August 2022

Special Focus: Refining Technology

Evaluate options for decarbonizing petroleum refineries

The energy transition requires rebuilding the energy supply infrastructure for a lower-carbon economy and renewable energy generation for industry and transportation that run more on electricity and hydrogen and less on fossil fuels and provide a circular path for consumer plastics. The growth in global oil demand is predicted to end within 10 yr, but it is still too early to foresee a rapid decline in that demand.

The energy transition requires rebuilding the energy supply infrastructure for a lower-carbon economy and renewable energy generation for industry and transportation that run more on electricity and hydrogen (H₂) and less on fossil fuels and provide a circular path for consumer plastics. The growth in global oil demand is predicted to end within 10 yr, but it is still too early to foresee a rapid decline in that demand.

Refiners are strategizing to align with a low-carbon future. Moving from transport fuels to petrochemical feedstocks, producing renewable fuels and sourcing low-carbon H₂ are emerging as possible options. However, uncertainty remains around demand forecasts and potential regulatory framework. Governments, technology providers, refinery owners and engineering companies will all play a role in selecting and implementing the most efficient and least-disruptive pathways to a low-carbon future. One thing is certain: this transition will be gradual and require operating refineries to align product slate with demand and reduce their direct carbon dioxide (CO₂) emissions.

Although the vast majority (85%–90%) of carbon emissions in the petroleum fuel cycle occur during final consumption of the petroleum products, refineries remain a substantial source. This article estimates the CO₂ emissions from refineries and the impact that factors such as crude quality, configuration, electricity source, etc., have on these emissions estimates. Options for reducing emissions from major sources are also evaluated.

Refinery CO₂ emissions

Petroleum refining products are an essential part of the world economy, providing energy as well as other high-value products. The refining process involves separating, cracking, restructuring, treating and blending hydrocarbon molecules to generate petroleum products. FIG. 1 shows a simplified, typical overall refining process. The specific processes implemented will vary from refinery to refinery and depend upon the refinery’s capacity, feedstock and specific product slate.

Each refinery has unique features, which makes finding a global unified model to represent all of them difficult. This is even more true when it comes to estimating CO₂ emissions from a refinery, allocating the emissions to products to determine the impact on fuel carbon intensity, and developing strategies for CO₂ reduction. However, it is possible to represent operating refineries in a few scenarios by grouping the common variables impacting CO₂ emissions. While this will not have the granularity of an individual refinery model, it does provide useful insights into potential CO₂ reduction strategies, target emissions and achievable reductions. The Petroleum Refinery Lifecycle Evaluation Model (PRELIM) developed at the University of Calgary and freely available for download¹ is used here to estimate CO₂ emissions for a range of refinery configurations, feedstocks, upstream emissions and energy sources. PRELIM was developed to offer a free, flexible, transparent and open-source tool that captures the impact of crude oil quality and refinery configuration on energy use and the environmental impacts associated with refining crude oils.

The estimates from PRELIM are analyzed for CO₂ reduction strategies. Technically feasible technologies are proposed for reducing CO₂ from refinery heating, steam methane reformer (SMR) H₂ units utilizing natural gas (NG) feedstock and fluidized catalytic cracking (FCC). For simplicity, global warming potential (GWP) in terms of CO₂ equivalent (CO₂e) is presented as CO₂—in a refinery, that is the major component.

Modelling methodology

PRELIM employs a system-level approach and refinery linear modelling methods. This allows the selection of different crudes and alternate refinery configurations. It is also capable of changing the product slate, such as the gasoline/diesel ratio and petrochemical feedstocks, alternate dispositions of refinery off-gas, alternate sources of electricity, etc. TABLE 1 presents the parameters and options used for this article.

Other parameters (e.g., allocation methods, allocation products, GWP values) are kept as default. In this model, a medium-conversion refinery includes crude/vacuum distillation, naphtha hydrotreater, isomerization, naphtha catalytic reformer, diesel/ kerosene hydrotreater, FCC and gasoil hydrocracker units. All medium-conversion units are included in a deep-conversion configuration with the addition of either a delayed coking or residue hydrocracking unit. PRELIM presently does not include configurations with petrochemical integration (e.g., multi-feed cracker, aromatics). The article excludes these integrations and only discusses fuels refining.

