Gas Accumulation Mechanism Research Articles

Influence of Aspect Ratio of Migration Space on Gas Migration and Accumulation Mechanisms of Different Types of Gas Reservoirs

Influence of Aspect Ratio of Migration Space on Gas Migration and Accumulation Mechanisms of Different Types of Gas Reservoirs

Coupling of source rock gas expulsion intensity and reservoir quality in time and space-a key to determine gas accumulation in Upper Paleozoic tight sandstones of the Mugua gas field, Ordos Basin, China

Research on gas accumulation mechanisms and variations in gas saturation is limited in the newly established Mugua gas field in the Ordos Basin. Understanding these aspects is vital for reduce drilling uncertainty and exploration risk. This study employed a variety of methods, including: (1) the use of organic geochemical examinations to determine the gas expulsion intensity of hydrocarbon source rocks; (2) fluid inclusion analyses to determine the time of gas accumulation; (3) a combination of optical microscopy, scanning electron microscopy observations, pore-simulation and permeability tests, mercury-intrusion capillary pressure experiments, and nuclear magnetic resonance studies to assess the properties of the reservoir quality and identify the tight sandstone rock type; (4) wireline logging and interpretive data analyses to research the gas saturations features; and (5) establish reservoir quality evolution model to systematically study this problem. Integrating fluid inclusion homogenization temperatures with burial and thermal histories indicates that gas accumulation in the Mugua gas fields occurred throughout the Early Jurassic to Late Cretaceous period. Five diagenetic facies have been identified: dissolution, quartz-cemented, clay mineral filling, tightly compacted, and carbonate-cemented facies. The reservoir quality evolution model reveals that the five diagenetic facies experienced densification before the period of gas accumulation. Therefore, for gas accumulation in tight sandstones, it is essential that mature and gas-generating source rocks, provide sufficient expulsion forces to drive gas into the rocks. The mechanism of gas accumulation in the Mugua gas field's tight gas sandstone reservoirs involves the process occurring in sandstones that are either near or interbedded with source rocks, under high pore-fluid pressure generated by gas production. Compared to other Upper Paleozoic gas fields in the Ordos Basin, the gas expulsion intensity in the Mugua gas field is lower, ranging from 6.12–8.39 × 108 m3/km2. Due to the low gas expulsion intensity, the Shihezi 8 Member's tight sandstone reservoirs, situated away from the source rock, typically show low gas saturation. Conversely, the dissolution and quartz-cemented facies within the Benxi, Taiyuan, and Shanxi Formations, intimately interbedded with hydrocarbon source rocks, exhibit good reservoir quality. They offer ideal conditions for gas accumulation, making them prime candidates for exploration and development.

Sedimentary paleoenvironment and its control on organic matter enrichment in the Mesoproterozoic hydrocarbon source rocks in the Ordos Basin, southern margin of the North China Craton

The black shale of the Mesoproterozoic Cuizhuang Formation in the Changcheng System in Yongji city, North China Craton, is a potential source rock. Understanding the organic matter enrichment mechanism is crucial for evaluating source rock resources and understanding oil and gas accumulation mechanisms. In this study, we evaluated the sedimentary paleoenvironment and organic matter enrichment mechanisms of shale using thin section observations, mineral composition analysis, organic geochemistry, and elemental geochemistry. We found significant differences in the sedimentary paleoenvironment and organic matter enrichment mechanisms between the lower Cuizhuang Formation and the Beidajian Formation shale. The Cuizhuang Formation was deposited in a late-stage, restricted basin environment during the rift phase, and elemental and geochemical indicators showed that the Cuizhuang Formation was in a suboxic–anoxic water environment, that was influenced by a warm and humid paleoclimate and submarine hydrothermal activities, which promoted the accumulation of organic matter. However, the enrichment of organic matter in the Cuizhuang Formation was mainly controlled by redox conditions. The formation of suboxic-anoxic water environments may be closely related to the warm and humid paleoclimate and submarine hydrothermal activities. Warm conditions promote continental weathering and increase marine productivity, thereby consuming oxygen in the bottom water. Moreover, acidic hydrothermal activity also helps to establish an anoxic environment. Our results reveal the effects controlling various coupled mechanisms dominated by redox conditions, which may explain the development of source rocks in the Cuizhuang Formation.

