PTQ Q2 2023 Issue

Reducing emissions through carbon capture Another way firms can reduce emissions is to implement car - bon capture, sequestration, and utilisation. To address CO 2 capture, Honeywell UOP offers an Advanced Solvent for Carbon Capture (ASCC) system. An advanced solvent allows for a higher mass transfer rate, which enables regeneration at a higher pressure, delivering CO 2 at 5-6 bar(g) instead of just 1 bar(g). As a result, the unit is smaller for lower Capex, while the higher pressure sub- stantially reduces Opex – up to $10-15 per tonne captured. Adding an advanced solvent for carbon capture to the four key stacks in a refinery that produce 93% of the CO2 emis- sions for the entire complex, we were able to reduce net CO 2 by 81% (see Figure 4 ). The economics behind CCUS are dramatically impacted by government policy. It is important to understand the regional tax benefits, carbon credits, and traded carbon market values associated with carbon capture. Another way to improve the CO 2 footprint for many refiners is to bury the petroleum coke (petcoke) produced rather than reselling it as a high-carbon fuel. Petcoke traditionally com- petes with coal in the fuel market. In a decarbonising world, governments will set coal policy. Refiners can only impact what they control, and that is the decision of whether to sell petcoke as a fuel, or to sequester that carbon in solid form. This avoids the high Scope 3 CO 2 footprint created when the eventual end user burns it and has a net cost of CO 2 avoid- ance of $10-40 per tonne. Pivoting from refined fuel products toward petrochemicals Finally, an effective strategy to increase the internal rate of return of a facility and reduce Scope 3 emissions is to con- sider a pivot from refined fuel products toward petrochemi - cals. It is not a question of immediately and forever getting out of fuels; it is simply considering a migration across time that may align with the business plan of your firm. The production of petrochemicals centres around the mixed feed steam cracker, or naphtha cracker, commonly the heart of an integrated facility’s operation. One can feed a broad range of hydrocarbons into a steam cracker, with the preferred output being ethylene. All other products, while useful, are not the primary aim of this process. In fact, while heavier products (propylene, butadiene, benzene, and mixed

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$130 NPV $120 NPV

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$20 NPV

$2 NPV

12% IRR

26% IRR

69% IRR

73% IRR

5% 10% 15% 20% 25% 30% 35% Discount rate -50

40%

30 mol% $5 Gas - $0/MT CO 50 mol% $5 Gas - $0/MT CO

50 mol% $20 Gas - $0/MT CO 50 mol% $20 Gas - $100/MT CO

Figure 3 NPV sensitivity to discount rate

How does this impact the ways in which we try to improve carbon efficiencies and operations costs? It means there is a huge argument for capturing the hydrogen that refiners have already made. Capturing stray hydrogen A survey of operating sites showed that many facilities operate in the range of 30-50 mol% H 2 in their fuel gas headers; some even higher. This is due in large part to solu- tion losses. The higher the operating pressure of a unit, such as a hydrocracker, the higher the solution and purge losses into the fuel gas. If one assumes 30 mol% H2 in the fuel gas in a region with a (low) cost of $5 per million BTUs with no CO 2 credit, you can see that hydrogen recovery can lead to a 12% IRR)(see Figure 3 ). If the hydrogen content in the fuel gas is 50 mol% at the same cost of $5, you see an IRR of 26% by recovering this grey hydrogen that is oth - erwise lost to fuel. When you move to Europe and Asia, where you typically see fuel costs closer to $20 per million BTUs, you start to see IRRs in the range of 69-73%, depending on the amount of CO 2 credit available. In a typical 100K b/d refinery, the invest - ment to recover the hydrogen you have already made is $15- $18M. The chemical value of the hydrogen so far exceeds the fuel value of the hydrogen. It is clearly worth recovering, given the IRRs previously discussed. Retrot 4 key stacks that produce 93% of complex CO emissions 1. Steam c racker 2. SMR h ydrogen p lant 3. NViro - SDA pitch and steam cracker p y o il to steam 4. Combined c ycle p ower p lant Capture additional CO produced from power and steam needed for ASCC u nits 15,073 t⁄ d CO captured 8% more than base emissions

Complex CO emissions by area 3,100 KM t/y c rude LP 530

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CCPP ( s team & power) NViro ( s team) H p lant Steam cracker PDH MaxEne AroFlex NS Pygas NS

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ASCC on 4 Stacks

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81% CO reduction

HCU SDA NHT/NS CDU

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Economic burden on the project was (4%) IRR with no government support

2,000

Notes: 1. 75 MW power, 730 MT/hr MP s team and 30,000 m/h CW needed for case 2. ‘NS’ is n aphtha splitter

Base Complex ASCC Complex

Figure 4 Impact of ASCC on 3,100 KMt/y crude case

PTQ Q2 2023