The oil and gas industry is responsible for 6% of total global CO2 emissions, from exploration to downstream petrochemical production and account for another 50% when including the use of its products. Thus, this industry has a significant role in realising the target of net “zero” CO2 emissions by 2070, essential to limit global warming to 1.8 °C [2], as introduced under the Paris agreement. Currently, the interactions of an extensive set of individual and combined CO2 mitigation measures along the value chain and over time are poorly assessed. This paper aims to assess a bottom-up CO2 mitigation potential for a complex refinery, including portfolios of combined mitigation options, considering synergies, overlap, and interactions over time for more realistic insight into the costs and constraints of the mitigation portfolio. A total of 40 measures were identified, covering a wide range of technologies such as energy efficiency measures (EEM), carbon capture and storage (CCS), bio-oil co-processing, blue and green hydrogen (BH2, GH2), green electricity import, and electrification of refining processes linked to the transition of the Colombian energy systems. Five deployment pathways were assessed to achieve different specific targets: 1-base case scenario, 2-less effort, 3-maximum CO2 avoidance, 4-INDC, and 5-measures below 200 €/t CO2. Two scenarios (3 and 5) gave the highest GHG emission reduction potentials of 106% and 98% of refining process emissions, respectively. Although significant, it represent only around 13% of the life-cycle emissions when including upstream and final-use emissions of the produced fuels. Bio-oil co-processing options account for around 60% of the mitigation options portfolio, followed by CCS (23%), green electricity (7%) and green H2 (6%). The devised methodological approach in this study can also be applied to assess other energy-intensive industrial complexes and shed light on the bias for estimating CO2 mitigation potentials, especially when combining different mitigation options. This is turn is vital to define optimal transition pathways of industrial complexes.@en

The oil industry needs to reduce CO2 emissions across the entire lifecycle of fossil fuels to meet environmental regulations and societal requirements and to sustain its business. With this goal in mind, this study aims to evaluate the CO2 mitigation potential of several bio-oil co-processing pathways in an oil refinery. Techno-economic analysis was conducted on different pathways and their greenhouse gas (GHG) mitigation potentials were compared. Thirteen pathways with different bio-oils, including vegetable oil (VO), fast pyrolysis oil (FPO), hydro-deoxygenated oil (HDO), catalytic pyrolysis oil (CPO), hydrothermal liquefaction oil (HTLO), and Fischer–Tropsch fuels, were analyzed. However, no single pathway could be presented as the best option. This would depend on the criteria used and the target of the co-processing route. The results obtained indicated that up to 15% of the fossil-fuel output in the refinery could be replaced by biofuel without major changes in the core activities of the refinery. The consequent reduction in CO2 emissions varied from 33% to 84% when compared with pure equivalent fossil fuels replaced (i.e., gasoline and diesel). Meanwhile, the production costs varied from 17 to 31€/GJ (i.e., 118–213$/bbleq). Co-processing with VO resulted in the lowest overall performance among the options that were evaluated while co-processing HTLO in the hydrotreatment unit and FPO in the fluid catalytic cracking unit showed the highest potential for CO2 avoidance (69% of refinery CO2 emissions) and reduction in CO2 emissions (84% compared to fossil fuel), respectively. The cost of CO2 emissions avoided for all of the assessed routes was in the range of €99–651 per tCO2.@en

Combining co-firing biomass and carbon capture and storage (CCS) in power plants offers attractive potential for net removal of carbon dioxide (CO2) from the atmosphere. In this study, the impact of co-firing biomass (wood pellets and straw pellets) on the emission profile of power plants with carbon capture and storage has been assessed for two types of coal-fired power plants: a supercritical pulverised coal power plant (SCPC) and an integrated gasification combined cycle plant (IGCC). Besides, comparative life cycle assessments have been performed to examine the environmental impacts of the combination of co-firing biomass and CCS. Detailed calculations on mass balances of the inputs and outputs of the power plants illustrate the effect of the different content of pollutants in biomass on the capture unit. Life cycle assessment results reveal that 30% co-firing biomass and applying CCS net negative CO2 emissions in the order of 67-85g/kWh are obtained. The impact in all other environmental categories is increased by 20-200%. However, aggregation into endpoint levels shows that the decrease in CO2 emissions more than offsets the increase in the other categories. Sensitivity analyses illustrate that results are most sensitive to parameters that affect the amount of fuel required, such as the efficiency of the power plant and assumptions regarding the supply chains of coal and biomass. Especially, assumptions regarding land use allocation and carbon debt of biomass significantly influence the environmental performance of BioCCS.@en

