TECHNICAL PROGRAMME | Primary Energy Supply – Future Pathways
New Exploration & Production Technologies to Extend Supply
Forum 3 | Hall 9 - Technical Programme 1
13
October
14:30
16:00
UTC+3
New exploration and production technologies are revolutionising the oil and gas industry, enabling access to previously untapped resources, improving efficiency, and reducing the environmental impact of exploration and production activities. By leveraging these advancements, the industry can extend the supply of hydrocarbons while addressing environmental and sustainability concerns.
Most of CCS projects at oilfields are now through CO2 enhanced oil recovery (EOR). CO2-EOR has been widely used in the past 50 years in the US and elsewhere. The carbon storage incidental to EOR varies with field/reservoir characteristics with about half of injected CO2 retained in oil reservoirs on average. This incidental storage enables the produced oil to be low- or even negative- carbon from a life cycle perspective. The objective of this paper is to conduct a rigorous greenhouse gas assessment on these historical CO2-EOR projects to identify a suite of economic, operational, and geological factors that favor low-carbon oil production.
We revisited 140+ historical CO2-EOR projects and collected data for injection-production rates. We first conducted production history matching through type curve modeling to predict the long-term (>2 hydrocarbon pore volume) performance of both carbon storage and oil production. Then we employed a greenhouse gas emission modeling tool to quantify the carbon footprints associated with major steps of CCS-EOR (from capture, injection, storage, production, processing). The emission modelling was also coupled with an economic assessment model to understand how both economic and technical factors influence the duration of low-carbon oil production for these projects. We also varied operational parameters (e.g., water alternating gas injection ratio) and CO2 source types (natural and industrial CO2) to examine associated influence.
The collections have good coverage of flood types (miscible and immiscible), rock types (carbonate and sandstone), reservoir depth (1200-11950 ft), permeability ranges (0.1-2300 mD), oil viscosity (0.3-260 cp), and other field/reservoir characteristics. Based on the extensive assessment of these projects, we found that low-carbon oil production normally occurred at early period of CO2 injection with the low-carbon duration varying dramatically. This wide variability in duration exhibited a strong dependence on reservoir depth, permeability, gas-oil-ratios, and gas compositions. The duration can be extended through optimizing injection strategies, switching CO2 source types, and selecting surface CO2 separation processes. With the best combinations of these factors, the low-carbon production can be doubled in comparison to the base case.
Carbon storage in oil reservoirs is the most tangible option for CCUS. Through robust assessment on carbon performance of historical CO2-EOR projects with reliable reservoir datasets, we demonstrate that CCS-EOR has the potential to achieve low-carbon oil for certain production periods, which depends on careful engineering design, optimized processing practices, and the availability of robust carbon storage incentives.
Our findings imply that reservoir assets at a stranding risk due to intensive carbon emissions of traditional operations might be revitalized through CO2 injection for both EOR and carbon storage.
We revisited 140+ historical CO2-EOR projects and collected data for injection-production rates. We first conducted production history matching through type curve modeling to predict the long-term (>2 hydrocarbon pore volume) performance of both carbon storage and oil production. Then we employed a greenhouse gas emission modeling tool to quantify the carbon footprints associated with major steps of CCS-EOR (from capture, injection, storage, production, processing). The emission modelling was also coupled with an economic assessment model to understand how both economic and technical factors influence the duration of low-carbon oil production for these projects. We also varied operational parameters (e.g., water alternating gas injection ratio) and CO2 source types (natural and industrial CO2) to examine associated influence.
The collections have good coverage of flood types (miscible and immiscible), rock types (carbonate and sandstone), reservoir depth (1200-11950 ft), permeability ranges (0.1-2300 mD), oil viscosity (0.3-260 cp), and other field/reservoir characteristics. Based on the extensive assessment of these projects, we found that low-carbon oil production normally occurred at early period of CO2 injection with the low-carbon duration varying dramatically. This wide variability in duration exhibited a strong dependence on reservoir depth, permeability, gas-oil-ratios, and gas compositions. The duration can be extended through optimizing injection strategies, switching CO2 source types, and selecting surface CO2 separation processes. With the best combinations of these factors, the low-carbon production can be doubled in comparison to the base case.
Carbon storage in oil reservoirs is the most tangible option for CCUS. Through robust assessment on carbon performance of historical CO2-EOR projects with reliable reservoir datasets, we demonstrate that CCS-EOR has the potential to achieve low-carbon oil for certain production periods, which depends on careful engineering design, optimized processing practices, and the availability of robust carbon storage incentives.
Our findings imply that reservoir assets at a stranding risk due to intensive carbon emissions of traditional operations might be revitalized through CO2 injection for both EOR and carbon storage.
Effectively developing tight carbonate reservoir is challenging due to low-permeability, strong heterogeneity, high uncertainty and consequently high cost. This paper focusses on a typical tight carbonate reservoir in Middle East with permeability 0.1 – 1mD with strong heterogeneity, which was not effectively developed over last 15 years, This paper presents a comprehensive development mode that achieved good production and economic performance.
3 different reservoir types are identified based on a novel and comprehensive workflow including seismic data, well logging, mechanics study, production performance, surveillance data etc. Customized development mode including well type, pattern, spacing, MRC design, and stimulation design to improve productivity and extend plateau. In addition, full life cycle development roadmap is established for this reservoir to enhance the EUR.
By successfully implementing this development strategy, single well production rate was increased by 150% by implementing the customized stimulation technologies combined with MRC well. Moreover, UTC was reduced by 21% while the field production rate was increased by 200% in 2 years by implementing this development mode.
This paper offers a case study on optimizing the development strategy for super tight carbonate reservoirs with strong heterogeneity. It also provides a methodology and a reference case for managers and engineers to develop other similar challenging reservoirs.
3 different reservoir types are identified based on a novel and comprehensive workflow including seismic data, well logging, mechanics study, production performance, surveillance data etc. Customized development mode including well type, pattern, spacing, MRC design, and stimulation design to improve productivity and extend plateau. In addition, full life cycle development roadmap is established for this reservoir to enhance the EUR.
By successfully implementing this development strategy, single well production rate was increased by 150% by implementing the customized stimulation technologies combined with MRC well. Moreover, UTC was reduced by 21% while the field production rate was increased by 200% in 2 years by implementing this development mode.
This paper offers a case study on optimizing the development strategy for super tight carbonate reservoirs with strong heterogeneity. It also provides a methodology and a reference case for managers and engineers to develop other similar challenging reservoirs.
As global efforts intensify to decarbonize energy systems, the energy transition offers an intelligent pathway to repurpose existing oil and gas infrastructure for sustainable applications. Among renewable options, geothermal energy stands out as a reliable resource with strong technical synergies to hydrocarbon exploration and development. This study examines how legacy hydrocarbon assets—such as wells, datasets, and subsurface models—can be strategically utilized to reduce risk and expedite geothermal exploration, particularly in frontier basins where renewable-specific data is scarce.
Unlike traditional geothermal approaches that often depend on limited surface mapping and sparse subsurface data, hydrocarbon provinces offer a wealth of underutilized data and infrastructure, which needs to be employed for geothermal exploration. This study demonstrates how legacy datasets, including well logs, bottom-hole temperature (BHT) readings, seismic interpretations, and lithological information, can be harnessed to improve geothermal resource assessment. By applying corrections to BHT data and integrating them with heat flow models, core sample analyses, and potential field data, it becomes possible to construct more reliable geothermal gradient maps. Furthermore, existing oil and gas wells can serve as cost-effective test sites or even production wells, significantly lowering exploration costs and timelines.
Repurposing oil and gas tools and workflows—such as seismic interpretation, facies modeling, and petrophysical analysis—enhances geothermal prospectivity and reduces exploration risk. Reprocessing seismic data to map deep basin structures and fault zones enables better target identification for geothermal drilling. Furthermore, historical production data, pressure tests, and water chemistry records from hydrocarbon operations provide insights into fluid pathways and system sustainability. Co-locating geothermal initiatives with existing infrastructure also opens the door to integrated applications like direct-use heating, carbon capture and storage (CCS), and critical mineral extraction (e.g., lithium from geothermal brines), adding economic and strategic value.
This research highlights a practical, cost-effective pathway for accelerating energy transition by capitalizing on decades of investment in hydrocarbon infrastructure. It presents a framework for cross-sector integration, where legacy oil and gas assets not only support renewable energy development but also extend their utility in a low-carbon future. The approach fosters collaboration between geothermal and petroleum disciplines, unlocking new opportunities in sedimentary basins and beyond.
Unlike traditional geothermal approaches that often depend on limited surface mapping and sparse subsurface data, hydrocarbon provinces offer a wealth of underutilized data and infrastructure, which needs to be employed for geothermal exploration. This study demonstrates how legacy datasets, including well logs, bottom-hole temperature (BHT) readings, seismic interpretations, and lithological information, can be harnessed to improve geothermal resource assessment. By applying corrections to BHT data and integrating them with heat flow models, core sample analyses, and potential field data, it becomes possible to construct more reliable geothermal gradient maps. Furthermore, existing oil and gas wells can serve as cost-effective test sites or even production wells, significantly lowering exploration costs and timelines.
Repurposing oil and gas tools and workflows—such as seismic interpretation, facies modeling, and petrophysical analysis—enhances geothermal prospectivity and reduces exploration risk. Reprocessing seismic data to map deep basin structures and fault zones enables better target identification for geothermal drilling. Furthermore, historical production data, pressure tests, and water chemistry records from hydrocarbon operations provide insights into fluid pathways and system sustainability. Co-locating geothermal initiatives with existing infrastructure also opens the door to integrated applications like direct-use heating, carbon capture and storage (CCS), and critical mineral extraction (e.g., lithium from geothermal brines), adding economic and strategic value.
This research highlights a practical, cost-effective pathway for accelerating energy transition by capitalizing on decades of investment in hydrocarbon infrastructure. It presents a framework for cross-sector integration, where legacy oil and gas assets not only support renewable energy development but also extend their utility in a low-carbon future. The approach fosters collaboration between geothermal and petroleum disciplines, unlocking new opportunities in sedimentary basins and beyond.
Located in the Santos Basin, the Buzios Field was discovered in 2010. In the same year, Petrobras acquired the rights to explore the area through the Transfer of Rights (ToR) contract, allowing for the extraction of 3 billion boe. To develop the Field, Petrobras, as operator, defined a development plan composed of 5 production units.
During exploration, several wells showed excellent productivity, indicating around 34 billion boe in place, making Buzios the largest ultra-deepwater oil field globally. To exploit the additional volumes, in November 2019, the Brazilian government held the ToR surplus bidding round, with Petrobras and Partners CNOOC and CNODC winning the right to exploit the Field without volume limits until 2055. A new Global Development Plan (GDP) was defined, including 7 additional FPSOs, totaling 12 production units.
In February 2025 the 6th FPSO started production, and the 7th to 11th units are under construction, planned to start operation until end 2027. The 12th module is under study, with the objective to increase the production of the Field, as well as providing more gas to the market.
As Operator and Partners work to implement the GDP, focus is also being put on the future of the Field, with the goal of boosting production through the adoption of new technologies and initiatives, while also investing to increase energy availability, operational efficiency and reduce emissions.
Innovative subsea water injection systems are being implemented to enhance oil recovery and sustain reservoir pressure. Furthermore, plans for new infill wells are being devised to access undrained areas of the reservoir. To support these initiatives, Petrobras and Partners are investing in cutting-edge reservoir monitoring technologies, including 4D Seismic and well monitoring utilizing Distributed Acoustic and Temperature Sensing (DATS). Additionally, in order to increase the energy availability, thus increasing operational efficiencies, Petrobras is studying to electrically connect platforms through submarine power umbilical.
In alignment with the Net Zero by 2050 Petrobras ambition, several technologies are being incorporated, such as flare gas recovery units, carbon capture, utilization, and storage associated with enhanced oil recovery, operational venting recovery systems and low-emission fugitive valves.
For the long-term of the Field, studies are being carried out to ensure the integrity of the facilities and extend the life span of the current units.
With those innovative technologies and initiatives, Petrobras, Partners and PPSA intend not only to extract the best value of the Field in the present, but also guarantee a long-term production, maximizing the value of the world’s largest ultra-deepwater oil field.
During exploration, several wells showed excellent productivity, indicating around 34 billion boe in place, making Buzios the largest ultra-deepwater oil field globally. To exploit the additional volumes, in November 2019, the Brazilian government held the ToR surplus bidding round, with Petrobras and Partners CNOOC and CNODC winning the right to exploit the Field without volume limits until 2055. A new Global Development Plan (GDP) was defined, including 7 additional FPSOs, totaling 12 production units.
In February 2025 the 6th FPSO started production, and the 7th to 11th units are under construction, planned to start operation until end 2027. The 12th module is under study, with the objective to increase the production of the Field, as well as providing more gas to the market.
As Operator and Partners work to implement the GDP, focus is also being put on the future of the Field, with the goal of boosting production through the adoption of new technologies and initiatives, while also investing to increase energy availability, operational efficiency and reduce emissions.
Innovative subsea water injection systems are being implemented to enhance oil recovery and sustain reservoir pressure. Furthermore, plans for new infill wells are being devised to access undrained areas of the reservoir. To support these initiatives, Petrobras and Partners are investing in cutting-edge reservoir monitoring technologies, including 4D Seismic and well monitoring utilizing Distributed Acoustic and Temperature Sensing (DATS). Additionally, in order to increase the energy availability, thus increasing operational efficiencies, Petrobras is studying to electrically connect platforms through submarine power umbilical.
In alignment with the Net Zero by 2050 Petrobras ambition, several technologies are being incorporated, such as flare gas recovery units, carbon capture, utilization, and storage associated with enhanced oil recovery, operational venting recovery systems and low-emission fugitive valves.
For the long-term of the Field, studies are being carried out to ensure the integrity of the facilities and extend the life span of the current units.
With those innovative technologies and initiatives, Petrobras, Partners and PPSA intend not only to extract the best value of the Field in the present, but also guarantee a long-term production, maximizing the value of the world’s largest ultra-deepwater oil field.
Yoshiyuki Okano
Chair
General Manager, Subsurface Evaluation
Japan Petroleum Exploration Co., Ltd.
As global efforts intensify to decarbonize energy systems, the energy transition offers an intelligent pathway to repurpose existing oil and gas infrastructure for sustainable applications. Among renewable options, geothermal energy stands out as a reliable resource with strong technical synergies to hydrocarbon exploration and development. This study examines how legacy hydrocarbon assets—such as wells, datasets, and subsurface models—can be strategically utilized to reduce risk and expedite geothermal exploration, particularly in frontier basins where renewable-specific data is scarce.
Unlike traditional geothermal approaches that often depend on limited surface mapping and sparse subsurface data, hydrocarbon provinces offer a wealth of underutilized data and infrastructure, which needs to be employed for geothermal exploration. This study demonstrates how legacy datasets, including well logs, bottom-hole temperature (BHT) readings, seismic interpretations, and lithological information, can be harnessed to improve geothermal resource assessment. By applying corrections to BHT data and integrating them with heat flow models, core sample analyses, and potential field data, it becomes possible to construct more reliable geothermal gradient maps. Furthermore, existing oil and gas wells can serve as cost-effective test sites or even production wells, significantly lowering exploration costs and timelines.
Repurposing oil and gas tools and workflows—such as seismic interpretation, facies modeling, and petrophysical analysis—enhances geothermal prospectivity and reduces exploration risk. Reprocessing seismic data to map deep basin structures and fault zones enables better target identification for geothermal drilling. Furthermore, historical production data, pressure tests, and water chemistry records from hydrocarbon operations provide insights into fluid pathways and system sustainability. Co-locating geothermal initiatives with existing infrastructure also opens the door to integrated applications like direct-use heating, carbon capture and storage (CCS), and critical mineral extraction (e.g., lithium from geothermal brines), adding economic and strategic value.
