2020 Vol.3(4)
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2020, 3(4): 511-523.
doi: 10.31035/cg2020075
Abstract:
Natural gas hydrate, oil and gas were all found together in the Qilian Mountain permafrost area, northeast of Qinghai-Tibet Plateau, China. They are closely associated with each other in space, but whether they are in any genetic relations are unknown yet. In this paper, a hydrocarbon gas-generation series, gas-fluid migration series and hydrocarbon gas-accumulation series are analyzed to probe the spatial, temporal and genetic relationships among natural gas hydrate, oil and gas. The subsequent results show that natural gas hydrate, oil and gas actually form a natural gas hydrate-oil-gas system. Based on the Middle Jurassic and the Upper Triassic hydrocarbon gas-generation series, it is divided into four major sub-systems in the study area: (1) A conventional Upper Triassic gas-bearing sub-system with peak hydrocarbon gas-generation in the late Middle Jurassic; (2) a conventional Middle Jurassic oil-bearing sub-system with low to mature hydrocarbon gas-generation in the late Middle Jurassic; (3) a natural gas hydrate sub-system with main gas source from the Upper Triassic gas-bearing sub-system and minor gas source from the Middle Jurassic oil-bearing sub-system as well as little gas source from the Middle Jurassic coal-bed gas and the microbial gas; (4) a shallower gas sub-system with microbial alteration of the main gas source from the Upper Triassic gas-bearing sub-system. This natural gas hydrate-oil-gas system and its sub-systems are not only theoretical but also practical, and thus they will play an important role in the further exploration of natural gas hydrate, oil and gas, even other energy resources in the study area.
Natural gas hydrate, oil and gas were all found together in the Qilian Mountain permafrost area, northeast of Qinghai-Tibet Plateau, China. They are closely associated with each other in space, but whether they are in any genetic relations are unknown yet. In this paper, a hydrocarbon gas-generation series, gas-fluid migration series and hydrocarbon gas-accumulation series are analyzed to probe the spatial, temporal and genetic relationships among natural gas hydrate, oil and gas. The subsequent results show that natural gas hydrate, oil and gas actually form a natural gas hydrate-oil-gas system. Based on the Middle Jurassic and the Upper Triassic hydrocarbon gas-generation series, it is divided into four major sub-systems in the study area: (1) A conventional Upper Triassic gas-bearing sub-system with peak hydrocarbon gas-generation in the late Middle Jurassic; (2) a conventional Middle Jurassic oil-bearing sub-system with low to mature hydrocarbon gas-generation in the late Middle Jurassic; (3) a natural gas hydrate sub-system with main gas source from the Upper Triassic gas-bearing sub-system and minor gas source from the Middle Jurassic oil-bearing sub-system as well as little gas source from the Middle Jurassic coal-bed gas and the microbial gas; (4) a shallower gas sub-system with microbial alteration of the main gas source from the Upper Triassic gas-bearing sub-system. This natural gas hydrate-oil-gas system and its sub-systems are not only theoretical but also practical, and thus they will play an important role in the further exploration of natural gas hydrate, oil and gas, even other energy resources in the study area.
2020, 3(4): 533-544.
doi: 10.31035/cg2020072
Abstract:
In order to evaluate the geological characteristics and gas-bearing factors of Niutitang Formation within the Lower Cambrian of northern Guizhou, the Huangping area located at the southern edge of the ancient uplift belt of Xuefeng Mountain was selected as the target area, and Well Huangdi 1 was drilled for the geological survey of shale gas. Through geological background analysis and well logging and laboratory analysis such as organic geochemical test, gas content analysis, isothermal adsorption, and specific surface area experiments on Well Huangdi 1, the results show that the Niutitang Formation is a deep-water shelf, trough-like folds and thrust fault. The thickness of black shale is 119.95 m, of which carbonaceous shale is 89.6 m. The average value of organic carbon content is 3.55%, kerogen vitrinite reflectance value is 2.37% and kerogen type is sapropel-type. The brittle mineral content is 51% (quartz 38%), clay mineral content is 38.3%. The value of porosity and permeability are 0.5% and 0.0014 mD, which the reservoir of the Niutitang Formation belongs to low permeability with characteristics of ultra-low porosity. The gas content is 0.09‒1.31 m3/t with a high-value area and a second high-value area. By comparing with the geological parameters of adjacent wells in the adjacent area, the accumulation model of “sediment control zone, Ro control zone, structure controlling reservoir” in the study area is proposed. Therefore, deep-water shelf-slope facies, Ro is between high maturity-early stage of overmaturity and well-preserved zones in the Niutitang Formation in this area are favorable direction for the next step of shale gas exploration.
