Highly Sour Gas Processing in a More Sustainable World

François Lallemand and Ari Minkkinen 10.1

Introduction

For decades to come, natural gas will be the energy source of choice to meet evergreener worldwide environmental standards. Fortunately, gas reserves are growing; but new gas is often found to be of substandard quality in remote and/or stranded areas of the world. When natural wellhead or oil field associated gases are highly loaded with acid gases, the dilemma facing most operators is what to do, how and when to best exploit these poor quality resources. Total is increasingly faced with these choices, together with its operating partners around the world; especially in areas known to have highly sour oil and gas reserves, such as the Caspian sea region.

Fortunately, Total, via past efforts of Elf Aquitaine, has many years of experience in producing gas from slightly sour to very sour gas reserves, notably in the Lacq region of France. This experience has been the ideal proving ground in the development of state-of-the-art acid gas removal technologies. Today the advanced activated MDEA process offers economy and versatility in handling both selective and complete acid gas removal services. The process has a good synergy with modern Claus sulfur recovery processes and remains among the best alternatives even when no sulfur recovery is foreseen.

Nevertheless, there are limitations of even the most advanced amines-only based gas treatment technologies in handling very highly acid gas loaded natural or associated oil field gases - especially for bulk acid gas removal when the acid gases are destined for cycling and/or disposal by re-injection.

Today, cycling and disposal by re-injection offers a promising alternative to avoid sulfur production and reduce CO2 emissions to the atmosphere simultaneously. To this end, technologies of choice are those that offer maximum simplicity and require least downstream processing intensity and power for re-injection.

450 | 10 Highly Sour Gas Processing in a More Sustainable World 10.1.1

Background

When Elf Aquitaine, years before becoming Total, decided in the mid-1950s to produce gas from the then discovered Lacq field in south west France several challenges were faced as it was the first highly sour, high pressure and high temperature gas field produced at that time. High performance had to be achieved to remove large quantity of acid gases from raw gases containing over 15% H2S and up to 10% CO2. In addition, new steel alloys had to be developed to resist the highly corrosive behavior of the fluids.

The technology first selected in the early days was the so-called SNPA-DEA process using exclusively the reactive chemical solvent diethanolamine (DEA). Much experience was gained while improving the process by nearly doubling the DEA solution concentration. This was done to reduce solvent circulation and operating costs while keeping corrosion under control without inhibitors. The continually improved processes were implemented in several sweetening units between 1957 and 1968, eventually attaining a sales gas production capacity of 25 million standard cubic meters per day (880 MMSCFD).

With the decline in production of the Lacq field and with constantly increasing energy costs, the need for new processes, better suited than DEA to a new competitive gas market environment, became apparent. Fortunately, existing units and equipment made available by the reduction of Lacq gas production conveniently opened the way to conversion, remodeling and testing on the industrial scale new solvent formulations, absorber internals and processing techniques. The new processes then developed were based on the use of tertiary-methyldiethanolamine (MDEA) and a flash-procured rich amine regeneration system. This significantly reduced the energy consumption of the amine reboilers.

Since 1977 MDEA has been used by Elf Aquitaine for de-acidification of gases that do not require total CO2 removal. The possibilities offered by the MDEA process to control the CO2 slippage from the absorber by proper choice of absorber internals and operating conditions make it suitable for many different applications, allowing tailored amounts of CO2 in the product gas while making H2S-richer acid gas for Claus sulfur recovery units. Since 1986, an MDEA process has been used at Lacq to remove H2S from raw high-pressure sour gas streams to produce H2S-rich streams used for thio-organic chemical synthesis. The MDEA process for selective H2S removal has been implemented in more than 20 units worldwide, either operated by the Total group or other operating companies under license. The need to respond also to the requirement of total acid gas removal, to be able to produce product gas with less than 50 ppm CO2, subsequently led to the development of an activated MDEA process having the removal performance of DEA with significantly reduced energy consumption. Today a series of chemical activators used with MDEA in a split semiregenerative process scheme offers the most cost-effective answer to complete or controlled acid gas removal from sour to very sour natural gases.

Total has also long been interested in the bulk removal of acid gases; notably, in gas fields operated in the Far East, containing over 40% CO2, as well as in the Caspian sea

10.2 Use of Activated MDEA for Acid Gas Removal | 451

region, for gas and oil-associated gases containing over 20% H2S with CO2. Recognizing that the world sulfur market today is saturated and CO2 emissions as a greenhouse gas need to be drastically curtailed, has led to serious consideration of acid gas cycling and/or disposal by re-injection. To this end, technologies other than the classical aqueous amine based ones are expected to have more favorable attributes. Some of these attributes are the delivery of acid gases in a dry state and at higher pressures to reduce recompression power, facilitate re-injection system design and avoid exotic materials.

