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Select optimal schemes for gas processing plants

01.01.2012  |  Khorsand Movaghar, M. ,  Energy Industries Engineering and Design Consultant Company (EIED), Tehran, IranMaleki, M. ,  Energy Industries Engineering and Design Consultant Company (EIED), Tehran, Iran

With careful analysis, meet product requirements and environmental standards

Keywords: [gas processing] [engineering and design] [sulfur recovery] [CO2 removal]

Gas processing plants are an essential part of the energy industry and provide one of the cleanest-burning fuels and a valuable chemical feedstock. The importance and complexity of gas processing plants have increased over the years due to their use as a feedstock source and their integration with petrochemical plants.

Important factors that drive the process selection and design of gas processing plants are environmental and safety regulations, capital and operating costs, and process efficiency. Therefore, selecting an optimized process scheme during the project feasibility study is vital to ensure that the project is technically feasible, cost-effective and profitable.


The process selection study usually begins with a design basis to specify the general configuration of the plant and its outline requirements. These requirements consist of:
• Feed characteristics, especially H2S, CO2 and mercaptan concentrations
• Product specifications, including maximum concentrations of sulfur and CO2 in the products.

The criteria to be optimized for the process scheme selection include:
• Environmental and safety compliance with local regulations for effluents from incinerators, flare stacks, wastewater treatment, etc.
• Flexibility and performance
• Cost
• Energy consumption.

The maximum H2S concentration allowed in the sales gas is 4–5 parts per million by volume (ppmv); therefore, gas treating of the feed gas using amine is necessary. The amine unit is designed for total H2S removal and total or partial CO2 removal. This article will investigate the reason for partial CO2 removal, which is no longer required due to the recent advances in sulfur recovery technology used in gas processing plants, including South Pars gas plants.

Partial CO2 removal scheme.

Over a span of 20 years, the process design of each gas processing plant has been modified to some extent. The main reasons for the changes are more stringent environmental regulations for newer projects and higher ethane purities required for petrochemical plants.

The original scheme designed to meet the product specifications from a sour feed containing high concentrations of H2S, CO2 and mercaptans is depicted in Fig. 1.

  Fig. 1. Original scheme for sour gas treating plant.

The gas processing facility has a feed gas treating unit (GTU) using amine for total H2S removal and partial CO2 removal. The facility also includes utilities, offsites and necessary infrastructure. The functions of the main process units can be summarized as follows:
• Feed reception and gas/liquid separation
• Total H2S removal and partial CO2 removal from gas
• Dehydration using molecular sieve technology
• Ethane recovery for production of sales gas and gaseous ethane
• NGL separation for production of liquid C3, C4 and gas condensate
• Sales gas export compression
• Sulfur recovery
• Ethane treatment for CO2 removal and drying.

Restrictions affect design.

New environmental standards have influenced product specifications and have led to changes in the gas plant design. The main changes that have altered the design are:
• Improved sulfur recovery efficiency in the sulfur recovery unit (SRU), resulting in less sulfur being burned in the incinerator
• Lower CO2 content requirement in the ethane product
• Lower sulfur content requirement in propane and butane products.

This article investigates the best process scheme for the new conditions and compares total CO2 and H2S removal for the GTU vs. partial CO2 removal. It also examines the impact of this change on other units in the plant.

Gas treating unit. The GTU uses amine for H2S and CO2 removal. Although we assume that readers are familiar with amines, it is important to note that three types of amines are already used in most gas refineries, as summarized in Table 1.1, 2


When the GTU is designed for total H2S and CO2 removal, normally the CO2 can be reduced to less than 5 ppmv. However, because of design limitations, guaranteed figures using generic diethanolamine (DEA) generally provide maximum CO2 concentrations of 100 ppmv in the treated gas.

Changes in the sulfur recovery unit. The acid gases (H2S and CO2) removed in the amine unit are sent to the SRU. The SRU is based on the modified Claus process for recovering elemental sulfur from acid gas. The chemistry of reactions involved in the Claus process may be described in a simplified form with the following two equations: the first is a simple combustion of one-third of the hydrogen sulfide; the second is the reaction of SO2 produced with the remaining two-thirds of H2S, according to the following reactions:3

H2S + 3/2 O2 t SO2 + H2O – 519 kJ/mole (–124 kcal/mole)

2 H2S + SO2 t 3/n Sn + 2 H2O – 143 kJ/mole (–34 kcal/mole)

Feed gas composition. The acid gas from the GTU regenerator column consists of H2S and CO2 that is fed to the Claus unit. The Claus process efficiency is largely dependent on the H2S/CO2 ratio, and it is difficult to maintain at a high value when the H2S content in the acid gas drops below 36%–40%. This difficulty is due to the following factors:

• CO2 is an inert gas that dilutes the process gas and, consequently, reduces the conversion efficiency by lowering the partial pressure of reactants. Furthermore, in the reaction furnace (where the thermal Claus reaction takes place), the conversion efficiency is limited due to resulting low flame temperature.

