January 2025
Special Focus: Sustainability and the Energy Transition
Decarbonization pathway for net-zero by 2050: Carbon neutrality roadmap strategy for an integrated refinery and petrochemical facility
This article quantifies GHG emissions from various sources, such as fired heaters and boilers, within refinery and petrochemical operations. Based on these quantified emissions, a tailored carbon neutrality roadmap is developed, incorporating carbon reduction, mitigation and offsetting strategies.
As the world races towards net-zero emissions—with > 4,000 companies approving net-zero targets by December 2023, according to the Science Based Targets initiative (SBTi) and the World Resources Institute1—the energy and chemicals sectors face significant pressure due to the inherent nature of their energy-intensive processes.
Achieving net-zero is often viewed as cost-prohibitive. This article outlines a pathway to net-zero for integrated refinery and petrochemical facilities. Fuel gas combustion for heating in these plants presently results in substantial greenhouse gas (GHG) emissions. This article quantifies GHG emissions from various sources, such as fired heaters and boilers, within refinery and petrochemical operations. Based on these quantified emissions, a tailored carbon neutrality roadmap is developed, incorporating carbon reduction, mitigation and offsetting strategies. This roadmap provides a clear decarbonization path for refiners aiming to achieve net-zero emissions by 2050.
Carbon neutrality roadmap. As the global demand for energy continues to surge and atmospheric carbon levels approach the critical threshold of 430 parts per million (ppm),2 the energy sector is confronted with the dual challenge of meeting escalating demand while simultaneously reducing carbon emissions. This article proposes a comprehensive strategy to retrofit existing refineries with petrochemical units and develop a carbon neutrality roadmap aimed at achieving net-zero emissions by 2050.
The carbon neutrality strategy is structured in phases, beginning with a focus on reducing emissions by approximately 20% by 2030 through energy efficiency improvements. This is followed by the implementation of carbon capture units to mitigate about 70% of emissions by 2040, and carbon offsetting for the remaining emissions by 2050. Carbon offsetting can be achieved through divesting carbon-intensive assets or purchasing carbon credits, which must meet specific criteria and are reserved for GHG emissions that cannot be reduced or eliminated through all technical and economically feasible methods.3
In grassroots energy transition projects, sustainability is evaluated at various stages, including conceptual feasibility, front-end engineering design (FEED) and detailed design, using four key performance indicators (KPIs):
- Carbon intensity
- Energy intensity
- Water intensity
- Waste intensity.
During the conceptual feasibility phase, projected sustainability KPIs provide the foundational data for the carbon neutrality roadmap strategy. The primary challenge at this stage is obtaining representative data without licensors’ proposals. To address this, reference plant data, process evaluation/research planning (PERP) reports and/or previous project experiences are integrated into linear programing (LP) models to assess the economic impacts of sustainability. Published emissions factors4 can be used to estimate GHG emissions, though these are high-level estimates and not site-specific. This baseline data is then compared to relevant energy intensity targets.
At the end of the conceptual feasibility phase, a sustainability workshop can be held to develop strategic plans for improving energy efficiency, reducing GHG emissions and minimizing water and waste from each process unit. This phase concludes with clear recommendations for further carbon reduction studies and a high-level cost estimate.
During the pre-FEED phase, key information for the inside battery limits (ISBL) design is available from technology providers and the ISBL engineering teams, and the sustainability engineering team can use site-specific information to execute identified energy efficiency improvement studies. The sustainability KPIs calculated at this stage are more accurate than those from the conceptual feasibility phase and are compared with the guaranteed figures provided by the licensor for GHG emissions, energy intensity, water and waste. Based on the energy optimization studies and the licensor’s proposals, the utility summary is updated to estimate the sustainability KPIs. At this point, energy efficiency improvements of approximately 10%–25% can be observed, resulting from a combination of energy improvement studies from the conceptual feasibility phase and energy-efficient designs from the selected licensors. The pre-FEED phase concludes with estimates of carbon emissions and the capital expenditure (CAPEX) required for their mitigation.