The parameters presented in TABLE 1 were grouped into 11 alternate cases and run in PRELIM. Selected options cover a wide range of existing refineries. TABLE 2 summarizes the input parameters and estimated product slate, energy use and CO₂ emissions. Parameters are varied to bring out the major factors that impact CO₂ emissions. CO₂ emissions are presented as per barrel (bbl) of crude processed to eliminate the impact of refinery capacity. For this article, the default data and constants in PRELIM are used for estimates. PRELIM does give the option to modify these defaults values with data available for specific design.

The input parameters that are varied are: crude quality; refinery configuration; cogeneration, included or not; source of electricity; and upstream emissions for NG, included or excluded. This covers a wide range of existing refineries and captures the variations in CO₂ emissions both at an aggregate level and specific to the source.

Discussion of modelling results

From TABLE 2, CO₂ emissions range between 30 kg CO₂/bbl and 90 kg CO₂/bbl of crude processed. Major findings are summarized below:

1. For the same crude (Cases 2–4), moving from a medium-conversion to deep-conversion refinery with a coker increases CO₂ emissions by ~40%. Processing the same crude in deep conversion with a residue hydrocracker further increases
   emissions by ~20%.
2. For a refinery with the same configuration (a deep conversion with coker), processing heavier crude (Cases 3 and 5) increases CO₂ emissions by ~25%.
3. The difference in CO₂ emissions between a deep-conversion refinery with a residue hydrocracker vs. one with a coker is 50% (Cases 5 and 6).
4. For the same crude and refinery configuration, the decrease in CO₂ emissions by switching from a natural gas combined-cycle (NGCC) power plant, or cogeneration based on NG, to a low-carbon power source is ~8% (Cases 5, 7 and 8).
5. For the same crude and refinery configuration, the decrease in CO₂ emissions in switching from a coal-fired power plant source to a low-carbon power source is ~14% (Cases 9 and 11).
6. Upstream NG emissions can account for ~10% of the total estimated CO₂ emissions (Cases 6 and 10).
7. Process heating accounts for 30%–65% of the total CO₂ emissions. This share is higher for refineries processing lighter crudes.
8. H₂ production from the SMR can account for 15%–60% of the total estimated CO₂ emissions. This share is much higher for refineries with residue hydrocracking.
9. An FCCU accounts for 6%–12% of CO₂ emissions and is the next highest single source after process heating and H₂ production.

These conclusions are based on per/bbl basis and, therefore, crude capacity is not a factor. However, depending on crude quality and refinery configuration, the product slates can differ. An alternate perspective of looking at refinery CO₂ emissions is by allocating the CO₂ to the products. This perspective can then be utilized in estimating the carbon intensity of fuel products. This aspect is not discussed in this paper. PRELIM estimates are based on calculations and equations available in literature, and it allows expert input to correct for design when used for a specific site.

CO₂ REDUCTION OPTIONS

Refinery configuration, crude selection and product slate are determined based on economics. Results presented and discussed in the previous section indicate the possibility of reducing CO₂ emissions by processing a lighter crude. This will be feasible if the additional cost of lighter crude is compensated by being eligible for trading CO₂ saved as a result. Similarly, for new refineries in the planning stage, CO₂ emissions can be included in internal rate of return (IRR) calculations by assigning a price to the emitted CO₂. This approach will penalize configurations with higher CO₂ emissions. These options are not further elaborated here since the focus is on existing refineries and on deeper reductions than offered by crude switching or change in configuration.

Another option for refineries is to source electricity from a low-carbon source. For refineries operating with electricity sourced from coal-fired plants, this provides substantial (~14%) CO₂ reductions. For refineries operating with cogeneration utilizing NGCC, the benefits are lower (~8%). This option requires a review of the overall refinery steam and power balance and investigating the conversion of some of the steam-driven equipment to electric drives to decrease CO₂.

