Alluvial stratigraphy is influenced by both allogenic and autogenic factors, which are difficult to be distinguished from each other because they operate at overlapping spatial and temporal scales. Moreover, it remains uncertain whether autogenic dynamics can result in sedimentary cyclicity that resembles allogenically-driven stratigraphic products. In order to undertake this challenge and address the uncertainty, we first test what sedimentary processes can produce the alluvial cyclicity observed in outcrops by designing comparable scenarios in the process-based numerical modelling. In the meantime, we systematically characterize floodplain aggradation cycles by tracing them in a UAV-based photogrammetric model. Moreover, we comprehensively describe channelized sandstone bodies in the field and the model to reconstruct the paleogeography. Lastly, we configure the relationships between floodplain aggradation cycles and sandstone bodies of different river styles, based on which we identify the link between orbital forcing and alluvial stratigraphic response.@en

The middle Eocene Dongying sag in the Bohai Bay Basin of China has an estimated shale oil resource of approximately 1.1 billion t (8.06 billion bbl); flows of shale oil have been produced in the succession from tens of wells, where the daily production of a single well generally varies between 10 and 100 t (73.3–733 bbl). Therein, the mudrock successions composed of meter-scale mudstone–limestone couplets are the most important shale oil-producing layers. The controls on the deposition of the meter-scale mudstone–limestone couplets, however, remain enigmatic, constraining the analysis of lithofacies and, therefore, sweet spot distributions. Here, we analyze three continuously cored organic-rich successions of mudstone–limestone couplets (371 m [1217 ft] in total) in the middle Eocene Dongying sag, accompanied by decimeter- to meter-scale sampling and testing of mineralogy, organic geochemistry, and paleontology of the rocks. Our integrated cyclostratigraphic analysis shows that the observed mudstone–limestone couplets occur at periods that coincide with Milankovitch periodicities; 21-k.y. precession cycles are the main driver of the meter-scale mudstone–limestone couplets, with additional imprints of 41-k.y. obliquity cycles. Specifically, precession minima are associated with high summer insolation and consequently high summer monsoonal precipitation, which increased river discharge and terrigenous input to the basin, resulting in the deposition of siliciclastic-rich mudstones. In the study, low summer insolation during precession maxima led to decreased summer monsoonal precipitation, lower river discharge and terrigenous input, and increased lake water salinity, resulting in the deposition of authigenic lime mudstones. The shale reservoir quality kept pace with the orbital climate changes; compared with lime mudstones deposited during precession maxima, mudstones deposited during precession minima had higher total organic carbon, porosity, and oil content, but lower brittleness.@en

Formation of alluvial stratigraphy is controlled by autogenic processes that mix their imprints with allogenic forcing. In some alluvial successions, sedimentary cycles have been linked to astronomically-driven, cyclic climate changes. However, it remains challenging to define how such cyclic allogenic forcing leads to sedimentary cycles when it continuously occurs in concert with autogenic forcing. Accordingly, we evaluate the impact of cyclic and non-cyclic upstream forcing on alluvial stratigraphy through a process-based alluvial architecture model, the Karssenberg and Bridge (2008) model (KB08). The KB08 model depicts diffusion-based sediment transport, erosion and deposition within a network of channel belts and associated floodplains, with river avulsion dependent on lateral floodplain gradient, flood magnitude and frequency, and stochastic components. We find cyclic alluvial stratigraphic patterns to occur when there is cyclicity in the ratio of sediment supply over water discharge (Qs/Qw ratio), in the precondition that the allogenic forcing has sufficiently large amplitudes and long, but not very long, wavelengths, depending on inherent properties of the modelled basin (e.g. basin subsidence, size, and slope). Each alluvial stratigraphic cycle consists of two phases: an aggradation phase characterized by rapid sedimentation due to frequent channel shifting and a non-deposition phase characterized by channel belt stability and, depending on Qs/Qw amplitudes, incision. Larger Qs/Qw ratio amplitudes contribute to weaker downstream signal shredding by stochastic components in the model. Floodplain topographic differences are found to be compensated by autogenic dynamics at certain compensational timescales in fully autogenic runs, while the presence of allogenic forcing clearly impacts the compensational stacking patterns.@en

ABSTRACT The lower Eocene Willwood Formation of the Bighorn Basin, Wyoming, USA, is an alluvial succession with a sand content varying around 25 palaeoenvironments and palaeoclimates, as well as sedimentological and stratigraphic analysis. Channel dynamics were studied at a relatively low resolution throughout the basin over the geological time from late Palaeocene to early Eocene. Here, a high-resolution study is reported to complement previous research at the basin scale. Efforts are made to document the characteristics and river planform styles of most sandstone bodies encountered through ca 300 m of alluvial stratigraphy in a 10 km2 area of the Deer Creek part of the McCullough Peaks area situated in the basin axis of northern Bighorn Basin. Four channel facies associations are recognized and ascribed to four river planform styles: crevasse channel, trunk channel, braided-like channel and sinuous-like channel, with the latter two types dominant. Braided-like and sinuous-like channel sandstone bodies differ significantly in thicknesses, being on average 6.1 m versus 9.0 m, but they have similar palaeoflow–perpendicular widths of on average 231 m and palaeoflow directions of on average N 003°. Braided-like and sinuous-like river planform styles show no spatial dependency in the 10 km2 study area. Results of this study are in line with existing basin-scale depositional models that are composed of a single axial system fed by several transverse systems dominantly from the west. The feeding of these systems could be influenced by palaeoclimate changes possibly controlling their contribution over time, thereby impacting river planform styles. At the same time, changing water discharge hydrograph, sediment load, and overbank cohesiveness may have equally driven the observed river planform style changes within the basin without a major role of catchments.@en

The middle Eocene was a key period of global climate change from a warm “greenhouse” to a cooling “doubthouse”. At the middle Eocene, an extensive arid climate in China was recorded in the mudstones and shales interbedded with salinastone which formed good hydrocarbon source rocks, especially in the Bohai Bay Basin. The sedimentary paleoenvironment and its variations affected the source rock quality and distribution. Based on successive and dense sampling of the middle Eocene Shahejie Formation shale (MES shale) in Nanpu Sag of Bohai Bay Basin, petro-mineralogical tests, geochemical methods and spectrum analysis were performed to analyse the palaeoenvironmental fluctuations and the responses to Milankovitch cycles. Element analysis on MES shale shows that the middle Eocene climate was arid and the sediments were deposited under dysoxic/suboxic conditions with relatively high salinity. Based on the Δlog R method, the organic matter (OM) abundance was evaluated and ranged from 0.18 to 3.55 wt % for MES shale. The mean primary productivity of 545 g C m−2 yr−1 shows a eutrophic environment in middle Eocene Nanpu paleolake. Wavelet analysis performed on gamma logging and palaeoenvironmental proxies revealed clear Milankovitch cycles for MES shale, and the cyclostratigraphic and palaeoenvironmental fluctuations were effected by astronomical oscillation periods of the short eccentricity cycle (100 k.y.), obliquity cycle (39 k.y.) and precession cycle (19 k.y.). The depositional rate of MES shale was corrected to 0.43 m/k.y. The sedimental process of MES shale was associated with palaeoenvironmental variation, which have been divided into four stages affecting OM accumulation. A hypothesis that the vast carbon of “greenhouse” gases in the Palaeocene and early Eocene was fixed in organic matters during middle Eocene and enriched in the hydrocarbon source rocks of the sedimentary basins formed at early Eocene was proposed to explain the “doubthouse” world in the Eocene.@en

The middle Eocene was a key period of global climate change from a warm “greenhouse” to a cooling “doubthouse”. At the middle Eocene, an extensive arid climate in China was recorded in the mudstones and shales interbedded with salinastone which formed good hydrocarbon source rocks, especially in the Bohai Bay Basin. The sedimentary paleoenvironment and its variations affected the source rock quality and distribution. Based on successive and dense sampling of the middle Eocene Shahejie Formation shale (MES shale) in Nanpu Sag of Bohai Bay Basin, petro-mineralogical tests, geochemical methods and spectrum analysis were performed to analyse the palaeoenvironmental fluctuations and the responses to Milankovitch cycles. Element analysis on MES shale shows that the middle Eocene climate was arid and the sediments were deposited under dysoxic/suboxic conditions with relatively high salinity. Based on the Δlog R method, the organic matter (OM) abundance was evaluated and ranged from 0.18 to 3.55 wt % for MES shale. The mean primary productivity of 545 g C m−2 yr−1 shows a eutrophic environment in middle Eocene Nanpu paleolake. Wavelet analysis performed on gamma logging and palaeoenvironmental proxies revealed clear Milankovitch cycles for MES shale, and the cyclostratigraphic and palaeoenvironmental fluctuations were effected by astronomical oscillation periods of the short eccentricity cycle (100 k.y.), obliquity cycle (39 k.y.) and precession cycle (19 k.y.). The depositional rate of MES shale was corrected to 0.43 m/k.y. The sedimental process of MES shale was associated with palaeoenvironmental variation, which have been divided into four stages affecting OM accumulation. A hypothesis that the vast carbon of “greenhouse” gases in the Palaeocene and early Eocene was fixed in organic matters during middle Eocene and enriched in the hydrocarbon source rocks of the sedimentary basins formed at early Eocene was proposed to explain the “doubthouse” world in the Eocene.@en

In order to determine the source of the light hydrocarbons in the Kuqa Depression of the Tarim Basin, Northwest China, their geochemical characteristics are documented, and possible influencing factors are discussed in a broad context on the basis of geochemical analyses of natural gas samples from 19 wells in combination with previously reported natural gas components and carbon isotope values from the same depression. The biomarker analytical results show that (a) methyl cyclohexane (37.5–60.3%) of natural gas predominates the C7 light hydrocarbon series (methyl cyclohexane, heptanes, and dimethyl cyclopentane), and (b) the heptane content (25.0–54.8%) is also relatively high. The C6–7 light hydrocarbon series (aromatics, normal alkanes, and cycloalkanes) have abnormally high aromatics (benzene and toluene) content (26.2–83.8%). Heptane value (13.31–37.77%) and isoheptane value (2.10–7.64%) indicate that the Kuqa natural gases are of high maturity and typical of coal-derived gas (gas generated by sapropelic source rock). Their light hydrocarbons, however, appear to have some characteristics of mixed-source organic matter. Specifically, the light hydrocarbons in the Dina 2 gas field show characteristics of the coal-derived gas; those in the Dabei gas field show some features of the oil-associated gas (gas generated by humic source rock), whereas those in the Kela 2 and Keshen 2 gas fields and Well Yangtake-101 display characteristics of the mixed source organic matter. The abnormally high content of the aromatics in the Kuqa Depression may have resulted mainly from their high productivity during the thermal maturity of humic type organic matters and the gases accumulation of late stage. The different relative contents of the aromatics in various oil and gas fields may have been accounted by different organic matter types, maturity, and distribution patterns of source rocks.@en

In order to determine the source of the light hydrocarbons in the Kuqa Depression of the Tarim Basin, Northwest China, their geochemical characteristics are documented, and possible influencing factors are discussed in a broad context on the basis of geochemical analyses of natural gas samples from 19 wells in combination with previously reported natural gas components and carbon isotope values from the same depression. The biomarker analytical results show that (a) methyl cyclohexane (37.5–60.3%) of natural gas predominates the C7 light hydrocarbon series (methyl cyclohexane, heptanes, and dimethyl cyclopentane), and (b) the heptane content (25.0–54.8%) is also relatively high. The C6–7 light hydrocarbon series (aromatics, normal alkanes, and cycloalkanes) have abnormally high aromatics (benzene and toluene) content (26.2–83.8%). Heptane value (13.31–37.77%) and isoheptane value (2.10–7.64%) indicate that the Kuqa natural gases are of high maturity and typical of coal-derived gas (gas generated by sapropelic source rock). Their light hydrocarbons, however, appear to have some characteristics of mixed-source organic matter. Specifically, the light hydrocarbons in the Dina 2 gas field show characteristics of the coal-derived gas; those in the Dabei gas field show some features of the oil-associated gas (gas generated by humic source rock), whereas those in the Kela 2 and Keshen 2 gas fields and Well Yangtake-101 display characteristics of the mixed source organic matter. The abnormally high content of the aromatics in the Kuqa Depression may have resulted mainly from their high productivity during the thermal maturity of humic type organic matters and the gases accumulation of late stage. The different relative contents of the aromatics in various oil and gas fields may have been accounted by different organic matter types, maturity, and distribution patterns of source rocks.@en

