2022 Vol. 47, No. 5
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2022, 47(5): 1517-1533.
doi: 10.3799/dqkx.2022.160
Abstract:
After more than ten years of continuous theoretical and technological research, we have achieved the scale development of tight sandstone gas, the rapid development of shale gas, the sustainable development of coalbed methane, the steady development of tight oil and the accelerated exploration of shale oil. Hydrocarbons in source rock strata have become the main component of increasing reserves and production of unconventional oil and gas in China. Hydrocarbons in source rock strata include source rock oil and gas and tight oil and gas. They generally have the basic geological formation conditions of effective allocation of source rock, reservoir and accumulation and preservation, and show the characteristics of continuous distribution in or near the source. Marine shale gas is mainly distributed in the deep-water shelf area, tight sandstone gas and coalbed methane are generally distributed in the coal measures in the main coal accumulation period, and the oil of shale strata is mainly developed in the oil-rich lacustrine basin with long-term continuous subsidence. The oil and gas development of source rock strata pursues better economic resource conditions of "plane sweet area" and "vertical sweet section", in which, shale gas is of high gas content, high porosity, high TOC content, moderate degree of thermal evolution, moderate gas reservoir burial, good preservation conditions, good reservoir compressibility and large reserve scale, where as tight sandstone gas is of all-process gas source, medium coarse-grained sandstone, many gas bearing strata, large-area accumulation, stable slope area and medium and shallow burial. Economic resource conditions of tight oil sweet section generally show "six characteristics" of source rock, reservoir, oiliness, fluidity, fracturing and economy. China is rich in unconventional source rock strata oil and gas resources. Natural gas in source rock strata is the "main force" of natural gas production, and shale oil is the "weight" of stable oil production. Realizing the "two revolutionary field breakthroughs" of deep shale gas, underground coal gasification and continental shale oil conversion is the key path to promote the "leapfrog" development of source rock strata oil and gas field.
After more than ten years of continuous theoretical and technological research, we have achieved the scale development of tight sandstone gas, the rapid development of shale gas, the sustainable development of coalbed methane, the steady development of tight oil and the accelerated exploration of shale oil. Hydrocarbons in source rock strata have become the main component of increasing reserves and production of unconventional oil and gas in China. Hydrocarbons in source rock strata include source rock oil and gas and tight oil and gas. They generally have the basic geological formation conditions of effective allocation of source rock, reservoir and accumulation and preservation, and show the characteristics of continuous distribution in or near the source. Marine shale gas is mainly distributed in the deep-water shelf area, tight sandstone gas and coalbed methane are generally distributed in the coal measures in the main coal accumulation period, and the oil of shale strata is mainly developed in the oil-rich lacustrine basin with long-term continuous subsidence. The oil and gas development of source rock strata pursues better economic resource conditions of "plane sweet area" and "vertical sweet section", in which, shale gas is of high gas content, high porosity, high TOC content, moderate degree of thermal evolution, moderate gas reservoir burial, good preservation conditions, good reservoir compressibility and large reserve scale, where as tight sandstone gas is of all-process gas source, medium coarse-grained sandstone, many gas bearing strata, large-area accumulation, stable slope area and medium and shallow burial. Economic resource conditions of tight oil sweet section generally show "six characteristics" of source rock, reservoir, oiliness, fluidity, fracturing and economy. China is rich in unconventional source rock strata oil and gas resources. Natural gas in source rock strata is the "main force" of natural gas production, and shale oil is the "weight" of stable oil production. Realizing the "two revolutionary field breakthroughs" of deep shale gas, underground coal gasification and continental shale oil conversion is the key path to promote the "leapfrog" development of source rock strata oil and gas field.
2022, 47(5): 1534-1548.
doi: 10.3799/dqkx.2021.249
Abstract:
In recent years, many large oil and gas fields of the Archaean buried hills in the Bohai Sea have been discovered, among which, the natural gas reserves of Bozhong 19-6 structure exceed 100 billion cubic meters, showing the huge exploration potential in this field. The scale of buried hill reservoirs is the key factor restricting the exploration of metamorphic rock. It is of great theoretical and practical significance to study the formation conditions of large-scale buried hill reservoirs. Based on the experimental data of cores, thin sections, scanning electron microscopy and seismic data, in this paper it systematically analyzes the formation conditions of several large metamorphic buried hill reservoirs in the Bohai Sea area. The results show follows: (1) The brittle felsic minerals are the important material basis for the development of large buried hill reservoirs of Archean metamorphic rocks in Bohai Sea area, which are not only conducive to the development of fractures, but also provide favorable conditions for weathering leaching and dissolution of deep fluids. (2) The multiple types of compressive structures control the formation of large fractured reservoirs. (3) Weathering and leaching is an important factor in the vertical zonation of Archean buried hill reservoir, which obviously controls the vertical development of Archean buried hill reservoirs. (4) The deep fluid plays an important role in improving the Archean buried hill reservoirs, expanding the scale of fractures. Under the guidance of the above formation conditions, the genetic model of Archean large buried hill reservoirs is established.
In recent years, many large oil and gas fields of the Archaean buried hills in the Bohai Sea have been discovered, among which, the natural gas reserves of Bozhong 19-6 structure exceed 100 billion cubic meters, showing the huge exploration potential in this field. The scale of buried hill reservoirs is the key factor restricting the exploration of metamorphic rock. It is of great theoretical and practical significance to study the formation conditions of large-scale buried hill reservoirs. Based on the experimental data of cores, thin sections, scanning electron microscopy and seismic data, in this paper it systematically analyzes the formation conditions of several large metamorphic buried hill reservoirs in the Bohai Sea area. The results show follows: (1) The brittle felsic minerals are the important material basis for the development of large buried hill reservoirs of Archean metamorphic rocks in Bohai Sea area, which are not only conducive to the development of fractures, but also provide favorable conditions for weathering leaching and dissolution of deep fluids. (2) The multiple types of compressive structures control the formation of large fractured reservoirs. (3) Weathering and leaching is an important factor in the vertical zonation of Archean buried hill reservoir, which obviously controls the vertical development of Archean buried hill reservoirs. (4) The deep fluid plays an important role in improving the Archean buried hill reservoirs, expanding the scale of fractures. Under the guidance of the above formation conditions, the genetic model of Archean large buried hill reservoirs is established.
2022, 47(5): 1549-1568.
doi: 10.3799/dqkx.2021.119
Abstract:
The natural gas hydrate exploration and evaluation of South China Sea are mainly concentrated in continental margin slope deep water area of the northern South China Sea in the last 20 years. Major breakthroughs in the exploration and production of natural gas hydrate have been made in Shenhu area, Dongsha area and Lingshui-Songnan area of Qiongdongnan basin, where three billions of cubic meters of reserves of natural gas hydrate reservoir were found. A preliminary evaluation prediction about the south China sea natural gas hydrate resources is scale of 80 billion tons of oil equivalent, which has made major achievements in the natural gas hydrate exploration stage of South China Sea. However, where are the gas hydrate resources beneficial areas to further deepen and expand exploration in the South China Sea? In particular, where are the strategic replacement areas for sustainable rolling exploration? Is there any geological condition for gas hydrate formation in the continental slope-ocean continent transition (OCT) zone or even ocean basin area which is closely adjacent to the exploration of oil, gas and hydrate in deep water of continental slope at present? In this paper it intends to make a preliminary analysis and discussion on the key issues affecting and determining the future deployment and trend of gas hydrate exploration. It is hoped that it can be of some benefit to the exploration and evaluation of gas hydrate resources in the South China Sea and the selection of strategic replacement areas.
The natural gas hydrate exploration and evaluation of South China Sea are mainly concentrated in continental margin slope deep water area of the northern South China Sea in the last 20 years. Major breakthroughs in the exploration and production of natural gas hydrate have been made in Shenhu area, Dongsha area and Lingshui-Songnan area of Qiongdongnan basin, where three billions of cubic meters of reserves of natural gas hydrate reservoir were found. A preliminary evaluation prediction about the south China sea natural gas hydrate resources is scale of 80 billion tons of oil equivalent, which has made major achievements in the natural gas hydrate exploration stage of South China Sea. However, where are the gas hydrate resources beneficial areas to further deepen and expand exploration in the South China Sea? In particular, where are the strategic replacement areas for sustainable rolling exploration? Is there any geological condition for gas hydrate formation in the continental slope-ocean continent transition (OCT) zone or even ocean basin area which is closely adjacent to the exploration of oil, gas and hydrate in deep water of continental slope at present? In this paper it intends to make a preliminary analysis and discussion on the key issues affecting and determining the future deployment and trend of gas hydrate exploration. It is hoped that it can be of some benefit to the exploration and evaluation of gas hydrate resources in the South China Sea and the selection of strategic replacement areas.
