Extending the treatment of highly sour gases: cryogenic distillation

Cryogenic bulk removal of H2S or CO2 offers an economic advantage when the separated acid gases from super sour gas are re-injected


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Article Summary

Companies willing to produce large gas fields with very high amounts of CO2 have to face a constraint related to the essential need to reduce the atmospheric emissions of greenhouse gases.

The economics may also be improved by the growing acceptance of the re-injection of separated H2S and CO2, for reutilisation to enhance oil recovery. Separated acid gas re-injection into a depleted reservoir or an aquifer, as a feasible alternative to costly sulphur recovery to a diminishing sulphur market, or to limit atmospheric emissions of greenhouse gases, increases the number of highly sour gas fields that can be reconsidered as exploitable to produce much needed natural gas.1,2

These new constraints lead to the development of more energy efficient technologies for acid gas separation, adapted to these new production schemes. With this objective, in addition to the AdvAmine series of gas sweetening processes using amine based solvents and discussed in a preceding article (PTQ, Q4 2013), Total, IFP Energies nouvelles and Prosernat have developed the Sprex and SprexCO2 processes for the production of highly sour gas reserves with acid gas re-injection. This second article discusses the benefits of the Sprex and SprexCO2 processes.

Cryogenic distillation for the sweetening of super sour gases
Some gas fields contain very high amounts of H2S (more than 30 vol%) or CO2 (up to 70 vol%) in natural or associated gases. Even though amine processes can be optimised to treat very sour gases, the high cost associated with sweetening may make the production of these super sour gases uneconomic under certain gas price conditions.

Permeation membranes have been used commercially since the 1980s for the bulk removal of CO2 from gases with a very high CO2 content down to levered CO2 content generally between 5% and 10%. With the current status of this technology, permeation membranes can only be used to treat gases with very limited H2S content, as they are very sensitive to this chemical. Membrane units are relatively simple and use very little energy, however permeation membranes are not selective and one must accept large methane losses with the separated acid gases, even with dual-stage membrane units with inter-stage recompression. Provided that adequate preconditioning of the gas is performed, membrane life is considered as acceptable to limit the cost of replacement. However, the preconditioning unit is generally fairly large, which substantially increases the cost of the sweetening. The process further needs post-treatment with an amine solvent to reach tight CO2 specifications.

Cryogenic distillation processes offer many advantages when the separated acid gases need to be re-injected, to limit undesired sulphur production or to minimise greenhouse gases emissions to the atmosphere. They are very selective towards light hydrocarbons, and the separated acid gases (H2S and/or CO2) are recovered in the liquid state under pressure. Producing the acid gases as a high pressure liquid saves expensive and energy consuming compression requirements, because the pumping duty is much lower.

It is possible to produce 
pipeline quality gas with cryogenic distillation. Such technologies require dehydration of the sour gas prior to entering cryogenic separation. Separating CO2 or H2S down to a commercial specification requires a very low temperature in the reflux drum, corresponding to a very significant refrigeration requirement. Furthermore, CO2 separation down to commercial levels suffers from limitation due to CO2 freezing conditions in the top section of the cryogenic distillation column. Some processes address this limitation by adding, for example, a suitable hydrocarbon solvent to the top section of the demethaniser to stay outside the CO2 freezing conditions, or by using a column with a specific frozen CO2 remelting zone.

The Sprex and SprexCO2 processes, jointly developed by Total and IFP Energies nouvelles/Prosernat, are bulk fractionation processes. The Sprex process for bulk H2S removal does not require upstream dehydration of the gas. The refrigeration requirements of Sprex and SprexCO2 are limited compared to those of other cryogenic processes and, as the temperature in the SprexCO2 is not as low, the operating conditions are far away from the CO2 freezing region, therefore avoiding the need for an additive fractionation and recycle or for a remelting zone.

When pipeline or LNG specification is required, the Sprex or SprexCO2 unit is easily and economically combined with a solvent based acid gas removal unit.

Bulk H2S removal with the Sprex process
The Sprex process was jointly developed to improve the 
economics of the production of ultra sour gas with high H2S content when the separated H2S is re-injected. The process was improved and several other patents were filed in the 2000s.3 Figures 1 and 2 show the principles and process flow diagram of the staged acid gas separation from a very sour natural or associated gas using Sprex followed by a conventional solvent sweetening plant.
The process has the following advantages:2     
• It reduces the H2S content in the gas by producing a partially sweetened gas, which can then be processed by a smaller, conventional amine sweetening unit, capable of meeting the most severe H2S and CO2 gas specifications (pipeline gas or feed for a LNG plant)
• It produces a high pressure liquid H2S soup (50 to 65 bar) that can be easily re-injected into a geological reservoir.   

In this basic version of the process, which has been demonstrated in an industrial context at the Lacq plant,4 in the southwest of France (see Figure 3), the H2S content in the gas leaving the Sprex unit is about 10-12%. The reflux, consisting of cold, dry H2S, dehydrates to some extent the incoming gas in the upper zone of the Sprex column. The minimum temperature reached in the unit’s low temperature reflux drum is limited to about -30°C, so as to remain outside the hydrate zone at all points of the unit. This rules out the necessity of installing a dehydration unit upstream of the Sprex column.

The H2S separated out in the process is produced in a high 
pressure liquid phase, requiring considerable less energy for re-injection into an underground reservoir, as the large, multistage acid gas compressors can be replaced by injection pumps.

Now that the amine sweetening unit located downstream has less H2S to separate, the amine solvent circulation rate can be substantially decreased, as can the size of the equipment. This drastically reduces both the investment cost and energy consumption.
To illustrate the benefits of using the technology, the two schemes shown in Figure 4 have been compared: a reference case using an amine unit, a base case using Sprex for bulk removal and an amine unit as a finishing unit.

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