July 2021

Special Focus: Plant Design, Engineering and Construction

Oil refinery/petrochemical integration in a CO2-constrained world—Part 1

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

Petrochemical demand will increase with gross domestic product, while motor fuel demand will only show modest growth and may even decline in certain regions, given environmental/legislative pressure and the introduction of battery-powered electric vehicles. Any new oil refinery will likely include petrochemical facilities, as well. This article evaluates several configurations, highlighting salient differences between them (including economics) and assessing their sensitivity to product and feed price fluctuations, cost of utilities, type of crude and a carbon dioxide (CO2) tax. These options are evaluated complex-wide as the only way to ensure that schemes are compared on a consistent basis and that all interactions and synergies between units are considered.

While the scenarios and investment costs are based on new facilities, the methodology could equally be applied to revamp projects where options to expand refinery operations with petrochemical units are being considered, along with the revamp costs of existing assets.

The base case refinery scheme includes either a residue fluid catalytic cracking unit (RFCCU) or a hydrocracking unit (HCU). The feed to the RFCCU comes from an atmospheric residue desulfurization (ARDS) unit. The hydrocracker schemes include a delayed coking unit (DCU) or residue HCU (RHCU) as a residue conversion unit. The complex includes motor fuel (Euro-5 gasoline and diesel) and jet fuel production. Where required, ethyl tertiary butyl ether (ETBE) is imported as a gasoline pool component. In some cases, fuel-oil components are produced.

The petrochemical facilities produce base petrochemicals such as polyethylene (PE), polypropylene (PP), butadiene, benzene and paraxylene (PX). The complex includes a hydrogen production unit (HPU)—based on steam reforming—to balance the refinery’s hydrogen demand.

The complex processes 10 MMtpy of Urals crude, priced at $70/bbl. The complex will only import natural gas (for process and utility heater service, as well as for hydrogen production), electric power and raw water.

The economic evaluation depends on the prices of raw materials, products and utilities, as well as the unit prices of steel and the costs of construction, labor, etc. The economic analyses detailed in this article are more representative of the differences between certain schemes, rather than of being correct in the absolute sense.

Part 1 introduces the various configurations and how they compare based on investment cost, gross and net margin, and internal rate of return (IRR). Part 2, which will be featured in the August issue of Hydrocarbon Processing, will discuss crude effects, CO2 emissions and the impact of a CO2 tax on IRR.

RFCCU alternates

The RFCCU is a propylene-optimized unit, with approximately 17 wt% of C3= from the RFCCU reactor. The RFCCU feed is pretreated in an ARDS unit, taking atmospheric residue directly from the crude distillation unit (CDU). The complex includes ETBE and alkylation units to facilitate Euro-5 gasoline manufacturing. In case of isobutane (iC4) insufficiency for the alkylation unit, a C4 isomerization unit processing RFCCU and other refinery butanes is included. The petrochemical extensions include the addition of a PP unit to process polymer-grade propylene from the RFCCU (Case A1) and an aromatics complex (Case A2). The PP unit consists of two trains. An ethylene recovery unit (ERU)—recovering ethylene from FCCU dry gas—is included for cases A1 and A2, with the ethylene co-feed to the PP unit to also produce impact and random co-polymers; excess ethylene is sold. In Case A2, the reformate is sent to the aromatics complex. The raffinate from the aromatics units is used for gasoline blending. TABLE 1 provides an overview of the units considered under the various schemes.

A graphical depiction of scheme A2 (RFCCU, PP unit and aromatics complex) is shown in FIG. 1, with traditional refinery units in green (and blue for the residue conversion units) and with petrochemical units in yellow or pink (aromatics).

FIG. 1. Block flow diagram of Case A2: An RFCCU, along with a PP unit and an aromatics complex.

The evaluation results are detailed in TABLE 2. Gross margin is the value of the products sold minus the cost of all feeds purchased. Net margin in this article is the gross margin minus the cost of utilities, catalyst and chemicals. Investment cost includes the total engineering, procurement and construction (EPC) cost of the complex, excluding the owner’s cost. Simple payback is the straightforward calculation of the total EPC investment cost against the net margin, based on a complex operating 8,400 hr/yr. All costs are based on Western European costs in 2019. IRR is based on an 8% weighted average cost of cash, 2% inflation, a yearly maintenance cost of 1% of investment costs, a 4-yr construction period, and a project life of 20 yr. Petrochemicals output is the sum of polyolefins, benzene, PX, propylene and ethylene production.

Adding petrochemical units increases the gross margin. Adding a PP unit increases the gross margin by $52/t and the net margin by $40/t (Case A1), comfortably paying for the $676 MM higher capital cost (with the PP unit consisting of two trains), and with IRR increasing from 12.4% to 16.5%. Adding an aromatics complex—using reformate as feedstock—further improves the economics (Case A2). The petrochemicals output increases to 18%. In addition, processing FCC gasoline in the aromatics unit has little economic benefit, as it produces less aromatics relative to the reformate, while simultaneously causing the need for more reformate in the gasoline pool to compensate for the loss of FCC gasoline. In this case, FCC gasoline would most likely also require complete hydrotreatment to remove olefins—thus further increasing investment and operating costs, which hurts economics.

