Sour gas sweetening
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
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:
- 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. 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.
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. 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. 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. 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.
 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:
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.
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. 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.
 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.
This secondary amine is not used by itself as a sweetening solvent but is part of the Sulfinol solvent formulation.
TEA is not in general use for gas sweetening.
 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.
Hot potassium carbonate (K2CO3) (Hot Pot)
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.
The specific gravity of the amine solutions is shown in Fig. 2. The specific gravity of potassium carbonate may be approximated by 1 + weight fraction K2CO3 in solution.
Fig. 2—Specific gravity of aqueous armine solutions (after Engineering Data Book of Gas Processors Suppliers and Gas Processors Association).
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:
- 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
Solution foaming occurs when gas is mechanically entrained in liquid as bubbles. 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 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: 
- 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.
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:
- 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:
- 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
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.
The Selexol 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 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.
The Purisol 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 Shell Sulfinol 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:
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. 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. 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 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 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 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.”
|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, %|
- Smith, R.S. 1975. Improve Economics of Acid-Gas Treatment. Oil & Gas J 73(March): 78-79.
- Tennyson, R.N. and Schaaf, R.P. 1977. Guidelines Can Help Choose Proper Process for Gas-Treating Plants. Oil & Gas J 75 (2): 78.
- King, J.C. et al. 1986. Rigorous Screening Selects Sour-Gas Plant Process. Oil & Gas J 84 (36): 101-110.
- Butwell, K.F., Kubek, D.J., and Sigmund, P.W. 1982. Alkanolamine Treating. Hydrocarbon Processing (March): 108.
- Fitzgerald, K.J. and Richardson, J.A. 1966. New Correlations Enhance Value of Monoethanolamine Process. Oil & Gas J 64 (43): 110-118.
- Freireich, E. and Tennyson, R.N. 1976. Process Improves Acid Gas Removal, Trims Costs, and Reduces Effluents. Oil & Gas J 74 (34): 130-132.
- Love, D. 1972. Quick Design Charts For Diethanolamine Plants. Oil & Gas J 70 (January): 88.
- Goar, B.G. 1980. Selective Gas Treating Produces Better Claus Feeds. Oil & Gas J 78 (18): 239-242.
- Maddox, R.N. 1967. Hot Carbonate—Another Possibility. Oil & Gas J (October): 167-173.
- Dehydration. 1998. In GPSA Engineering Data Book, 11th edition, Sec. 19, 20, and 21. Tulsa, Oklahoma: Gas Processors Suppliers Association.
- 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.
- Pauley, C.R., Hashemi, R., and Caothien, S. 1989. Ways to Control Amine Unit Foaming Offered. Oil & Gas J 87 (50): 67-75.
- DuPart, M.S., Bacon, T.R., and Edwards, D.J. 1963. Understanding Corrosion in Alkanolamine Gas Treating Plants, Part 1. Hydrocarbon Processing (April): 80.
- Kutsher, G.S., Smith, G.A., and Greene, P.A. 1967. NOW—Sour-Gas Scrubbing by the Solvent Process. Oil & Gas J (March): 116.
- Buckingham, P.A. 1964. Fluor Solvent Process Plants: How They Are Working. Hydrocarbon Processing (April): 113.
- Purisol. 2000. Hydrocarbon Processing (April) 84.
- Goar, B.G. 1969. Sulfinol Process Has Several Key Advantages. Oil & Gas J (30 June): 117.
- 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.
- Dillon, E.T. 1991. Triazines Sweeten Gas Easier. Hydrocarbon Processing (December): 65.
- Anerousis, J.P. and Whitman, S.K. 1985. Iron Sponge: Still a Top Option for Sour Gas Sweetening. Oil & Gas J (18 February): 71.
- Samuels, A. 1990. H2S Removal System Shows Promise Over Iron Sponge. Oil & Gas J (5 February): 44.
- 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
Sour gas sweetening