Decarbonisation Technology May 2022 Issue

The much leaner fuel gas stream is representative of that found from conditioned process gas in an oil refinery, with membrane or cryogenic processing pretreatment to remove almost all the C 3 + and much of the ethane/ ethylene content. The resulting reduction in furnace CO 2 emissions is on the order of ~6% or near 6,700 tonnes per year of CO 2 . The impact can be significant depending on the particulars of the plant configuration. The emissions reduction above is compounded across many process heaters in the facility since they typically draw from the same fuel gas source or header. For demonstration purposes, two similarly sized crude unit feed furnaces and a corresponding delayed coker could see an emissions reduction of roughly 45,000 tonnes per year of CO 2 , with the same change in fuel composition as above. This does not include any other support fired heaters or gas-fired steam generators required to operate these units. Example process schema and available technologies Many available technologies and processes can be used to recover these heavier molecules from natural gas streams, with their typical recoveries presented in Table 2 . In most cases, cryogenic separation plants are already designed for near-maximum recovery of ethane, while improved recovery is possible through operational changes or modest upgrades. Cryogenic separation uses a combination of refrigeration (often with propane) and a large pressure drop followed by separation in a demethaniser column. Pressure reduction occurs with a machine called a turboexpander to cool the gas to -85°C or lower, removing much of the ethane. Conversely, refrigeration with propane for dewpoint control cools a gas stream to near -35°C to remove almost all C 3 and heavier molecules. Although it is difficult to improve this process further, the following are some ideas for better C 2 + recovery or energy efficiency overall: • Lower demethaniser pressure – the higher the pressure drop across the expander, the lower the demethaniser operating temperature will be, resulting in improved recovery • ‘Re-wheeling’ the turboexpander – in many cases, the expander is not operating in its most

Component (dry basis)

Rich refinery Lean refinery fuel gas (mol%) fuel gas (mol%)

Methane

55% 25%

80% 10% 0.5%

Ethane/ethylene Propane/propylene

8% 3% 1% 6% 2%

Butane/Iso-butane/C 4 olefins

0% 0% 9% 3%

C 5 +

Hydrogen

Other Impurities (CO 2 , N 2 , etc.)

industrial carbon emissions at 52%, according to the EPA. With new incentives for carbon emissions reduction, along with changing and tightening markets for many commodities compared to the prevailing market conditions when many facilities were built, recovering these heavy molecules from the natural gas stream leads to profitable reductions in scope 1 carbon emissions. As one demonstration of this, two natural gas streams were modelled in Aspen HYSYS as fuel for a conventional furnace, with a process line-up as shown in Figure 2 . The furnace in this model represents the fired heater at the front of a crude distillation unit processing 4.8 MTPA, heating this crude from 230°C to 340°C. The stream compositions and the resulting emissions for the same overall energy consumption are shown in Figure 2 . The detailed stream compositions are shown in Table 1 . Table 1 Dry compositions of the two different fuel gas streams modelled with Aspen HYSY

Gas recovery process

Typical target recoveries

technology

Lean oil absorption

Ethane rejected >60% C 3 recovery 90% C 4 recovery >95% C 5 + recovery ~40-70% C 2 recovery 70-90% C 3 recovery >95% C 4 + recovery

Membrane separation

Cryogenic separation or refrigerated dewpoint

Can be designed for ethane rejection (dewpoint control)

control process

70% C² recovery 95% C³ recovery ~100% C 4 + recovery

Table 2 Example gas recovery technologies and typical recovery performance