HCU alternates

The base case refinery now includes a DCU, along with a middle-distillate-oriented HCU processing the DCU heavy gasoil and straight-run vacuum gasoil from the vacuum distillation unit (VDU). The refinery was subsequently expanded with a steam cracker complex—including pygas hydrotreating, butadiene extraction and polyolefin units—and an aromatics complex. Hexene-1 is imported as co-feed to the PE unit. A full overview of the units included in the evaluation is shown in TABLE 3. A graphical depiction of Case B3 is shown in FIG. 2.

FIG. 2. Block flow diagram of Case B3: An NHCU, along with a steam cracker and an aromatics complex.

Key results of the evaluation are detailed in TABLE 4. The percentage of petrochemicals on crude is negative when more ETBE is imported than the sum of the petrochemical products sold.

The steam-cracking schemes (Cases B1–B3) include pygas saturation and ETBE production to facilitate Euro-5 gasoline production. Adding alkylation to process the remaining C4=s is not beneficial, as it would deprive the steam cracker of i+nC4s. The reduction of petrochemicals does not compensate for the higher gasoline production. Ethylene and propylene are worked up to their respective polymers in generic PE and PP units. These units now consist of multiple trains. Case B2B includes two steam cracker units. The light naphtha isomerization unit disappears for Cases B1–B3, as the C5–C6 material is sent to the steam cracker, but it reappears with cases B4 and B5 (TABLE 3).

Expanding the base case (B0)—the DCU/HCU refinery with petrochemical production units—has the potential to more than double (and possibly triple) the gross margin (TABLE 4). However, operating and investment costs increase, as well. The base case is penalized by the high cost of ETBE imports, which is an inherent feature of the DCU/HCU refineries that produce Euro-5 gasoline.

Adding a steam cracker complex to the base refinery (Case B1) improves economics. The steam cracker is a mixed-feed cracker, processing all fuel gas and LPG streams, as well as light naphtha and the bulk of heavy naphtha. The gasoline pool predominantly consists of hydrotreated pygas and ETBE; some reformate is still needed to meet octane specification. Relative to the base case, gasoline production is reduced by approximately 70%.

While gross margin increases by $100/t of crude [from $94/t (Case B0) to $194/t (Case B1)], the net margin only increases by $64/t of crude (from $61/t to $125/t), which is still enough to compensate for the 85% increase in investment cost (from $4.16 B to $7.7 B). IRR increases from 11% to 12.4%.

The value of the steam cracker was further explored by increasing the naphtha flow to the unit, with the additional naphtha produced by the HCU converted to naphtha operation, which produces nearly four times as much naphtha vs. the base case (Case B2A). The gross margin increases from $194/t to $252/t. However, the increase in net margin from $125/t to $151/t does not pay for the higher investment (from $7.7 B to $10.1 B), with IRR decreasing from 12.4% to 11.2%. The petrochemicals output rises to 24% of crude. In addition, sending atmospheric and light coker gasoils to the naphtha hydrocracking unit (NHCU) (Case B2B) further increases the petrochemicals output to 35%, but with poorer economics.

Adding an aromatics complex—with or without a steam cracker—in the scheme (Cases B3 and B4) substantially improves economics, with IRR increasing from 12.4% (Case B1) to 14.1% and 15.4% for Cases B3 and B4, respectively. Despite the lower margin, the case without the steam cracker (i.e., Case B4) has the better economics on account of the lower investment. The gasoline pool properties can only be met by importing supplemental ETBE and sending some reformate to the pool. The petrochemicals output for Cases B3 and B4 is now 37% and 17% of crude, respectively.

In Case B5, the DCU has been swapped for an RHCU, based on slurry technology. Relative to Case B4, the gross margin improves $22/t. This decreases to $17/t on a net margin basis. The RHCU’s catalyst cost is a major contributor to the higher operating cost. IRR further improves to 17.7%.

Based on IRR, Case B5—which includes a slurry RHCU that processes the same feed as the DCU previously, along with an HCU geared toward naphtha production and an aromatics complex—has the best economics of the evaluated HCU cases.

Comparisons and sensitivities to product/utility pricing

As a reference case, the obtained IRR results are reported in the first column of TABLE 5. The RFCC cases (Cases A0–A2) typically yield better returns than the HCU and NHCU cases (Cases B0–B4) (see also FIG. 3). The DCU+HCU case (B0) is penalized by the higher import of ETBE (TABLE 4). Adding a steam cracker to the HCU (Cases B1–B2B) does not close the IRR gap with the FCC cases.

