Desulphurisation and Mercury Removal from Natural Gases a report by Vince Atma Row1 and Kevin Robinson2
1.Global Product Manager for Gas Processing and Refineries; 2. Technical Sales Manager for Gas Processing, Johnson Matthey Catalysts, Process Catalysts and Technologies
Mercury and hydrogen sulphide (H2S) are recognised as serious contaminants of hydrocarbon streams that must be removed to avoid
corrosion of equipment, poisoning of catalysts and to comply with environmental regulations. Johnson Matthey has developed a range of
fixed bed absorbents for both H2S and mercury removal. This article demonstrates the benefits that can be achieved from the PURASPECJM™ fixed bed technology.
Sulphur Removal
During the early stages of gas processing projects it is sometimes difficult to get a detailed composition of the gas stream and its associated impurities. This uncertainty has sometimes led to acid gas removal units being over-designed to take into account the
fluctuations in H2S concentration. Introducing a more flexible approach to sulphur removal could have saved the extra capital expenditure in those cases.
To meet stringent product specifications with varying feedstock, a single sweetening unit may not be the most cost-effective option and it would be worth considering a two-step process such as a bulk sulphur removal step followed by a polishing step. A phased investment approach would also reduce capital expenditure as capital is only spent when required. By realistic assessment of the project development and the inclusion of appropriate civil work and tie-ins, investment can be delayed, cash flow improved and, in some instances, unnecessary capital expenditure avoided. Operators can also benefit by taking advantage of ongoing process and product improvements.
Vince Atma Row is a Chartered Chemical Engineer with experience in the ammonia, methanol and gas processing industries. He also holds an MBA from Durham University. Over the past 15 years he has held a number of roles in process design, technical/production management and was until recently the Gas Processing Business Development Manager for Johnson Matthey in the Middle East and Africa. He is currently the Global Product Manager for the Gas Processing and Refineries
business of Johnson Matthey Catalysts and is responsible for new product development for the H2S polishing and mercury removal markets.
Kevin Robinson graduated from the University of East Anglia in 1997 with a BSc Honours degree in Chemistry. Since graduating he has worked in a variety of sales and marketing roles in the speciality chemicals and catalysts markets offering products and services in the personal care, industrial care, polymer and oil and gas industries. He joined Johnson Matthey in 2005 and is currently the Technical Sales Manager for the Gas Processing business of Johnson Matthey, with responsibility for
the sales and marketing of H2S polishing and mercury removal absorbents into the Middle East and Africa.
A conventional acid gas removal plant uses a solvent to trap the acid gases at ambient or a lower temperature and the solvent is regenerated in a reboiler. The absorption is carried out at pressure in a packed column and regeneration is carried out at close to atmospheric pressure in a stripping column. Figure 1 shows a typical acid gas removal flowsheet.
Johnson Matthey have developed a range of high capacity absorbents
that use the high rate of reaction H2S with activated metal oxides for its complete removal. H2S + metal oxide = metal sulphide + H2O
Gas Sweetening with Combined Amine and Fixed Bed Absorber
A combined activated-MDEA, TEG dehydration and fixed bed
polishing system was installed in Europe to remove H2S down to <3.3 ppmv, while simultaneously controlling sales gas CO2 content to <4 % (see Figure 2). The plant was designed to process any of
four different feed gases or a mixture. Inlet concentrations of H2S varied from 2–50 ppmv, while the CO2 level in the feed gas ranged from 4.5–10.5 %. The aMDEA absorber was only designed to handle the fraction of full production gas flow that, when combined with
the gas bypassing the absorber, yields the required sales gas CO2 content. This gas must be polished to bring it within H2S specification. The absorber is also provided with multiple injection points so that at low production rates all the gas can be processed
through the absorber to remove H2S while not exceeding the required removal of CO2.
The PURASPECJM fixed bed technology for H2S removal can also be integrated with a membrane unit to offer significant flexibility in plant operations. A gas processing facility in Australia processes
raw gas that contains 5–6 % CO2 and 8–10 ppmv H2S and which necessitates some treatment before transmission down a dedicated pipeline to an industrial customer. The first purification stage is a carbon bed to remove polycyclic aromatics to prevent fouling of downstream membrane materials. This is followed by the membrane
separator that produces a permeate stream rich in CO2, which is burned, while reducing the CO2 in the product stream to less than the 4 % specification. The membrane unit also reduces the H2S to 5–6 ppmv but further removal is needed to achieve the product specification of <3.2 pmv. This is provided by a fixed bed unit, which
has been in service since 1993. H2S is completely removed from gas passing through the absorbent beds and the bypass valve is adjusted to ensure that export gas always meets specification while absorbent consumption is minimised. Typically 35–40 % of the gas stream is treated. The operation has been reliable and trouble-free,
32 © TOUCH BRIEFINGS 2011
Sulphur
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