Hybrid Solvent Helps Ease Bottlenecking in Natural-Gas Plant

Fig. 1—Hydrocarbon solubility in hybrid solvents.

You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers.

To ensure continued access to JPT's content, please Sign In, JOIN SPE, or Subscribe to JPT

Processing sour natural gas is a challenge. If mercaptans are present in the sour gas, the limited mercaptan-absorption capacity of the well-known alkanolamine solvents can be a problem. A solution is to replace the usual alkanolamine aqueous solvent with a hybrid formulation that allows simultaneous removal of mercaptans and acid gases. A new solvent has been developed by the addition of a physical component into a generic alkanolamine/water solvent. This hybrid solvent can be used without any plant modification.


More than 40% of identified gas reserves contain acid gases. Over the years, solvent technologies have been developed, demonstrated, and improved for hydrogen sulfide (H2S) and carbon dioxide (CO2) removal.

Sour-gas processing has recently seen the requirement of more-stringent specifications for total sulfur compounds, particularly mercaptans and carbonyl sulfide. Producing sour-gas fields in an economic way became a challenge. Indeed, the physicochemical properties of mercaptans allow only very limited reaction with amines under operating conditions. Classical aqueous amine technologies generally are not sufficient to reach mercaptan or total-­sulfur specifications. Consequently, additional treatment is required to remove these compounds.

The first option to treat a gas containing CO2, H2S, and mercaptans consists of a polishing stage for further mercaptan removal (for example, molecular sieves) downstream from the amine treating process. One drawback of this option is that the gas used for adsorbents regeneration needs to be sweetened, which requires a dedicated unit. Another drawback is that the gas-sweetening unit is generally designed to use a physical solvent, which has high affinity for hydrocarbon.

The second option is most often used when the recovery of natural-gas liquids is considered. Mercaptans and other sulfur compounds concentrated in the liquid-hydrocarbon cuts are removed through a caustic-soda process or by molecular sieves. With the first option, the succession of treatment stages requires an increase in plant footprint, which brings unavoidable extended lifecycle costs. Meanwhile, the drawbacks of these schemes include the disposal of the disulfide oil with the caustic-soda process or the treatment of the gas used for molecular-sieve regeneration.

The last option is the simultaneous removal of mercaptans, carbonyl sulfide, and acid gases in a single unit by use of a mixture of chemical and physical solvents. However, the mercaptan-removal efficiency is correlated with the solvent composition and flow rate. Design criteria can be for H2S and CO2 removal or for mercaptan elimination. Expenditure optimization will drive the selection of the process scheme: either total mercaptan removal within the gas-­sweetening unit or partial mercaptan removal with the hybrid solvent followed by a polishing unit.

These options have pros and cons for mercaptan removal. A greenfield project will accommodate any of them, considering project constraints. How­ever, mercaptan removal in a brownfield project is different because of the constraints of the existing plant. That may result in significant plant modification to increase mercaptan removal or to cope with more-stringent product or environmental specifications. For brownfields, the use of a hybrid solvent is the most attractive solution.

A New Hybrid Solvent

A new hybrid solvent has been developed that allows for the simultaneous removal of CO2, H2S, and mercaptans while p reserving lowhydrocarbon coabsorption.

In 2007, declining gas fields in southwest France treated approximately 5 million std m3/d of sour gas. The sour gas typically contained approximately 17 mol% H2S and 10 mol% CO2. The sour gas was sweetened by use of water/diethanolamine (DEA) solvent. The sweet gas from the amine units was sent to a molecular-sieve unit before reaching the hydrocarbon dewpoint; this unit removes mercaptans and dehydrates the gas to specifications. To face new sales-gas specification and an increase in sulfur-component concentrations in the sour gas, the following options were considered to achieve the new mercaptan specification:

  • Modifying existing molecular-sieve units or installing additional mercaptan-removal units
  • Increasing the mercaptan-elimination capability of the existing acid-gas-removal unit either by adjusting the flow rate of the DEA solvent or by implementing a hybrid solvent

Installation of new molecular sieves requires substantial investment that is not justified for the declining gas field. The implementation of a hybrid solvent was considered to be the best solution.