Finally, Total in collaboration with IFP has embarked upon a comprehensive program with a pooling of resources to develop new gas treatment technologies to better suit the bulk acid gas removal destined for re-injection applications. To this end, pre-treatment techniques and hybrid solvent processes are envisioned as the most cost-effective overall solutions.

10.2

Use of Activated MDEA for Acid Gas Removal

When the MDEA process was developed in the mid-1970s it was principally destined for the sweetening of gases that did not require complete CO2 removal [1], or required the removal of only a controlled part of the CO2. Typical applications of the selective MDEA process are:

• H2S removal from gases already at or close to the allowable CO2 specification;

• H2S removal from gases where the CO2 is not important; as in fuel gas, for example;

• production of an H2S-rich (i.e., CO2 poor) acid gas for Claus type sulfur recovery and or thio-chemical synthesis.

The use of MDEA for selective H2S removal is based on the fact that, unlike DEA, MDEA does not react directly with CO2, and thus CO2 absorption kinetics can be controlled by the slow reaction of CO2 with water. For complete CO2 removal along with H2S, the more reactive DEA has traditionally been used but with a serious energy consumption handicap in its regeneration step. The ever tighter constraints imposed on gas processing, stemming mainly from the necessity to reduce operating costs, led to the development of a new MDEA process for complete acid gases removal from sour gases with a substantially lower regeneration energy consumption than conventional DEA.

Two main factors affecting a solvent's performance for CO2 absorption and its ease of regeneration are solubility and reactivity. While reactivity of CO2 in MDEA is lower than in DEA, its solubility in MDEA is more strongly influenced by CO2 partial pressure than its solubility in DEA. This can be shown by the slopes of the equilibrium solubility curves (Figure 10.1).

The basic concept for a new process was then to take advantage of the slope of the equilibrium solubility curves of CO2 in aqueous MDEA solutions to be able to liberate a maximum amount of the acid gas from the solution by simple physical

Equilibrium Solubility H2s Selexol
Figure 10.1 Equilibrium solubility of CO2 in aqueous amines.

pressure let-down flash and thus reduce the thermal regeneration duty substantially. For example, as shown in Figure 10.1, the MDEA solution releases almost twice as much CO2 as the DEA solution by a pressure letdown from 10 bar to 2 bar. In addition, the equilibrium solubility of H2S in aqueous MDEA exhibits identical behavior to CO2, allowing equivalent amount of H2S liberation by pressure letdown. Unfortunately, unlike with H2S, MDEA reacts slowly with CO2. This in particular, which is used to advantage for selective H2S and controlled CO2 removal, becomes a handicap for complete acid gas removal - especially when a substantial quantity of CO2 has to be removed. To overcome this kinetic obstacle, activators were sought among secondary amines having high speeds of reaction with CO2 to blend into the otherwise desirable MDEA solvent. Figure 10.2 illustrates the reaction mechanism postulated.

With MDEA alone the transformation of CO2 into bicarbonate is a slow process while the reaction of the carbonic acid with MDEA is instantaneous. With an activator in the MDEA solution the transformation into bicarbonate via a first step formation of

Mdea And Co2

Bicarbonate of MDEA + Activator

Figure 10.2 Mechanism of CO2 activation.

Bicarbonate of MDEA + Activator

Figure 10.2 Mechanism of CO2 activation.

10.2 Use of Activated MDEA for Acid Gas Removal I 453

Treated gas

10.2 Use of Activated MDEA for Acid Gas Removal I 453

Treated gas

Mdea Gas Sweetening

a carbamate is made faster. Laboratory tests were performed to select amines with carbamate formation rates that could substantially activate the CO2-MDEA reaction and to determine the concentrations required to optimize solvent efficiency. Several activators were selected from among those best suited to industrial conditions, taking into account commercial availability, cost and impact on the environment [2].

Another process improvement over the conventional DEA process is the introduction of a secondary semi-lean solvent circulation, as shown in the simplified process flow diagram in Figure 10.3. The rich amine solution after letdown through a hydraulic turbine is divested of co-absorbed light hydrocarbons in a first flash drum, as in the conventional process, then further expanded to a low pressure in a second flash drum to partially liberate CO2 and H2S. The greater part of the rich amine thus partially regenerated is returned to an intermediate level of the absorber as a semi-lean solvent. This second solvent loop is particularly economic as it reduces the thermal regenerator load and consumes only pumping energy.

