TECHNICAL PROGRAMME | Primary Energy Supply – Future Pathways
Opportunities for Oil & Gas Supply Growth - Shales, Oil Sands, New Basins Other Unconventionals
Forum 2 | Hall 5 Digital Poster Plaza 1
13
October
12:30
14:30
UTC+3
As the world continues to consume 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?
The growing demand for natural gas in China has driven a shift in supply over the past decade — from predominantly conventional sources to an increasing share of unconventional reservoirs. Commercial-scale Coalbed Methane (CBM) production was primarily extracted from Qinshui basin, targeting the shallow CBM deposits with very low single-well gas rates. By 2019, the exploration and development of deep CBM (depth greater than 1500m) in the Ordos Basin has been deciphered with the cost-effective scheme. Investments and activities have surged into the area to exploit the CBM resources and turned the production online. This comprehensive study examines the geological, engineering and management variations influencing the outcome by comparing key performance metrics from Ordos, San-Juan Basin and Queensland.
In this study, we first evaluate the formation characteristics that influence production performance, including reservoir pressure, in-situ stress, gas content, adsorption-desorption behavior, and brittleness. As coal seams extend to greater depths, the controlling factors become increasingly complex, exerting significant influence on properties that are closely linked to gas productivity. For example, coal seams located within zones of restricted water retention may exhibit higher gas saturation, while the orientation and density of butt and face cleats can impact permeability and fracability. In addition to geological variability, engineering designs and management strategies are also examined to address the unique challenges of deep CBM development. This paper provides a detailed comparison of key performance metrics across major CBM basins worldwide.
Overall, the study indicates that mid-to-high-rank coals in the Ordos Basin generally exhibit lower permeability but possess higher or comparable gas content relative to those in the San Juan and Queensland. Well completion practices also vary across these basins. In the Ordos Basin, the majority of wells are hydraulically fractured horizontal wells, whereas in the San Juan basin and Queensland, open-hole cavity vertical wells or directional wells targeting thicker coal seams are commonly employed. This comparative analysis highlights three key findings: 1) Production profiles differ between the Ordos Basin and the other two basins, with water production declining rapidly after gas production reaches a plateau. 2) Higher initial gas rates are largely driven by elevated free gas content (exceeding 20%). 3) Implementation of a controlled drawdown strategy can improve well EUR by 10–20%.
In this study, we first evaluate the formation characteristics that influence production performance, including reservoir pressure, in-situ stress, gas content, adsorption-desorption behavior, and brittleness. As coal seams extend to greater depths, the controlling factors become increasingly complex, exerting significant influence on properties that are closely linked to gas productivity. For example, coal seams located within zones of restricted water retention may exhibit higher gas saturation, while the orientation and density of butt and face cleats can impact permeability and fracability. In addition to geological variability, engineering designs and management strategies are also examined to address the unique challenges of deep CBM development. This paper provides a detailed comparison of key performance metrics across major CBM basins worldwide.
Overall, the study indicates that mid-to-high-rank coals in the Ordos Basin generally exhibit lower permeability but possess higher or comparable gas content relative to those in the San Juan and Queensland. Well completion practices also vary across these basins. In the Ordos Basin, the majority of wells are hydraulically fractured horizontal wells, whereas in the San Juan basin and Queensland, open-hole cavity vertical wells or directional wells targeting thicker coal seams are commonly employed. This comparative analysis highlights three key findings: 1) Production profiles differ between the Ordos Basin and the other two basins, with water production declining rapidly after gas production reaches a plateau. 2) Higher initial gas rates are largely driven by elevated free gas content (exceeding 20%). 3) Implementation of a controlled drawdown strategy can improve well EUR by 10–20%.
Objectives & Scope:
To reach Kuwait’s oil production target, production enhancement from tight carbonate reservoirs is essential. In this paper, it will be demonstrated how an integrated workflow that includes advanced reservoir characterization to optimize the stimulation design with enhanced zonal coverage in a heterogenous Jurassic reservoir.
Methods, Procedures & Process:
To accurately select the candidate based on precise determination of the reservoir permeability contrast across the different layers. Representative fluid samples have been captured to map the asphaltene envelope. The injection logging survey was a key input to determine the permeability profile and to evaluate the integrity of the patchy cement through temperature analysis. Pressure Transiet Analysis (PTA) were essential to evaluate the significance of the depletion across the different areas of the field as well as to determine the total skin of the reservoir. The integration of these data in a structured workflow enhanced the stimulation design.
Results, Observations & Conclusions:
Based on the significant permeability contrast, Single-Phase Retarded Acid (SPRA) and Bio-degradable Particulate Diverters (BPD) were found to be essential to unlock the tighter layers. Five wells were stimulated utilizing the above workflow resulting in 7 folds of increase in the oil production versus 4 folds of increase before implementing this workflow. Another important observation is the sustainability of these wells for over 1 year with less frequency in asphaltene clean-out treatments.
It can be observed that meticulous characterization, planning and execution for tight carbonate reservoirs is critical for a sustained production enhancement. This reservoir oil production has increased by 150% from existing wells with rigless intervention.
New Information to Existing Literature:
This paper demonstrates the economical development of deep tight carbonate reservoirs through fit-for-purpose workflows. The findings were utilized to update the full field development strategy.
To reach Kuwait’s oil production target, production enhancement from tight carbonate reservoirs is essential. In this paper, it will be demonstrated how an integrated workflow that includes advanced reservoir characterization to optimize the stimulation design with enhanced zonal coverage in a heterogenous Jurassic reservoir.
Methods, Procedures & Process:
To accurately select the candidate based on precise determination of the reservoir permeability contrast across the different layers. Representative fluid samples have been captured to map the asphaltene envelope. The injection logging survey was a key input to determine the permeability profile and to evaluate the integrity of the patchy cement through temperature analysis. Pressure Transiet Analysis (PTA) were essential to evaluate the significance of the depletion across the different areas of the field as well as to determine the total skin of the reservoir. The integration of these data in a structured workflow enhanced the stimulation design.
Results, Observations & Conclusions:
Based on the significant permeability contrast, Single-Phase Retarded Acid (SPRA) and Bio-degradable Particulate Diverters (BPD) were found to be essential to unlock the tighter layers. Five wells were stimulated utilizing the above workflow resulting in 7 folds of increase in the oil production versus 4 folds of increase before implementing this workflow. Another important observation is the sustainability of these wells for over 1 year with less frequency in asphaltene clean-out treatments.
It can be observed that meticulous characterization, planning and execution for tight carbonate reservoirs is critical for a sustained production enhancement. This reservoir oil production has increased by 150% from existing wells with rigless intervention.
New Information to Existing Literature:
This paper demonstrates the economical development of deep tight carbonate reservoirs through fit-for-purpose workflows. The findings were utilized to update the full field development strategy.
While natural gas is increasingly important, especially for electricity generation and as a cleaner alternative to coal and oil, oil has historically been the backbone of energy supply and economic revenue for many Middle Eastern countries. The higher profitability and global demand for oil have often driven more investment into oil exploration and production. Since the early 1970s, the discovery of the massive South Pars/North Dome gas resources in Permo-Triassic reservoirs has opened a new horizon in this area for various Middle Eastern countries. In deep reservoirs (Permo-Triassic and deeper) in the Middle East, the expectation is generally for the discovery of gas, and many fields are already in production.
Exploring for oil in such challenging reservoirs demands advanced approaches. The combination of reservoir depth and extreme temperature and pressure makes conventional exploration and production techniques less effective or riskier. Therefore detailed geological, geophysical, and geochemical studies are crucial to better understand the subsurface conditions and to accurately identify any possible hydrocarbon presence.
