Physical solvents such as DEPG (Selexol^™ or Coastal AGR^®), NMP or N-Methyl-2- Pyrrolidone (Purisol^®), Methanol (Rectisol^®), and Propylene Carbonate (Fluor Solvent^™) are becoming increasingly popular as gas treating solvents, especially for coal gasification applications. Physical solvents tend to be favored over chemical solvents when the concentration of acid gases or other impurities is very high. In addition, physical solvents can usually be stripped of impurities by reducing the pressure without the addition of heat. This paper compares the acid gas removal ability, required equipment, and power requirements for the four physical solvents DEPG, Methanol, NMP, and Propylene Carbonate.

In amine sweetening units, the heat of absorption and VOC and BTEX solubility have been found to vary significantly with acid gas loading as well as with temperature, amine type, and amine concentration. The heat of absorption declines by up to 20% while VOC and BTEX solubility can drop by as much as 40 to 50% with loadings up to 0.5 mol/mol for MDEA solutions. VOC and BTEX solubility are also highly dependent on temperature and amine concentration. As a result, amine sweetening units should be operated at the lowest circulation rate possible as limited by corrosion and treating requirements. For example, over circulation of 100 gpm in amine sweetening units can cost about $250,000/yr in additional reboiler fuel, can greatly increase pick up of VOC and BTEX, and lead to problems with emissions or in downstream sulfur recovery units.

Environmental regulations controlling the amount of H2S emissions require the Aquila Navasota Gas Plant to treat the acid gas from the main amine-treating unit to meet standard specifications. Originally, a batch process was installed to remove a portion of the H2S, bypassing the remaining gas, to meet the specifications. Operating cost of this batch process increased as the H2S content increased and became excessive. This required Aquila to investigate alternative processes. Process evaluations were requested from several sources and a large variance in unit designs was found. Due to the unique nature of the feed gas, 96+% CO2 and < 1000 ppm H2S at 10 psig, conventional design technology for amines required a higher circulation rate and excessive CO2 absorption. Since the recovered H2S would be sent to a flare, fuel consumption would be higher with the excess CO2. One design, provided by Huntsman Corporation, was found to offer the lowest capital investment along with lower operating cost. This design utilized specific design parameters in the absorber that allowed the circulation rate to be less than one-third of the other designs. Unit operating parameters will be reviewed and have been within original estimates. Design also allows for a wide range of operating conditions without much change in treated specifications. Design and operating characteristics will be reviewed.

This paper compares the solubility of hydrocarbons in several physical solvents such as ethylene glycol, diethylene glycol, triethylene glycol, methanol, and dimethyl ethers of polyethylene glycol (DEPG, a solvent marketed by Union Carbide, UOP, and Coastal). Most of these solvents are designed to extract unwanted components such as water and acid gases. However, these solvents also have a tendency to remove the hydrocarbon product. Quantifying this amount of absorption is critical in order to minimize hydrocarbon losses or to optimize hydrocarbon recovery depending on the objective of the process. The influence of several parameters on hydrocarbon solubility including temperature, pressure and solvent water content is examined. Suggested operating parameters to achieve hydrocarbon absorption objectives are included. Hydrocarbon solubility is a major factor when considering the use of a physical solvent.

There are many possible process variations for sweetening sour hydrocarbons with amines. Those to which we have given attention include the use of precontactors (static or jet eductor mixers), multiple absorber inlet nozzles, split flow units and pressure swing regeneration. Each of these variations is best suited to a certain set of operating conditions. Not all processes are appropriate for use with certain feed compositions or product requirements. This paper will discuss the application of the various flow scheme alternatives to a variety of different process conditions.

Gas treating process variables such as solvent type and concentration, pressure, and circulation can be manipulated to produce specification quality hydrocarbon products. Interest has increased recently in exploring the effects of inlet gas and solvent temperatures as an aid in meeting these specifications. In general, lower temperatures tend to promote absorption of lower molecular weight components based on vapor-liquid equilibrium.

Physical solvents exploit this principle by absorbing acid gases and water at lower temperatures. If the absorption process is reactive and allowed to reach equilibrium, lower temperatures still favor the absorption of low molecular weight components.

