Subsurface pore pressure affects the direction of hydrocarbon migration, determines the distribut... more Subsurface pore pressure affects the direction of hydrocarbon migration, determines the distribution of the hydrocarbon reservoir, and provides scientific reference for drilling planning. Overpressures are widespread in the Paleogene Shahejie Formation in the Linnan Sag, which is closely related to the distribution of oil reservoir. However, the overpressure generation mechanisms are undefined, let alone the relationship between the evolution of paleo-overpressure and hydrocarbon migration in the Linnan Sag, which brings great challenges for the understanding of oil accumulation and future oil exploration. Basin modeling was carried out to solve the issue of quantitative evaluation of overpressure mechanisms and to restore the overpressure evolution of the Paleogene source rocks. The implications for the pore pressure prediction and oil migration in the Linnan Sag were further discussed. The modeling results show that the disequilibrium compaction of mudstones is a dominated overpre...
Heat flow and associated thermal regimes are related to the tectonic evolution and geophysical pr... more Heat flow and associated thermal regimes are related to the tectonic evolution and geophysical properties of the lithosphere. The Ordos Basin is located in a tectonic transitional zone: areas to the east of the basin are characterized as tectonically active, while regions to the west of the basin are characterized as tectonically stable. It is of general interest to learn the geothermal characteristics of the basin in such tectonic conditions. To clarify the spatial variability of the present-day geothermal field across the basin and its implications, we report 13 terrestrial heat flow points based on the first systematic steady-state deep borehole temperature measurements in the basin. The new data together with existing data show that the geothermal gradients in the basin range from 12.6 to 42.3 • C km −1 with a mean of 27.7 ± 5.3 • C km −1 ; the terrestrial heat flow values range from 43.3 to 88.7 mW m −2 with a mean of 64.7 ± 8.9 mW m −2. Such values are higher than those of typical cratonic basins and lower than those of tectonically active areas. By using all these data in the basin and adjacent areas, we plot geothermal gradient and heat flow distribution maps. The maps reveal that the basin is cooling westwards and northwards. The distribution pattern of the geothermal field is consistent with the lithospheric thickness variation in the basin. This similarity suggests that the geothermal spatial variability of the Ordos Basin is mainly influenced by heat from the deep mantle. In the southeastern basin, we locate a positive geothermal anomaly caused by the convergence of heat flow in basement highs and the high radiogenic heat production. In addition, the high heat flow in the eastern basin is related to the intense uplift during the Cenozoic Era.
ABSTRACT The organic geochemistry, mineralogy and methane sorption of lacustrine shales of the Up... more ABSTRACT The organic geochemistry, mineralogy and methane sorption of lacustrine shales of the Upper Triassic Yanchang Formation, collected from the south-eastern Ordos Basin, were investigated to characterize them and clarify the effects of shale composition on their sorbed gas capacity. These Yanchang shales have recently been selected as a target area for shale gas exploration in typical terrestrial strata in China. The two main sections of these shales containing type II organic matters, Chang 7 and Chang 9, have relatively high total organic carbon content (TOC) of 2–10%. The two shales also have similar mineralogies, mainly comprising quartz, clay minerals and feldspars. Both the Chang 7 and Chang 9 shales are generally in the oil window; Chang 9 is slightly more mature than Chang 7. Higher methane sorption capacity was observed for Chang 9 than for Chang 7 shales, determined on a dried basis at 50 °C. Methane sorption measurements were further performed on three samples from which the residual bitumen had been extracted, and their corresponding kerogen fractions, to gain insight into the effects of shale composition on methane sorption. This was significantly higher in solvent-extracted samples than in raw samples, indicating that residual bitumen largely restricts methane sorption on such shales. A positive correlation between the amount of clay minerals and methane sorption capacity of bulk rocks was evident, suggesting that clay mineral content is relevant to methane sorption. This result was also supported by the much higher methane sorption capacity of solvent-extracted shales compared to the extracted kerogen from those shales, when measured sorption data was normalized to TOC values. The effects of both residual bitumen and clay mineral on the methane sorption of bulk rocks have complicated the evaluation of methane sorption on organic matter in these mature shales.