During the FEED phase, utilities design begins, further refining the sustainability KPIs within a 20% accuracy. These KPIs are compared at every phase until construction. During plant operations, these KPIs are continuously monitored and reported annually.
CASE STUDY
Basis. To achieve carbon neutrality targets, it is expected that global demand for crude oil-based gasoline and diesel will significantly decline, and most fuels refineries will need to shift to producing more petrochemicals to remain in profitable operation.
An LP model was chosen to develop a case study to show how carbon neutrality methods can be used for an integrated refinery and petrochemical facility. An LP model is an economic planning tool used to optimize the profitability of refineries and petrochemical plants during the design and operating phases. For this case study, the LP model is used to develop an optimized product slate, operational expenditures (OPEX) and fuel gas composition.
Four facility configurations with different levels of petrochemical integration are presented as a case study. Refer to TABLE 1 for a description of each case, and FIGS. 1–4 for a block flow diagram of each case’s configuration.
FIG. 1. Case 1: Block flow diagram of a typical fuel-focused refinery.
FIG. 2. Case 2: Block flow diagram of a refinery with the addition of a PP unit.
FIG. 3. Case 3: Block flow diagram of a refinery with the addition of an aromatics complex.
FIG. 4. Case 4: Block flow diagram of a refinery with the addition of an aromatics complex and PP unit.
Case 1 represents the Base Case refinery configuration with no petrochemical integration. This Base Case refinery primarily produces transportation fuels and includes a delayed coking unit (DCU). The produced petroleum coke could be burned as fuel, but in this case study, it is exported from the facility.
Case 2 begins to examine petrochemical integrations with the propylene produced by the refinery’s fluidized catalytic cracker (FCC) and DCU fed to a polypropylene (PP) unit.
In Case 3, the base refinery configuration and product slate is modified to feed naphtha to a reformer and aromatics complex to produce benzene and paraxylene (PX) products.
Finally, in Case 4, both the PP unit and aromatics complex are integrated with the base refinery. These configurations represent possible paths an existing refinery may take to move toward petrochemical production and away from traditional transportation fuel products. Each case includes a petrochemical naphtha product that could be used for further petrochemical integration by feeding it to a mixed-feed steam cracker to produce ethylene and additional propylene. Neither the steam cracker complex nor other means to further increase petrochemical production are considered for this study.
Each case considers 300,000 bpd of light Middle Eastern crude as the refinery design feed basis. Purchased natural gas is directly fed to the hydrogen (H2) plant. Natural gas is also mixed with the refinery fuel gas to meet the fuel requirements of the fired equipment. Power and steam required by the refinery is purchased from a nearby cogeneration plant, which is also fueled by natural gas.
Results. For each of the four cases, the LP model determines the optimal solution by maximizing the net cash margin for the facility through optimization of the products produced, utilities used, other production costs and fuel gas composition. The refinery fuel gas composition directly impacts the quantity of carbon dioxide (CO2) emissions the facility produces. Refer to TABLE 2 for the overall material balance of the primary feeds and products for each case, and TABLE 3 for the overall utility consumptions. TABLE 4 shows the fuel gas composition of each case.
In addition to the case configuration and overall material balance, the block flow diagrams indicate the quantity of CO2 emitted by the fired equipment in each unit. This shows that most CO2 emissions are concentrated with only a small number of the total units. Scope 1 CO2 emissions are those shown produced from the facility units. Scope 2 CO2 emissions are shown produced by the third-party cogeneration plant (TABLE 5). From this, a strategy to mitigate CO2 emissions can be developed.
Since Case 1 and Case 2 have equal fired duties and the same fuel gas composition, they have equal Scope 1 CO2 emissions. Similarly, since Case 3 and Case 4 have the same fired duties and the same fuel gas composition, they have equal Scope 1 CO2 emissions. Scope 2 CO2 emissions are different across the four cases, as shown in TABLE 5.
