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HighSulf enhances conventional tail gas treatment

Recently, a new family of HighSulf amine-based desulphurisation strategies has been introduced into the patent and technical literature, with several patents devoted to the HighSulf TGTU.

Tofik K Khanmamedov, TKK Company
Ralph H Weiland, Optimized Gas Treating, Inc
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Article Summary
This new process actually enhances the well-known SCOT process, uses identical equipment and requires almost no additional capital investment. The beauty of HighSulf is its simplicity, and any existing SCOT type unit can be switched easily to HighSulf. Moreover, any HighSulf TGTU can be returned to conventional treating without shut down or modification of the unit. This technology has been substantiated via computer simulation using several commercial software packages. In the present article we use the ProTreat process simulator to discuss several cases of both the original and extended HighSulf TGTU process strategies. A comparison of different versions of HighSulf TGTU is made, focusing mainly on the SRU’s amine section using generic N-methyldiethanolamine.

The SCOT (Shell Claus Off-gas Treating) process, first utilised commercially in California refineries in 1973, has become one of the standard treatments, allowing reduced sulphur emissions in the tail gas from Claus sulphur recovery units (SRUs). This technology has been applied extensively worldwide using a variety of solvents that selectively remove H2S in the amine section of the tail gas treating unit (TGTU). Since its inception, the technology has remained relatively static in terms of the philosophy of designing TGTUs. However, there is demand for improvement of this process in terms of efficiency and reduction of operating cost. In this article we discuss a new patented strategy for the amine section of TGTUs that is known in the market as the HighSulf process (Khanmamedov, 1995, 1996, 1998a, 1998b, 1998c, 2000, 2002, 2003).

Conventional and HIGHSULF TGTU Flowsheets

In a conventional TGTU (Figure 1) with reduction and amine sections, the tail gas from the SRU is heated by the combustion products generated by burning fuel gas under sub-stoichiometric conditions to generate the reducing medium, hydrogen. The heated- tail-gas and reducing-gas mixture is fed to a catalytic reactor containing Al-Co-Mo type of catalyst. In the reactor all sulphur species (S6, S8, SO2, COS, CS2 and partially CO are hydrogenated and converted to H2S and CO2). Some of the COS and CS2 is hydrolysed to H2S and CO2. The effluent of this catalytic reactor has roughly 600°F and is used to produce about 50 psig steam in a waste heat boiler (WHB). Gas then enters a water quench tower where it is cooled to 100–130°F. Quench water goes to the refinery sour water stripping system (SWS). Cooled gas now enters the amine section of the TGTU where H2S is selectively removed by using a selective amine such as N-methyldiethanolamine (MDEA) or a hindered amine. High selectivity is paramount because ensuring a high level of CO2 rejection is essential to minimize the flow rate of acid gas through the sulphur plant and to maximise its H2S content. The acid gas from the regenerator is recycled back to the SRU. A conventional TGTU can be designed for a wide range of sulphur concentrations in the overhead from the absorber (an H2S leak of up to 350 ppmv of H2S). On the other hand, if the H2S leak cannot be reduced by conventional means to a satisfactory level (as determined, for example, by local emission standards) other approaches such as amine stripping promoters or speciality amines, can be used.

The main problem in many gas plants is a low concentration of H2S and quite high concentration of CO2, i.e., raw gas with low H2S to CO2 ratio. This leads to extremely high CO2 levels in SRU tail gases. And as a result, the gas from TGTU that is recycled and sent back to the SRU has high volume fraction of ballast CO2. This dilutes the fresh feed to the SRU which is quite detrimental to sulphur plant performance. Also, the high volume of CO2 in the acid gas from the TGTU increases hydraulic load on the SRU. The quality of the acid gas from a TGTU is directly related to the H2S to CO2 ratio of the gas feeding it. If the H2S:CO2 ratio is low, the acid gas produced will also have a low H2S:CO2 ratio. If it is high in the feed gas it will also be high in the product. The new family of HighSulf strategies recognises this very important fact and takes steps to increase the H2S:CO2 ratio in the TGTU feed gas.

The following figures show two alternative flowsheets to conventional treating; Figure 2 shows HighSulf tail gas treating as it appears in the patent and technical literature. As can be seen, a HighSulf TGTU uses same equipment as the conventional TGTU.

The SRU tail gas flows to the same heater, hydrogenation/hydrolysis reactor, produces steam in the same WHB, is cooled in the same quench tower and then feds the amine section. H2S is recovered in the amine section using on the same MDEA solvent under identical operating conditions. Rich amine is sent from the absorber to the regenerator for reboiled stripping at the identical rate of energy consumption. The key element of HighSulf is that the acid gas to the absorber is enriched in H2S by recycling a portion of the acid gas from the regenerator back to the front end of the absorber where it is mixed with the fresh tail gas coming from the quench tower. This so-called HighSulf line automatically brings very significant advantages to the process, similar to the Acid Gas Enrichment cases described elsewhere (Khanmamedov and Weiland, 2008; Weiland and Khanmamedov, 2010).

This new HighSulf strategy has inspired others to extend the use of this simple concept for amine units. For example, Palmer (2005, 2006) suggests introducing absorber feed gas and recycle gas at different places in the common absorber instead of mixing the two gases together and introducing them as a single acid-gas feed. The concept and strategy are very similar — the objective is to create absorber conditions such that the absorber is seeing a gas phase much richer in H2S. This allows it to send a rich amine more heavily loaded in H2S (and more lightly loaded in CO2) to the regenerator, and the regenerator then produces an acid-gas feed much richer in H2S to the SRU at a lower total volume flow rate. We consider this as an extended use of HighSulf with two feeds to the absorber and will discuss its application for TGTU (Figure 3).

Comparing HighSulf and conventional tail gas treating
The approach to comparing these schemes is through accurate process simulation. The tool we have chosen to use is the ProTreat simulator. This uses a mass and heat transfer rate based column model that takes full account of the effect of column internals and hydraulics, vapour-liquid equilibrium and chemical reaction kinetics on the actual performance of both absorbers and regenerators. It uses the actual number and design of trays and the actual depth of real packing (random and structured) in the columns as they are truly built. All calculations are done on real trays and packing, not theoretical stages.
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