However, if the reactive absorption is kinetically limited as is the case with CO2 and certain amines, it is impossible to determine how temperature affects the absorption in the absence of additional information. This ambiguity results from the competing phenomena and opposite effect temperature has on reaction rates and solubility. For absorption of H2S and CO2 in alkanolamines or mixtures of amines with physical solvents, H2S absorption reaches equilibrium conditions while CO2 absorption is kinetically limited in some situations. The performance of various amines and physical solvents are compared based on solvent and feed gas temperatures. Understanding the competing phenomena of equilibrium and kinetics may yield situations where this effect can be exploited for more profitable operation.

Amine solutions are often used to treat LPG streams that contain acid gases. In this work, the selection of an amine and the method of contacting the amine with a 50gpm [189 lpm] LPG stream containing 7.7 mol% as CO2 are evaluated. A packed contactor is compared to a static mixer and MEA, DEA, and MDEA are compared as potential solvents. A static mixer using 70 gpm [265 lpm] of 25 wt.% DEA is chosen for the final design. The operating data reveal 0.10 mol% CO2 in the sweet LPG compared to the design value of 0.16 mol%.

Due to the addition of new wells, the feed to Ferguson Burleson County Gas Gathering System (FB) Anderson gas treating plant was scheduled to increase from 180 MMSCFD to a design capacity of 210 MMSCFD. The feed gas contained both CO2 (6.0 mol %) and H2S (25 ppm) at high pressure (980 psig). A feasibility study determined that a cost effective method to handle the additional gas volume was to switch from a single amine to an amine mixture and to add static mixers to treat a bypass stream for H2S. The primary amine contactors would perform bulk removal of the acid gases from the main stream. Although increased treating capacity was the ultimate goal, a secondary concern was that corrosion be kept to within acceptable limits. To be certain this concern was adequately addressed, all of the heat exchangers within the system were rated and heat fluxes were investigated for possible problem areas. Several different amine mixtures were also evaluated with an eye toward potential corrosion limitations. This paper discusses the modifications made to the system and the results of subsequent plant trials to determine the overall capacity increase.

The removal of trace components from a gas by absorption using a chemical solvent is of importance to the gas processing industry. There is a growing interest in reaching lower outlet concentrations for reasons of health and safety; however, this requires very high energy use for solvent regeneration. Instead, solid-adsorption-based processes are often used as a secondary treatment step. We have developed new processes for liquid absorption that exploit better understanding of the thermodynamics of chemisorption processes in mixed solvent systems. The new processes use any conventional solvent and incorporate recycles between the absorber and stripper, by means of which the thermodynamic and process conditions for stripping are optimized to reduce the process heat requirement at high separation efficiency. Using these new processes it is possible to reach sub-ppm concentrations of acid gas with considerable savings in energy costs and without requiring use of solid sorbents. The new technology is based on conventional vapor-liquid contacting equipment and is suitable for retrofit to existing plant.

Mixing amines can be the best method for increasing capacity or improving efficiency in an amine sweetening unit. In many cases, it may be possible simply to add a second amine to the existing solution "on the fly", or as the unit is running.

The dramatic increase in the use of selective amines for gas sweetening has resulted from the inherent economic benefits including smaller equipment sizes, lower circulation rates, and higher overall amine concentration. Selective amines absorb H2S in the presence of CO2, either from thermodynamic solubility or kinetic effects. Mixtures containing selective amines can be formulated to allow a certain amount of CO2 to remain in the processed gas. Units designed with selective amines often have little margin for error with respect to plant capacity. Unfortunately, increases in the acid gas concentration or increases in throughput exceeding design can result in sweet gas which does not meet the CO2 specification. Since adding additional equipment can be very expensive, variables such as increasing the amine concentration, using mixtures of amines, and varying the lean amine temperature affect amine sweetening were studied. These variables require little or no additional capital expenditure relative to other alternatives such as adding reboiler area or pumping capacity.

Following these guidelines will ensure a well-designed and efficient plant.

This paper is an update from the original in: Energy Progress September 1984: 146-150. The selection of an amine for gas sweetening is complex and must be based on several process considerations. These factors are analyzed based on experimental data and a process simulation program for gas sweetening called TSWEET.

