
|=  
| =
|specific gravity of solution (water = 1)  
| specific gravity of solution (water = 1)
|-
|-
|''W''  
| ''W''
|=  
| =
|weight percent of solvent in solution, %  
| weight percent of solvent in solution,&nbsp;%
|}
|}


==References==
== References ==
<references>
<ref name="r1">Smith, R.S. 1975. Improve Economics of Acid-Gas Treatment. ''Oil & Gas J'' '''73'''(March): 78-79. </ref>


<ref name="r2">Tennyson, R.N. and Schaaf, R.P. 1977. Guidelines Can Help Choose Proper Process for Gas-Treating Plants. ''Oil & Gas J'' '''75''' (2): 78. </ref>
<references />


<ref name="r3">King, J.C. et al. 1986. Rigorous Screening Selects Sour-Gas Plant Process. ''Oil & Gas J'' '''84''' (36): 101-110. </ref>
== Noteworthy papers in OnePetro ==


<ref name="r4">Butwell, K.F., Kubek, D.J., and Sigmund, P.W. 1982. Alkanolamine Treating. ''Hydrocarbon Processing'' (March): 108. </ref>
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read


<ref name="r5">Fitzgerald, K.J. and Richardson, J.A. 1966. New Correlations Enhance Value of Monoethanolamine Process. ''Oil & Gas J'' '''64''' (43): 110-118. </ref>
== External links ==


<ref name="r6">Freireich, E. and Tennyson, R.N. 1976. Process Improves Acid Gas Removal, Trims Costs, and Reduces Effluents. ''Oil & Gas J'' '''74''' (34): 130-132. </ref>
[http://www.iadc.org/ International Association of Drilling Contractors]


<ref name="r7">Love, D. 1972. Quick Design Charts For Diethanolamine Plants. ''Oil & Gas J'' '''70''' (January): 88. </ref>
[https://www.osha.gov/SLTC/etools/oilandgas/general_safety/h2s_monitoring.html Occupational Safety & Health Administration]


<ref name="r8">Goar, B.G. 1980. Selective Gas Treating Produces Better Claus Feeds. ''Oil & Gas J'' '''78''' (18): 239-242. </ref>
== See also ==


<ref name="r9">Maddox, R.N. 1967. Hot Carbonate—Another Possibility. ''Oil & Gas J'' (October): 167-173. </ref>
[[Hydrogen_sulfide_(H2S)_fields|Hydrogen sulfide (H2S) fields]]


<ref name="r10">Dehydration. 1998. In ''GPSA Engineering Data Book'', 11th edition, Sec. 19, 20, and 21. Tulsa, Oklahoma: Gas Processors Suppliers Association. </ref>
[[Sour_gas|Sour gas]]


<ref name="r11">Abry, R.G.F. and DuPart, M.S. 1995. Amine Plant Troubleshooting and Optimization. ''Hydrocarbon Processing'' (April): 41-50. http://www.ineosllc.com/pdf/Hc%20Processing%20April%201995.pdf. </ref>
'''Sour gas sweetening'''


<ref name="r12">Pauley, C.R., Hashemi, R., and Caothien, S. 1989. Ways to Control Amine Unit Foaming Offered. ''Oil & Gas J'' '''87''' (50): 67-75. </ref>
[[PEH:Drilling_Problems_and_Solutions]]


<ref name="r13">DuPart, M.S., Bacon, T.R., and Edwards, D.J. 1963. Understanding Corrosion in Alkanolamine Gas Treating Plants, Part 1. ''Hydrocarbon Processing'' (April): 80. </ref>
[[PEH:Gas_Treating_and_Processing|PEH:Gas Treating and Processing]]
 
<ref name="r14">Kutsher, G.S., Smith, G.A., and Greene, P.A. 1967. NOW—Sour-Gas Scrubbing by the Solvent Process. ''Oil & Gas J'' (March): 116. </ref>
 
<ref name="r15">Buckingham, P.A. 1964. Fluor Solvent Process Plants: How They Are Working. ''Hydrocarbon Processing'' (April): 113. </ref>
 
<ref name="r16">Purisol. 2000. ''Hydrocarbon Processing'' (April) 84. </ref>
 
<ref name="r17">Goar, B.G. 1969. Sulfinol Process Has Several Key Advantages. ''Oil & Gas J'' (30 June): 117. </ref>
 