In order to evaluate the geological characteristics and gas-bearing factors of Niutitang Formation within the Lower Cambrian of northern Guizhou, the Huangping area located at the southern edge of the ancient uplift belt of Xuefeng Mountain was selected as the target area, and Well Huangdi 1 was drilled for the geological survey of shale gas. Through geological background analysis and well logging and laboratory analysis such as organic geochemical test, gas content analysis, isothermal adsorption, and specific surface area experiments on Well Huangdi 1, the results show that the Niutitang Formation is a deep-water shelf, trough-like folds and thrust fault. The thickness of black shale is 119.95 m, of which carbonaceous shale is 89.6 m. The average value of organic carbon content is 3.55%, kerogen vitrinite reflectance value is 2.37% and kerogen type is sapropel-type. The brittle mineral content is 51% (quartz 38%), clay mineral content is 38.3%. The value of porosity and permeability are 0.5% and 0.0014 mD, which the reservoir of the Niutitang Formation belongs to low permeability with characteristics of ultra-low porosity. The gas content is 0.09‒1.31 m3/t with a high-value area and a second high-value area. By comparing with the geological parameters of adjacent wells in the adjacent area, the accumulation model of “sediment control zone, Ro control zone, structure controlling reservoir” in the study area is proposed. Therefore, deep-water shelf-slope facies, Ro is between high maturity-early stage of overmaturity and well-preserved zones in the Niutitang Formation in this area are favorable direction for the next step of shale gas exploration.
2020, 3(4): 545-557.
doi: 10.31035/cg2020070
Abstract:
The composition of gas released under vacuum by crushing from the gas shale of Longmaxi Formation in Upper Yangtze Plate, Southern China was systematically investigated in this study. The effect of residual gas release on pore structures was checked using low-pressure nitrogen adsorption techniques. The influence of particle size on the determination of pore structure characteristics was considered. Using the Frenkel-Halsey-Hill method from low-pressure nitrogen adsorption data, the fractal dimensions were identified at relative pressures of 0‒0.5 and 0.5‒1 as D1 and D2, respectively, and the evolution of fractal features related to gas release was also discussed. The results showed that a variety component of residual gas was released from all shale samples, containing hydrocarbon gas of CH4 (29.58%‒92.53%), C2H6 (0.97%‒2.89%), C3H8 (0.01%‒0.65%), and also some non-hydrocarbon gas such as CO2 (3.54%‒67.09%) and N2 (1.88%‒8.07%). The total yield of residual gas was in a range from 6.1 μL/g to 17.0 μL/g related to rock weight. The geochemical and mineralogical analysis suggested that the residual gas yield was positively correlated with quartz (R2=0.5480) content. The residual gas released shale sample has a higher surface area of 17.20‒25.03 m2/g and the nitrogen adsorption capacity in a range of 27.32‒40.86 ml/g that is relatively higher than the original samples (with 9.22‒16.30 m2/g and 10.84‒17.55 ml/g). Clearer hysteresis loop was observed for the original shale sample in nitrogen adsorption-desorption isotherms than residual gas released sample. Pore structure analysis showed that the proportions of micro-, meso- and macropores were changed as micropores decreased while meso- and macropores increased. The fractal dimensions D1 were in range from 2.5466 to 2.6117 and D2 from 2.6998 to 2.7119 for the residual gas released shale, which is smaller than the original shale. This factor may indicate that the pore in residual gas released shale was more homogeneous than the original shale. The results indicated that both residual gas and their pore space have few contributions to shale gas production and effective reservoir evaluation. The larger fragments samples of granular rather than powdery smaller than 60 mesh fraction of shale seem to be better for performing effective pore structure analysis to the Longmaxi shale.
The composition of gas released under vacuum by crushing from the gas shale of Longmaxi Formation in Upper Yangtze Plate, Southern China was systematically investigated in this study. The effect of residual gas release on pore structures was checked using low-pressure nitrogen adsorption techniques. The influence of particle size on the determination of pore structure characteristics was considered. Using the Frenkel-Halsey-Hill method from low-pressure nitrogen adsorption data, the fractal dimensions were identified at relative pressures of 0‒0.5 and 0.5‒1 as D1 and D2, respectively, and the evolution of fractal features related to gas release was also discussed. The results showed that a variety component of residual gas was released from all shale samples, containing hydrocarbon gas of CH4 (29.58%‒92.53%), C2H6 (0.97%‒2.89%), C3H8 (0.01%‒0.65%), and also some non-hydrocarbon gas such as CO2 (3.54%‒67.09%) and N2 (1.88%‒8.07%). The total yield of residual gas was in a range from 6.1 μL/g to 17.0 μL/g related to rock weight. The geochemical and mineralogical analysis suggested that the residual gas yield was positively correlated with quartz (R2=0.5480) content. The residual gas released shale sample has a higher surface area of 17.20‒25.03 m2/g and the nitrogen adsorption capacity in a range of 27.32‒40.86 ml/g that is relatively higher than the original samples (with 9.22‒16.30 m2/g and 10.84‒17.55 ml/g). Clearer hysteresis loop was observed for the original shale sample in nitrogen adsorption-desorption isotherms than residual gas released sample. Pore structure analysis showed that the proportions of micro-, meso- and macropores were changed as micropores decreased while meso- and macropores increased. The fractal dimensions D1 were in range from 2.5466 to 2.6117 and D2 from 2.6998 to 2.7119 for the residual gas released shale, which is smaller than the original shale. This factor may indicate that the pore in residual gas released shale was more homogeneous than the original shale. The results indicated that both residual gas and their pore space have few contributions to shale gas production and effective reservoir evaluation. The larger fragments samples of granular rather than powdery smaller than 60 mesh fraction of shale seem to be better for performing effective pore structure analysis to the Longmaxi shale.
