2023 Vol. 48, No. 7
Display Method:
2023, 48(7): 2427-2442.
doi: 10.3799/dqkx.2022.190
PDF 20729KB
Abstract:
Natural fracture is an important reservoir space and main seepage channel of organic rich shale oil and gas reservoir, which affects the enrichment, preservation, single well productivity and development effect of shale oil and gas. The research on the development law of natural fracture is of great significance to the exploration and development of organic rich shale oil and gas. Based on the research results of marine and continental organic rich shale fractures in recent years, this paper summarizes the latest progress in the genetic types, development characteristics, main control factors, evaluation and prediction methods of organic rich shale natural fractures, and finally discusses the key research directions of organic rich shale natural fractures in the future. The natural fractures of organic rich shale can be divided into three categories and six sub categories: tectonic fractures, diagenetic fractures and abnormally high-pressure-related fractures. The main fracture types are intraformational open fractures, transformational shear fractures, bed-parallel shear fractures and bed-parallel lamellated fractures. The development degree of shale tectonic fractures is mainly controlled by brittle mineral content, organic matter content, high brittle shale layer thickness, structure, formation dip angle and fluid pressure. The formation and development of bed-parallel lamellated fractures are mainly affected by organic matter content, lamina type, lamina number, lamina thickness and later tectonic uplift. Due to the differences in mineral composition, lithofacies changes and thermal evolution of organic matter caused by different sedimentary environments between continental shale and marine shale, the development characteristics of fractures between continental shale and marine shale are obviously different. Compared with marine shale fractures, the distribution pattern of continental shale fractures is more complex, the scale of tectonic fractures is smaller, and the development degree of cross layer shear fractures and bedding shear fractures is low. At present, the evaluation and prediction of shale fractures are mainly carried out with the help of the existing conventional research methods of tectonic fractures in low-permeability tight reservoirs. How to combine geology, geophysics and machine learning to form a classification evaluation and prediction method suitable for different scales and types of shale fractures according to the characteristics of small scale of shale fractures and development of bed-parallel lamellated fractures, It is very important to improve the evaluation and prediction accuracy of shale fractures and better guide oil and gas development. The development law of deep organic rich shale fractures, the influence of natural fractures on hydraulic fracturing fractures, and the three-dimensional geological modeling of complex fracture network system integrating multi-scale, multi occurrence and multi Genesis shale fractures will also be important problems to be solved in the research of shale fractures in the future.
Natural fracture is an important reservoir space and main seepage channel of organic rich shale oil and gas reservoir, which affects the enrichment, preservation, single well productivity and development effect of shale oil and gas. The research on the development law of natural fracture is of great significance to the exploration and development of organic rich shale oil and gas. Based on the research results of marine and continental organic rich shale fractures in recent years, this paper summarizes the latest progress in the genetic types, development characteristics, main control factors, evaluation and prediction methods of organic rich shale natural fractures, and finally discusses the key research directions of organic rich shale natural fractures in the future. The natural fractures of organic rich shale can be divided into three categories and six sub categories: tectonic fractures, diagenetic fractures and abnormally high-pressure-related fractures. The main fracture types are intraformational open fractures, transformational shear fractures, bed-parallel shear fractures and bed-parallel lamellated fractures. The development degree of shale tectonic fractures is mainly controlled by brittle mineral content, organic matter content, high brittle shale layer thickness, structure, formation dip angle and fluid pressure. The formation and development of bed-parallel lamellated fractures are mainly affected by organic matter content, lamina type, lamina number, lamina thickness and later tectonic uplift. Due to the differences in mineral composition, lithofacies changes and thermal evolution of organic matter caused by different sedimentary environments between continental shale and marine shale, the development characteristics of fractures between continental shale and marine shale are obviously different. Compared with marine shale fractures, the distribution pattern of continental shale fractures is more complex, the scale of tectonic fractures is smaller, and the development degree of cross layer shear fractures and bedding shear fractures is low. At present, the evaluation and prediction of shale fractures are mainly carried out with the help of the existing conventional research methods of tectonic fractures in low-permeability tight reservoirs. How to combine geology, geophysics and machine learning to form a classification evaluation and prediction method suitable for different scales and types of shale fractures according to the characteristics of small scale of shale fractures and development of bed-parallel lamellated fractures, It is very important to improve the evaluation and prediction accuracy of shale fractures and better guide oil and gas development. The development law of deep organic rich shale fractures, the influence of natural fractures on hydraulic fracturing fractures, and the three-dimensional geological modeling of complex fracture network system integrating multi-scale, multi occurrence and multi Genesis shale fractures will also be important problems to be solved in the research of shale fractures in the future.
2023, 48(7): 2443-2461.
doi: 10.3799/dqkx.2022.088
Abstract:
Fractures are effective reservoir spaces and important seepage channels of tight reservoirs. Fractures are very important for the exploration and development of tight reservoirs. Fracture identification of single well mainly can use image logs, array acoustic logs and conventional logs. How to accurately identify fractures is a key problem in the field of tight reservoir research. In the new era of intelligent exploration and development of oil and gas, artificial intelligence is a powerful tool to break through the limitations of existing technology and improve the accuracy of fracture identification in single well. Therefore, combined with the fracture identification cases using artificial intelligence in tight reservoirs in recent years and our research in this field, this paper introduces the application in fracture identification using the three types of logging data by unsupervised learning, supervised learning and semi-supervised learning artificial intelligence methods. So far, artificial intelligence is most widely used in fracture identification using conventional logging, followed by imaging logs, and array acoustic relatively less. As for artificial intelligence algorithms, unsupervised methods are less used because of the problem of recognition accuracy. Supervised learning methods are the mainstream at present, but it needs sufficient labeled data to establish an effective fracture prediction model. Semi-supervised learning method is a new trend in recent years, which can integrate the advantages of unsupervised and supervised learning, and make full use of small sample data of labeled logging and large sample data of unlabeled logging. Noted the operation efficiency of this kind of method needs to be improved. At present, the development trends of fracture identification methods by artificial intelligence for single well are from lower to higher nonlinear fitting ability and integrate multiple single prediction methods into an ensemble prediction method. At the same time, this paper also systematically discusses the existing problems and future development trend of artificial intelligence methods for fracture identification in tight reservoirs.
Fractures are effective reservoir spaces and important seepage channels of tight reservoirs. Fractures are very important for the exploration and development of tight reservoirs. Fracture identification of single well mainly can use image logs, array acoustic logs and conventional logs. How to accurately identify fractures is a key problem in the field of tight reservoir research. In the new era of intelligent exploration and development of oil and gas, artificial intelligence is a powerful tool to break through the limitations of existing technology and improve the accuracy of fracture identification in single well. Therefore, combined with the fracture identification cases using artificial intelligence in tight reservoirs in recent years and our research in this field, this paper introduces the application in fracture identification using the three types of logging data by unsupervised learning, supervised learning and semi-supervised learning artificial intelligence methods. So far, artificial intelligence is most widely used in fracture identification using conventional logging, followed by imaging logs, and array acoustic relatively less. As for artificial intelligence algorithms, unsupervised methods are less used because of the problem of recognition accuracy. Supervised learning methods are the mainstream at present, but it needs sufficient labeled data to establish an effective fracture prediction model. Semi-supervised learning method is a new trend in recent years, which can integrate the advantages of unsupervised and supervised learning, and make full use of small sample data of labeled logging and large sample data of unlabeled logging. Noted the operation efficiency of this kind of method needs to be improved. At present, the development trends of fracture identification methods by artificial intelligence for single well are from lower to higher nonlinear fitting ability and integrate multiple single prediction methods into an ensemble prediction method. At the same time, this paper also systematically discusses the existing problems and future development trend of artificial intelligence methods for fracture identification in tight reservoirs.
2023, 48(7): 2462-2474.
doi: 10.3799/dqkx.2022.290
Abstract:
Fractures are important seepage channels in tight carbonate reservoir which affect reservoir development. Fracture prediction is difficult due to the weak and complex geophysical response of fractures. Based on the deep mining of fracture characteristic information in seismic attributes, in this paper it establishes an artificial intelligence-based fracture distribution prediction method. This method uses the support vector machine algorithm to optimize the fracture sensitive attributes, and uses the gradient boosting decision tree (GBDT) algorithm to deeply explore the nonlinear relationship between the fracture development of a single well and the seismic attributes. Gradient boosting decision tree algorithm has strong robustness to outliers, and can better solve the problem of weak and complex fracture seismic response. This method has been applied to a tight carbonate reservoir in the Oligocene to Neogene Asmari Formation of an oilfield in Zagros Basin, Middle East. Five fracture sensitive seismic attributes including variance, curvature, dip deviation, dip angle and azimuth angle were optimized. The gradient boosting decision tree was used to integrate the fracture characteristics of different seismic attributes, and the fracture distribution prediction model was established to predict the fracture distribution of carbonate reservoir in the study area. Compared with conventional fracture prediction methods, the results of this method are more consistent with fracture interpretation of single well. The prediction results show that the fractures both in the northern part of the study area and near the structural heights are more developed, which is consistent with the understanding of production dynamics.