2022, 47(5): 1569-1585.
doi: 10.3799/dqkx.2021.190
Abstract:
The gravity flow channel and subsea fan reservoirs of the middle and deep Huangliu Formation-Meishan Formation in Ledong 10 area of Yinggehai basin have been proved to have great natural gas resource potential. However, the preliminary test results show that the gas reservoir was mixed with high content of CO2 gas. Therefore, fine determination of natural gas charging periods and clear spatial and temporal distribution rules such as CH4 and CO2 are crucial to avoid high CO2 risks. In this study, based on the detailed observation of the petrographic characteristics of fluid inclusions with different occurrences, combined with laser Raman spectroscopy analysis and inclusions microscopic temperature measurement technology, three stages of natural gas charging with different components were identified at 4.0-2.9 Ma, 2.0-1.2 Ma and 0.8-0.3 Ma, respectively. Among them, the first stage of charging is mainly hydrocarbon gas, accompanied by a small amount of organic CO2 and N2. The second and third acts of charging were dominated by a large amount of inorganic CO2 and hydrocarbon gas, accompanied by a small amount of N2. Combined with the geochemical characteristics of natural gas and source rock, natural gas component analysis and transportation system identification, the accumulation model of Ledong 10 area is summarized, in order to provide a basis for the next gas exploration and development in the study area and to avoid the risk of high CO2 content.
The gravity flow channel and subsea fan reservoirs of the middle and deep Huangliu Formation-Meishan Formation in Ledong 10 area of Yinggehai basin have been proved to have great natural gas resource potential. However, the preliminary test results show that the gas reservoir was mixed with high content of CO2 gas. Therefore, fine determination of natural gas charging periods and clear spatial and temporal distribution rules such as CH4 and CO2 are crucial to avoid high CO2 risks. In this study, based on the detailed observation of the petrographic characteristics of fluid inclusions with different occurrences, combined with laser Raman spectroscopy analysis and inclusions microscopic temperature measurement technology, three stages of natural gas charging with different components were identified at 4.0-2.9 Ma, 2.0-1.2 Ma and 0.8-0.3 Ma, respectively. Among them, the first stage of charging is mainly hydrocarbon gas, accompanied by a small amount of organic CO2 and N2. The second and third acts of charging were dominated by a large amount of inorganic CO2 and hydrocarbon gas, accompanied by a small amount of N2. Combined with the geochemical characteristics of natural gas and source rock, natural gas component analysis and transportation system identification, the accumulation model of Ledong 10 area is summarized, in order to provide a basis for the next gas exploration and development in the study area and to avoid the risk of high CO2 content.
2022, 47(5): 1586-1603.
doi: 10.3799/dqkx.2021.214
Abstract:
The Lower Cambrian Niutitang Formation (∈1n) is one of the important shale gas target reservoirs in Hubei Province, China. The deep study of the ∈1n helps to calculate the resource potential and indicate exploration direction. Based on outcrop profiles and wells, the characteristics of shale reservoir and resource potential of the ∈1n were deeply studied. The results show that the ∈1n can be divided into two sections, the first section (∈1n1) and the second section (∈1n2). The organic-rich shales of Yichang-Enshi and Shennongjia in West Hubei and Tongshan-Chongyang area in eastern Hubei are characterized by large thickness, high TOC and silica content, which indicates a good material foundation and shale gas resource potential. The area with high gas content is mainly distributed in the southeast slope of Huangling anticline in Yichang, West Hubei. The weak deformation, the effective roof and floor, and moderate thermal evolution are the key factors for the enrichment of Niutitang shale gas reservoir. In addition to Yichang area, Zigui and Hefeng areas are also worthy of further exploration. Due to the strong tectonic deformation and magmatic activity, there is no shale gas exploration prospect in Southeast Hubei and Northwest Hubei.
The Lower Cambrian Niutitang Formation (∈1n) is one of the important shale gas target reservoirs in Hubei Province, China. The deep study of the ∈1n helps to calculate the resource potential and indicate exploration direction. Based on outcrop profiles and wells, the characteristics of shale reservoir and resource potential of the ∈1n were deeply studied. The results show that the ∈1n can be divided into two sections, the first section (∈1n1) and the second section (∈1n2). The organic-rich shales of Yichang-Enshi and Shennongjia in West Hubei and Tongshan-Chongyang area in eastern Hubei are characterized by large thickness, high TOC and silica content, which indicates a good material foundation and shale gas resource potential. The area with high gas content is mainly distributed in the southeast slope of Huangling anticline in Yichang, West Hubei. The weak deformation, the effective roof and floor, and moderate thermal evolution are the key factors for the enrichment of Niutitang shale gas reservoir. In addition to Yichang area, Zigui and Hefeng areas are also worthy of further exploration. Due to the strong tectonic deformation and magmatic activity, there is no shale gas exploration prospect in Southeast Hubei and Northwest Hubei.
2022, 47(5): 1604-1618.
doi: 10.3799/dqkx.2022.007
Abstract:
The He-1 Member of Hangjinqi block in Ordos basin is rich in natural gas, but the reservoir is dense and heterogeneous which restricts the increase of natural gas storage and production in this area. In this paper it makes full use of cores, casting thin section observation, field emission scanning electron microscopy (FE-SEM) observation, porosity and permeability test, X-ray diffraction (XRD) analysis, high-pressure mercury injection and constant-rate mercury injection analysis to illustrate the reservoir characteristics and controlling factors of He-1 Member in the study area. Based on that, the reservoirs are divided into superior reservoirs and poor reservoirs. The superior reservoirs are mainly composed of coarse-grained sublitharenite and litharenite developed in diara with less matrix and developed dissolution pores. The poor reservoirs are mainly composed of fine-grained litharenite developed with much matrix and undeveloped pores. The difference of provenance resulted in higher quartz content in the west than in the east. The strength of hydrodynamic condition is the initial condition that determines the quality of reservoir. Early argillaceous filling results in lower original porosity in poor reservoirs. The superior reservoir is more resistant to overburden pressure due to the less matrix. And the pore fluid is more active in superior reservoir which is benefitial to the formation of disolutionpore.
The He-1 Member of Hangjinqi block in Ordos basin is rich in natural gas, but the reservoir is dense and heterogeneous which restricts the increase of natural gas storage and production in this area. In this paper it makes full use of cores, casting thin section observation, field emission scanning electron microscopy (FE-SEM) observation, porosity and permeability test, X-ray diffraction (XRD) analysis, high-pressure mercury injection and constant-rate mercury injection analysis to illustrate the reservoir characteristics and controlling factors of He-1 Member in the study area. Based on that, the reservoirs are divided into superior reservoirs and poor reservoirs. The superior reservoirs are mainly composed of coarse-grained sublitharenite and litharenite developed in diara with less matrix and developed dissolution pores. The poor reservoirs are mainly composed of fine-grained litharenite developed with much matrix and undeveloped pores. The difference of provenance resulted in higher quartz content in the west than in the east. The strength of hydrodynamic condition is the initial condition that determines the quality of reservoir. Early argillaceous filling results in lower original porosity in poor reservoirs. The superior reservoir is more resistant to overburden pressure due to the less matrix. And the pore fluid is more active in superior reservoir which is benefitial to the formation of disolutionpore.
2022, 47(5): 1619-1634.
doi: 10.3799/dqkx.2022.094
Abstract:
Following the successful production test of natural gas hydrate in the Shenhu area in China, the exploration in the Qiongdongnan basin in recent years has confirmed the existence of natural gas hydrate, which shows a complex symbiotic relationship with shallow gas by the drilling. In order to reveal the accumulation characteristics of gas hydrate-shallow gas symbiotic system in the deep water area of the Qiongdongnan basin, combining core photos, logging data, and three-dimensional seismic data, the spatial distribution characteristics of gas hydrate and shallow gas is expounded in the study area.The research results show that gas hydrate mainly exists in sandy sediments above -200 m below the seafloor, and its formation process is related to the vertical migration of shallow gas. The deep analysis of the accumulation characteristics of gas hydrate and shallow gas symbiotic system shows that deep thermogenic gas and shallow biogenic gas are the vital gas source. The unconsolidated sand layer in the Quaternary strata is a high-quality reservoir. The distribution of gas hydrate and shallow gas symbiotic system is mainly affected by deep gas chimneys and faults. Shallow gas has been providing stable gas source for gas hydrate. The mass transport deposits and gas hydrate-bearing sediments developed in the Quaternary strata can effectively block the vertical migration of natural gas and further promote the accumulation of shallow gas. Therefore, there are positive feedback interactions between the formation of gas hydrate and the development of shallow gas, which are conducive to the formation of larger gas hydrate ore bodies and shallow gas reservoirs, and have good commercial development potential.