2020, 3(4): 558-566.
doi: 10.31035/cg2020063
Abstract:
It has been an intense debate on the exact boundary between Ediacaran and Cambrian in the southwest Yangtze Block. The calibration of this critical boundary has a remarkable influence on the further investigation of the break-up of the Rodinia Supercontinent, the early life evolution, and the mechanism of the phosphorite deposit. Ediacaran and Cambrian strata and fossils are widely distributed in Anning, Yunnan Province in China. In recent years, the Xiaowaitoushan Member from the Lower Yuhucun Formation has been studied. Through this interval with continuous collections, the first appearance datums (FADs) of the protoconodont (Fomitchella cf. inchoate Yang et He, Protohertzina cf. anabarica Missarzhevsky) and globular embryos fossil (Olivooides sp.) earlier than these in the Lower Cambrian strata of the Meishucun Formation were discovered. This discovery indicates that the Xiaowaitoushan Member has included more FADs than the previously discovered single FAD of Anabarites primitivus Qian et Jiang, and the Ediacaran–Cambrian boundary in southwest China should be replaced below the Point “A” of the Meishucun Formation in Yunnan Province. The Point “B” of the Meishucun Formation is younger than the suggested age 541 Ma of the Ediacaran–Cambrian boundary and can no longer reference the Global Boundary Stratotype Section and Point (GSSP) correlation in southwest China. It can be suggested based on the previous stratigraphy and palaeontology studies from northern Sichuan and southern Shaanxi and the FAD of the globular embryos fossils that the Ediacaran‒Cambrian boundary in the southwest Yangtze Block should be placed at the base of the Xiaowaitoushan Member; other phosphorite strata refer to Xiaowaitoushan Member. The discovery of the FADs of the shelly fossils in the Xiaowaitoushan Member provides new evidence for the global correlation of the Ediacaran–Cambrian boundary in the southwest Yangtze Block. The conodont discoloration index (CAI) of the specimens in Anning is between 2 and 3, which indicates that the organic matter in Xiaowaitoushan Member is matured and has high potential to form a shale gas reservoir.
It has been an intense debate on the exact boundary between Ediacaran and Cambrian in the southwest Yangtze Block. The calibration of this critical boundary has a remarkable influence on the further investigation of the break-up of the Rodinia Supercontinent, the early life evolution, and the mechanism of the phosphorite deposit. Ediacaran and Cambrian strata and fossils are widely distributed in Anning, Yunnan Province in China. In recent years, the Xiaowaitoushan Member from the Lower Yuhucun Formation has been studied. Through this interval with continuous collections, the first appearance datums (FADs) of the protoconodont (Fomitchella cf. inchoate Yang et He, Protohertzina cf. anabarica Missarzhevsky) and globular embryos fossil (Olivooides sp.) earlier than these in the Lower Cambrian strata of the Meishucun Formation were discovered. This discovery indicates that the Xiaowaitoushan Member has included more FADs than the previously discovered single FAD of Anabarites primitivus Qian et Jiang, and the Ediacaran–Cambrian boundary in southwest China should be replaced below the Point “A” of the Meishucun Formation in Yunnan Province. The Point “B” of the Meishucun Formation is younger than the suggested age 541 Ma of the Ediacaran–Cambrian boundary and can no longer reference the Global Boundary Stratotype Section and Point (GSSP) correlation in southwest China. It can be suggested based on the previous stratigraphy and palaeontology studies from northern Sichuan and southern Shaanxi and the FAD of the globular embryos fossils that the Ediacaran‒Cambrian boundary in the southwest Yangtze Block should be placed at the base of the Xiaowaitoushan Member; other phosphorite strata refer to Xiaowaitoushan Member. The discovery of the FADs of the shelly fossils in the Xiaowaitoushan Member provides new evidence for the global correlation of the Ediacaran–Cambrian boundary in the southwest Yangtze Block. The conodont discoloration index (CAI) of the specimens in Anning is between 2 and 3, which indicates that the organic matter in Xiaowaitoushan Member is matured and has high potential to form a shale gas reservoir.
2020, 3(4): 567-574.
doi: 10.31035/cg2020062
Abstract:
In order to figure out the redox conditions and paleo-sedimentary environment of the Middle Devonian shales in the northwest of Guizhong Depression, the trace element analysis was conducted on the Middle Devonian cores (320.35–938.50 m) of the typical shale gas investigation well (GY-1) at a 1.50 m sampling interval through X-ray fluorescence spectroscopy (XRF) and inductively coupled plasma mass spectrometry (ICP-MS). According to the test result, the average values of V/(V+Ni), V/Cr and Ni/Co in Nabiao formation (Fm.) are larger than 0.67, 4.65 and 7.71 respectively, and Nabiao Fm. is rich in biological assemblages such as tabasheer, ammonite, etc. These evidences indicate the rising sea level rose relatively in the sedimentation period of Nabiao Fm. and a deepwater shelf environment, which was favorable for the preservation of organic matters. The V/(V+Ni), V/Cr and Ni/Co in Luofu Fm. and Tangting Fm. are 0.38–0.65, 0.73–4.10 and 3.70–6.72 respectively, indicating that the sea level dropped relatively in their sedimentation period, during which the water bodies became shallow, and the sedimentary environment was a weak oxidizing shallow water shelf environment. In addition, the variation of TOC has a high correlation with the enrichment degree of Ba element, indicating the favorable conditions for the enrichment and preservation of organic matters under an oxygen-deficient environment. Moreover, according to the identification of trace element indexes, the northwest of Guizhong Depression experienced the sedimentary cycle of relative rise to relative fall of sea level from bottom to top in the Middle Devonian sedimentation period. The relative sea level rose to the highest in the sedimentation period of Nabiao Fm., in which the organic-rich shales with stable thickness and high organic content were deposited. Hence, the Nabiao Fm. could be regarded as the favorable exploration target interval in this area.