• The low H2S content may present challenges to sustaining the flame in the reaction furnace, where only one-third of the acid gas should be burned to achieve the stoichiometric H2S-to-SO2 ratio of 2 required by the Claus reaction.

• Carbon dioxide may react with a sulfur species to form carbonyl sulfide (COS) and carbon disulfide (CS2) or a dissociate, which may result in reduction of the overall sulfur recovery, unless adequate precautions are taken for the design of the reaction furnace and the catalytic converters.

• Due to the above reasons, limitations in the Claus process on the maximum CO2 content require a ratio of 60:40 for CO2:H2S for the acid gas from the GTU. Lower H2S concentrations can be accepted using special measures (such as enriched air and fuel gas co-firing), but at the expense of lower conversion efficiencies. However, to minimize the Claus unit size and maximize efficiency, an acid gas enrichment using selective amine is generally used to produce “enriched” acid gas suitable for conventional Claus SRUs.4

• Another option is to use an amine absorption process, which is suitable for H2S concentrations within the range of 1%–30 vol%.5 They offer less complex designs and the same sulfur quality as the Claus process, but have the disadvantage of providing lower sulfur recovery of 96%–97%.

Sulfur recovery efficiency. Typical sulfur recovery efficiencies for Claus plants are 90%–96% for a two-stage reactor and 95%–98% for a three-stage reactor. However, new environmental regulations limit sulfur recovery efficiencies to 98.5%–99.9%. This limitation has led to the development of a large number of tail gas units based on different concepts to remove the last remaining sulfur species.6

Changes in ethane quality.

Due to partial CO2 removal in the current design, the ethane product—which is separated from the treated gas in the ethane-recovery section—contains CO2. Therefore, it becomes necessary to add an ethane decarbonation unit (EDU) to reduce the CO2 level to the specified maximum of 50 parts per million by weight (ppmw) prior to export. DEA is used to remove CO2 from ethane in the EDU before it is dehydrated using molecular sieve beds.

In the case of total CO2 removal in the GTU, the ethane cut from the ethane recovery section will contain very little to virtually no CO2. In fact, ethane will contain around 500 ppmw if CO2 is lowered to 100 ppmv in the GTU using DEA, which can be removed by molecular sieve beds. Also, there is no need for a separate drying unit if molecular sieve beds are used, which provides an advantage in terms of cost, ease of operation and maintenance. Therefore, in the case of total CO2 removal, even the molecular sieve bed is just a CO2 guard.

Changes in LPG product quality. The environmental specification for the total sulfur content in LPG products (C3 and C4) has been lowered from 80 ppmw to 10 ppmw; this was the case for LPG products from South Pars gas plants.

Sulfur species in LPG are essentially mercaptans, which are removed by direct oxidation with air in the presence of a proprietary catalyst, using a caustic soda-wash process. The LPG product is then dried before export.

A molecular sieve sulfur guard is installed after the LPG dryers. The molecular sieve beds are regenerated using sales gas that is then sent to the fuel gas system. The regeneration gas must be CO2-free, as requested by the LPG guard bed vendor. Therefore, if partial removal of CO2 is considered for the GTU design, then another DEA absorber must be installed for total CO2 removal from the regeneration gas. However, if the CO2 is totally removed in the GTU, then molecular sieve guard beds can be used instead of a DEA absorber.

Evaluation of existing GTU.

The CO2 specifications for sales gas fed to a consumer network should be less than 2 mol%—the maximum limit to prevent general corrosion and pitting in pipelines. This limit will be achieved if the CO2 content in the treated gas from the GTU is less than 1 mol%. In fact, the latter quantity was obtained by back calculation using the ratio of 60:40 for CO2:H2S in the acid gas to the SRU and a sulfur recovery of 97.5%. Therefore, partial CO2 removal in the GTU was dictated by the process requirements in the SRU.

In more recent projects, environmental regulations allow for fewer SO2 emissions from the SRU incinerator, which requires an increase in the conversion of sulfur recovery from 97.5% to 99.5%. Thus, to achieve higher overall sulfur recovery, acid gas enrichment and tail gas treatment units must be used. The acid gas enrichment unit consists of selective H2S removal from the acid gas in the presence of CO2 (i.e., partial CO2 removal from the acid gas). This is accomplished by including an amine unit using a generic MDEA solvent that selectively absorbs H2S. The offgas leaving the top of the amine absorber is sent to the incinerator to convert the residual H2S to less harmful SO2, while the sour gas reaching the required H2S:CO2 ratio from the amine regeneration unit is sent as feed to the Claus reactor.

Therefore, by making a gas enrichment unit part of the sulfur gas recovery unit, it is no longer a requirement to specify an outlet CO2 of 1 mol% in the treated gas from the GTU. Based on these results, two alternatives exist for the gas processing plant scheme:
1. Partial CO2 removal in the GTU—similar to the old scheme, regardless of the changes in the SRU, as shown in Fig. 2.
2. Total CO2 removal in the GTU—an optimized gas processing plant scheme based on changes in the SRU, as depicted in Fig. 3. 