Fractures are important seepage channels in tight carbonate reservoir which affect reservoir development. Fracture prediction is difficult due to the weak and complex geophysical response of fractures. Based on the deep mining of fracture characteristic information in seismic attributes, in this paper it establishes an artificial intelligence-based fracture distribution prediction method. This method uses the support vector machine algorithm to optimize the fracture sensitive attributes, and uses the gradient boosting decision tree (GBDT) algorithm to deeply explore the nonlinear relationship between the fracture development of a single well and the seismic attributes. Gradient boosting decision tree algorithm has strong robustness to outliers, and can better solve the problem of weak and complex fracture seismic response. This method has been applied to a tight carbonate reservoir in the Oligocene to Neogene Asmari Formation of an oilfield in Zagros Basin, Middle East. Five fracture sensitive seismic attributes including variance, curvature, dip deviation, dip angle and azimuth angle were optimized. The gradient boosting decision tree was used to integrate the fracture characteristics of different seismic attributes, and the fracture distribution prediction model was established to predict the fracture distribution of carbonate reservoir in the study area. Compared with conventional fracture prediction methods, the results of this method are more consistent with fracture interpretation of single well. The prediction results show that the fractures both in the northern part of the study area and near the structural heights are more developed, which is consistent with the understanding of production dynamics.
2023, 48(7): 2475-2488.
doi: 10.3799/dqkx.2022.066
Abstract:
The Lower Jurassic in eastern Kuqa foreland basin is a fractured tight sandstone reservoir. The distribution of natural fractures controls hydrocarbon accumulation and single well productivity. Fracture connectivity is a key factor affecting porosity and permeability performance, productivity of tight reservoirs and cap integrity, but it lacks in systematic research on quantitative characterization methods of fracture connectivity and its influencing factors. Taking the Lower Jurassic tight sandstone reservoirs in eastern Kuqa foreland basin as an example, in this paper it analyzes the fracture development characteristics, quantitatively characterizes the fracture connectivity using a fracture node types and their proportions based method, and analyzes the controlling factors of fracture connectivity using numerical simulation. There are three types of microfractures in the study area: intragranular microfractures, grain-edge microfractures and intergranular microfractures. From west to east, fracture connectivity deteriorates gradually, which is consistent with fracture development intensity. Fracture azimuth dispersion, fracture length, fracture density and angle between fracture sets are the main factors affecting fracture connectivity. With the increase of fracture azimuth dispersion, fracture length, fracture density and angle between fracture sets, fracture connectivity becomes better.
The Lower Jurassic in eastern Kuqa foreland basin is a fractured tight sandstone reservoir. The distribution of natural fractures controls hydrocarbon accumulation and single well productivity. Fracture connectivity is a key factor affecting porosity and permeability performance, productivity of tight reservoirs and cap integrity, but it lacks in systematic research on quantitative characterization methods of fracture connectivity and its influencing factors. Taking the Lower Jurassic tight sandstone reservoirs in eastern Kuqa foreland basin as an example, in this paper it analyzes the fracture development characteristics, quantitatively characterizes the fracture connectivity using a fracture node types and their proportions based method, and analyzes the controlling factors of fracture connectivity using numerical simulation. There are three types of microfractures in the study area: intragranular microfractures, grain-edge microfractures and intergranular microfractures. From west to east, fracture connectivity deteriorates gradually, which is consistent with fracture development intensity. Fracture azimuth dispersion, fracture length, fracture density and angle between fracture sets are the main factors affecting fracture connectivity. With the increase of fracture azimuth dispersion, fracture length, fracture density and angle between fracture sets, fracture connectivity becomes better.
2023, 48(7): 2489-2505.
doi: 10.3799/dqkx.2022.227
Abstract:
To clarify the characteristics of fracture distribution in ultra-deep and tight sandstone reservoir in Kuqa Depression, based on the principle of fracture generated by paleo-stress and fracture effectiveness affected by current in-situ stress, determine fracture mechanical properties and pick fracture parameters according to core data and FMI logging data, the present-day in-situ stress field is predicted by structural recovery inversion of equivalent paleo-stress and finite element method, and combined with DFN discrete fracture grid modeling, the fractures of ultra-deep and tight sandstone reservoir in Bozi-X Block of Kelasu structural belt in Kuqa Depression are predicted. The results show that the tectonic fractures of Bozi-X gas reservoir are mainly unfilled semi-filled high angle shear fractures, and small-scale tensile fractures are developed locally. The majority of natural fractures in the study area were formed by rapid and strong compression in the Late Himalayas. From the Cretaceous to Neogene, high stress values moved southwards in Bozi-X area due to the continuous southward advancement of force source. The heterogeneity of tectonic fracture development and distribution in Bozi-X gas reservoir is extremely obvious. The development degree is high in Well X104 area in the northeast and low around Well X103 area in the southwest. Current in-situ stress has a significant impact on fracture effectiveness, and then affects the productivity of gas wells. The formation of fractures in Bozi-X block is jointly controlled by faults and folds. It is difficult to accurately predict the distribution of fractures only from the structural characteristics, but the prediction of fractures by geomechanical principles and methods has a good coincidence. Gas production cannot be evaluated and predicted only by porosity and reservoir thickness.
To clarify the characteristics of fracture distribution in ultra-deep and tight sandstone reservoir in Kuqa Depression, based on the principle of fracture generated by paleo-stress and fracture effectiveness affected by current in-situ stress, determine fracture mechanical properties and pick fracture parameters according to core data and FMI logging data, the present-day in-situ stress field is predicted by structural recovery inversion of equivalent paleo-stress and finite element method, and combined with DFN discrete fracture grid modeling, the fractures of ultra-deep and tight sandstone reservoir in Bozi-X Block of Kelasu structural belt in Kuqa Depression are predicted. The results show that the tectonic fractures of Bozi-X gas reservoir are mainly unfilled semi-filled high angle shear fractures, and small-scale tensile fractures are developed locally. The majority of natural fractures in the study area were formed by rapid and strong compression in the Late Himalayas. From the Cretaceous to Neogene, high stress values moved southwards in Bozi-X area due to the continuous southward advancement of force source. The heterogeneity of tectonic fracture development and distribution in Bozi-X gas reservoir is extremely obvious. The development degree is high in Well X104 area in the northeast and low around Well X103 area in the southwest. Current in-situ stress has a significant impact on fracture effectiveness, and then affects the productivity of gas wells. The formation of fractures in Bozi-X block is jointly controlled by faults and folds. It is difficult to accurately predict the distribution of fractures only from the structural characteristics, but the prediction of fractures by geomechanical principles and methods has a good coincidence. Gas production cannot be evaluated and predicted only by porosity and reservoir thickness.
2023, 48(7): 2506-2519.
doi: 10.3799/dqkx.2023.110
Abstract:
The segmental characteristics of the deep strike-slip fault zone in the Tarim Basin are the key issues in the study of fault zone reservoir control, which is of great significance for promoting deep oil and gas exploration and development. From the perspective of the integration of the development characteristics of the Harahatang fault zone and the results of seismic data interpretation, in this study it discusses the segmentation characteristics of the Ha-15 fault zone in the Harahatang area of Tabei by carefully characterizing the structure and structural style of the Harahatang fault zone. On the basis of clarification of characteristics and stress state of the strike-slip motion of the fault zone in the north of the tower, the causal mechanism of the orderly development of secondary R' shear fracture and T-tensile fracture of deep strike-slip fracture is reasonably explained by taking the Coulomb-Anderson pure shear model and the Riddle single shear model as the framework, and combining the rock fracture criteria of Griffith and Coulomb-Moir. Finally, according to the structural analysis of the Harb-15 fault zone, a typical model of convergent strike-slip fault and derived tectonic development in the passive strike-slip tectonic environment is established. It is believed that the attenuation of regional extrusion stress and the change of three-way stress state are the main reasons for the segmentation of strike-slip fractures, which can be divided into compression torsion zone, torsion zone and tensile torsion zone along the direction of extrusion stress, and can be subdivided into linear tight closure fault combination zone, linear braided structural zone, symmetrical plume fault zone, stretch/extrusion laminate zone or oblique tensile division plot and horsetail fault combination zone.
The segmental characteristics of the deep strike-slip fault zone in the Tarim Basin are the key issues in the study of fault zone reservoir control, which is of great significance for promoting deep oil and gas exploration and development. From the perspective of the integration of the development characteristics of the Harahatang fault zone and the results of seismic data interpretation, in this study it discusses the segmentation characteristics of the Ha-15 fault zone in the Harahatang area of Tabei by carefully characterizing the structure and structural style of the Harahatang fault zone. On the basis of clarification of characteristics and stress state of the strike-slip motion of the fault zone in the north of the tower, the causal mechanism of the orderly development of secondary R' shear fracture and T-tensile fracture of deep strike-slip fracture is reasonably explained by taking the Coulomb-Anderson pure shear model and the Riddle single shear model as the framework, and combining the rock fracture criteria of Griffith and Coulomb-Moir. Finally, according to the structural analysis of the Harb-15 fault zone, a typical model of convergent strike-slip fault and derived tectonic development in the passive strike-slip tectonic environment is established. It is believed that the attenuation of regional extrusion stress and the change of three-way stress state are the main reasons for the segmentation of strike-slip fractures, which can be divided into compression torsion zone, torsion zone and tensile torsion zone along the direction of extrusion stress, and can be subdivided into linear tight closure fault combination zone, linear braided structural zone, symmetrical plume fault zone, stretch/extrusion laminate zone or oblique tensile division plot and horsetail fault combination zone.