Influence of tectonic preservation conditions on the nanopore structure of shale reservoir: A case study of Wufeng-Longmaxi Formation shale in western Hubei area, south China

Tectonism is one of the dominant factors affecting the shale pore structure. However, the control of shale pore structure by tectonic movements is still controversial, which limits the research progress of shale gas accumulation mechanism in the complex tectonic region of southern China. In this study, 34 samples were collected from two exploratory wells located in different tectonic locations. Diverse experiments, e.g., organic geochemistry, XRD analysis, FE-SEM, low-pressure gas adsorption, and high-pressure mercury intrusion, were conducted to fully characterize the shale reservoir. The TOC, Ro, and mineral composition of the shale samples between the two wells are similar, which reflects that the shale samples of the two wells have proximate pores-generating capacity and pores-supporting capacity. However, the pore characteristics of shale samples from two wells are significantly different. Compared with the stabilized zone shale, the porosity, pore volume, and specific surface area of the deformed zone shale were reduced by 60.61%, 64.85%, and 27.81%, respectively. Moreover, the macroscopic and fine pores were reduced by 54.01% and 84.95%, respectively. Fault activity and uplift denudation are not conducive to pore preservation, and the rigid basement of Huangling uplift can promote pore preservation. These three factors are important reasons for controlling the difference in pore structure between two wells shales. We established a conceptual model of shale pores evolution under different tectonic preservation conditions. This study is significant to clarify the scale of shale gas formation and enrichment in complex tectonic regions, and helps in the selection of shale sweet spots.

Tight gas charging and accumulation mechanisms and mathematical model

The gas-water distribution and production heterogeneity of tight gas reservoirs have been summarized from experimental and geological observations, but the charging and accumulation mechanisms have not been examined quantitatively by mathematical model. The tight gas charging and accumulation mechanisms were revealed from a combination of physical simulation of nuclear magnetic resonance coupling displacement, numerical simulation considering material and mechanical equilibria, as well as actual geological observation. The results show that gas migrates into tight rocks to preferentially form a gas saturation stabilization zone near the source-reservoir interface. When the gas source is insufficient, gas saturation reduction zone and uncharged zone are formed in sequence from the source-reservoir interface. The better the source rock conditions with more gas expulsion volume and higher overpressure, the thicker the gas saturation stabilization and reduction zones, and the higher the overall gas saturation. When the source rock conditions are limited, the better the tight reservoir conditions with higher porosity and permeability as well as larger pore throat, the thinner the gas saturation stabilization and reduction zones, but the gas saturation is high. The sweet spot of tight gas is developed in the high-quality reservoir near the source rock, which often corresponds to the gas saturation stabilization zone. The numerical simulation results by mathematical model agree well with the physical simulation results by nuclear magnetic resonance coupling displacement, and reasonably explain the gas-water distribution and production pattern of deep reservoirs in the Xujiaweizi fault depression of the Songliao Basin and tight gas reservoirs in the Linxing−Huangfu area of the Ordos Basin.

Generation, accumulation, and distribution of Upper Paleozoic tight sandstone gas in the northeastern margin of the Ordos Basin

