Time to prepare for the new marine fuel sulphur specifications is rapidly running out for refiners. Many residue conversion options are available, including quick-win solutions. For example, the Shell Claus off-gas treating (SCOT1) ULTRA process offers the potential to increase sulphur recovery unit (SRU) capacity by up to 30% quickly and without capital expenditure, while cutting tail gas treating unit operating costs by up to 50%.

Few shipping operators are investing in expensive bulky on-board sulphur scrubbers with their associated sludge retention and disposal facilities. Instead, they are expecting refiners to provide fuels that will meet the International Maritime Organization’s (IMO) global 0.5% cap for sulphur content in marine fuel set to come into force in 2020. Compliance will be a major disruptive change, one that could be either a threat to the profitability of your refinery or, with the right preparation, an opportunity.

There are many ways to reduce the sulphur content of the bottom of the barrel. You could process lower-sulphur crudes or blend in high-value distillates, but these options are economically unattractive. Burning high-sulphur fuel oil on-site in utility boilers is another option, but this creates local emission challenges. That leaves a range of technology solutions for increasing residue conversion. The question is how can you take sulphur out (i.e., increase sulphur processing) in an affordable manner and before 2020?

Time, cost and plot-space constraints may preclude some new-build and revamp options, but there are low-cost solutions that you could implement quickly to safeguard your competitive position.

In this article, we consider enhancing capacity in an existing SRU by increasing the front-end pressure (Option 1); through increased oxygen enrichment (Option 2); or a combination of both (Option 3). We will only consider the SRU and assume that the solvent flow system has an additional 10% capacity and that an oxygen supply for low (up to 28%) oxygen enrichment is achievable.

Our example uses the SRU feed gas composition and parameters from a Shell refinery.2 The SRU line-up includes indirect heating (steam reheating) with two Claus catalytic reactors; the SCOT unit uses a formulated methyl diethanolamine (MDEA) solvent. The SRU has a thermal incinerator that operates at 650°C and uses a Shell sulphur degassing system to achieve a <10-ppmw hydrogen sulphide (H2S) specification in liquid sulphur.

Options 1 and 2 are feasible for a high (250-mg/Nm3) sulphur dioxide (SO2) emissions regime, but not Option 3, as it demands more than the assumed maximum solvent flow (Table 1). Option 2 achieves 120% SRU capacity. The modest (102%) 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. Only Option 2 remains feasible when a low (150-mg/Nm3) SO2 emissions limit is applied, and gives 120% SRU capacity with 105% solvent flow.

However, the development of the Shell SCOT ULTRA next-generation tail gas treating process can transform the situation by offering a performance step change with minimal investment.

In most cases, you only need a simple swap to the highly selective JEFFTREAT3 ULTRA solvent, which was developed jointly by Shell and Huntsman Corporation, and a change to Criterion Catalysts & Technologies’ C-834 high-activity, low-temperature SCOT catalyst, without hardware alterations. The new solvent can achieve deep decreases in H2S emissions while maximising CO2 slippage; absorbs H2S at higher temperatures compared with MDEA, which eliminates the need for a solvent refrigeration system; and provides robust performance compared with formulated MDEA, even with line burner/fuel gas co-firing designs, as it handles CO2 better. The new catalyst increases the destruction of organic sulphur compounds at low operating temperatures.

Table 1. Upgrade option feasibility.

Option Variables Capacity, %base SO2 emissions: 250-MG/NM3 : Solvent flow, %base SO2 emissions: 250-MG/NM3 : Feasibility SO2 emissions: 150-MG/NM3 : Solvent flow, %base SO2 emissions: 150-MG/NM3 : Feasibility
1 Increase front-end pressure 110 110 Yes 113 No
2 Low-level oxygen enrichment 120 102 Yes 105 Yes
3 Both 1 and 2 130 115 No 118 No

Table 2. Upgrading with the SCOT ULTRA process.

Option Variables Capacity, %base SO2 emissions, MG/NM3 Solvent flow, %base Feasibility
1 Increase front-end pressure 130 250 72 Yes
2 Low-level oxygen enrichment 110 150 73 Yes
3 Both 1 and 2 130 150 75 Yes

In this example, Option 1 with the SCOT ULTRA process achieves 130% SRU capacity with only 72% of the solvent flow for the high SO2 emissions regime (Table 2). Option 3 is also feasible with 130% SRU capacity and 75% solvent flow for the low SO2 emissions regime.

Further analysis shows that using the SCOT ULTRA process in a new tail gas treating unit for a Middle East SRU has the potential to cut a 25-year life-cycle cost to 71% of the equivalent cost using formulated MDEA without cooling.4 In this case, operating costs are halved.

The SCOT ULTRA process is one of a suite of technical solutions with the potential to help turn IMO 2020 to your advantage. If you have not already begun to prepare, the SCOT ULTRA process may represent a quick way to boost sulphur recovery while cutting operating costs.

Key takeaways

  • IMO 2020 specifications mean that high-sulphur fuel oil may soon be worth less than crude oil.
  • A suite of bottom-of-the-barrel sulphur recovery options is available, including a range of brownfield solutions for increasing sulphur-processing capacity.
  • The Shell SCOT ULTRA process is a solution that can be implemented quickly through a solvent and catalyst swap, without hardware changes in most cases, to help you to debottleneck SRU capacity with low oxygen enrichment.
  • The Shell SCOT ULTRA process can cut solvent circulation to 70–75% of the base design, which can potentially reduce operational costs by 50%, mostly through lower reboiler duty (steam consumption).

1 SCOT is a trademark owned by the Shell group of companies.

2 Amine acid gas at 50°C, 0.75 barg and 100 t/d, composed of 95.5 mol% H2S, 4.05 mol% carbon dioxide (CO2) and 0.45 mol% hydrocarbons, and sour water stripper acid gas at 80°C, 0.8 barg and 15 t/d, composed of 62.4 mol% H2S, 2.4 mol% CO2, 34.4 mol% ammonia and 0.8 mol% hydrocarbons (dry basis).

3 JEFFTREAT is a registered trademark of Huntsman Corporation or an affiliate thereof in one or more, but not all countries.

4 Analysis based on a Middle East refinery with a 220-t/d capacity SRU that needs a new tail gas treating unit with a 25-year life to handle an absorber feed gas with 2.5 mol% H2S and 0.8 mol% CO2. The treated gas must have <200 ppmv H2S to meet a 500-mg/Nm3 SO2 emissions limit. Low- and high-pressure steam costs $3.6/t and $5.8/t respectively, and power costs $0.035/kWh. The cost of cooling the solvent from 60 to 42°C is $0.05/m3.

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