<ref name="r18">Fong, H.L., Kushner, D.S., and Scott, R.T. 1987. Shell Redox Desulfurization Process Stresses Versatility. ''Oil & Gas J'' '''84''' (21): 54-64. </ref>
 
<ref name="r19">Schaack, J.P. and Chan, F. 1989. H<sub>2</sub>S Scavenging, 4-part series. ''Oil & Gas J'' (23 January): 51; (30 January): 81; (20 February): 45; (27 February): 90. </ref>
 
<ref name="r20">Dillon, E.T. 1991. Triazines Sweeten Gas Easier. ''Hydrocarbon Processing'' (December): 65. </ref>
 
<ref name="r21">Anerousis, J.P. and Whitman, S.K. 1985. Iron Sponge: Still a Top Option for Sour Gas Sweetening. ''Oil & Gas J'' (18 February): 71. </ref>
 
<ref name="r22">Samuels, A. 1990. H<sub>2</sub>S Removal System Shows Promise Over Iron Sponge. ''Oil & Gas J'' (5 February): 44. </ref>
 
<ref name="r23">Maddox, R.N. and Burns, M.D. 1968. Solids Processes for Gas Sweetening. ''Oil & Gas J'' (17 June): 90. </ref>
</references>
 
==Noteworthy papers in OnePetro==
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
 
==External links==
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
 
==See also==
[[PEH%3AGas_Treating_and_Processing|PEH:Gas Treating and Processing]]


[[Gas_treating_and_processing|Gas Treating and Processing]]
[[Gas_treating_and_processing|Gas Treating and Processing]]
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[[Dry_dessicant_dehydration|Dry dessicant dehydration]]
[[Dry_dessicant_dehydration|Dry dessicant dehydration]]
==Category==
[[Category:4.1.5 Processing equipment]] [[Category:YR]]

Latest revision as of 12:10, 6 July 2015

Sour natural gas compositions can vary over a wide concentration of H2S and CO2 and a wide concentration of hydrocarbon components. If the H2S content exceeds the sales gas specification limit, the excess H2S must be separated from the sour gas. The removal of H2S from sour gas is called “sweetening.”

Overview of sweetening process

The process selected for sweetening a sour gas depends on the general conditions:

  • H2S and mercaptan concentration in the sour gas, and sales gas H2S and total sulfur limits
  • maximum design flow rate
  • raw gas inlet pressure
  • requirement for sulfur recovery
  • acceptable method of waste products disposal

Cost considerations

The selected process must be cost effective in meeting the various specifications and requirements. Throughout the world, regulations generally limit the flaring of H2S. Sweetening of gas streams containing very low concentrations of H2S can be done in many ways, depending on the general conditions. If the sour gas stream contains more than 70 to 100 pounds of sulfur/day in the form of H2S in the inlet gas to a sour plant, a regenerative chemical solvent is usually selected for the sweetening of the sour gas stream. For very low H2S content sour gas, a scavenger chemical is usually used. In such cases, the chemical is consumed, and the method for ultimate disposal of the spent chemical is a consideration.

Typical process equipment for sweetening sour gas with a regenerative solvent

A schematic drawing of typical process equipment for sweetening sour gas with regenerative solvent is shown in Fig. 1. The first vessel is the inlet separator, which performs the important function of separating the fluid phases on the basis of density difference between the liquid and the gas. The sour gas flows from the separator into the lower part of the absorber or contactor. This vessel usually contains 20 to 24 trays, but for small units, it could be a column containing packing. Lean solution containing the sweetening solvent in water is pumped into the absorber near the top. As the solution flows down from tray to tray, it is in intimate contact with the sour gas as the gas flows upward through the liquid on each tray. When the gas reaches the top of the vessel, virtually all the H2S and, depending on the solvent used, all the CO2 have been removed from the gas stream. The gas is now sweet and meets the specifications for:

  • H2S
  • CO2
  • total sulfur content

The rich solution leaves the contactor at the bottom and is flowed through a pressure letdown valve, allowing the pressure to drop to about 60 psig. In some major gas plants, the pressure reduction is accomplished through turbines recovering power.[1] Upon reduction of the pressure, the rich solution is flowed into a flash drum, where most dissolved hydrocarbon gas and some acid gas flash off. The solution then flows through a heat exchanger, picking up heat from the hot, regenerated lean solution stream. The rich solution then flows into the still, where the regeneration of the solvent occurs at a pressure of about 12 to 15 psig and at the solution boiling temperature. Heat is applied from an external source, such as a steam reboiler. The liberated acid gas and any hydrocarbon gas not flashed off in the flash drum leave the still at the top, together with some solvent and a lot of water vapor. This stream of vapors is flowed through a condenser, usually an aerial cooler, to condense the solvent and water vapors. The liquid and gas mixture is flowed into a separator, normally referred to as a reflux drum, where the acid gas is separated from the condensed liquids. The liquids are pumped back into the top of the still as reflux. The gas stream, consisting mainly of H2S and CO2, is generally piped to a sulfur recovery unit. The regenerated solution is flowed from the reboiler or the bottom of the still through the rich/lean solution heat exchanger to a surge tank. From here, the solution is pumped through a cooler to adjust the temperature to the appropriate treating temperature in the absorber. The stream is then pumped with a high-pressure pump back into the top of the absorber, to continue the sweetening of the sour gas.

Most solvent systems have a means of filtering the solution. This is accomplished by flowing a portion of the lean solution through a particle filter and sometimes a carbon filter as well. The purpose is to maintain a high degree of solution cleanliness to avoid solution foaming. Some solvent systems also have a means of removing degradation products that involves maintaining an additional reboiler for this purpose in the regeneration equipment hook-up. In some designs, the rich solution is filtered after it leaves the surge drum.

Sweetening solvents

The desirable characteristics of a sweetening solvent are:

  • Required removal of H2S and other sulfur compounds must be achieved.
  • Pickup of hydrocarbons must be low.
  • Solvent vapor pressure must be low to minimize solvent losses.
  • Reactions between solvent and acid gases must be reversible to prevent solvent degradation.
  • Solvent must be thermally stable.
  • Removal of degradation products must be simple.
  • The acid gas pickup per unit of solvent circulated must be high.
  • Heat requirement for solvent regeneration or stripping must be low.
  • The solvent should be noncorrosive.
  • The solvent should not foam in the contactor or still.
  • Selective removal of acid gases is desirable.
  • The solvent should be cheap and readily available.

Unfortunately, there is no one solvent that has all the desirable characteristics. This makes it necessary to select the solvent that is best suited for treating the particular sour gas mixture from the various solvents that are available.[2] The sour natural gas mixtures vary in:

  • H2S and CO2 content and ratio
  • content of heavy or aromatic compounds
  • content of COS, CS2, and mercaptans

While most of the sour gas is sweetened with regenerative solvents, for slightly sour gas, it may be more economical to use scavenger solvents or solid agents.[3] In such processes, the compound reacts chemically with the H2S and is consumed in the sweetening process, requiring the sweetening agent to be periodically replaced.

Regenerative chemical solvents

Most of the regenerative chemical sweetening solvents are alkanolamines, which are compounds formed by replacing one, two, or three hydrogen atoms of the ammonia molecule with radicals of other compounds to form primary, secondary, or tertiary amines respectively.[4] Amines are weak organic bases that have been used for many years in gas treating to remove CO2 and H2S from natural gas as well as from synthesis gas. These compounds combine chemically with the acid gases in the contactor to form unstable salts. The salts break down under the elevated temperature and low pressure in the still.

Because the chemical reactions are reversible by changing the physical conditions of temperature and pressure between absorber and still, amines are highly suitable for removing the acid gases from the hydrocarbon gas stream. However, sometimes nonreversible reactions take place to a minor degree, forming degradation compounds. Such degradation compounds must be periodically removed by distillation. This occurs in a reclaimer vessel. Primary amines are more prone to forming degradation compounds than the other solvents.

Another chemical solvent, potassium carbonate (K2CO3), has also been used for removing H2S and CO2 from manufactured or natural gas. It is not widely accepted in the sour natural gas industry, but it is periodically mentioned in the literature as finding some application under specific conditions. This chemical solvent was originally developed by the U.S. Bureau of Mines for removing CO2 from manufactured gas. Table 1 lists the regenerative chemical solvents generally used for sweetening sour gas and gives the acronyms, chemical formulas, and molecular weights.