FIG. 3. IRR vs. petrochemicals on crude (%).

Due to the higher capacity of the aromatics complex and the higher naphtha production from the NHCU, adding an aromatics unit is more attractive in an NHCU (moving from Case B2A to Case B3 increases IRR by 2.9%) vs. an RFCC-based configuration (moving from Case A1 to Case A2 increases IRR by 1.5%).

The combination of an RFCC, PP and aromatics complex (Case A2) has the highest IRR, followed closely by the RHCU, NHCU and aromatics complex (Case B5). The economics depend on the pricing scenarios under consideration. Higher petrochemical prices (an additional 20% relative to the other feed/product and utility prices) greatly improve the economics of the schemes having a high petrochemical output (see FIG. 4 and TABLE 5). IRR is 4%–7% higher as petrochemicals output increases to 20%–40%. With an IRR near 22%, the combination of an RFCCU, PP unit and aromatics complex (Case A2) ranks at the top of the list.

FIG. 4. Impact of 20% higher petrochemical prices on IRR.

If fuel gas costs are halved, IRR improves between 6% and 33% for all cases, with the high natural gas import cases (B0, B2A and B2B) benefiting IRR the most (TABLE 5). Relative to the reference case, if electricity prices are halved, IRR improves between 5% and 20% (Case B2B).

The effect of electricity and fuel gas prices on economics is most pronounced with the combinations having a high electricity and/or thermal demand. However, the ranking of the cases may change with different assumptions. Whereas Case A2 ranks best in the reference case and Case A2, for example, still looks best in the high petrochemical price scenario, Case B5 looks best in a scenario of lower fuel gas prices. In case of low electricity prices, Case A2 ranks the highest.

All units have typical fuel gas, steam and electricity consumption levels. No effort has been made to increase electricity consumption by changing steam turbines to electric drives or by considering electric heaters.

Options for further increasing the petrochemical value chain

Making specialty chemicals and/or expanding petrochemicals production will further increase petrochemicals output and/or profitability. Some of the options to be considered include:

  • Converting C4= and recycling it within the steam cracker
  • Sending pygas to the aromatics unit
  • Sending hydrotreated pygas/raffinate to the steam cracker
  • Only producing gasoline blend components
  • Incorporating a propane dehydrogenation unit to produce additional propylene
  • Adding metathesis to convert C4= (with C2=) to propylene and then to PP
  • Forward integration with the following:
    • C2=s processed to glycol and its derivatives and/or polyvinyl chloride
    • C3= to propylene-oxide and/or its derivatives, which include acrylic acid and acrylonitrile
    • C3=s and C4=s to oxo alcohols
    • C4=s processed to methyl ethyl ketone
    • Butadiene to synthetic rubbers.


Any new refinery complex should integrate petrochemicals manufacturing to produce both transportation fuels and base petrochemical materials. Existing refineries will need to review their options to expand into petrochemical production or integrate with neighboring petrochemical plants.

Part 1 of this article explored several possible grassroots configurations, including an RFCCU, DCU or RHCU—the latter two combined with a vacuum gasoil hydrocracker. The key petrochemical units included a steam cracker with downstream PE and PP units, as well as an aromatics complex.

While it is theoretically possible to produce large amounts of petrochemicals, it may not always result in better economics, as shown within the confines of this study and regarding market circumstances. A DCU—combined with a naphtha-oriented hydrocracker that processes middle distillates with the bulk of the gases, LPG and naphtha sent to a steam cracker with downstream polyolefin units—can produce nearly 40% of petrochemicals from crude for a refinery processing Urals crude. However, in this study, a propylene RFCC-based refinery with an aromatics complex yielding 23% of petrochemicals from crude has better economics.

FCC-based schemes typically have better economics than DCU/RHCU/HCU-based schemes. However, this depends on many factors. Other than feed/product and utility pricing, it also depends on the design under consideration. For example, for a light crude, DCU/RHCU-based configurations may be more attractive, as will be detailed in Part 2.

This comparison is based on commercially available technologies and does not consider technology developments, which continue unabated. In general, the more-integrated schemes with a high petrochemical output are more robust to changes in feed/product and utility pricing. Higher petrochemical production is possible by ceasing Euro-5 gasoline production (allowing more naphtha to be sent to the aromatics complex or used as feed for the steam cracker), or by using pygas as aromatic feedstock, routing hydrotreated pygas and/or raffinate to the steam cracker, changing unit operations (higher RFCCU severity to produce more C3=) or adding other units (e.g., metathesis). These projects can be implemented stepwise, with petrochemical units being built in a second phase. Processing bio-based materials and/or streams from plastics recycling 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 operating and investment costs, and could change depending on local circumstances. Feedstock flexibility, along with robustness for feed/product pricing changes, combined with a proper assessment of risks and opportunities associated with each investment, should be part of a proper evaluation. HP

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