PTQ Q3 2022 Issue

Rather than relying on an incremental yield analysis, a 14 C yield analysis should be used (and in many cases is required) to validate the renewable content of the final product for any economic incentives/credits. Corrosion mechanisms With changes to bio-oil feedstocks from traditional petro- leum feedstocks, expected damage mechanisms are likely to change. These changes can include new damage mecha- nisms that were not previously expected, increased severity of corrosion (i.e. high corrosion rates), or a higher likelihood of environmental cracking. Within hydrotreating units, there are two particular areas of concern: feed and reactor effluent. In diesel and heavier hydrotreating units, naphthenic acid corrosion can occur but is generally seen to not be severe in the feed system. Additionally, once hydrogen has been added to the hydrocarbon feed, naphthenic acids are not considered to cause corrosion within feed equipment. To complete the discussion, naphthenic acids are destroyed in the hydrotreating process. Many bio-oil feedstocks have a ‘free fatty acid’ (FFA) con- tent to measure different carboxylic acids with the feedstock. The amount of FFA in a typical corn oil feedstock is much greater than typical naphthenic acid in petroleum feedstocks when compared by titration. Anecdotal evidence has shown potential for free fatty acid corrosion to occur in the reactor feed system both before and after hydrogen has been added. It is also pos- sible for FFA corrosion to occur at lower temperatures than naphthenic acid. Currently, FFA corrosion from bio-oil feeds is under investigation to quantify the potential for acceler- ated corrosion. The second area of particular concern for hydrotreating units is the reactor effluent system. Ammonium chloride and ammonium bisulphide are still primary corrodents in the reactor effluent but can vary as the amount of sulphur and nitrogen are very different between different bio-oil feeds. Additionally, due to the increase in oxygen with bio-oil feeds when compared to petroleum feeds, carbon diox- ide (CO 2 ) content is typically much higher than traditional hydrotreaters. Ammonium carbonate, ammonium bicarbon- ate, and ammonium carbamate become new corrosion and fouling concerns. Another important consideration is water content increase in the effluent due to increased water formation during the hydrotreating reaction. When considering these bespoke points, the dew point and salt point in the system are likely to have a different morphology and location than expected in hydrodesulphurisation. This can lead to corrosion and fouling in different locations than the prior operation in revamped units. Current water wash locations and amounts would need to be studied to determine effectiveness. Furthermore, in the reactor effluent system, additional water from the reaction section may create water separa- tor issues, including water boot and drain valve size. Water carryover may be a start-up issue in a retrofitted unit. Water may be more acidic than alkaline due to higher CO 2 con- centrations and lower ammonia generation. Acid sour water is likely to have a different morphology than alkaline sour

Heat

Hydrogen

R enewable product

T all oil

P yrole oil

FCCU or pyrolysis

Reaction section

Figure 5 FCC unit or pyrolysis

requiring further processing for transportation fuels but is suitable for direct combustion. H₂ demand increase and H₂ supply options With the expected expansion of renewable feed process- ing, there is an anticipated increase in the required hydro- gen generation from the current capacity of 3 billion scf/day to 11 billion scf/day. In order to reduce net CO 2 footprint, there is a drive to shift hydrogen generation to lower emission technologies (see Figure 6 ). Grey hydrogen is generated from fossil feeds and results in significant CO2 emissions (often from steam methane reforming, SMR) and is least preferred. Blue hydrogen is SMR produced hydrogen but with car- bon capture and sequestration added to reduce the CO 2 emissions anywhere from 30 to 80%. Green hydrogen is from water electrolysis with power from renewable sources (wind, solar, tidal) and is one of the preferred options. Red hydrogen is from electrolysis with power from nuclear-produced electricity. Estimating biofuel credits Obtaining full credit for the biofuel content in fuels is usu- ally a significant economic consideration in processing renewable feeds. However, when co-processing a modest amount of renewable feed, the typical refinery yield analysis on an incremental basis will not give an accurate measure of the biofuel content of the final product. The lack of accuracy is a result of the increased tempera- ture of hydrotreating (caused by the high oxygen content and reduced hydrogen partial pressure due to higher hydro- gen consumption). This results in base feed yield losses due to cracking/gas make that will get allocated to the renew- able feed in a normal incremental yield analysis.

+ –

4H + 4e

Anode 2HO

O +

4H + 4e

Cathode

Hydrogen

Oxygen

H +

Membrane

Figure 6 Electrolytic hydrogen

PTQ Q3 2022