2023, 48(7): 2520-2534.
doi: 10.3799/dqkx.2022.138
Abstract:
Kelasu gas field of Kuqa foreland thrust belt in Tarim Basin is an important strategic gas-producing area for China's "West to East Gas Transmission" project. Structural fractures are widely developed, and it plays an obvious role in controlling the high and stable production of oil and gas wells. However, the distribution of fractures is still unclear. In this paper, the genetic mechanism of fractures, as well as the reservoir development tactics were summarized and analyzed through core fracture measurement, outcrop fracture Ridar scanning, FMI data, analyzing grouting thin section, laser confocal, CT scanning, and cathodoluminescence (CL) results. There are four types of structural deformation styles, three types of structural fractures, as well as three types of relationships between pores, throats and micro-fractures in Kelasu gas field. The structural fracture in this region is characterize by alternating density and clustered distribution, with a width of 2-6 km. To promote the fracture penetration rate effectively, and to avoid the invasion of bottom water at the same time, it is suggested to, drill highly deviated wells vertical to structural fractures, from north to south, in combination with differentiated reservoir reconstruction.
Kelasu gas field of Kuqa foreland thrust belt in Tarim Basin is an important strategic gas-producing area for China's "West to East Gas Transmission" project. Structural fractures are widely developed, and it plays an obvious role in controlling the high and stable production of oil and gas wells. However, the distribution of fractures is still unclear. In this paper, the genetic mechanism of fractures, as well as the reservoir development tactics were summarized and analyzed through core fracture measurement, outcrop fracture Ridar scanning, FMI data, analyzing grouting thin section, laser confocal, CT scanning, and cathodoluminescence (CL) results. There are four types of structural deformation styles, three types of structural fractures, as well as three types of relationships between pores, throats and micro-fractures in Kelasu gas field. The structural fracture in this region is characterize by alternating density and clustered distribution, with a width of 2-6 km. To promote the fracture penetration rate effectively, and to avoid the invasion of bottom water at the same time, it is suggested to, drill highly deviated wells vertical to structural fractures, from north to south, in combination with differentiated reservoir reconstruction.
2023, 48(7): 2535-2556.
doi: 10.3799/dqkx.2022.498
Abstract:
Mechanical stratigraphy is an essential factor in controlling fault and fracture system. The scaling and distribution characteristics of mechanical stratigraphy are important geological factors affecting oil and gas enrichment and the yield of the tight reservoir. The multi-scale characteristics of mechanical stratigraphy are determined by types, characteristics, and the limiting capacity of mechanical stratigraphic interfaces, which affects the vertical extension of faults and fractures with different scales. The study and division methods of multi-scale mechanical stratigraphy include the structural deformation (such as the fracture layer and the structural layer) method, the petrology method, the sequence stratigraphy method, the logging data inversion mechanical parameter method, the measured rock mechanical parameter method, the prestack seismic data inversion, and so on. Lithology is the basis for the evolution of mechanical properties and the development of faults and fractures. Lithology combination controls the distribution of multi-scale mechanical stratigraphy. The mechanical interface limiting capacity to fractures determines the scale of the corresponding mechanical stratigraphy. The thickness of mechanical stratigraphy has a noticeable control effect on the fracture density and mainly includes two quantitative relationships: the linear model and the power function model of the fracture spacing index. Large-scale mechanical stratigraphy controls the characteristics of large-scale fractures and faults, such as dip angles, densities, and structural style, and controls reservoir development, fluid migration and enrichment, and determines the vertical distribution of oil-bearing formations and the development of favorable reservoirs. Medium to small-scale and micro-scale mechanical stratigraphy controls the vertical heterogeneity of fracture⁃cavity reservoirs. This study deepens the understanding of the main controlling factors of multi-scale fractures and provides a reference to the research of petroleum seepage and fractured reservoir modeling.
Mechanical stratigraphy is an essential factor in controlling fault and fracture system. The scaling and distribution characteristics of mechanical stratigraphy are important geological factors affecting oil and gas enrichment and the yield of the tight reservoir. The multi-scale characteristics of mechanical stratigraphy are determined by types, characteristics, and the limiting capacity of mechanical stratigraphic interfaces, which affects the vertical extension of faults and fractures with different scales. The study and division methods of multi-scale mechanical stratigraphy include the structural deformation (such as the fracture layer and the structural layer) method, the petrology method, the sequence stratigraphy method, the logging data inversion mechanical parameter method, the measured rock mechanical parameter method, the prestack seismic data inversion, and so on. Lithology is the basis for the evolution of mechanical properties and the development of faults and fractures. Lithology combination controls the distribution of multi-scale mechanical stratigraphy. The mechanical interface limiting capacity to fractures determines the scale of the corresponding mechanical stratigraphy. The thickness of mechanical stratigraphy has a noticeable control effect on the fracture density and mainly includes two quantitative relationships: the linear model and the power function model of the fracture spacing index. Large-scale mechanical stratigraphy controls the characteristics of large-scale fractures and faults, such as dip angles, densities, and structural style, and controls reservoir development, fluid migration and enrichment, and determines the vertical distribution of oil-bearing formations and the development of favorable reservoirs. Medium to small-scale and micro-scale mechanical stratigraphy controls the vertical heterogeneity of fracture⁃cavity reservoirs. This study deepens the understanding of the main controlling factors of multi-scale fractures and provides a reference to the research of petroleum seepage and fractured reservoir modeling.
2023, 48(7): 2557-2571.
doi: 10.3799/dqkx.2022.114
Abstract:
In the SW Qaidam Basin, fractures are widely developed in tight lacustrine carbonate rocks of the Upper Xiagnchaigou Formation in the Shizigou structure, which is the key factor controlling the high production of hydrocarbon. The purpose of this study is to establish the present-day in-situ stress state and distribution patterns of fracture attitudes, which is significant to determine effective fractures and to design horizontal well orientations considering hydraulic fracture distribution. In this study, fracture characteristics were revealed in cores and thin sections. The spatial relation between deep faults and trajectories of Well A, Well B and Well C was extracted from 3D seismic data. We selected horizontal intervals of Well A and Well B to construct in-situ stress profiles and image log intervals of Well A and Well C to count fracture attitudes which were further shown by stereonets, rose diagrams and fracture dip histograms. Horizontal intervals of three selected wells are nearly parallel to the NW-trending faults belonging to the strike-slip positive flower structure. Geostress logging shows that the measuring intervals in the Upper Xiaganchaigou Formation are under the strike-slip faulting stress state. Most unfilled conductive fractures and filled resistive fractures have NE strikes and high to near-vertical dips, and they were dominated by the strike-slip faulting stress state whose maximum horizontal principal stress is in the NE direction since the Early Miocene. Unfilled fractures and dissolved fractures which were previously filled can act as hydrocarbon reservoirs and migration pathways. NE-trending unfilled fractures with vertical dips are the most effective fractures. If NE-trending horizontal wells are drilled near NW-trending main faults, more natural fractures will be met, and NE-trending hydraulic fractures with vertical dips are effective. The design of NE-trending horizontal wells is worth considering due to the poor production of NW-trending horizontal wells.
In the SW Qaidam Basin, fractures are widely developed in tight lacustrine carbonate rocks of the Upper Xiagnchaigou Formation in the Shizigou structure, which is the key factor controlling the high production of hydrocarbon. The purpose of this study is to establish the present-day in-situ stress state and distribution patterns of fracture attitudes, which is significant to determine effective fractures and to design horizontal well orientations considering hydraulic fracture distribution. In this study, fracture characteristics were revealed in cores and thin sections. The spatial relation between deep faults and trajectories of Well A, Well B and Well C was extracted from 3D seismic data. We selected horizontal intervals of Well A and Well B to construct in-situ stress profiles and image log intervals of Well A and Well C to count fracture attitudes which were further shown by stereonets, rose diagrams and fracture dip histograms. Horizontal intervals of three selected wells are nearly parallel to the NW-trending faults belonging to the strike-slip positive flower structure. Geostress logging shows that the measuring intervals in the Upper Xiaganchaigou Formation are under the strike-slip faulting stress state. Most unfilled conductive fractures and filled resistive fractures have NE strikes and high to near-vertical dips, and they were dominated by the strike-slip faulting stress state whose maximum horizontal principal stress is in the NE direction since the Early Miocene. Unfilled fractures and dissolved fractures which were previously filled can act as hydrocarbon reservoirs and migration pathways. NE-trending unfilled fractures with vertical dips are the most effective fractures. If NE-trending horizontal wells are drilled near NW-trending main faults, more natural fractures will be met, and NE-trending hydraulic fractures with vertical dips are effective. The design of NE-trending horizontal wells is worth considering due to the poor production of NW-trending horizontal wells.
2023, 48(7): 2572-2588.
doi: 10.3799/dqkx.2022.234
Abstract:
The rock mechanical stratigraphy controls the development degree and genetic mechanism of natural fractures. Similarly, the development of fractures also affects the size and anisotropy of rock mechanical parameters. Affected by diagenesis and tectonics, the rock mechanics layer has migrated. Therefore, the rock mechanics layer that controls the development of fractures and the rock mechanics layer suitable for predicting the distribution of natural fractures may no longer exist. This paper proposes a method based on reservoir geomechanics modeling to analyze the evolution of rock mechanics layer under the control of structural factors. A three-dimensional fracture discrete network model was established through field observations, combined with rock mechanics experiments to determine the mechanical parameters of the rock and fracture surfaces, the method for determining the optimal representation unit size of the fractured reservoir mechanical parameters was determined, and the three-dimensional geomechanical model of the fractured reservoir was established. A three-cycle method is proposed to characterize the equivalent mechanical parameters of fractured reservoirs with different sizes and different orientations. The Young's modulus discriminant index and Poisson's ratio discriminant index are used to characterize the scale effect and anisotropy of the mechanical parameters of fractured reservoirs, and the evolution of rock mechanics layer is analyzed. The results show that the fracture combination pattern on the western edge of Ordos basin and the accuracy requirements of the later stress field simulation determine the optimal element size for geomechanical modeling to be 28 m. In geomechanical modeling, too small grid element scale can not completely describe the fracture development mode in the element. The development of natural fractures from the Yanshanian period to the Himalayan period to the present has resulted in an overall decrease in the equivalent Young's modulus and an overall increase in the Poisson's ratio of the rock mass in the Ordos Basin. The difference between the equivalent Young's modulus and the Poisson's ratio of the rock mass has decreased over time.
The rock mechanical stratigraphy controls the development degree and genetic mechanism of natural fractures. Similarly, the development of fractures also affects the size and anisotropy of rock mechanical parameters. Affected by diagenesis and tectonics, the rock mechanics layer has migrated. Therefore, the rock mechanics layer that controls the development of fractures and the rock mechanics layer suitable for predicting the distribution of natural fractures may no longer exist. This paper proposes a method based on reservoir geomechanics modeling to analyze the evolution of rock mechanics layer under the control of structural factors. A three-dimensional fracture discrete network model was established through field observations, combined with rock mechanics experiments to determine the mechanical parameters of the rock and fracture surfaces, the method for determining the optimal representation unit size of the fractured reservoir mechanical parameters was determined, and the three-dimensional geomechanical model of the fractured reservoir was established. A three-cycle method is proposed to characterize the equivalent mechanical parameters of fractured reservoirs with different sizes and different orientations. The Young's modulus discriminant index and Poisson's ratio discriminant index are used to characterize the scale effect and anisotropy of the mechanical parameters of fractured reservoirs, and the evolution of rock mechanics layer is analyzed. The results show that the fracture combination pattern on the western edge of Ordos basin and the accuracy requirements of the later stress field simulation determine the optimal element size for geomechanical modeling to be 28 m. In geomechanical modeling, too small grid element scale can not completely describe the fracture development mode in the element. The development of natural fractures from the Yanshanian period to the Himalayan period to the present has resulted in an overall decrease in the equivalent Young's modulus and an overall increase in the Poisson's ratio of the rock mass in the Ordos Basin. The difference between the equivalent Young's modulus and the Poisson's ratio of the rock mass has decreased over time.
2023, 48(7): 2589-2600.
doi: 10.3799/dqkx.2023.208
Abstract:
There are various types of natural fractures in Chang 7 shale oil reservoir in Longdong area, Ordos Basin, which are the key factors affecting shale oil enrichment and productivity. In order to guide the exploration and development of this area, the genetic types and development characteristics of natural fractures were analyzed by comprehensively utilizing various data of outcrops, cores, thin sections and imaging logging. Natural fractures in the study area can be divided into three types according to their origin, including tectonic fractures, diagenetic fractures and abnormal high pressure fractures. The tectonic fractures mainly include high-angle shear fractures, low-angle shear fractures and tensile fractures. Diagenetic fractures are mainly bedding fractures with a few sutures. Abnormal high pressure fractures are less developed. On this basis, the controlling factors affecting fracture development are further studied. The results show that tectonic fractures are mainly controlled by lithology, rock mechanical layer thickness and tectonic stress field. The development degree of bedding fractures is related to organic carbon content and lamina, and abnormal high pressure fractures are mainly affected by abnormal high pressure.
There are various types of natural fractures in Chang 7 shale oil reservoir in Longdong area, Ordos Basin, which are the key factors affecting shale oil enrichment and productivity. In order to guide the exploration and development of this area, the genetic types and development characteristics of natural fractures were analyzed by comprehensively utilizing various data of outcrops, cores, thin sections and imaging logging. Natural fractures in the study area can be divided into three types according to their origin, including tectonic fractures, diagenetic fractures and abnormal high pressure fractures. The tectonic fractures mainly include high-angle shear fractures, low-angle shear fractures and tensile fractures. Diagenetic fractures are mainly bedding fractures with a few sutures. Abnormal high pressure fractures are less developed. On this basis, the controlling factors affecting fracture development are further studied. The results show that tectonic fractures are mainly controlled by lithology, rock mechanical layer thickness and tectonic stress field. The development degree of bedding fractures is related to organic carbon content and lamina, and abnormal high pressure fractures are mainly affected by abnormal high pressure.
2023, 48(7): 2601-2613.
doi: 10.3799/dqkx.2022.116
Abstract:
The matrix physical properties of tight sandstone reservoir are very poor. The development of natural fractures provides seepage channel and reservoir space for oil and gas migration and accumulation. The distribution of effective fractures significantly improves the reservoir permeability and single well production. Based on the core, thin section, logging data and relevant experimental analysis, the genetic types, development characteristics and distribution law of natural fractures in tight sandstone reservoir of the Chang 7 Member in Sanbian area of Ordos Basin were characterized, the fracture effectiveness was evaluated, and the main controlling factors affecting fracture effectiveness were analyzed. The main development type of macro fractures in the study area is structural fractures, diagenetic fractures can be observed in some cores, and the micro fractures are mainly intergranular fractures. The development degree of fractures is controlled by lithology, mechanical stratigraphy and diagenetic facies. Fracture effectiveness was evaluated by two parameters of fracture filling degree and fracture aperture. Fracture effectiveness is controlled by factors such as fracture formation time, diagenesis, fracture occurrence and current in-situ stress. Affected by diagenesis, cementation reduces fracture effectiveness, while dissolution improves fracture effectiveness. The effectiveness of late formed fractures is better than that of early formed fractures. Five sets of fractures are developed in the study area, including nearly E-W trending, NW-SE trending, nearly S-N trending, NNE-SSW trending and NEE-SWW trending fractures. Among them, the NEE-SWW trending fractures which are parallel to the direction of current maximum principal stress, have the largest aperture and the best effectiveness, followed by NNE-SSW trending and nearly E-W trending fractures. The nearly E-W trending and NW-SE trending fractures are nearly perpendicular to or at a high angle with the direction of current maximum principal stress, and the fracture aperture is relatively small and the effectiveness is poor.
The matrix physical properties of tight sandstone reservoir are very poor. The development of natural fractures provides seepage channel and reservoir space for oil and gas migration and accumulation. The distribution of effective fractures significantly improves the reservoir permeability and single well production. Based on the core, thin section, logging data and relevant experimental analysis, the genetic types, development characteristics and distribution law of natural fractures in tight sandstone reservoir of the Chang 7 Member in Sanbian area of Ordos Basin were characterized, the fracture effectiveness was evaluated, and the main controlling factors affecting fracture effectiveness were analyzed. The main development type of macro fractures in the study area is structural fractures, diagenetic fractures can be observed in some cores, and the micro fractures are mainly intergranular fractures. The development degree of fractures is controlled by lithology, mechanical stratigraphy and diagenetic facies. Fracture effectiveness was evaluated by two parameters of fracture filling degree and fracture aperture. Fracture effectiveness is controlled by factors such as fracture formation time, diagenesis, fracture occurrence and current in-situ stress. Affected by diagenesis, cementation reduces fracture effectiveness, while dissolution improves fracture effectiveness. The effectiveness of late formed fractures is better than that of early formed fractures. Five sets of fractures are developed in the study area, including nearly E-W trending, NW-SE trending, nearly S-N trending, NNE-SSW trending and NEE-SWW trending fractures. Among them, the NEE-SWW trending fractures which are parallel to the direction of current maximum principal stress, have the largest aperture and the best effectiveness, followed by NNE-SSW trending and nearly E-W trending fractures. The nearly E-W trending and NW-SE trending fractures are nearly perpendicular to or at a high angle with the direction of current maximum principal stress, and the fracture aperture is relatively small and the effectiveness is poor.
2023, 48(7): 2614-2629.
doi: 10.3799/dqkx.2022.217
Abstract:
A large number of fractures are developed in the Yanchang Formation in the western Ordos Basin, and the existence of fractures has a good indication of tight oil sweet spots. In this paper, taking the tight oil reservoirs of the Yanchang Formation in the Zhidan-Wuqi region of the Ordos Basin as an example, a large amount of core, thin section, logging, paleomagnetism, productivity data and numerical simulation methods are used to systematically study the development characteristics and control of tight oil fractures in the study area. The research results show that the Yanchang Formation mainly develops vertical fractures, and the classification standard for the degree of fracture development is established according to the thickness of the fractures. Combining the coupling relationship between fractures and sand bodies, structures, and reservoirs and the current status of reservoir production, the fracture-controlling action for oil is clarified. It is believed that the regional fractures provide a good drainage system for the Yanchang Formation tight oil reservoirs; the river convergence or diversion areas are repeatedly washed by river water, the sandstone is well sorted, brittle, and the fractures are well developed and are conducive to hydrocarbon accumulation; the low-amplitude structural high points and nose-like uplift areas have developed fractures and are conducive to hydrocarbon accumulation; the relationship between the fracture zone and the strike of the sand body is coupled to form a "parallel drainage" fracture sweet spot; the fractures are mainly developed in the medium and low thickness fine sandstone, and the cumulative thickness of the sand body is mainly distributed in the range of 5-15 m; from the point of view of the location of the sand body, the fractures are mainly developed in the wings of the main channel, which is related to the reduction of the particle size, compaction space and thickness of the sand bodies in the wings.
