Enhanced sulphur recovery from lean acid gases
A preferred acid gas enrichment scheme is combined with two gas-treating schemes to examine the lifecycle cost of a sour natural gas treatment facility
Angela Slavens and Justin Lamar, Black & Veatch
Djordje L Nikolic and Theo Brok, Shell Global Solutions International
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The exploitation of increasingly difficult natural gas reserves has risen in recent years, requiring the removal of a number of harder to remove sulphur species, as well as H2S, CO2 and H2O. In addition, maximum limits for sulphur content in pipeline gas continue to tighten. As a result, the treating requirements for gas field development projects have significantly increased in complexity, often requiring a combination of process steps and units. As the development of difficult sour gas fields is expected to further increase in the future, strategic integration of various gas-treating process units is necessary to achieve an overall optimised flow sheet with lowest lifecycle cost. The ability to combine technologies and process units in the optimum configuration results in a competitive advantage for addressing challenges and opportunities posed by undeveloped sour gas fields.
In 2010, a study by Black & Veatch compared several alternative Claus sulphur recovery unit (SRU)/tail gas-treating unit (TGTU) configurations for achieving high sulphur recovery and reliable operation from lean acid gas containing high concentrations of carbonyl sulphide (COS) and mercaptans. The lean acid gas stream that was used as the basis for comparison of the process configuration test cases had an H2S concentration of 25 mole% and an organic sulphur concentration of 1 mole%. The study noted that a lean acid gas stream such as this could be produced from sweetening natural gas with a high COS/mercaptan content and affirmed that, at such a low H2S concentration, reliable Claus unit operation can be difficult.
The 2010 study considered the use of the acid gas enrichment (AGE) process to increase acid gas H2S concentration, as a means to alleviate the problems associated with the lean acid gas feed to the Claus SRU/TGTU. It also addressed the fact that the conventional AGE processing scheme cannot achieve high sulphur recovery when COS and mercaptans are present, due to the fact that selective treating solvents commonly utilised for acid gas enrichment do not absorb these organic sulphur species and allow them to slip to the incinerator. Several acid gas enrichment processing schemes were compared, and it was concluded that when acid gas COS/mercaptan levels are high enough to reduce sulphur recovery with conventional acid gas enrichment below an acceptable level, an alternative enrichment design configuration should be considered.
The purpose of the previous study was to compare alternative acid gas enrichment processing schemes for a given lean acid gas stream composition and flow rate, but not to consider the impact that the upstream acid gas removal unit (AGRU) solvent selection can have on the acid gas quality. However, in most situations, it is important to consider the overall sour gas treatment flow scheme rather than simply evaluating the acid gas processing in isolation, as synergies often exist between the various processing units (AGRU/AGE/SRU/TGTU) that provide opportunities for optimisation of the overall flowsheet.
This article compares three different Sulfinol AGRU options for development of the overall flow scheme for treatment of a sour natural gas stream containing significant quantities of organic sulphur (methyl and ethyl mercaptan). Although COS was an â€¨additional organic sulphur compound considered in the 2010 study, it would typically not be present in acid gas from the overhead of a chemical amine solvent or hybrid chemical/physical solvent regenerator. This is primarily due to the fact that absorbed COS is hydrolysed to H2S and CO2 in the solvent regeneration step of the AGRU. All Sulfinol solvents remove COS to a large extent in the main absorber of the AGRU. With Sulfinol-X, deep removal of COS can be achieved due to the presence of piperazine, which enhances COS hydrolysis. With Sulfinol-M, most of the COS would be absorbed due to the larger number of trays employed. Since Sulfinol is a hybrid chemical/physical solvent, for the reasons described above, COS captured in the absorber will not be present in the acid gas. Therefore, it is anticipated that the small variations of COS in the sales gas and treated flash gas would not be a differentiator between the three cases studied in this article; hence, COS has been omitted from the analysis.
The resulting acid gas from each AGRU configuration is processed utilising some of the acid gas treatment schemes presented in the 2010 article. The optimum configurations, in terms of relative Capex and Opex, are presented.
The sour natural gas stream used for comparison of the various process configuration test cases is shown in Table 1. Sulphur content is 96.1 t/d. About 2% of the acid gas sulphur is present as mercaptans; therefore, recovery of mercaptan sulphur is important if high sulphur recovery is to be achieved.
The treated gas specifications used for the comparison test cases are shown in Table 2. The specifications considered are typical for pipeline-quality natural gas. Table 3 and Table 4 describe the three process configuration test cases compared in this article, each of which is illustrated in Figures 1–3.
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