Following the successful production test of natural gas hydrate in the Shenhu area in China, the exploration in the Qiongdongnan basin in recent years has confirmed the existence of natural gas hydrate, which shows a complex symbiotic relationship with shallow gas by the drilling. In order to reveal the accumulation characteristics of gas hydrate-shallow gas symbiotic system in the deep water area of the Qiongdongnan basin, combining core photos, logging data, and three-dimensional seismic data, the spatial distribution characteristics of gas hydrate and shallow gas is expounded in the study area.The research results show that gas hydrate mainly exists in sandy sediments above -200 m below the seafloor, and its formation process is related to the vertical migration of shallow gas. The deep analysis of the accumulation characteristics of gas hydrate and shallow gas symbiotic system shows that deep thermogenic gas and shallow biogenic gas are the vital gas source. The unconsolidated sand layer in the Quaternary strata is a high-quality reservoir. The distribution of gas hydrate and shallow gas symbiotic system is mainly affected by deep gas chimneys and faults. Shallow gas has been providing stable gas source for gas hydrate. The mass transport deposits and gas hydrate-bearing sediments developed in the Quaternary strata can effectively block the vertical migration of natural gas and further promote the accumulation of shallow gas. Therefore, there are positive feedback interactions between the formation of gas hydrate and the development of shallow gas, which are conducive to the formation of larger gas hydrate ore bodies and shallow gas reservoirs, and have good commercial development potential.
2022, 47(5): 1635-1651.
doi: 10.3799/dqkx.2021.244
Abstract:
Middle-deep layers in Baiyun sag have great potential for unexplored hydrocarbon resources. Reservoirs in the middle-deep layers are generally of low porosity and permeability. In order to describe the favorable reservoir characteristics, to find the reservoir macro-controlling factors, and to predict the special distribution of the favorable reservoirs, Baiyun 5A structure in Baiyun sag was studied. Taking middle-deep layers of Baiyun 5A structures for example, the microcosmic aspects such as reservoir lithology, reservoir properties, and constructive diagenesis and the macro aspects such as facies identification, prediction of progradation complex with thick sand, seismic inversion for sand and porosity, and fracture distribution recognition of reservoir are studied. Reservoir "sweet points" characteristics in the middle-deep layers, controlling factors that can be identified macroscopically, and special distribution of the "sweet points" are studied. It suggests that middle-coarse sandstones with big thickness in the distributary channels and underwater distributary channels in the Baiyun 5A structure developed secondary solution caves and microfractures, and these sandstones can be used as reservoir "sweet points". Sand body thickness that represents its microfacies and fractures that represent the constructive diagenesis are controlling factors that can be identified macroscopically for reservoir "sweet points" prediction. Progradation complex with thick sand can be identified through the shape of "bump", the superposed inside structure, and the low part of the microrelief in the seismic data. Combining the results of thick sand body identification, sand and porosity prediction, and fracture distribution recognition, the eastern part of the C block in the Baiyun 5A structure is recognized as the reservoir "sweet points".
Middle-deep layers in Baiyun sag have great potential for unexplored hydrocarbon resources. Reservoirs in the middle-deep layers are generally of low porosity and permeability. In order to describe the favorable reservoir characteristics, to find the reservoir macro-controlling factors, and to predict the special distribution of the favorable reservoirs, Baiyun 5A structure in Baiyun sag was studied. Taking middle-deep layers of Baiyun 5A structures for example, the microcosmic aspects such as reservoir lithology, reservoir properties, and constructive diagenesis and the macro aspects such as facies identification, prediction of progradation complex with thick sand, seismic inversion for sand and porosity, and fracture distribution recognition of reservoir are studied. Reservoir "sweet points" characteristics in the middle-deep layers, controlling factors that can be identified macroscopically, and special distribution of the "sweet points" are studied. It suggests that middle-coarse sandstones with big thickness in the distributary channels and underwater distributary channels in the Baiyun 5A structure developed secondary solution caves and microfractures, and these sandstones can be used as reservoir "sweet points". Sand body thickness that represents its microfacies and fractures that represent the constructive diagenesis are controlling factors that can be identified macroscopically for reservoir "sweet points" prediction. Progradation complex with thick sand can be identified through the shape of "bump", the superposed inside structure, and the low part of the microrelief in the seismic data. Combining the results of thick sand body identification, sand and porosity prediction, and fracture distribution recognition, the eastern part of the C block in the Baiyun 5A structure is recognized as the reservoir "sweet points".
2022, 47(5): 1652-1668.
doi: 10.3799/dqkx.2021.152
Abstract:
The tectonic-thermal evolution history of the Meso-Cenozoic rift basin in the South Yellow Sea is established by using Advanced McKenzie geodynamic model and Easy%RoDL chemical kinetic model, combined with the deep crust and lithospheric mantle structure of the basin, the process of Meso-Cenozoic plate convergence and dispersion around the basin is analyzed. In addition, the genesis of low geothermal state, basin-forming mechanism and thermal evolution of source rocks in the basin are discussed. The results show that the crustal extension coefficient is of about 1.22 and the lithospheric mantle extension coefficient is of about 1.06. From the rift period to the present, the maximum heat flow value only decreased from 76 mW/m2 to 66 mW/m2, and the maximum geothermal gradient only decreased from 37 ℃/km to 30 ℃/km. It is revealed that the low geothermal state runs through the whole rift basin development stage for the first time. Low lithospheric mantle extension coefficient, deep non-mirror Moho distribution, the development stage of the basin are only in the far field tensile stress environment behind the arc, all indicate that the low intensity of lithospheric mantle extension and asthenosphere upwelling is low that is the fundamental reason for the continuous low geothermal state of the basin, and the deep thermal stress is not the main power source of the basin formation. According to the high crustal extension coefficient and the evolution of the detachment fault, it is suggested that the Indosinian and Yanshanian thrust fault regenerated to form the intra-crustal detachment system, and controlled the development of rift basin by simple shear deformation, which is the basic basin-forming mechanism. The main oil expulsion of the source rocks in the southern and northern depressions is the sedimentary period of the second member of the Sanduo Formation, and the thermal evolution of the source rocks ended since the Oligocene tectonic inversion. Paleo-buried depth and paleo-geothermal field jointly control the thermal maturity differences of source rocks at the present same depth in the southern and northern depressions.
The tectonic-thermal evolution history of the Meso-Cenozoic rift basin in the South Yellow Sea is established by using Advanced McKenzie geodynamic model and Easy%RoDL chemical kinetic model, combined with the deep crust and lithospheric mantle structure of the basin, the process of Meso-Cenozoic plate convergence and dispersion around the basin is analyzed. In addition, the genesis of low geothermal state, basin-forming mechanism and thermal evolution of source rocks in the basin are discussed. The results show that the crustal extension coefficient is of about 1.22 and the lithospheric mantle extension coefficient is of about 1.06. From the rift period to the present, the maximum heat flow value only decreased from 76 mW/m2 to 66 mW/m2, and the maximum geothermal gradient only decreased from 37 ℃/km to 30 ℃/km. It is revealed that the low geothermal state runs through the whole rift basin development stage for the first time. Low lithospheric mantle extension coefficient, deep non-mirror Moho distribution, the development stage of the basin are only in the far field tensile stress environment behind the arc, all indicate that the low intensity of lithospheric mantle extension and asthenosphere upwelling is low that is the fundamental reason for the continuous low geothermal state of the basin, and the deep thermal stress is not the main power source of the basin formation. According to the high crustal extension coefficient and the evolution of the detachment fault, it is suggested that the Indosinian and Yanshanian thrust fault regenerated to form the intra-crustal detachment system, and controlled the development of rift basin by simple shear deformation, which is the basic basin-forming mechanism. The main oil expulsion of the source rocks in the southern and northern depressions is the sedimentary period of the second member of the Sanduo Formation, and the thermal evolution of the source rocks ended since the Oligocene tectonic inversion. Paleo-buried depth and paleo-geothermal field jointly control the thermal maturity differences of source rocks at the present same depth in the southern and northern depressions.