Primary amines

Monoethanolamine (MEA)

[5] MEA was the earliest amine used for sweetening sour gas. It is a stronger base than diethanolamine (DEA) and also has a higher vapor pressure than DEA; therefore, vapor losses are higher than for DEA. MEA forms nonregenerative (degradation) compounds with:

  • CO2
  • COS
  • CS2

This is a disadvantage, as the degradation compounds must be removed periodically to lessen the corrosion rate. A reclaimer is usually incorporated in an MEA sweetening train to periodically remove the degradation products from the solution by distillation. MEA has been used for more than 60 years in process applications, and the process operation and problem areas are well understood. Solution strengths of MEA are usually in the range of 15 to 22% by weight MEA in water. Mol loadings (moles of acid gas picked up in the contactor per mole of solvent circulated) are generally in the range of 0.25 to 0.33 moles acid gas per mol of MEA.

Diglycolamine (DGA)

The DGA process was developed by The Fluor Corp. in the 1950s, which called the process the Econamine Process. The advantage of DGA over MEA appears to be the lower solution circulation rate owing to the higher solvent concentration, resulting in higher acid gas pickup per volume of solution circulated.[6] This yields capital savings, as the regeneration equipment is smaller for DGA than for MEA. Disadvantages appear to be degradation of the chemical with CO2 and greater solubility of heavier hydrocarbons in the solution, as compared to MEA. This is a serious drawback if the acid gas stream is fed to a Claus plant, as additional air is required for the combustion of the hydrocarbons. Also, this dilutes the sulfur compounds in the sulfur recovery train. Solution strength is on the order of 50 to 70% by weight of DGA in water, with mol loadings in the range of 0.3 to 0.4 moles of acid gas per mole of DGA circulated. The DGA process train usually includes a reclaimer.

Secondary armines

Diethanolamine (DEA)

[7] DEA became a popular sour gas treating solvent in the 1960s after it was developed for such application in France. It can be used at higher concentrations than MEA. DEA has the advantage of picking up more acid gas per solution volume circulated, thus effecting some energy saving in circulation and regeneration. It does not form the nonregenerative products with COS and CS2 as is the case with MEA, which is another advantage over MEA. DEA is also generally less corrosive than MEA. Solution strength is usually in the 25 to 40% range, with mol loadings of 0.35 to 0.63.

Diisopropanolamine (DIPA)

This secondary amine is not used by itself as a sweetening solvent but is part of the Sulfinol solvent formulation.

Tertiary armines

Triethanolamine (TEA)

TEA is not in general use for gas sweetening.

Methyldiethanolamine (MDEA)

[8] MDEA reacts more slowly with CO2 than the previously described amines. It forms a slightly different salt with CO2 from those of the other amines, at a lower rate of reaction. The difference in the rates of reaction with H2S and CO2 gives MDEA a desirable feature over other amines, namely selectivity of H2S over CO2. This is an attractive feature in cases where it is not necessary to remove all the CO2 from the gas stream. By leaving some of the CO2 in the natural gas, the circulation rate of the solution can be reduced, or the treating capacity of an existing unit can be increased with MDEA as compared with DEA.

MDEA concentrations are on the order of 30 to 50% by weight, with mol loadings of 0.40 to 0.55 moles acid gas per mol of amine. As a tertiary amine, MDEA is naturally a weaker base and is therefore less corrosive than the primary and secondary amines. The energy required for regeneration is also less than the requirement for the other amines.

Proprietary armine solvent formulations

By making use of the difference in the rates of reaction between MDEA and the acid gases, several proprietary solvents have been developed that are suited for preferential extraction of H2S, with only partial removal of CO2 . These proprietary formulations usually contain MDEA plus other amines at various concentrations in aqueous solutions to tailor them for specific applications. Several chemical companies have developed such proprietary solvents.[3]

Hot potassium carbonate (K2CO3) (Hot Pot)

[9]The potassium carbonate process was developed for removing CO2 from manufactured gas. It reacts with both acid gases. Because the contacting of the sour gas occurs at very high temperatures, such as 195 to 230°F in this process, it is sometimes referred to as the “hot pot” process. It requires lower heat input for regeneration and is therefore somewhat less costly to operate than some amine processes. Also, no heat exchanger is required in the regeneration equipment. The process has difficulty in meeting the H2S specification of the treated gas if the H2S/CO2 ratio is not extremely small. This process is significant for treating gas with a large concentration of CO2. The chemistry of the process can be enhanced by the addition of various catalysts, and this has resulted in the process being referred to by various trade names.

