Novel Approach to Sour-Gas Treatment Lowers Cost and Limits Safety Hazards

This paper investigates novel approaches to sour-gas treatment for use in the Middle East that are outside the common oil and gas market and compares them with traditional techniques.


This paper investigates novel approaches to sour-gas treatment for use in the Middle East that are outside the common oil and gas market and compares them with traditional techniques. The methods presented in this paper were based on one central tenet: deliver a practical, economical solution to producing from an extremely sour [greater than 40,000‑ppm hydrogen sulfide (H2S)] gas field. Modified tail-gas treatment units (TGTUs) were found to be economically viable, can be implemented onsite, and can tie in to existing infrastructure with minimal capital expenditure (CAPEX) or operational expenditure (OPEX).


A field in the Mediterranean was producing sour gas at a rate that would render production untenable. One of the wells was producing 24,000-ppm H2S with an expected increase to 46,000 ppm within a few years. While the lower rate allowed production as long as it was coincident with other, sweeter wells in the region, the rising sourness eventually would render operation impossible. To counter this trend, a stage-gate process was established to identify potential solutions and an array of technologies was proposed.

The main criteria that have been considered for the selection of gas-­sweetening technologies are cost, operability, and efficiency. The selected options would be analyzed on the basis of these criteria using a screening sheet upon which each criterion had been broken into key elements (the screening method is detailed in Appendix A of the complete paper). The selected option ideally should be low-cost, highly efficient, and environmentally friendly.

Offshore Acid-Gas Removal Options

These technologies included the following:

  • H2S scavengers
  • Absorption processes
    • Regenerative absorption
    • Nonregenerative absorption
  • Adsorption H2S-removal processes
    • Regenerative adsorption
    • Nonregenerative adsorption
  • Membrane separation

The membrane-separation units consist of many polymerized hollow fibers arranged asymmetrically and formed into loose bundles of membrane elements. When a pressure differential is applied, the molecules diffuse into the pores of the polymeric material and transport (permeation) occurs across the membrane. Membrane units have relatively modest layout requirements, and CAPEX can be modest to high.

Acid-Gas Disposal-Treatment Options

Claus+TGTU. In the Claus process, H2S is treated with air (oxygen) over a catalyst to form elemental sulfur and water. The tail gas from a Claus unit goes through a tail-gas cleanup or TGTU process.

Liquid-Redox Process. Processes in this group absorb H2S from gas streams and react oxygen with the H2S to form elemental sulfur and water. Iron-chelate processes belong to the liquid-redox sulfur-recovery group and are the most commonly used active redox reagents. A chelating agent is generally an organic molecule able to bind with a metallic cation in such a way that the cation is ­sequestered from the solution.

Biological Process. In this process, a gas stream containing H2S contacts an aqueous soda solution containing sulfur bacteria in an absorber. The soda absorbs the H2S and then transfers to a regenerator.

Modified TGTU. Some processes replace the traditional TGTU with an ammonia-desulfurization unit. The processes use a Claus unit to remove the majority of the H2S in the acid gas to recover sulfur. However, the residual H2S is converted to sulfur dioxide (SO2) by incineration, and the SO2 reacts with ammonia in the ammonia-desulfurization unit to produce ammonium-sulfate fertilizer as a byproduct. The ammonia-desulfurization unit does not always need to be downstream of the Claus unit but can be used downstream of the incinerator if required.

Concepts Evaluated

Once the technologies that showed promise were selected, a model of the system was set up that incorporated potential modes of operation to see how combinations of treatments at various intervention points could be used. A combined approach was considered essential for removal of the acid-gas issues because of the large quantities involved. As part of the process of evaluating the five most-viable options, several small study cases were explored to find potential costs associated with the various technologies.

The five options investigated included the following:

  • Option 1 (H2S scavenger+dry bed)
  • Option 2 (membrane technology)
  • Option 3 (membrane+dry bed)
  • Option 4 (H2S scavenger+membrane)
  • Option 5 (concentrated acid-gas removal using advanced TGTU onshore)

Of these options, two were considered suitable for further review:

  • Membrane technology deployed offshore, provided that acid-gas reinjection and a suitable layout are possible (Option 2)
  • Acid-gas removal using TGTU technology at the onshore plant downstream of the incinerator (Option 5)

Membrane-Technology Assessment

For appraisal of the membrane technology, a base case with field production limited to maintain approximately 4,000 ppmv of H2S at the membrane-unit inlet was used. This value was selected because 4,000 ppmv represents the upper limit at which process-membrane units can achieve export specification levels (less than 1800 ppmv) of H2S in the produced fluids.

