Sohrab Fathi
Faculty Member
Kermanshah University of Technology
Dr. Fathi holds a Ph.D. and M.Sc. in Chemical Engineering from Amirkabir University of Technology (Tehran Polytechnic). He is an assistant professor at Kermanshah University of Technology with over 15 years of academic experience. Dr. Fathi has served on Research Council of Ilam Gas Refining Company and led several industrial projects for the NIOC and the NIGC. His research focuses on oil and gas separation technologies for decarbonization, CCS, power-to-gas systems, and adsorption processes.
Participates in
TECHNICAL PROGRAMME | Energy Fuels and Molecules
Fueling the Future: Innovations & Strategies for Tomorrow’s Electricity Supply
Forum 13 | Technical Programme Hall 3
27
April
13:30
15:00
UTC+3
As the global energy sector transitions towards a low-carbon future, experts are discussing projects that use excess renewable electricity to electrolyze water into hydrogen (H2) and oxygen (O2), injecting the hydrogen into existing natural gas pipelines for both storage and transportation. This process is well-known as the Power-to-Gas (PtG) technique.
This study investigates the potential of hydrogen blending as a key policy for contributing a reliable and sustainable electricity supply in the future by integrating renewable energy sources into existing infrastructure. Blending renewable hydrogen into natural gas networks can either be co-combusted with natural gas for decarbonized thermal applications. Alternatively, it can be separated downstream using membrane or pressure swing adsorption (PSA) technologies for application in related industries or as a fuel cell feed. We have also verified blending hydrogen into natural gas pipeline networks and determined the key barriers related to this process. Recent advancements in pipeline material science have expanded the safe limits for hydrogen blending. Under appropriate conditions and at relatively low hydrogen concentrations (approximately 5% by volume), blending may require only minor modifications to the operation and maintenance of the pipeline networks. Recent advancements in pipeline technology indicate that hydrogen can be added to the pipeline by up to 20% in low-pressure systems with minimal impact on infrastructures.
This study presents a dynamic blending approach that adjusts the hydrogen mix in real-time based on renewable generation profiles, energy demand, and grid conditions. By integrating smart grid technologies and digital monitoring tools, this system can adapt to varying conditions, optimizing hydrogen injection to maximize efficiency and reduce carbon emissions.
Technical analysis suggests that infrastructure modifications to accommodate up to 20% hydrogen can be achieved with the potential for significant reductions in CO2 emissions—up to 60% in certain regions. Moreover, specific challenges must be addressed for higher blends of up to 40%, such as potential damage to household appliances or the need for increased compression capacity along distribution networks. Blends above 40% face more challenging matters across multiple areas, including pipeline materials, safety, and modifications required for end-use appliances or other applications.
The paper concludes by summarizing the key findings and offering recommendations for policymakers, urging the harmonization of hydrogen blending standards, and investment in pilot projects to test and demonstrate the scalability of PtG solutions. By facilitating the mixture of hydrogen into the natural gas pipelines, the PtG project will play an important role in achieving a reliable, sustainable, and low-carbon electricity supply for the future.
Co-author/s:
Roozbeh Mehdiaba, Engineering Manager, Kermanshah Province Gas Company.
This study investigates the potential of hydrogen blending as a key policy for contributing a reliable and sustainable electricity supply in the future by integrating renewable energy sources into existing infrastructure. Blending renewable hydrogen into natural gas networks can either be co-combusted with natural gas for decarbonized thermal applications. Alternatively, it can be separated downstream using membrane or pressure swing adsorption (PSA) technologies for application in related industries or as a fuel cell feed. We have also verified blending hydrogen into natural gas pipeline networks and determined the key barriers related to this process. Recent advancements in pipeline material science have expanded the safe limits for hydrogen blending. Under appropriate conditions and at relatively low hydrogen concentrations (approximately 5% by volume), blending may require only minor modifications to the operation and maintenance of the pipeline networks. Recent advancements in pipeline technology indicate that hydrogen can be added to the pipeline by up to 20% in low-pressure systems with minimal impact on infrastructures.
This study presents a dynamic blending approach that adjusts the hydrogen mix in real-time based on renewable generation profiles, energy demand, and grid conditions. By integrating smart grid technologies and digital monitoring tools, this system can adapt to varying conditions, optimizing hydrogen injection to maximize efficiency and reduce carbon emissions.
Technical analysis suggests that infrastructure modifications to accommodate up to 20% hydrogen can be achieved with the potential for significant reductions in CO2 emissions—up to 60% in certain regions. Moreover, specific challenges must be addressed for higher blends of up to 40%, such as potential damage to household appliances or the need for increased compression capacity along distribution networks. Blends above 40% face more challenging matters across multiple areas, including pipeline materials, safety, and modifications required for end-use appliances or other applications.
The paper concludes by summarizing the key findings and offering recommendations for policymakers, urging the harmonization of hydrogen blending standards, and investment in pilot projects to test and demonstrate the scalability of PtG solutions. By facilitating the mixture of hydrogen into the natural gas pipelines, the PtG project will play an important role in achieving a reliable, sustainable, and low-carbon electricity supply for the future.