Computer simulation of sweetening processes

The design and optimization of sweetening processes can be done by computer, using programs such as HYSIM from Hyprotech of Calgary, which contains AMSIM from D.B. Robinson and Associates Ltd. of Edmonton, Alberta; ProTreat from Optimized Gas Treating Inc. of Houston; TSWEET from Bryan Research and Engineering Inc. of Bryan, Texas; and proprietary programs from the chemical supplier.

Estimating solution circulation rate

The circulation rate or the acid gas pickup by the solution can be estimated with the next two formulas.

RTENOTITLE

RTENOTITLE

The specific gravity of the amine solutions is shown in Fig. 2.[10] The specific gravity of potassium carbonate may be approximated by 1 + weight fraction K2CO3 in solution.

Types of operating problems

The main problems that can be encountered in the operation of sour gas treating facilities using chemical solvents are as follows:[11]

  • failure to meet H2S specification for sales gas
  • solution foaming in the contactor or regenerator
  • corrosion in pipes and vessels
  • solvent losses

Failure to Meet H2S Sales-Gas Specifications. Treated gas that does not meet the H2S specifications is not admitted into the sales-gas transmission lines. Potential causes for “going sour” are:

  • a change in the acid gas concentration of feed gas
  • a change in the feed gas temperature
  • too hot lean amine solution
  • too low solvent concentration in solution
  • inadequate regeneration of solution
  • insufficient contact in absorber
  • too low amine circulation rate
  • too low absorber pressure
  • too high concentration of degradation products
  • too high inlet gas rate
  • mechanical damage or problems in absorber
  • foaming

Solution Foaming

Solution foaming occurs when gas is mechanically entrained in liquid as bubbles.[12] The tendency to form bubbles increases with decreasing surface tension of the solution owing to interference of foreign substance at the surface of the solution on the tray. Foaming is thought to be caused by factors such as:

  • liquid hydrocarbons entering the contactor with the sour gas
  • acidic amine-degradation products
  • treating chemicals from wells or gathering system
  • treating chemicals from makeup water
  • compressor oil
  • fine solid suspensions such as iron sulfide

While solids suspended in the solution by themselves might not cause foaming, it is thought that they tend to stabilize the foam. The results from foaming can be:

  • severe upsets in the process tower
  • leading to carryover and loss of chemical
  • possible damage to downstream process equipment or material

The best way to reduce the propensity for foaming is to ensure that the sour gas entering the contactor is clean, free of condensed liquids, and that the solution is cleaned up by mechanical and carbon filtration. The addition to the solution of antifoam agents is sometimes effective in controlling the foaming tendency of the solution. However, this does not solve the basic problem. Too much antifoam in the solution can actually add to the foaming problem.

Corrosion

Corrosion is common in most amine plants. It is necessary to control the corrosion rate by the addition of corrosion inhibitor and by use of stainless steel in certain pieces of process equipment. In the case of MEA solutions, corrosion rates tend to increase with increasing solution strengths beyond about 22% MEA, as well as with high levels of amine degradation products in the solution. Most of the process piping and vessels in amine plants are built with carbon steel, meeting NACE MR0175 guidelines.

It is not possible to predict with certainty where corrosive attack will take place. Experience has shown that the most likely areas for corrosive attack are those where the temperatures are high, such as in:

  • the top part of the still
  • the reboiler tubes
  • the heat exchangers
  • some connecting piping

Hydrogen blisters are sometimes evident after many years of service in the shell of the contactor or still. Hydrogen-induced cracking can also occur in welds in the vessels or piping after many years of service. Corrosion/erosion can occur in areas where fluid velocities are high, such as:

  • in the return line from the reboiler
  • at the point of entry of the reboiler vapors into the still
  • downstream of pressure letdown valves

As compared with CO2 and H2S mixtures, corrosion rates in amine systems, especially MEA systems, generally increase with: [13]

  • increasing temperature
  • increasing amine concentration
  • increasing mole loadings
  • pure acid gas

MEA is generally much more corrosive than DEA, and MDEA is only slightly corrosive.

Use of Corrosion Inhibitors. The use of corrosion inhibitors is a common practice to reduce the attack on steel by H2S and CO2 in aqueous environments. In most sour gas sweetening installations, a corrosion inhibitor is continuously injected into the sweetening solution.

Solvent Loss

In all regenerative solvent systems, it is necessary to periodically add pure solvent to the solution because of the loss of solvent during operation. Solvent losses in gas treating systems can occur because of:

  • vaporization
  • entrainment
  • degradation and removal of degradation products
  • mechanical losses

Solvents used in gas treating, like any other liquids, have a vapor pressure that increases with temperature. In a gas sweetening system, there are three vessels where gas and liquid streams separate:

  • contactor
  • flash tank
  • reflux drum

By far the largest gas stream is the one leaving the contactor. To reduce the solvent losses from this source, a water wash process is usually applied to the treated gas downstream of the contactor. Solvent losses from the flash tank are usually quite small, as the amount of gas leaving this vessel is usually small when compared to the total plant stream. When the solution is regenerated in the still, some solvent leaves the still overhead with the acid gas stream and the water vapor. Upon cooling the still overhead stream and condensing most of the water and amine, the liquid is returned to the top of the still as reflux, which also recovers most of the solvent. Nevertheless, some solvent vapor leaves the top of the reflux drum with the acid gas stream. Lower reflux drum temperatures reduce solvent losses at this point.

Entrainment of solvent occurs during foaming or under high gas velocity situations. By preventing foaming and by staying within design throughput, entrainment losses can be avoided.

In amine systems, some degradation of the solvent occurs. Primary amines are most susceptible to this problem, and such systems require special separation equipment to periodically remove the degradation products that contribute to corrosion. The degradation products are mainly caused by irreversible reactions between the solvent and CO2.

The most serious losses of solvent usually result from mechanical actions or problems. These include:

  • filter changeouts
  • drips from pumps or flanges
  • vessel cleaning and draining

Physical solvents

In addition to the chemical solvents, there are also physical solvents available for extracting the acid gases from natural gas. Physical solvents do not react chemically with acid gases but have a high physical absorptive capacity. The amount of acid gas absorbed is proportional to the partial pressure of the solute, and no upper limit, owing to saturation, is evident, as is the case with chemical solvents. Hence, they are mainly suited for sour gases with high acid gas content at high contacting pressures. The physical absorption solvents have the advantage of regeneration by flashing upon reduction of pressure and, therefore, do not require much heat in the stripping column. This makes physical solvents useful as bulk-removal processes, followed by final cleanup using a chemical solvent because physical solvents have difficulty in achieving the H2S limit specified for sales gas. Unfortunately, they also tend to absorb heavier hydrocarbons, which is a disadvantage if the acid gas is fed to a Claus plant for sulfur recovery.

There are several physical solvents mentioned in the literature. Fig. 3 is a process schematic of a typical physical solvent process. A brief description of the more prominent physical solvent processes is discussed next.

Selexol process

The Selexol[14] process was developed by Allied Chemical Corp. The solvent is dimethyl ether of polyethylene glycol and is usually used in its pure form. It has a preference for H2S over CO2, and, therefore, some CO2 remains in the gas stream, depending on the mole loading of the solvent. Several stages of flashing are provided for in the regeneration step, to allow the absorbed hydrocarbons to evolve from the solution. The flashed gases from the initial flash stages are compressed and returned to the inlet of the absorber. Selexol is noncorrosive and also removes water vapor from the gas stream.

Fluor solvent process

The solvent[15] in this process is propylene carbonate and was developed in the late 1950s by The Fluor Corp. This solvent also has a greater affinity for H2S than for CO2 and also dehydrates the feed gas. Absorptive capacity is highly temperature dependent, favoring the lower temperature.

Purisol

The Purisol[16] solvent process was developed in Germany by Lurgi. The solvent used is N-methylpyrrolidone, which has a high absorptive capacity for the acid gases.

Hybrid process

Sulfinol

The Shell Sulfinol[17] process is a hybrid process using a combination of a physical solvent, sulfolane, and a chemical solvent, Diisopropanolamine (DIPA) or Methyl diethanolamine MDEA. The physical solvent and one of the chemical solvents each make up about 35 to 45% of the solution with the balance being water. The sulfinol process is economically attractive for treating gases with a high partial pressure of the acid gases, and it also removes:

  • COS
  • CS2
  • mercaptans

Other advantages are:

  • good heat economy
  • low losses because of low vapor pressure
  • absence of corrosion

A disadvantage of this process is that the sulfolane absorbs heavier hydrocarbons from the gas, some of which are then contained in the acid gas feed stream to the sulfur plant. Thus, the Sulfinol process is best suited for very sour, lean gas.

