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Sour gas

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Sour gas is natural gas or any other gas containing significant amounts of hydrogen sulfide H2S).Sour gas reserves are historically left undeveloped because of the technical challenges and costs involved in their extraction and processing.[1]


Natural gas that contains more than 4 ppmv of hydrogen sulphide (H2S) is commonly referred to as "sour". This is because the odour of hydrogen sulphide gas in air at very low concentrations is similar to that of rotten eggs. Significant quantities of natural gas resources around the world are known to contain H2S. These have been difficult to produce in the past because of the tendency for sour gas to cause corrosion and sulphide stress corrosion cracking, particularly in pipelines. With the advent of corrosion resistant materials and advanced manufacturing techniques for steel pipelines the production of these sour gas reserves is now becoming possible. Downstream refineries have been handling sour gas as a by-product from the processing of sour crude oil for many decades .....

H2S is highly toxic and can cause serious injury and death at relatively low concentrations. The characteristic odour can be detected by human beings at very low concentrations. However, at higher concentrations the odour can no longer be detected by human beings and the inability of human beings to detect its presence is a major risk factor. The toxic effects of H2S are summarised in the table below.

Concentration in Air Effect
< 1 ppm Odour of rotten eggs can be clearly detected. Noticeable odour at concentrations as low as 10 ppb.
1 ppm Unpleasant odour. Possible eye irritation. American Conference of Industrial Hygienists (ACGIH) recommended Threshold Limit Value Time Weighted Average (TLV-TWA) over 8 hours
5 ppm ACGIH Threshold Limit Value Short Term Exposure Level (TLV- STEL) averaged over 15 minutes
50 ppm Loss of sense of smell after about 15 or more minutes exposure. Exposure over one hour may lead to headache, dizziness, and/or staggering.
100 ppm Coughing, eye irritation, loss of sense of smell after 3 to 15 minutes. Altered respiration, pain in eyes, and drowsiness after 15 to 20 minutes, followed by throat irritation after one hour.
200 ppm The sense of smell will be lost rapidly, and it will irritate the eyes and throat. Prolonged exposure (>20 to 30 minutes) may cause irreversible pulmonary oedema, i.e. accumulation of fluid in the lungs.
500 ppm Unconsciousness after short exposure, breathing will stop if not treated quickly. Dizziness, loss of sense of reasoning and balance. Victims need prompt artificial ventilation and /or cardiopulmonary resuscitation (CPR) techniques.
700 ppm Unconscious quickly. Breathing will stop and death will result if not rescued promptly. Artificial ventilation and/or cardiopulmonary resuscitation (CPR) are needed immediately

Technical challenges

Hydrogen sulfide H2S is:

  • Toxic
  • Flammable
  • Corrosive

Safety training


The removal of H2S from sour gas is called “sweetening".

Claus process

The Claus process is the most significant sulfur recovery process in the industry, recovering elemental sulfur from gaseous hydrogen sulfide. First patented in 1883 by the scientist Carl Friedrich Claus, the Claus process recovers elemental sulfur from an acid gas stream through partial oxidation of the H2S to SO2 and then to Sulfur. Typically, the Claus process works along with an acid gas removal system, which serves to remove the hydrogen sulfide from the sour gas stream. The resulting acid gas stream which generally contains hydrogen sulfide, carbon dioxide and moisture can be treated through a Claus unit. In general, the natural gas stream, or syngas stream containing hydrogen sulfide is not sent directly to a Claus plant, because the Claus plant will oxidize the valuable natural gas or syngas, which is why an Acid Gas Removal system generally precedes a Claus plant. In general, a Claus plant requires H2S concentration of >50% in the feed stream, although a Claus plant can handle streams with lower H2S concentrations with process modifications including co-firing with natural gas, furnace modifications, furnace bypass, sulfur burning etc. Typically, a Claus plant can remove 95-98% of the inlet sulfur. The Claus plant generates medium and low pressure steam, and if this has utility, the Claus plant may be considered to have minimal net operating cost.

Alberta Sulfur at Vancouver BC

GT-SPOC process

The GT-SPOC process is Claus type process, where the burner and reaction furnace section in a conventional Claus plant is replaced by a catalytic section. The catalytic section is a short contact time reactor, with millisecond residence time. The catalytic section can operate with lean H2S (<25% H2S) and produces less COS, CS2 and dissolved H2S in the molten sulfur.

GT-DOS - Direct catalytic oxidation process

TDA Research developed the Direct Oxidation to Sulfur process, which is licensed to GTC Technology. The process converts H2S catalytically directly into sulfur, from lean (low concentration) H2S streams (0.2% to 40% H2S). The sulfur conversion efficiency is around 90% in a single pass.[2], and can attain 95 - 98% overall conversion efficiency. Although the GT-DOS process can directly treat gas, it is most commonly considered for sulfur recovery from an acid gas stream from an Acid Gas Removal unit. In that configuration, the H2S in the acid gas is partially oxidized directly to Sulfur (without producing SO2 first, as in the Claus process). Unlike the Claus process, there is no burner and reaction furnace, which means the GT-DOS process can directly handle lean acid gas streams. The operating cost is in the $200 - 1,000 per ton of Sulfur removed.

Stretford process

This is a liquid-redox process. The Stretford process was developed during the late 1940s to remove hydrogen sulfide H2S from town gas. It was the first liquid phase, oxidation process for converting H2S into sulfur to gain widespread commercial acceptance. Developed by Tom Nicklin of the North Western Gas Board (NWGB) and the Clayton Aniline Company, in Manchester, England, the name of the process was derived from the location of the NWGB's laboratories, in Stretford.

Small Stretford reactor

Lo-Cat process

This is a liquid-redox process. The LO-CAT® process is a patented, wet scrubbing, liquid redox system that uses a chelated iron solution to convert H2S to innocuous, elemental sulfur. It does not use any toxic chemicals and does not produce any hazardous waste byproducts.[3]. In general, the LO-CAT process can directly treat a gas stream, or treat the H2S containing stream from an Acid Gas Removal unit, although the direct treat capability is limited to low pressure streams. The operating cost is in the $1,000 - 2,000 per ton of Sulfur removed.

Sulferox process

SulFerox is a Shell proprietary Iron Redox process, whereby a sour gas stream, containing hydrogen sulphide, is contacted with a liquid, containing soluble ferric (Fe3+) ions. In the process the H2S is oxidized to elemental sulphur and the Fe3+ is reduced to ferrous (Fe2+) ions. The system is regenerable, Fe2+ is subsequently reconverted to Fe3+ by oxidation with air. Sulphur is recovered from the aqueous solution as a moist cake.[4]

Typical Sulferox[5] process equipment is illustrated in Fig. 4. In this process, the sour gas is contacted in a small contactor in cocurrent flow with a water solution containing about 4% ferric iron ions, held in solution by proprietary chelate ligand. The H2S ionizes in the solution, and the ferric iron ions exchange electrons with the sulfur ions to form ferrous iron ions and elemental sulfur. The gas and the solution leave the contactor and are flowed into a separator. The gas out of the separator is sweet and requires further treating for dewpoint control. The solution is flowed into additional vessels for separating the elemental sulfur and for restoring the ferrous iron ions back to the active ferric iron state by contacting the solution with air. The chemistry is illustrated next.

In general, the Sulferox process can directly treat a gas stream, or treat the H2S containing stream from an Acid Gas Removal unit, although the direct treat capability is limited to low pressure streams. The operating cost is in the $1,000 - 2,000 per ton of Sulfur removed.

Vol3 page 195 eq 001.PNG

Thiopaq O&G process

The THIOPAQ O&G process integrates gas purification with sulfur recovery in a single unit. The sour feed gas first comes into contact with the lean solution in the absorber. This solution absorbs the H2S to form sodium sulfides, and sweet gas exits the absorber, ready for use or further processing.[6] The process uses naturally occurring bacteria (Thiobacillus) to oxidize the H2S to elemental sulfur.

CrystaSulf process

This process was developed in the 1990s by the Gas Research Institute for the H2S removal from high-pressure gas. The technology is currently licensed through URS/AECOM. CrystaSulf uses a nonaqueous solution with a high solubility for elemental sulfur. Because the elemental sulfur stays dissolved in the solution, there are no solids in the liquid circulated to the absorber. By design, CrystaSulf avoids the problems that make the aqueous sulfur recovery systems unsuitable for direct treatment of high-pressure sour gas.[7]


  1. Boschee, P. 2014. Taking On the Technical Challenges of Sour Gas Processing. Oil and Gas Fac 3 (6): 22--25.
  2. GTC Technology. GT-DOS™ Direct Oxidation to Sulfur.
  3. Merichem Company. Lo-Cat H2S Removal Technology.
  4. Njo, L., and Strous, M. 1993. Preliminary design of a SulFerox unit. Report. Delft University of Technology.
  5. Fong, H.L., Kushner, D.S., and Scott, R.T. 1987. Shell Redox Desulfurization Process Stresses Versatility. Oil & Gas J 84 (21): 54-64.
  6. Paqell. THIOPAQ O&G Process Description.
  7. GTC Technology. Sulfur Recovery--CrystaSulf®.

Noteworthy papers in OnePetro

Verlaan, C., & Van der Zwet, G. 2012. Challenges and Opportunities in Sour Gas Developments. Society of Petroleum Engineers.

Wu, R., Rijken, M. C. M., Macary, S., Shinikulova, M., Amangaliev, B., & Ayazov, Z. 2014. Tengiz Sour Gas Injection Modeling: A Geo-mechanics Approach to Understand Gas Breakthrough. Society of Petroleum Engineers.

Onerhime, A., Daher, E., & Kveps, A. 2014. Addressing Safety Challenges of Operating in Sour Gas Fields: A Case Study from the Middle East. Society of Petroleum Engineers.

External links

International Association of Drilling Contractors

Occupational Safety & Health Administration


See also

Hydrogen sulfide (H2S) fields

Sour gas sweetening

PEH:Drilling Problems and Solutions