Tight sandstone gas in the Upper Paleozoic strata of the northeastern margin of the Ordos Basin exhibits remarkable exploration potential. The objective of this study is to characterize the generation, accumulation, and distribution of Upper Paleozoic tight sandstone gas in the Linxing–Shenfu gas fields located on the northeastern margin of the Ordos Basin. This study uses the following approaches: (1) porosimetry and permeability testing; (2) stable carbon isotope analysis; (3) organic geochemical examination; (4) gold tube pyrolysis experiments; (5) basin modeling; (6) fluid inclusion analysis; and (7) drilling and seismic data analysis. Reservoirs are classified based on the distance between the sandstone traps and source rocks: in Type I reservoirs, the sandstone traps are interbedded with the source rocks; in Type II reservoirs, the sandstone traps immediately overlie the source rocks; and in Type III reservoirs, the sandstone traps are located far from the source rocks. The three types of gas-bearing reservoirs in the Linxing–Shenfu gas fields formed between 190 Ma and 96 Ma (Early Jurassic to Late Cretaceous), and gas accumulation in the three types of reservoirs occurred during the same period. A pressure differential was created between the source rocks and neighboring sandstones as a response to gas generation, and this was the primary mechanism of gas migration and accumulation in the Type I and Type II reservoirs. The initiation and growth of the vertical faults enabled the gas to migrate from the deep source rocks along faults, eventually accumulating in the Type III reservoirs; additionally, the gas migration and accumulation were primarily driven by buoyancy. Type I reservoirs with high gas saturation was mainly distributed in regions with gas expulsion intensities greater than 7 × 108 m3/km2 and located away from the faults. Type II reservoirs with high gas saturation were predominantly distributed in regions with gas expulsion intensities greater than 10 × 108 m3/km2. Type III reservoirs with gas production capacity primarily distributed in conventional sandstone units with high reservoir quality near the faults.

A New Natural Gas Accumulation Model in the Triassic Xujiahe Formation: A Case Study in the Tongjiang-Malubei Area of the Sichuan Basin

The natural gas in the Triassic Xujiahe Formation (T3x) is reported to be mainly derived from the T3x source rock itself. Here, we report a new natural gas accumulation model, which demonstrates that the T3x gas in the Tongjiang-Malubei (TM) area is derived from both T3x and underline marine source rocks. The T3x gas in the TM area is characterized by CH4 with a gas dryness coefficient above 0.99, indicating a high thermal maturity. The δ13C values of the methane, ethane, and propane in the T3x gas in the TM area are −33.7~−29.2‰, −32.7~−28.3‰, and −32.8~−29.5‰, respectively. Compared with the T3x gas in the Yuanba area, which was sourced from the T3x source rock, the T3x gas in the TM area contains heavier δ13C in methane and lighter δ13C in ethane, showing a partial reversal carbon isotope distribution (δ13C1 > δ13C2). According to their chemical and isotopic compositions, the T3x gas in the TM area was a mixture of coal-type and oil-type gases. The coal-type gas was mainly derived from the type III kerogen of the T3x source rock, and the oil-type gas was derived from the type-I kerogen of marine source rock in the Permian Wujiaping Formation (P3w). The oil-type gas migrated upward along the deep-seated faults that connect the P3w source rock and T3x sandstone reservoirs, and then mixed with coal-type gas in the T3x reservoirs, resulting in large-scale gas accumulation. This new gas accumulation model is controlled by a dual gas source supply and a high efficiency migration via the fault system. The findings of this study can help us to better understand the gas accumulation mechanism with the development of late-stage penetrating faults, which not only have implications for future petroleum exploration and development in the TM area, but also affect other analogous areas in the Sichuan Basin.

Tight sandstone gas accumulation mechanisms and sweet spot prediction, Triassic Xujiahe Formation, Sichuan Basin, China

The prediction of continental tight sandstone gas sweet spots is an obstacle during tight sandstone gas exploration. In this work, the classic physical fluid charging experimental equipment is improved, the combination of the gas migration and accumulation process with the pore network numerical simulation method is investigated, and application of the permeability/porosity ratio is proposed to predict the gas saturation and sweet spots of continental formations. The results show that (1) as the charging pressure increases, the permeability of the reservoir increases because more narrow pore throats are displaced in the percolation process; and (2) based on pore network numerical simulation and theoretical analysis, the natural gas migration and accumulation mechanisms are revealed. The gas saturation of tight sandstone rock is controlled by the gas charging pressure and dynamic percolation characteristics. (3) The ratio of permeability/porosity and fluid charging pressure is proposed to predict the gas saturation of the formation. The ratio is verified in a pilot and proven to be applicable and practical. This work highlights the tight sandstone gas migration and accumulation mechanisms and narrows the gap among microscale physical experiments, numerical simulation research, and field applications.