In order to figure out the redox conditions and paleo-sedimentary environment of the Middle Devonian shales in the northwest of Guizhong Depression, the trace element analysis was conducted on the Middle Devonian cores (320.35–938.50 m) of the typical shale gas investigation well (GY-1) at a 1.50 m sampling interval through X-ray fluorescence spectroscopy (XRF) and inductively coupled plasma mass spectrometry (ICP-MS). According to the test result, the average values of V/(V+Ni), V/Cr and Ni/Co in Nabiao formation (Fm.) are larger than 0.67, 4.65 and 7.71 respectively, and Nabiao Fm. is rich in biological assemblages such as tabasheer, ammonite, etc. These evidences indicate the rising sea level rose relatively in the sedimentation period of Nabiao Fm. and a deepwater shelf environment, which was favorable for the preservation of organic matters. The V/(V+Ni), V/Cr and Ni/Co in Luofu Fm. and Tangting Fm. are 0.38–0.65, 0.73–4.10 and 3.70–6.72 respectively, indicating that the sea level dropped relatively in their sedimentation period, during which the water bodies became shallow, and the sedimentary environment was a weak oxidizing shallow water shelf environment. In addition, the variation of TOC has a high correlation with the enrichment degree of Ba element, indicating the favorable conditions for the enrichment and preservation of organic matters under an oxygen-deficient environment. Moreover, according to the identification of trace element indexes, the northwest of Guizhong Depression experienced the sedimentary cycle of relative rise to relative fall of sea level from bottom to top in the Middle Devonian sedimentation period. The relative sea level rose to the highest in the sedimentation period of Nabiao Fm., in which the organic-rich shales with stable thickness and high organic content were deposited. Hence, the Nabiao Fm. could be regarded as the favorable exploration target interval in this area.
2020, 3(4): 575-590.
doi: 10.31035/cg2020067
Abstract:
The sequence stratigraphic framework of Shanxi Formation in the northeast Zhoukou Depression was established based on detailed sequence stratigraphical and sedimentological analysis by utilizing the logging and core data of six wells drilled in the eastern tectonic unit of Zhoukou Depression. It was divided into three third-order sequences, namely SQs1, SQs2, and SQs3 from bottom to top. Each sequence can be divided into a transgressive system tract (TST) and a highstand system tract (HST). Furthermore, four sequence boundaries and three maximum flooding surfaces were identified, and they are the bottom interface SBs and maximum flooding surface mfss1 of SQs1, the bottom interface SBs1 and maximum flooding surface mfss2 of SQs2, the bottom interface SBs3 and maximum flooding surface mfss3 of SQs3, and the top interface SBx from bottom to top. Carbonate tidal flat–clastic tidal flat sedimentary system developed in Shanxi Formation in the northeast Zhoukou Depression (also referred to as the study area) under the control of regression. Meanwhile, four sedimentary microfacies were identified in the sedimentary system, which are lime-mud flats, sand flats, mixed flats, and mud flats. The transgression in the study area occurred from the southeast to the northwest. Therefore, the northwestern part is the seaward side, and the southeastern part is the landward side. As revealed by relevant drilling data, SQs1 of the Shanxi Formation is characterized by the development of limestone and carbonaceous mudstone, with limestone, dark mudstone, and carbonaceous mudstone mainly developing. Meanwhile, lime-mud flats were mainly deposited in it. During the periods of SQs2 and SQs3, the sedimentary environment of the study area changed from the carbonate tidal flats to clastic tidal flats as the coastline migrated towards the sea. In these periods, sand flats mainly developed near the maximum flooding surfaces and were relatively continuous in the eastern and southern parts of the transgressive system tract; mixed flats were relatively continuous in the western and northern parts of the transgressive system tract as well as the eastern and southern parts of the highstand system tract; mud flats widely developed in the highstand system tract. Peat flats mainly developed in the period of HSTs2, with coal seams relatively developing in the southeastern part of the study area as revealed by drilling data. The peat flats in SQs2 are favorable hydrocarbon source layers, the lime-mud flats in SQs1 and sand flats formed in the transgression periods of SQs2 and SQs3 constitute favorable hydrocarbon reservoirs, and the mud flats form in the transgressions periods serve as favorable cap rocks. Therefore, the study area features a reservoir-cap assemblage for self-generating and self-storing of hydrocarbon, and the southeastern part of the study area can be taken as a favorable exploration area.
