Decarbonisation Technology May 2022 Issue

improve recovery. If recovery is below desired performance, additional membrane modules can be added in series or parallel to improve ultimate recovery. Naturally, the ‘permeate’ stream of heavier hydrocarbons is not simply wasted. These can either be sent to an existing heavy hydrocarbon stream or additional liquefied petroleum gas (LPG) recovery system to ensure they are economically recovered. In some cases, they can be recycled back to the process as depicted in Figure 4 , depending on the unit operations available to further separate these compounds. Depending on the local market, this stream could be sold directly, either as a cheaper feedstock or it could be mixed into a mixed condensate/natural gas liquid. Available markets and disposition One challenging aspect of planning gas recovery projects is that no two processing facilities are exactly alike, and the composition of the gas streams could necessitate entirely different solutions or commercial arrangements to monetise the opportunity fully. Even as carbon markets develop, ‘negative cost’ carbon abatement projects still require revenue streams from selling or moving product out of fuel gas into another product. There are myriad options out there to best monetise ‘heavy hydrocarbons’, though a few key examples are listed: • Gas plants with nearby pipeline infrastructure – pipelines are often the cheapest and easiest way to ship out liquefied petroleum gases, and if all compounds can be sold as a combined natural gas liquid or mixed condensate, then the avoidance of additional fractionation capacity can significantly reduce Capex • Gas streams with high olefins or branched compounds – olefins and branched molecules have value, and it is often economical to install additional infrastructure to meet local or international pure compound quality specifications. Refineries may also have uses for these molecules in alkylation or other octane boosting units • Chemical complexes – this is one of the few complexes where separating out the ethane makes sense. There is a market for ethane, but it is often most profitable to be used directly via ethane cracking/chemical value chains. Otherwise, ethane is usually left in the fuel gas stream.



Feed gas



TEG unit





Slip stream to membranes

Mem inlet

Cond. fuel




To engines

Filter coalescer



Membrane skid



exchangers, debutaniser bottoms used as de- ethaniser reboiler heat). Replacing only 450 kg/h of 1,000 kPa steam production can save near 750 TPA of CO 2 emissions while reducing overall project cost Lastly, membrane and other solid medium transport technologies represent a generally more energy-efficient, smaller footprint method for fuel gas conditioning. Although it is tough to obtain the same level of C 2 + recovery with a membrane-based system as with a cryogenic unit, these systems can be modularised and scaled to treat only a fuel gas stream for a facility, whether small or large. This makes the technology useful for facilities small and large, whether complex refineries or remote drilling sites. Membranes work via a principle called selective permeability, with ultimate separation being a function of the membrane material, solubility of the gas components in that material, the differential process pressure across the membrane, and the surface area/ size of the membrane itself. In Figure 4 , a fuel gas slipstream is depicted being sent to the membrane system, where a high differential pressure and selective spiral wound membrane separates impurities, including H 2 S, CO 2 , propane and heavier molecules, from the fuel. The pressure drop and membrane surface area can be most easily manipulated to Figure 4 Depiction of membrane unit module on a facility fuel gas ‘slipstream’


Powered by