Installation of a membrane unit on the asset was evaluated as the governing factor because of space and load limitations. Ultimately, installation of a bridge-linked platform (BLP) to the platform was identified as the most-feasible installation option; however, outside of a major CAPEX project, installation of a BLP to the platform was considered prohibitively expensive.

When installation costs are added to the investment in membranes, revenue is offset and a loss is yielded. Membranes fail to reduce the H2S to a sufficient level to be considered a lone solution. Therefore, process membranes were not considered a feasible solution.

TGTU Assessment

The TGTU assessment considered applications from three vendors. The first two used variations of efficient ammonia-based desulfurization (EADS) and ammonium sulfate wet-flue gas desulfurization (AS-WFGD). The last vendor used a lime/gypsum system that required flow rates much greater than those produced by the asset. The EADS and AS-WFGD systems have been deployed across China and the United States for several years across the coal industry but had not been considered for use in the oil and gas sector at the time of the study. Both vendors claimed greater than 98% SO2 conversion.

A process-flow schematic for the EADS system is shown in Fig. 1. The concentrated acid-gas stream from the amine will be fed to an incinerator unit. The incinerator unit converts the H2S in the concentrated acid gas to oxides of sulfur in the flue-gas stream. The reaction takes place at high temperatures and is highly exothermic. To limit the temperatures before feeding into the absorber, the flue-gas stream is cooled in a heat-recovery unit such as a waste-heat boiler.

Fig. 1—Process diagram of the EADS system.


The SO2 in the flue-gas stream then undergoes a series of reactions in the absorber; most is converted to ammonium sulfate, which is processed into a salable fertilizer. The SO2 in the flue gas was predicted to be less than 200 mg/Nm3, within the established environmental criterion of 300 mg/Nm3.

Ammonia Storage. Ammonia ­storage systems should be equipped with a ­water-spray system to prevent ammonia vapor from endangering personnel in the event of a release. Ammonia is highly soluble in water, and any release can be captured by dousing the area with water (much like a fire-suppressant system) and capturing the tainted water in drainage tanks for recycling or disposal. The storage facilities proposed by the vendor were equipped with such a system. The storage site should be free from ignition sources and equipped with sprinklers. It is also recommended that selected materials have a 4-hour fire-resistance rating.

Ammonia would be required at approximately 0.5 t/h in the desulfurization system, with a recommended store of 120 m3/h (volume for a week). The storage footprint has been estimated as approximately 15×12 m for the tanks. Potential storage sites for ammonia at the plant were identified, and there is enough space onsite to accommodate these and the pipework.

Venting Considerations. The treated gas out of the absorber unit is predicted to have high quantities of CO2 (essentially the same as the current output) and very low quantities of SO2. Two options are provided by the vendor to vent this stream: venting out of the absorber or venting using a stack. Because of the potential safety issues resulting from the first option, venting using a stack was recommended.

Economic Considerations. The quote from the vendor includes the cost of design, engineering, manufacturing, delivery, installation (including the piping work), construction, and commissioning. The CAPEX of an ammonia storage area has not been included as a part of the vendor’s estimate. This was estimated at $290,000 ±40% including unit, pumps, and piping.

The breakdown of the OPEX provided by the vendor assumes the sale of ammonium sulfate at present market rates and gains from heat-recovery results; the steam generated by the waste-heat-recovery system is considered as a cost saving. However, if heat recovery is not to be considered, the OPEX estimate is approximately $2.8 million/year.

It was clear from the economic considerations that the EADS system was favorable to the AS-WFGD system because of its cost of $21.6 million compared with $49.4 million.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193115, “Novel Approaches to Sour-Gas Treatment in Oil and Gas: Onshore and Offshore Facilities,” by Iain Pollitt and Joao Conde, Infinity Oilfield Services, prepared for the 2018 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed.