TECHNICAL PROGRAMME | Energy Fuels and Molecules – Future Pathways
Fueling the Future: Innovations & Strategies for Tomorrow’s Electricity Supply
Forum 13 | Hall 10 - Technical Programme 3
12
October
16:00
17:30
UTC+3
As the world transitions to a lower carbon energy future, the electricity supply system is undergoing significant changes. This session will explore the key trends, technologies, and challenges in ensuring a reliable and sustainable electricity supply. Topics will include renewable energy integration, advancements in grid technology, energy storage solutions, and the role of emerging technologies like hydrogen and CCS. The session will look at how different energy sources and technologies can work together to fuel the future of electricity.
This study explores the potential of repurposing long-shut gas wells in China’s Ordos Basin for enhanced geothermal electricity generation through cold water injection within an Enhanced Geothermal System (EGS). The focus is on achieving sustainable high-temperature water production for electricity generation from ultra-low permeability reservoirs, with Lian5 and Lian6 abandoned directional gas wells used as case studies.
A dual-permeability model was developed using CMG STARS software to simulate various operational strategies. The model incorporated key factors such as natural microfractures, hydraulic fractures, and heat transfer within wellbores. The Lian5 well was vertically drilled and then side-drilled to form a horizontal section, which was connected to the Lian6 directional well for water production. The horizontal section of Lian5 was hydraulically fractured to create a high-permeability fracture network, enhancing heat exchange and facilitating cold water injection for efficient electricity generation.
Results indicated that closed-loop wells failed to sustain high-temperature production due to inadequate fracture networks. Directional wells met short-term production needs but showed rapid temperature decline. Horizontal wells, enhanced with high-conductivity fracture networks, proved optimal, maintaining stable production above 90°C for nearly ten years. For long-term cooling and electricity generation, lower injection volumes (1500m³/day to 2000m³/day) resulted in more stable and sustainable effects. Sensitivity analysis revealed that wider well spacing minimized thermal interference, thus improving system longevity and efficiency.
This research introduces a novel approach to sustainable geothermal electricity generation by optimizing horizontally stimulated wells in ultra-low permeability reservoirs, contributing valuable insights into the application of EGS technology in the Ordos Basin and offering a practical pathway for future geothermal electricity supply.
A dual-permeability model was developed using CMG STARS software to simulate various operational strategies. The model incorporated key factors such as natural microfractures, hydraulic fractures, and heat transfer within wellbores. The Lian5 well was vertically drilled and then side-drilled to form a horizontal section, which was connected to the Lian6 directional well for water production. The horizontal section of Lian5 was hydraulically fractured to create a high-permeability fracture network, enhancing heat exchange and facilitating cold water injection for efficient electricity generation.
Results indicated that closed-loop wells failed to sustain high-temperature production due to inadequate fracture networks. Directional wells met short-term production needs but showed rapid temperature decline. Horizontal wells, enhanced with high-conductivity fracture networks, proved optimal, maintaining stable production above 90°C for nearly ten years. For long-term cooling and electricity generation, lower injection volumes (1500m³/day to 2000m³/day) resulted in more stable and sustainable effects. Sensitivity analysis revealed that wider well spacing minimized thermal interference, thus improving system longevity and efficiency.
This research introduces a novel approach to sustainable geothermal electricity generation by optimizing horizontally stimulated wells in ultra-low permeability reservoirs, contributing valuable insights into the application of EGS technology in the Ordos Basin and offering a practical pathway for future geothermal electricity supply.
As the world transitions towards a low-carbon energy future, hydrogen is emerging as a crucial component of the energy mix. Depleted oil and gas reservoirs present a promising opportunity for subsurface hydrogen storage for excess energy, leveraging their geological characteristics and existing infrastructure. The objective of this study is to develop a comprehensive screening framework for evaluating depleted oil and gas reservoirs as potential subsurface hydrogen storage sites, supporting site selection and accelerating deployment.
The proposed framework is a multi-criteria decision analysis that integrates both quantitative and qualitative assessments to evaluate the suitability of depleted reservoirs for subsurface hydrogen storage. Quantitative evaluation is carried out using simulation models to assess the storage phase by quantifying the mount of hydrogen that can be injected, stored and withdrawn under varying reservoir and operational conditions, while qualitative assessment is performed through a weighted scoring matrix. The framework incorporates geological properties (e.g., porosity, permeability, caprock integrity), well characteristics (e.g., configurations, injectivity, deliverability), and operational parameters (e.g., pressure constraints, cyclic performance), for both early-phase screening and detailed feasibility assessment.