Saudi Arabia, Qatar, Iran, United Arab Emirates, and Oman have achieved successes in the past two decades, and the results of these studies can illuminate the future prospects for oil discovery in these reservoirs. Drawing on the experiences of Saudi Arabia and Qatar and carefully examining their studies and achievements in this area has led to various detailed studies in Iran, which have confirmed the presence of oil, both onshore and offshore, in the Permo-Triassic horizon. Paleohighs play a crucial role in hydrocarbon systems. These ancient structural highs can control where oil is generated, how it migrates, and where it gets trapped and preserved. Therefore, understanding the trend of paleohighs and the timing of their formation (especially the Qatar-Fars Arch in Iran) in relation to the migration and trapping of oil, has led to the discovery of various oil fields in the Permo-Triassic horizon in Iran. A change in approach and a more complete understanding of previously discovered Permo-Triassic gas reservoirs has also led to a new assessment of the potential for oil rims in previous assumed gas fields. This shift in perspective, from considering deep reservoirs as solely gas-bearing to the possibility of oil presence, has ultimately directed to the discovery of oil horizons in proven gas reservoirs.
Integrated geological studies, combining data from geology, geophysics, geochemistry, and petrophysics have indeed revolutionized oil exploration in challenging deep reservoirs (Permo-Triassic horizon). This multidisciplinary approach helps reduce uncertainties and better characterize reservoirs. For countries like Iran, this opens up new prospects, potentially boosting energy supply and economic benefits. It also encourages future exploration to be more data-driven and precise, improving success rates and resource management.
Exploring for oil in such challenging reservoirs demands advanced approaches. The combination of reservoir depth and extreme temperature and pressure makes conventional exploration and production techniques less effective or riskier. Therefore detailed geological, geophysical, and geochemical studies are crucial to better understand the subsurface conditions and to accurately identify any possible hydrocarbon presence.
Saudi Arabia, Qatar, Iran, United Arab Emirates, and Oman have achieved successes in the past two decades, and the results of these studies can illuminate the future prospects for oil discovery in these reservoirs. Drawing on the experiences of Saudi Arabia and Qatar and carefully examining their studies and achievements in this area has led to various detailed studies in Iran, which have confirmed the presence of oil, both onshore and offshore, in the Permo-Triassic horizon. Paleohighs play a crucial role in hydrocarbon systems. These ancient structural highs can control where oil is generated, how it migrates, and where it gets trapped and preserved. Therefore, understanding the trend of paleohighs and the timing of their formation (especially the Qatar-Fars Arch in Iran) in relation to the migration and trapping of oil, has led to the discovery of various oil fields in the Permo-Triassic horizon in Iran. A change in approach and a more complete understanding of previously discovered Permo-Triassic gas reservoirs has also led to a new assessment of the potential for oil rims in previous assumed gas fields. This shift in perspective, from considering deep reservoirs as solely gas-bearing to the possibility of oil presence, has ultimately directed to the discovery of oil horizons in proven gas reservoirs.
Integrated geological studies, combining data from geology, geophysics, geochemistry, and petrophysics have indeed revolutionized oil exploration in challenging deep reservoirs (Permo-Triassic horizon). This multidisciplinary approach helps reduce uncertainties and better characterize reservoirs. For countries like Iran, this opens up new prospects, potentially boosting energy supply and economic benefits. It also encourages future exploration to be more data-driven and precise, improving success rates and resource management.
The Kuqa Foreland Basin accounts for over 70% of the total proven natural gas reserves in the Tarim Oilfield. Due to complex reservoir conditions, primarily characterized by large thickness and well-developed natural fractures, hydraulic fracturing for production enhancement faces multiple challenges. First, matrix-type tight sandstone reservoirs typically aim to create long fractures, while the stimulation strategies for fractured tight sandstone reservoirs are still in the exploratory phase. Secondly, the large thickness and high closure stress make it difficult to achieve long-distance proppant transport and efficient placement across the entire fracture domain. Thirdly, high formation pressure and gel back-production increase the risk of proppant flowback, making it challenging to maintain proppant pack stability.
Extensive G-function pressure decline analysis of wells in the block indicates that the low-permeability matrix and natural fractures form an equivalent high-permeability composite system, requiring high main fracture conductivity. Therefore, for fractured tight sandstone, it is crucial to increase the fracture length to maximize connectivity with natural fractures and optimize proppant placement to enhance fracture conductivity. To achieve this stimulation objective, a fiber-assisted proppant high-efficient placement technology was developed and successfully applied in Well A with a depth of over 7000 m. Building on the stimulation parameters of adjacent wells in the same block (with fluid intensity of 12.5 m³/m, proppant intensity of 0.58 m³/m), the introduction of fiber and structural stabilizers (with fiber concentration of 0.4%, structural stabilizer concentration of 0.2%) was implemented to increase the proppant-supporting area and improve the conductivity of the whole fracture domain post-hydraulic fracturing.
Compared with conventional fracturing wells, Well A showed significantly improved hydraulic fracture conductivity and effective mitigation of proppant flowback after implementing proppant high-efficiency placement technology. Based on post-fracturing flowback data and proppant flowback statistics, the concepts of flowback intensity and flowback proppant production index were introduced. Flowback intensity represents the daily flowback volume per meter during the flowback phase, indicating the hydraulic fracture conductivity. The flowback proppant production index is defined as the ratio of cumulative proppant flowback to flowback intensity, reflecting the severity of proppant flowback. Compared to adjacent wells, Well A exhibited a 1.5-fold increase in flowback intensity and a 70% reduction in the flowback proppant production index after using fiber-assisted proppant transport. These results demonstrate that the proppant efficient placement technology is successful in ultra-deep fractured tight sandstone reservoirs.
Under the same proppant volume, the proppant high-efficiency placement technology can effectively enhance post-fracturing production, indicating that this technology can also reduce the required proppant volume while meeting single-well production targets. This technology provides a viable solution for the economic and efficient development of ultra-deep and naturally fractured reservoirs.
Co-author/s: Yuxuan Liu, Associate Professor, Southwest Petroleum University.
Extensive G-function pressure decline analysis of wells in the block indicates that the low-permeability matrix and natural fractures form an equivalent high-permeability composite system, requiring high main fracture conductivity. Therefore, for fractured tight sandstone, it is crucial to increase the fracture length to maximize connectivity with natural fractures and optimize proppant placement to enhance fracture conductivity. To achieve this stimulation objective, a fiber-assisted proppant high-efficient placement technology was developed and successfully applied in Well A with a depth of over 7000 m. Building on the stimulation parameters of adjacent wells in the same block (with fluid intensity of 12.5 m³/m, proppant intensity of 0.58 m³/m), the introduction of fiber and structural stabilizers (with fiber concentration of 0.4%, structural stabilizer concentration of 0.2%) was implemented to increase the proppant-supporting area and improve the conductivity of the whole fracture domain post-hydraulic fracturing.
Compared with conventional fracturing wells, Well A showed significantly improved hydraulic fracture conductivity and effective mitigation of proppant flowback after implementing proppant high-efficiency placement technology. Based on post-fracturing flowback data and proppant flowback statistics, the concepts of flowback intensity and flowback proppant production index were introduced. Flowback intensity represents the daily flowback volume per meter during the flowback phase, indicating the hydraulic fracture conductivity. The flowback proppant production index is defined as the ratio of cumulative proppant flowback to flowback intensity, reflecting the severity of proppant flowback. Compared to adjacent wells, Well A exhibited a 1.5-fold increase in flowback intensity and a 70% reduction in the flowback proppant production index after using fiber-assisted proppant transport. These results demonstrate that the proppant efficient placement technology is successful in ultra-deep fractured tight sandstone reservoirs.
Under the same proppant volume, the proppant high-efficiency placement technology can effectively enhance post-fracturing production, indicating that this technology can also reduce the required proppant volume while meeting single-well production targets. This technology provides a viable solution for the economic and efficient development of ultra-deep and naturally fractured reservoirs.
Co-author/s: Yuxuan Liu, Associate Professor, Southwest Petroleum University.
Objective/Scope:
Permeability is an important parameter for production prediction of a source rock reservoir as permeability decreases with production (i.e. the increase of effective stress) and it is indispensable to extract a reliable poroelastic coefficient of the formation in order to accurately characterize the permeability-effective stress relationship. This work outlines a new workflow to extract the poroelastic coefficient of a source rock reservoir using a set of permeability measurements.
