TECHNICAL PROGRAMME | Energy Technologies – Future Pathways
Research, Technology Start-ups and Funding
Forum 19 | Hall 5 Digital Poster Plaza 4
28
April
10:00
12:00
UTC+3
Technology and innovation are the key to energy transition. Significant advancements have been achieved for conventional energies production in terms of efficiency and emission reductions. New energies such as solar, wind, hydrogen, nuclear, hydro, biomass etc. together with energy storage and complementary technologies, have boomed and are playing more and more important roles in energy transition. This forum will discuss the latest progress and achievements including research, experiments, applications, management and investment, with a particular focus on the roles of start-ups and venture capitals in projects initiation, planning and commercialisation.
Natural hydrogen, often called “white hydrogen,” has emerged as a potential low-carbon energy resource. It occurs in various geologic settings such as cratonic basins, ultrabasic rock zones, and ophiolitic complexes. Unlike conventional hydrocarbon reservoirs, hydrogen accumulations are often associated with serpentinization reactions, water radiolysis, and degassing through faulted and fractured systems. This presents unique challenges for drilling, completion, and production design due to hydrogen’s low molecular weight, high mobility, and the reactivity of subsurface environments.
To ensure viable production, tailored completion strategies are essential. Natural hydrogen systems often feature shallow reservoirs (typically <3000 m), low pressures, and non-traditional trapping mechanisms. These factors necessitate specialized casing and cementing designs to prevent leakage and crossflow while minimizing the risk of gas migration during shut-in or low-flow periods. Corrosion-resistant materials must be considered due to hydrogen's propensity to embrittle steel and elastomers, especially under cyclical loading and long-term exposure.
Our proposed approach involves integrating real-time geochemical monitoring, pressure-transient analysis, and low-rate gas flow testing to characterize the productivity of hydrogen-bearing zones. Emphasis is placed on horizontal or multilateral well completions in fractured or fault-controlled systems, using open-hole or slotted-liner completions to maximize exposure to migrating hydrogen. Artificial lift strategies and low-flow metering systems are evaluated for early-life production monitoring, given the anticipated low volume and diffusivity-driven flow regimes of natural hydrogen systems.
Preliminary modeling and field analog studies suggest that managing hydrogen production requires a hybrid design philosophy, drawing from conventional gas and geothermal well practices. Initial outcomes indicate the need for adaptive well control strategies, long-duration flowback to desorb gas from microfractures, and optimized surface separation systems. These insights are critical to derisk early natural hydrogen exploration projects and will inform the development of regulatory and safety protocols as the industry scales.
Co-author/s:
Krishna Raghav Chaturvedi, Senior Research Fellow, Rajiv Gandhi Institute of Petroleum Technology.
To ensure viable production, tailored completion strategies are essential. Natural hydrogen systems often feature shallow reservoirs (typically <3000 m), low pressures, and non-traditional trapping mechanisms. These factors necessitate specialized casing and cementing designs to prevent leakage and crossflow while minimizing the risk of gas migration during shut-in or low-flow periods. Corrosion-resistant materials must be considered due to hydrogen's propensity to embrittle steel and elastomers, especially under cyclical loading and long-term exposure.
Our proposed approach involves integrating real-time geochemical monitoring, pressure-transient analysis, and low-rate gas flow testing to characterize the productivity of hydrogen-bearing zones. Emphasis is placed on horizontal or multilateral well completions in fractured or fault-controlled systems, using open-hole or slotted-liner completions to maximize exposure to migrating hydrogen. Artificial lift strategies and low-flow metering systems are evaluated for early-life production monitoring, given the anticipated low volume and diffusivity-driven flow regimes of natural hydrogen systems.
Preliminary modeling and field analog studies suggest that managing hydrogen production requires a hybrid design philosophy, drawing from conventional gas and geothermal well practices. Initial outcomes indicate the need for adaptive well control strategies, long-duration flowback to desorb gas from microfractures, and optimized surface separation systems. These insights are critical to derisk early natural hydrogen exploration projects and will inform the development of regulatory and safety protocols as the industry scales.
Co-author/s:
Krishna Raghav Chaturvedi, Senior Research Fellow, Rajiv Gandhi Institute of Petroleum Technology.
Energy saving and combustion optimization are crucial for several reasons:
Improved Efficiency: Optimizing combustion processes in chemical & petrochemical industries, such as reformers, furnaces and boilers, can enhance energy efficiency, reducing fuel consumption and operational costs.
Reduced Emissions: Better combustion control leads to lower emissions of pollutants like carbon monoxide, nitrogen oxides, and particulate matter, contributing to cleaner air and a healthier environment.
Enhanced Process Quality: Accurate and repeatable measurement of excess air ensures consistent combustion, improving the quality of the end product in manufacturing processes.
Safety: Proper combustion optimization reduces the risk of hazardous conditions, such as explosions or fires, by maintaining safe operating parameters.
Improving Combustion Efficiency is achieved by measuring the excess oxygen and combustibles by an oxygen analyzer. Measuring excess oxygen is essential for controlling Air/Fuel Ratio and to make sure that there is no excess fuel or excess air. Measuring combustibles is required to ensure efficient combustion with no left over non burned CO which is harmful for environment. Improving Burner Control is done by a gas chromatograph for measuring real time heating vale (BTU) for the fuel gas and measuring Wobbe Index for Burner Optimization, this is very essential for Calculating Air/Fuel Ratio to improve burner control, improve efficiency, and reduce emissions. By focusing on energy saving and combustion optimization, we can achieve a more sustainable, cost-effective, and safer future.
Improved Efficiency: Optimizing combustion processes in chemical & petrochemical industries, such as reformers, furnaces and boilers, can enhance energy efficiency, reducing fuel consumption and operational costs.
Reduced Emissions: Better combustion control leads to lower emissions of pollutants like carbon monoxide, nitrogen oxides, and particulate matter, contributing to cleaner air and a healthier environment.
Enhanced Process Quality: Accurate and repeatable measurement of excess air ensures consistent combustion, improving the quality of the end product in manufacturing processes.
Safety: Proper combustion optimization reduces the risk of hazardous conditions, such as explosions or fires, by maintaining safe operating parameters.
Improving Combustion Efficiency is achieved by measuring the excess oxygen and combustibles by an oxygen analyzer. Measuring excess oxygen is essential for controlling Air/Fuel Ratio and to make sure that there is no excess fuel or excess air. Measuring combustibles is required to ensure efficient combustion with no left over non burned CO which is harmful for environment. Improving Burner Control is done by a gas chromatograph for measuring real time heating vale (BTU) for the fuel gas and measuring Wobbe Index for Burner Optimization, this is very essential for Calculating Air/Fuel Ratio to improve burner control, improve efficiency, and reduce emissions. By focusing on energy saving and combustion optimization, we can achieve a more sustainable, cost-effective, and safer future.
Aqueous zinc-ion batteries (ZIBs) are emerging as safe, low-cost, and sustainable alternatives for large-scale energy storage. However, the widespread application of manganese dioxide (MnO₂) cathodes remains limited by their inherently poor electronic conductivity, slow Zn²⁺ diffusion, and gradual structural degradation. In this work, we demonstrate a simple, room temperature electrodeposition method to fabricate cobalt-doped MnO₂ (Co–MnO₂) nanowire cathodes directly on conductive graphite substrates. This scalable process enables precise control over composition and morphology, producing interconnected amorphous nanowires with abundant active sites and open diffusion channels.
Comprehensive structural and surface characterization using X-ray diffraction, field-emission scanning electron microscopy, and X-ray photoelectron spectroscopy confirms that cobalt incorporation generates oxygen vacancies, stabilizes mixed Mn³⁺/Mn⁴⁺ valence states, and induces partial amorphization. These synergistic effects markedly enhance Zn²⁺ transport and electronic conductivity, resulting in lower charge-transfer resistance and improved redox kinetics.
Electrochemical testing reveals that the Co–MnO₂ cathode delivers an initial capacity of 372 mAh g⁻¹ at 0.5 A g⁻¹ and maintains 246.4 mAh g⁻¹ at 1 A g⁻¹, while retaining approximately 84% of its capacity after 600 cycles at 1 A g⁻¹. These values surpass those of pristine MnO₂ and many MnO₂-based cathodes reported in recent literature. The outstanding rate capability and long-term stability are attributed to the combined benefits of cobalt-induced defect engineering and the high-surface-area nanowire architecture.
This study highlights cobalt doping via electrodeposition as an effective and industry-compatible route to engineer defect-rich MnO₂ cathodes. The results provide actionable insights for designing next-generation aqueous ZIBs and other sustainable energy-storage systems aligned with the global transition toward clean and reliable energy.
Comprehensive structural and surface characterization using X-ray diffraction, field-emission scanning electron microscopy, and X-ray photoelectron spectroscopy confirms that cobalt incorporation generates oxygen vacancies, stabilizes mixed Mn³⁺/Mn⁴⁺ valence states, and induces partial amorphization. These synergistic effects markedly enhance Zn²⁺ transport and electronic conductivity, resulting in lower charge-transfer resistance and improved redox kinetics.
Electrochemical testing reveals that the Co–MnO₂ cathode delivers an initial capacity of 372 mAh g⁻¹ at 0.5 A g⁻¹ and maintains 246.4 mAh g⁻¹ at 1 A g⁻¹, while retaining approximately 84% of its capacity after 600 cycles at 1 A g⁻¹. These values surpass those of pristine MnO₂ and many MnO₂-based cathodes reported in recent literature. The outstanding rate capability and long-term stability are attributed to the combined benefits of cobalt-induced defect engineering and the high-surface-area nanowire architecture.
This study highlights cobalt doping via electrodeposition as an effective and industry-compatible route to engineer defect-rich MnO₂ cathodes. The results provide actionable insights for designing next-generation aqueous ZIBs and other sustainable energy-storage systems aligned with the global transition toward clean and reliable energy.
Recently, the production of in-situ upgraded oil and hydrogen in some heavy oil field pilots became a reality. This was achieved with the Toe-to-Heel Air Injection (THAI) process, which consists of a combination of in-situ combustion with horizontal wells. Also, field testing of nano-catalysts and nanofluids in heavy oil reservoirs has recorded the first positive results.
THAI is the first enhanced oil recovery process that upgrades heavy oil underground, while recovering it, without any external heat sources; its second feature is the hydrogen contained in the produced gases. With the special completion of the THAI horizontal producers, an add-on new process called CAPRI can achieve a secondary upgrading.
THAI has been technically validated by seven field pilots located in India, Canada and China. Kerrobert Pilot, in Canada, has been in operation for 16 years; oil upgrading of 3-4 0API and viscosity decrease from 54,000cp to 3,000 cp have been achieved. Canadian, Athabasca THAI pilot, showed hydrogen in the range of 2%-6%, but in some conditions it was up to 14%.
Unintentional in-situ upgrading was recorded in eight very old conventional in-situ combustion (ISC) field projects, with or without special modifications. Not being designed to produce hydrogen (H2), for most of them, the mechanisms are deciphered only today. The most important project was Marguerite Lake wet ISC pilot in Canada, which produced 2-3% H2 during air-sustained wet ISC and up to 10-21% during oxygen (O2) sustained wet ISC, applied by alternative injection of O2 and water (with 10% H2 during O2 injection and up to 21% during water injection). Recently, a simulation model for the generation and production of H2 was developed, and it was validated by history matching of Marguerite Lake project.
Intensive laboratory investigations have indicated a maximum of 36% H2 in the case of catalyst use and for a combination of ISC with steam injection, which showed the best perspectives.
Obtaining ISC-generated hydrogen directly in-situ has been under investigation for 7 years. Although there are two main challenges – development of H2-selective, robust membranes and forcing CO2 to remain underground - some small progress has been made.
Recently, using nano-catalysts, important field successes were recorded for heavy oil production via the oil viscosity decrease, leading to enhanced recovery up to 200% per cycle in cyclic steam stimulations. The most important results are presented and discussed. Therefore, nano-catalysts’ successful use for a short-distance action is almost proven, technically.
Typical results of oil upgrading and hydrogen production in heavy oil fields and laboratory investigations correlated with recent simulations of laboratory and field tests will be presented and discussed. This way, the future pathways in field testing and in main research directions will be indicated to accelerate the potential commercial application.