A large number of fractures are developed in the Yanchang Formation in the western Ordos Basin, and the existence of fractures has a good indication of tight oil sweet spots. In this paper, taking the tight oil reservoirs of the Yanchang Formation in the Zhidan-Wuqi region of the Ordos Basin as an example, a large amount of core, thin section, logging, paleomagnetism, productivity data and numerical simulation methods are used to systematically study the development characteristics and control of tight oil fractures in the study area. The research results show that the Yanchang Formation mainly develops vertical fractures, and the classification standard for the degree of fracture development is established according to the thickness of the fractures. Combining the coupling relationship between fractures and sand bodies, structures, and reservoirs and the current status of reservoir production, the fracture-controlling action for oil is clarified. It is believed that the regional fractures provide a good drainage system for the Yanchang Formation tight oil reservoirs; the river convergence or diversion areas are repeatedly washed by river water, the sandstone is well sorted, brittle, and the fractures are well developed and are conducive to hydrocarbon accumulation; the low-amplitude structural high points and nose-like uplift areas have developed fractures and are conducive to hydrocarbon accumulation; the relationship between the fracture zone and the strike of the sand body is coupled to form a "parallel drainage" fracture sweet spot; the fractures are mainly developed in the medium and low thickness fine sandstone, and the cumulative thickness of the sand body is mainly distributed in the range of 5-15 m; from the point of view of the location of the sand body, the fractures are mainly developed in the wings of the main channel, which is related to the reduction of the particle size, compaction space and thickness of the sand bodies in the wings.
2023, 48(7): 2630-2642.
doi: 10.3799/dqkx.2022.226
Abstract:
The characteristics of natural fractures are important geological indicators in evaluating the law of shale gas enrichment and preservation. The research object is the Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation shale in the Luzhou area of southern Sichuan Basin. The characteristics and controlling factors of different types of natural fractures in the study area were studied by using seismic, logging, core, thin sections, scanning electron microscopy, and analytical laboratory data. The research results show that the Wufeng-Longmaxi shale fractures in the Luzhou area can be divided into three types: structural fractures, diagenetic fractures and abnormally high pressure fractures according to their geological origin. According to the mechanical properties of the fracture and the relationship with the rock mechanics layer, structural fractures are dominated by transformational shear fractures, intraformational open fractures, and bed-parallel shear fractures. Diagenetic fractures include lamellation fractures and shrinkage fractures. In the Luzhou area, a large number of structural fractures and bedding fractures are developed, while shrinkage fractures and abnormally high pressure fractures are relatively low. The distribution and development of structural fractures are controlled by faults, folds, rock mechanics layer and brittleness, and the development of lamellation fractures is mainly controlled by brittleness, organic matter content and lamina types.
The characteristics of natural fractures are important geological indicators in evaluating the law of shale gas enrichment and preservation. The research object is the Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation shale in the Luzhou area of southern Sichuan Basin. The characteristics and controlling factors of different types of natural fractures in the study area were studied by using seismic, logging, core, thin sections, scanning electron microscopy, and analytical laboratory data. The research results show that the Wufeng-Longmaxi shale fractures in the Luzhou area can be divided into three types: structural fractures, diagenetic fractures and abnormally high pressure fractures according to their geological origin. According to the mechanical properties of the fracture and the relationship with the rock mechanics layer, structural fractures are dominated by transformational shear fractures, intraformational open fractures, and bed-parallel shear fractures. Diagenetic fractures include lamellation fractures and shrinkage fractures. In the Luzhou area, a large number of structural fractures and bedding fractures are developed, while shrinkage fractures and abnormally high pressure fractures are relatively low. The distribution and development of structural fractures are controlled by faults, folds, rock mechanics layer and brittleness, and the development of lamellation fractures is mainly controlled by brittleness, organic matter content and lamina types.
2023, 48(7): 2643-2651.
doi: 10.3799/dqkx.2022.496
Abstract:
The carbonate reservoirs of the Lower Triassic Feixianguan Formation in the Northeast Sichuan Basin are characterized with strong heterogeneity and development of natural fractures. The distribution of natural fractures plays an important role in hydrocarbon migration and development. In this paper, the development laws of natural fractures in carbonate reservoirs of Feixianguan Formation in Huanglongchang-Qilibei area in Northeast Sichuan area are predicted by combining 3D seismic attributes with imaging logging and core analysis methods. NEE-SWW trending, NE-SW trending, NW-SE trending and NWW-SEE trending fractures are mainly developed in the carbonate reservoirs of Feixianguan Formation. NNE-SSW trending fractures are the most developed, followed by NE-SW trending and NW-SE trending fractures, NWW-SEE trending fractures are relatively poorly developed, and the fractures are dominated by high angle fractures greater than 70°. The fracture development degree of carbonate reservoir in Feixianguan Formation is mainly controlled by sedimentary facies and faults. Sedimentary facies is the basis of fracture development, and the fracture development degree of different sedimentary facies is obviously different. The fractures are mostly developed in marginal-platform shoal subfacies and intra-platform shoal subfacies, followed by interbank sea subfacies and intra-platform depression subfacies, and the fracture development degree of gentle slope subfacies is relatively poor. Fault is the key to influence fracture development degree and distribution laws. According to the fracture development index (FDI) method analysis, the width of the fault-controlled fracture zones mainly ranges between 250 m and 1 000 m in this area. With the increase of the fault scale, the width of fault-controlled fracture zones increases as well.
The carbonate reservoirs of the Lower Triassic Feixianguan Formation in the Northeast Sichuan Basin are characterized with strong heterogeneity and development of natural fractures. The distribution of natural fractures plays an important role in hydrocarbon migration and development. In this paper, the development laws of natural fractures in carbonate reservoirs of Feixianguan Formation in Huanglongchang-Qilibei area in Northeast Sichuan area are predicted by combining 3D seismic attributes with imaging logging and core analysis methods. NEE-SWW trending, NE-SW trending, NW-SE trending and NWW-SEE trending fractures are mainly developed in the carbonate reservoirs of Feixianguan Formation. NNE-SSW trending fractures are the most developed, followed by NE-SW trending and NW-SE trending fractures, NWW-SEE trending fractures are relatively poorly developed, and the fractures are dominated by high angle fractures greater than 70°. The fracture development degree of carbonate reservoir in Feixianguan Formation is mainly controlled by sedimentary facies and faults. Sedimentary facies is the basis of fracture development, and the fracture development degree of different sedimentary facies is obviously different. The fractures are mostly developed in marginal-platform shoal subfacies and intra-platform shoal subfacies, followed by interbank sea subfacies and intra-platform depression subfacies, and the fracture development degree of gentle slope subfacies is relatively poor. Fault is the key to influence fracture development degree and distribution laws. According to the fracture development index (FDI) method analysis, the width of the fault-controlled fracture zones mainly ranges between 250 m and 1 000 m in this area. With the increase of the fault scale, the width of fault-controlled fracture zones increases as well.
2023, 48(7): 2652-2664.
doi: 10.3799/dqkx.2022.257
Abstract:
Natural non-tectonic fracture is an important reservoir space for shale gas. However, there are currently insufficient researches on the formation mechanism, control factors, and development characteristics of non-tectonic fractures. It characterizes natural non-tectonic fractures of Lower Silurian Longmaxi Shale and Lower Cambrian Niutitang Shale in study area. The non-tectonic micro-fractures of Lower Palaeozoic Shale were identified and their interior structures were characterized by analyzing SME images. The main controlling factors on the characteristics and distribution of non-tectonic fractures were analyzed by researching sedimentary environment, organic matter abundance and types, thermal evolution degree, hydrocarbon generation history, clay minerals, paleosalinity and diagenesis. The results show that natural non-tectonic fractures, which produced because of diagenetic shrinkage, dissolution and abnormal high pressure, are abundant in both Longmaxi Shale and Niutitang Shale. Natural non-tectonic fractures, of which the microstructure is in the irregular shape of silk-thread and curly sheet, cut shallowly in longitudinal direction, with width ranging from 10 nm to 50 nm, even more than 1 μm. The porosity and permeability of shale could be improved due to excellent extensibility and connectivity of non-tectonic fractures. The lower part of Niutitang Shale and Longmaxi Shale is deep-water shelf facies with numerous horizontal bedding, therefore, it is a favorable facies for the development of non-tectonic fractures. Undercompaction and hydrocarbon generation can produce large-scale overpressure fractures. In the early stage of burial, undercompaction was the main cause of formation overpressure. Hydrocarbon generation pressurization, that has a good corresponding relationship with thermal evolution, could release organic acids to promote the development of secondary dissolution fractures. While the destruction and adjustment of tectonic movement released the abnormal overpressure, the overpressure fractures shrunk or even closed. The lower Paleozoic shale was deposited in the water environment with medium paleosalinity, in addition, high clay content is conducive to the generation of diagenetic shrinkage fractures. Longmaxi Shale was in middle-late or late diagenesis stage, while the smectite transformed to illite gradually, the volume of diagenetic shrinkage fractures was close to the maximum. Niutitang Shale was in late diagenesis stage, the generation rate of shrinkage fractures became slow, moreover, the volume of diagenetic shrinkage fractures had approached or reached the maximum.