Reduction/oxidation (Redox) process

Nonregenerative chemical solvent (Scavenger) processes

When the gas is only slightly sour, that is to say, contains only a few ppm of H2S above the specification limit, a simpler sweetening process might have economic advantages over the typical processes described in the previous sections.[18] These processes scavenge the H2S from the sour gas, with the chemical being consumed in the process. It is, therefore, necessary to periodically replenish the chemical, as well as dispose of the end product of reaction containing the sulfur. Table 2 gives a summary of some common chemicals used for this purpose. The process equipment consists of a tower containing a solution of the chemical, or the chemical is in suspension in water. The sour gas is bubbled through the solution, and the chemical reacts with the H2S. The chemicals do not react with CO2.

The Sulfa-scrub process development.[19] The chemical used in this process is triazine. The end product is beneficial as a corrosion inhibitor and is water soluble. As a result, disposal of the end product is convenient, as it is simply added to a water-disposal system. Sulfa-scrub can be injected into the flowline at the well, and it reacts with the H2S while the gas is flowing to the plant. Thus, there might not be a requirement for a treating tower.

Dry sweetening processes

While the sweetening of sour gas is predominantly done with regenerative solvents, there are also some dry processes that can be used for this purpose. Because these processes are batch processes, two or more towers are usually used, so that one tower can be taken out of service for chemical charge replacement without interruption of gas flow.

Iron sponge (Iron Oxide)

Iron sponge[20] consists of wood chips that have been impregnated with a hydrated form of iron oxide. The material is placed in a pressure vessel through which the sour gas is flowed. Because this is a batch process, usually two vessels are installed—one in service and the other on standby. The H2S reacts with the iron oxide to form iron sulfide. In due course, the iron oxide is consumed. While it is possible to regenerate the iron sulfide with air to restore the iron oxide, in practice this is not done. Instead, the tower containing the spent iron sponge is taken out of service, and the standby tower is placed in service. The spent iron sponge is moistened with water, removed, and disposed of at an approved disposal site, and the tower is filled with a new charge of iron sponge. Care has to be exercised in handling the spent material in the dry state, as it is pyrophoric. When dry iron sulfide is exposed to air, a spontaneous chemical reaction between the iron sulfide and oxygen takes place—oxidizing the iron sulfide to iron oxide and emitting sulfur dioxide into the air.

SulfaTreat (Iron Oxide)

Several years ago, a new iron-oxide-based dry product with the trade name of SulfaTreat[21] was introduced for sweetening sour gas. The product is placed in towers, as illustrated in Fig. 5, through which the sour gas is flowed. The gas stream should have a superficial gas velocity of no more than 10 ft/minute, and the temperature of the gas should be between 70 and 110°F. The gas must be water saturated at the tower conditions of temperature and pressure. SulfaTreat has a different molecular structure from that of iron sponge and, upon reaction with H2S, forms iron pyrite instead of iron sulfide. The charge of SulfaTreat is replaced when consumed.

This process is usually installed in a two-tower configuration, as shown in Fig. 5. The slightly sour gas is flowed through both towers in series. The H2S content is monitored in the gas between the two towers. When the concentration of H2S starts to increase in this gas, it is an indication that the SulfaTreat chemical in the first tower is consumed. This tower is then temporarily bypassed, and a fresh charge of chemical is installed. The tower containing the new chemical charge becomes the second tower in the continuation of the operation.

Molecular sieves

Molecular sieves[22] are crystalline compounds created from alumina silicates, with controlled and precise structures, which contain pores of uniform size. These compounds have an affinity for various molecules, especially for polar compounds such as water, H2S, and CO2. The pore size can be controlled during the manufacturing process and can be tailor-made for specific molecules, such as H2S. Molecular sieves can therefore be used for removing water from sour gas, or they can also be used for sweetening sour gas that exceeds the H2S specification by a few ppm. The process requires two or three towers filled with molecular sieves, one of which is used for adsorption, while the others are being regenerated by the application of a hot gas stream. Sweetening with molecular sieves is suitable for large volume, very low H2S concentration gas.

Screening program for optimum process selection

The Gas Research Institute (GRI) of Chicago, now called the Gas Technology Institute (GTI), has performed large scale investigations of redox and scavenger sweetening processes. The results have been compiled in reports and papers, which are available from GTI. Furthermore, computer screening programs have been prepared, and these are also available for a nominal fee. The two programs dealing with scavenger process selection are CalcBase™ and SeleXpert™. Information on these programs can be accessed on the GTI website, http://griweb.gastechnology.org/, by searching for the term “H2S scavenger.”