To achieve deeper reduction in CO₂ emissions, refineries must reduce emissions from three sources: process heating, H₂ production and FCC catalyst regeneration. Three main approaches to reduce CO₂ from these areas are pre-combustion, post-combustion and oxy-fuel combustion.

Post-combustion systems separate CO₂ from the flue gases produced by the combustion of the primary fuel with air. Pre-combustion systems process the primary fuel in a reactor with steam and air or oxygen to produce a mixture of carbon monoxide (CO), CO₂ and H₂ (synthesis gas). Additional H₂, together with CO₂, is produced by reacting the CO with steam in a second reactor (shift reactor). The resulting mixture of H₂ and CO₂ can then be separated into a CO₂- and a H₂-rich stream. The CO₂ is captured, and the syngas or carbon-free H₂ can be combusted to generate power and/or heat, or utilized for synthesizing chemicals.

Oxy-fuel combustion systems use oxygen rather than air for combustion of the primary fuel to produce a flue gas that is mainly water vapor and CO₂. This results in a flue gas with high CO₂ concentrations (> 80 vol%). The water vapor is then removed by cooling and compressing the gas stream. While all three are technically feasible, considering the need for an air separation unit, extensive oxygen piping, retrofit of flue gas recycle, sealing of furnaces, etc., the option of oxy-fuel firing is not considered in this article. The other two options are discussed in detail in the subsequent sections for each type of emissions source.

CO₂ reduction from refinery heaters

CO₂ emissions attributed to process heaters are spatially distributed across the refinery. TABLE 3 presents typical source-wise emissions for a deep-conversion coking refinery processing 100,000 bpd.

Flue gases from these furnaces have high volumetric flowrates, are at atmospheric pressure and have low CO₂ partial pressure. Despite the low CO₂ partial pressure, certain amines—such as monoethanolamine (MEA) and other similar solvents—can achieve high levels of CO₂ capture due to fast kinetics and strong chemical reactions. Post-combustion CO₂ capture requires ducting, fans, cooling of flue gas, a CO₂ absorber, a regenerator and CO₂ compression/drying (FIGS. 2 and 3).

Low pressure requires large ducts and fans, which consume significant power; to be economical, the CO₂ capture equipment must be located near the emissions source. This imposes limitations for retrofit applications that typically do not have space for ducting, large cooling equipment and absorbers. Additionally, to lower the capital cost, the CO₂ capture units must exploit economies of scale. Providing a dedicated CO₂ capture facility for each furnace in the above refinery example is not an economic choice. The present state of the art design for CO₂ capture from low-pressure streams can handle ~3,000 tpd in a single absorber train. Therefore, designing for CO₂ recovery of ~500 tpd will not achieve economies of scale.

Pre-combustion CO₂ capture applied to refinery process heating requires the conversion of the refinery fuel to decarbonized H₂, as discussed in the previous section. Because of the centralized production of fuel for the entire refinery, pre-combustion can be built at economic scale capacities. The next section discusses CO₂ capture from an SMR H₂ production unit. Many existing refineries have SMRUs to meet process H₂ needs. A dedicated SMR H₂ unit with carbon capture is required to produce H₂ for process heating. The technical feasibility of using H₂ in refinery heaters has been ascertained.³

CO₂ reduction from SMR H₂ production

An SMR plant consists of four major sections:

• Feedstock pre-treatment
• Steam reformer
• Shift reactor
• Pressure swing adsorption (PSA) unit.

CO₂ is generated by the reforming and water-gas shift reaction, the combustion of CO in the PSA tail gas, and the combustion of natural gas as supplementary fuel. This implies that CO₂ could be captured from three possible locations (FIG. 4):

1. Shifted syngas
2. PSA tail gas
3. SMR flue gas.

TABLE 4 presents the typical pressure, CO₂ mol% and CO₂ quantity in these three streams for a 70,000-NM³/hr H₂ plant meeting the requirement of a 100,000-bpd deep-conversion refinery with a coker.

The stream at the inlet of the PSA unit has high operating pressure and high partial pressure of CO₂. CO₂ capture from streams with high partial pressure of CO₂ is proven using methyldiethylamine (MDEA). Due to the high pressure, a fan is not required, and piping and absorber sizes are smaller compared to low-pressure streams. MDEA is a tertiary amine with high CO₂ absorption capacity, low regeneration energy compared to primary amine [such as monoethanolamine (MEA)], but also has a slower reaction rate.