Natural non-tectonic fracture is an important reservoir space for shale gas. However, there are currently insufficient researches on the formation mechanism, control factors, and development characteristics of non-tectonic fractures. It characterizes natural non-tectonic fractures of Lower Silurian Longmaxi Shale and Lower Cambrian Niutitang Shale in study area. The non-tectonic micro-fractures of Lower Palaeozoic Shale were identified and their interior structures were characterized by analyzing SME images. The main controlling factors on the characteristics and distribution of non-tectonic fractures were analyzed by researching sedimentary environment, organic matter abundance and types, thermal evolution degree, hydrocarbon generation history, clay minerals, paleosalinity and diagenesis. The results show that natural non-tectonic fractures, which produced because of diagenetic shrinkage, dissolution and abnormal high pressure, are abundant in both Longmaxi Shale and Niutitang Shale. Natural non-tectonic fractures, of which the microstructure is in the irregular shape of silk-thread and curly sheet, cut shallowly in longitudinal direction, with width ranging from 10 nm to 50 nm, even more than 1 μm. The porosity and permeability of shale could be improved due to excellent extensibility and connectivity of non-tectonic fractures. The lower part of Niutitang Shale and Longmaxi Shale is deep-water shelf facies with numerous horizontal bedding, therefore, it is a favorable facies for the development of non-tectonic fractures. Undercompaction and hydrocarbon generation can produce large-scale overpressure fractures. In the early stage of burial, undercompaction was the main cause of formation overpressure. Hydrocarbon generation pressurization, that has a good corresponding relationship with thermal evolution, could release organic acids to promote the development of secondary dissolution fractures. While the destruction and adjustment of tectonic movement released the abnormal overpressure, the overpressure fractures shrunk or even closed. The lower Paleozoic shale was deposited in the water environment with medium paleosalinity, in addition, high clay content is conducive to the generation of diagenetic shrinkage fractures. Longmaxi Shale was in middle-late or late diagenesis stage, while the smectite transformed to illite gradually, the volume of diagenetic shrinkage fractures was close to the maximum. Niutitang Shale was in late diagenesis stage, the generation rate of shrinkage fractures became slow, moreover, the volume of diagenetic shrinkage fractures had approached or reached the maximum.
2023, 48(7): 2665-2677.
doi: 10.3799/dqkx.2022.110
Abstract:
The Bonan region is a hot spot for oil and gas exploration and development in the Bohai Sea area in recent years. Though the Cenozoic volcanic activity provides advantageous conditions for oil and gas reservoir formation, it also poses a problem for oil and gas field development. The internal non-homogeneous, high-temperature and intense volcanic channels have affected the fracture development of the surrounding strata, triggering serious fractured well leaks resulted in huge economic losses. Based on the logging, core and seismic data, we identify the petrographic characteristics of the volcanic rocks and analyze the fracture development of the surrounding strata. The boundary conditions of the temperature field of volcanic activity are determined by means of core mineral analysis and thin section observation. In addition, applying the principle of thermodynamic coupling and the finite element numerical simulation method, the thermal expansion fractures of rocks caused by volcanic activity are quantitatively predicted, based on the law of energy conservation and geomechanics. Based on the thermodynamic coupling analysis of the influence range of volcanic channels on perimeter fracture development, the results have important reference values for drilling safety and volcano-related reservoir prediction in Bohai oil fields.
2023, 48(7): 2678-2689.
doi: 10.3799/dqkx.2022.202
Abstract:
Fracture as reservoir space and migration channel of oil and gas, is an important part of the fracture reservoir study, so that, fracture porosity is the most important parameter in fracture reservoir logging evaluation. Although there are many qualitative identification and description methods, but how to use conventional log data to quantitatively calculate fracture porosity has always been a difficult problem in fracture reservoir interpretation. A new method for calculating fracture porosity based on conventional logging data of probabilistic neural network is proposed in this study, taking a reservoir of a gas field in the Amu Darya Basin as an example. The reservoir in Upper Jurassic Callovian-Oxfordian order group is located on the platform margin slope, with relatively high energy beach facies and high beach complex fracture-pore type. To calculate fracture porosity of the wells which have imaging well logging data, first, a variety of classic model methods are used to calculate fracture porosity with dual laterolog resistivity data, comprehensive with the acoustic data and density data. Then the weighted factor to weighted the fracture porosity is calculated by those kinds of models, and the weighted calculation result is calibrated using the accurate fracture porosity calculated by imaging logging data as a constraint to get the final fracture porosity curve. For the wells which do not have imaging well logging data, using probabilistic neural network algorithm of deep learning to establish the mapping relation between the calculated fracture porosity curve from imaging logging data and conventional well logging data, so that the fracture porosity curve of other wells can be calculated, and the calculation error can be determined by using cross validation criterion. The results show that the fracture porosity calculated by this new method is in good agreement with the fracture porosity interpreted by imaging logging. For the wells without imaging logging data, after the lateral extrapolation calculation, according to the actual lost circulation of the target interval, the analysis of production performance data and the verification and comparison of reservoir parameters were made, which is consistent with the oilfield production situation, which indirectly confirms the reliability of the calculation results and indicates that this method is an effective method.
Fracture as reservoir space and migration channel of oil and gas, is an important part of the fracture reservoir study, so that, fracture porosity is the most important parameter in fracture reservoir logging evaluation. Although there are many qualitative identification and description methods, but how to use conventional log data to quantitatively calculate fracture porosity has always been a difficult problem in fracture reservoir interpretation. A new method for calculating fracture porosity based on conventional logging data of probabilistic neural network is proposed in this study, taking a reservoir of a gas field in the Amu Darya Basin as an example. The reservoir in Upper Jurassic Callovian-Oxfordian order group is located on the platform margin slope, with relatively high energy beach facies and high beach complex fracture-pore type. To calculate fracture porosity of the wells which have imaging well logging data, first, a variety of classic model methods are used to calculate fracture porosity with dual laterolog resistivity data, comprehensive with the acoustic data and density data. Then the weighted factor to weighted the fracture porosity is calculated by those kinds of models, and the weighted calculation result is calibrated using the accurate fracture porosity calculated by imaging logging data as a constraint to get the final fracture porosity curve. For the wells which do not have imaging well logging data, using probabilistic neural network algorithm of deep learning to establish the mapping relation between the calculated fracture porosity curve from imaging logging data and conventional well logging data, so that the fracture porosity curve of other wells can be calculated, and the calculation error can be determined by using cross validation criterion. The results show that the fracture porosity calculated by this new method is in good agreement with the fracture porosity interpreted by imaging logging. For the wells without imaging logging data, after the lateral extrapolation calculation, according to the actual lost circulation of the target interval, the analysis of production performance data and the verification and comparison of reservoir parameters were made, which is consistent with the oilfield production situation, which indirectly confirms the reliability of the calculation results and indicates that this method is an effective method.
2023, 48(7): 2690-2702.
doi: 10.3799/dqkx.2022.409
Abstract:
The continental shale oil reservoir of Fengcheng Formation in the northern slope area of Mahu Sag, Junggar Basin is a mixed deposition of multiple provenances, with frequent interbedding of various lithologies and small thickness of rock mechanics layer, resulting in small fracture scale, weak conventional logging response of fractures and great difficulty in identification. Aiming at the logging identification of shale fractures, in this paper it applies the extreme gradient boosting (XGBoost) method in ensemble learning to deeply mine the nonlinear relationship between fracture information and logging data, integrates multiple weak classifiers into strong classifiers, reduces the uncertainty of fracture identification, and improves the accuracy of fracture identification. In this method, core fracture description and fracture interpretation results of image logging are used as labels, and conventional logging information is used as input data for model training. On the basis of outlier screening, SMOTE oversampling and feature optimization, the optimal hyperparameters of fracture intelligent identification model are obtained through grid search method. Compared with the commonly used machine learning methods such as support vector machine and logical regression, the XGBoost has better fracture identification ability than the other two nonlinear machine learning methods, and the accuracy of test set identification reaches 90%. The identification results of the P1f3 of Well A1 reflect that the fractures in this section are relatively developed, and the model has a good identification ability for both fractured and non-fractured sections, with a high coincidence rate with the core observation results. It can provide effective means for intelligent identification of fractures in continental shale oil reservoirs in Mahu Sag.
