Decarbonisation Technology May 2022 Issue

AGO steam Diesel steam

Atmos cond O gas

Preash vapour

Rich fuel CO emissions

Waste water

Raw crude


Molar ow 2790 Master comp mass ow (CO) 12462.6891

kgmole/h kg/h


Atm feed

Rich fuel CO emissions Steam out Superheated steam out

Pre sh liq

Condensate inj


C kPa kgmole/h

232.2 517.1 2042



Molar ow Mass ow

Steam in


kg/h 5.134e+005


Hot cude

Pre sh liq

Rich fuel furnace


Rich fuel gas stream Air



Main steam


Lean fuel CO emissions

Rich fuel gas stream

Molar ow 2840 Master comp mass ow (CO) 11698.4229

kgmole/h kg/h


C kPa kgmole/h

30.00 200.0


Molar ow Master comp mole frac (Ethane) Master comp mole frac (HO) Master comp mole frac (Hydrogen) Master comp mole frac (i-Butane) Master comp mole frac (Methane) Master comp mole frac (n-Butane) Master comp mole frac (CO) Master comp mole frac (Nitrogen)

0.2480 0.0200 0.0580 0.0140 0.5480 0.0150 0.0090 0.0090 201.4

Pre sh liq-2

Lean fuel gas stream

Lean fuel CO emissions Steam out-2


C kPa kgmole/h

30.00 200.0

Condensate inj-2


Molar ow Master comp mole frac (Ethane) Master comp mole frac (HO) Master comp mole frac (Hydrogen) Master comp mole frac (i-Butane) Master comp mole frac (Methane) Master comp mole frac (n-Butane) Master comp mole frac (CO) Master comp mole frac (Nitrogen)

0.0825 0.0200 0.0850 0.0000 0.7800 0.0000 0.0140 0.0140 273.3

Steam in-2

Superheated steam out-2

Lean fuel furnace

Hot cude-2


Rich fuel gas stream

Figure 2 Aspen HYSYS model with feedstream compositions and CO2 emissions (rich and lean)

with the cheapest and highest priority projects on the left-most part of the graph and higher abatement cost initiatives to the right. As shown, industrial process improvements mostly have ‘negative’ abatement costs associated with them, meaning they provide positive earnings or cash for the responsible enterprise. The use of critical benchmarking, through a firm such as Solomon Associates, can provide insights that facilitate project prioritisation and further process intensification studies (Solomon Associates, 2022). Gas recovery and process heat management Although many processes fit in the ‘industrial process improvement’ bucket in Figure 1 , gas recovery is one such process employed in gas plants, large refineries, and chemical plants. Through Solomon Associates benchmarking on gas processing facilities, insights can be gained on heavy molecule recovery plant efficiency, including energy and non-energy efficiencies. Three key components that can cut scope 1 emissions significantly are the degree of heavy molecule recovery (i.e. removing propane and butane out of a heavy natural gas stream), the extent of heat integration, and the energy efficiency within a unit. Typically, these gas

recovery units are designed to economically recover some amount of propane or butane from the natural gas stream before that gas is then burned as fuel (or sold to be burned as fuel by some other entity). It is common for the overall recovery of propane to be less than 50%. In contrast, the recovery of ethane was often ignored in older facilities due to the high cost of recovery and lower margin of direct ethane sales when the facility was built. Unfortunately, the heavier the overall fuel or natural gas stream is, generally the higher its carbon intensity as a fuel. Data from the U.S. Environmental Protection Agency (EPA) report the emissions intensity in kg/MMBTU of CO 2 by hydrocarbon molecule (U.S. EPA, 2014). Natural gas, primarily methane with some residual ethane, has an emissions intensity of 53.06 kg CO 2 /MMBTU, while the emissions intensity of heavier molecules is higher; for example, butane is 64.77 kg CO2/MMBTU (JISEA, 2016). For fired heaters that demand millions of BTU per hour, such a range of intensities can lead to differences in stack emissions on the order of several thousand metric tonnes of CO 2 per year. The impact can be staggering, with overall gas and other fuel-fired process heat and steam generation representing the lion’s share of direct


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