THAI is the first enhanced oil recovery process that upgrades heavy oil underground, while recovering it, without any external heat sources; its second feature is the hydrogen contained in the produced gases. With the special completion of the THAI horizontal producers, an add-on new process called CAPRI can achieve a secondary upgrading.
THAI has been technically validated by seven field pilots located in India, Canada and China. Kerrobert Pilot, in Canada, has been in operation for 16 years; oil upgrading of 3-4 0API and viscosity decrease from 54,000cp to 3,000 cp have been achieved. Canadian, Athabasca THAI pilot, showed hydrogen in the range of 2%-6%, but in some conditions it was up to 14%.
Unintentional in-situ upgrading was recorded in eight very old conventional in-situ combustion (ISC) field projects, with or without special modifications. Not being designed to produce hydrogen (H2), for most of them, the mechanisms are deciphered only today. The most important project was Marguerite Lake wet ISC pilot in Canada, which produced 2-3% H2 during air-sustained wet ISC and up to 10-21% during oxygen (O2) sustained wet ISC, applied by alternative injection of O2 and water (with 10% H2 during O2 injection and up to 21% during water injection). Recently, a simulation model for the generation and production of H2 was developed, and it was validated by history matching of Marguerite Lake project.
Intensive laboratory investigations have indicated a maximum of 36% H2 in the case of catalyst use and for a combination of ISC with steam injection, which showed the best perspectives.
Obtaining ISC-generated hydrogen directly in-situ has been under investigation for 7 years. Although there are two main challenges – development of H2-selective, robust membranes and forcing CO2 to remain underground - some small progress has been made.
Recently, using nano-catalysts, important field successes were recorded for heavy oil production via the oil viscosity decrease, leading to enhanced recovery up to 200% per cycle in cyclic steam stimulations. The most important results are presented and discussed. Therefore, nano-catalysts’ successful use for a short-distance action is almost proven, technically.
Typical results of oil upgrading and hydrogen production in heavy oil fields and laboratory investigations correlated with recent simulations of laboratory and field tests will be presented and discussed. This way, the future pathways in field testing and in main research directions will be indicated to accelerate the potential commercial application.
Energy systems face continual deterioration of the mineral resource base and recurrent technological or economic shocks. Conventional planning models treat innovation as an external adjustment and leave the value of superior information unquantified. For the first time, resource degradation, endogenous innovation and the quantitative Value of Information (VOI) are integrated in a single linear-quadratic optimal-control problem. The framework yields an explicit technological-capital substitution rate, captures investment lags and maps the nonlinear variation of marginal returns across factor levels, so that capital is channelled into research or extraction only when this is provably optimal.
A four-factor translog production structure links physical assets, skilled labour, innovation effort and resource quality. Factor dynamics follow a stochastic control law that allows for market and geological uncertainty. New data and shocks enter a Kalman filter; every reduction in posterior variance is monetised as VOI, interpreted as the expected improvement of the objective caused by tighter control around the optimum. The optimal feedback rule is derived by the Pontryagin Maximum Principle and solved through an algebraic Riccati equation, redistributing expenditure among capacity expansion, innovation and extraction rate. Two fast-response scenarios are analysed—a sudden drop in resource quality and an abrupt technological breakthrough—after which the local rules are aggregated to the industry level under market-clearing and infrastructure constraints, producing a second optimisation that balances total output with innovation intensity.
Model experiments show that when resource quality worsens, the feedback law automatically shifts funds from physical expansion toward innovation, limiting output losses without locking in excess capital. Under a technology shock the rule reverses, curtailing non-essential projects and concentrating resources on monitoring and incremental upgrades. The analysis pinpoints a critical elasticity interval: below that range, extra information yields higher marginal benefit than new physical capacity, establishing a transparent threshold for investment committees. Aggregated across firms, the rules smooth sectoral production and stabilise research spending, indicating that VOI-driven innovation can offset resource decline and dampen volatility triggered by external shocks.
For operating companies the framework delivers a quantitative metric: the analytical VOI function directly converts uncertainty reduction into expected profit gain, allowing R&D to be benchmarked against capital alternatives. Regulators can embed VOI thresholds and substitution rates in licence terms, encouraging timely innovation and discouraging inefficient capacity growth. For the first time, resource degradation, delayed dynamics, variable substitution elasticities and the explicit cost of information are combined in a coherent optimisation of the production function, producing clear rules usable at both field and industry scales and providing a robust tool for balancing capital and research under deep uncertainty.
Co-author/s:
Ivan Ovsyannikov, Senior Expert, Technological Development Centre of the Fuel and Energy Complex.
A four-factor translog production structure links physical assets, skilled labour, innovation effort and resource quality. Factor dynamics follow a stochastic control law that allows for market and geological uncertainty. New data and shocks enter a Kalman filter; every reduction in posterior variance is monetised as VOI, interpreted as the expected improvement of the objective caused by tighter control around the optimum. The optimal feedback rule is derived by the Pontryagin Maximum Principle and solved through an algebraic Riccati equation, redistributing expenditure among capacity expansion, innovation and extraction rate. Two fast-response scenarios are analysed—a sudden drop in resource quality and an abrupt technological breakthrough—after which the local rules are aggregated to the industry level under market-clearing and infrastructure constraints, producing a second optimisation that balances total output with innovation intensity.
Model experiments show that when resource quality worsens, the feedback law automatically shifts funds from physical expansion toward innovation, limiting output losses without locking in excess capital. Under a technology shock the rule reverses, curtailing non-essential projects and concentrating resources on monitoring and incremental upgrades. The analysis pinpoints a critical elasticity interval: below that range, extra information yields higher marginal benefit than new physical capacity, establishing a transparent threshold for investment committees. Aggregated across firms, the rules smooth sectoral production and stabilise research spending, indicating that VOI-driven innovation can offset resource decline and dampen volatility triggered by external shocks.
For operating companies the framework delivers a quantitative metric: the analytical VOI function directly converts uncertainty reduction into expected profit gain, allowing R&D to be benchmarked against capital alternatives. Regulators can embed VOI thresholds and substitution rates in licence terms, encouraging timely innovation and discouraging inefficient capacity growth. For the first time, resource degradation, delayed dynamics, variable substitution elasticities and the explicit cost of information are combined in a coherent optimisation of the production function, producing clear rules usable at both field and industry scales and providing a robust tool for balancing capital and research under deep uncertainty.