Methods, Procedures, Process:
Several series permeability measurements of a source rock sample are carefully designed with increasing effective stress given a predetermined, estimated range of poroelastic coefficients, each series are with a constant differential pressure between the confining pressure and pore pressure, and all measurements are carried with pore pressure higher than the supercritical pressure of the measuring gas to minimize the effect of Knudsen diffusion and gas slippage. Each series of data are analyzed separately and results of subsets of the series of data are combined.
Results, Observations, Conclusions:
The data of each series of permeability measurements have a small range of effective stress thus have a uniform poroelastic coefficient and the changes of poroelastic coefficient within a large range of effective stress can be evaluated using several series of permeability measurements. Previous hypothesis postulated that the poroelastic coefficient may change with effective stress as the pore types are progressively affected, more microfractures and slit-shaped pores play a dominant role at low effective stress and round- or equant-dimensional pores play a dominant role at high effective stress. The results are compliant with this hypothesis that poroelastic coefficient starts from 1 when the microfractures and slit-shaped pores in source rock samples are dominant and decreases as more effective stress is applied.
Novel/Additive Information:
This study develops a practical method to extract the poroelastic coefficient for permeability of source rock samples within a large effective stress range.
Permeability is an important parameter for production prediction of a source rock reservoir as permeability decreases with production (i.e. the increase of effective stress) and it is indispensable to extract a reliable poroelastic coefficient of the formation in order to accurately characterize the permeability-effective stress relationship. This work outlines a new workflow to extract the poroelastic coefficient of a source rock reservoir using a set of permeability measurements.
Methods, Procedures, Process:
Several series permeability measurements of a source rock sample are carefully designed with increasing effective stress given a predetermined, estimated range of poroelastic coefficients, each series are with a constant differential pressure between the confining pressure and pore pressure, and all measurements are carried with pore pressure higher than the supercritical pressure of the measuring gas to minimize the effect of Knudsen diffusion and gas slippage. Each series of data are analyzed separately and results of subsets of the series of data are combined.
Results, Observations, Conclusions:
The data of each series of permeability measurements have a small range of effective stress thus have a uniform poroelastic coefficient and the changes of poroelastic coefficient within a large range of effective stress can be evaluated using several series of permeability measurements. Previous hypothesis postulated that the poroelastic coefficient may change with effective stress as the pore types are progressively affected, more microfractures and slit-shaped pores play a dominant role at low effective stress and round- or equant-dimensional pores play a dominant role at high effective stress. The results are compliant with this hypothesis that poroelastic coefficient starts from 1 when the microfractures and slit-shaped pores in source rock samples are dominant and decreases as more effective stress is applied.
Novel/Additive Information:
This study develops a practical method to extract the poroelastic coefficient for permeability of source rock samples within a large effective stress range.
Nanomaterials offer promising solutions for many challenges encountered throughout the oil-and-gas value chain, from exploration to production. Nevertheless, their performance can be compromised by the extreme temperatures and salinity conditions typical of subsurface reservoirs. This study reports a novel route to synthesize stable nanomaterials at a scale utilizing In-Kingdom chemicals, which is a significant breakthrough in the development of locally sourced materials for Enhanced Oil Recovery (EOR) applications. Furthermore, we compared the stability and efficacy of locally produced Nanosurfactants (NS) with imported commercial ones for EOR applications, aiming to reduce reliance on outsourced materials and improve economics.
Our results indicate that locally sourced surfactants showed comparable results to the commercial imported Petronate-HL/L in terms of density, stability, and interfacial tension reduction. Notably, the local NS formulations achieved reductions of 96.67% and 99.86% in interfacial tension, similar to Petronate-HL/L's 99.73% reduction. The local NS also demonstrated excellent stability under high temperatures and salinity environment. Moreover, spontaneous imbibition experiments also demonstrate that both formulations are effective in enhancing the recovery of oil, further proving the possibility to utilize In-Kingdom synthesized nanomaterials for EOR applications. These findings suggest that the locally produced NS can be a viable alternative to imported materials, which can help reduce costs and improve the economic viability of EOR projects.
Novel/Additive Information:
This study demonstrates the feasibility of using Saudi-produced nanomaterials NS to replace imported ones for EOR treatments, aligning with Saudi Vision 2030's goal of reducing reliance on imported materials. The successful development and testing of locally sourced nanomaterials can have a significant impact on the oil and gas industry, enabling the country to become self-sufficient in oil and gas technologies.
Co-author/s: Abdullah Boqmi, Lead Lab Technician, Saudi Aramco I Amr Abdel-Fattah, Petroleum Engineering Consultant, Saudi Aramco I Ahmed Alsmaeil, Senior Petroleum Engineer Gas and Unconventional Focus Area Champion, Saudi Aramco.
Our results indicate that locally sourced surfactants showed comparable results to the commercial imported Petronate-HL/L in terms of density, stability, and interfacial tension reduction. Notably, the local NS formulations achieved reductions of 96.67% and 99.86% in interfacial tension, similar to Petronate-HL/L's 99.73% reduction. The local NS also demonstrated excellent stability under high temperatures and salinity environment. Moreover, spontaneous imbibition experiments also demonstrate that both formulations are effective in enhancing the recovery of oil, further proving the possibility to utilize In-Kingdom synthesized nanomaterials for EOR applications. These findings suggest that the locally produced NS can be a viable alternative to imported materials, which can help reduce costs and improve the economic viability of EOR projects.
Novel/Additive Information:
This study demonstrates the feasibility of using Saudi-produced nanomaterials NS to replace imported ones for EOR treatments, aligning with Saudi Vision 2030's goal of reducing reliance on imported materials. The successful development and testing of locally sourced nanomaterials can have a significant impact on the oil and gas industry, enabling the country to become self-sufficient in oil and gas technologies.
Co-author/s: Abdullah Boqmi, Lead Lab Technician, Saudi Aramco I Amr Abdel-Fattah, Petroleum Engineering Consultant, Saudi Aramco I Ahmed Alsmaeil, Senior Petroleum Engineer Gas and Unconventional Focus Area Champion, Saudi Aramco.
Based on the results of 2D visualization oil displacement experiment, this study uses a gray image recognition algorithm, which relates the recognized gray data with the oil saturation, and then quantifies the oil saturation in each area of the 2D visualization experiment. The EOR effects of different composite modes in different stages in different regions during multi-component composite steam flooding are analyzed. The microscopic displacement characteristics during the experiment were photographed by macro lens.It is found that in the process of pure steam flooding, the phenomenon of steam channeling is obvious, and the injected steam mainly flows along the dominant channel between injection and production wells, and the sweep efficiency is only 52.4%. After combining foam and viscosity reducer successively, the overall sweeping efficiency has been greatly improved, and the final sweeping efficiency has reached 97.97%. The picture taken by the macro lens shows that the foam formed by the foaming agent and the non-condensate gas and the emulsified oil droplets formed by the viscosity reducer and crude oil block the mainstream channel to a certain extent through the Jamin effect, causing the subsequent injection fluid to divert, which is the main reason for the improvement of sweeping efficiency. The acquired images are partitioned and combined with image recognition algorithm, then the oil saturation of each area is identified, and the recovery effect of multi-component composite steam flooding process is evaluated by the evaluation parameters of enhanced oil recovery factor. In the process of pure steam flooding, the main displacement is concentrated in the near-well zone and main flow channel, and the final recovery rate is only 28.01%. In the process of succession foam composite steam flooding, the displacement area extends to the middle of the swept zone and the side channels, and the recovery factor is increased by 36% on the basis of steam flooding. Finally, the viscosity reducer composite steam flooding further extends the displacement area to the front of displacement zone and corner zones, and increases the oil recovery by 10.71% on the basis of foam composite steam flooding. Multi-component composite steam flooding was used to achieve the multiple compounding of steam-gas agent, and the final recovery factor reached 74.72%, which was 46.71% higher than that of pure steam flooding.This study introduced an image recognition algorithm that offering a more accurate, intuitive, and efficient alternative to traditional physical analysis methods. The experimental results reveal the EOR mechanism of multi-component composite steam flooding, and this information is helpful to understand the oil displacement mechanism deeply. By overcoming the limitations of traditional steam flooding methods, this method provides a valuable reference for optimizing the steam flooding process and promoting future research in the field of heavy oil recovery.
In SINOPEC operating plays, tight sandstone and shale reservoir are important successors for traditional hydrocarbon reservoir. These two types of unconventional reservoirs are characterized by large area, continuous distribution, Low resource endowment. Regardless the huge potential, a variety of challenges needs to be carefully reviewed during E&P strategic planning. For tight sandstone reservoir, it is apparently hard to predict sweetspot due to its inhomogenious nature which could impact its potential exploitation; the unique characteristics of shale gas make the high-precision geophysics-engineering sweetspot prediction especially important; at the same time, the natural production capacity of these two types of reservoirs is low, as a result, engineering modification is indispensable making the accuracy of microseismic-based modification monitoring needs further improvement in order to reduce costs and increase efficiency.
To address the exploration and development problems of tight sandstone reservoirs, innovative technologies such as reservoir parameter simulation based on multi-information fusion and prestack attenuation analysis were adopted to improve the prediction accuracy of gas-enriched reservoirs, and the coincidence rate was increased by 15%, resulting in an increase of over 20% of proved reserves.
In shale gas exploration, we have innovatively formed the geophysical sweetspot prediction technology series including simultaneous porosity-TOC inversion, multi-information fusion gas content identification and broadband impedance based high-quality shale thickness prediction; and the engineering sweetspot prediction technology series including prestack azimuthal anisotropy inversion, pressure prediction based on CPS model and RT method, and the coefficient of stress difference prediction. Innovative and optimized shale gas geophysics-engineering sweetspot prediction technologies increased the shale gas reservoir prediction coincidence rate by 10%.
For engineering modification monitoring, microseismic monitoring related technologies were studied. We formed a new acquisition method based on hybrid observation system for fracturing microseismic signals in deep and complex media and a weak signal enhancement processing method, realized effective monitoring of microseismic signals at depths of over 4,000 meters, and increased microseismic event detection capability by 20%. We constructed an intelligent processing flow of fracturing realizing unsupervised automatic monitoring and effectively enhanced the efficiency and automation of monitoring. The developed multidimensional and multidisciplinary integrated interpretation technology of fracturing provides a basis for estimating effectiveness of fracturing and fracturing schemes optimization.
The innovative technology and geophysics-engineering integration strategy is of great significance to improve the accuracy of tight sandstone and shale gas reservoir description and benefits the engineering modification. This abstract will share the practices of above effective and advanced mentioned technologies through the latest E&P application cases of tight sandstone and shale gas reservoir in typical basins in western China.
To address the exploration and development problems of tight sandstone reservoirs, innovative technologies such as reservoir parameter simulation based on multi-information fusion and prestack attenuation analysis were adopted to improve the prediction accuracy of gas-enriched reservoirs, and the coincidence rate was increased by 15%, resulting in an increase of over 20% of proved reserves.
In shale gas exploration, we have innovatively formed the geophysical sweetspot prediction technology series including simultaneous porosity-TOC inversion, multi-information fusion gas content identification and broadband impedance based high-quality shale thickness prediction; and the engineering sweetspot prediction technology series including prestack azimuthal anisotropy inversion, pressure prediction based on CPS model and RT method, and the coefficient of stress difference prediction. Innovative and optimized shale gas geophysics-engineering sweetspot prediction technologies increased the shale gas reservoir prediction coincidence rate by 10%.
For engineering modification monitoring, microseismic monitoring related technologies were studied. We formed a new acquisition method based on hybrid observation system for fracturing microseismic signals in deep and complex media and a weak signal enhancement processing method, realized effective monitoring of microseismic signals at depths of over 4,000 meters, and increased microseismic event detection capability by 20%. We constructed an intelligent processing flow of fracturing realizing unsupervised automatic monitoring and effectively enhanced the efficiency and automation of monitoring. The developed multidimensional and multidisciplinary integrated interpretation technology of fracturing provides a basis for estimating effectiveness of fracturing and fracturing schemes optimization.
The innovative technology and geophysics-engineering integration strategy is of great significance to improve the accuracy of tight sandstone and shale gas reservoir description and benefits the engineering modification. This abstract will share the practices of above effective and advanced mentioned technologies through the latest E&P application cases of tight sandstone and shale gas reservoir in typical basins in western China.
Johannes Alvarez
Chair
Enhanced Oil Recovery Manager Shale & Tight Business
Chevron Upstream
United States of America
Objective/Scope:
Permeability is an important parameter for production prediction of a source rock reservoir as permeability decreases with production (i.e. the increase of effective stress) and it is indispensable to extract a reliable poroelastic coefficient of the formation in order to accurately characterize the permeability-effective stress relationship. This work outlines a new workflow to extract the poroelastic coefficient of a source rock reservoir using a set of permeability measurements.
Methods, Procedures, Process:
Several series permeability measurements of a source rock sample are carefully designed with increasing effective stress given a predetermined, estimated range of poroelastic coefficients, each series are with a constant differential pressure between the confining pressure and pore pressure, and all measurements are carried with pore pressure higher than the supercritical pressure of the measuring gas to minimize the effect of Knudsen diffusion and gas slippage. Each series of data are analyzed separately and results of subsets of the series of data are combined.
Results, Observations, Conclusions:
The data of each series of permeability measurements have a small range of effective stress thus have a uniform poroelastic coefficient and the changes of poroelastic coefficient within a large range of effective stress can be evaluated using several series of permeability measurements. Previous hypothesis postulated that the poroelastic coefficient may change with effective stress as the pore types are progressively affected, more microfractures and slit-shaped pores play a dominant role at low effective stress and round- or equant-dimensional pores play a dominant role at high effective stress. The results are compliant with this hypothesis that poroelastic coefficient starts from 1 when the microfractures and slit-shaped pores in source rock samples are dominant and decreases as more effective stress is applied.
Novel/Additive Information:
This study develops a practical method to extract the poroelastic coefficient for permeability of source rock samples within a large effective stress range.
Permeability is an important parameter for production prediction of a source rock reservoir as permeability decreases with production (i.e. the increase of effective stress) and it is indispensable to extract a reliable poroelastic coefficient of the formation in order to accurately characterize the permeability-effective stress relationship. This work outlines a new workflow to extract the poroelastic coefficient of a source rock reservoir using a set of permeability measurements.
Methods, Procedures, Process:
Several series permeability measurements of a source rock sample are carefully designed with increasing effective stress given a predetermined, estimated range of poroelastic coefficients, each series are with a constant differential pressure between the confining pressure and pore pressure, and all measurements are carried with pore pressure higher than the supercritical pressure of the measuring gas to minimize the effect of Knudsen diffusion and gas slippage. Each series of data are analyzed separately and results of subsets of the series of data are combined.
Results, Observations, Conclusions:
The data of each series of permeability measurements have a small range of effective stress thus have a uniform poroelastic coefficient and the changes of poroelastic coefficient within a large range of effective stress can be evaluated using several series of permeability measurements. Previous hypothesis postulated that the poroelastic coefficient may change with effective stress as the pore types are progressively affected, more microfractures and slit-shaped pores play a dominant role at low effective stress and round- or equant-dimensional pores play a dominant role at high effective stress. The results are compliant with this hypothesis that poroelastic coefficient starts from 1 when the microfractures and slit-shaped pores in source rock samples are dominant and decreases as more effective stress is applied.
Novel/Additive Information:
This study develops a practical method to extract the poroelastic coefficient for permeability of source rock samples within a large effective stress range.