Discussion. Case 1 represents the base refinery configuration for the case study (FIG. 1). This refinery primarily produces gasoline, jet fuel and diesel. It also produces a significant amount of petroleum coke that is exported as a product from the facility. It also sells naphtha and propylene products, likely to another nearby petrochemical facility. This is a common configuration of many fuel-focused refineries that operate today. Such a facility is susceptible to market changes as the energy transition continues and changing regulations related to carbon emissions limits.
This facility is dropping potential profit margins by selling petrochemical feedstocks. With some investment, this facility can build its own petrochemical units to take advantage of the margin uplift from producing these products. The next three cases discuss potential paths toward petrochemical integration, along with the carbon neutrality roadmap strategy that should be considered. Refer to TABLE 2 for the baseline carbon emissions for this case and the other cases discussed below.
Case 2. Case 2 adds a PP unit as one option to move the facility toward petrochemical integration. The propylene produced from the FCCU and DCU that was sold as a product is moved to feed the PP unit. Assuming the facility can easily sell into the PP market, there are likely good positive margins from moving propylene to a PP product.
From a carbon neutrality perspective, the advantage of starting petrochemical integration with a PP unit is that this unit does not add to the Scope 1 emissions of the facility. However, it does add to the Scope 2 emissions for consideration in a mitigation strategy.
Case 3. In Case 3, heavy naphtha is separated from the full-range naphtha product and fed to a naphtha hydrotreater (NHT), reformer and aromatics complex. This is another path that can be taken toward petrochemical integration, utilizing the naphtha sold toward higher value products, namely benzene and PX. Although these added petrochemicals result in additional Scope 1 CO2 emissions, the significant quantity of additional petrochemical products that can be produced should prove to be profitable overall, even after any carbon emissions mitigation is considered.
One advantage to highlight for this case is that due to a portion of the H2 produced by the reformer ending up in the fuel gas system, the CO2 emissions levels from all Scope 1 CO2 emissions sources are dropped due to the higher quantity of H2 present in the fuel gas. In fact, TABLE 2 shows that the Scope 1 emissions are less than in Cases 1 and 2 as a result, even though additional emissions sources are added to the facility.
Case 4. Case 4 integrates the PP unit from Case 2 and the aromatics plant from Case 3 into a single case. The CAPEX required for this level of integration is obviously the highest of the cases, but it also offers the higher marginal uplift and potential Scope 1 emissions reduction of the other cases. However, this case results in the highest quantity of Scope 2 emissions, which must be considered in the carbon neutrality strategy.
The addition of the PP unit does not affect the overall fuel gas consumption, so Cases 1 and 2 and Cases 3 and 4 have the same fuel gas compositions. In Cases 3 and 4, with the addition of the reformer to the configuration, more H2 and methane (CH4) are produced, both of which are routed to the fuel gas system. The LP model optimization chooses to route all the propane to the LPG product instead of to the fuel gas system as it chose for Cases 1 and 2. The result is a reduced quantity of CO2 emissions for the same fired duty.
Carbon neutrality roadmap strategy. The carbon neutrality roadmap strategy involves engineering, fuel switching, carbon capture and carbon offsetting, as presented in TABLE 6. The first step in the carbon neutrality roadmap strategy is the initial assessment and benchmarking. This includes an estimation of GHG emissions and energy intensity for all the processing units.
15%–20% carbon reduction by 2030. Comparing the energy intensity of respective processing units with the best available technology (BAT) or national benchmarks provides a good starting point. If the energy intensity is higher compared to the BAT or national energy intensity guidelines, this provides an opportunity to optimize the energy intensity. At this stage, fuel gas consumption, steam import and exports, and electricity consumption can be optimized for the processing units via energy efficiency and optimization, pinch analysis, waste heat recovery, etc. For the licensed units, the technology providers can provide energy savings options. This is low-hanging fruit5,6 and can be easily achieved within the next couple of years without much CAPEX with a carbon reduction of 15%–20%. Therefore, achieving a 20% carbon reduction by 2030 comes without much CAPEX.