The sequence stratigraphic framework of Shanxi Formation in the northeast Zhoukou Depression was established based on detailed sequence stratigraphical and sedimentological analysis by utilizing the logging and core data of six wells drilled in the eastern tectonic unit of Zhoukou Depression. It was divided into three third-order sequences, namely SQs1, SQs2, and SQs3 from bottom to top. Each sequence can be divided into a transgressive system tract (TST) and a highstand system tract (HST). Furthermore, four sequence boundaries and three maximum flooding surfaces were identified, and they are the bottom interface SBs and maximum flooding surface mfss1 of SQs1, the bottom interface SBs1 and maximum flooding surface mfss2 of SQs2, the bottom interface SBs3 and maximum flooding surface mfss3 of SQs3, and the top interface SBx from bottom to top. Carbonate tidal flat–clastic tidal flat sedimentary system developed in Shanxi Formation in the northeast Zhoukou Depression (also referred to as the study area) under the control of regression. Meanwhile, four sedimentary microfacies were identified in the sedimentary system, which are lime-mud flats, sand flats, mixed flats, and mud flats. The transgression in the study area occurred from the southeast to the northwest. Therefore, the northwestern part is the seaward side, and the southeastern part is the landward side. As revealed by relevant drilling data, SQs1 of the Shanxi Formation is characterized by the development of limestone and carbonaceous mudstone, with limestone, dark mudstone, and carbonaceous mudstone mainly developing. Meanwhile, lime-mud flats were mainly deposited in it. During the periods of SQs2 and SQs3, the sedimentary environment of the study area changed from the carbonate tidal flats to clastic tidal flats as the coastline migrated towards the sea. In these periods, sand flats mainly developed near the maximum flooding surfaces and were relatively continuous in the eastern and southern parts of the transgressive system tract; mixed flats were relatively continuous in the western and northern parts of the transgressive system tract as well as the eastern and southern parts of the highstand system tract; mud flats widely developed in the highstand system tract. Peat flats mainly developed in the period of HSTs2, with coal seams relatively developing in the southeastern part of the study area as revealed by drilling data. The peat flats in SQs2 are favorable hydrocarbon source layers, the lime-mud flats in SQs1 and sand flats formed in the transgression periods of SQs2 and SQs3 constitute favorable hydrocarbon reservoirs, and the mud flats form in the transgressions periods serve as favorable cap rocks. Therefore, the study area features a reservoir-cap assemblage for self-generating and self-storing of hydrocarbon, and the southeastern part of the study area can be taken as a favorable exploration area.
2020, 3(4): 591-601.
doi: 10.31035/cg2020068
Abstract:
The Sichuan Basin is one of the vital basins in China, boasting abundant hydrocarbon reservoirs. To clarify the intensity of the tectonic stress field of different tectonic episodes since the Mesozoic and to identify the regional dynamic background of different tectonic movements in the Sichuan Basin and its adjacent areas, the characteristics of the acoustic emission in rocks in different strata of these areas were researched in this paper. Meanwhile, the tectonic stress magnitude in these areas since the Mesozoic was restored. The laws state that the tectonic stress varied with depth was revealed, followed by the discussion of the influence of structural stress intensity on structural patterns in different tectonic episodes. These were conducted based on the paleostress measurement by acoustic emission method and the inversion principle of the stress fields in ancient periods and the present, as well as previous research achievements. The results of this paper demonstrate that the third episode of Yanshanian Movement (Yanshanian III) had the maximum activity intensity and tremendously influenced the structural pattern in the study area. The maximum horizontal principal stress of Yanshanian III varied with depth as follows: 0.0168 x + 37.001 (MPa), R2 = 0.8891. The regional structural fractures were mainly formed in Yanshanian III in Xujiahe Formation, west Sichuan Basin, of which the maximum paleoprincipal stress ranging from 85.1 MPa to 120.1 MPa. In addition, the law stating the present maximum horizontal principal stress varies with depth was determined to be 0.0159 x+10.221 (MPa), R2=0.7868 in Wuling Mountain area. Meanwhile, it was determined to be 0.0221 x+9.4733 (MPa), R2=0.9121 in the western part of Xuefeng Mountain area and 0.0174 x+10.247 (MPa), R2=0.8064 in the whole study area. These research results will not only provide data for the simulation of stress field, the evaluation of deformation degree, and the prediction of structural fractures, but also offer absolute geological scientific bases for the elevation of favorable shale gas preservation.
