Hydrogen sulfide (H2S) is a very toxic and pungent gas that causes problems in both the upstream and downstream oil and gas industry. The process of removing H2S is known as gas sweetening, by either iron sponge H2S scrubbers (forming iron sulfide) or chemical scavengers. Typical H2S scavengers used in the oilfield are amine based chemicals. They can be roughly categorized into regenerative and non-regenerative H2S scavengers.
Regenerative H2S scavengers
In large production facilities, the most economic solution to remove H2S in the gas process stream is to install a regenerative system for treating the sour gas. After absorbing the H2S, the chemical is then regenerated, usually by heating and reused in the system. The separated H2S is treated by a modified Claus process to form elemental sulfur.
Several types of amine solutions can be used as the absorbent depending on the sour gas specifications. Typical amines are:
- Diethanolamine (DEA)
- N-methyldiethanolamine (MDEA)
- Diglycolamine (DGA), also known as 2-(2-aminoethoxy)ethanolamine
Most modern amine gas sweetening processes are MDEA-based, which typically only absorbs H2S. MEA, DEA and DGA typically absorb other acid gases as well (i.e. CO2) besides H2S.
Amine gas treating can be utilized to remove H2S in the gas stream.
Non-regenerative H2S scavengers
- Triazine - alkaline and can cause carbonate scaling
- Solid scavengers (generally zinc or iron based materials)
- Oxidizing chemicals (e.g. NaClO2, NaBrO3, NaNO2, etc.)
- Glyoxal - can be applied in neutral, acidic, and alkaline conditions. Glyoxal does not increase scaling risk, but its reaction time is much slower than triazine.
- Metal carboxylates and chelates
- Both water and oil soluble high valence metal chelates have been used as H2S scavengers for treating drilling fluids and contaminated water and oil streams.
Non-generative H2S scavengers are typically applied via a in-line injection quail to finely disperse the liquid chemical into the gas stream to maximize reaction.
A contact tower can be used to improve efficiency if weight/space is not a constraint.
- H2S scavenger increases the pH of the water and can cause severe carbonate scale.
- Over-reacted H2S scavenger can form polymeric sulfar deposit.
- Performance of H2S scavenger can be improved by increasing resident time or adding a static mixer.
- The dosage of H2S scavenger is calculated based on the amount of sulfur to be removed.
- Production chemicals for the oil and gas industry
- M. Pandey, SPE, Oil and Natural Gas Corp. Ltd. , Process Optimization in Gas Sweetening Unit - A Case Study, International Petroleum Technology Conference, 21-23 November 2005, Doha, Qatar
- T. Salma, M.L. Briggs, Baker Petrolite; D.T. Herrmann, E.K. Yelverton, British Petroleum , "Hydrogen Sulfide Removal from Sour Condensate Using Non-Regenerable Liquid Sulfide Scavengers: A Case Study", SPE Rocky Mountain Petroleum Technology Conference, 21-23 May 2001, Keystone, Colorado
- Yaser K. Al-Duailej, Saleh H. Al-Mutairi, and Adel Y. Al-Humaidan, SPE, Saudi Aramco Oil Company, "Evaluation of Triazine-Based H2S Scavengers for Stimulation Treatments", SPE/DGS Saudi Arabia Section Technical Symposium and Exhibition, 4-7 April 2010, Al-Khobar, Saudi Arabia
- Meiliza Sumestry, SPE and Hendy Tedjawidjaja, PT Medco E&P Indonesia, " Case Study : Calcium Carbonate Scale Inhibitor Performance Degradation due to H2S Scavenger Injection in Semoga Field", North Africa Technical Conference and Exhibition, 20-22 February 2012, Cairo, Egypt
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- J.G.R. Eylander, H.A. Holtman, Nederlandse Aardolie Maatschappij; T. Salma, M. Yuan, M. Callaway, J.R. Johnstone, Baker Petrolite, The Development of Low-Sour Gas Reserves Utilizing Direct-Injection Liquid Hydrogen Sulphide Scavengers, SPE Annual Technical Conference and Exhibition, 30 September-3 October 2001, New Orleans, Louisiana