2022, 47(5): 1669-1683.
doi: 10.3799/dqkx.2022.036
Abstract:
The Neogene LD5 extra-heavy oil reservoir in Liaodongwan depression shows special phenomena of high porosity and permeability, inconsistent oil-water relationship and wavy interface. In this paper it presents a study on the oil source correlation, crude oil thickening, lithologic facies of reservoir and classification of pore throat types. The analysis shows that LD5 reservoir is a secondary reservoir, and the crude oil is low-maturity heavy oil from E2s3 in the southwest of Liaoxi sag. In the early stage, the crude oil gathered and reservoirs formed in the Dongying Formation, which were destroyed by neotectonic movement and migrated to shallow formation in the later stage. Secondary thickening occurred in the secondary migration, and as a result, the crude oil had been thickened into secondary heavy oil before accumulation in the shallow layer, which provided a prerequisite for abnormal oil-water relationship. Braided fluvial deposits developed in the Neogene in the study area, 4 kinds of sedimentary microfacies and 10 lithologic facies were identified in braided fluvial facies. Sedimentation affects reservoir permeability by controlling the microscopic pore-throat types of different lithologic facies, and then determines the filling efficiency of heavy oil. The interbedded sand conglomerate reservoir is mainly composed of massive bedding conglomerate facies and large cross bedding sand conglomerate facies, with narrow throat leading to low reservoir permeability, resulting in physical plugging, restricting secondary heavy oil charging and forming water layer. After the secondary heavy oil entered reservoir, the free flow of crude oil was limited due to its high density and viscosity, so it could not replace with pore water in time to form a horizontal oil-water interface. Instead, it was pushed into the reservoir by external pressure in an inclined manner. During the filling process, the reservoir with high permeability was preferentially charged, and the crude oil no longer flowed after the filling stopped, and the low-permeability reservoir was not filled at this time, thus forming the phenomena of inconsistent oil-water relationship and wavy interface.
The Neogene LD5 extra-heavy oil reservoir in Liaodongwan depression shows special phenomena of high porosity and permeability, inconsistent oil-water relationship and wavy interface. In this paper it presents a study on the oil source correlation, crude oil thickening, lithologic facies of reservoir and classification of pore throat types. The analysis shows that LD5 reservoir is a secondary reservoir, and the crude oil is low-maturity heavy oil from E2s3 in the southwest of Liaoxi sag. In the early stage, the crude oil gathered and reservoirs formed in the Dongying Formation, which were destroyed by neotectonic movement and migrated to shallow formation in the later stage. Secondary thickening occurred in the secondary migration, and as a result, the crude oil had been thickened into secondary heavy oil before accumulation in the shallow layer, which provided a prerequisite for abnormal oil-water relationship. Braided fluvial deposits developed in the Neogene in the study area, 4 kinds of sedimentary microfacies and 10 lithologic facies were identified in braided fluvial facies. Sedimentation affects reservoir permeability by controlling the microscopic pore-throat types of different lithologic facies, and then determines the filling efficiency of heavy oil. The interbedded sand conglomerate reservoir is mainly composed of massive bedding conglomerate facies and large cross bedding sand conglomerate facies, with narrow throat leading to low reservoir permeability, resulting in physical plugging, restricting secondary heavy oil charging and forming water layer. After the secondary heavy oil entered reservoir, the free flow of crude oil was limited due to its high density and viscosity, so it could not replace with pore water in time to form a horizontal oil-water interface. Instead, it was pushed into the reservoir by external pressure in an inclined manner. During the filling process, the reservoir with high permeability was preferentially charged, and the crude oil no longer flowed after the filling stopped, and the low-permeability reservoir was not filled at this time, thus forming the phenomena of inconsistent oil-water relationship and wavy interface.
2022, 47(5): 1684-1693.
doi: 10.3799/dqkx.2022.021
Abstract:
Fracture veins contain important information such as natural fracture evolution and paleo-fluid injection activities, which is also indicative of the preservation conditions of deep shale gas. In this paper, the development characteristics of fractures and veins in the deep shale of Longmaxi Formation in Luzhou block were analyzed by means of optical thin section, cathode luminescence, fluid inclusion and in-situ microanalysis, and the activity of vein-forming fluid and its diagenetic environment evolution were studied, and the preservation conditions of shale gas were discussed. It is found that the deep shale fracture vein is mainly a composite vein composed of quartz, dolomite or calcite, showing a complex cutting relationship between different minerals, a large number of brine inclusions and high-density methane inclusions are developed, and the fracture vein is mainly formed in a reducing environment. On the whole, under the background of tectonic uplift, the deep shale fractures began to form and were in the process of continuous opening or closing. The three stages of paleo-fluid with different properties were filled and cemented for many times, and the closed diagenetic system was favorable for the preservation of the deep shale gas.
Fracture veins contain important information such as natural fracture evolution and paleo-fluid injection activities, which is also indicative of the preservation conditions of deep shale gas. In this paper, the development characteristics of fractures and veins in the deep shale of Longmaxi Formation in Luzhou block were analyzed by means of optical thin section, cathode luminescence, fluid inclusion and in-situ microanalysis, and the activity of vein-forming fluid and its diagenetic environment evolution were studied, and the preservation conditions of shale gas were discussed. It is found that the deep shale fracture vein is mainly a composite vein composed of quartz, dolomite or calcite, showing a complex cutting relationship between different minerals, a large number of brine inclusions and high-density methane inclusions are developed, and the fracture vein is mainly formed in a reducing environment. On the whole, under the background of tectonic uplift, the deep shale fractures began to form and were in the process of continuous opening or closing. The three stages of paleo-fluid with different properties were filled and cemented for many times, and the closed diagenetic system was favorable for the preservation of the deep shale gas.
2022, 47(5): 1694-1710.
doi: 10.3799/dqkx.2021.188
Abstract:
To decipher the fluid action and pore evolution in the Carboniferous altered tuff reservoir in Kelameili gas field (Junggar basin, Northwest China), the petrography and geochemistry were studied by core and thin section observation, scanning electron microscopy, electron probe, cathodoluminescence, fluorescence, rare elements and U-Pb isotope dating, etc.. The results show that the pore filling minerals of reservoir in the well Dixi 14 area mainly include kaolinite, albite, quartz, chlorite, pyrite, apatite, and the pore types are mainly residual pores of feldspar (K-feldspar and plagioclase) by dissolution-infilling and intergranular pores of various authigenic minerals. Firstly, the dissolution of pyroclastic materials and the transformation of diagenetic materials were fundamental for the formation of authigenic mineral. A large number of mold pores in crystal pyroclast were formed by acid fluid dissolution and kaolinite and quartz were precipitated from pores. More importantly, diagenetic environment changes caused by burial, hydrocarbon generation, hydrothermal charging and other activities are significant for pore formation and evolution. Albite and calcite were precipitated in dissolved pores by the fluid transformation from acid to alkaline, and resulted in the rapidly decrease of pores. During Middle Yanshanian (135±27 Ma), the thermal events were critical for the formation and evolution of the reservoir. (1) The illite of matrix was transformed into K-feldspar by the recharge of high temperature and rich-silicon hydrothermal fluid. (2) Simultaneously, fluoapatite and titanite were precipitated by combination of P, Ti, F ions with Ca2+ ion that derived by secondary dissolution, and filled the pores. Quartz was precipitated in the pore by the oversaturation of SiO2 fluid. Thereafter, arsenopyrite and chlorite were formed by the transformation of alkaline and redox condition in the process of burial diagenesis. Thus, devitrification caused by temperature elevation, mineral transformation from clay to zeolite, recrystallization and dissolution partly increased the secondary reservoir space, which is beneficial to the enrichment of hydrocarbon.
To decipher the fluid action and pore evolution in the Carboniferous altered tuff reservoir in Kelameili gas field (Junggar basin, Northwest China), the petrography and geochemistry were studied by core and thin section observation, scanning electron microscopy, electron probe, cathodoluminescence, fluorescence, rare elements and U-Pb isotope dating, etc.. The results show that the pore filling minerals of reservoir in the well Dixi 14 area mainly include kaolinite, albite, quartz, chlorite, pyrite, apatite, and the pore types are mainly residual pores of feldspar (K-feldspar and plagioclase) by dissolution-infilling and intergranular pores of various authigenic minerals. Firstly, the dissolution of pyroclastic materials and the transformation of diagenetic materials were fundamental for the formation of authigenic mineral. A large number of mold pores in crystal pyroclast were formed by acid fluid dissolution and kaolinite and quartz were precipitated from pores. More importantly, diagenetic environment changes caused by burial, hydrocarbon generation, hydrothermal charging and other activities are significant for pore formation and evolution. Albite and calcite were precipitated in dissolved pores by the fluid transformation from acid to alkaline, and resulted in the rapidly decrease of pores. During Middle Yanshanian (135±27 Ma), the thermal events were critical for the formation and evolution of the reservoir. (1) The illite of matrix was transformed into K-feldspar by the recharge of high temperature and rich-silicon hydrothermal fluid. (2) Simultaneously, fluoapatite and titanite were precipitated by combination of P, Ti, F ions with Ca2+ ion that derived by secondary dissolution, and filled the pores. Quartz was precipitated in the pore by the oversaturation of SiO2 fluid. Thereafter, arsenopyrite and chlorite were formed by the transformation of alkaline and redox condition in the process of burial diagenesis. Thus, devitrification caused by temperature elevation, mineral transformation from clay to zeolite, recrystallization and dissolution partly increased the secondary reservoir space, which is beneficial to the enrichment of hydrocarbon.
2022, 47(5): 1711-1727.
doi: 10.3799/dqkx.2021.207
Abstract:
In order to clarify the influencing factors and accumulation model of gas hydrate in the southern low uplift and its surrounding area of Qiongdongnan basin, using drilling, logging and 2D/3D seismic data obtained from gas hydrate drilling, the geological and geophysical characteristics of gas hydrate occurrence in the study area are analyzed, and the influencing factors of hydrate accumulation control are discussed, and the gas hydrate accumulation model is established. The results show that the southern low uplift of Qiongdongnan basin and its surrounding areas are located in the dominant direction of deep fluid transport on the southern slope of the central depression zone. Gas hydrate drilling at multiple stations shows that the gas hydrate has the characteristics of stratified and multi-type reservoirs. In logging, gas hydrate formation is characterized by high resistivity and low acoustic.The seismic profile analysis shows that the gas filling at the top of gas chimney is obvious, and the gas vertical migration is limited. The gas source of hydrate in the study area is both biogenic and thermogenic gas. Faults, gas chimney and and pore fracture leakage system provide good transportation conditions for the migration of thermogenic gas. The rapid accumulation of shallow mass transport deposits makes it difficult for the internal pore fluid to discharge rapidly, so the pore fluid pressure is higher than that of the overlying and underlying strata, which hinders the vertical dispersion of the underlying fluid and forms a sealing effect. Overpressure sealing layer is the main controlling factor of hydrate in multi-type reservoirs in the study area. According to the difference of sealing ability and its influence on gas hydrate accumulation, two types of hydrate accumulation and enrichment models of closed system and open system are summarized.
In order to clarify the influencing factors and accumulation model of gas hydrate in the southern low uplift and its surrounding area of Qiongdongnan basin, using drilling, logging and 2D/3D seismic data obtained from gas hydrate drilling, the geological and geophysical characteristics of gas hydrate occurrence in the study area are analyzed, and the influencing factors of hydrate accumulation control are discussed, and the gas hydrate accumulation model is established. The results show that the southern low uplift of Qiongdongnan basin and its surrounding areas are located in the dominant direction of deep fluid transport on the southern slope of the central depression zone. Gas hydrate drilling at multiple stations shows that the gas hydrate has the characteristics of stratified and multi-type reservoirs. In logging, gas hydrate formation is characterized by high resistivity and low acoustic.The seismic profile analysis shows that the gas filling at the top of gas chimney is obvious, and the gas vertical migration is limited. The gas source of hydrate in the study area is both biogenic and thermogenic gas. Faults, gas chimney and and pore fracture leakage system provide good transportation conditions for the migration of thermogenic gas. The rapid accumulation of shallow mass transport deposits makes it difficult for the internal pore fluid to discharge rapidly, so the pore fluid pressure is higher than that of the overlying and underlying strata, which hinders the vertical dispersion of the underlying fluid and forms a sealing effect. Overpressure sealing layer is the main controlling factor of hydrate in multi-type reservoirs in the study area. According to the difference of sealing ability and its influence on gas hydrate accumulation, two types of hydrate accumulation and enrichment models of closed system and open system are summarized.
2022, 47(5): 1728-1747.
doi: 10.3799/dqkx.2022.015
Abstract:
JLYY-1 well was drilled to explore the continental shale gas resources by the China Geological Survey of the Shahezi Formation in the south of Songliao basin, where 51 m hybrid sedimentary shale layer contributed to a high-yield shale gas breakthrough. Through coring observation and indoor comprehensive analysis, it is found that this set of 51 m shale has the following characteristics. First, hybrid sedimentary(carbonate minerals and siliceous minerals account for a high proportion, followed by volcanic materials). Second, shale is intercalated with multiple sets of thin-layer tuff or tuffaceous mud/shale. Thirdly, a large number of bubbles gushing along the foliation surface were observed in the field core immersion experiment. Based on the element logging data of well JLYY-1, combined with the test results of scanning electron microscope imaging, optical microscopic imaging, and Roqscan mineral composition imaging, it is summarized as the formation mode of organic-rich hybrid sedimentary shale in the faulted continental basin during volcanic activity periods, and the formation conditions are as follows. (1) The input of multiple organic sources improves the abundance of organic matter in shale contributing to the co-preservation of type Ⅰ, Ⅱ and type Ⅲ kerogens. (2) In the later stage of volcanic activity, the migration of nutrient elements leads to algae bloom in the intervening shales. (3) Carbonate diagenesis contributes to hydrocarbon generation in the hybrid sedimentary shales which are sedimented in a closed saltwater environment under dry and hot climates. (4) The oxidation stratification of the water body forms four types of laminae of shale in this section: siliceous, clayey, calcareous, and pyrite laminae.
JLYY-1 well was drilled to explore the continental shale gas resources by the China Geological Survey of the Shahezi Formation in the south of Songliao basin, where 51 m hybrid sedimentary shale layer contributed to a high-yield shale gas breakthrough. Through coring observation and indoor comprehensive analysis, it is found that this set of 51 m shale has the following characteristics. First, hybrid sedimentary(carbonate minerals and siliceous minerals account for a high proportion, followed by volcanic materials). Second, shale is intercalated with multiple sets of thin-layer tuff or tuffaceous mud/shale. Thirdly, a large number of bubbles gushing along the foliation surface were observed in the field core immersion experiment. Based on the element logging data of well JLYY-1, combined with the test results of scanning electron microscope imaging, optical microscopic imaging, and Roqscan mineral composition imaging, it is summarized as the formation mode of organic-rich hybrid sedimentary shale in the faulted continental basin during volcanic activity periods, and the formation conditions are as follows. (1) The input of multiple organic sources improves the abundance of organic matter in shale contributing to the co-preservation of type Ⅰ, Ⅱ and type Ⅲ kerogens. (2) In the later stage of volcanic activity, the migration of nutrient elements leads to algae bloom in the intervening shales. (3) Carbonate diagenesis contributes to hydrocarbon generation in the hybrid sedimentary shales which are sedimented in a closed saltwater environment under dry and hot climates. (4) The oxidation stratification of the water body forms four types of laminae of shale in this section: siliceous, clayey, calcareous, and pyrite laminae.
2022, 47(5): 1748-1761.
doi: 10.3799/dqkx.2021.160
Abstract:
The genesis of volcanic reservoir of the Huoshiling Formation in the Longfengshan area of the Changling fault depression is complex. The study on the main controlling factors and genetic mechanism of high-quality reservoirs in this area can improve the effectiveness of oil and gas exploration. By means of core observation, thin section identification, porosity and permeability analysis and logging interpretation, starting from the study of reservoir characteristics, the main controlling factors and genetic mechanism of high-quality reservoirs development are analyzed. The results show that the main rock types of volcanic rocks in Huoshiling Formation are andesitic tuff and andesitic breccia of explosive facies and andesite of effusive facies. Volcanic rocks belong to medium porosity and medium permeability reservoir, and the reservoir space is dominated by intergranular dissolved pores, ingranular dissolved pores, matrix dissolved pores and microfractures. Lithology, lithofacies and apparatus-cycle control the formation and distribution of high-quality reservoirs, and weathering and leaching, acid fluid dissolution and tectonism determine whether volcanic rocks can become high-quality reservoirs. The genesis of high-quality reservoirs includes three types: primary reservoir, weathering crust reservoir, and fault-corrosion reservoir. High-quality reservoirs are distributed in the high part of the structure, the upper part of the lava flow and the boundary of the cycle periods near the faults and hydrocarbon generation depressions.
The genesis of volcanic reservoir of the Huoshiling Formation in the Longfengshan area of the Changling fault depression is complex. The study on the main controlling factors and genetic mechanism of high-quality reservoirs in this area can improve the effectiveness of oil and gas exploration. By means of core observation, thin section identification, porosity and permeability analysis and logging interpretation, starting from the study of reservoir characteristics, the main controlling factors and genetic mechanism of high-quality reservoirs development are analyzed. The results show that the main rock types of volcanic rocks in Huoshiling Formation are andesitic tuff and andesitic breccia of explosive facies and andesite of effusive facies. Volcanic rocks belong to medium porosity and medium permeability reservoir, and the reservoir space is dominated by intergranular dissolved pores, ingranular dissolved pores, matrix dissolved pores and microfractures. Lithology, lithofacies and apparatus-cycle control the formation and distribution of high-quality reservoirs, and weathering and leaching, acid fluid dissolution and tectonism determine whether volcanic rocks can become high-quality reservoirs. The genesis of high-quality reservoirs includes three types: primary reservoir, weathering crust reservoir, and fault-corrosion reservoir. High-quality reservoirs are distributed in the high part of the structure, the upper part of the lava flow and the boundary of the cycle periods near the faults and hydrocarbon generation depressions.
2022, 47(5): 1762-1776.
doi: 10.3799/dqkx.2022.101
Abstract:
In order to solve the poor effect and low accuracy of fluid identification of Es2 tight sandstone reservoir in Qibei slope belt, logging interpretation model of reservoir and fluid saturation is established, based on the analysis of reservoir characteristics and "four natures" relationship, optimization of logging series, standardization of logging curve, combined with petro-electric and NMR experimental results, with an integrated approach of qualitative, semi-qualitative and quantitative methods to identify and evaluate the fluid in tight sandstone reservoir. The relationship between "four natures" of tight sandstone reservoir in Es2 is complex, and the correlation coefficient of logging interpretation model is high, ranging between 0.75 and 0.95. Overlapping-map method can qualitatively distinguish high resistivity oil layer and water layer. Cross-plot method (Iwa-Φ and Ia-Iwa) can effectively distinguish oil layer, oil-water layer and water layer.The water saturation interval of oil layer, oil-water layer, water layer calculated by the legal quantity of the formula is 35.5%-91.4%, 60.5%-96.5%, and 77.2%-90.9%, respectively, and the irreducible water saturation interval of oil layer, oil-water layer, water layer calculated by the legal quantity of the formula is 30.3%-89.9%, 58.2%-90.1%, and 62.1%-64.4%, respectively. The coincidence rate of logging fluid identification and evaluation results is 25% higher than the original logging interpretation, and it provides reliable technical support for oil and gas exploration and development in the study area.
In order to solve the poor effect and low accuracy of fluid identification of Es2 tight sandstone reservoir in Qibei slope belt, logging interpretation model of reservoir and fluid saturation is established, based on the analysis of reservoir characteristics and "four natures" relationship, optimization of logging series, standardization of logging curve, combined with petro-electric and NMR experimental results, with an integrated approach of qualitative, semi-qualitative and quantitative methods to identify and evaluate the fluid in tight sandstone reservoir. The relationship between "four natures" of tight sandstone reservoir in Es2 is complex, and the correlation coefficient of logging interpretation model is high, ranging between 0.75 and 0.95. Overlapping-map method can qualitatively distinguish high resistivity oil layer and water layer. Cross-plot method (Iwa-Φ and Ia-Iwa) can effectively distinguish oil layer, oil-water layer and water layer.The water saturation interval of oil layer, oil-water layer, water layer calculated by the legal quantity of the formula is 35.5%-91.4%, 60.5%-96.5%, and 77.2%-90.9%, respectively, and the irreducible water saturation interval of oil layer, oil-water layer, water layer calculated by the legal quantity of the formula is 30.3%-89.9%, 58.2%-90.1%, and 62.1%-64.4%, respectively. The coincidence rate of logging fluid identification and evaluation results is 25% higher than the original logging interpretation, and it provides reliable technical support for oil and gas exploration and development in the study area.
2022, 47(5): 1777-1790.
doi: 10.3799/dqkx.2021.112
Abstract:
In order to clarify the geological factors affecting underground coal gasification (UCG) and construct a scientific and quantitative geological index evaluation system, seven types of geological conditions and 41 geological indexes affecting UCG are systematically analyzed, graded and quantified, and then the geological selection index system is established in the paper. According to the importance of the selected area, each geological index is divided into two categories: basic geological index (A) and key geological index (B). Based on these two categories of indexes, two new quantitative evaluation methods for favorable areas of UCG are proposed, namely fine type (A+B) and general type (B). The weight of geological indexes involved in the two evaluation methods is determined using expert scoring method and analytic hierarchy process (AHP). According to the conditions of resources, mining technology, regional structure and environment, the qualitative classification scheme of evaluation results is determined, and the general steps of favorable area optimization are put forward by comprehensive quantitative evaluation and qualitative classification. Finally, a complete set of evaluation technical system for favorable areas of UCG is formed. The effective application of the evaluation technology system can provide important theoretical support for the scientific site selection and industrialization process of UCG.
In order to clarify the geological factors affecting underground coal gasification (UCG) and construct a scientific and quantitative geological index evaluation system, seven types of geological conditions and 41 geological indexes affecting UCG are systematically analyzed, graded and quantified, and then the geological selection index system is established in the paper. According to the importance of the selected area, each geological index is divided into two categories: basic geological index (A) and key geological index (B). Based on these two categories of indexes, two new quantitative evaluation methods for favorable areas of UCG are proposed, namely fine type (A+B) and general type (B). The weight of geological indexes involved in the two evaluation methods is determined using expert scoring method and analytic hierarchy process (AHP). According to the conditions of resources, mining technology, regional structure and environment, the qualitative classification scheme of evaluation results is determined, and the general steps of favorable area optimization are put forward by comprehensive quantitative evaluation and qualitative classification. Finally, a complete set of evaluation technical system for favorable areas of UCG is formed. The effective application of the evaluation technology system can provide important theoretical support for the scientific site selection and industrialization process of UCG.
2022, 47(5): 1791-1804.
doi: 10.3799/dqkx.2022.098
Abstract:
With Yichang as the research area in the paper, the relationships between lithofacies and geological property of Niutitang Formation and Doushantuo Formation shale were studied by drilling, logging and testing data (geological properties includes total organic carbon content, porosity, transverse permeability, brittleness and pore type). The study shows that there are 11 types of lithological shale developed in the western Hubei, and there are obvious differences in geological properties between the different lithological shale. In combination with the characteristics of organic shale, three types of high quality shale were identified: siliceous shale, mud-rich siliceous shale, and mixed shale. The high quality shale contains significantly higher gas contents than the non-high quality shale, which confirms the accuracy of high quality shale identification results. By analyzing the influencing factors of shale logging, it is summarized that high quality shale has the logging response characteristics of high natural gamma ray, high resistivity, high acoustic time difference, high uranium, low density, low thorium and low potassium (four high values and three low values) in conventional logging curves. Thus, a logging identification method is proposed and it is suitable for finding shale reservoirs with low thermal evolution degree, strong hydrocarbon generation potential and easy development in high thermal evolution area of western Hubei.
With Yichang as the research area in the paper, the relationships between lithofacies and geological property of Niutitang Formation and Doushantuo Formation shale were studied by drilling, logging and testing data (geological properties includes total organic carbon content, porosity, transverse permeability, brittleness and pore type). The study shows that there are 11 types of lithological shale developed in the western Hubei, and there are obvious differences in geological properties between the different lithological shale. In combination with the characteristics of organic shale, three types of high quality shale were identified: siliceous shale, mud-rich siliceous shale, and mixed shale. The high quality shale contains significantly higher gas contents than the non-high quality shale, which confirms the accuracy of high quality shale identification results. By analyzing the influencing factors of shale logging, it is summarized that high quality shale has the logging response characteristics of high natural gamma ray, high resistivity, high acoustic time difference, high uranium, low density, low thorium and low potassium (four high values and three low values) in conventional logging curves. Thus, a logging identification method is proposed and it is suitable for finding shale reservoirs with low thermal evolution degree, strong hydrocarbon generation potential and easy development in high thermal evolution area of western Hubei.
2022, 47(5): 1805-1818.
doi: 10.3799/dqkx.2021.113
Abstract:
The research on the controlling factors of the oil and water sealing capacity of small-displacement faults to oil and water just scratches the surface of the problem in the process of oil and gas exploration, and it is difficult to obtain the internal structure and permeability change laws of the fault zone in different deformation processes in the field outcrop. Therefore, in this study it takes the artificial core of pure sandstone with high porosity as the research object, and uses the independently-developed "high-pressure and low-speed ring shear laboratory equipment" to carry out the experiment. After the experiment, the samples are cored for different analysis tests according to the needs, including permeability and porosity tests with overburden pressure, nano-CT scan, casting thin section analysis, etc. we have carried out several groups of ring shear experiments with effective normal stress and fault displacement as experimental variables. The research results show that macroscopically, obvious scratches and powdery cataclastic rock can be observed on the fault surface. Microscopically, the main reason for the decrease of porosity and permeability is the reduction of particle size and the directional arrangement of particles caused by the cataclastic in the fault zone. The fault zone permeability is less than 10 mD, 2~3 orders of magnitude lower than that of the host rock. With the increase of effective normal stress or sliding displacement, the cataclastic degree of fault zone increases, the particle size and pore diameter decrease, the thickness of fault zone increases, and the porosity and permeability decrease gradually. The study results lay a theoretical foundation for the study of the lateral sealing capacity of small-displacement faults in oil and gas exploration.