Piperazine is typically added as an activator to MDEA to increase the rate of reaction. Typically, a recovery of 90% is achievable. In the above reference plant, this would give 250,000 tpy of CO₂ recovery. For a deep-conversion refinery with a residue hydrocracker, applying CO₂ capture on this stream alone can yield 750,000 tpy of CO₂. This scheme is similar to that depicted in FIG. 2, except that a fan is not required.

Recovery from this high-pressure stream alone yields 52%–55% of the total CO₂ from an SMRU. The PSA outlet stream is at a lower operating pressure but higher CO₂ content. A compressor will be required to boost pressure to approximately 10 barg to use the MDEA process. Equipment sizes required will increase and additional energy will be needed for compression. Design pressures will reduce compared to Option 1. A preliminary analysis indicates this option will be uneconomical at most sites and is not discussed further here.

Capturing CO₂ from reformer flue gases can lead to much higher CO₂ recovery. Typically for these low-pressure streams, primary amines such as MEA or similar solvents are used. These have limited absorption capacities and usable solution concentration ranges. The energy required for regeneration of solvent is significantly higher compared to MDEA. Low pressure implies large ducts and absorber sizes. In the above reference plant, this option would capture ~500,000 tpy of CO₂ recovery.

CO₂ absorption is most efficient at gas temperatures between 30°C and 50°C. This implies that when capturing CO₂ from flue gas, there will be a cooling requirement before routing to an absorber. This adds additional equipment and the need for either cooling water or additional energy to use air cooling/a gas-gas exchanger, significantly impacting the economics of CO₂ recovery.

The above options are applicable for refineries with existing SMR-based H₂ production units. Refineries also have an option to explore alternate routes for meeting H₂ requirements. This may include:

• Green H₂, which is produced by electrolyzing water with the use of renewable energy
• H₂ production from alternate fossil feedstocks, such as petroleum coke/coal gasification with carbon capture.

Green H₂ is a promising alternative in areas with abundant and uninterrupted renewable energy and will become more attractive as capital costs reduce in the future. This option is not discussed further in this article. The option of integrating petroleum coke/coal gasification with CO₂ capture is another promising alternative for low-carbon H₂, and is briefly discussed in the next section.

Gasification for H₂ production

Gasification is the partial oxidation of any fossil fuel to synthesis gas (syngas), in which the major components are H₂ and CO. To produce H₂, syngas is routed to the shift unit, where CO is shifted to H₂ and CO₂. An acid gas treatment unit removes hydrogen sulfide (H₂S) and CO₂. Shifted and cleaned syngas is routed to the PSA unit where H₂ is recovered, and the rejected tail gas is available for use as fuel (FIG. 5). A two-stage shift increases the H₂ content in the fuel and maximizes the degree of CO₂ removal. Gasification requires pure oxygen, which is produced in the air separation unit (ASU).

Feedstock for gasification can be petroleum coke, coal or heavy liquid ends from refining. High-pressure steam is co-produced from heat recovery in syngas and PSA tail gas as fuel. The gasification system and refinery operations can share amine stripper, sulfur block, water treatment and cooling water systems. Product compositions vary depending upon the selected gasification technology and the characteristics of the petroleum coke. Coke produced from the 100,000-bpd deep-conversion coking refinery processing heavy crude discussed in previous sections will yield approximately 130 MMsft³d of H₂. This will exceed what is required by the refinery for process use alone. Additional available H₂ can be mixed with refinery fuel gas and used in furnaces, leading to significant additional CO₂ reduction.^3,4

Since petroleum coke has a significantly higher carbon-to-H₂ ratio compared to NG, the CO₂ quantity that must be captured and sequestered in this route will be significantly higher than in the SMR H₂ route. The electricity requirement will also be significantly higher. However, in this route, all CO₂ is captured from high-pressure syngas. This enables a much more efficient CO₂ capture, yielding an overall CO₂ capture efficiency of ~90% while targeting only high-pressure streams. The gasification route has higher indirect emissions due to electricity, whereas the SMR route has higher upstream emissions, depending on the source of NG. If the electricity for gasification is acquired from a low-carbon source, this route becomes attractive. Since most existing refineries have NG-based SMR H₂ units, the capital costs for this option will be high.