When H2S is present and the treated gas specification calls for the removal of H2S below 3.0 ppm, or for the removal of CO2 below the 1-2vol.% range, thoroughly regenerated, virtually H2S- and CO2-free, amine is required. This is accomplished in a conventional thermal regenerator by returning a small flow ofthe leanest amine to the top section of the absorber.

In 1990 the new solvent and regeneration system were tested on an existing DEA unit at Lacq, which was then converted into the then-called Elf Activated MDEA process [3,4]. This process was also used in several other locations offshore North Sea such as in Sleipner Vest for CO2 removal and Elgin Franklin for controlled CO2 removal. Different activators have been selected and patented to suit each specific case of treatment; total or partial, controlled CO2 removal with or without H2S.

454 | 10 Highly Sour Gas Processing in a More Sustainable World 10.3

Process Performance Highlights

The performance of the Elf Activated MDEA is closely related to site-specific treatment conditions, notably feed gas composition and treated gas specifications. Below are some practical rules-of-thumb to highlight the general interest of regeneration by flash [5]:

• The greater the H2S and/or CO2 partial pressure in the feed gas, the greater is the efficiency of the flash. In the case of the Lacq plant, the acid gas partial pressure of the feed is approximately 15 bar in comparison to a total pressure of 2 bar in the flash drum. This gives a ratio of 7.5 (acid gas partial pressure/flash pressure). In general the advantage of flash starts above a ratio of 3.0.

• The overall energy consumption of the Activated MDEA unit increases as the treated gas specification becomes more stringent, since the amount oflean totally regenerated amine from the thermal regeneration increases. In some CO2-only cases, as mentioned above, it may even be possible to completely eliminate the thermal regenerator.

As a consequence of the above attributes the Elf Activated MDEA process will be well adapted to the treatment of high pressure and very sour gases where the advantages of flash procured regeneration will be maximized.

10.4

Case Study of the Use of Activated MDEA for Treatment of Very Sour Gas

A noteworthy case study of the use of the Activated MDEA process is given below for the treatment of very H2S sour gas. It concerns a real plant that was operated by Elfin the 1970s in Alberta Canada. The original design used a conventional 30 wt% DEA solution, which was considered the state-of-the-art at the time the plant was built. Table 10.1 gives the gas composition on a dry basis.

Table 10.1 Sour gas composition: an example.

Component

Volume %

H2S CO2

Methane

Ethane

Propane

Butanes

Pentanes plus

10.4 Case Study of the Use of Activated MDEA for Treatment of Very Sour Gas 455

2 absorbers

Treated gas Acid gas

Sour gas

Lean DEA

Semilean DEA

Fuel gas r a

2 regenerators

LP steam

Figure 10.4 Original amine sweetening units process flow-scheme (30wt% DEA).

The treated gas had to meet typical pipeline gas specifications, that is, less than 4 ppm vol. H2S and less than 2.0 vol.% CO2. The acid gas liberated is sent to conventional two-stage Claus units followed by a Sulfreen tail gas treating unit. Figure 10.4 illustrates the original amine sweetening units process flow-scheme. There are two identical trains, each equipped with two high-pressure absorbers and two regenerators.

The raw sour gas capacity of each train is 162 million std.ft3 per day (MMSCFD) or 4.6 million std.m3 per day for a sulfur production of over 2000 tons per day. The reboilers dutyfor each amine train was 135 MW (460 MMBtuh-1 or 116Gcalh~1), which is roughly equivalent to the heat energy produced by the downstream Claus unit as LP steam.

We have revised the original design to reflect current state-of-the-art amine technology, using 48 wt% activated MDEA solution while retaining the same process scheme using a conventional double split flow design with thermal regeneration. This results in a decreased amine solution circulation rate and thus reduced reboiler duty. The reboiler duty is reduced from 135 to 91 MW.

Figure 10.5 shows what would be the design of the amine units using the Elf Activated MDEA process with the addition of partial regeneration by flash. In this case only a third of the total amine solution circulation is sent to thermal regenerator. As a consequence the reboiler duty is reduced to only 46 MW. This uses only one-third of the Claus unit's steam production and only one regeneration column is needed for each train, resulting in additional capital cost savings potential. The quality of the treated gas is identical to the original design and the acid gas produced still has a very good quality, with a hydrocarbon content of less than 1.0 vol.%. The latter specification is important for charging a Claus unit, but is equally important for acid gas cycling and/or re-injection, as will be discussed below. Table 10.2 summarizes the stepwise improvements achieved.