The application of the proposed framework to real-world depleted oil and gas reservoirs demonstrates its effectiveness in identifying and ranking suitable candidates for subsurface hydrogen storage. By integrating simulation results into the scoring criteria, the framework enabled a comparative assessment of multiple sites, where simulated reservoir performance under realistic technical and operational scenarios informed and supported the scoring and final ranking. This approach allowed for clear differentiation between more and less suitable reservoirs, supporting informed decision-making and prioritization for protentional further development. The evaluated cases revealed significant variability in key parameters, highlighting the importance of a tailored site-specific evaluation approach.
The integration of technical and operational factors, combined with the use of a scoring matrix, provides a robust and objective methodology for evaluating candidate reservoirs. This study's findings have significant implications for the development of hydrogen storage infrastructure, highlighting the potential for repurposing legacy hydrocarbon assets and reducing the need for new surface infrastructure, ultimately supporting the transition to a low-carbon energy future.
The proposed framework is a multi-criteria decision analysis that integrates both quantitative and qualitative assessments to evaluate the suitability of depleted reservoirs for subsurface hydrogen storage. Quantitative evaluation is carried out using simulation models to assess the storage phase by quantifying the mount of hydrogen that can be injected, stored and withdrawn under varying reservoir and operational conditions, while qualitative assessment is performed through a weighted scoring matrix. The framework incorporates geological properties (e.g., porosity, permeability, caprock integrity), well characteristics (e.g., configurations, injectivity, deliverability), and operational parameters (e.g., pressure constraints, cyclic performance), for both early-phase screening and detailed feasibility assessment.
The application of the proposed framework to real-world depleted oil and gas reservoirs demonstrates its effectiveness in identifying and ranking suitable candidates for subsurface hydrogen storage. By integrating simulation results into the scoring criteria, the framework enabled a comparative assessment of multiple sites, where simulated reservoir performance under realistic technical and operational scenarios informed and supported the scoring and final ranking. This approach allowed for clear differentiation between more and less suitable reservoirs, supporting informed decision-making and prioritization for protentional further development. The evaluated cases revealed significant variability in key parameters, highlighting the importance of a tailored site-specific evaluation approach.
The integration of technical and operational factors, combined with the use of a scoring matrix, provides a robust and objective methodology for evaluating candidate reservoirs. This study's findings have significant implications for the development of hydrogen storage infrastructure, highlighting the potential for repurposing legacy hydrocarbon assets and reducing the need for new surface infrastructure, ultimately supporting the transition to a low-carbon energy future.
Hydrogen has emerged as a cornerstone of future low-carbon energy systems, offering clean, high-density, and versatile energy storage across power, transportation, and industry sectors. As hydrogen deployment accelerates globally, the development of large-scale, long-duration storage solutions becomes increasingly critical to bridge temporal mismatches between intermittent renewable generation and stable energy demand. Underground hydrogen storage (UHS) in depleted gas reservoirs presents a technically viable and geologically abundant solution, with high storage capacity, proven seal structures, and existing infrastructure enabling rapid deployment. However, subsurface hydrogen storage introduces complex multiphysics interactions—particularly thermal, hydraulic, chemical, and mechanical (THMC) couplings—that challenge storage efficiency, reservoir stability, and long-term system integrity, especially under cyclic injection–production conditions.
This study establishes a fully coupled numerical modeling framework to simulate THMC responses during repeated hydrogen injection–production cycles in porous and fractured formations. The model integrates thermal conduction, multiphase flow governed by Darcy's law, hydrogen–mineral geochemical interactions based on kinetic and equilibrium reactions, porosity and permeability evolution linked to mineral dissolution and precipitation, and mechanical deformation driven by stress redistribution. Rock deformation is modeled using stress–strain relationships that account for pressure sensitivity and thermoelastic effects. The coupling strategy allows for dynamic feedback among heat transfer, fluid migration, chemical alteration, and geomechanical responses. Boundary conditions such as temperature gradients, injection pressure schedules, fluid composition, and initial mineralogical heterogeneity are systematically varied to assess their impact on reservoir evolution and hydrogen storage performance.