60%–75% carbon reduction by 2040. Further carbon reduction comes with CAPEX-intense solutions such as carbon capture units, fuel switching5,6 or renewable energy. A carbon capture unit’s cost can vary significantly depending on the use or storage. If the captured CO2 must be stored underground—such as geological sequestration in Class VI wells—it must be dehydrated and compressed first, which requires additional CAPEX. The high-level cost estimate—excluding OSBLs, offsites and future price escalations—can be put together during the conceptual development phase. This can provide necessary information for the refiners to decide whether to build the carbon capture facility onsite or let it be built, owned, operated and maintained (BOOM) by a third-party. The U.S. Inflation Reduction Act (IRA) was signed into law in 2022, which provides the 45Q tax credit of $85/t of CO2 captured and stored for 12 yr of operations. For refiners to take advantage of these tax credits, the carbon capture units must capture and store at least 100,000 tpy of CO2, and these carbon capture units must not only be designed but also be fully operational by Jan 1, 2033. In this study, carbon capture units captured and stored 75% of CO2, which resulted in 45Q tax credits of $1.5 B–1.7 B over a 12-yr period. The amount of tax credits provides significant opportunity cost to make the case for CAPEX expenses for the carbon capture units.
Net-zero by 2050. Residual CO2 emissions—i.e., somewhere between 5%–30%—could be offset by purchasing carbon credits. These carbon credits could range between $40/t and $100/t of CO2. In this study, carbon credits provided 5% carbon offset with $65/t CO2, resulting in the cost of $1.3 MM/yr–1.4 MM/yr.
Takeaways. This article has outlined a systematic approach to a carbon neutrality roadmap strategy for integrated oil refinery and petrochemical facilities. Initially perceived as cost-prohibitive, carbon neutrality can be financially viable through the integration of refineries with petrochemicals facilities, which boosts revenues. These increased revenues, combined with energy efficiency measures and 45Q tax credits from the U.S. IRA, can fund CAPEX-intensive carbon capture units.
It is crucial to recognize that there is no one-size-fits-all solution: each refinery is unique. Therefore, the feasibility of carbon neutrality should be assessed on a case-by-case basis, considering technical, commercial and regulatory aspects. The carbon neutrality roadmap strategy should commence as early as the conceptual feasibility phase for new facilities. For existing facilities, energy efficiency presents low-hanging fruit, capable of reducing emissions by 15%–20% with minimal-to-no CAPEX.
LITERATURE CITED
1 World Resources Institute, “Science-Based Targets initiative (SBTi),” online: https://www.wri.org/initiatives/science-based-targets#:~:text=By%20the%20end%20of%202023,them%20validated%20by%20the%20SBTi
2 Sverdrup, B. O., “How to realistically decarbonize the oil and gas industry,” YouTube, March 3, 2022, online: www.youtube.com/watch?v=XNNuwvbR6aA
3 International Standards Organization (ISO), “ISO 14068-1:2023: Climate change management—Transition to net-zero,” 2023, online: https://www.iso.org/standard/43279.html
4 API, Compendium of Greenhouse Gas Emissions Methodologies, online: https://www.api.org/-/media/Files/Policy/ESG/GHG/API-GHG-Compendium-110921.pdf
5 Turner, J. and T. Chan, “Decarbonization of industrial fired heaters using hydrogen fuel,” YouTube, October 13, 2022, online: www.youtube.com/watch?v=WLN-o62x5wo
6 Turner, J., T. Chan and S. Rabb, “Using hydrogen to decarbonize industrial fired heaters,” Chemical Engineering Progress, 2024.
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