Process Improvement Table
Table 10.2 Stepwise improvements achieved using the Elf Activated MDEA process.

Solvent

Process

Reboil energy consumption

[MW (MMbtu h-1)]

30 wt% DEA

Original

135 (460)

48 wt% Act. MDEA

Thermal regeneration

91 (310)

48 wt% Act. MDEA

Flash procured regeneration

Acid Gas Removal for Cycling and/or Disposal

Environmental concern over global warming due to greenhouse gas emissions has given ever rising importance to the re-injection of CO2 removed from natural gases; either for reutilization to enhance oil recovery (EOR) or just simple disposal to a depleted reservoir to avoid atmospheric venting. Moreover, with the growing acceptance of H2S re-injection as a feasible alternative to costly sulfur recovery to a diminishing sulfur market, several very sour gas wells can be re-considered as exploitable to produce much needed natural gas. Many of such wells have been blocked-in, waiting either for the gas price increase to justify costly production or a simplification of the overall processing scheme to reduce production costs. Though gas prices today have increased, who knows for how long the present price situation will prevail. In any case, acid gas re-injection to a disposal reservoir will provide the simplification and cost reduction to make exploitation of the sour gas reserves attractive even in a flat gas price scenario. Since H2S and CO2 are re-injected

10.5 Acid Gas Removal for Cycling and/or Disposal j 457

underground, back to where they originated from, no CO2 or sulfur emissions are made to the atmosphere.

Acid gas removal from the desired marketable hydrocarbons is the first step in the sour gas production scheme. Many acid gas removal processes are available to meet current pipeline sales gas-specifications in H2S and CO2 content. However, for maximum versatility and economic benefit to an acid gas removal to re-injection or disposal project, the overall process scheme should have quality characteristics, among which are:

• high capacity for acid gas removal with minimum hydrocarbon co-absorption;

• easy regeneration by pressure letdown with minimal thermal input as co-produced heat energy of the Claus unit is no longer available;

• liberation of acid gases at some pressure and preferably cold and dry;

• possibility to adapt regeneration pressures to inter-stage acid gas compression.

Physical solvent processes give some, but not all, ofthe above qualities. The Selexol process has several industrial applications, most of them for synthesis gas de-acidification and some for natural gas treatment [6-8]. A methanol-based refrigerated solvent process such as the Ifpex-2 process from the Ifpexol technology matrix of IFP is also a good contender [9]. However, physical solvents have a high affinity for hydrocarbons and the separated acid gas stream contains large quantities ofvaluable hydrocarbon products.

Chemical solvent processes generally have a higher energy requirement than physical solvent processes, but do not absorb hydrocarbons. However, among these processes, the Activated MDEA process from Total discussed in the preceding sections, which removes H2S completely and CO2 as required, has a low energy requirement, thanks to the ability ofthe Activated MDEA to liberate the bulk ofthe acid gases in a simple flash (flash procured regeneration). With the exception of acid gas dryness and pressure, the Elf Activated MDEA process meets all ofthe above listed quality characteristics for a re-injection scheme; most remarkably the liberation of acid gases without hydrocarbons. This is important not only to reduce sales gas shrinkage but also to reduce re-compression flowing capacity. The very low hydrocarbon content ofthe acid gas produced by the Activated MDEA process is another factor impacting positively on the wellhead pressure requirements as the hydrocarbons present reduce the density and water solubility ofthe pressurized acid gas fluids. The only disadvantage ofthe Activated MDEA process is the liberation ofthe acid gases at low pressure.

Hybrid solvent processes use a mixture of a physical solvent with a chemical solvent and combine some ofthe advantages of physical solvent processes with those of chemical solvent processes. The Sulfinol process has numerous industrial applications in sour gas de-acidification. Its energy requirement is relatively low, but hydrocarbon co-absorption is higher than that of an amine process.

The cost of acid gas removal depends strongly on its concentration and the need for downstream compression. In the case of very sour gas the combination of a bulk removal step ahead of the final sweetening unit can reduce the overall acid gas removal cost. If the acid gas is re-injected the bulk removal process should offer the possibility of pre-extracting and/or recovering acid gas in the liquid phase and at high pressure for pumping to re-injection pressure.