Nanomaterials offer promising solutions for many challenges encountered throughout the oil-and-gas value chain, from exploration to production. Nevertheless, their performance can be compromised by the extreme temperatures and salinity conditions typical of subsurface reservoirs. This study reports a novel route to synthesize stable nanomaterials at a scale utilizing In-Kingdom chemicals, which is a significant breakthrough in the development of locally sourced materials for Enhanced Oil Recovery (EOR) applications. Furthermore, we compared the stability and efficacy of locally produced Nanosurfactants (NS) with imported commercial ones for EOR applications, aiming to reduce reliance on outsourced materials and improve economics.
Our results indicate that locally sourced surfactants showed comparable results to the commercial imported Petronate-HL/L in terms of density, stability, and interfacial tension reduction. Notably, the local NS formulations achieved reductions of 96.67% and 99.86% in interfacial tension, similar to Petronate-HL/L's 99.73% reduction. The local NS also demonstrated excellent stability under high temperatures and salinity environment. Moreover, spontaneous imbibition experiments also demonstrate that both formulations are effective in enhancing the recovery of oil, further proving the possibility to utilize In-Kingdom synthesized nanomaterials for EOR applications. These findings suggest that the locally produced NS can be a viable alternative to imported materials, which can help reduce costs and improve the economic viability of EOR projects.
Novel/Additive Information:
This study demonstrates the feasibility of using Saudi-produced nanomaterials NS to replace imported ones for EOR treatments, aligning with Saudi Vision 2030's goal of reducing reliance on imported materials. The successful development and testing of locally sourced nanomaterials can have a significant impact on the oil and gas industry, enabling the country to become self-sufficient in oil and gas technologies.
Co-author/s: Abdullah Boqmi, Lead Lab Technician, Saudi Aramco I Amr Abdel-Fattah, Petroleum Engineering Consultant, Saudi Aramco I Ahmed Alsmaeil, Senior Petroleum Engineer Gas and Unconventional Focus Area Champion, Saudi Aramco.
Our results indicate that locally sourced surfactants showed comparable results to the commercial imported Petronate-HL/L in terms of density, stability, and interfacial tension reduction. Notably, the local NS formulations achieved reductions of 96.67% and 99.86% in interfacial tension, similar to Petronate-HL/L's 99.73% reduction. The local NS also demonstrated excellent stability under high temperatures and salinity environment. Moreover, spontaneous imbibition experiments also demonstrate that both formulations are effective in enhancing the recovery of oil, further proving the possibility to utilize In-Kingdom synthesized nanomaterials for EOR applications. These findings suggest that the locally produced NS can be a viable alternative to imported materials, which can help reduce costs and improve the economic viability of EOR projects.
Novel/Additive Information:
This study demonstrates the feasibility of using Saudi-produced nanomaterials NS to replace imported ones for EOR treatments, aligning with Saudi Vision 2030's goal of reducing reliance on imported materials. The successful development and testing of locally sourced nanomaterials can have a significant impact on the oil and gas industry, enabling the country to become self-sufficient in oil and gas technologies.
Co-author/s: Abdullah Boqmi, Lead Lab Technician, Saudi Aramco I Amr Abdel-Fattah, Petroleum Engineering Consultant, Saudi Aramco I Ahmed Alsmaeil, Senior Petroleum Engineer Gas and Unconventional Focus Area Champion, Saudi Aramco.
Ran Bi
Speaker
Senior Reservoir Engineer
Research Institute of Petroleum Exploration and Development, PetroChina
China
The growing demand for natural gas in China has driven a shift in supply over the past decade — from predominantly conventional sources to an increasing share of unconventional reservoirs. Commercial-scale Coalbed Methane (CBM) production was primarily extracted from Qinshui basin, targeting the shallow CBM deposits with very low single-well gas rates. By 2019, the exploration and development of deep CBM (depth greater than 1500m) in the Ordos Basin has been deciphered with the cost-effective scheme. Investments and activities have surged into the area to exploit the CBM resources and turned the production online. This comprehensive study examines the geological, engineering and management variations influencing the outcome by comparing key performance metrics from Ordos, San-Juan Basin and Queensland.
In this study, we first evaluate the formation characteristics that influence production performance, including reservoir pressure, in-situ stress, gas content, adsorption-desorption behavior, and brittleness. As coal seams extend to greater depths, the controlling factors become increasingly complex, exerting significant influence on properties that are closely linked to gas productivity. For example, coal seams located within zones of restricted water retention may exhibit higher gas saturation, while the orientation and density of butt and face cleats can impact permeability and fracability. In addition to geological variability, engineering designs and management strategies are also examined to address the unique challenges of deep CBM development. This paper provides a detailed comparison of key performance metrics across major CBM basins worldwide.
Overall, the study indicates that mid-to-high-rank coals in the Ordos Basin generally exhibit lower permeability but possess higher or comparable gas content relative to those in the San Juan and Queensland. Well completion practices also vary across these basins. In the Ordos Basin, the majority of wells are hydraulically fractured horizontal wells, whereas in the San Juan basin and Queensland, open-hole cavity vertical wells or directional wells targeting thicker coal seams are commonly employed. This comparative analysis highlights three key findings: 1) Production profiles differ between the Ordos Basin and the other two basins, with water production declining rapidly after gas production reaches a plateau. 2) Higher initial gas rates are largely driven by elevated free gas content (exceeding 20%). 3) Implementation of a controlled drawdown strategy can improve well EUR by 10–20%.
In this study, we first evaluate the formation characteristics that influence production performance, including reservoir pressure, in-situ stress, gas content, adsorption-desorption behavior, and brittleness. As coal seams extend to greater depths, the controlling factors become increasingly complex, exerting significant influence on properties that are closely linked to gas productivity. For example, coal seams located within zones of restricted water retention may exhibit higher gas saturation, while the orientation and density of butt and face cleats can impact permeability and fracability. In addition to geological variability, engineering designs and management strategies are also examined to address the unique challenges of deep CBM development. This paper provides a detailed comparison of key performance metrics across major CBM basins worldwide.
Overall, the study indicates that mid-to-high-rank coals in the Ordos Basin generally exhibit lower permeability but possess higher or comparable gas content relative to those in the San Juan and Queensland. Well completion practices also vary across these basins. In the Ordos Basin, the majority of wells are hydraulically fractured horizontal wells, whereas in the San Juan basin and Queensland, open-hole cavity vertical wells or directional wells targeting thicker coal seams are commonly employed. This comparative analysis highlights three key findings: 1) Production profiles differ between the Ordos Basin and the other two basins, with water production declining rapidly after gas production reaches a plateau. 2) Higher initial gas rates are largely driven by elevated free gas content (exceeding 20%). 3) Implementation of a controlled drawdown strategy can improve well EUR by 10–20%.
Payam Hassanzadeh
Speaker
Senior Geochemistry Specialist, Project Manager
National Iranian Oil Company-Exploration Directorate
Iran
While natural gas is increasingly important, especially for electricity generation and as a cleaner alternative to coal and oil, oil has historically been the backbone of energy supply and economic revenue for many Middle Eastern countries. The higher profitability and global demand for oil have often driven more investment into oil exploration and production. Since the early 1970s, the discovery of the massive South Pars/North Dome gas resources in Permo-Triassic reservoirs has opened a new horizon in this area for various Middle Eastern countries. In deep reservoirs (Permo-Triassic and deeper) in the Middle East, the expectation is generally for the discovery of gas, and many fields are already in production.
Exploring for oil in such challenging reservoirs demands advanced approaches. The combination of reservoir depth and extreme temperature and pressure makes conventional exploration and production techniques less effective or riskier. Therefore detailed geological, geophysical, and geochemical studies are crucial to better understand the subsurface conditions and to accurately identify any possible hydrocarbon presence.