Co-author/s:
Roozbeh Mehdiaba, Engineering Manager, Kermanshah Province Gas Company.
TECHNICAL PROGRAMME | Energy Infrastructure
CCS Hub Facilities
Forum 09 | Technical Programme Hall 2
28
April
14:30
16:00
UTC+3
Iran, with the fourth largest proven oil reserves in the world, faces two major challenges: decreasing oil production in the mature fields and increasing pressure to reduce carbon emissions in the energy sector. One proposed solution is to combine enhanced oil recovery (EOR) with carbon capture and storage (CCS) by injecting CO₂ into depleted or partially depleted reservoirs. This study examines the technical and geological feasibility of establishing CCS hubs in Iran, according to actual data from domestic reservoirs.
This analysis examines several oil reservoirs in the southern and southwestern of Iran, including the Maroon, Ahvaz, and Aghajari fields. According to data from the National Iranian Oil Company (NIOC), these fields have an estimated CO2 storage capacity of more than 4.3 billion tons. For example, the Aghajari field alone has the potential to store about 730 million tons of CO₂, which is equivalent to decades of injection under a standard EOR program. Injection at pressures of 1100 up to 1500 psi can provide miscibility in these formations and increase oil recovery by up to 12%.
This study uses seismic and petrophysical data to investigate formation integrity, properties of caprock sealing, and regional fault systems. Also, the separation of carbon dioxide from produced oil—a major operational bottleneck—has been investigated, according to existing gas separation and recovery units. The deployment of these infrastructures reduces the new investment costs and make the integrated CCS hubs more economically viable.
Although Iran currently does not have an official mechanism for carbon pricing, the feasibility study of this plan has been done using global carbon credit prices between $30 and $100 per ton. The results show that the break-even point of the project is achieved in less than 10 years under optimal recovery conditions. Having the dual benefit of increasing oil recovery and permanent CO₂ storage, this plan is aligned with Iran's strategic goals to increase the life of reservoirs and reduce carbon emissions.
Several CO₂-EOR projects have been done in Iran, mainly focusing on enhancing oil recovery and reducing greenhouse gas emissions. A pilot project at the Ramin oil field utilized CO₂ captured from the Ramin Power Plant, aiming to increase oil recovery by 16–80%. Also, feasibility studies by Alborz Energy examined over 40 reservoirs for CO₂ injection, leading to the design of necessary capture and injection infrastructure. Additional evaluations estimated that each ton of injected CO₂ could yield 2–8 additional barrels of oil.
This paper suggests that CCS hubs based on CO2-EOR in Iran are technically and geologically feasible. With appropriate regulatory frameworks and investment in monitoring and verification, these hubs could form the backbone of Iran’s long-term carbon management infrastructure.
Co-author/s:
Saeed Ovaysi, Faculty Member, Razi University.
Roozbeh Mehdiabadi, Engineering Manager, Kermanshah Province Gas Company.
This analysis examines several oil reservoirs in the southern and southwestern of Iran, including the Maroon, Ahvaz, and Aghajari fields. According to data from the National Iranian Oil Company (NIOC), these fields have an estimated CO2 storage capacity of more than 4.3 billion tons. For example, the Aghajari field alone has the potential to store about 730 million tons of CO₂, which is equivalent to decades of injection under a standard EOR program. Injection at pressures of 1100 up to 1500 psi can provide miscibility in these formations and increase oil recovery by up to 12%.
This study uses seismic and petrophysical data to investigate formation integrity, properties of caprock sealing, and regional fault systems. Also, the separation of carbon dioxide from produced oil—a major operational bottleneck—has been investigated, according to existing gas separation and recovery units. The deployment of these infrastructures reduces the new investment costs and make the integrated CCS hubs more economically viable.
Although Iran currently does not have an official mechanism for carbon pricing, the feasibility study of this plan has been done using global carbon credit prices between $30 and $100 per ton. The results show that the break-even point of the project is achieved in less than 10 years under optimal recovery conditions. Having the dual benefit of increasing oil recovery and permanent CO₂ storage, this plan is aligned with Iran's strategic goals to increase the life of reservoirs and reduce carbon emissions.
Several CO₂-EOR projects have been done in Iran, mainly focusing on enhancing oil recovery and reducing greenhouse gas emissions. A pilot project at the Ramin oil field utilized CO₂ captured from the Ramin Power Plant, aiming to increase oil recovery by 16–80%. Also, feasibility studies by Alborz Energy examined over 40 reservoirs for CO₂ injection, leading to the design of necessary capture and injection infrastructure. Additional evaluations estimated that each ton of injected CO₂ could yield 2–8 additional barrels of oil.
This paper suggests that CCS hubs based on CO2-EOR in Iran are technically and geologically feasible. With appropriate regulatory frameworks and investment in monitoring and verification, these hubs could form the backbone of Iran’s long-term carbon management infrastructure.
Co-author/s:
Saeed Ovaysi, Faculty Member, Razi University.
Roozbeh Mehdiabadi, Engineering Manager, Kermanshah Province Gas Company.
