August 2021

Plant Design, Engineering and Construction

Oil refinery/petrochemical integration in a CO₂-constrained world—Part 2

Petrochemical demand will increase with gross domestic product, while the demand for motor fuels will only show modest growth and may even decline in certain regions, given environmental/legislative pressures and the introduction of battery-powered electric vehicles.

Petrochemical demand will increase with gross domestic product, while the demand for motor fuels will only show modest growth and may even decline in certain regions, given environmental/legislative pressures and the introduction of battery-powered electric vehicles. Any new oil refinery will likely include petrochemical facilities, as well.

In Part 1, published in the July issue of Hydrocarbon Processing, the authors reviewed several possible refinery/petrochemical complex configurations around an RFCCU (FIG. 1 from Part 1) or HCU (FIG. 4 from Part 1). It was shown that investments, and gross and net margins, vary considerably between the various configurations. This article will evaluate the impact of a CO₂ tax and crude source/pricing on IRR.

CO₂ emissions

The CO₂ emissions associated with the various configurations are reported in TABLE 6. CO₂ emissions are the total emissions of the complex due to the combustion of natural gas, refinery fuel gas and FCC coke, and exclude the CO₂ associated with generating the required electrical power or any other CO₂ emissions associated with outside battery limit facilities (such as tank heating, process water demineralization, boiler feed water preparation, flare purging and tracing). As such, the emissions reported in this article are the larger part of the Scope 1 emissions.

For the FCCU cases (A0–A2), the CO₂ emissions increase with increased complexity—e.g., increasing from 367 t/hr to 402 t/hr when going from the Base Case A0 to Case A2, primarily due to the contribution of the aromatics complex (FIGS. 5 and 6). The RFCCU is the biggest contributor to emissions, representing 45% and 41% in Base Case A0 and Case A2, respectively.

For the HCU alternatives, the CO₂ emissions gradually increase with increased complexity. In the SC cases (B2A and B2B), CO₂ emissions have increased 3x–4x relative to the base case.

In Base Case B0 (FIG. 7), the HPU and CDU/VDU are the biggest contributors, accounting for 30% and 24% of total CO₂ emissions, respectively. With the addition of the steam cracker and the aromatics complex, and converting the hydrocracker to a naphtha-oriented hydrocracker, CO₂ emissions increased from 223 t/hr to 472 t/hr (Case B3), as shown in FIG. 8.

In Case B3 (FIG. 8), the SC and aromatics units have become the biggest CO₂ emissions contributors, representing 32% and 15%, respectively. The CO₂ emissions for cases B4 and B5 are shown in FIGS. 9 and 10. In Case B4, the aromatics complex is second to the CDU/VDU in terms of total CO₂ emissions. In Case B5, the top CO₂ emitters are the HPU (18%), the CDU/VDU (16%) and the aromatics complex (15%).

CO₂ emissions increase with increasing petrochemical production (FIG. 11). The steam cracker HCU cases (B1, B2A and B2B) have the highest emissions. The aromatics HCU cases (B3, B4 and B5) have the lower emissions at a given petrochemicals output. The FCC cases (A0–A2) are intermediate.

Effect of a CO₂ tax

The effect of a CO₂ tax on IRR are shown in FIG. 12. IRR deteriorates with an increasing CO₂ tax, but even more so for the high-CO₂ cases—e.g., Case B2B: DCU + NHCU2 + SC, with emissions of 0.79 t CO₂/t crude (TABLE 7). For Case B2B, IRR even becomes negative when the CO₂ tax reaches $125/t. For lower-CO₂-intensive configurations (e.g., Case B5: RHC + NHCU + aromatics complex, with CO₂ emissions of 0.27 t/t crude, or Case A2: RFCC + PP + aromatics complex, with CO₂ emissions of 0.34 t/t crude), the IRR drops only 5% when the CO₂ tax increases from zero to $125/t CO₂.

The impact of a CO₂ tax can be mitigated by reducing CO₂ emissions at the source or by opting for carbon capture where CO₂ can be reused (e.g., enhanced oil recovery) or stored as part of a CO₂ sequestration project. Intrinsic CO₂ emissions can be reduced by implementing energy conservation methods, incorporating system electrification (such as replacing steam drivers with electric drivers and using electric heaters instead of gas-fired heaters), and replacing natural gas for bio-based materials or co-processing bio-based materials in the process units.