Saudi Arabia, Qatar, Iran, United Arab Emirates, and Oman have achieved successes in the past two decades, and the results of these studies can illuminate the future prospects for oil discovery in these reservoirs. Drawing on the experiences of Saudi Arabia and Qatar and carefully examining their studies and achievements in this area has led to various detailed studies in Iran, which have confirmed the presence of oil, both onshore and offshore, in the Permo-Triassic horizon. Paleohighs play a crucial role in hydrocarbon systems. These ancient structural highs can control where oil is generated, how it migrates, and where it gets trapped and preserved. Therefore, understanding the trend of paleohighs and the timing of their formation (especially the Qatar-Fars Arch in Iran) in relation to the migration and trapping of oil, has led to the discovery of various oil fields in the Permo-Triassic horizon in Iran. A change in approach and a more complete understanding of previously discovered Permo-Triassic gas reservoirs has also led to a new assessment of the potential for oil rims in previous assumed gas fields. This shift in perspective, from considering deep reservoirs as solely gas-bearing to the possibility of oil presence, has ultimately directed to the discovery of oil horizons in proven gas reservoirs.
Integrated geological studies, combining data from geology, geophysics, geochemistry, and petrophysics have indeed revolutionized oil exploration in challenging deep reservoirs (Permo-Triassic horizon). This multidisciplinary approach helps reduce uncertainties and better characterize reservoirs. For countries like Iran, this opens up new prospects, potentially boosting energy supply and economic benefits. It also encourages future exploration to be more data-driven and precise, improving success rates and resource management.
Exploring for oil in such challenging reservoirs demands advanced approaches. The combination of reservoir depth and extreme temperature and pressure makes conventional exploration and production techniques less effective or riskier. Therefore detailed geological, geophysical, and geochemical studies are crucial to better understand the subsurface conditions and to accurately identify any possible hydrocarbon presence.
Saudi Arabia, Qatar, Iran, United Arab Emirates, and Oman have achieved successes in the past two decades, and the results of these studies can illuminate the future prospects for oil discovery in these reservoirs. Drawing on the experiences of Saudi Arabia and Qatar and carefully examining their studies and achievements in this area has led to various detailed studies in Iran, which have confirmed the presence of oil, both onshore and offshore, in the Permo-Triassic horizon. Paleohighs play a crucial role in hydrocarbon systems. These ancient structural highs can control where oil is generated, how it migrates, and where it gets trapped and preserved. Therefore, understanding the trend of paleohighs and the timing of their formation (especially the Qatar-Fars Arch in Iran) in relation to the migration and trapping of oil, has led to the discovery of various oil fields in the Permo-Triassic horizon in Iran. A change in approach and a more complete understanding of previously discovered Permo-Triassic gas reservoirs has also led to a new assessment of the potential for oil rims in previous assumed gas fields. This shift in perspective, from considering deep reservoirs as solely gas-bearing to the possibility of oil presence, has ultimately directed to the discovery of oil horizons in proven gas reservoirs.
Integrated geological studies, combining data from geology, geophysics, geochemistry, and petrophysics have indeed revolutionized oil exploration in challenging deep reservoirs (Permo-Triassic horizon). This multidisciplinary approach helps reduce uncertainties and better characterize reservoirs. For countries like Iran, this opens up new prospects, potentially boosting energy supply and economic benefits. It also encourages future exploration to be more data-driven and precise, improving success rates and resource management.
The growing demand for natural gas in China has driven a shift in supply over the past decade — from predominantly conventional sources to an increasing share of unconventional reservoirs. Commercial-scale Coalbed Methane (CBM) production was primarily extracted from Qinshui basin, targeting the shallow CBM deposits with very low single-well gas rates. By 2019, the exploration and development of deep CBM (depth greater than 1500m) in the Ordos Basin has been deciphered with the cost-effective scheme. Investments and activities have surged into the area to exploit the CBM resources and turned the production online. This comprehensive study examines the geological, engineering and management variations influencing the outcome by comparing key performance metrics from Ordos, San-Juan Basin and Queensland.
In this study, we first evaluate the formation characteristics that influence production performance, including reservoir pressure, in-situ stress, gas content, adsorption-desorption behavior, and brittleness. As coal seams extend to greater depths, the controlling factors become increasingly complex, exerting significant influence on properties that are closely linked to gas productivity. For example, coal seams located within zones of restricted water retention may exhibit higher gas saturation, while the orientation and density of butt and face cleats can impact permeability and fracability. In addition to geological variability, engineering designs and management strategies are also examined to address the unique challenges of deep CBM development. This paper provides a detailed comparison of key performance metrics across major CBM basins worldwide.
Overall, the study indicates that mid-to-high-rank coals in the Ordos Basin generally exhibit lower permeability but possess higher or comparable gas content relative to those in the San Juan and Queensland. Well completion practices also vary across these basins. In the Ordos Basin, the majority of wells are hydraulically fractured horizontal wells, whereas in the San Juan basin and Queensland, open-hole cavity vertical wells or directional wells targeting thicker coal seams are commonly employed. This comparative analysis highlights three key findings: 1) Production profiles differ between the Ordos Basin and the other two basins, with water production declining rapidly after gas production reaches a plateau. 2) Higher initial gas rates are largely driven by elevated free gas content (exceeding 20%). 3) Implementation of a controlled drawdown strategy can improve well EUR by 10–20%.
In this study, we first evaluate the formation characteristics that influence production performance, including reservoir pressure, in-situ stress, gas content, adsorption-desorption behavior, and brittleness. As coal seams extend to greater depths, the controlling factors become increasingly complex, exerting significant influence on properties that are closely linked to gas productivity. For example, coal seams located within zones of restricted water retention may exhibit higher gas saturation, while the orientation and density of butt and face cleats can impact permeability and fracability. In addition to geological variability, engineering designs and management strategies are also examined to address the unique challenges of deep CBM development. This paper provides a detailed comparison of key performance metrics across major CBM basins worldwide.
Overall, the study indicates that mid-to-high-rank coals in the Ordos Basin generally exhibit lower permeability but possess higher or comparable gas content relative to those in the San Juan and Queensland. Well completion practices also vary across these basins. In the Ordos Basin, the majority of wells are hydraulically fractured horizontal wells, whereas in the San Juan basin and Queensland, open-hole cavity vertical wells or directional wells targeting thicker coal seams are commonly employed. This comparative analysis highlights three key findings: 1) Production profiles differ between the Ordos Basin and the other two basins, with water production declining rapidly after gas production reaches a plateau. 2) Higher initial gas rates are largely driven by elevated free gas content (exceeding 20%). 3) Implementation of a controlled drawdown strategy can improve well EUR by 10–20%.
Qingjing Hong
Speaker
Doctoral Student
State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum
China
Based on the results of 2D visualization oil displacement experiment, this study uses a gray image recognition algorithm, which relates the recognized gray data with the oil saturation, and then quantifies the oil saturation in each area of the 2D visualization experiment. The EOR effects of different composite modes in different stages in different regions during multi-component composite steam flooding are analyzed. The microscopic displacement characteristics during the experiment were photographed by macro lens.It is found that in the process of pure steam flooding, the phenomenon of steam channeling is obvious, and the injected steam mainly flows along the dominant channel between injection and production wells, and the sweep efficiency is only 52.4%. After combining foam and viscosity reducer successively, the overall sweeping efficiency has been greatly improved, and the final sweeping efficiency has reached 97.97%. The picture taken by the macro lens shows that the foam formed by the foaming agent and the non-condensate gas and the emulsified oil droplets formed by the viscosity reducer and crude oil block the mainstream channel to a certain extent through the Jamin effect, causing the subsequent injection fluid to divert, which is the main reason for the improvement of sweeping efficiency. The acquired images are partitioned and combined with image recognition algorithm, then the oil saturation of each area is identified, and the recovery effect of multi-component composite steam flooding process is evaluated by the evaluation parameters of enhanced oil recovery factor. In the process of pure steam flooding, the main displacement is concentrated in the near-well zone and main flow channel, and the final recovery rate is only 28.01%. In the process of succession foam composite steam flooding, the displacement area extends to the middle of the swept zone and the side channels, and the recovery factor is increased by 36% on the basis of steam flooding. Finally, the viscosity reducer composite steam flooding further extends the displacement area to the front of displacement zone and corner zones, and increases the oil recovery by 10.71% on the basis of foam composite steam flooding. Multi-component composite steam flooding was used to achieve the multiple compounding of steam-gas agent, and the final recovery factor reached 74.72%, which was 46.71% higher than that of pure steam flooding.This study introduced an image recognition algorithm that offering a more accurate, intuitive, and efficient alternative to traditional physical analysis methods. The experimental results reveal the EOR mechanism of multi-component composite steam flooding, and this information is helpful to understand the oil displacement mechanism deeply. By overcoming the limitations of traditional steam flooding methods, this method provides a valuable reference for optimizing the steam flooding process and promoting future research in the field of heavy oil recovery.
In SINOPEC operating plays, tight sandstone and shale reservoir are important successors for traditional hydrocarbon reservoir. These two types of unconventional reservoirs are characterized by large area, continuous distribution, Low resource endowment. Regardless the huge potential, a variety of challenges needs to be carefully reviewed during E&P strategic planning. For tight sandstone reservoir, it is apparently hard to predict sweetspot due to its inhomogenious nature which could impact its potential exploitation; the unique characteristics of shale gas make the high-precision geophysics-engineering sweetspot prediction especially important; at the same time, the natural production capacity of these two types of reservoirs is low, as a result, engineering modification is indispensable making the accuracy of microseismic-based modification monitoring needs further improvement in order to reduce costs and increase efficiency.
To address the exploration and development problems of tight sandstone reservoirs, innovative technologies such as reservoir parameter simulation based on multi-information fusion and prestack attenuation analysis were adopted to improve the prediction accuracy of gas-enriched reservoirs, and the coincidence rate was increased by 15%, resulting in an increase of over 20% of proved reserves.
In shale gas exploration, we have innovatively formed the geophysical sweetspot prediction technology series including simultaneous porosity-TOC inversion, multi-information fusion gas content identification and broadband impedance based high-quality shale thickness prediction; and the engineering sweetspot prediction technology series including prestack azimuthal anisotropy inversion, pressure prediction based on CPS model and RT method, and the coefficient of stress difference prediction. Innovative and optimized shale gas geophysics-engineering sweetspot prediction technologies increased the shale gas reservoir prediction coincidence rate by 10%.
For engineering modification monitoring, microseismic monitoring related technologies were studied. We formed a new acquisition method based on hybrid observation system for fracturing microseismic signals in deep and complex media and a weak signal enhancement processing method, realized effective monitoring of microseismic signals at depths of over 4,000 meters, and increased microseismic event detection capability by 20%. We constructed an intelligent processing flow of fracturing realizing unsupervised automatic monitoring and effectively enhanced the efficiency and automation of monitoring. The developed multidimensional and multidisciplinary integrated interpretation technology of fracturing provides a basis for estimating effectiveness of fracturing and fracturing schemes optimization.
The innovative technology and geophysics-engineering integration strategy is of great significance to improve the accuracy of tight sandstone and shale gas reservoir description and benefits the engineering modification. This abstract will share the practices of above effective and advanced mentioned technologies through the latest E&P application cases of tight sandstone and shale gas reservoir in typical basins in western China.
To address the exploration and development problems of tight sandstone reservoirs, innovative technologies such as reservoir parameter simulation based on multi-information fusion and prestack attenuation analysis were adopted to improve the prediction accuracy of gas-enriched reservoirs, and the coincidence rate was increased by 15%, resulting in an increase of over 20% of proved reserves.
In shale gas exploration, we have innovatively formed the geophysical sweetspot prediction technology series including simultaneous porosity-TOC inversion, multi-information fusion gas content identification and broadband impedance based high-quality shale thickness prediction; and the engineering sweetspot prediction technology series including prestack azimuthal anisotropy inversion, pressure prediction based on CPS model and RT method, and the coefficient of stress difference prediction. Innovative and optimized shale gas geophysics-engineering sweetspot prediction technologies increased the shale gas reservoir prediction coincidence rate by 10%.
For engineering modification monitoring, microseismic monitoring related technologies were studied. We formed a new acquisition method based on hybrid observation system for fracturing microseismic signals in deep and complex media and a weak signal enhancement processing method, realized effective monitoring of microseismic signals at depths of over 4,000 meters, and increased microseismic event detection capability by 20%. We constructed an intelligent processing flow of fracturing realizing unsupervised automatic monitoring and effectively enhanced the efficiency and automation of monitoring. The developed multidimensional and multidisciplinary integrated interpretation technology of fracturing provides a basis for estimating effectiveness of fracturing and fracturing schemes optimization.
The innovative technology and geophysics-engineering integration strategy is of great significance to improve the accuracy of tight sandstone and shale gas reservoir description and benefits the engineering modification. This abstract will share the practices of above effective and advanced mentioned technologies through the latest E&P application cases of tight sandstone and shale gas reservoir in typical basins in western China.
Yuewei Pan
Speaker
Land and Reserve Supervisor
Oil, Gas and New Energies Company, PetroChina
China
The growing demand for natural gas in China has driven a shift in supply over the past decade — from predominantly conventional sources to an increasing share of unconventional reservoirs. Commercial-scale Coalbed Methane (CBM) production was primarily extracted from Qinshui basin, targeting the shallow CBM deposits with very low single-well gas rates. By 2019, the exploration and development of deep CBM (depth greater than 1500m) in the Ordos Basin has been deciphered with the cost-effective scheme. Investments and activities have surged into the area to exploit the CBM resources and turned the production online. This comprehensive study examines the geological, engineering and management variations influencing the outcome by comparing key performance metrics from Ordos, San-Juan Basin and Queensland.
In this study, we first evaluate the formation characteristics that influence production performance, including reservoir pressure, in-situ stress, gas content, adsorption-desorption behavior, and brittleness. As coal seams extend to greater depths, the controlling factors become increasingly complex, exerting significant influence on properties that are closely linked to gas productivity. For example, coal seams located within zones of restricted water retention may exhibit higher gas saturation, while the orientation and density of butt and face cleats can impact permeability and fracability. In addition to geological variability, engineering designs and management strategies are also examined to address the unique challenges of deep CBM development. This paper provides a detailed comparison of key performance metrics across major CBM basins worldwide.
Overall, the study indicates that mid-to-high-rank coals in the Ordos Basin generally exhibit lower permeability but possess higher or comparable gas content relative to those in the San Juan and Queensland. Well completion practices also vary across these basins. In the Ordos Basin, the majority of wells are hydraulically fractured horizontal wells, whereas in the San Juan basin and Queensland, open-hole cavity vertical wells or directional wells targeting thicker coal seams are commonly employed. This comparative analysis highlights three key findings: 1) Production profiles differ between the Ordos Basin and the other two basins, with water production declining rapidly after gas production reaches a plateau. 2) Higher initial gas rates are largely driven by elevated free gas content (exceeding 20%). 3) Implementation of a controlled drawdown strategy can improve well EUR by 10–20%.
In this study, we first evaluate the formation characteristics that influence production performance, including reservoir pressure, in-situ stress, gas content, adsorption-desorption behavior, and brittleness. As coal seams extend to greater depths, the controlling factors become increasingly complex, exerting significant influence on properties that are closely linked to gas productivity. For example, coal seams located within zones of restricted water retention may exhibit higher gas saturation, while the orientation and density of butt and face cleats can impact permeability and fracability. In addition to geological variability, engineering designs and management strategies are also examined to address the unique challenges of deep CBM development. This paper provides a detailed comparison of key performance metrics across major CBM basins worldwide.
Overall, the study indicates that mid-to-high-rank coals in the Ordos Basin generally exhibit lower permeability but possess higher or comparable gas content relative to those in the San Juan and Queensland. Well completion practices also vary across these basins. In the Ordos Basin, the majority of wells are hydraulically fractured horizontal wells, whereas in the San Juan basin and Queensland, open-hole cavity vertical wells or directional wells targeting thicker coal seams are commonly employed. This comparative analysis highlights three key findings: 1) Production profiles differ between the Ordos Basin and the other two basins, with water production declining rapidly after gas production reaches a plateau. 2) Higher initial gas rates are largely driven by elevated free gas content (exceeding 20%). 3) Implementation of a controlled drawdown strategy can improve well EUR by 10–20%.