New methods to reconstruct paleo-oil and gas compositions and P-T trapping conditions of hydrocarbon fluid inclusions in sedimentary basins

Accurate predictions of fluid composition and P-T trapping condition of hydrocarbon fluid inclusions (HFIs) is crucial to understand complex oil and gas charging history and accumulation mechanism. However, traditional P-T prediction methods are not enough powerful to get reliable results because of difficulty in direct composition measurement and great uncertainties in indirect composition prediction for single HFI. In this study, we collected 296 crude oil and 983 gas condensate fluids to develop new composition and trapping pressure (Pt) prediction models. Based on the measured fluid composition, saturation pressure (corresponding to homogenization pressure, Ph) and volume data, we firstly calibrate the Ph, the degree of bubble filling (Fv, at 20 °C) and isochores predictions for the measured fluids through matching saturation pressure and volume calibration and then established a standard fluid database with fluid composition, Ph, Fv and Pt. For the first time, a new hydrocarbon fluid composition prediction model was developed which is only function of Fv and homogenization temperature (Th) of HFIs. The new composition model allows directly predicting the entire fluid compositions from methane (C1) to heptane plus (C7+) fractions in HFI based on Fv and Th. Furthermore, we developed different Pt prediction models for varying fluid compositions and phase states of HFIs. For oil-bearing fluid inclusions which homogenize into liquid phase (OFIL) methane molar content is the only variable that is needed to predict Pt with a high degree of accuracy (8.2–12.3% for average absolute deviation, AAD). However, for gas condensate-bearing fluid inclusions (GCFI), more composition (C1–C7+) together with the physical property (molecular weight and specific gravity) of C7+ composition must be incorporated into the prediction model to obtain a better prediction accuracy of Pt. The new Pt prediction models give prediction accuracy of 11.2–17.6% (AAD) for GCFIL (homogenizing into liquid phase), and 15.9–22.8% (AAD) for GCFIG (homogenizing into gas phase). Our new composition and Pt prediction models can give the best and fastest predictions of hydrocarbon fluid composition and trapping condition and are of great significance for petroleum charging history reconstruction in sedimentary basins.

Evaluating Shale Gas Sweet Spots of the Jurassic Da'anzhai Member in the Yuanba Area, Sichuan Basin

Terrestrial shale strata generally has frequent and strong heterogeneity characteristics, thus affecting shale gas enrichment and target selection. In this study, samples from the Da’anzhai Member of Well A in Yuanba area have performed a series of experiments including total organic carbon ( TOC) content measurement, rock pyrolysis, organic petrology, vitrinite reflectance ( Ro), whole-rock mineral composition, thin section analysis, focused ion beam scanning electron microscope, high-pressure Hg injection, nitrogen (N2) adsorption, and methane (CH4) isothermal adsorption. The results show that: (1) Da'anzhai (J1da) Member is a set of mixed sediments with various lithology, which consists of black shale and well-developed siltstone and carbonate rocks interlayers. The second section of the Da'anzhai Member (J1da2) has relatively greater organic matter abundance (1.24% TOC), better organic matter type dominated by type III and II, as well as higher maturity (1.67% Ro), which is the most favorable section of J1da. (2) J1da2 shale strata can be divided into three shale lithofacies types, two interlayer lithofacies types, and three macro-lithofacies assemblage types. Among them, mudstone–limestone lithofacies assemblage (type AB-I) has preferable hydrocarbon generation conditions, better reservoir properties, and more developed shell limestone interlayers with better fracturing performance, is thought the most favorable interval. (3) The optimal interval and horizontal target of J1da2 are further selected based on the source–reservoir coupling relationship, corresponding to the depth is 3909–3914 m, which imply the optimal horizontal target window for Well A. This study has application values not only for the identification of “sweet intervals” and well location deployment of J1da but also supports the later systematic studies of shale gas accumulation mechanism and enrichment regularity in Yuanba area.