The effects of ammonia in the feed to amine sweetening units has been investigated using a process simulation program called TSWEET®. In the cases studied, MEA and MDEA were used to treat gases contaminated with up to 0.3% ammonia. The MEA units studied were 1100 psi gas contactors sweetening 0.25 to 4% H2S and 0.25 to 2.5% CO2. The MDEA units were 300 and 20 psi units treating high CO2 streams in a selective manner. Small amounts of ammonia can cause serious problems in some amine sweetening units. These problems are usually traceable to a complex of ammonia with CO2 in the stripper. When large amounts of CO2 are present, this complex may cause a build up of CO2 and ammonia in the circulating amine. In MEA, ammonia tends to push CO2 into the reboiler, increasing the CO2 residuals and ammonia in the lean amine. In MDEA, the ammonia appears to help drive CO2 overhead, decreasing CO2 and increasing the H2S in the stripper bottoms.

The use of amine mixtures employing methyldiethanolamine (MDEA), monoethanolamine (MEA), and diethanolamine (DEA) have been investigated for a variety of cases using a process simulation program called TSWEET . The results show that, at high pressures, amine mixtures have little or no advantage in the cases studied. As the pressure is lowered, it becomes more difficult for MDEA to meet residual gas requirements and mixtures can usually improve plant performance.

The use of MDEA and mixtures of amines for bulk CO2 removal was explored using three case studies. A process simulation program called TSWEET was used to study the effect of the amine used and the major operating parameters on the performance of MDEA solutions for bulk CO2 removal. The results showed that MDEA can be used quite advantageously for bulk CO2 removal and that the performance is often very sensitive to one or more of the operating parameters: liquid residence time on the trays, circulation rate and lean amine temperature. A good parametric analysis of the operating parameters should be performed in every case.

Operating data were collected from the Signalta gas sweetening plant. The plant has had an interesting variety of feed gas and operating conditions. The design and operation of the facility for CO2 slippage are discussed.

As more LPG's (liquefied petroleum gas) are being produced, the demand for liquid hydrocarbon sweetening facilities has increased. The most common contaminants in LPG's are CO2, H2S, mercaptans, COS, CS2, and elemental sulfur. Each of these contaminants can cause problems in the finished products.

Canada's first plant conversion from DEA to MDEA is a success. Dome's North Caroline amine plant performs very smoothly after being debottlenecked to, at least, original design capacity. Performance data taken for the absorber at several amine flow rates compare with safe accuracy to values calculated by the TSWEET program that was used as the basis for conversion.

Currently, the most common method to analyze for acid gases in amine solutions is by wet chemistry titration which is both tedious and time consuming. A simple gas chromatographic method now exists which is accurate and performs one analysis within eight minutes.

A version of this paper ("How to Reduce Costs in Amine Sweetening Units")also appeared in: Chemical Engineering Progress March 1983: 63-67. The design capability for gas-sweetening units has improved greatly. The selection of an efficient alternative flowsheet minimizes capital and operating costs.

The selective removal of H2S from gas streams containing CO2 has become of widespread interest as a means to reduce equipment sizes and operating cost. A selective absorption design capability has been added to the amine sweetening process simulation program, TSWEET. The program results agreed closely with selective absorption data using MEA at contact times of about 0.4 seconds. The program calculations also agreed with a 40% CO2 rejection measured in a DEA absorber operating at 11 psig and 2 seconds residence time per tray. A 6-ft diameter absorber using 15 wt% MDEA was also used for comparison. The calculated H2S in the sweet gas was well within the scatter of the data while the calculated CO2 rejection was about 10% high. The process simulation program accurately represents the selective absorption process including the influence of all process variables.

Large volumes of natural gas are produced throughout this country and Canada for the purpose of heating homes, producing electricity and generating heat for a wide variety of industries. As it comes from the ground, much of the gas produced contains quantities of acid gases, notably H2S and CO2. The carbon dioxide is of little consequence for the most part, but H2S is quite toxic and virtually all of this gas must be removed before the gas can be sent to commerical pipeline.