Co-author/s:
Ivan Ovsyannikov, Senior Expert, Technological Development Centre of the Fuel and Energy Complex.
The quality of ultra - deep, high - temperature and high - pressure oil - gas reservoirs in Tarim has declined. Over 85% of the wells require stimulation before achieving economic production. In some wells, the in - situ stress gradient exceeds 2.0 MPa/100m, natural fractures are poorly developed, and it is extremely challenging to initiate fractures. As a result, these wells fail to meet the economic production targets after stimulation. For ultra - deep reservoirs with natural fractures, by demonstrating the activation state of natural fractures during the reservoir stimulation process and their influence on increasing the fracture - controlled stimulated volume, the effect of increasing the bottom - hole net pressure on the tensile opening of natural fractures was analyzed. Technical measures such as temporary plugging in fractures, weighted fracturing fluids, slick water, and low - viscosity and high - efficiency proppant - carrying fracturing fluids, as well as other supporting process technologies for enhancing the fracture - controlled stimulated volume, were studied. This aims to fully stimulate the reservoirs at a relatively low puping flow rate and improve the stimulation effect. Secondly, for high - stress - gradient reservoirs with under - developed natural fractures, different - density and different - temperature - resistant series of weighted fracturing fluids were mainly developed. The weighted density ranges from 1.2 to 1.5g/cm³, and the maximum temperature resistance reaches 200°C. Low - cost calcium chloride were utilized as weighting materials, and thickening agents were optimally selected. Supporting cross - linking agents and gel - breaking agents, especially stress - corrosion inhibitors, were developed, which resolved the stress corrosion issue caused by high - concentration brine and significantly broadened the application scope of calcium chloride - weighted fracturing fluids. Field oil well tests indicated that the drag - reduction rate of the new - type weighted fracturing fluids was 45 - 58% (weighted to 1.35g/cm³, with a flow rate of 2 - 5m³/min), confirming the high drag - reduction effect of the weighted fracturing fluid system. The minimum flow rate in field application was 1.8m³/min, and 20m³ of proppant was added, providing a favorable liquid technology for the stimulation of high - stress tight reservoirs. More than 20 ultra - deep wells in Tarim have applied the new processes and new fluids formed through comprehensive laboratory research. The proppant - adding success rate was 100%, and no problems such as sand plugging occurred. The production increased by 2.8 - 3.5 times, achieving excellent stimulation results. The stimulation technology of ultra deep oil and gas reservoirs in Tarim has made significant progress, and some of the technologies have reference significance for the fracturing of ultra deep reservoirs in other regions around the world. We hope that colleagues can gain inspiration from this. Keywords: Ultra - deep reservoir; High - temperature and high - pressure; Natural fracture; Weighted fracturing; Stimulation process.
Low permeability carbonate reservoirs have been playing an increasingly important role in operators’ portfolios in the Middle East. In the Greater Burgan field of southeast Kuwait, the Mauddud is a relatively thin carbonate reservoir (20 – 60ft thickness) with low matrix permeability (0.1 – 5mD range). Under this scenario lower production performance is expected, this has been observed in practice with the Mauddud only showing good productivity when wells intercept clusters of natural fractures. In this work we describe the approach to estimate occurrence of natural fractures in the Mauddud reservoir across the Greater Burgan field, and future development scenarios.
We created a discrete fracture network (DFN) model that integrated data from several sources such as well logs, borehole images, core photos, 3D far-field sonic, 3D geomechanics and production data. Our approach was to recreate the evolution of tectonics across the Greater Burgan field to model stress perturbations around faults and predict location and characteristics of natural fractures. Borehole images, core photos and 3D far-field sonic provided hard data at well locations to calibrate the DFN, with well-level production data corroborating with results further.
Reservoir simulation models using a single porosity approach without natural fractures were not able to reproduce production results in many wells. However, results improved significantly when incorporating the DFN results into a dual permeability (DPDP) reservoir simulation model. For example, the DFN predicted intense natural fracturing in the Magwa region of the Greater Burgan field. Good production performance was observed from Mauddud completions in this area and successful simulation history matches were only obtained using a DPDP guided by the DFN. However, uncertainties in the DFN are an important action item we have identified for future work as we observed some wells with excellent production performance but modest natural fracturing from the DFN.
One way of addressing DFN uncertainty has been to incorporate horizontal multistage proppant or acid fracturing in Mauddud development wells within the next year. This has been a trend in some Middle Eastern operators as stimulation can help intercept clusters of natural fractures that do not cross the wellbore. Additional data such as higher resolution and azimuthal seismic can help narrow down uncertainties in the DFN modeling results.
We created a discrete fracture network (DFN) model that integrated data from several sources such as well logs, borehole images, core photos, 3D far-field sonic, 3D geomechanics and production data. Our approach was to recreate the evolution of tectonics across the Greater Burgan field to model stress perturbations around faults and predict location and characteristics of natural fractures. Borehole images, core photos and 3D far-field sonic provided hard data at well locations to calibrate the DFN, with well-level production data corroborating with results further.
Reservoir simulation models using a single porosity approach without natural fractures were not able to reproduce production results in many wells. However, results improved significantly when incorporating the DFN results into a dual permeability (DPDP) reservoir simulation model. For example, the DFN predicted intense natural fracturing in the Magwa region of the Greater Burgan field. Good production performance was observed from Mauddud completions in this area and successful simulation history matches were only obtained using a DPDP guided by the DFN. However, uncertainties in the DFN are an important action item we have identified for future work as we observed some wells with excellent production performance but modest natural fracturing from the DFN.
One way of addressing DFN uncertainty has been to incorporate horizontal multistage proppant or acid fracturing in Mauddud development wells within the next year. This has been a trend in some Middle Eastern operators as stimulation can help intercept clusters of natural fractures that do not cross the wellbore. Additional data such as higher resolution and azimuthal seismic can help narrow down uncertainties in the DFN modeling results.