Reservoir characteristics of marine–continental transitional shale and gas-bearing mechanism:Understanding based on comparison with marine shale reservoir

Transitional shale gas layers are widely distributed in China, but no significant exploration breakthrough has been made so far. This paper investigates and analyzes the characteristics and gas-bearing mechanisms of transitional shale gas reservoirs in detail, aiming to clarify the shale gas accumulation mechanism of transitional shale and provide theoretical support for the selection of favorable intervals. The transitional shale gas layer is characterized by a thin single-layer thickness, rapid lithological change, low brittle mineral content, and poor kerogen type. The lack of organic matter (OM) sponge pore development process from the oil-generation stage results in limited numbers of OM nanometer-scale pores. Shale pore space is dominated by pores and fractures related to clay minerals. The measured gas content is well consistent with the theoretically calculated gas content for marine organic-rich shales. However, the actual measured gas content is far lower than the theoretically calculated gas content for the transitional shale gas reservoir. The main mechanisms are summarized to be (1) the high hydrocarbon expulsion efficiency of the “sandwich” space structure of the sandstone–shale–coal association, which gives rise to most natural gas migrating into nearby sandstone, and (2) high water saturation resulting in insufficient storage space for free gas in the shale reservoir. Unlike marine shale gas, natural gas in the transitional shale reservoir is primarily dominated by adsorbed gas in kerogen, and free gas is relatively low. The favorable lithofacies types are organic-rich siliceous/calcareous shales. Multiple layers of siderite-bearing shales/siderites are developed vertically and continuously distributed horizontally in transitional strata, particularly in flat-lagoon facies. It is easy to form a “micro-trap” to store gas in siderite-bearing shale, and siderite-bearing shale has strong sealing properties due to low porosity, low permeability and high breakthrough pressure. This property can form overpressure and trap shale gas inside the shale, providing a new research perspective for the optimization of vertical favorable intervals, as well as exploration breakthrough in transitional shale gas. Further research should strengthen the systematic sedimentological study of transitional facies, reveal shale gas occurrence state and dynamic transformation, and optimize favorable interval evaluation systems to clarify the feasibility of coal-measure gas commingled production.

Development model of shallow lithologic traps and natural gas accumulation mechanisms in marine deep-water areas: A case study in the qiongdongnan basin, south China sea

Although hydrocarbon gases are widely distributed in the shallow strata of marine deep-water areas, it is generally believed that these shallow gases have little potential to form large gas accumulations due to unfavorable conditions, especially for effective trap development. Based on a comprehensive analysis of the latest geological exploration data of the deep-water areas of the Qiongdongnan Basin, this study reports a large lithologic trap that developed in the shallow Ledong Formation with burial depths of 200–600 m below the seafloor (mbsf). Systematically, this work investigates the development model of the trap and its gas accumulation mechanism. The results indicate that during the Pleistocene, sediment mainly from the southern Kunsong Uplift was transported to the Qiongdongnan Basin due to confined canyon geomorphology and developed a large channelized submarine fan in the deep-water areas. The roof of the submarine fan was cut and eroded and laterally sealed by overlying muddy channels, resulting in a dome-shaped structure, which was further covered by the Pleistocene tight mudstones forming the Ledong lithologic trap. The Yacheng coal-measure source rocks in the deep-water areas had high gas yields, which resulted in increased pressures and promoted deep gas migration into shallow reservoirs along a combined migration pathway including sand strata, structural ridges, faults, fissures, and gas chimneys. The gas accumulated in the Ledong trap as a result of the decreases in temperature and pressure. After the deep gases charged the Ledong strata, migration was blocked by the overburden consisting of Pleistocene tight mudstones, whose seal capacity was significantly enhanced by overlying gas hydrates in the deep-water areas. Meanwhile, the seawater in deep-water areas compacts the underlying cap rocks through its own weight, which enhances the seal capacity of cap rocks. In shallow reservoirs, thermogenic gases may mix with microbial gases from shallow marine source rocks, and some thermogenic gases may be reformed by microorganisms to form secondary microbial gases. The shallow Ledong gas reservoir connects the underlying gas reservoirs and the overlying gas hydrate reservoirs and vertically consists of a continuous hydrocarbon enrichment zone, which significantly expands exploration targets in the deep-water areas of the Qiongdongnan Basin. Additionally, the development model of the shallow Ledong lithologic trap and its gas accumulation mechanism may have general significance for hydrocarbon exploration in marine deep-water areas worldwide.