Abstract These effective reservoir rocks that can have sufficient porosity and permeability and h... more Abstract These effective reservoir rocks that can have sufficient porosity and permeability and hydrocarbon accumulations determine economic reserves and high yield of tight oil and gas. Understanding the origin and distribution of these effective reservoir rocks is important for sorting out “sweet spots” in tight reservoirs. Multiple-scale analyses from the microscopic, via drill core to single wellbore have been conducted to examine reservoir heterogeneity of the Upper Paleozoic Shanxi Formation in the southeastern Ordos Basin. Five sandstone petrofacies have been defined in terms of texture and framework composition, detrital matrix, diagenesis and pore types: quartz arenite, tuffaceous quartz arenite, ductile lithic-lean sub-litharenite, ductile lithic-rich sandstone and tightly carbonate-cemented sandstone. The various petrofacies show fundamentally different pathways of diagenetic and reservoir-quality evolutions, due to the complexity of texture and detrital composition in the Shanxi Formation, directly related to the provenance and depositional environment. Quartz arenites and ductile grain-lean sub-litharenites both form effective reservoir rocks. By translating petrofacies to well-log signatures corrected from petrographic and core analysis data, a model based on factor analysis has been built to predict petrofacies at the well scale. For investigating the distribution of each petrofacies at the field scale, sequential indicator simulation method has been used to construct a 3-D petrofacies model with facies conditioning. The isopach maps of quartz arenites and ductile lithic-lean sub-litharenites have been made from the 3-D petrofacies model to quantify their areal distributions, and to define the “sweet spots” by combining isopach maps of these effective reservoir rocks and gas production data from well tests. The concept of reservoir petrofacies is an important tool for the characterization of tight sandstone reservoirs.
Subsurface pore pressure affects the direction of hydrocarbon migration, determines the distribut... more Subsurface pore pressure affects the direction of hydrocarbon migration, determines the distribution of the hydrocarbon reservoir, and provides scientific reference for drilling planning. Overpressures are widespread in the Paleogene Shahejie Formation in the Linnan Sag, which is closely related to the distribution of oil reservoir. However, the overpressure generation mechanisms are undefined, let alone the relationship between the evolution of paleo-overpressure and hydrocarbon migration in the Linnan Sag, which brings great challenges for the understanding of oil accumulation and future oil exploration. Basin modeling was carried out to solve the issue of quantitative evaluation of overpressure mechanisms and to restore the overpressure evolution of the Paleogene source rocks. The implications for the pore pressure prediction and oil migration in the Linnan Sag were further discussed. The modeling results show that the disequilibrium compaction of mudstones is a dominated overpre...
Heat flow and associated thermal regimes are related to the tectonic evolution and geophysical pr... more Heat flow and associated thermal regimes are related to the tectonic evolution and geophysical properties of the lithosphere. The Ordos Basin is located in a tectonic transitional zone: areas to the east of the basin are characterized as tectonically active, while regions to the west of the basin are characterized as tectonically stable. It is of general interest to learn the geothermal characteristics of the basin in such tectonic conditions. To clarify the spatial variability of the present-day geothermal field across the basin and its implications, we report 13 terrestrial heat flow points based on the first systematic steady-state deep borehole temperature measurements in the basin. The new data together with existing data show that the geothermal gradients in the basin range from 12.6 to 42.3 • C km −1 with a mean of 27.7 ± 5.3 • C km −1 ; the terrestrial heat flow values range from 43.3 to 88.7 mW m −2 with a mean of 64.7 ± 8.9 mW m −2. Such values are higher than those of typical cratonic basins and lower than those of tectonically active areas. By using all these data in the basin and adjacent areas, we plot geothermal gradient and heat flow distribution maps. The maps reveal that the basin is cooling westwards and northwards. The distribution pattern of the geothermal field is consistent with the lithospheric thickness variation in the basin. This similarity suggests that the geothermal spatial variability of the Ordos Basin is mainly influenced by heat from the deep mantle. In the southeastern basin, we locate a positive geothermal anomaly caused by the convergence of heat flow in basement highs and the high radiogenic heat production. In addition, the high heat flow in the eastern basin is related to the intense uplift during the Cenozoic Era.