Simulation results show that hydrogen–rock reactions, particularly those involving carbonates and sulfates, can lead to mineral dissolution, secondary precipitation, and spatial heterogeneity in pore structure. These geochemical changes alter permeability fields and modulate pressure propagation. Concurrently, thermal effects such as local heating enhance reaction rates, while stress redistribution causes compaction or dilation, especially in weakly cemented zones. The interaction between these coupled fields results in asymmetric hydrogen plume evolution, reduced injectivity, and localized sealing risk.
The THMC model provides a quantitative tool to evaluate storage performance and containment safety under complex geologic and operational conditions. The findings contribute to a deeper understanding of reservoir evolution during hydrogen cycling and offer technical insights for optimizing UHS system design, operational strategy, and long-term risk mitigation.
This study establishes a fully coupled numerical modeling framework to simulate THMC responses during repeated hydrogen injection–production cycles in porous and fractured formations. The model integrates thermal conduction, multiphase flow governed by Darcy's law, hydrogen–mineral geochemical interactions based on kinetic and equilibrium reactions, porosity and permeability evolution linked to mineral dissolution and precipitation, and mechanical deformation driven by stress redistribution. Rock deformation is modeled using stress–strain relationships that account for pressure sensitivity and thermoelastic effects. The coupling strategy allows for dynamic feedback among heat transfer, fluid migration, chemical alteration, and geomechanical responses. Boundary conditions such as temperature gradients, injection pressure schedules, fluid composition, and initial mineralogical heterogeneity are systematically varied to assess their impact on reservoir evolution and hydrogen storage performance.
Simulation results show that hydrogen–rock reactions, particularly those involving carbonates and sulfates, can lead to mineral dissolution, secondary precipitation, and spatial heterogeneity in pore structure. These geochemical changes alter permeability fields and modulate pressure propagation. Concurrently, thermal effects such as local heating enhance reaction rates, while stress redistribution causes compaction or dilation, especially in weakly cemented zones. The interaction between these coupled fields results in asymmetric hydrogen plume evolution, reduced injectivity, and localized sealing risk.
The THMC model provides a quantitative tool to evaluate storage performance and containment safety under complex geologic and operational conditions. The findings contribute to a deeper understanding of reservoir evolution during hydrogen cycling and offer technical insights for optimizing UHS system design, operational strategy, and long-term risk mitigation.
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.
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.
As the world transitions towards a low-carbon energy future, hydrogen is emerging as a crucial component of the energy mix. Depleted oil and gas reservoirs present a promising opportunity for subsurface hydrogen storage for excess energy, leveraging their geological characteristics and existing infrastructure. The objective of this study is to develop a comprehensive screening framework for evaluating depleted oil and gas reservoirs as potential subsurface hydrogen storage sites, supporting site selection and accelerating deployment.
The proposed framework is a multi-criteria decision analysis that integrates both quantitative and qualitative assessments to evaluate the suitability of depleted reservoirs for subsurface hydrogen storage. Quantitative evaluation is carried out using simulation models to assess the storage phase by quantifying the mount of hydrogen that can be injected, stored and withdrawn under varying reservoir and operational conditions, while qualitative assessment is performed through a weighted scoring matrix. The framework incorporates geological properties (e.g., porosity, permeability, caprock integrity), well characteristics (e.g., configurations, injectivity, deliverability), and operational parameters (e.g., pressure constraints, cyclic performance), for both early-phase screening and detailed feasibility assessment.
The application of the proposed framework to real-world depleted oil and gas reservoirs demonstrates its effectiveness in identifying and ranking suitable candidates for subsurface hydrogen storage. By integrating simulation results into the scoring criteria, the framework enabled a comparative assessment of multiple sites, where simulated reservoir performance under realistic technical and operational scenarios informed and supported the scoring and final ranking. This approach allowed for clear differentiation between more and less suitable reservoirs, supporting informed decision-making and prioritization for protentional further development. The evaluated cases revealed significant variability in key parameters, highlighting the importance of a tailored site-specific evaluation approach.
The integration of technical and operational factors, combined with the use of a scoring matrix, provides a robust and objective methodology for evaluating candidate reservoirs. This study's findings have significant implications for the development of hydrogen storage infrastructure, highlighting the potential for repurposing legacy hydrocarbon assets and reducing the need for new surface infrastructure, ultimately supporting the transition to a low-carbon energy future.
