TECHNICAL PROGRAMME | Primary Energy Supply – Future Pathways
Opportunities for Oil & Gas Supply Growth - Shales, Oil Sands, New Basins Other Unconventionals
Forum 2 | Hall 9 - Technical Programme 1
13
October
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?
Objectives:
Conventional approaches to bottom hole pressure (BHP) calculations often suffer from inaccuracy due to a significant number of uncertainties of the fluid and tubular properties in real field operations, leading to a non-optimized decision-making process during critical operations. This paper introduces a novel methodology for calibrating friction data to enhance the precision of BHP calculations specifically tailored for hydraulic fracturing applications.
Method/Procedures:
The proposed approach integrates real-time friction data acquisition with advanced computational techniques to calibrate friction coefficients and accurately model the frictional losses incurred during fluid injection into the reservoir. By incorporating comprehensive consideration of wellbore geometry, fluid rheology, proppant characteristics, and operational parameters, the calibrated friction data significantly improves the fidelity of BHP predictions. Although the workflow was calibrated with bottom hole gauges data, most statistical data come from standard completions without extra cost. A significant difference in the approach was made after selecting a representative group based on pressure behavior at shut-in events.
Results/Observations/Conclusions:
Case studies illustrate the efficacy of the methodology in various hydraulic fracturing scenarios, showcasing its ability to optimize fracture designs, mitigate the risk of fracturing fluid diversion, and improve reservoir contact. Furthermore, the calibrated friction data facilitates the identification of potential wellbore integrity issues and enables proactive measures to enhance well performance and longevity. Considering the criticality of live decision-making for the expensive high-pressure high-temperature (HPHT) operations in the environment with operations being held within a narrow pressure window, the approach represents significant importance to fracture placement success and overall field development. The method allowed to reduce uncertainty in decision-making by more than 60%. Implemented in over 100 hydraulic fracturing treatments across various geological formations and operational conditions; it allowed placing flawlessly to completion up to 5% additional fracturing stages by avoiding early flushing due to pressure uncertainties. Statistical analysis of the case studies from a diverse set of hydraulic fracturing scenarios, covering different reservoir types, depths, and fluid compositions revealed a mean absolute error reduction of 20% and a correlation coefficient improvement of 0.15 compared to conventional methods. Showcased up to 25% decrease in the risk of inefficient reservoir stimulation, contributing to safer and more effective hydraulic fracturing operations.
Novelty:
The integration of friction data calibration into BHP calculations during hydraulic fracturing operations represents a significant advancement in reservoir engineering practices, enabling operators to make informed decisions, maximize production efficiency, and optimize asset performance. This paper contributes to the ongoing efforts to enhance the reliability and effectiveness of hydraulic fracturing operations in unlocking tight hydrocarbon resources in high-stress geological environments. An innovative approach based on water-hummer criteria was shown vital and reliable to optimize decision-making.
Conventional approaches to bottom hole pressure (BHP) calculations often suffer from inaccuracy due to a significant number of uncertainties of the fluid and tubular properties in real field operations, leading to a non-optimized decision-making process during critical operations. This paper introduces a novel methodology for calibrating friction data to enhance the precision of BHP calculations specifically tailored for hydraulic fracturing applications.
Method/Procedures:
The proposed approach integrates real-time friction data acquisition with advanced computational techniques to calibrate friction coefficients and accurately model the frictional losses incurred during fluid injection into the reservoir. By incorporating comprehensive consideration of wellbore geometry, fluid rheology, proppant characteristics, and operational parameters, the calibrated friction data significantly improves the fidelity of BHP predictions. Although the workflow was calibrated with bottom hole gauges data, most statistical data come from standard completions without extra cost. A significant difference in the approach was made after selecting a representative group based on pressure behavior at shut-in events.
Results/Observations/Conclusions:
Case studies illustrate the efficacy of the methodology in various hydraulic fracturing scenarios, showcasing its ability to optimize fracture designs, mitigate the risk of fracturing fluid diversion, and improve reservoir contact. Furthermore, the calibrated friction data facilitates the identification of potential wellbore integrity issues and enables proactive measures to enhance well performance and longevity. Considering the criticality of live decision-making for the expensive high-pressure high-temperature (HPHT) operations in the environment with operations being held within a narrow pressure window, the approach represents significant importance to fracture placement success and overall field development. The method allowed to reduce uncertainty in decision-making by more than 60%. Implemented in over 100 hydraulic fracturing treatments across various geological formations and operational conditions; it allowed placing flawlessly to completion up to 5% additional fracturing stages by avoiding early flushing due to pressure uncertainties. Statistical analysis of the case studies from a diverse set of hydraulic fracturing scenarios, covering different reservoir types, depths, and fluid compositions revealed a mean absolute error reduction of 20% and a correlation coefficient improvement of 0.15 compared to conventional methods. Showcased up to 25% decrease in the risk of inefficient reservoir stimulation, contributing to safer and more effective hydraulic fracturing operations.
Novelty:
The integration of friction data calibration into BHP calculations during hydraulic fracturing operations represents a significant advancement in reservoir engineering practices, enabling operators to make informed decisions, maximize production efficiency, and optimize asset performance. This paper contributes to the ongoing efforts to enhance the reliability and effectiveness of hydraulic fracturing operations in unlocking tight hydrocarbon resources in high-stress geological environments. An innovative approach based on water-hummer criteria was shown vital and reliable to optimize decision-making.
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: Ting Huang, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Hongjun Lu, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Changhao Yan, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Xiaohu Bai, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Xiangping Li, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Bo Kang, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Jinzhu Yu, Petroleum Engineer, 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: Ting Huang, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Hongjun Lu, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Changhao Yan, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Xiaohu Bai, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Xiangping Li, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Bo Kang, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Jinzhu Yu, Petroleum Engineer, 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.
Johannes Alvarez
Chair
Enhanced Oil Recovery Manager Shale & Tight Business
Chevron Upstream
United States of America
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.
Objectives:
Conventional approaches to bottom hole pressure (BHP) calculations often suffer from inaccuracy due to a significant number of uncertainties of the fluid and tubular properties in real field operations, leading to a non-optimized decision-making process during critical operations. This paper introduces a novel methodology for calibrating friction data to enhance the precision of BHP calculations specifically tailored for hydraulic fracturing applications.
Method/Procedures:
The proposed approach integrates real-time friction data acquisition with advanced computational techniques to calibrate friction coefficients and accurately model the frictional losses incurred during fluid injection into the reservoir. By incorporating comprehensive consideration of wellbore geometry, fluid rheology, proppant characteristics, and operational parameters, the calibrated friction data significantly improves the fidelity of BHP predictions. Although the workflow was calibrated with bottom hole gauges data, most statistical data come from standard completions without extra cost. A significant difference in the approach was made after selecting a representative group based on pressure behavior at shut-in events.
Results/Observations/Conclusions:
Case studies illustrate the efficacy of the methodology in various hydraulic fracturing scenarios, showcasing its ability to optimize fracture designs, mitigate the risk of fracturing fluid diversion, and improve reservoir contact. Furthermore, the calibrated friction data facilitates the identification of potential wellbore integrity issues and enables proactive measures to enhance well performance and longevity. Considering the criticality of live decision-making for the expensive high-pressure high-temperature (HPHT) operations in the environment with operations being held within a narrow pressure window, the approach represents significant importance to fracture placement success and overall field development. The method allowed to reduce uncertainty in decision-making by more than 60%. Implemented in over 100 hydraulic fracturing treatments across various geological formations and operational conditions; it allowed placing flawlessly to completion up to 5% additional fracturing stages by avoiding early flushing due to pressure uncertainties. Statistical analysis of the case studies from a diverse set of hydraulic fracturing scenarios, covering different reservoir types, depths, and fluid compositions revealed a mean absolute error reduction of 20% and a correlation coefficient improvement of 0.15 compared to conventional methods. Showcased up to 25% decrease in the risk of inefficient reservoir stimulation, contributing to safer and more effective hydraulic fracturing operations.
Novelty:
The integration of friction data calibration into BHP calculations during hydraulic fracturing operations represents a significant advancement in reservoir engineering practices, enabling operators to make informed decisions, maximize production efficiency, and optimize asset performance. This paper contributes to the ongoing efforts to enhance the reliability and effectiveness of hydraulic fracturing operations in unlocking tight hydrocarbon resources in high-stress geological environments. An innovative approach based on water-hummer criteria was shown vital and reliable to optimize decision-making.
Conventional approaches to bottom hole pressure (BHP) calculations often suffer from inaccuracy due to a significant number of uncertainties of the fluid and tubular properties in real field operations, leading to a non-optimized decision-making process during critical operations. This paper introduces a novel methodology for calibrating friction data to enhance the precision of BHP calculations specifically tailored for hydraulic fracturing applications.
Method/Procedures:
The proposed approach integrates real-time friction data acquisition with advanced computational techniques to calibrate friction coefficients and accurately model the frictional losses incurred during fluid injection into the reservoir. By incorporating comprehensive consideration of wellbore geometry, fluid rheology, proppant characteristics, and operational parameters, the calibrated friction data significantly improves the fidelity of BHP predictions. Although the workflow was calibrated with bottom hole gauges data, most statistical data come from standard completions without extra cost. A significant difference in the approach was made after selecting a representative group based on pressure behavior at shut-in events.
Results/Observations/Conclusions:
Case studies illustrate the efficacy of the methodology in various hydraulic fracturing scenarios, showcasing its ability to optimize fracture designs, mitigate the risk of fracturing fluid diversion, and improve reservoir contact. Furthermore, the calibrated friction data facilitates the identification of potential wellbore integrity issues and enables proactive measures to enhance well performance and longevity. Considering the criticality of live decision-making for the expensive high-pressure high-temperature (HPHT) operations in the environment with operations being held within a narrow pressure window, the approach represents significant importance to fracture placement success and overall field development. The method allowed to reduce uncertainty in decision-making by more than 60%. Implemented in over 100 hydraulic fracturing treatments across various geological formations and operational conditions; it allowed placing flawlessly to completion up to 5% additional fracturing stages by avoiding early flushing due to pressure uncertainties. Statistical analysis of the case studies from a diverse set of hydraulic fracturing scenarios, covering different reservoir types, depths, and fluid compositions revealed a mean absolute error reduction of 20% and a correlation coefficient improvement of 0.15 compared to conventional methods. Showcased up to 25% decrease in the risk of inefficient reservoir stimulation, contributing to safer and more effective hydraulic fracturing operations.
Novelty:
The integration of friction data calibration into BHP calculations during hydraulic fracturing operations represents a significant advancement in reservoir engineering practices, enabling operators to make informed decisions, maximize production efficiency, and optimize asset performance. This paper contributes to the ongoing efforts to enhance the reliability and effectiveness of hydraulic fracturing operations in unlocking tight hydrocarbon resources in high-stress geological environments. An innovative approach based on water-hummer criteria was shown vital and reliable to optimize decision-making.
Yushuo Zhang
Speaker
Petroleum Engineer
Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company
Canada
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: Ting Huang, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Hongjun Lu, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Changhao Yan, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Xiaohu Bai, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Xiangping Li, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Bo Kang, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Jinzhu Yu, Petroleum Engineer, 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: Ting Huang, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Hongjun Lu, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Changhao Yan, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Xiaohu Bai, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Xiangping Li, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Bo Kang, Senior Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company I Jinzhu Yu, Petroleum Engineer, Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company.