Fractal analysis of pore structures in transitional shale gas reservoirs in the Linxing area, Ordos Basin

Studying complex pore structures and fractal characteristics of gas shale provides significant guidance for clarifying the mechanism of shale gas accumulation and realizing its efficient development. In this paper, 12 samples of Taiyuan Formation shale are used as the research object, and the fractal theory is combined with mercury intrusion porosimetry and N2 adsorption technology to innovatively solve the problem of splicing point selection, which can reveal the full-scale pore size distribution of shale. The results demonstrate that the most common types of pores in the chosen samples are pores between or within clay minerals, micropores and mesopores inside organic matter, and microfractures, based on scanning electron microscopy imagery analyses. The pores of shale samples have fractal geometries. The fractal dimension DM1 values in the mercury intrusion porosimetry experiments range from 2.3060 to 2.6528. Two fractal dimensions, DN1 and DN2, may be obtained using the Frenkel-Halsey-Hill fractal method. DN1 values vary from 2.4780 to 2.6387, whereas DN2 values range from 2.5239 to 2.7388. Most macropores in shale samples have a size range of about 0.2 mm, with a wide pore size distribution, and the largest peak of the micro-mesopore volume is generally about 50 nm. The fractal dimension correlates positively with the corresponding pore volume, although the correlation between volume and composition is weak. The relatively strong correlation between fractals and the basic compositions of shale proves the fractal theory’s relevance in defining pore inhomogeneity. This study would contribute to the development of a fractal perspective-based method for pore splicing while also expanding our understanding of pore morphology and structure in transitional shale.

Fault-bounded models of oil–Gas and gas–Hydrate accumulation in the Chaoshan Depression, the South China Sea

The Dongsha Basin is a large Mesozoic basin extended from the northern South China Sea (SCS) to onshore South China. Though long-term uplift and denudation occurred since the end of the Mesozoic, still thick Mesozoic strata (up to 5,000 m) relict over the Dongsha waters where lies the largest depression, Chaoshan Depression, covering an area of 3.7 × 104 km2. It was confirmed by a drilling hole, the well LF35-1-1, that high organic carbon-bearing marine Jurassic layers are present in the depression. However, due to the complexity of the superposed Mesozoic and Cenozoic tectonism and poor imaging quality in previous surveys, the petroleum geology remains poorly understood in view of the deep basin structure, the Mesozoic hydrocarbon migration conditions, and the oil–gas accumulation mechanism. In recent surveys, the seismic imaging quality has been significantly improved by employing long and quasi-3D seismic streamer techniques. Correlating with the regional geology onshore the South China, drilling data of the Well LF35-1-1, and well-tying seismic profiles, it is found that two sets of source rocks are developed in the semi-closed gulf during the Upper Triassic-Lower Jurassic and the Upper Jurassic. Their effective thicknesses are estimated as 495 m and 600 m, respectively, being hopeful with high hydrocarbon generation potentials. During the Dongsha Movement that occurred in the late Cenozoic, deep faults have been extensively activated to disturb the overlying sequences, even in some places breaking through the seafloor. A potential trap structure, DS-A, is found in an intra-sag bulge which is bounded by antithetic and synthetic faults. The oil and gas generated in the neighboring sags can migrate along the faults into reservoir layers at higher levels. The antithetic faults also play the role of seal for oil and gas from the hanging wall. Apparent flat bright spots appearing within the DS-A trap indicate likely entrapment of layered petroleum. The synthetic faults on the opposite side of the DS-A structure, although fails to seal oil–gas reservoirs, provide plumbing channels for oil and gas to leak to the shallow layers above which a few pockmarks and mud volcanoes are visible. As the water depth of the continental slope there ranges from 300 m to 2000 m, it is likely for the leaked gas to form natural gas hydrates. A close cogenetic interrelation exists between the natural gas hydrates at the seafloor and oil–gas reservoirs in the deep.