Objectives & Scope:
To reach Kuwait’s oil production target, production enhancement from tight carbonate reservoirs is essential. In this paper, it will be demonstrated how an integrated workflow that includes advanced reservoir characterization to optimize the stimulation design with enhanced zonal coverage in a heterogenous Jurassic reservoir.
Methods, Procedures & Process:
To accurately select the candidate based on precise determination of the reservoir permeability contrast across the different layers. Representative fluid samples have been captured to map the asphaltene envelope. The injection logging survey was a key input to determine the permeability profile and to evaluate the integrity of the patchy cement through temperature analysis. Pressure Transiet Analysis (PTA) were essential to evaluate the significance of the depletion across the different areas of the field as well as to determine the total skin of the reservoir. The integration of these data in a structured workflow enhanced the stimulation design.
Results, Observations & Conclusions:
Based on the significant permeability contrast, Single-Phase Retarded Acid (SPRA) and Bio-degradable Particulate Diverters (BPD) were found to be essential to unlock the tighter layers. Five wells were stimulated utilizing the above workflow resulting in 7 folds of increase in the oil production versus 4 folds of increase before implementing this workflow. Another important observation is the sustainability of these wells for over 1 year with less frequency in asphaltene clean-out treatments.
It can be observed that meticulous characterization, planning and execution for tight carbonate reservoirs is critical for a sustained production enhancement. This reservoir oil production has increased by 150% from existing wells with rigless intervention.
New Information to Existing Literature:
This paper demonstrates the economical development of deep tight carbonate reservoirs through fit-for-purpose workflows. The findings were utilized to update the full field development strategy.
To reach Kuwait’s oil production target, production enhancement from tight carbonate reservoirs is essential. In this paper, it will be demonstrated how an integrated workflow that includes advanced reservoir characterization to optimize the stimulation design with enhanced zonal coverage in a heterogenous Jurassic reservoir.
Methods, Procedures & Process:
To accurately select the candidate based on precise determination of the reservoir permeability contrast across the different layers. Representative fluid samples have been captured to map the asphaltene envelope. The injection logging survey was a key input to determine the permeability profile and to evaluate the integrity of the patchy cement through temperature analysis. Pressure Transiet Analysis (PTA) were essential to evaluate the significance of the depletion across the different areas of the field as well as to determine the total skin of the reservoir. The integration of these data in a structured workflow enhanced the stimulation design.
Results, Observations & Conclusions:
Based on the significant permeability contrast, Single-Phase Retarded Acid (SPRA) and Bio-degradable Particulate Diverters (BPD) were found to be essential to unlock the tighter layers. Five wells were stimulated utilizing the above workflow resulting in 7 folds of increase in the oil production versus 4 folds of increase before implementing this workflow. Another important observation is the sustainability of these wells for over 1 year with less frequency in asphaltene clean-out treatments.
It can be observed that meticulous characterization, planning and execution for tight carbonate reservoirs is critical for a sustained production enhancement. This reservoir oil production has increased by 150% from existing wells with rigless intervention.
New Information to Existing Literature:
This paper demonstrates the economical development of deep tight carbonate reservoirs through fit-for-purpose workflows. The findings were utilized to update the full field development strategy.
The Kuqa Foreland Basin accounts for over 70% of the total proven natural gas reserves in the Tarim Oilfield. Due to complex reservoir conditions, primarily characterized by large thickness and well-developed natural fractures, hydraulic fracturing for production enhancement faces multiple challenges. First, matrix-type tight sandstone reservoirs typically aim to create long fractures, while the stimulation strategies for fractured tight sandstone reservoirs are still in the exploratory phase. Secondly, the large thickness and high closure stress make it difficult to achieve long-distance proppant transport and efficient placement across the entire fracture domain. Thirdly, high formation pressure and gel back-production increase the risk of proppant flowback, making it challenging to maintain proppant pack stability.
Extensive G-function pressure decline analysis of wells in the block indicates that the low-permeability matrix and natural fractures form an equivalent high-permeability composite system, requiring high main fracture conductivity. Therefore, for fractured tight sandstone, it is crucial to increase the fracture length to maximize connectivity with natural fractures and optimize proppant placement to enhance fracture conductivity. To achieve this stimulation objective, a fiber-assisted proppant high-efficient placement technology was developed and successfully applied in Well A with a depth of over 7000 m. Building on the stimulation parameters of adjacent wells in the same block (with fluid intensity of 12.5 m³/m, proppant intensity of 0.58 m³/m), the introduction of fiber and structural stabilizers (with fiber concentration of 0.4%, structural stabilizer concentration of 0.2%) was implemented to increase the proppant-supporting area and improve the conductivity of the whole fracture domain post-hydraulic fracturing.
Compared with conventional fracturing wells, Well A showed significantly improved hydraulic fracture conductivity and effective mitigation of proppant flowback after implementing proppant high-efficiency placement technology. Based on post-fracturing flowback data and proppant flowback statistics, the concepts of flowback intensity and flowback proppant production index were introduced. Flowback intensity represents the daily flowback volume per meter during the flowback phase, indicating the hydraulic fracture conductivity. The flowback proppant production index is defined as the ratio of cumulative proppant flowback to flowback intensity, reflecting the severity of proppant flowback. Compared to adjacent wells, Well A exhibited a 1.5-fold increase in flowback intensity and a 70% reduction in the flowback proppant production index after using fiber-assisted proppant transport. These results demonstrate that the proppant efficient placement technology is successful in ultra-deep fractured tight sandstone reservoirs.
Under the same proppant volume, the proppant high-efficiency placement technology can effectively enhance post-fracturing production, indicating that this technology can also reduce the required proppant volume while meeting single-well production targets. This technology provides a viable solution for the economic and efficient development of ultra-deep and naturally fractured reservoirs.
Co-author/s: Yuxuan Liu, Associate Professor, Southwest Petroleum University.
Extensive G-function pressure decline analysis of wells in the block indicates that the low-permeability matrix and natural fractures form an equivalent high-permeability composite system, requiring high main fracture conductivity. Therefore, for fractured tight sandstone, it is crucial to increase the fracture length to maximize connectivity with natural fractures and optimize proppant placement to enhance fracture conductivity. To achieve this stimulation objective, a fiber-assisted proppant high-efficient placement technology was developed and successfully applied in Well A with a depth of over 7000 m. Building on the stimulation parameters of adjacent wells in the same block (with fluid intensity of 12.5 m³/m, proppant intensity of 0.58 m³/m), the introduction of fiber and structural stabilizers (with fiber concentration of 0.4%, structural stabilizer concentration of 0.2%) was implemented to increase the proppant-supporting area and improve the conductivity of the whole fracture domain post-hydraulic fracturing.
Compared with conventional fracturing wells, Well A showed significantly improved hydraulic fracture conductivity and effective mitigation of proppant flowback after implementing proppant high-efficiency placement technology. Based on post-fracturing flowback data and proppant flowback statistics, the concepts of flowback intensity and flowback proppant production index were introduced. Flowback intensity represents the daily flowback volume per meter during the flowback phase, indicating the hydraulic fracture conductivity. The flowback proppant production index is defined as the ratio of cumulative proppant flowback to flowback intensity, reflecting the severity of proppant flowback. Compared to adjacent wells, Well A exhibited a 1.5-fold increase in flowback intensity and a 70% reduction in the flowback proppant production index after using fiber-assisted proppant transport. These results demonstrate that the proppant efficient placement technology is successful in ultra-deep fractured tight sandstone reservoirs.
Under the same proppant volume, the proppant high-efficiency placement technology can effectively enhance post-fracturing production, indicating that this technology can also reduce the required proppant volume while meeting single-well production targets. This technology provides a viable solution for the economic and efficient development of ultra-deep and naturally fractured reservoirs.
Co-author/s: Yuxuan Liu, Associate Professor, Southwest Petroleum University.