Here we examine the combination of the well-established Elf Activated MDEA process from Total with a new pre-extraction technique under development by IFP.

10.6

Bulk H2S Removal for Disposal

The proposed overall process flow-scheme for the treatment of very sour gases (i.e., with an acid gas content above 20%) with re-injection of the separated acid gases to a disposal reservoir incorporates a special patented H2S pre-extraction step upstream of the Activated MDEA acid gas removal process. In this upstream step [10], called SPREX, a substantial amount of the H2S and some of the CO2 are pre-removed from the wet raw gas as a pumpable liquid stream. This liquid will essentially contain by solubility all the water of saturation that comes with the inlet raw gas. It will also contain some of the incoming hydrocarbons. Figure 10.6 depicts a process flow diagram of this special pre-extraction and Activated MDEA combination process.

The dried gas leaving the SPREX contactor is cooled through a gas/gas heat exchange, gas/condensate heat exchange and then through a refrigerated chiller before being passed to a low temperature separation (LTS) drum operating essentially at line pressure. Since the SPREX liquid removed most of the water from the feed gas by solubility, no further free water condensation is expected in the chilling train. However, in practice some hard-piped methanol injection would be incorporated in case upset trace free water might appear. No methanol recovery is warranted due to the negligible amount of, and only intermittent injection of, methanol, if any. Any

H2s Partial Pressure Temperature
Figure 10.6 Basic scheme of H2S removal to disposal process.

injected methanol is thus considered lost. The refrigerated chiller may be replaced by any other refrigeration process, such as a turbo-expander, if the inlet fluid is available at sufficient pressure.

The separated liquid stream is pumped through a heat exchanger and warmed before being recycled to the SPREX contactor. The H2S-rich recycle contains dissolved hydrocarbons, which are then stripped from the liquid in contact with ambient temperature feed gas. Owing to the equilibrium recycle, the H2S partial pressure is substantially increased in the contactor, allowing a good portion of the incoming H2S to condense and drop out in its bottom section. The H2S-rich mixed liquid stream or "soup" at line pressure and near ambient temperature, containing also pre-extracted CO2, some of the hydrocarbons from the inlet gas together with soluble water and any methanol injected, is taken to the suction of the disposal pump shown. Pumping liquid is more energy efficient than compressing vapor to reinjection pressure.

The gas stream exiting the LTS with the remaining acid gas is warmed through gas/gas heat exchange and is then taken to the absorber of the MDEA unit. The MDEA unit is designed using the Elf Activated MDEA process. The selection of an activator or none will depend upon the amount of CO2 to be allowed to slip into the pipeline gas. In this case, CO2 removal can be selective with savings on solvent loading and regeneration duty. When the remaining acid gas loads are still significant, the partial flash regeneration may be advantageously used to reduce solvent circulation and reboil duty as described and illustrated in the previous section with Figure 10.3.

The treated gas leaving the MDEA unit will require downstream dehydration since the pipeline gas specifications require a minimum water dew point. This is best achieved with a conventional TEG glycol dehydration unit, as the gas is very lean without condensable hydrocarbons.

10.7

SPREX Performance

Acid gas extraction performance of the SPREX process is dependant on the inlet fluid composition and on the temperature in the LTS. The higher the acid gas content of the inlet gas, or the lower the temperature in the LTS, the higher the pre-extraction performance (Figure 10.7).

Hydrocarbon co-extraction will increase with the acid gas pre-extraction efficiency. For the bulk removal of acid gas from very sour gases, where very high acid gas pre-extraction is achieved, more sophisticated process schemes are being evaluated to maintain hydrocarbon co-extraction at a low and acceptable level. It is envisaged that the hydrocarbon shrinkage can be maintained below 3% in all cases, even when treating gases with a very high H2S content.

For a LTS temperature of—30 °C, an H2S pre-extraction of more than 70% maybe achieved from a gas with 35% H2S. The CO2 pre-extraction performance of the SPREX process is somewhat lower than that of H2S.

Temperature at LTS, °C Figure 10.7 SPREX process: H2S extraction performance.

10.8

Capital Cost and Energy Balance Comparison

The SPREX "soup" is available at line pressure and in the liquid phase, thus considerably reducing the power consumption for re-injecting the acid gas. Since the MDEA process for the remaining acid gas removal is now substantially reduced in its acid gas removal load, its solvent circulation, equipment sizes and investment cost are correspondingly reduced. Table 10.3 summarizes the capital cost and energy savings achieved when using the SPREX process in the Canadian case already described above, assuming that the separated acid gases are re-injected with a wellhead injection pressure of 150 bar (2140 psig). The figures given in Table 10.3 concern the following processing units: de-acidification, acid gas compression and pumping, associated utilities generation, and are exclusive of field costs.

