Analysis: Brownfield options in bottom-of-the-barrel sulphur processing

This is a major challenge for refiners. Five possible responses would enable refiners to meet the new IMO specifications: (i) process more-expensive, lower-sulphur crudes; (ii) blend in high-value distillates; (iii) make a loss on high-sulphur fuel oil, which would be worth less than the crude oil feed; (v) burn high-sulphur fuel oil on-site in utility boilers; and (v) invest in residue conversion.

The economic penalties of the first three options are clear and the fourth option creates local emission challenges. That leaves residue conversion. The question is how can we take sulphur out (i.e., increase sulphur processing) in an affordable manner?

Adding or upgrading?

The simplest solution would be to add new sulphur recovery unit (SRU) trains. With the IMO specifications coming into play in just two years, any new trains would need to be copies of the existing train and implemented immediately. However, the low oil price makes justifying capital expenditure difficult and refineries may not have plot space near the SRU trains.

So, what is the alternative? Can we make better use of the existing facilities? Capacity in the existing SRUs can be enhanced by increasing the front-end pressure or through increased oxygen enrichment or a combination of both (this article considers only the SRU and assumes design margins in the upstream amine unit). Let us consider an example.

Brownfield case study

A case study looking at brownfield SRU capacity increase options has been developed using the composition and parameters of the amine and sour water stripper acid gases that feed an SRU at a Shell refinery (Table 1).

In this example, the SRU line-up includes indirect heating (steam reheating) with two Claus catalytic reactors. Formulated methyl diethanolamine (MDEA) solvent is used in the SCOT unit. The unit is equipped with a thermal incinerator that operates at 650°C and there is a Shell sulphur degassing system to achieve a <10-ppmw H2S specification in liquid sulphur.

The brownfield modifications considered assume that the solvent flow system has an additional 10% capacity and that oxygen supply for low (up to 28%) oxygen enrichment is achievable.

Table 2 compares three options, assuming a high (250-mg/Nm3) sulphur dioxide (SO2) emissions regime. Option 1: Higher front-end pressure, would increase capacity to 110% of the base case and requires 110% solvent flow, which is feasible within the assumed boundaries. Option 2: Low-level oxygen enrichment, would give 120% capacity with 102% solvent flow, which is also feasible. The modest solvent flow increase is because the oxygen enrichment also means less volumetric flow through the SCOT absorber with lower nitrogen content and consequently only a minor H2S column load increase. Option 3: However, combining increased front-end pressure and low-level oxygen enrichment would be unfeasible, as it would require 115% solvent flow – 5% more than the assumed maximum.

For a low (150-mg/Nm3) SO2 emissions regime, the solvent flow required for options 1 and 3 are 113 and 118% respectively, which leaves low-level oxygen enrichment as the feasible option for 120% SRU capacity with 105% solvent flow. However, now there is a fourth option with the potential to deliver up to 130% SRU capacity with substantially lower operating costs and without hardware changes.

Increasing SRU capacity

The Shell SCOT ULTRA process offers a step-change in the performance of the well-established SCOT process. It features Shell and Huntsman Corporation’s jointly developed highly selective JEFFTREAT2 ULTRA family of solvents, which can achieve deep decreases in H2S emissions while maximising carbon dioxide (CO2) slippage.

It also absorbs H2S at higher temperatures compared with MDEA, which eliminates the need for a solvent refrigeration system – an additional cost in hot climates such as in the Middle East.

The process provides robust performance compared with formulated MDEA, even with line burner/fuel gas co-firing designs, as it handles CO2 better.

It also features Criterion Catalysts & Technologies’ C-834 high-activity, low-temperature SCOT catalyst, which adds further value by increasing the destruction of organic sulphur compounds at low operating temperatures.

The process potentially offers an easy and cost-effective upgrade of existing units. In most cases, a simple solvent and catalyst swap is required without additional hardware changes.

In this example, the SCOT ULTRA process would enable Option 1 (increased front-end pressure) to achieve 130% SRU capacity with only 72% of the solvent flow for a 250-mg/Nm3 SO2 emissions regime (Table 3). It also makes Option 3 (increased front-end pressure and low-level oxygen enrichment) feasible with 130% SRU capacity, with 75% solvent flow for a 150-mg/Nm3 SO2 emissions regime.

Let us consider a refinery in the Middle East with an SRU that needs a new tail gas treating unit (TGTU) with the following specifications and economics: TGTU capacity – 220t/d (cooling 42°C and no cooling 60°C); TGTU absorber feed gas: 2.5mol% H2S, and 0.8mol% CO2;    <200 ppmv H2S absorber treated gas to meet a 500-mg/Nm3 SO2 emissions limit; low-pressure steam $3.6/t; high-pressure steam $5.8/t; cost of utilities $0.05/m3; power $0.035/kWh; and 25-year life. In this case, the life-cycle cost            of using the SCOT ULTRA process is 71% of the cost of using formulated MDEA without cooling (Figure 1).

Is higher capacity possible?

Increasing SRU capacity beyond 130% is possible. Processing capacity can be increased with high oxygen enrichment. This leads to an increased reaction furnace temperature and that can be the limiting factor.

Increasing the amount of sulphur processed as SO2 by 1% can reduce the volume of air necessary and lower the reaction furnace temperature by 10-20°C. However, finding SO2 streams can be challenging – most are unsuitable, have dust contamination and are dilute flows.

The Shell CANSOLV1 SO2 Scrubbing System offers a potential solution by providing a debottlenecking SO2 feedstock. Some of the SRU’s acid gas feed is diverted to the tail gas incinerator (intended to be recycled as SO2).

The Shell CANSOLV SO2 Scrubbing System is installed downstream of the tail gas incinerator. It uses regenerable solvent to capture SO2 selectively in an absorption column.

Low-pressure steam is then used to strip SO2 from solution in a regeneration column and the solvent is returned to the absorption column. A stream of pure, water-saturated, gaseous SO2 is then sent to the thermal section of the SRU, where it reduces the reaction furnace temperature and thus enables SRU capacity to be increased through high oxygen enrichment. However, there are also other considerations beyond the scope of this article.

The advantages

Impending IMO global sulphur specifications mean that high-sulphur fuel oil may soon be worth less than crude oil. There are different bottom-of-the-barrel sulphur recovery options available, including a range of brownfield solutions for increasing sulphur-processing capacity. Shell has a suite of technologies that can help, as no single solution will be right for every situation.

The Shell SCOT ULTRA process is an attractive option that can help to debottleneck SRU capacity with low oxygen enrichment. The process can be implemented through a solvent and catalyst swap, and without hardware changes in most cases.

It reduces solvent circulation to 70-75% of the base design, which can potentially translate into 50% lower operational costs, mostly through lower reboiler duty (steam consumption). The SCOT ULTRA process provides robust performance compared with formulated MDEA, even with line burner/fuel gas co-firing designs.

The Shell CANSOLV SO2 Scrubbing System can help to deliver high oxygen-enrichment upgrade options with the potential to increase SRU capacity to over 130%.