The research on the controlling factors of the oil and water sealing capacity of small-displacement faults to oil and water just scratches the surface of the problem in the process of oil and gas exploration, and it is difficult to obtain the internal structure and permeability change laws of the fault zone in different deformation processes in the field outcrop. Therefore, in this study it takes the artificial core of pure sandstone with high porosity as the research object, and uses the independently-developed "high-pressure and low-speed ring shear laboratory equipment" to carry out the experiment. After the experiment, the samples are cored for different analysis tests according to the needs, including permeability and porosity tests with overburden pressure, nano-CT scan, casting thin section analysis, etc. we have carried out several groups of ring shear experiments with effective normal stress and fault displacement as experimental variables. The research results show that macroscopically, obvious scratches and powdery cataclastic rock can be observed on the fault surface. Microscopically, the main reason for the decrease of porosity and permeability is the reduction of particle size and the directional arrangement of particles caused by the cataclastic in the fault zone. The fault zone permeability is less than 10 mD, 2~3 orders of magnitude lower than that of the host rock. With the increase of effective normal stress or sliding displacement, the cataclastic degree of fault zone increases, the particle size and pore diameter decrease, the thickness of fault zone increases, and the porosity and permeability decrease gradually. The study results lay a theoretical foundation for the study of the lateral sealing capacity of small-displacement faults in oil and gas exploration.
2022, 47(5): 1819-1833.
doi: 10.3799/dqkx.2022.011
Abstract:
This study aims to investigate the characteristics of paleo-temperature and paleo-pressure of fluid inclusions in shale fracture veins of Wufeng Formation, and to understand the main influencing factors of the shale reservoir pressure reduction and the mechanism of shale gas loss in the normal pressure shale gas zone, southeast margin of Sichuan basin. Taking the fluid inclusions in the fracture veins of the black carbonaceous shale of the Wufeng Formation in Songkan region as the main research object, the gas-liquid saline inclusion and high-density methane inclusion with the records of paleo-temperature and paleo-pressure characteristics in fracture veins were studied systematically by the microscope optical observation, cathodoluminescence (CL) test, inclusion temperature measurement and laser Raman analysis, combined with burial-hydrocarbon generation-thermal history simulation. The results show that there are mainly two phases of vein filling in the fractures of Wufeng Formation in Songkan region. The first phase fracture veins (M1) was formed about 103-86 Ma ago, which are wide in size and with orange-red CL color. The capture pressure of methane inclusions in the fractures recorded by the M1 vein is 82.6-91.5 MPa, reflecting that the shale gas reservoir in the basin margin region was still in the overpressure state at the medium stage of Yanshanian. The second-stage fracture veins (M2) grew along both sides of the first-stage fracture veins, and the formation time was about 90-72 Ma. The M2 veins are relative narrower than M1, and with dark-red CL color. And the trapping pressure of methane inclusions in M2 veins is calculated to be 43.6-47.3 MPa. Comprehensive analysis suggests that the Wufeng Formation in the Songkan region of the Southeast margin of Sichuan basin experienced a transition from overpressure to normal pressure during the Yanshanian. The uplift, denudation and fold deformation since the Yanshanian have caused a large amount of shale gas to migrate and dissipate laterally along the detachment zone within shales of Wufeng Formation and lower section of Longmaxi Formation, and leading to the formation pressure decreased rapidly. During the late Yanshan period, the shale gas reservoir in the stable structural zone was still in overpressure stage, while the basin margin region had dropped to normal pressure.
This study aims to investigate the characteristics of paleo-temperature and paleo-pressure of fluid inclusions in shale fracture veins of Wufeng Formation, and to understand the main influencing factors of the shale reservoir pressure reduction and the mechanism of shale gas loss in the normal pressure shale gas zone, southeast margin of Sichuan basin. Taking the fluid inclusions in the fracture veins of the black carbonaceous shale of the Wufeng Formation in Songkan region as the main research object, the gas-liquid saline inclusion and high-density methane inclusion with the records of paleo-temperature and paleo-pressure characteristics in fracture veins were studied systematically by the microscope optical observation, cathodoluminescence (CL) test, inclusion temperature measurement and laser Raman analysis, combined with burial-hydrocarbon generation-thermal history simulation. The results show that there are mainly two phases of vein filling in the fractures of Wufeng Formation in Songkan region. The first phase fracture veins (M1) was formed about 103-86 Ma ago, which are wide in size and with orange-red CL color. The capture pressure of methane inclusions in the fractures recorded by the M1 vein is 82.6-91.5 MPa, reflecting that the shale gas reservoir in the basin margin region was still in the overpressure state at the medium stage of Yanshanian. The second-stage fracture veins (M2) grew along both sides of the first-stage fracture veins, and the formation time was about 90-72 Ma. The M2 veins are relative narrower than M1, and with dark-red CL color. And the trapping pressure of methane inclusions in M2 veins is calculated to be 43.6-47.3 MPa. Comprehensive analysis suggests that the Wufeng Formation in the Songkan region of the Southeast margin of Sichuan basin experienced a transition from overpressure to normal pressure during the Yanshanian. The uplift, denudation and fold deformation since the Yanshanian have caused a large amount of shale gas to migrate and dissipate laterally along the detachment zone within shales of Wufeng Formation and lower section of Longmaxi Formation, and leading to the formation pressure decreased rapidly. During the late Yanshan period, the shale gas reservoir in the stable structural zone was still in overpressure stage, while the basin margin region had dropped to normal pressure.
2022, 47(5): 1834-1848.
doi: 10.3799/dqkx.2022.008
Abstract:
Qiangtang basin is a large Mesozoic marine sedimentary basin, in which several sets of source rocks are developed, and many paleo-reservoirs and hydrocarbon indications are discovered. Determining the oil source of paleo-reservoirs is very important for oil and gas exploration. In order to clarify the oil source of the paleo-reservoir, geochemical analysis of oil and source rock samples is carried out in this paper. The results show that the paleo-reservoirs can be divided into two types: type Ⅰ paleo-reservoirs are in the mature-high mature stage in general with the high content of C24 tetracyclic terpane, the low tricyclic terpane abundance, C29 regular sterane with certain advantages in content, and high C29 hopane content, reflecting the contribution of terrigenous organic matter. Type Ⅱ paleo-reservoir is in the low mature-mature stage in general, with C23 tricyclic terpane as the main peak, low content of C24 tetracyclic terpane and the domination of C27 regular sterane, indicating the precursor was mainly lower aquatic organisms. The oil-source correlation result shows that the two types of paleo-reservoirs come from different source rocks. Type Ⅰ crude oil comes from the source rocks of Zhana Formation of Upper Triassic, and type Ⅱ crude oil is mainly contributed by the source rocks of Quse Formation of Lower Jurassic.
Qiangtang basin is a large Mesozoic marine sedimentary basin, in which several sets of source rocks are developed, and many paleo-reservoirs and hydrocarbon indications are discovered. Determining the oil source of paleo-reservoirs is very important for oil and gas exploration. In order to clarify the oil source of the paleo-reservoir, geochemical analysis of oil and source rock samples is carried out in this paper. The results show that the paleo-reservoirs can be divided into two types: type Ⅰ paleo-reservoirs are in the mature-high mature stage in general with the high content of C24 tetracyclic terpane, the low tricyclic terpane abundance, C29 regular sterane with certain advantages in content, and high C29 hopane content, reflecting the contribution of terrigenous organic matter. Type Ⅱ paleo-reservoir is in the low mature-mature stage in general, with C23 tricyclic terpane as the main peak, low content of C24 tetracyclic terpane and the domination of C27 regular sterane, indicating the precursor was mainly lower aquatic organisms. The oil-source correlation result shows that the two types of paleo-reservoirs come from different source rocks. Type Ⅰ crude oil comes from the source rocks of Zhana Formation of Upper Triassic, and type Ⅱ crude oil is mainly contributed by the source rocks of Quse Formation of Lower Jurassic.