The Sichuan Basin is one of the vital basins in China, boasting abundant hydrocarbon reservoirs. To clarify the intensity of the tectonic stress field of different tectonic episodes since the Mesozoic and to identify the regional dynamic background of different tectonic movements in the Sichuan Basin and its adjacent areas, the characteristics of the acoustic emission in rocks in different strata of these areas were researched in this paper. Meanwhile, the tectonic stress magnitude in these areas since the Mesozoic was restored. The laws state that the tectonic stress varied with depth was revealed, followed by the discussion of the influence of structural stress intensity on structural patterns in different tectonic episodes. These were conducted based on the paleostress measurement by acoustic emission method and the inversion principle of the stress fields in ancient periods and the present, as well as previous research achievements. The results of this paper demonstrate that the third episode of Yanshanian Movement (Yanshanian III) had the maximum activity intensity and tremendously influenced the structural pattern in the study area. The maximum horizontal principal stress of Yanshanian III varied with depth as follows: 0.0168 x + 37.001 (MPa), R2 = 0.8891. The regional structural fractures were mainly formed in Yanshanian III in Xujiahe Formation, west Sichuan Basin, of which the maximum paleoprincipal stress ranging from 85.1 MPa to 120.1 MPa. In addition, the law stating the present maximum horizontal principal stress varies with depth was determined to be 0.0159 x+10.221 (MPa), R2=0.7868 in Wuling Mountain area. Meanwhile, it was determined to be 0.0221 x+9.4733 (MPa), R2=0.9121 in the western part of Xuefeng Mountain area and 0.0174 x+10.247 (MPa), R2=0.8064 in the whole study area. These research results will not only provide data for the simulation of stress field, the evaluation of deformation degree, and the prediction of structural fractures, but also offer absolute geological scientific bases for the elevation of favorable shale gas preservation.
2020, 3(4): 602-610.
doi: 10.31035/cg2020057
Abstract:
Thirty-nine crude oils and twenty-one rock samples from Niger Delta Basin, Nigeria have been characterized based on their isotope compositions by elemental analysis-isotope ratio mass spectrometry and gas chromatography-isotope ratio mass spectrometry. The bulk carbon isotopic values of the whole rock extracts, saturate and aromatic fractions range from –28.7‰ to –26.8‰, –29.2‰ to –27.2 ‰ and –28.5‰ to –26.7‰, respectively while the bulk carbon isotopic values of the whole oils, saturate and aromatic fractions range from –25.4‰ to –27.8‰, –25.9‰ to –28.4‰ and –23.5‰ to –26.9‰, respectively. The average carbon isotopic compositions of individual alkanes (nC12-nC33) in the rock samples range from –34.9‰ to –28.2‰ whereas the average isotopic values of individual n-alkanes in the oils range from –31.1‰ to –23.8‰. The δ13C isotope ratios of pristane and phytane in the rock samples range from –29.2‰ to –28.2‰ and –30.2‰ to –27.4‰ respectively while the pristane and phytane isotopic values range from –32.1‰ to –21.9‰ and –30.5‰ to –26.9‰, respectively. The isotopic values recorded for the samples indicated that the crude oils were formed from the mixed input of terrigenous and marine organic matter and deposited under oxic to sub-oxic condition in lacustrine-fluvial/deltaic environments. The stable carbon isotopic compositions were found to be effective in assessing the origin and depositional environments of crude oils in the Niger Delta Basin.
Thirty-nine crude oils and twenty-one rock samples from Niger Delta Basin, Nigeria have been characterized based on their isotope compositions by elemental analysis-isotope ratio mass spectrometry and gas chromatography-isotope ratio mass spectrometry. The bulk carbon isotopic values of the whole rock extracts, saturate and aromatic fractions range from –28.7‰ to –26.8‰, –29.2‰ to –27.2 ‰ and –28.5‰ to –26.7‰, respectively while the bulk carbon isotopic values of the whole oils, saturate and aromatic fractions range from –25.4‰ to –27.8‰, –25.9‰ to –28.4‰ and –23.5‰ to –26.9‰, respectively. The average carbon isotopic compositions of individual alkanes (nC12-nC33) in the rock samples range from –34.9‰ to –28.2‰ whereas the average isotopic values of individual n-alkanes in the oils range from –31.1‰ to –23.8‰. The δ13C isotope ratios of pristane and phytane in the rock samples range from –29.2‰ to –28.2‰ and –30.2‰ to –27.4‰ respectively while the pristane and phytane isotopic values range from –32.1‰ to –21.9‰ and –30.5‰ to –26.9‰, respectively. The isotopic values recorded for the samples indicated that the crude oils were formed from the mixed input of terrigenous and marine organic matter and deposited under oxic to sub-oxic condition in lacustrine-fluvial/deltaic environments. The stable carbon isotopic compositions were found to be effective in assessing the origin and depositional environments of crude oils in the Niger Delta Basin.
2020, 3(4): 611-622.