The proposed framework is a multi-criteria decision analysis that integrates both quantitative and qualitative assessments to evaluate the suitability of depleted reservoirs for subsurface hydrogen storage. Quantitative evaluation is carried out using simulation models to assess the storage phase by quantifying the mount of hydrogen that can be injected, stored and withdrawn under varying reservoir and operational conditions, while qualitative assessment is performed through a weighted scoring matrix. The framework incorporates geological properties (e.g., porosity, permeability, caprock integrity), well characteristics (e.g., configurations, injectivity, deliverability), and operational parameters (e.g., pressure constraints, cyclic performance), for both early-phase screening and detailed feasibility assessment.
The application of the proposed framework to real-world depleted oil and gas reservoirs demonstrates its effectiveness in identifying and ranking suitable candidates for subsurface hydrogen storage. By integrating simulation results into the scoring criteria, the framework enabled a comparative assessment of multiple sites, where simulated reservoir performance under realistic technical and operational scenarios informed and supported the scoring and final ranking. This approach allowed for clear differentiation between more and less suitable reservoirs, supporting informed decision-making and prioritization for protentional further development. The evaluated cases revealed significant variability in key parameters, highlighting the importance of a tailored site-specific evaluation approach.
The integration of technical and operational factors, combined with the use of a scoring matrix, provides a robust and objective methodology for evaluating candidate reservoirs. This study's findings have significant implications for the development of hydrogen storage infrastructure, highlighting the potential for repurposing legacy hydrocarbon assets and reducing the need for new surface infrastructure, ultimately supporting the transition to a low-carbon energy future.
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.
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.
Hydrogen has emerged as a cornerstone of future low-carbon energy systems, offering clean, high-density, and versatile energy storage across power, transportation, and industry sectors. As hydrogen deployment accelerates globally, the development of large-scale, long-duration storage solutions becomes increasingly critical to bridge temporal mismatches between intermittent renewable generation and stable energy demand. Underground hydrogen storage (UHS) in depleted gas reservoirs presents a technically viable and geologically abundant solution, with high storage capacity, proven seal structures, and existing infrastructure enabling rapid deployment. However, subsurface hydrogen storage introduces complex multiphysics interactions—particularly thermal, hydraulic, chemical, and mechanical (THMC) couplings—that challenge storage efficiency, reservoir stability, and long-term system integrity, especially under cyclic injection–production conditions.
This study establishes a fully coupled numerical modeling framework to simulate THMC responses during repeated hydrogen injection–production cycles in porous and fractured formations. The model integrates thermal conduction, multiphase flow governed by Darcy's law, hydrogen–mineral geochemical interactions based on kinetic and equilibrium reactions, porosity and permeability evolution linked to mineral dissolution and precipitation, and mechanical deformation driven by stress redistribution. Rock deformation is modeled using stress–strain relationships that account for pressure sensitivity and thermoelastic effects. The coupling strategy allows for dynamic feedback among heat transfer, fluid migration, chemical alteration, and geomechanical responses. Boundary conditions such as temperature gradients, injection pressure schedules, fluid composition, and initial mineralogical heterogeneity are systematically varied to assess their impact on reservoir evolution and hydrogen storage performance.
Simulation results show that hydrogen–rock reactions, particularly those involving carbonates and sulfates, can lead to mineral dissolution, secondary precipitation, and spatial heterogeneity in pore structure. These geochemical changes alter permeability fields and modulate pressure propagation. Concurrently, thermal effects such as local heating enhance reaction rates, while stress redistribution causes compaction or dilation, especially in weakly cemented zones. The interaction between these coupled fields results in asymmetric hydrogen plume evolution, reduced injectivity, and localized sealing risk.
The THMC model provides a quantitative tool to evaluate storage performance and containment safety under complex geologic and operational conditions. The findings contribute to a deeper understanding of reservoir evolution during hydrogen cycling and offer technical insights for optimizing UHS system design, operational strategy, and long-term risk mitigation.