Hybrid solvents were evaluated during the prefront-end engineering and design steps of a debottlenecking project for the Lacq plant. The usual hybrid solvents were considered unsuitable for use in the existing sweetening units. Some of the installed pieces of equipment were not suitable for the physicochemical properties of the hybrid solvents; in particular, absorber internals would have to be replaced.

Benefits of the New Hybrid Solvent

The addition of a physical solvent into an amine aqueous solvent has a negligible effect on acid-gas solubility. The chemical reactions with the amine remain the main driver for H2S and CO2 removal.

Regarding mass-transfer ­efficiency, viscosity and surface tension are increased by the addition of a physical component. As a consequence, the mass-transfer efficiency of the absorber internals might be lowered. That could be the limitation for the use of a hybrid solvent in an existing unit.

Tests were conducted to compare two hybrid solvents with a generic water/amine solvent. The operating conditions considered for the study were a typical case requiring selective H2S removal. Solvent A is a generic methyl diethanolamine (MDEA) solvent, with 45 wt% MDEA. Solvent B is an additive/MDEA solvent prepared by adding the new physical additive to the water/MDEA solvent to reach a water/MDEA/additive composition of 30/45/25 wt%. Solvent C is an MDEA-based hybrid solvent prepared with sulfolane. The ­physical-component content was adjusted to 15 wt%.

Solvent A removes the H2S to 4 ppm by volume in the treated gas and coabsorbs 51% of the CO2. With the same absorber operating conditions, the addition of the physical additive affects the acid-gas-absorption efficiency. For Solvent B, the H2S content in the treated gas is increased to 30 ppm by volume but only 47% of the CO2 is coabsorbed. The addition of 15 wt% sulfolane (Solvent C) results in significant H2S slippage. The CO2 coabsorption is increased compared with Solvent A. Moreover, with 48% of the CO2 coabsorbed, Solvent C is less selective by comparison with Solvent B. Last, the addition of 15 wt% sulfolane in Solvent C removes 31% of the mercaptans, while 38% is removed with Solvent B. These absorption results demonstrate the constraints and limitations for hybrid-solvent use in an existing unit considering acid-gas and mercaptan removal.

Hydrocarbon solubility is the second constraint when considering the use of a hybrid solvent in an existing unit. The acid-gas stream from the gas-­sweetening unit is processed generally in a sulfur-­recovery unit. Less than 1 mol% of hydrocarbon content is recommended for an acid-gas stream feeding a typical sulfur-recovery unit. The selection and concentration of the physical additive are key elements to control hydrocarbon coabsorption. Hydrocarbon-­solubility measurements were taken with different hybrid solvents prepared by adding 20 wt% of a physical component into a generic water/MDEA solvent. The composition of the hybrid solvents is 35/45/20 wt% of water/MDEA/physical component. The study clearly demonstrated that the replacement of part of the water with a physical additive leads to higher hydrocarbon solubility (Fig. 1 above). The physical additive will increase hydrocarbon solubility by 30%.

Finally, the hybrid solvent offers an additional benefit. A decade of operation has shown that this new hybrid solvent requires 8–15% less energy for solvent regeneration compared with water/amine solvent. This lower energy requirement makes this new hybrid solvent an attractive candidate to replace water/amine solvents in existing units.


In the past, hybrid solvents were generally considered an option for the treatment of highly sour gas and when the physical solubility of nonreactive contaminants such as mercaptans is targeted. A new hybrid solvent can be implemented easily in existing gas-sweetening units.

The solvents have been used in the Lacq plant, and no operational issues were reported during more than 10 years of continuous industrial operation. The operation is similar to that of classical amine mercaptan removal, but the efficiency of the mercaptan removal is improved significantly. Increase in hydrocarbon coabsorption is controlled, and the concentration of hydrocarbon in the acid gas is acceptable for downstream units.

As shown in the Lacq plant, the switch from water/amine solvent to the hybrid solvent does not require equipment modification.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188252, “Natural-Gas-Plant Debottlenecking Thanks to Hybrid Solvent,” by Eric Cloarec, Renaud Cadours, and Claire Weiss, Total, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.

Hybrid Solvent Helps Ease Bottlenecking in Natural-Gas Plant

01 April 2018

Volume: 70 | Issue: 4


Don't miss out on the latest technology delivered to your email weekly.  Sign up for the JPT newsletter.  If you are not logged in, you will receive a confirmation email that you will need to click on to confirm you want to receive the newsletter.