Qun Li
Chair
Senior Specialist, Standard and Cooperation Division, R&D Department
China National Petroleum Corporation
China
Abdulakhat Ismailov
Vice Chair
Dean of the School of Energy & Petroleum Industry
Kazakh-British Technical University
Kazakhstan
Katerina Yared
Vice Chair
Global Energy Portfolio Leader - O&G, Carbon Capture, Geothermal
3M
United States of America
Low permeability carbonate reservoirs have been playing an increasingly important role in operators’ portfolios in the Middle East. In the Greater Burgan field of southeast Kuwait, the Mauddud is a relatively thin carbonate reservoir (20 – 60ft thickness) with low matrix permeability (0.1 – 5mD range). Under this scenario lower production performance is expected, this has been observed in practice with the Mauddud only showing good productivity when wells intercept clusters of natural fractures. In this work we describe the approach to estimate occurrence of natural fractures in the Mauddud reservoir across the Greater Burgan field, and future development scenarios.
We created a discrete fracture network (DFN) model that integrated data from several sources such as well logs, borehole images, core photos, 3D far-field sonic, 3D geomechanics and production data. Our approach was to recreate the evolution of tectonics across the Greater Burgan field to model stress perturbations around faults and predict location and characteristics of natural fractures. Borehole images, core photos and 3D far-field sonic provided hard data at well locations to calibrate the DFN, with well-level production data corroborating with results further.
Reservoir simulation models using a single porosity approach without natural fractures were not able to reproduce production results in many wells. However, results improved significantly when incorporating the DFN results into a dual permeability (DPDP) reservoir simulation model. For example, the DFN predicted intense natural fracturing in the Magwa region of the Greater Burgan field. Good production performance was observed from Mauddud completions in this area and successful simulation history matches were only obtained using a DPDP guided by the DFN. However, uncertainties in the DFN are an important action item we have identified for future work as we observed some wells with excellent production performance but modest natural fracturing from the DFN.
One way of addressing DFN uncertainty has been to incorporate horizontal multistage proppant or acid fracturing in Mauddud development wells within the next year. This has been a trend in some Middle Eastern operators as stimulation can help intercept clusters of natural fractures that do not cross the wellbore. Additional data such as higher resolution and azimuthal seismic can help narrow down uncertainties in the DFN modeling results.
We created a discrete fracture network (DFN) model that integrated data from several sources such as well logs, borehole images, core photos, 3D far-field sonic, 3D geomechanics and production data. Our approach was to recreate the evolution of tectonics across the Greater Burgan field to model stress perturbations around faults and predict location and characteristics of natural fractures. Borehole images, core photos and 3D far-field sonic provided hard data at well locations to calibrate the DFN, with well-level production data corroborating with results further.
Reservoir simulation models using a single porosity approach without natural fractures were not able to reproduce production results in many wells. However, results improved significantly when incorporating the DFN results into a dual permeability (DPDP) reservoir simulation model. For example, the DFN predicted intense natural fracturing in the Magwa region of the Greater Burgan field. Good production performance was observed from Mauddud completions in this area and successful simulation history matches were only obtained using a DPDP guided by the DFN. However, uncertainties in the DFN are an important action item we have identified for future work as we observed some wells with excellent production performance but modest natural fracturing from the DFN.
One way of addressing DFN uncertainty has been to incorporate horizontal multistage proppant or acid fracturing in Mauddud development wells within the next year. This has been a trend in some Middle Eastern operators as stimulation can help intercept clusters of natural fractures that do not cross the wellbore. Additional data such as higher resolution and azimuthal seismic can help narrow down uncertainties in the DFN modeling results.
Energy saving and combustion optimization are crucial for several reasons:
Improved Efficiency: Optimizing combustion processes in chemical & petrochemical industries, such as reformers, furnaces and boilers, can enhance energy efficiency, reducing fuel consumption and operational costs.
Reduced Emissions: Better combustion control leads to lower emissions of pollutants like carbon monoxide, nitrogen oxides, and particulate matter, contributing to cleaner air and a healthier environment.
Enhanced Process Quality: Accurate and repeatable measurement of excess air ensures consistent combustion, improving the quality of the end product in manufacturing processes.
Safety: Proper combustion optimization reduces the risk of hazardous conditions, such as explosions or fires, by maintaining safe operating parameters.
Improving Combustion Efficiency is achieved by measuring the excess oxygen and combustibles by an oxygen analyzer. Measuring excess oxygen is essential for controlling Air/Fuel Ratio and to make sure that there is no excess fuel or excess air. Measuring combustibles is required to ensure efficient combustion with no left over non burned CO which is harmful for environment. Improving Burner Control is done by a gas chromatograph for measuring real time heating vale (BTU) for the fuel gas and measuring Wobbe Index for Burner Optimization, this is very essential for Calculating Air/Fuel Ratio to improve burner control, improve efficiency, and reduce emissions. By focusing on energy saving and combustion optimization, we can achieve a more sustainable, cost-effective, and safer future.
Improved Efficiency: Optimizing combustion processes in chemical & petrochemical industries, such as reformers, furnaces and boilers, can enhance energy efficiency, reducing fuel consumption and operational costs.
Reduced Emissions: Better combustion control leads to lower emissions of pollutants like carbon monoxide, nitrogen oxides, and particulate matter, contributing to cleaner air and a healthier environment.
Enhanced Process Quality: Accurate and repeatable measurement of excess air ensures consistent combustion, improving the quality of the end product in manufacturing processes.
Safety: Proper combustion optimization reduces the risk of hazardous conditions, such as explosions or fires, by maintaining safe operating parameters.
Improving Combustion Efficiency is achieved by measuring the excess oxygen and combustibles by an oxygen analyzer. Measuring excess oxygen is essential for controlling Air/Fuel Ratio and to make sure that there is no excess fuel or excess air. Measuring combustibles is required to ensure efficient combustion with no left over non burned CO which is harmful for environment. Improving Burner Control is done by a gas chromatograph for measuring real time heating vale (BTU) for the fuel gas and measuring Wobbe Index for Burner Optimization, this is very essential for Calculating Air/Fuel Ratio to improve burner control, improve efficiency, and reduce emissions. By focusing on energy saving and combustion optimization, we can achieve a more sustainable, cost-effective, and safer future.