Two cases of carbon capture are considered: 1) pre-combustion CO₂ capture from the process gas in a hydrogen plant (also known as blue hydrogen, which will reduce hydrogen plant CO₂ emissions by 50%), and 2) post-combustion CO₂ capture from the combined complex flue gases, which reduces total CO₂ emissions by approximately 70% in this example (theoretically, higher removal rates are possible). In all cases, CO₂ is made available at the complex battery limit at a pressure of 35 barg for further transportation.

Adding CO₂ capture comes with increased investment and operational costs, both of which negatively impact economics. Relative to the reference case, IRR drops between 0.4% (in Case A2, IRR decreases 18% to 17.6%, and, in Case B5, IRR decreases from 17.7% to 17.3%) and 0.5% (in Case B2B, IRR decreases from 8.3% to 7.8%), with pre-combustion capture and no CO₂ tax enforced (TABLE 7). Post-combustion CO₂ capture reduces IRR between 3.5% (in Case B5, IRR decreases from 17.7% to 14.2%) and 4.6% (in Case B2B, IRR decreases from 8.3% to 3.7%).

IRR decreases as the CO₂ tax increases, but less so when CO₂ capture is part of the complex. At some point, the IRR with CO₂ capture exceeds the IRR without CO₂ capture, despite the higher investment and operational costs. For pre-combustion CO₂ capture, this happens when the CO₂ tax exceeds $75/t. For post-combustion CO₂ capture, this occurs when the CO₂ tax approaches $100/t for a high-CO₂ case (e.g., Case B2B). For lower-CO₂ cases (e.g., cases A2 and B5), the CO₂ tax would need to be more than $125/t.

Crude effects

The design crude also influences economics. Both Arab Light and Caspian Pipeline Consortium (CPC) crudes have a higher price in this study. This hurts the simple configurations (e.g., cases A0 and B0), with IRR decreasing 5%–8% (TABLE 8), but much less than in more complex configurations where IRR decreases only 1%–3%, as they have a higher intrinsic gross margin.

With CPC crude, the RFCC Case A0 looks poor as the gasoline pool becomes unbalanced. The smaller FCCU (and ETBE and alkylation units), relative to the Urals or Arab Light case, now requires the purchase of a significant amount of ETBE as a gasoline pool blending component. The base HCU (Case B0) also needs a high ETBE import. This disadvantage disappears when the reformate is sent to an aromatics complex (Case A2) or when a steam cracker and/or aromatics complex is included (cases B1–B5). The aromatic cases (A2, B3, B4 and B5) look particularly good when using CPC crude.

As shown, the ranking of technologies changes with crude. In the CPC case, an advanced DCU/RHCU scheme (Case B4 or B5) is more attractive than an RFCC-based scheme (Case A2).

Takeaway

Any future new refinery complex will likely integrate petrochemicals manufacturing. Existing refineries will need to look at options to expand into petrochemical units or to integrate with neighboring petrochemical plants. In general, the more integrated schemes—with a high petrochemical output—are more robust to changes in feed/product and utility pricing, as well as to the selection of crude and CO₂ tax.

CO₂ emissions will increase as petrochemical output increases—the addition of a steam cracker has a large effect on CO₂ emissions. A CO₂ tax will negatively affect the economics of any refinery/petrochemical complex.

In this article, the authors have illustrated how it paid to invest in pre-combustion CO₂ capture at the hydrogen plant when CO₂ taxes increased to $75/t. Post-combustion carbon capture did not look attractive until the CO₂ tax reached $125/t.

These projects can be implemented stagewise, with petrochemical units being built in a second phase commensurate with an anticipated reduction in motor fuel demand. Processing bio-based materials and/or streams from plastic recycle plants presents another opportunity to improve economics and sustainability.

The conclusions drawn in this analysis are based on a particular crude diet, feed and product pricing, as well as on operational and investment costs, and may change depending on local circumstances. Feedstock flexibility and a robustness for feed/product pricing changes, coupled with a proper assessment of risks and opportunities associated with each investment, should be part of a proper evaluation. HP

The Authors

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