This paper studies the potential application of a novel biogas upgrading technology called alkaline with regeneration (AwR). This technology uses an alkaline solution, along with carbon mineralization, to remove and store CO2 from biogas in order to create biomethane, a substitute of natural gas. Three different applications of biogas were explored for their potential economic benefits along three different biogas generation capabilities of landfills in Spain (250Nm3/h, 1000Nm3/h and 5000Nm3/h). The scenarios include upgrading biogas using AwR and injecting the biomethane into the natural gas grid, or selling the gas as a vehicle fuel. The third reference scenario assessed directly burning the biogas for the production of electricity. The latter showed an annual profit of 0.2-5 million €2012 while upgrading the biogas to obtain biomethane showed an annual loss of 3-50 million €2012. This was due to the operational costs involved in AwR, namely the cost of NaOH (principal reagent) and the treatment of wastewater. Increasing revenue can help obtain an annual profit. In order to break-even it would be necessary to raise CO2 credits to 99€2012/t or, through feed in tariffs, increase the price of the sale of biomethane to 0.25€2012/kWh.@en

This paper studies the potential application of a novel biogas upgrading technology called alkaline with regeneration (AwR). This technology uses an alkaline solution, along with carbon mineralization, to remove and store CO2 from biogas in order to create biomethane, a substitute of natural gas. Three different applications of biogas were explored for their potential economic benefits along three different biogas generation capabilities of landfills in Spain (250Nm3/h, 1000Nm3/h and 5000Nm3/h). The scenarios include upgrading biogas using AwR and injecting the biomethane into the natural gas grid, or selling the gas as a vehicle fuel. The third reference scenario assessed directly burning the biogas for the production of electricity. The latter showed an annual profit of 0.2-5 million €2012 while upgrading the biogas to obtain biomethane showed an annual loss of 3-50 million €2012. This was due to the operational costs involved in AwR, namely the cost of NaOH (principal reagent) and the treatment of wastewater. Increasing revenue can help obtain an annual profit. In order to break-even it would be necessary to raise CO2 credits to 99€2012/t or, through feed in tariffs, increase the price of the sale of biomethane to 0.25€2012/kWh.@en

This paper studies the potential application of a novel biogas upgrading technology called alkaline with regeneration (AwR). This technology uses an alkaline solution, along with carbon mineralization, to remove and store CO2 from biogas in order to create biomethane, a substitute of natural gas. Three different applications of biogas were explored for their potential economic benefits along three different biogas generation capabilities of landfills in Spain (250Nm3/h, 1000Nm3/h and 5000Nm3/h). The scenarios include upgrading biogas using AwR and injecting the biomethane into the natural gas grid, or selling the gas as a vehicle fuel. The third reference scenario assessed directly burning the biogas for the production of electricity. The latter showed an annual profit of 0.2-5 million €2012 while upgrading the biogas to obtain biomethane showed an annual loss of 3-50 million €2012. This was due to the operational costs involved in AwR, namely the cost of NaOH (principal reagent) and the treatment of wastewater. Increasing revenue can help obtain an annual profit. In order to break-even it would be necessary to raise CO2 credits to 99€2012/t or, through feed in tariffs, increase the price of the sale of biomethane to 0.25€2012/kWh.@en

This paper studies the potential application of a novel biogas upgrading technology called alkaline with regeneration (AwR). This technology uses an alkaline solution, along with carbon mineralization, to remove and store CO2 from biogas in order to create biomethane, a substitute of natural gas. Three different applications of biogas were explored for their potential economic benefits along three different biogas generation capabilities of landfills in Spain (250Nm3/h, 1000Nm3/h and 5000Nm3/h). The scenarios include upgrading biogas using AwR and injecting the biomethane into the natural gas grid, or selling the gas as a vehicle fuel. The third reference scenario assessed directly burning the biogas for the production of electricity. The latter showed an annual profit of 0.2-5 million €2012 while upgrading the biogas to obtain biomethane showed an annual loss of 3-50 million €2012. This was due to the operational costs involved in AwR, namely the cost of NaOH (principal reagent) and the treatment of wastewater. Increasing revenue can help obtain an annual profit. In order to break-even it would be necessary to raise CO2 credits to 99€2012/t or, through feed in tariffs, increase the price of the sale of biomethane to 0.25€2012/kWh.@en