Bayan Baatiyah
Speaker
Ph.D Student
King Fahad University for Petroleum and Minerals
Saudi Arabia
Aqueous zinc-ion batteries (ZIBs) are emerging as safe, low-cost, and sustainable alternatives for large-scale energy storage. However, the widespread application of manganese dioxide (MnO₂) cathodes remains limited by their inherently poor electronic conductivity, slow Zn²⁺ diffusion, and gradual structural degradation. In this work, we demonstrate a simple, room temperature electrodeposition method to fabricate cobalt-doped MnO₂ (Co–MnO₂) nanowire cathodes directly on conductive graphite substrates. This scalable process enables precise control over composition and morphology, producing interconnected amorphous nanowires with abundant active sites and open diffusion channels.
Comprehensive structural and surface characterization using X-ray diffraction, field-emission scanning electron microscopy, and X-ray photoelectron spectroscopy confirms that cobalt incorporation generates oxygen vacancies, stabilizes mixed Mn³⁺/Mn⁴⁺ valence states, and induces partial amorphization. These synergistic effects markedly enhance Zn²⁺ transport and electronic conductivity, resulting in lower charge-transfer resistance and improved redox kinetics.
Electrochemical testing reveals that the Co–MnO₂ cathode delivers an initial capacity of 372 mAh g⁻¹ at 0.5 A g⁻¹ and maintains 246.4 mAh g⁻¹ at 1 A g⁻¹, while retaining approximately 84% of its capacity after 600 cycles at 1 A g⁻¹. These values surpass those of pristine MnO₂ and many MnO₂-based cathodes reported in recent literature. The outstanding rate capability and long-term stability are attributed to the combined benefits of cobalt-induced defect engineering and the high-surface-area nanowire architecture.
This study highlights cobalt doping via electrodeposition as an effective and industry-compatible route to engineer defect-rich MnO₂ cathodes. The results provide actionable insights for designing next-generation aqueous ZIBs and other sustainable energy-storage systems aligned with the global transition toward clean and reliable energy.
Comprehensive structural and surface characterization using X-ray diffraction, field-emission scanning electron microscopy, and X-ray photoelectron spectroscopy confirms that cobalt incorporation generates oxygen vacancies, stabilizes mixed Mn³⁺/Mn⁴⁺ valence states, and induces partial amorphization. These synergistic effects markedly enhance Zn²⁺ transport and electronic conductivity, resulting in lower charge-transfer resistance and improved redox kinetics.
Electrochemical testing reveals that the Co–MnO₂ cathode delivers an initial capacity of 372 mAh g⁻¹ at 0.5 A g⁻¹ and maintains 246.4 mAh g⁻¹ at 1 A g⁻¹, while retaining approximately 84% of its capacity after 600 cycles at 1 A g⁻¹. These values surpass those of pristine MnO₂ and many MnO₂-based cathodes reported in recent literature. The outstanding rate capability and long-term stability are attributed to the combined benefits of cobalt-induced defect engineering and the high-surface-area nanowire architecture.
This study highlights cobalt doping via electrodeposition as an effective and industry-compatible route to engineer defect-rich MnO₂ cathodes. The results provide actionable insights for designing next-generation aqueous ZIBs and other sustainable energy-storage systems aligned with the global transition toward clean and reliable energy.
Natural hydrogen, often called “white hydrogen,” has emerged as a potential low-carbon energy resource. It occurs in various geologic settings such as cratonic basins, ultrabasic rock zones, and ophiolitic complexes. Unlike conventional hydrocarbon reservoirs, hydrogen accumulations are often associated with serpentinization reactions, water radiolysis, and degassing through faulted and fractured systems. This presents unique challenges for drilling, completion, and production design due to hydrogen’s low molecular weight, high mobility, and the reactivity of subsurface environments.
To ensure viable production, tailored completion strategies are essential. Natural hydrogen systems often feature shallow reservoirs (typically <3000 m), low pressures, and non-traditional trapping mechanisms. These factors necessitate specialized casing and cementing designs to prevent leakage and crossflow while minimizing the risk of gas migration during shut-in or low-flow periods. Corrosion-resistant materials must be considered due to hydrogen's propensity to embrittle steel and elastomers, especially under cyclical loading and long-term exposure.
Our proposed approach involves integrating real-time geochemical monitoring, pressure-transient analysis, and low-rate gas flow testing to characterize the productivity of hydrogen-bearing zones. Emphasis is placed on horizontal or multilateral well completions in fractured or fault-controlled systems, using open-hole or slotted-liner completions to maximize exposure to migrating hydrogen. Artificial lift strategies and low-flow metering systems are evaluated for early-life production monitoring, given the anticipated low volume and diffusivity-driven flow regimes of natural hydrogen systems.
Preliminary modeling and field analog studies suggest that managing hydrogen production requires a hybrid design philosophy, drawing from conventional gas and geothermal well practices. Initial outcomes indicate the need for adaptive well control strategies, long-duration flowback to desorb gas from microfractures, and optimized surface separation systems. These insights are critical to derisk early natural hydrogen exploration projects and will inform the development of regulatory and safety protocols as the industry scales.
Co-author/s:
Krishna Raghav Chaturvedi, Senior Research Fellow, Rajiv Gandhi Institute of Petroleum Technology.
To ensure viable production, tailored completion strategies are essential. Natural hydrogen systems often feature shallow reservoirs (typically <3000 m), low pressures, and non-traditional trapping mechanisms. These factors necessitate specialized casing and cementing designs to prevent leakage and crossflow while minimizing the risk of gas migration during shut-in or low-flow periods. Corrosion-resistant materials must be considered due to hydrogen's propensity to embrittle steel and elastomers, especially under cyclical loading and long-term exposure.
Our proposed approach involves integrating real-time geochemical monitoring, pressure-transient analysis, and low-rate gas flow testing to characterize the productivity of hydrogen-bearing zones. Emphasis is placed on horizontal or multilateral well completions in fractured or fault-controlled systems, using open-hole or slotted-liner completions to maximize exposure to migrating hydrogen. Artificial lift strategies and low-flow metering systems are evaluated for early-life production monitoring, given the anticipated low volume and diffusivity-driven flow regimes of natural hydrogen systems.