Nomenclature

AG = percent acid gas, %
ML = mole loading, moles/mole
MW = molecular weight, lbm/mole
Q = gas flow rate, MMscf/d
SG = specific gravity of solution (water = 1)
W = weight percent of solvent in solution, %

References

  1. Smith, R.S. 1975. Improve Economics of Acid-Gas Treatment. Oil & Gas J 73(March): 78-79.
  2. Tennyson, R.N. and Schaaf, R.P. 1977. Guidelines Can Help Choose Proper Process for Gas-Treating Plants. Oil & Gas J 75 (2): 78.
  3. 3.0 3.1 King, J.C. et al. 1986. Rigorous Screening Selects Sour-Gas Plant Process. Oil & Gas J 84 (36): 101-110.
  4. Butwell, K.F., Kubek, D.J., and Sigmund, P.W. 1982. Alkanolamine Treating. Hydrocarbon Processing (March): 108.
  5. Fitzgerald, K.J. and Richardson, J.A. 1966. New Correlations Enhance Value of Monoethanolamine Process. Oil & Gas J 64 (43): 110-118.
  6. Freireich, E. and Tennyson, R.N. 1976. Process Improves Acid Gas Removal, Trims Costs, and Reduces Effluents. Oil & Gas J 74 (34): 130-132.
  7. Love, D. 1972. Quick Design Charts For Diethanolamine Plants. Oil & Gas J 70 (January): 88.
  8. Goar, B.G. 1980. Selective Gas Treating Produces Better Claus Feeds. Oil & Gas J 78 (18): 239-242.
  9. Maddox, R.N. 1967. Hot Carbonate—Another Possibility. Oil & Gas J (October): 167-173.
  10. 10.0 10.1 Dehydration. 1998. In GPSA Engineering Data Book, 11th edition, Sec. 19, 20, and 21. Tulsa, Oklahoma: Gas Processors Suppliers Association.
  11. Abry, R.G.F. and DuPart, M.S. 1995. Amine Plant Troubleshooting and Optimization. Hydrocarbon Processing (April): 41-50. http://www.ineosllc.com/pdf/Hc%20Processing%20April%201995.pdf.
  12. Pauley, C.R., Hashemi, R., and Caothien, S. 1989. Ways to Control Amine Unit Foaming Offered. Oil & Gas J 87 (50): 67-75.
  13. DuPart, M.S., Bacon, T.R., and Edwards, D.J. 1963. Understanding Corrosion in Alkanolamine Gas Treating Plants, Part 1. Hydrocarbon Processing (April): 80.
  14. Kutsher, G.S., Smith, G.A., and Greene, P.A. 1967. NOW—Sour-Gas Scrubbing by the Solvent Process. Oil & Gas J (March): 116.
  15. Buckingham, P.A. 1964. Fluor Solvent Process Plants: How They Are Working. Hydrocarbon Processing (April): 113.
  16. Purisol. 2000. Hydrocarbon Processing (April) 84.
  17. Goar, B.G. 1969. Sulfinol Process Has Several Key Advantages. Oil & Gas J (30 June): 117.
  18. Schaack, J.P. and Chan, F. 1989. H2S Scavenging, 4-part series. Oil & Gas J (23 January): 51; (30 January): 81; (20 February): 45; (27 February): 90.
  19. Dillon, E.T. 1991. Triazines Sweeten Gas Easier. Hydrocarbon Processing (December): 65.
  20. Anerousis, J.P. and Whitman, S.K. 1985. Iron Sponge: Still a Top Option for Sour Gas Sweetening. Oil & Gas J (18 February): 71.
  21. Samuels, A. 1990. H2S Removal System Shows Promise Over Iron Sponge. Oil & Gas J (5 February): 44.
  22. Maddox, R.N. and Burns, M.D. 1968. Solids Processes for Gas Sweetening. Oil & Gas J (17 June): 90.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

International Association of Drilling Contractors

Occupational Safety & Health Administration

See also

Hydrogen sulfide (H2S) fields

Sour gas

Sour gas sweetening

PEH:Drilling_Problems_and_Solutions

PEH:Gas Treating and Processing

Gas Treating and Processing

Dehydration with deliquescing dessicants

Dehydration with glycol

Dehydration with refrigeration and hydrate suppression

Dry dessicant dehydration

Category