The continental shale oil reservoir of Fengcheng Formation in the northern slope area of Mahu Sag, Junggar Basin is a mixed deposition of multiple provenances, with frequent interbedding of various lithologies and small thickness of rock mechanics layer, resulting in small fracture scale, weak conventional logging response of fractures and great difficulty in identification. Aiming at the logging identification of shale fractures, in this paper it applies the extreme gradient boosting (XGBoost) method in ensemble learning to deeply mine the nonlinear relationship between fracture information and logging data, integrates multiple weak classifiers into strong classifiers, reduces the uncertainty of fracture identification, and improves the accuracy of fracture identification. In this method, core fracture description and fracture interpretation results of image logging are used as labels, and conventional logging information is used as input data for model training. On the basis of outlier screening, SMOTE oversampling and feature optimization, the optimal hyperparameters of fracture intelligent identification model are obtained through grid search method. Compared with the commonly used machine learning methods such as support vector machine and logical regression, the XGBoost has better fracture identification ability than the other two nonlinear machine learning methods, and the accuracy of test set identification reaches 90%. The identification results of the P1f3 of Well A1 reflect that the fractures in this section are relatively developed, and the model has a good identification ability for both fractured and non-fractured sections, with a high coincidence rate with the core observation results. It can provide effective means for intelligent identification of fractures in continental shale oil reservoirs in Mahu Sag.
2023, 48(7): 2703-2717.
doi: 10.3799/dqkx.2022.258
Abstract:
Conventional borehole acoustic imaging mainly uses reflected waves, which is not conducive to high-resolution imaging of fractures in the formation beside wells, while it is possible to obtain higher-resolution measurements using detection methods based on scattered waves. The research presented in this paper develops an inversion method that uses scattered waves for borehole 3D acoustic imaging and proposes an implementation scheme that combines plane and spherical scanning imaging. Using thin aluminum plate to simulate formation fractures, the underwater physical simulation experiment of borehole azimuthal acoustic imaging was carried out in the lake, and the experiment data were processed by the inversion method proposed in this paper. The data processing results show that the proposed inversion method using scattered waves for borehole 3D acoustic imaging can improve the imaging signal-to-noise ratio, resolution, enhance the detection range, and accurately estimate the parameters such as radial distance, azimuth, dip angle, scale and depth of fractures. In contrast with the 3D slowness time coherence (STC) and beamforming methods, the proposed method does not assume that the echo signal is a plane wave, which improves the azimuth positioning accuracy of fractures. It is expected to break through the limitations of conventional borehole acoustic imaging and has great practical application potential.
Conventional borehole acoustic imaging mainly uses reflected waves, which is not conducive to high-resolution imaging of fractures in the formation beside wells, while it is possible to obtain higher-resolution measurements using detection methods based on scattered waves. The research presented in this paper develops an inversion method that uses scattered waves for borehole 3D acoustic imaging and proposes an implementation scheme that combines plane and spherical scanning imaging. Using thin aluminum plate to simulate formation fractures, the underwater physical simulation experiment of borehole azimuthal acoustic imaging was carried out in the lake, and the experiment data were processed by the inversion method proposed in this paper. The data processing results show that the proposed inversion method using scattered waves for borehole 3D acoustic imaging can improve the imaging signal-to-noise ratio, resolution, enhance the detection range, and accurately estimate the parameters such as radial distance, azimuth, dip angle, scale and depth of fractures. In contrast with the 3D slowness time coherence (STC) and beamforming methods, the proposed method does not assume that the echo signal is a plane wave, which improves the azimuth positioning accuracy of fractures. It is expected to break through the limitations of conventional borehole acoustic imaging and has great practical application potential.
2023, 48(7): 2718-2732.
doi: 10.3799/dqkx.2022.398
Abstract:
The development stage of the fault deformation zone refers to the weak deformation (strong concealment) zone developed in the sedimentary cover of the basin, which is the product of the early and middle stages of the formation and evolution of the fault zone. It is difficult to identify because of the lack of obvious fracture surface (zone) and significant displacement. It has been found that the weakly deformed tectonic belt is an objective tectonic phenomenon in the sedimentary basin cover, and is closely related to oil and gas accumulation. It can be recognized by regular arrangement of different geological units (secondary faults, oil reservoirs, traps, facies belts, depressions, rock masses, buried hills, etc.). In order to reveal the deformation intensity and hydrocarbon accumulation scale of cap cover deformation zone, the key issue of oil and gas geology, this paper takes the Dongying Sag as the research object and applies variable caprock thickness and the structural physical simulation experiment method in which variable shear strength is used to study the process of basement fault strike-slip activity on the formation of faults in the sedimentary caprock of the basin. Using SPSS software, taking the sliding amount of the basement/the thickness of the experimental cover layer (DNBD) as the independent variable x1, the amount of lateral sliding/the thickness of the experimental cover layer as the independent variable x2 (x2=x1×tanα) and the length of the echelon seam/the thickness of the experimental cover as the dependent variable y, multivariate quadratic function fitting was performed. According to the strata thickness, shear length of structural map R and experimentally estimated tensional and torsion angles by experiment in different periods of Paleogene in Bamianhe (strong strike slip) and Wangjiagang (weak strike slip) areas of Dongying Sag, the strike-slip amounts of the basement faults of Bamianhe and Wangjiagang fault zones in each period were calculated. At each stage of the simulation experiment, dyed oil was charged, and combined with the sag examples, the accumulation models of the basement faults were established, such as Early R shear single-channel migration-isolated aggregation, Early and mid-term R shear main channel migration-geese and beaded aggregation, P shear main channel migration-intermittent zonal aggregation, full channel migration-continuous belt aggregation, etc.. Finally, it is pointed out that the R shear pressurized deformation section and the R and P shear intersection section in the deformation zone are favorable target areas for oil and gas exploration.
The development stage of the fault deformation zone refers to the weak deformation (strong concealment) zone developed in the sedimentary cover of the basin, which is the product of the early and middle stages of the formation and evolution of the fault zone. It is difficult to identify because of the lack of obvious fracture surface (zone) and significant displacement. It has been found that the weakly deformed tectonic belt is an objective tectonic phenomenon in the sedimentary basin cover, and is closely related to oil and gas accumulation. It can be recognized by regular arrangement of different geological units (secondary faults, oil reservoirs, traps, facies belts, depressions, rock masses, buried hills, etc.). In order to reveal the deformation intensity and hydrocarbon accumulation scale of cap cover deformation zone, the key issue of oil and gas geology, this paper takes the Dongying Sag as the research object and applies variable caprock thickness and the structural physical simulation experiment method in which variable shear strength is used to study the process of basement fault strike-slip activity on the formation of faults in the sedimentary caprock of the basin. Using SPSS software, taking the sliding amount of the basement/the thickness of the experimental cover layer (DNBD) as the independent variable x1, the amount of lateral sliding/the thickness of the experimental cover layer as the independent variable x2 (x2=x1×tanα) and the length of the echelon seam/the thickness of the experimental cover as the dependent variable y, multivariate quadratic function fitting was performed. According to the strata thickness, shear length of structural map R and experimentally estimated tensional and torsion angles by experiment in different periods of Paleogene in Bamianhe (strong strike slip) and Wangjiagang (weak strike slip) areas of Dongying Sag, the strike-slip amounts of the basement faults of Bamianhe and Wangjiagang fault zones in each period were calculated. At each stage of the simulation experiment, dyed oil was charged, and combined with the sag examples, the accumulation models of the basement faults were established, such as Early R shear single-channel migration-isolated aggregation, Early and mid-term R shear main channel migration-geese and beaded aggregation, P shear main channel migration-intermittent zonal aggregation, full channel migration-continuous belt aggregation, etc.. Finally, it is pointed out that the R shear pressurized deformation section and the R and P shear intersection section in the deformation zone are favorable target areas for oil and gas exploration.
2023, 48(7): 2733-2749.
doi: 10.3799/dqkx.2023.084
Abstract:
Carbon capture, utilization and storage (CCUS) technology has achieved preliminary progress worldwide. This paper summarizes the progress in CO2 geological storage with enhanced oil recovery and enhanced geothermal recovery by literature review and our previous research, the future trend of the CO2 geological storage with enhanced oil recovery and enhanced geothermal recovery is presented. Results show that most CCUS deployment focuses on the CO2 enhanced oil recovery, especially in the conventional oil and gas fields. 0.1-0.6 ton of oil can be produced by each ton of CO2 injection. The way to handle CO2 breakthrough in the producer is the main challenge in the CO2 enhanced oil recovery process. The research on the CO2 enhanced oil recovery will move to the unconventional reservoirs, the future research should focus on increasing amount of CO2 migration into the matrix of the unconventional reservoirs including shale oil and gas reservoirs, and coalbed methane reservoir. In addition, CO2 can be used to enhance geothermal recovery. The research on CO2 enhanced geothermal recovery mainly focuses on the comparisons of water and CO2 as the working fluid. However, the further research on Thermal (T)-Hydro (H)-Mechanical (M)-Chemical (C) coupling with CO2 enhance geothermal recovery is required. The CO2 geological storage with CO2 enhanced oil recovery, enhanced geothermal recovery in the same oil or gas reservoir may become popular in the future CCUS deployment. This paper helps to accelerate the CCUS deployment, to develop the oil and gas fields and heat mining in the same reservoir, and helps to reach the goal of carbon peak and carbon neutrality.