Preliminary modeling and field analog studies suggest that managing hydrogen production requires a hybrid design philosophy, drawing from conventional gas and geothermal well practices. Initial outcomes indicate the need for adaptive well control strategies, long-duration flowback to desorb gas from microfractures, and optimized surface separation systems. These insights are critical to derisk early natural hydrogen exploration projects and will inform the development of regulatory and safety protocols as the industry scales.
Co-author/s:
Krishna Raghav Chaturvedi, Senior Research Fellow, Rajiv Gandhi Institute of Petroleum Technology.
Recently, the production of in-situ upgraded oil and hydrogen in some heavy oil field pilots became a reality. This was achieved with the Toe-to-Heel Air Injection (THAI) process, which consists of a combination of in-situ combustion with horizontal wells. Also, field testing of nano-catalysts and nanofluids in heavy oil reservoirs has recorded the first positive results.
THAI is the first enhanced oil recovery process that upgrades heavy oil underground, while recovering it, without any external heat sources; its second feature is the hydrogen contained in the produced gases. With the special completion of the THAI horizontal producers, an add-on new process called CAPRI can achieve a secondary upgrading.
THAI has been technically validated by seven field pilots located in India, Canada and China. Kerrobert Pilot, in Canada, has been in operation for 16 years; oil upgrading of 3-4 0API and viscosity decrease from 54,000cp to 3,000 cp have been achieved. Canadian, Athabasca THAI pilot, showed hydrogen in the range of 2%-6%, but in some conditions it was up to 14%.
Unintentional in-situ upgrading was recorded in eight very old conventional in-situ combustion (ISC) field projects, with or without special modifications. Not being designed to produce hydrogen (H2), for most of them, the mechanisms are deciphered only today. The most important project was Marguerite Lake wet ISC pilot in Canada, which produced 2-3% H2 during air-sustained wet ISC and up to 10-21% during oxygen (O2) sustained wet ISC, applied by alternative injection of O2 and water (with 10% H2 during O2 injection and up to 21% during water injection). Recently, a simulation model for the generation and production of H2 was developed, and it was validated by history matching of Marguerite Lake project.
Intensive laboratory investigations have indicated a maximum of 36% H2 in the case of catalyst use and for a combination of ISC with steam injection, which showed the best perspectives.
Obtaining ISC-generated hydrogen directly in-situ has been under investigation for 7 years. Although there are two main challenges – development of H2-selective, robust membranes and forcing CO2 to remain underground - some small progress has been made.
Recently, using nano-catalysts, important field successes were recorded for heavy oil production via the oil viscosity decrease, leading to enhanced recovery up to 200% per cycle in cyclic steam stimulations. The most important results are presented and discussed. Therefore, nano-catalysts’ successful use for a short-distance action is almost proven, technically.
Typical results of oil upgrading and hydrogen production in heavy oil fields and laboratory investigations correlated with recent simulations of laboratory and field tests will be presented and discussed. This way, the future pathways in field testing and in main research directions will be indicated to accelerate the potential commercial application.
THAI is the first enhanced oil recovery process that upgrades heavy oil underground, while recovering it, without any external heat sources; its second feature is the hydrogen contained in the produced gases. With the special completion of the THAI horizontal producers, an add-on new process called CAPRI can achieve a secondary upgrading.
THAI has been technically validated by seven field pilots located in India, Canada and China. Kerrobert Pilot, in Canada, has been in operation for 16 years; oil upgrading of 3-4 0API and viscosity decrease from 54,000cp to 3,000 cp have been achieved. Canadian, Athabasca THAI pilot, showed hydrogen in the range of 2%-6%, but in some conditions it was up to 14%.
Unintentional in-situ upgrading was recorded in eight very old conventional in-situ combustion (ISC) field projects, with or without special modifications. Not being designed to produce hydrogen (H2), for most of them, the mechanisms are deciphered only today. The most important project was Marguerite Lake wet ISC pilot in Canada, which produced 2-3% H2 during air-sustained wet ISC and up to 10-21% during oxygen (O2) sustained wet ISC, applied by alternative injection of O2 and water (with 10% H2 during O2 injection and up to 21% during water injection). Recently, a simulation model for the generation and production of H2 was developed, and it was validated by history matching of Marguerite Lake project.
Intensive laboratory investigations have indicated a maximum of 36% H2 in the case of catalyst use and for a combination of ISC with steam injection, which showed the best perspectives.
Obtaining ISC-generated hydrogen directly in-situ has been under investigation for 7 years. Although there are two main challenges – development of H2-selective, robust membranes and forcing CO2 to remain underground - some small progress has been made.
Recently, using nano-catalysts, important field successes were recorded for heavy oil production via the oil viscosity decrease, leading to enhanced recovery up to 200% per cycle in cyclic steam stimulations. The most important results are presented and discussed. Therefore, nano-catalysts’ successful use for a short-distance action is almost proven, technically.
Typical results of oil upgrading and hydrogen production in heavy oil fields and laboratory investigations correlated with recent simulations of laboratory and field tests will be presented and discussed. This way, the future pathways in field testing and in main research directions will be indicated to accelerate the potential commercial application.