ABSTRACT The organic geochemistry, mineralogy and methane sorption of lacustrine shales of the Up... more ABSTRACT The organic geochemistry, mineralogy and methane sorption of lacustrine shales of the Upper Triassic Yanchang Formation, collected from the south-eastern Ordos Basin, were investigated to characterize them and clarify the effects of shale composition on their sorbed gas capacity. These Yanchang shales have recently been selected as a target area for shale gas exploration in typical terrestrial strata in China. The two main sections of these shales containing type II organic matters, Chang 7 and Chang 9, have relatively high total organic carbon content (TOC) of 2–10%. The two shales also have similar mineralogies, mainly comprising quartz, clay minerals and feldspars. Both the Chang 7 and Chang 9 shales are generally in the oil window; Chang 9 is slightly more mature than Chang 7. Higher methane sorption capacity was observed for Chang 9 than for Chang 7 shales, determined on a dried basis at 50 °C. Methane sorption measurements were further performed on three samples from which the residual bitumen had been extracted, and their corresponding kerogen fractions, to gain insight into the effects of shale composition on methane sorption. This was significantly higher in solvent-extracted samples than in raw samples, indicating that residual bitumen largely restricts methane sorption on such shales. A positive correlation between the amount of clay minerals and methane sorption capacity of bulk rocks was evident, suggesting that clay mineral content is relevant to methane sorption. This result was also supported by the much higher methane sorption capacity of solvent-extracted shales compared to the extracted kerogen from those shales, when measured sorption data was normalized to TOC values. The effects of both residual bitumen and clay mineral on the methane sorption of bulk rocks have complicated the evaluation of methane sorption on organic matter in these mature shales.
Abstract These effective reservoir rocks that can have sufficient porosity and permeability and h... more Abstract These effective reservoir rocks that can have sufficient porosity and permeability and hydrocarbon accumulations determine economic reserves and high yield of tight oil and gas. Understanding the origin and distribution of these effective reservoir rocks is important for sorting out “sweet spots” in tight reservoirs. Multiple-scale analyses from the microscopic, via drill core to single wellbore have been conducted to examine reservoir heterogeneity of the Upper Paleozoic Shanxi Formation in the southeastern Ordos Basin. Five sandstone petrofacies have been defined in terms of texture and framework composition, detrital matrix, diagenesis and pore types: quartz arenite, tuffaceous quartz arenite, ductile lithic-lean sub-litharenite, ductile lithic-rich sandstone and tightly carbonate-cemented sandstone. The various petrofacies show fundamentally different pathways of diagenetic and reservoir-quality evolutions, due to the complexity of texture and detrital composition in the Shanxi Formation, directly related to the provenance and depositional environment. Quartz arenites and ductile grain-lean sub-litharenites both form effective reservoir rocks. By translating petrofacies to well-log signatures corrected from petrographic and core analysis data, a model based on factor analysis has been built to predict petrofacies at the well scale. For investigating the distribution of each petrofacies at the field scale, sequential indicator simulation method has been used to construct a 3-D petrofacies model with facies conditioning. The isopach maps of quartz arenites and ductile lithic-lean sub-litharenites have been made from the 3-D petrofacies model to quantify their areal distributions, and to define the “sweet spots” by combining isopach maps of these effective reservoir rocks and gas production data from well tests. The concept of reservoir petrofacies is an important tool for the characterization of tight sandstone reservoirs.
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