doi: 10.31035/cg2020049
Abstract:
The Makran accretionary prism is located at the junction of the Eurasian Plate, Arabian Plate and Indian Plate and is rich in natural gas hydrate (NGH) resources. It consists of a narrow continental shelf, a broad continental slope, and a deformation front. The continental slope can be further divided into the upper slope, middle slope, and lower slope. There are three types of diapir structure in the accretionary prism, namely mud diapir, mud volcano, and gas chimney. (1) The mud diapirs can be grouped into two types, namely the ones with low arching amplitude and weak-medium activity energy and the ones with high arching amplitude and medium-strong activity energy. The mud diapirs increase from offshore areas towards onshore areas in general, while the ones favorable for the formation of NGH are mainly distributed on the middle slope in the central and western parts of the accretionary prism. (2) The mud volcanoes are mainly concentrated along the anticline ridges in the southern part of the lower slope and the deformation front. (3) The gas chimneys can be grouped into three types, which are located in piggyback basins, active anticline ridges, and inactive anticline ridges, respectively. They are mainly distributed on the middle slope in the central and western parts of the accretionary prism and most of them are accompanied with thrust faults. The gas chimneys located at different tectonic locations started to be active at different time and pierced different horizons. The mud diapirs, mud volcanoes, and gas chimneys and thrust faults serve as the main pathways of gas migration, and thus are the important factors that control the formation, accumulation, and distribution of NGH in the Makran accretionary prism. Mud diapir/gas chimney type hydrate develop in the middle slope, mud volcano type hydrate develop in the southern lower slope and the deformation front, and stepped accretionary prism type hydrate develop on the central and northern lower slope. The middle slope, lower slope and deformation front in the central and western parts of the Makran accretionary prism jointly constitute the NGH prospect area.
The Makran accretionary prism is located at the junction of the Eurasian Plate, Arabian Plate and Indian Plate and is rich in natural gas hydrate (NGH) resources. It consists of a narrow continental shelf, a broad continental slope, and a deformation front. The continental slope can be further divided into the upper slope, middle slope, and lower slope. There are three types of diapir structure in the accretionary prism, namely mud diapir, mud volcano, and gas chimney. (1) The mud diapirs can be grouped into two types, namely the ones with low arching amplitude and weak-medium activity energy and the ones with high arching amplitude and medium-strong activity energy. The mud diapirs increase from offshore areas towards onshore areas in general, while the ones favorable for the formation of NGH are mainly distributed on the middle slope in the central and western parts of the accretionary prism. (2) The mud volcanoes are mainly concentrated along the anticline ridges in the southern part of the lower slope and the deformation front. (3) The gas chimneys can be grouped into three types, which are located in piggyback basins, active anticline ridges, and inactive anticline ridges, respectively. They are mainly distributed on the middle slope in the central and western parts of the accretionary prism and most of them are accompanied with thrust faults. The gas chimneys located at different tectonic locations started to be active at different time and pierced different horizons. The mud diapirs, mud volcanoes, and gas chimneys and thrust faults serve as the main pathways of gas migration, and thus are the important factors that control the formation, accumulation, and distribution of NGH in the Makran accretionary prism. Mud diapir/gas chimney type hydrate develop in the middle slope, mud volcano type hydrate develop in the southern lower slope and the deformation front, and stepped accretionary prism type hydrate develop on the central and northern lower slope. The middle slope, lower slope and deformation front in the central and western parts of the Makran accretionary prism jointly constitute the NGH prospect area.
2020, 3(4): 623-632.
doi: 10.31035/cg2020064
Abstract:
North Carnarvon Basin is a gas province with minor oily sweet spots in deepwater area with water depth more than 500 m, which is one of the hot spots of global petroleum exploration for its series of giant hydrocarbon discoveries in recent years. However, the degree of oil and gas exploration in deepwater area is still low, and the conditions for oil and gas accumulation are not clear. Based on the current exploration situation and latest database of fields, applying multidisciplinary analysis of hydrocarbon geology, hydrocarbon accumulation elements and its exploration direction of North Carnarvon Basin in deepwater area are analyzed. The results show that there are three sets of main source rocks in deepwater area of North Carnarvon Basin, which are Triassic marine shale in Locker Formation and delta coal-bearing mudstone with thin carbonaceous mudstone in Mungaroo Formation, Lower–Middle Jurassic paralic carbargilite and coal measure strata in Athol Formation and Murat Formation, Cretaceous delta mudstone in Barrow Group and marine shale in Muderong Formation. Most source rock samples show gas-prone capability. The coarse sandstone of delta facies in Middle–Upper Triassic Mungaroo Formation is the most important reservoir in deepwater area, Lower Cretaceous Barrow Group deep-water gravity flow or underwater fan turbidite sandstone is the secondly main reservoir. Lower Cretaceous marine shale in Muderong Formation is most important regional caprock. Triassic mudstone in Mungaroo Formation is an important interlayer caprock in deepwater area. There are two main reservoir accumulation assemblages in deepwater area, one is Triassic structural-unconformity plane reservoir accumulation assemblage of Locker Formation to Mungaroo Formation, and the other is Lower–Middle Jurassic Athol Formation and Murat Formation–Lower Cretaceous stratigraphic lithology-structural reservoir accumulation assemblage of Barrow Group to Muderong Formation. There are three main control factors of hydrocarbon Accumulation: One is coupling of source and seal control hydrocarbon distribution area, the second is multi-stage large wave dominated deltas dominate accumulation zone, the third is direction of hydrocarbon migration and accumulation in hydrocarbon-rich generation depression was controlled by overpressure. The south of Exmouth platform in deepwater area is adjacent to hydrocarbon rich depression zone, reservoir assemblage is characterized by “near source rocks, excellent reservoir facies, high position and excellent caprocks”, which is the main battlefield of deepwater oil and gas exploration in North Carnarvon Basin at present. There are a lot of fault block traps in the northern structural belt of Exmouth platform, and the favorable sedimentary facies belt at the far end of delta plain in Mungaroo Formation is widely distributed, which is the next favorable exploration zone. The Lower Cretaceous, which is located at the concave edge uplift adjacent to the investigator depression and the Exmouth platform, also has a certain exploration prospect in northwest of deepwater area.