This research highlights a practical, cost-effective pathway for accelerating energy transition by capitalizing on decades of investment in hydrocarbon infrastructure. It presents a framework for cross-sector integration, where legacy oil and gas assets not only support renewable energy development but also extend their utility in a low-carbon future. The approach fosters collaboration between geothermal and petroleum disciplines, unlocking new opportunities in sedimentary basins and beyond.
Unlike traditional geothermal approaches that often depend on limited surface mapping and sparse subsurface data, hydrocarbon provinces offer a wealth of underutilized data and infrastructure, which needs to be employed for geothermal exploration. This study demonstrates how legacy datasets, including well logs, bottom-hole temperature (BHT) readings, seismic interpretations, and lithological information, can be harnessed to improve geothermal resource assessment. By applying corrections to BHT data and integrating them with heat flow models, core sample analyses, and potential field data, it becomes possible to construct more reliable geothermal gradient maps. Furthermore, existing oil and gas wells can serve as cost-effective test sites or even production wells, significantly lowering exploration costs and timelines.
Repurposing oil and gas tools and workflows—such as seismic interpretation, facies modeling, and petrophysical analysis—enhances geothermal prospectivity and reduces exploration risk. Reprocessing seismic data to map deep basin structures and fault zones enables better target identification for geothermal drilling. Furthermore, historical production data, pressure tests, and water chemistry records from hydrocarbon operations provide insights into fluid pathways and system sustainability. Co-locating geothermal initiatives with existing infrastructure also opens the door to integrated applications like direct-use heating, carbon capture and storage (CCS), and critical mineral extraction (e.g., lithium from geothermal brines), adding economic and strategic value.
This research highlights a practical, cost-effective pathway for accelerating energy transition by capitalizing on decades of investment in hydrocarbon infrastructure. It presents a framework for cross-sector integration, where legacy oil and gas assets not only support renewable energy development but also extend their utility in a low-carbon future. The approach fosters collaboration between geothermal and petroleum disciplines, unlocking new opportunities in sedimentary basins and beyond.
Most of CCS projects at oilfields are now through CO2 enhanced oil recovery (EOR). CO2-EOR has been widely used in the past 50 years in the US and elsewhere. The carbon storage incidental to EOR varies with field/reservoir characteristics with about half of injected CO2 retained in oil reservoirs on average. This incidental storage enables the produced oil to be low- or even negative- carbon from a life cycle perspective. The objective of this paper is to conduct a rigorous greenhouse gas assessment on these historical CO2-EOR projects to identify a suite of economic, operational, and geological factors that favor low-carbon oil production.
We revisited 140+ historical CO2-EOR projects and collected data for injection-production rates. We first conducted production history matching through type curve modeling to predict the long-term (>2 hydrocarbon pore volume) performance of both carbon storage and oil production. Then we employed a greenhouse gas emission modeling tool to quantify the carbon footprints associated with major steps of CCS-EOR (from capture, injection, storage, production, processing). The emission modelling was also coupled with an economic assessment model to understand how both economic and technical factors influence the duration of low-carbon oil production for these projects. We also varied operational parameters (e.g., water alternating gas injection ratio) and CO2 source types (natural and industrial CO2) to examine associated influence.
The collections have good coverage of flood types (miscible and immiscible), rock types (carbonate and sandstone), reservoir depth (1200-11950 ft), permeability ranges (0.1-2300 mD), oil viscosity (0.3-260 cp), and other field/reservoir characteristics. Based on the extensive assessment of these projects, we found that low-carbon oil production normally occurred at early period of CO2 injection with the low-carbon duration varying dramatically. This wide variability in duration exhibited a strong dependence on reservoir depth, permeability, gas-oil-ratios, and gas compositions. The duration can be extended through optimizing injection strategies, switching CO2 source types, and selecting surface CO2 separation processes. With the best combinations of these factors, the low-carbon production can be doubled in comparison to the base case.
Carbon storage in oil reservoirs is the most tangible option for CCUS. Through robust assessment on carbon performance of historical CO2-EOR projects with reliable reservoir datasets, we demonstrate that CCS-EOR has the potential to achieve low-carbon oil for certain production periods, which depends on careful engineering design, optimized processing practices, and the availability of robust carbon storage incentives.