  Fig. 2. Sour gas treating plant with partial CO2 removal.

  Fig. 3. Sour gas treating plant with total CO2 removal.

Effects of total CO2 removal on sales gas quality. The sales gas from gas processing plants can contain a maximum of 2 mol% of CO2, as stated in the previous section. Carbon dioxide is an inert gas that only uses energy to be heated to the flame temperature, without any heat input contribution to the combustion. Therefore, its presence at a relatively high amount in the sales gas is a waste of energy.

In addition to the above, environmental agencies of many countries continue to implement more stringent emissions standards requiring companies to report their greenhouse gas emissions. Thus, many customers buying sales gas want CO2 levels in the gas to be minimized. Also, the CO2 present in the sales gas is distributed through many users, although it can be recovered for industrial use when totally captured at the gas plant source.

These negative aspects of CO2 presence in the sales gas are some of the disadvantages that can be easily prevented by total CO2 removal in the GTU, which can be achieved using DEA or activated MDEA (aMDEA) in the GTU. When the GTU is designed for both H2S and CO2 removal (down to 3 ppmv and 100 ppmv, respectively) in the treated gas using DEA, the CO2 content in the sales gas ranges from 100 ppmv–200 ppmv.

Effects of CO2 removal on sales gas heating value. When modifying the sales gas composition by total CO2 removal, it is important to check the heating value to ensure that the changes are not significant enough to require burner change in the consuming furnaces. Two sales gases were studied for this purpose; the results are presented in Table 2. As the table shows, the effect of total CO2 removal on sales gas heating value and its possible consequences on burner design—as well as adverse effects on the operation of existing burners—is insignificant.


Effects of total CO2 removal on the dehydration unit. If CO2 is present in the feed gas to the dehydration unit after the GTU, it might be partially co-adsorbed by the molecular sieve beds, resulting in a reduced active area for water adsorption and a longer time for bed regeneration. Therefore, it could be expected that, in the case of total CO2 removal, the bed adsorption capacity will be increased while the bed regeneration time and energy consumption are decreased. This is an item that needs further investigation by operators and vendors.

Overall optimized scheme.

Fig. 3 shows the optimized scheme for total CO2 removal, where the ethane treatment with molecular sieve beds should only be considered if the treated gas from the GTU will provide an ethane product with a CO2 content higher than 50 ppmw.


Before selecting a scheme for a gas processing plant, it is necessary to construct a clear and complete picture of the entire facility. The requirements of each unit within the plant must be understood before they are integrated into the whole scheme.

The process scheme selection is carried out during the conceptual stage of a project and should take into account new technology developments for each unit in the plant. Such an approach will deliver an optimized process for the plant that is cost effective, energy efficient, and meets local environmental and safety regulations. HP


1 Hanamant Rao, P. P., D. L. Nikolic and R. Wijntje, “Do you have hard-to-handle gases?’’ Hydrocarbon Processing, July 2009.
2 Centi, G., S. Perathoner and F. Trifiró, Sustainable Industrial Processes, pp. 450–455, 1st ed., 2009.
3 Hocking, M., Handbook of Chemical Technology and Corrosion Control, pp. 267–271, 3rd ed., 2005.
4 Klikenbijl, J. M., M. L. Dilon and E. C. Heyman, “Gas Pre-Treatments and Their Impact on Liquefaction Processes,” Gas Processors Association, Nashville, Tennessee, US, March 2, 1999.
5 Echt, W. L. and C. J. Wendt, “Reduce Sulfur Emissions from Claus Recovery Units,” AIChE, April 1993.
6 Ramshni, M., “Cost Effective Options to Expand SRU Capacity Using Oxygen,” Sulfur Recovery Symposium, Banff, Alberta, Canada, May 6–10, 2002.

The authors 

  Mohammad Maleki is the process, utility and HSE (health, safety and environment) department manager at Energy Industries Engineering and Design Co. He was the consortium process and HSE manager of South Pars front-end engineering and design phases 17 and 18. Mr. Maleki received a BS degree in chemical engineering from the University of Texas at Austin. He has over 30 years of experience as a process and HSE manager, project engineering manager and principal process engineer on several oil, gas and petrochemical projects. 

  Mohammad Reza Khorsand Movaghar has worked in the process department at Energy Industries Engineering and Design Co. since 2008. He holds a BS degree in petrochemical engineering and a PhD in chemical engineering from Tehran Polytechnic University. Dr. Khorsand also received an MS degree from the University of Science and Technology in Tehran. He served as a process engineer on detailed design projects for gas train units—including acid gas removal, dehydration and ethane recovery—at South Pars gas plant phases 20 and 21. He has over five years of experience as a process engineer and process simulator on several oil and gas projects. 

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