Table 10.3 CAPEX and energy comparisons of the SPREX process.

Without Sprex With Sprex

Table 10.3 CAPEX and energy comparisons of the SPREX process.

Without Sprex With Sprex

CAPEX (base 100 for conventional treatment)

Sprex unit

0

23

MDEA + AG compression + utilities generation

100

57

Total processing units

100

80

Energy consumption (MW)

Power (pumps and compressors drivers)

52

29

Thermal energy (LP steam)

46

34

Highly sour gas processing is becoming evermore commonplace as the world's appetite for clean burning gas energy is growing and sweet gas reserves are dwindling. Technologies to treat sour natural gas to make it pipeline quality are numerous, but none have shown to be as versatile and economic as those using Activated MDEA.

To be truly competitive, the removal of the acid gas components H2S and CO2, be it trim or bulk, complete or partial, requires the optimum choice of an activator together with a carefully crafted know-how in solvent absorption/regeneration process design. The Elf Activated MDEA process developed by Total is probably the most cost-effective solution today to meet the widest range of applications from complete CO2 removal to bulk H2S and/or CO2 removal even for acid gas re-injection projects. The historical R&D efforts of Elf Aquitaine coupled with current resources of Total allows this MDEA process to be credited with the most significant know-how back-up technology base on the market today.

To further meet forthcoming challenges in an ever-greener world, acid gas reinjection for disposal has become an important technology, especially in regard to abatement of greenhouse gas and sulfur emissions. Moreover, today's diminishing sulfur market no longer justifies Claus-type sulfur recovery. To this end, Total and IFP have been collaborating on the development of new and less costly technologies to handle highly H2S sour gases, especially those intended for bulk acid gas disposal projects.

The upstream acid gas pre-extraction technique from IFP, called SPREX, offers a synergistic combination with the Elf Activated MDEA process in most applications for bulk H2S rich acid gas disposal projects. The substantial reduction of the acid gas removal and re-compression loads afforded by the SPREX step coupled with energy efficient flash procured Activated MDEA process achieves sour gas purification with bulk acid gas disposal very cost-effectively.

References

1 Blanc, C., Elgue, J. and Lallemand, F. (1981) MDEA process selects H2S. Hydrocarb. Process, 60 (8), 111.

2 Elgue, J., Peytavy, J.L. and Tournier-Lasserve, J. (1991) Recent industrial developments in natural gas sweetening by MDEA. Paper presented at the 18th World Gas Conference, Berlin.

3 Elgue, J. and Lallemand, F. (1996) MDEA based solvents used at the Lacq processing plant. Paper presented at the Gas

Processors Association European Chapter Meeting, London, January 18.

4 Elf Activated MDEA (1994) An important improvement in natural gas sweetening processes. 19th World Gas Conference, Milan.

5 Elgue, J., Peytavy, J.L. and Lallemand, F. (1995) The Elf Activated MDEA process: new developments and industrial results. Paper presented at the International Gas Research Conference, Cannes, 1995.

6 Johnson, J.E. and Homme, A.C. (1984) Selexol solvent process reduces lean, high-CO2 natural gas treating costs. Energy Prog., 4 (4).

7 Shah, V.A. and Huurdeman, T.L. (1990) Synthesis gas treating with physical solvent process using Selexol process technology. Ammonia Plant Safety, AIChE, 86, 279.

8 Epps, R. (1996) Selective absorption of H2S and removal of CO2 using Selexol solvent. Paper presented at the January 1996 GPA session, London, England.

9 Minkkinen, A., Rojey, A. Charron, Y. and Lebas, E. (1998) Technological developments in sour gas processing, Les Entretiens IFP, Rueil-Malmaison, France, May 14.

10 Minkkinen, A., Benayoun, D. and Barthel, Y. (1996) U.S. Patent 5,520,249, May 28.

11 Rojey, A., Lebas, E., Larue, J. and Minkkinen, A. (1998) U.S. Patent 5,782,958, July 21.

12 Minkkinen, A. and Jonchere, J.P. (1997) Methanol simplifies gas processing. Paper presented at the 76th Annual Convention of the Gas Processors Association, San Antonio, Texas, March 11.

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