CO₂ reduction from fluid catalytic cracking (FCC)

In the FCCU, during the reaction step, coke is formed and deposited on the surface of the catalyst. To regenerate catalyst, the coke is burned in the regenerator with air. This generates CO₂ and is a substantial single-point source of emissions from the refinery. FCC flue gas contains about 10 mol%–20 mol% of CO₂ when running in full combustion mode.

For the 100,000-bpd refinery discussed in previous sections, the estimated CO₂ emissions are 630 tpd (approximately 200,000 tpy) for a 25,000-bpd FCCU. Two options for CO₂ capture from FCCUs are post-combustion technologies: CO₂ absorption and oxy-combustion. Oxy-combustion has been demonstrated in trials⁵ as competitive with post-combustion, providing more flexibility and requiring a smaller plot area. Scale-up and commercial demonstration will be required before it is widely adopted.

Post-combustion capture will be similar to what was discussed for flue gas from heaters and SMRUs: a low-pressure, low-CO₂ partial pressure gas requiring MEA or similar solvents is used. A major difference is the presence of contaminants, such as particulates, sulfur oxides (SO_x) and nitrogen oxides (NO_x), which must be brought down to acceptable levels for amine absorption solvent. This will require a pre-treatment step typically utilizing DeNO_x and a wet gas scrubber. The scrubber reduces particulates, SO_x and temperature to acceptable levels. A single train of blower, scrubber, absorption, regeneration and compression will be capable of handling FCCUs processing 100,000 bpd–120,000 bpd.

Evaluation of options

A typical qualitative comparison of CO₂ reduction options based on capital and operating costs, commercial history, CO₂ reduction potential and constructability are presented in TABLE 5. The best-suited option will strongly depend on site-specific factors, such as plot plan constraints, availability of steam and energy cost, source of crude/NG, cost of capital, availability of water, labor cost, etc.

Takeaway

In the coming decades, petroleum refineries will be required to continue producing transport fuels while producing fuels from renewable feedstocks and diverting some of the lighter ends to petrochemical production. In addition to adapting the product slate to low-carbon needs, refineries will also be required to reduce their own carbon footprints. This article has identified options available to refineries for the decarbonization of production process. Proven and demonstrated technical options exist for achieving a high level of decarbonization from CO₂ emissions associated with process heating and H₂ production. For FCC CO₂, the solution is technically feasible although other options are also under development. The challenge will be to reduce the cost of applying these options and devising regulatory mechanisms to share the costs of decarbonization. These aspects will be discussed in a subsequent article. HP

LITERATURE CITED

1. University of Calgary, Energy Technology Assessment Research Group, “PRELIM: The petroleum refinery life cycle inventory model,” online: https://www.ucalgary.ca/energy-technology-assessment/open-source-models/prelim
2. Gary, J. H. and G. E. Handwerk, Petroleum refining: Technology and economics, 5th Ed. Marcel Dekker Inc., New York, New York, 2007.
3. Global CCS Institute, “Replacing 10% of NSW natural gas supply with clean H₂: Comparison of H₂ production options,” June 2020, online: https://www.globalccsinstitute.com/resources/publications-reports-research/replacing-10-of-nsw-natural-gas-supply-with-clean-hydrogen-comparison-of-hydrogen-production-options/
4. Digne, R., F. Feugnet and A. Gomez, “A technical and economical evaluation of CO₂ capture from fluidized catalytic cracking (FCC) flue gas,” Oil & Gas Science and Technology–Rev. de I IFP, November 2014.
5. bp Corp., “Carbon dioxide capture for storage in deep geologic formations—Results from the CO₂ capture project: CCS technology development and demonstration results (2009–2014),” Vol. 4, 2015, online: https://www.co2captureproject.org/reports/CCP3v4_full_version.pdf

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