In order to determine the source of the light hydrocarbons in the Kuqa Depression of the Tarim Basin, Northwest China, their geochemical characteristics are documented, and possible influencing factors are discussed in a broad context on the basis of geochemical analyses of natural gas samples from 19 wells in combination with previously reported natural gas components and carbon isotope values from the same depression. The biomarker analytical results show that (a) methyl cyclohexane (37.5–60.3%) of natural gas predominates the C7 light hydrocarbon series (methyl cyclohexane, heptanes, and dimethyl cyclopentane), and (b) the heptane content (25.0–54.8%) is also relatively high. The C6–7 light hydrocarbon series (aromatics, normal alkanes, and cycloalkanes) have abnormally high aromatics (benzene and toluene) content (26.2–83.8%). Heptane value (13.31–37.77%) and isoheptane value (2.10–7.64%) indicate that the Kuqa natural gases are of high maturity and typical of coal-derived gas (gas generated by sapropelic source rock). Their light hydrocarbons, however, appear to have some characteristics of mixed-source organic matter. Specifically, the light hydrocarbons in the Dina 2 gas field show characteristics of the coal-derived gas; those in the Dabei gas field show some features of the oil-associated gas (gas generated by humic source rock), whereas those in the Kela 2 and Keshen 2 gas fields and Well Yangtake-101 display characteristics of the mixed source organic matter. The abnormally high content of the aromatics in the Kuqa Depression may have resulted mainly from their high productivity during the thermal maturity of humic type organic matters and the gases accumulation of late stage. The different relative contents of the aromatics in various oil and gas fields may have been accounted by different organic matter types, maturity, and distribution patterns of source rocks.@en

In order to determine the source of the light hydrocarbons in the Kuqa Depression of the Tarim Basin, Northwest China, their geochemical characteristics are documented, and possible influencing factors are discussed in a broad context on the basis of geochemical analyses of natural gas samples from 19 wells in combination with previously reported natural gas components and carbon isotope values from the same depression. The biomarker analytical results show that (a) methyl cyclohexane (37.5–60.3%) of natural gas predominates the C7 light hydrocarbon series (methyl cyclohexane, heptanes, and dimethyl cyclopentane), and (b) the heptane content (25.0–54.8%) is also relatively high. The C6–7 light hydrocarbon series (aromatics, normal alkanes, and cycloalkanes) have abnormally high aromatics (benzene and toluene) content (26.2–83.8%). Heptane value (13.31–37.77%) and isoheptane value (2.10–7.64%) indicate that the Kuqa natural gases are of high maturity and typical of coal-derived gas (gas generated by sapropelic source rock). Their light hydrocarbons, however, appear to have some characteristics of mixed-source organic matter. Specifically, the light hydrocarbons in the Dina 2 gas field show characteristics of the coal-derived gas; those in the Dabei gas field show some features of the oil-associated gas (gas generated by humic source rock), whereas those in the Kela 2 and Keshen 2 gas fields and Well Yangtake-101 display characteristics of the mixed source organic matter. The abnormally high content of the aromatics in the Kuqa Depression may have resulted mainly from their high productivity during the thermal maturity of humic type organic matters and the gases accumulation of late stage. The different relative contents of the aromatics in various oil and gas fields may have been accounted by different organic matter types, maturity, and distribution patterns of source rocks.@en

In order to determine the source of the light hydrocarbons in the Kuqa Depression of the Tarim Basin, Northwest China, their geochemical characteristics are documented, and possible influencing factors are discussed in a broad context on the basis of geochemical analyses of natural gas samples from 19 wells in combination with previously reported natural gas components and carbon isotope values from the same depression. The biomarker analytical results show that (a) methyl cyclohexane (37.5–60.3%) of natural gas predominates the C7 light hydrocarbon series (methyl cyclohexane, heptanes, and dimethyl cyclopentane), and (b) the heptane content (25.0–54.8%) is also relatively high. The C6–7 light hydrocarbon series (aromatics, normal alkanes, and cycloalkanes) have abnormally high aromatics (benzene and toluene) content (26.2–83.8%). Heptane value (13.31–37.77%) and isoheptane value (2.10–7.64%) indicate that the Kuqa natural gases are of high maturity and typical of coal-derived gas (gas generated by sapropelic source rock). Their light hydrocarbons, however, appear to have some characteristics of mixed-source organic matter. Specifically, the light hydrocarbons in the Dina 2 gas field show characteristics of the coal-derived gas; those in the Dabei gas field show some features of the oil-associated gas (gas generated by humic source rock), whereas those in the Kela 2 and Keshen 2 gas fields and Well Yangtake-101 display characteristics of the mixed source organic matter. The abnormally high content of the aromatics in the Kuqa Depression may have resulted mainly from their high productivity during the thermal maturity of humic type organic matters and the gases accumulation of late stage. The different relative contents of the aromatics in various oil and gas fields may have been accounted by different organic matter types, maturity, and distribution patterns of source rocks.@en

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.@en

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.@en

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.@en

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.@en

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.@en

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.@en

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.@en

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.@en

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.@en