Our findings imply that reservoir assets at a stranding risk due to intensive carbon emissions of traditional operations might be revitalized through CO2 injection for both EOR and carbon storage.
We revisited 140+ historical CO2-EOR projects and collected data for injection-production rates. We first conducted production history matching through type curve modeling to predict the long-term (>2 hydrocarbon pore volume) performance of both carbon storage and oil production. Then we employed a greenhouse gas emission modeling tool to quantify the carbon footprints associated with major steps of CCS-EOR (from capture, injection, storage, production, processing). The emission modelling was also coupled with an economic assessment model to understand how both economic and technical factors influence the duration of low-carbon oil production for these projects. We also varied operational parameters (e.g., water alternating gas injection ratio) and CO2 source types (natural and industrial CO2) to examine associated influence.
The collections have good coverage of flood types (miscible and immiscible), rock types (carbonate and sandstone), reservoir depth (1200-11950 ft), permeability ranges (0.1-2300 mD), oil viscosity (0.3-260 cp), and other field/reservoir characteristics. Based on the extensive assessment of these projects, we found that low-carbon oil production normally occurred at early period of CO2 injection with the low-carbon duration varying dramatically. This wide variability in duration exhibited a strong dependence on reservoir depth, permeability, gas-oil-ratios, and gas compositions. The duration can be extended through optimizing injection strategies, switching CO2 source types, and selecting surface CO2 separation processes. With the best combinations of these factors, the low-carbon production can be doubled in comparison to the base case.
Carbon storage in oil reservoirs is the most tangible option for CCUS. Through robust assessment on carbon performance of historical CO2-EOR projects with reliable reservoir datasets, we demonstrate that CCS-EOR has the potential to achieve low-carbon oil for certain production periods, which depends on careful engineering design, optimized processing practices, and the availability of robust carbon storage incentives.
Our findings imply that reservoir assets at a stranding risk due to intensive carbon emissions of traditional operations might be revitalized through CO2 injection for both EOR and carbon storage.
Fabiano Rosa
Speaker
Buzios Field Reservoir Manager
PETROBRAS - Petróleo Brasileiro S.A.
Brazil
Located in the Santos Basin, the Buzios Field was discovered in 2010. In the same year, Petrobras acquired the rights to explore the area through the Transfer of Rights (ToR) contract, allowing for the extraction of 3 billion boe. To develop the Field, Petrobras, as operator, defined a development plan composed of 5 production units.
During exploration, several wells showed excellent productivity, indicating around 34 billion boe in place, making Buzios the largest ultra-deepwater oil field globally. To exploit the additional volumes, in November 2019, the Brazilian government held the ToR surplus bidding round, with Petrobras and Partners CNOOC and CNODC winning the right to exploit the Field without volume limits until 2055. A new Global Development Plan (GDP) was defined, including 7 additional FPSOs, totaling 12 production units.
In February 2025 the 6th FPSO started production, and the 7th to 11th units are under construction, planned to start operation until end 2027. The 12th module is under study, with the objective to increase the production of the Field, as well as providing more gas to the market.
As Operator and Partners work to implement the GDP, focus is also being put on the future of the Field, with the goal of boosting production through the adoption of new technologies and initiatives, while also investing to increase energy availability, operational efficiency and reduce emissions.
Innovative subsea water injection systems are being implemented to enhance oil recovery and sustain reservoir pressure. Furthermore, plans for new infill wells are being devised to access undrained areas of the reservoir. To support these initiatives, Petrobras and Partners are investing in cutting-edge reservoir monitoring technologies, including 4D Seismic and well monitoring utilizing Distributed Acoustic and Temperature Sensing (DATS). Additionally, in order to increase the energy availability, thus increasing operational efficiencies, Petrobras is studying to electrically connect platforms through submarine power umbilical.
In alignment with the Net Zero by 2050 Petrobras ambition, several technologies are being incorporated, such as flare gas recovery units, carbon capture, utilization, and storage associated with enhanced oil recovery, operational venting recovery systems and low-emission fugitive valves.
For the long-term of the Field, studies are being carried out to ensure the integrity of the facilities and extend the life span of the current units.