Carbon capture, utilization and storage (CCUS) technology has achieved preliminary progress worldwide. This paper summarizes the progress in CO2 geological storage with enhanced oil recovery and enhanced geothermal recovery by literature review and our previous research, the future trend of the CO2 geological storage with enhanced oil recovery and enhanced geothermal recovery is presented. Results show that most CCUS deployment focuses on the CO2 enhanced oil recovery, especially in the conventional oil and gas fields. 0.1-0.6 ton of oil can be produced by each ton of CO2 injection. The way to handle CO2 breakthrough in the producer is the main challenge in the CO2 enhanced oil recovery process. The research on the CO2 enhanced oil recovery will move to the unconventional reservoirs, the future research should focus on increasing amount of CO2 migration into the matrix of the unconventional reservoirs including shale oil and gas reservoirs, and coalbed methane reservoir. In addition, CO2 can be used to enhance geothermal recovery. The research on CO2 enhanced geothermal recovery mainly focuses on the comparisons of water and CO2 as the working fluid. However, the further research on Thermal (T)-Hydro (H)-Mechanical (M)-Chemical (C) coupling with CO2 enhance geothermal recovery is required. The CO2 geological storage with CO2 enhanced oil recovery, enhanced geothermal recovery in the same oil or gas reservoir may become popular in the future CCUS deployment. This paper helps to accelerate the CCUS deployment, to develop the oil and gas fields and heat mining in the same reservoir, and helps to reach the goal of carbon peak and carbon neutrality.
2023, 48(7): 2750-2763.
doi: 10.3799/dqkx.2023.154
Abstract:
A set of organic-rich shale was well-developed at the bottom of Wufeng Formation-Longmaxi Formation in Fuling Area. Based on shale quality and gas-bearing property, this shale reservoir can be vertically subdivided into 9 sublayers, and the lower ①‒⑤ sublayers of high-quality gas-bearing shale are the main layers of development. In 2017, the layering development and adjustment were launched in Jiaoshiba Block, focusing on the upper middle- and low- grade shale gas layers (⑥‒⑨ sublayers) of the first member of Longmaxi Formation. Good results have been achieved through this work. However, this layer has strong plane heterogeneity in terms of quality and thickness, hindering its layering development and adjustment. In this paper, we present a systematic study on the submarine paleogeomorphology and hydrodynamic conditions. Its plane heterogeneity characteristics and main controlling factors for development are clarified through systematic research. The upper gas layer changed from mixed shale facies in the southern and northern Fuling Area to felsic shale facies in the central Zilichang-Baitao area. The shale quality became slightly worse in the central Zilichang-Baitao area. The ⑦ sublayer on the south and north margin of central Zilichang-Baitao area showed a distinct decrease in thickness and its first half was absent. Meanwhile, the ⑦‒⑨ sublayers were also absent in some well regions presenting NE-trending banded distribution. Tectonic volcanism, sea level eustacy, seabed paleogeomorphology, terrigenous input and bottom currents jointly controlled the plane heterogeneity characteristics of this upper gas layer.
A set of organic-rich shale was well-developed at the bottom of Wufeng Formation-Longmaxi Formation in Fuling Area. Based on shale quality and gas-bearing property, this shale reservoir can be vertically subdivided into 9 sublayers, and the lower ①‒⑤ sublayers of high-quality gas-bearing shale are the main layers of development. In 2017, the layering development and adjustment were launched in Jiaoshiba Block, focusing on the upper middle- and low- grade shale gas layers (⑥‒⑨ sublayers) of the first member of Longmaxi Formation. Good results have been achieved through this work. However, this layer has strong plane heterogeneity in terms of quality and thickness, hindering its layering development and adjustment. In this paper, we present a systematic study on the submarine paleogeomorphology and hydrodynamic conditions. Its plane heterogeneity characteristics and main controlling factors for development are clarified through systematic research. The upper gas layer changed from mixed shale facies in the southern and northern Fuling Area to felsic shale facies in the central Zilichang-Baitao area. The shale quality became slightly worse in the central Zilichang-Baitao area. The ⑦ sublayer on the south and north margin of central Zilichang-Baitao area showed a distinct decrease in thickness and its first half was absent. Meanwhile, the ⑦‒⑨ sublayers were also absent in some well regions presenting NE-trending banded distribution. Tectonic volcanism, sea level eustacy, seabed paleogeomorphology, terrigenous input and bottom currents jointly controlled the plane heterogeneity characteristics of this upper gas layer.
2023, 48(7): 2764-2777.
doi: 10.3799/dqkx.2022.412
Abstract:
In order to study the sedimentary source-to-sink processes for marine sediments deposited in the Mentalle Basin of Southeast Indian Ocean from the Oligocene to Miocene, here it conducts the rare earth element (REE) composition analysis on these sediments derived during the International Ocean Discovery Program (IODP) Expedition 369. It characterizes the REE compositions and then analyzes their controlling factors and provenance significance. Among the three standard materials of the chondrite, the post Archean Australian shale (PAAS) and the Upper Continental Crust (UCC), the overall REE compositions of the sample sediment, including the REE contents (ΣREE) and the light REE/heavy REE ratio (ΣLREE/ΣHREE) is close to the characteristics of UCC. The variations of ΣREE, (La/Yb)UCC and (Gd/Yb)UCC are obviously affected by grain size and weathering processes, while ΣLREE/ΣHREE, δEu, (La/Sm)UCC and (Sm/Nd)UCC have no correlation with grain size and weathering proxy. The UCC-normalized REE patterns, discriminant function based on REE composition, and the triangular diagram of Zr-Th-Sc indicate that the Yilgarn Craton is the most likely provenance of Oligocene-Miocene terrestrial sediments from the Mentalle Basin. And the main weathering parent rocks of the Yilgarn Craton change from intermediate-mafic rocks to acidic rocks at 13 Ma. The above provenance research results will lay a solid foundation for the reconstruction of paleoclimate and paleoenvironment in the Southeast Indian Ocean from the Oligocene to Miocene.
In order to study the sedimentary source-to-sink processes for marine sediments deposited in the Mentalle Basin of Southeast Indian Ocean from the Oligocene to Miocene, here it conducts the rare earth element (REE) composition analysis on these sediments derived during the International Ocean Discovery Program (IODP) Expedition 369. It characterizes the REE compositions and then analyzes their controlling factors and provenance significance. Among the three standard materials of the chondrite, the post Archean Australian shale (PAAS) and the Upper Continental Crust (UCC), the overall REE compositions of the sample sediment, including the REE contents (ΣREE) and the light REE/heavy REE ratio (ΣLREE/ΣHREE) is close to the characteristics of UCC. The variations of ΣREE, (La/Yb)UCC and (Gd/Yb)UCC are obviously affected by grain size and weathering processes, while ΣLREE/ΣHREE, δEu, (La/Sm)UCC and (Sm/Nd)UCC have no correlation with grain size and weathering proxy. The UCC-normalized REE patterns, discriminant function based on REE composition, and the triangular diagram of Zr-Th-Sc indicate that the Yilgarn Craton is the most likely provenance of Oligocene-Miocene terrestrial sediments from the Mentalle Basin. And the main weathering parent rocks of the Yilgarn Craton change from intermediate-mafic rocks to acidic rocks at 13 Ma. The above provenance research results will lay a solid foundation for the reconstruction of paleoclimate and paleoenvironment in the Southeast Indian Ocean from the Oligocene to Miocene.
2023, 48(7): 2778-2806.
doi: 10.3799/dqkx.2022.455
Abstract:
Ocean, one of the most important reservoirs of mercury (Hg) on earth, plays a critical role in mediating the global Hg cycling. Recently, Hg isotope approach has shown significant advantages in studying the biogeochemical cycling of oceanic Hg, as it could be used not only to trace marine Hg sources and transformation processes, but also to reconstruct the paleoenvironment and paleoclimate. In this paper, it summarizes analytical methods for accurately measuring Hg isotopes in different marine samples, reported Hg isotopic compositions in seawater, marine sediments and biological samples of different regions worldwide, and elaborates the potential migration and transformation processes that fractionate Hg isotopes in the ocean.Overall, due to the fact that limited data are available for Hg isotopes in the ocean, and the studies on the potential mechanisms and processes fractionating Hg isotopes are still relatively scarce, the systematics of Hg in marine environment and thus the global Hg cycling model still could not be accurately established using Hg isotopes.In the future, it is still necessary to well investigate Hg isotope fractionation during potential biogeochemical processes such as the bioaccumulation and sedimentation, and to deeply decipher the source, migration and transformation of marine Hg using stable isotope approach, in order to provide basic data and theoretical support for improving the global Hg cycling and fairly preventing and controlling marine Hg pollution.
Ocean, one of the most important reservoirs of mercury (Hg) on earth, plays a critical role in mediating the global Hg cycling. Recently, Hg isotope approach has shown significant advantages in studying the biogeochemical cycling of oceanic Hg, as it could be used not only to trace marine Hg sources and transformation processes, but also to reconstruct the paleoenvironment and paleoclimate. In this paper, it summarizes analytical methods for accurately measuring Hg isotopes in different marine samples, reported Hg isotopic compositions in seawater, marine sediments and biological samples of different regions worldwide, and elaborates the potential migration and transformation processes that fractionate Hg isotopes in the ocean.Overall, due to the fact that limited data are available for Hg isotopes in the ocean, and the studies on the potential mechanisms and processes fractionating Hg isotopes are still relatively scarce, the systematics of Hg in marine environment and thus the global Hg cycling model still could not be accurately established using Hg isotopes.In the future, it is still necessary to well investigate Hg isotope fractionation during potential biogeochemical processes such as the bioaccumulation and sedimentation, and to deeply decipher the source, migration and transformation of marine Hg using stable isotope approach, in order to provide basic data and theoretical support for improving the global Hg cycling and fairly preventing and controlling marine Hg pollution.
