TECHNICAL PROGRAMME | Primary Energy Supply – Future Pathways
Opportunities for Oil & Gas Supply Growth - Shales, Oil Sands, New Basins Other Unconventionals
Forum 2 | Technical Programme Hall 1
28
April
10:00
11:30
UTC+3
As the world continues to consumes oil and natural gas as a critical component of energy supply to fuel economic growth, improve standards of living, and support the development of ever-cleaner energy technologies, there remains a need to offset production reduction from existing sources. Where do we find these new oil and natural gas resources? Which basins have remaining exploration potential? How do we tap the remaining potential in shales, oil sands, and other unconventional petroleum resources?
Mature oilfields, which contribute significantly to global production, often face challenges such as production decline, low recovery efficiency, and complex wellbore issues. This study presents integrated technical strategies developed and deployed in the Ordos Basin, China, aimed at enhancing recovery and stabilizing production in mature low-permeability oilfields.
The approach is structured around three main strategies. The first involves improving water flooding management through advanced technologies such as coded communication injection systems and self-adaptive conformance control agents, which help improve sweep efficiency and enhance injection profile conformance. The second strategy focuses on managing low-production and inactive wells. This is achieved through targeted methods like CO2-assisted re-fracturing, wide-fracture re-fracturing, and integrated well group stimulation to revive inactive wells and boost production. The third strategy involves the implementation of Enhanced Oil Recovery (EOR) techniques. These include gravity-assisted CO2 flooding, microfoam flooding, and quantum dot displacement agents, all aimed at improving recovery in low-permeability reservoirs.
Field results demonstrate significant improvements, including an increase in injection allocation qualification rates of more than 82 percent, a reduction in the natural decline rate, and significant incremental oil production from various stimulation and EOR methods. These technologies contributed to improved sweep efficiency, effective carbon utilization, and higher recovery factors.
This integrated technical system has proven effective in extending the productive life and maximizing recovery from mature, low-permeability oilfields like those in the Ordos Basin. The findings offer valuable insights for similar oil assets globally, providing a scalable and effective strategy for sustainable production and enhanced recovery.
Co-author/s:
Xiaohu Bai, Fracture Supervisor, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company.
The approach is structured around three main strategies. The first involves improving water flooding management through advanced technologies such as coded communication injection systems and self-adaptive conformance control agents, which help improve sweep efficiency and enhance injection profile conformance. The second strategy focuses on managing low-production and inactive wells. This is achieved through targeted methods like CO2-assisted re-fracturing, wide-fracture re-fracturing, and integrated well group stimulation to revive inactive wells and boost production. The third strategy involves the implementation of Enhanced Oil Recovery (EOR) techniques. These include gravity-assisted CO2 flooding, microfoam flooding, and quantum dot displacement agents, all aimed at improving recovery in low-permeability reservoirs.
Field results demonstrate significant improvements, including an increase in injection allocation qualification rates of more than 82 percent, a reduction in the natural decline rate, and significant incremental oil production from various stimulation and EOR methods. These technologies contributed to improved sweep efficiency, effective carbon utilization, and higher recovery factors.
This integrated technical system has proven effective in extending the productive life and maximizing recovery from mature, low-permeability oilfields like those in the Ordos Basin. The findings offer valuable insights for similar oil assets globally, providing a scalable and effective strategy for sustainable production and enhanced recovery.
Co-author/s:
Xiaohu Bai, Fracture Supervisor, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company.
Despite the global push toward renewable energy, fossil fuels are expected to maintain a significant share in the global energy mix over the coming decades. In this context, maximizing production from existing fields remains crucial. To address this challenge, Petrobras has implemented, since 2020, a strategic program aimed at increasing the recovery factor and accelerating reserve replacement in its key upstream assets.
Oil and gas recovery factors typically improve over time as reservoir knowledge deepens and new technologies or reservoir management practices are implemented. However, it is essential to define the limits of what can be technically and economically achieved. To address this, Petrobras developed a methodology to establish a reference recovery factor at the time of field abandonment. This benchmark is based on: (i) the correlation between current recovery factors and reservoir transmissibility, using global analogs; and (ii) a probabilistic approach that sets an ambition aligned with the performance of top-tier reservoirs worldwide.
With the reference benchmark in place, the program moved to define clear reserve replacement targets for each asset, aiming for achievement by 2030. To guide the execution, each asset develops a master plan detailing short, medium and long-term strategies. These plans identify the required investment projects, technologies, and reservoir management activities needed to reach the set targets, including the maturation of less-developed opportunities.
Once the master plan is in place, each opportunity is further assessed and developed to reach the technical and economic maturity required to progress through the company’s project approval process. Projects that are successfully approved then move into execution, directly contributing to reserve growth.
The impact of this initiative is already evident: since the program’s launch, Petrobras has consistently achieved a reserve replacement ratio above 100%, demonstrating both the effectiveness of the approach and the potential of strategic reservoir management to unlock significant value. This paper will present the methodology, implementation, and outcomes of Petrobras' reserve replacement program, showcasing a scalable model for maximizing the value of mature fields in a transitioning energy landscape.
Oil and gas recovery factors typically improve over time as reservoir knowledge deepens and new technologies or reservoir management practices are implemented. However, it is essential to define the limits of what can be technically and economically achieved. To address this, Petrobras developed a methodology to establish a reference recovery factor at the time of field abandonment. This benchmark is based on: (i) the correlation between current recovery factors and reservoir transmissibility, using global analogs; and (ii) a probabilistic approach that sets an ambition aligned with the performance of top-tier reservoirs worldwide.
With the reference benchmark in place, the program moved to define clear reserve replacement targets for each asset, aiming for achievement by 2030. To guide the execution, each asset develops a master plan detailing short, medium and long-term strategies. These plans identify the required investment projects, technologies, and reservoir management activities needed to reach the set targets, including the maturation of less-developed opportunities.
Once the master plan is in place, each opportunity is further assessed and developed to reach the technical and economic maturity required to progress through the company’s project approval process. Projects that are successfully approved then move into execution, directly contributing to reserve growth.
The impact of this initiative is already evident: since the program’s launch, Petrobras has consistently achieved a reserve replacement ratio above 100%, demonstrating both the effectiveness of the approach and the potential of strategic reservoir management to unlock significant value. This paper will present the methodology, implementation, and outcomes of Petrobras' reserve replacement program, showcasing a scalable model for maximizing the value of mature fields in a transitioning energy landscape.
Water demand in unconventional oil and gas hydraulic fracturing operationa poses a critical sustainability challenge in arid regions. For example, in The Jafurah field in Saudi Arabia, a world-scale shale gas development with estimated Gas In Place of 200 trillion cubic feet, requires millions of cubic meters of water annually per phase. Given its desert location, proximity to the saline Arabian Gulf, and the high salinity of produced water, traditional water sourcing and disposal practices are a challenge for such an operation—one that is crucial to satisfying the Kingdom’s growing gas needs.
This paper proposes a novel application of an integrated renewable energy system—including concentrated solar power, solar ponds, wind, and pressure-retarded osmosis—for decentralized water desalination and reuse in shale gas operations. The system, originally proposed for broader water-energy integration, is adapted here for field-scale deployment at Jafurah. It enables the treatment of flowback and produced water for reuse, reducing freshwater withdrawal and brine disposal, while supporting Saudi Arabia’s Vision 2030 sustainability targets.
Key performance metrics are presented to compare desalinated water yield and energy consumption under conventional and renewable-powered systems. Findings indicate significant potential for cost savings and emissions reduction by integrating such renewable platforms into gas field water management strategies. The work supports a pathway to an energy future that addresses both environmental stewardship and operational resilience.
This abstract is submitted in collaboration with a broader proposal on renewable-integrated systems for national energy and water security.
This paper proposes a novel application of an integrated renewable energy system—including concentrated solar power, solar ponds, wind, and pressure-retarded osmosis—for decentralized water desalination and reuse in shale gas operations. The system, originally proposed for broader water-energy integration, is adapted here for field-scale deployment at Jafurah. It enables the treatment of flowback and produced water for reuse, reducing freshwater withdrawal and brine disposal, while supporting Saudi Arabia’s Vision 2030 sustainability targets.
Key performance metrics are presented to compare desalinated water yield and energy consumption under conventional and renewable-powered systems. Findings indicate significant potential for cost savings and emissions reduction by integrating such renewable platforms into gas field water management strategies. The work supports a pathway to an energy future that addresses both environmental stewardship and operational resilience.
This abstract is submitted in collaboration with a broader proposal on renewable-integrated systems for national energy and water security.
The main objective of this paper is to establish a foundation for a new exploration model that rejects the previous paradigm and significantly expands the country's oil and gas prospectivity, which will ensure the nation's energy security.
Much pioneering work has been done on Cuban geology by Cuban and foreign geologists. The existing basis - knowledge in petroleum geology has been widely summarized in an evaluation conducted by the technical team of the CubaPetroleo's Research Petroleum Center (CEINPET) over the last five years. The results of this evaluation are introduced in this paper.
In order to achieve the above mentioned objective, several existing updated data, information, and knowledge on oil exploration and production were combined and integrated. An analysis, development and evaluation of criteria on the geological background and the petroleum geology had been performed, incorporating non-seismic and unconventional methods.
The previous paradigm for oil exploration in Cuba established the subsidence of the main producing sequences beneath rocks of the Caribbean Plate, with high geological complexity, thrusted from the south - relative to the current position of the Northern Cuban Oil Belt (NCOB) - located between Havana Bay and Cardenas Bay. The most developed sector of the Caribbean Plate was considered to have lower prospectivity.
The new model reveals areas with greater exploration potential not previously identified, offering the possibility of discovering larger oilfields with better - quality crude oil. It was demonstrated the presence of belts raised hypsometrically to the south (1.5–2.5 km), 20–30 km wide, extending 700 km in length, from Artemisa province to the west, to Holguín province in the east. This new model differences with the previous model, which only reaches about 200 km in length by 5–15 km in width, around the NCOB.
The new oilfields are predicted to contain better quality oils, up to medium and light, due to the increased maturity towards the south and the existence of improved preservation conditions. As a result, the reserve recovery ratio could be increase at least two to three times.
A methodology for the study, analysis, and evaluation of criteria, based on the geological background, evolution, and petroleum geology is established, founded on the exploration process value chain. This methodology allows the development of valid arguments regarding exploration potential. On the same page, the contribution of non-seismic and unconventional exploration methods improves the information knowledge for uncovering potential oilfields.
As a conclusion of this paper the new model strongly backs up the possibility of discovering oilfields up to the size of giants (like existing Varadero Oilfield), with higher - quality oil than those discovered in the NCOB and with higher reserve recovery ratio.
Co-author/s:
Jose Orlando Lopez Quintero, Senior Consultant, CUPET.
Much pioneering work has been done on Cuban geology by Cuban and foreign geologists. The existing basis - knowledge in petroleum geology has been widely summarized in an evaluation conducted by the technical team of the CubaPetroleo's Research Petroleum Center (CEINPET) over the last five years. The results of this evaluation are introduced in this paper.
In order to achieve the above mentioned objective, several existing updated data, information, and knowledge on oil exploration and production were combined and integrated. An analysis, development and evaluation of criteria on the geological background and the petroleum geology had been performed, incorporating non-seismic and unconventional methods.
The previous paradigm for oil exploration in Cuba established the subsidence of the main producing sequences beneath rocks of the Caribbean Plate, with high geological complexity, thrusted from the south - relative to the current position of the Northern Cuban Oil Belt (NCOB) - located between Havana Bay and Cardenas Bay. The most developed sector of the Caribbean Plate was considered to have lower prospectivity.
The new model reveals areas with greater exploration potential not previously identified, offering the possibility of discovering larger oilfields with better - quality crude oil. It was demonstrated the presence of belts raised hypsometrically to the south (1.5–2.5 km), 20–30 km wide, extending 700 km in length, from Artemisa province to the west, to Holguín province in the east. This new model differences with the previous model, which only reaches about 200 km in length by 5–15 km in width, around the NCOB.
The new oilfields are predicted to contain better quality oils, up to medium and light, due to the increased maturity towards the south and the existence of improved preservation conditions. As a result, the reserve recovery ratio could be increase at least two to three times.
A methodology for the study, analysis, and evaluation of criteria, based on the geological background, evolution, and petroleum geology is established, founded on the exploration process value chain. This methodology allows the development of valid arguments regarding exploration potential. On the same page, the contribution of non-seismic and unconventional exploration methods improves the information knowledge for uncovering potential oilfields.
As a conclusion of this paper the new model strongly backs up the possibility of discovering oilfields up to the size of giants (like existing Varadero Oilfield), with higher - quality oil than those discovered in the NCOB and with higher reserve recovery ratio.
Co-author/s:
Jose Orlando Lopez Quintero, Senior Consultant, CUPET.
Johannes Alvarez
Chair
Improved Recovery Team Lead, Applied Reservoir Management
Chevron Americas Exploration & Production
Water demand in unconventional oil and gas hydraulic fracturing operationa poses a critical sustainability challenge in arid regions. For example, in The Jafurah field in Saudi Arabia, a world-scale shale gas development with estimated Gas In Place of 200 trillion cubic feet, requires millions of cubic meters of water annually per phase. Given its desert location, proximity to the saline Arabian Gulf, and the high salinity of produced water, traditional water sourcing and disposal practices are a challenge for such an operation—one that is crucial to satisfying the Kingdom’s growing gas needs.
This paper proposes a novel application of an integrated renewable energy system—including concentrated solar power, solar ponds, wind, and pressure-retarded osmosis—for decentralized water desalination and reuse in shale gas operations. The system, originally proposed for broader water-energy integration, is adapted here for field-scale deployment at Jafurah. It enables the treatment of flowback and produced water for reuse, reducing freshwater withdrawal and brine disposal, while supporting Saudi Arabia’s Vision 2030 sustainability targets.
Key performance metrics are presented to compare desalinated water yield and energy consumption under conventional and renewable-powered systems. Findings indicate significant potential for cost savings and emissions reduction by integrating such renewable platforms into gas field water management strategies. The work supports a pathway to an energy future that addresses both environmental stewardship and operational resilience.
This abstract is submitted in collaboration with a broader proposal on renewable-integrated systems for national energy and water security.
This paper proposes a novel application of an integrated renewable energy system—including concentrated solar power, solar ponds, wind, and pressure-retarded osmosis—for decentralized water desalination and reuse in shale gas operations. The system, originally proposed for broader water-energy integration, is adapted here for field-scale deployment at Jafurah. It enables the treatment of flowback and produced water for reuse, reducing freshwater withdrawal and brine disposal, while supporting Saudi Arabia’s Vision 2030 sustainability targets.
Key performance metrics are presented to compare desalinated water yield and energy consumption under conventional and renewable-powered systems. Findings indicate significant potential for cost savings and emissions reduction by integrating such renewable platforms into gas field water management strategies. The work supports a pathway to an energy future that addresses both environmental stewardship and operational resilience.
This abstract is submitted in collaboration with a broader proposal on renewable-integrated systems for national energy and water security.
Despite the global push toward renewable energy, fossil fuels are expected to maintain a significant share in the global energy mix over the coming decades. In this context, maximizing production from existing fields remains crucial. To address this challenge, Petrobras has implemented, since 2020, a strategic program aimed at increasing the recovery factor and accelerating reserve replacement in its key upstream assets.
Oil and gas recovery factors typically improve over time as reservoir knowledge deepens and new technologies or reservoir management practices are implemented. However, it is essential to define the limits of what can be technically and economically achieved. To address this, Petrobras developed a methodology to establish a reference recovery factor at the time of field abandonment. This benchmark is based on: (i) the correlation between current recovery factors and reservoir transmissibility, using global analogs; and (ii) a probabilistic approach that sets an ambition aligned with the performance of top-tier reservoirs worldwide.
With the reference benchmark in place, the program moved to define clear reserve replacement targets for each asset, aiming for achievement by 2030. To guide the execution, each asset develops a master plan detailing short, medium and long-term strategies. These plans identify the required investment projects, technologies, and reservoir management activities needed to reach the set targets, including the maturation of less-developed opportunities.
Once the master plan is in place, each opportunity is further assessed and developed to reach the technical and economic maturity required to progress through the company’s project approval process. Projects that are successfully approved then move into execution, directly contributing to reserve growth.
The impact of this initiative is already evident: since the program’s launch, Petrobras has consistently achieved a reserve replacement ratio above 100%, demonstrating both the effectiveness of the approach and the potential of strategic reservoir management to unlock significant value. This paper will present the methodology, implementation, and outcomes of Petrobras' reserve replacement program, showcasing a scalable model for maximizing the value of mature fields in a transitioning energy landscape.
Oil and gas recovery factors typically improve over time as reservoir knowledge deepens and new technologies or reservoir management practices are implemented. However, it is essential to define the limits of what can be technically and economically achieved. To address this, Petrobras developed a methodology to establish a reference recovery factor at the time of field abandonment. This benchmark is based on: (i) the correlation between current recovery factors and reservoir transmissibility, using global analogs; and (ii) a probabilistic approach that sets an ambition aligned with the performance of top-tier reservoirs worldwide.
With the reference benchmark in place, the program moved to define clear reserve replacement targets for each asset, aiming for achievement by 2030. To guide the execution, each asset develops a master plan detailing short, medium and long-term strategies. These plans identify the required investment projects, technologies, and reservoir management activities needed to reach the set targets, including the maturation of less-developed opportunities.
Once the master plan is in place, each opportunity is further assessed and developed to reach the technical and economic maturity required to progress through the company’s project approval process. Projects that are successfully approved then move into execution, directly contributing to reserve growth.
The impact of this initiative is already evident: since the program’s launch, Petrobras has consistently achieved a reserve replacement ratio above 100%, demonstrating both the effectiveness of the approach and the potential of strategic reservoir management to unlock significant value. This paper will present the methodology, implementation, and outcomes of Petrobras' reserve replacement program, showcasing a scalable model for maximizing the value of mature fields in a transitioning energy landscape.
The main objective of this paper is to establish a foundation for a new exploration model that rejects the previous paradigm and significantly expands the country's oil and gas prospectivity, which will ensure the nation's energy security.
Much pioneering work has been done on Cuban geology by Cuban and foreign geologists. The existing basis - knowledge in petroleum geology has been widely summarized in an evaluation conducted by the technical team of the CubaPetroleo's Research Petroleum Center (CEINPET) over the last five years. The results of this evaluation are introduced in this paper.
In order to achieve the above mentioned objective, several existing updated data, information, and knowledge on oil exploration and production were combined and integrated. An analysis, development and evaluation of criteria on the geological background and the petroleum geology had been performed, incorporating non-seismic and unconventional methods.
The previous paradigm for oil exploration in Cuba established the subsidence of the main producing sequences beneath rocks of the Caribbean Plate, with high geological complexity, thrusted from the south - relative to the current position of the Northern Cuban Oil Belt (NCOB) - located between Havana Bay and Cardenas Bay. The most developed sector of the Caribbean Plate was considered to have lower prospectivity.
The new model reveals areas with greater exploration potential not previously identified, offering the possibility of discovering larger oilfields with better - quality crude oil. It was demonstrated the presence of belts raised hypsometrically to the south (1.5–2.5 km), 20–30 km wide, extending 700 km in length, from Artemisa province to the west, to Holguín province in the east. This new model differences with the previous model, which only reaches about 200 km in length by 5–15 km in width, around the NCOB.
The new oilfields are predicted to contain better quality oils, up to medium and light, due to the increased maturity towards the south and the existence of improved preservation conditions. As a result, the reserve recovery ratio could be increase at least two to three times.
A methodology for the study, analysis, and evaluation of criteria, based on the geological background, evolution, and petroleum geology is established, founded on the exploration process value chain. This methodology allows the development of valid arguments regarding exploration potential. On the same page, the contribution of non-seismic and unconventional exploration methods improves the information knowledge for uncovering potential oilfields.
As a conclusion of this paper the new model strongly backs up the possibility of discovering oilfields up to the size of giants (like existing Varadero Oilfield), with higher - quality oil than those discovered in the NCOB and with higher reserve recovery ratio.
Co-author/s:
Jose Orlando Lopez Quintero, Senior Consultant, CUPET.
Much pioneering work has been done on Cuban geology by Cuban and foreign geologists. The existing basis - knowledge in petroleum geology has been widely summarized in an evaluation conducted by the technical team of the CubaPetroleo's Research Petroleum Center (CEINPET) over the last five years. The results of this evaluation are introduced in this paper.
In order to achieve the above mentioned objective, several existing updated data, information, and knowledge on oil exploration and production were combined and integrated. An analysis, development and evaluation of criteria on the geological background and the petroleum geology had been performed, incorporating non-seismic and unconventional methods.
The previous paradigm for oil exploration in Cuba established the subsidence of the main producing sequences beneath rocks of the Caribbean Plate, with high geological complexity, thrusted from the south - relative to the current position of the Northern Cuban Oil Belt (NCOB) - located between Havana Bay and Cardenas Bay. The most developed sector of the Caribbean Plate was considered to have lower prospectivity.
The new model reveals areas with greater exploration potential not previously identified, offering the possibility of discovering larger oilfields with better - quality crude oil. It was demonstrated the presence of belts raised hypsometrically to the south (1.5–2.5 km), 20–30 km wide, extending 700 km in length, from Artemisa province to the west, to Holguín province in the east. This new model differences with the previous model, which only reaches about 200 km in length by 5–15 km in width, around the NCOB.
The new oilfields are predicted to contain better quality oils, up to medium and light, due to the increased maturity towards the south and the existence of improved preservation conditions. As a result, the reserve recovery ratio could be increase at least two to three times.
A methodology for the study, analysis, and evaluation of criteria, based on the geological background, evolution, and petroleum geology is established, founded on the exploration process value chain. This methodology allows the development of valid arguments regarding exploration potential. On the same page, the contribution of non-seismic and unconventional exploration methods improves the information knowledge for uncovering potential oilfields.
As a conclusion of this paper the new model strongly backs up the possibility of discovering oilfields up to the size of giants (like existing Varadero Oilfield), with higher - quality oil than those discovered in the NCOB and with higher reserve recovery ratio.
Co-author/s:
Jose Orlando Lopez Quintero, Senior Consultant, CUPET.
Yushuo Zhang
Speaker
Petroleum Engineer
Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company
Mature oilfields, which contribute significantly to global production, often face challenges such as production decline, low recovery efficiency, and complex wellbore issues. This study presents integrated technical strategies developed and deployed in the Ordos Basin, China, aimed at enhancing recovery and stabilizing production in mature low-permeability oilfields.
The approach is structured around three main strategies. The first involves improving water flooding management through advanced technologies such as coded communication injection systems and self-adaptive conformance control agents, which help improve sweep efficiency and enhance injection profile conformance. The second strategy focuses on managing low-production and inactive wells. This is achieved through targeted methods like CO2-assisted re-fracturing, wide-fracture re-fracturing, and integrated well group stimulation to revive inactive wells and boost production. The third strategy involves the implementation of Enhanced Oil Recovery (EOR) techniques. These include gravity-assisted CO2 flooding, microfoam flooding, and quantum dot displacement agents, all aimed at improving recovery in low-permeability reservoirs.
Field results demonstrate significant improvements, including an increase in injection allocation qualification rates of more than 82 percent, a reduction in the natural decline rate, and significant incremental oil production from various stimulation and EOR methods. These technologies contributed to improved sweep efficiency, effective carbon utilization, and higher recovery factors.
This integrated technical system has proven effective in extending the productive life and maximizing recovery from mature, low-permeability oilfields like those in the Ordos Basin. The findings offer valuable insights for similar oil assets globally, providing a scalable and effective strategy for sustainable production and enhanced recovery.
Co-author/s:
Xiaohu Bai, Fracture Supervisor, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company.
The approach is structured around three main strategies. The first involves improving water flooding management through advanced technologies such as coded communication injection systems and self-adaptive conformance control agents, which help improve sweep efficiency and enhance injection profile conformance. The second strategy focuses on managing low-production and inactive wells. This is achieved through targeted methods like CO2-assisted re-fracturing, wide-fracture re-fracturing, and integrated well group stimulation to revive inactive wells and boost production. The third strategy involves the implementation of Enhanced Oil Recovery (EOR) techniques. These include gravity-assisted CO2 flooding, microfoam flooding, and quantum dot displacement agents, all aimed at improving recovery in low-permeability reservoirs.
Field results demonstrate significant improvements, including an increase in injection allocation qualification rates of more than 82 percent, a reduction in the natural decline rate, and significant incremental oil production from various stimulation and EOR methods. These technologies contributed to improved sweep efficiency, effective carbon utilization, and higher recovery factors.
This integrated technical system has proven effective in extending the productive life and maximizing recovery from mature, low-permeability oilfields like those in the Ordos Basin. The findings offer valuable insights for similar oil assets globally, providing a scalable and effective strategy for sustainable production and enhanced recovery.
Co-author/s:
Xiaohu Bai, Fracture Supervisor, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company.