With those innovative technologies and initiatives, Petrobras, Partners and PPSA intend not only to extract the best value of the Field in the present, but also guarantee a long-term production, maximizing the value of the world’s largest ultra-deepwater oil field.
During exploration, several wells showed excellent productivity, indicating around 34 billion boe in place, making Buzios the largest ultra-deepwater oil field globally. To exploit the additional volumes, in November 2019, the Brazilian government held the ToR surplus bidding round, with Petrobras and Partners CNOOC and CNODC winning the right to exploit the Field without volume limits until 2055. A new Global Development Plan (GDP) was defined, including 7 additional FPSOs, totaling 12 production units.
In February 2025 the 6th FPSO started production, and the 7th to 11th units are under construction, planned to start operation until end 2027. The 12th module is under study, with the objective to increase the production of the Field, as well as providing more gas to the market.
As Operator and Partners work to implement the GDP, focus is also being put on the future of the Field, with the goal of boosting production through the adoption of new technologies and initiatives, while also investing to increase energy availability, operational efficiency and reduce emissions.
Innovative subsea water injection systems are being implemented to enhance oil recovery and sustain reservoir pressure. Furthermore, plans for new infill wells are being devised to access undrained areas of the reservoir. To support these initiatives, Petrobras and Partners are investing in cutting-edge reservoir monitoring technologies, including 4D Seismic and well monitoring utilizing Distributed Acoustic and Temperature Sensing (DATS). Additionally, in order to increase the energy availability, thus increasing operational efficiencies, Petrobras is studying to electrically connect platforms through submarine power umbilical.
In alignment with the Net Zero by 2050 Petrobras ambition, several technologies are being incorporated, such as flare gas recovery units, carbon capture, utilization, and storage associated with enhanced oil recovery, operational venting recovery systems and low-emission fugitive valves.
For the long-term of the Field, studies are being carried out to ensure the integrity of the facilities and extend the life span of the current units.
With those innovative technologies and initiatives, Petrobras, Partners and PPSA intend not only to extract the best value of the Field in the present, but also guarantee a long-term production, maximizing the value of the world’s largest ultra-deepwater oil field.
Chenji Wei
Speaker
Deputy Director of the Development Planning Department
Research Institute of Petroleum Exploration and Development, PetroChina
China
Effectively developing tight carbonate reservoir is challenging due to low-permeability, strong heterogeneity, high uncertainty and consequently high cost. This paper focusses on a typical tight carbonate reservoir in Middle East with permeability 0.1 – 1mD with strong heterogeneity, which was not effectively developed over last 15 years, This paper presents a comprehensive development mode that achieved good production and economic performance.
3 different reservoir types are identified based on a novel and comprehensive workflow including seismic data, well logging, mechanics study, production performance, surveillance data etc. Customized development mode including well type, pattern, spacing, MRC design, and stimulation design to improve productivity and extend plateau. In addition, full life cycle development roadmap is established for this reservoir to enhance the EUR.
By successfully implementing this development strategy, single well production rate was increased by 150% by implementing the customized stimulation technologies combined with MRC well. Moreover, UTC was reduced by 21% while the field production rate was increased by 200% in 2 years by implementing this development mode.
This paper offers a case study on optimizing the development strategy for super tight carbonate reservoirs with strong heterogeneity. It also provides a methodology and a reference case for managers and engineers to develop other similar challenging reservoirs.
3 different reservoir types are identified based on a novel and comprehensive workflow including seismic data, well logging, mechanics study, production performance, surveillance data etc. Customized development mode including well type, pattern, spacing, MRC design, and stimulation design to improve productivity and extend plateau. In addition, full life cycle development roadmap is established for this reservoir to enhance the EUR.
By successfully implementing this development strategy, single well production rate was increased by 150% by implementing the customized stimulation technologies combined with MRC well. Moreover, UTC was reduced by 21% while the field production rate was increased by 200% in 2 years by implementing this development mode.
This paper offers a case study on optimizing the development strategy for super tight carbonate reservoirs with strong heterogeneity. It also provides a methodology and a reference case for managers and engineers to develop other similar challenging reservoirs.