This study establishes a fully coupled numerical modeling framework to simulate THMC responses during repeated hydrogen injection–production cycles in porous and fractured formations. The model integrates thermal conduction, multiphase flow governed by Darcy's law, hydrogen–mineral geochemical interactions based on kinetic and equilibrium reactions, porosity and permeability evolution linked to mineral dissolution and precipitation, and mechanical deformation driven by stress redistribution. Rock deformation is modeled using stress–strain relationships that account for pressure sensitivity and thermoelastic effects. The coupling strategy allows for dynamic feedback among heat transfer, fluid migration, chemical alteration, and geomechanical responses. Boundary conditions such as temperature gradients, injection pressure schedules, fluid composition, and initial mineralogical heterogeneity are systematically varied to assess their impact on reservoir evolution and hydrogen storage performance.
Simulation results show that hydrogen–rock reactions, particularly those involving carbonates and sulfates, can lead to mineral dissolution, secondary precipitation, and spatial heterogeneity in pore structure. These geochemical changes alter permeability fields and modulate pressure propagation. Concurrently, thermal effects such as local heating enhance reaction rates, while stress redistribution causes compaction or dilation, especially in weakly cemented zones. The interaction between these coupled fields results in asymmetric hydrogen plume evolution, reduced injectivity, and localized sealing risk.
The THMC model provides a quantitative tool to evaluate storage performance and containment safety under complex geologic and operational conditions. The findings contribute to a deeper understanding of reservoir evolution during hydrogen cycling and offer technical insights for optimizing UHS system design, operational strategy, and long-term risk mitigation.
Yushuo Zhang
Speaker
Petroleum Engineer
Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company
China
This study explores the potential of repurposing long-shut gas wells in China’s Ordos Basin for enhanced geothermal electricity generation through cold water injection within an Enhanced Geothermal System (EGS). The focus is on achieving sustainable high-temperature water production for electricity generation from ultra-low permeability reservoirs, with Lian5 and Lian6 abandoned directional gas wells used as case studies.
A dual-permeability model was developed using CMG STARS software to simulate various operational strategies. The model incorporated key factors such as natural microfractures, hydraulic fractures, and heat transfer within wellbores. The Lian5 well was vertically drilled and then side-drilled to form a horizontal section, which was connected to the Lian6 directional well for water production. The horizontal section of Lian5 was hydraulically fractured to create a high-permeability fracture network, enhancing heat exchange and facilitating cold water injection for efficient electricity generation.
Results indicated that closed-loop wells failed to sustain high-temperature production due to inadequate fracture networks. Directional wells met short-term production needs but showed rapid temperature decline. Horizontal wells, enhanced with high-conductivity fracture networks, proved optimal, maintaining stable production above 90°C for nearly ten years. For long-term cooling and electricity generation, lower injection volumes (1500m³/day to 2000m³/day) resulted in more stable and sustainable effects. Sensitivity analysis revealed that wider well spacing minimized thermal interference, thus improving system longevity and efficiency.
This research introduces a novel approach to sustainable geothermal electricity generation by optimizing horizontally stimulated wells in ultra-low permeability reservoirs, contributing valuable insights into the application of EGS technology in the Ordos Basin and offering a practical pathway for future geothermal electricity supply.
A dual-permeability model was developed using CMG STARS software to simulate various operational strategies. The model incorporated key factors such as natural microfractures, hydraulic fractures, and heat transfer within wellbores. The Lian5 well was vertically drilled and then side-drilled to form a horizontal section, which was connected to the Lian6 directional well for water production. The horizontal section of Lian5 was hydraulically fractured to create a high-permeability fracture network, enhancing heat exchange and facilitating cold water injection for efficient electricity generation.
Results indicated that closed-loop wells failed to sustain high-temperature production due to inadequate fracture networks. Directional wells met short-term production needs but showed rapid temperature decline. Horizontal wells, enhanced with high-conductivity fracture networks, proved optimal, maintaining stable production above 90°C for nearly ten years. For long-term cooling and electricity generation, lower injection volumes (1500m³/day to 2000m³/day) resulted in more stable and sustainable effects. Sensitivity analysis revealed that wider well spacing minimized thermal interference, thus improving system longevity and efficiency.
This research introduces a novel approach to sustainable geothermal electricity generation by optimizing horizontally stimulated wells in ultra-low permeability reservoirs, contributing valuable insights into the application of EGS technology in the Ordos Basin and offering a practical pathway for future geothermal electricity supply.