North Carnarvon Basin is a gas province with minor oily sweet spots in deepwater area with water depth more than 500 m, which is one of the hot spots of global petroleum exploration for its series of giant hydrocarbon discoveries in recent years. However, the degree of oil and gas exploration in deepwater area is still low, and the conditions for oil and gas accumulation are not clear. Based on the current exploration situation and latest database of fields, applying multidisciplinary analysis of hydrocarbon geology, hydrocarbon accumulation elements and its exploration direction of North Carnarvon Basin in deepwater area are analyzed. The results show that there are three sets of main source rocks in deepwater area of North Carnarvon Basin, which are Triassic marine shale in Locker Formation and delta coal-bearing mudstone with thin carbonaceous mudstone in Mungaroo Formation, Lower–Middle Jurassic paralic carbargilite and coal measure strata in Athol Formation and Murat Formation, Cretaceous delta mudstone in Barrow Group and marine shale in Muderong Formation. Most source rock samples show gas-prone capability. The coarse sandstone of delta facies in Middle–Upper Triassic Mungaroo Formation is the most important reservoir in deepwater area, Lower Cretaceous Barrow Group deep-water gravity flow or underwater fan turbidite sandstone is the secondly main reservoir. Lower Cretaceous marine shale in Muderong Formation is most important regional caprock. Triassic mudstone in Mungaroo Formation is an important interlayer caprock in deepwater area. There are two main reservoir accumulation assemblages in deepwater area, one is Triassic structural-unconformity plane reservoir accumulation assemblage of Locker Formation to Mungaroo Formation, and the other is Lower–Middle Jurassic Athol Formation and Murat Formation–Lower Cretaceous stratigraphic lithology-structural reservoir accumulation assemblage of Barrow Group to Muderong Formation. There are three main control factors of hydrocarbon Accumulation: One is coupling of source and seal control hydrocarbon distribution area, the second is multi-stage large wave dominated deltas dominate accumulation zone, the third is direction of hydrocarbon migration and accumulation in hydrocarbon-rich generation depression was controlled by overpressure. The south of Exmouth platform in deepwater area is adjacent to hydrocarbon rich depression zone, reservoir assemblage is characterized by “near source rocks, excellent reservoir facies, high position and excellent caprocks”, which is the main battlefield of deepwater oil and gas exploration in North Carnarvon Basin at present. There are a lot of fault block traps in the northern structural belt of Exmouth platform, and the favorable sedimentary facies belt at the far end of delta plain in Mungaroo Formation is widely distributed, which is the next favorable exploration zone. The Lower Cretaceous, which is located at the concave edge uplift adjacent to the investigator depression and the Exmouth platform, also has a certain exploration prospect in northwest of deepwater area.
2020, 3(4): 633-642.
doi: 10.31035/cg2020051
Abstract:
Oil and gas resources are short in Pakistan and no commercially viable oil and gas sources have been yet discovered in its offshore areas up to now. In this study, the onshore-offshore stratigraphic correlation and seismic data interpretation were conducted to determine the oil and gas resource potential in the Offshore Indus Basin, Pakistan. Based on the comprehensive analysis of the results and previous data, it is considered that the Cretaceous may widely exist and three sets of source rocks may be developed in the Offshore Indus Basin. The presence of Miocene mudstones has been proven by drilling to be high-quality source rocks, while the Cretaceous and Paleocene–Eocene mudstones are potential source rocks. Tectonic-lithologic traps are developed in the northwestern part of the basin affected by the strike-slip faults along Murray Ridge. Furthermore, the Cretaceous and Paleocene–Eocene source rocks are thick and are slightly affected by volcanic activities. Therefore, it can be inferred that the northwestern part of Offshore Indus Basin enjoys good prospects of oil and gas resources.
Oil and gas resources are short in Pakistan and no commercially viable oil and gas sources have been yet discovered in its offshore areas up to now. In this study, the onshore-offshore stratigraphic correlation and seismic data interpretation were conducted to determine the oil and gas resource potential in the Offshore Indus Basin, Pakistan. Based on the comprehensive analysis of the results and previous data, it is considered that the Cretaceous may widely exist and three sets of source rocks may be developed in the Offshore Indus Basin. The presence of Miocene mudstones has been proven by drilling to be high-quality source rocks, while the Cretaceous and Paleocene–Eocene mudstones are potential source rocks. Tectonic-lithologic traps are developed in the northwestern part of the basin affected by the strike-slip faults along Murray Ridge. Furthermore, the Cretaceous and Paleocene–Eocene source rocks are thick and are slightly affected by volcanic activities. Therefore, it can be inferred that the northwestern part of Offshore Indus Basin enjoys good prospects of oil and gas resources.
Support service of geological technology in lifting residents of endemic disease area out of poverty
2020, 3(4): 656-660.
doi: 10.31035/cg2020074
Abstract:
2020, 3(4): 1-2.
Abstract:
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