Zhanwei Yang
Speaker
Engineer
Research Institute of Petroleum Exploration & Development, PetroChina
China
The quality of ultra - deep, high - temperature and high - pressure oil - gas reservoirs in Tarim has declined. Over 85% of the wells require stimulation before achieving economic production. In some wells, the in - situ stress gradient exceeds 2.0 MPa/100m, natural fractures are poorly developed, and it is extremely challenging to initiate fractures. As a result, these wells fail to meet the economic production targets after stimulation. For ultra - deep reservoirs with natural fractures, by demonstrating the activation state of natural fractures during the reservoir stimulation process and their influence on increasing the fracture - controlled stimulated volume, the effect of increasing the bottom - hole net pressure on the tensile opening of natural fractures was analyzed. Technical measures such as temporary plugging in fractures, weighted fracturing fluids, slick water, and low - viscosity and high - efficiency proppant - carrying fracturing fluids, as well as other supporting process technologies for enhancing the fracture - controlled stimulated volume, were studied. This aims to fully stimulate the reservoirs at a relatively low puping flow rate and improve the stimulation effect. Secondly, for high - stress - gradient reservoirs with under - developed natural fractures, different - density and different - temperature - resistant series of weighted fracturing fluids were mainly developed. The weighted density ranges from 1.2 to 1.5g/cm³, and the maximum temperature resistance reaches 200°C. Low - cost calcium chloride were utilized as weighting materials, and thickening agents were optimally selected. Supporting cross - linking agents and gel - breaking agents, especially stress - corrosion inhibitors, were developed, which resolved the stress corrosion issue caused by high - concentration brine and significantly broadened the application scope of calcium chloride - weighted fracturing fluids. Field oil well tests indicated that the drag - reduction rate of the new - type weighted fracturing fluids was 45 - 58% (weighted to 1.35g/cm³, with a flow rate of 2 - 5m³/min), confirming the high drag - reduction effect of the weighted fracturing fluid system. The minimum flow rate in field application was 1.8m³/min, and 20m³ of proppant was added, providing a favorable liquid technology for the stimulation of high - stress tight reservoirs. More than 20 ultra - deep wells in Tarim have applied the new processes and new fluids formed through comprehensive laboratory research. The proppant - adding success rate was 100%, and no problems such as sand plugging occurred. The production increased by 2.8 - 3.5 times, achieving excellent stimulation results. The stimulation technology of ultra deep oil and gas reservoirs in Tarim has made significant progress, and some of the technologies have reference significance for the fracturing of ultra deep reservoirs in other regions around the world. We hope that colleagues can gain inspiration from this. Keywords: Ultra - deep reservoir; High - temperature and high - pressure; Natural fracture; Weighted fracturing; Stimulation process.
Oleg Zhdaneev
Speaker
Head
Technological Development Centre of the Fuel and Energy Complex
Russia
Energy systems face continual deterioration of the mineral resource base and recurrent technological or economic shocks. Conventional planning models treat innovation as an external adjustment and leave the value of superior information unquantified. For the first time, resource degradation, endogenous innovation and the quantitative Value of Information (VOI) are integrated in a single linear-quadratic optimal-control problem. The framework yields an explicit technological-capital substitution rate, captures investment lags and maps the nonlinear variation of marginal returns across factor levels, so that capital is channelled into research or extraction only when this is provably optimal.
A four-factor translog production structure links physical assets, skilled labour, innovation effort and resource quality. Factor dynamics follow a stochastic control law that allows for market and geological uncertainty. New data and shocks enter a Kalman filter; every reduction in posterior variance is monetised as VOI, interpreted as the expected improvement of the objective caused by tighter control around the optimum. The optimal feedback rule is derived by the Pontryagin Maximum Principle and solved through an algebraic Riccati equation, redistributing expenditure among capacity expansion, innovation and extraction rate. Two fast-response scenarios are analysed—a sudden drop in resource quality and an abrupt technological breakthrough—after which the local rules are aggregated to the industry level under market-clearing and infrastructure constraints, producing a second optimisation that balances total output with innovation intensity.
Model experiments show that when resource quality worsens, the feedback law automatically shifts funds from physical expansion toward innovation, limiting output losses without locking in excess capital. Under a technology shock the rule reverses, curtailing non-essential projects and concentrating resources on monitoring and incremental upgrades. The analysis pinpoints a critical elasticity interval: below that range, extra information yields higher marginal benefit than new physical capacity, establishing a transparent threshold for investment committees. Aggregated across firms, the rules smooth sectoral production and stabilise research spending, indicating that VOI-driven innovation can offset resource decline and dampen volatility triggered by external shocks.
For operating companies the framework delivers a quantitative metric: the analytical VOI function directly converts uncertainty reduction into expected profit gain, allowing R&D to be benchmarked against capital alternatives. Regulators can embed VOI thresholds and substitution rates in licence terms, encouraging timely innovation and discouraging inefficient capacity growth. For the first time, resource degradation, delayed dynamics, variable substitution elasticities and the explicit cost of information are combined in a coherent optimisation of the production function, producing clear rules usable at both field and industry scales and providing a robust tool for balancing capital and research under deep uncertainty.
Co-author/s:
Ivan Ovsyannikov, Senior Expert, Technological Development Centre of the Fuel and Energy Complex.
A four-factor translog production structure links physical assets, skilled labour, innovation effort and resource quality. Factor dynamics follow a stochastic control law that allows for market and geological uncertainty. New data and shocks enter a Kalman filter; every reduction in posterior variance is monetised as VOI, interpreted as the expected improvement of the objective caused by tighter control around the optimum. The optimal feedback rule is derived by the Pontryagin Maximum Principle and solved through an algebraic Riccati equation, redistributing expenditure among capacity expansion, innovation and extraction rate. Two fast-response scenarios are analysed—a sudden drop in resource quality and an abrupt technological breakthrough—after which the local rules are aggregated to the industry level under market-clearing and infrastructure constraints, producing a second optimisation that balances total output with innovation intensity.
Model experiments show that when resource quality worsens, the feedback law automatically shifts funds from physical expansion toward innovation, limiting output losses without locking in excess capital. Under a technology shock the rule reverses, curtailing non-essential projects and concentrating resources on monitoring and incremental upgrades. The analysis pinpoints a critical elasticity interval: below that range, extra information yields higher marginal benefit than new physical capacity, establishing a transparent threshold for investment committees. Aggregated across firms, the rules smooth sectoral production and stabilise research spending, indicating that VOI-driven innovation can offset resource decline and dampen volatility triggered by external shocks.
For operating companies the framework delivers a quantitative metric: the analytical VOI function directly converts uncertainty reduction into expected profit gain, allowing R&D to be benchmarked against capital alternatives. Regulators can embed VOI thresholds and substitution rates in licence terms, encouraging timely innovation and discouraging inefficient capacity growth. For the first time, resource degradation, delayed dynamics, variable substitution elasticities and the explicit cost of information are combined in a coherent optimisation of the production function, producing clear rules usable at both field and industry scales and providing a robust tool for balancing capital and research under deep uncertainty.
Co-author/s:
Ivan Ovsyannikov, Senior Expert, Technological Development Centre of the Fuel and Energy Complex.