2022, 47(5): 1849-1864.
doi: 10.3799/dqkx.2021.241
Abstract:
To reveal the mechanical response characteristics and mechanisms of coal-rock with CO2 injection, the influencing factors of mechanical properties of coal-rock with CO2 injection, the transformation effect of CO2 on the macro molecular-pore-fracture structure of coal-rock and the statistical model, theoretical model and intelligence prediction model of mechanical parameters of coal-rock with CO2 injection were reviewed. Results show that mechanical properties of coal-rock with CO2 injection are controlled by the coal rank, the CO2 pressure, the moisture, the confining pressure and the time. The increase of CO2 injection pressure, the addition of water and the extension of time can further reduce the mechanical properties of coal-rock with CO2 injection, while the confining pressure can ameliorate the weakening effect of mechanical property to a certain extent. The CO2 aqueous solution recombines the macro molecular structure of coal-rock by the swelling, extraction and plasticization effects, reforms the pore structure of coal-rock by the micro crystalline structure change, chemical corrosion and non-uniform deformation effects, damages the fracture structure by the chemical corrosion, swelling stress and chemical-stress coupling effects, which all weaken the mechanical properties of coal-rock in varying degrees. Among the prediction models of mechanical parameters of coal-rock with CO2 injection, the Langmuir-like model, the extended exponential model and the modified cohesion model have clear physical significance, while the intelligence prediction model has higher prediction accuracy, and the prediction accuracy can reach more than 99%. This study lays a theoretical foundation for scientifically evaluating the CO2-ECBM safety and promoting the efficient injection of CO2 into deep coal seams.
To reveal the mechanical response characteristics and mechanisms of coal-rock with CO2 injection, the influencing factors of mechanical properties of coal-rock with CO2 injection, the transformation effect of CO2 on the macro molecular-pore-fracture structure of coal-rock and the statistical model, theoretical model and intelligence prediction model of mechanical parameters of coal-rock with CO2 injection were reviewed. Results show that mechanical properties of coal-rock with CO2 injection are controlled by the coal rank, the CO2 pressure, the moisture, the confining pressure and the time. The increase of CO2 injection pressure, the addition of water and the extension of time can further reduce the mechanical properties of coal-rock with CO2 injection, while the confining pressure can ameliorate the weakening effect of mechanical property to a certain extent. The CO2 aqueous solution recombines the macro molecular structure of coal-rock by the swelling, extraction and plasticization effects, reforms the pore structure of coal-rock by the micro crystalline structure change, chemical corrosion and non-uniform deformation effects, damages the fracture structure by the chemical corrosion, swelling stress and chemical-stress coupling effects, which all weaken the mechanical properties of coal-rock in varying degrees. Among the prediction models of mechanical parameters of coal-rock with CO2 injection, the Langmuir-like model, the extended exponential model and the modified cohesion model have clear physical significance, while the intelligence prediction model has higher prediction accuracy, and the prediction accuracy can reach more than 99%. This study lays a theoretical foundation for scientifically evaluating the CO2-ECBM safety and promoting the efficient injection of CO2 into deep coal seams.
2022, 47(5): 1865-1875.
doi: 10.3799/dqkx.2022.014
Abstract:
The development depth is mostly greater than 2 000 m in major shale gas producing areas of China. As burial depth increases, reservoir pressure increases. The experimental and theoretical study of shale gas adsorption under low pressure is not suitable for the development of medium-deep and deep shale gas reservoirs. Thus, it modified the Uniform Langmuir model, and developed a high-pressure methane adsorption model, i.e., the modified Uniform Langmuir(Unilan)model. Then, we used the published experimental data under high pressure to validate the modified Unilan model. Moreover, we compared the modified Unilan model with other high-pressure adsorption models. It is found that the modified Unilan model with less fitting parameters is characterized by high precision, compared with other high pressure adsorption models. Finally, we investigated the fitted model parameters based on the mineral composition of the used shale samples. It is found that the adsorption capacity of shale is mainly controlled by organic matter and clay. Moreover, the volume of the adsorbed phase at maximum adsorption capacity is greater than micropore volume, but is less than total pore volume. Adsorption entropy change is mainly controlled by the interaction strength between adsorbed methane molecules and shale.
The development depth is mostly greater than 2 000 m in major shale gas producing areas of China. As burial depth increases, reservoir pressure increases. The experimental and theoretical study of shale gas adsorption under low pressure is not suitable for the development of medium-deep and deep shale gas reservoirs. Thus, it modified the Uniform Langmuir model, and developed a high-pressure methane adsorption model, i.e., the modified Uniform Langmuir(Unilan)model. Then, we used the published experimental data under high pressure to validate the modified Unilan model. Moreover, we compared the modified Unilan model with other high-pressure adsorption models. It is found that the modified Unilan model with less fitting parameters is characterized by high precision, compared with other high pressure adsorption models. Finally, we investigated the fitted model parameters based on the mineral composition of the used shale samples. It is found that the adsorption capacity of shale is mainly controlled by organic matter and clay. Moreover, the volume of the adsorbed phase at maximum adsorption capacity is greater than micropore volume, but is less than total pore volume. Adsorption entropy change is mainly controlled by the interaction strength between adsorbed methane molecules and shale.
2022, 47(5): 1876-1889.
doi: 10.3799/dqkx.2021.195
Abstract:
The coal nanopore structure's common characterization pattern is established by the LP-N2GA method, CO2 adsorption method, SEM-PCAS, and the pore characteristics of six coals with different metamorphic degrees are analyzed. The characterization model enables us to study and analyze the pores in coal more effectively, including pore number, pore area, pore perimeter, average shape factor, porosity, fractal dimension, and pore size distribution. When the pore distribution of coal samples is similar, the adsorption capacity of coal for N2 and CO2, the approximate probability density of porosity and pore area (mesopore) of coal samples are negatively correlated with the volatile matter of coal, and the fractal dimension of the pore of coal samples is positively correlated with the volatile matter of coal. When the pore distribution of coal samples is quite different, the maximum adsorption capacity of N2 and CO2 is related to the pore distribution. The combination of SEM-PCAS and gas adsorption technology facilitates the understanding of the pore characteristics of coal. The research results have specific guiding significance for coal mine gas control.
The coal nanopore structure's common characterization pattern is established by the LP-N2GA method, CO2 adsorption method, SEM-PCAS, and the pore characteristics of six coals with different metamorphic degrees are analyzed. The characterization model enables us to study and analyze the pores in coal more effectively, including pore number, pore area, pore perimeter, average shape factor, porosity, fractal dimension, and pore size distribution. When the pore distribution of coal samples is similar, the adsorption capacity of coal for N2 and CO2, the approximate probability density of porosity and pore area (mesopore) of coal samples are negatively correlated with the volatile matter of coal, and the fractal dimension of the pore of coal samples is positively correlated with the volatile matter of coal. When the pore distribution of coal samples is quite different, the maximum adsorption capacity of N2 and CO2 is related to the pore distribution. The combination of SEM-PCAS and gas adsorption technology facilitates the understanding of the pore characteristics of coal. The research results have specific guiding significance for coal mine gas control.
2022, 47(5): 1890-1900.
doi: 10.3799/dqkx.2022.089
Abstract:
After the first successful trial production in the Shenhu area of the South China Sea in 2017, many scholars have used numerical methods to simulate this process, but the simulation results have always been deviated from the data of actual trial production. In order to explore the reasons for the deviation, a mathematical model is established for depressurization discovery in a two-dimensional cylindrical coordinate system, and a corresponding program is developed in this study, to simulate not only the non-uniform distribution of reservoir parameters such as permeability and so on, but also the impact of dynamic parameter such as the wellbore pressure on the production process. Making full use of the flexibility of the autonomous program, the reasons for the deviation are obtained through numerical experiment analysis: (1) The muddy silt-type reservoir has water sensitivity, and the fresh water produced by the decomposition of hydrate causes clay swelling, which makes the permeability decrease; (2) The production well pressure must be taken as the dynamic input parameter. Based on this, the permeability model was revised, and the time-varying pressure in production well was dynamically input. The simulated gas production obtained is very close to the trial production data, making the numerical simulation of depressurization closer to the actual situation.
After the first successful trial production in the Shenhu area of the South China Sea in 2017, many scholars have used numerical methods to simulate this process, but the simulation results have always been deviated from the data of actual trial production. In order to explore the reasons for the deviation, a mathematical model is established for depressurization discovery in a two-dimensional cylindrical coordinate system, and a corresponding program is developed in this study, to simulate not only the non-uniform distribution of reservoir parameters such as permeability and so on, but also the impact of dynamic parameter such as the wellbore pressure on the production process. Making full use of the flexibility of the autonomous program, the reasons for the deviation are obtained through numerical experiment analysis: (1) The muddy silt-type reservoir has water sensitivity, and the fresh water produced by the decomposition of hydrate causes clay swelling, which makes the permeability decrease; (2) The production well pressure must be taken as the dynamic input parameter. Based on this, the permeability model was revised, and the time-varying pressure in production well was dynamically input. The simulated gas production obtained is very close to the trial production data, making the numerical simulation of depressurization closer to the actual situation.