Characterization Method of Tight Sandstone Reservoir Heterogeneity and Tight Gas Accumulation Mechanism, Jurassic Formation, Sichuan Basin, China

Although significant progress has been made in tight gas exploration and development, there is still a limited understanding of the gas accumulation mechanism in tight formation. The description of heterogeneity in the tight reservoir is still an obstacle during tight gas exploration. In this work, we will develop a 3D gas accumulation facility that can reflect the high temperature and pressure under the geological condition to simulate the gas accumulation process in the tight formation of the Jurassic Formation, Sichuan Basin. Both the physical experiment simulation and numerical simulation methods will be combined to reveal the mechanism of gas accumulation. The results show that (1) the permeability ratio can characterize the heterogeneity of tight reservoirs. Based on this parameter, petroleum geologists can understand the interlayer heterogeneity during fluvial deposition and predict the sweet spots of tight gas; (2) the permeability ratio relationship between hydrocarbon accumulation of the tight sandstone reservoir mainly manifests as long as there is the existence of the differential permeability and there will be differences in natural gas migration dynamics, so that the natural gas accumulates in pores and depends on the extent of source rock; and (3) although the difference between capillary force curves is at the core of the influence of the permeability ratio on the gas-bearing capacity of the “sweet spot” sand body, the permeability ratio is a parameter of practical engineering significance. This work adds new methods to tight gas formation heterogeneity characterization and sheds light on the mechanisms of hydrocarbon accumulation in tight formation.

The Whole-Aperture Pore Structure Characteristics and Their Controlling Factors of the Dawuba Formation Shale in Western Guizhou

Since shale gas mainly occurs in shale pores, research on pore structure characteristics is the key to understanding the shale gas accumulation mechanism. The pore structure of the Lower Carboniferous Dawuba Formation shale in the Qianxi area, represented by the well QSD-1, which obtains a daily shale gas flow of 10,000 m3 and represents an important breakthrough in the investigation of marine shale gas in the Upper Paleozoic region of southern China, is characterized by high-pressure mercury compression experiments and low-temperature gas adsorption (N2 and CO2) experiments with whole pore size. The main controlling factors affecting the pore development of the shale are discussed. (i) The micropores and mesopores are more developed in the shale, and the macropores are the second most developed in the shales of the Dawuba Formation in the Qianxi area, among which the mesopores and macropores contribute most to the pore volume and the micropores and mesopores contribute most to the pore-specific surface area. (ii) The microfractures and interlayer pores of clay minerals are developed in the shales of the Dawuba Formation, which are the main storage spaces for hydrocarbon gases. (iii) The main factors affecting the adsorption capacity of the shales of the Dawuba Formation in the Qianxi area are the organic carbon content and clay mineral content of the shales, both of which have an obvious positive correlation with the variation of pore structure.

Fields and directions for shale gas exploration in China

China is highly dependent on foreign oil and gas, and the exploration and exploitation of shale gas is an important way to alleviate the energy and environmental pressure of China. Although a series of significant progress has been made in a short time, China is still at the crossroads of shale gas exploration direction. Therefore, this paper systematically reviews the particularity of shale gas geological conditions in China, and points out China's exploration direction of shale gas in different fields combined with the research achievements of shale gas accumulation mechanism. The following results were obtained. (1) China's shale gas exploration fields can be divided into three major parts, i.e., marine, continental and marine–continental transitional facies. The geological characteristics of shale gas in North China, Yangtze and Tarim plates are different. The interaction of multiple factors, including tectonic and sedimentary evolution, shale gas accumulation, late-stage transformation and etc., has led the complexity of the geological distribution and the diversity of exploration fields of shale gas in China. (2) The organic pores and fractures of marine shale are developed. The Ordovician Wufeng-Silurian Longmaxi Formation will still be the primary target of shale gas exploration in future. Meanwhile, the Cambrian Niutitang and Sinian Doushantuo Formation in the Yangtze region, the Devonian Luofu and Carboniferous Jiusi Formation in the Yunnan-Guizhou-Guangxi region, the Jixianian Hongshuizhuang and Mesoproterozoic Xiamaling Formation will be the targets of strategic breakthrough in shale gas exploration. (3) The structural deep and slope of middle-large basins and the sedimentation centers of small-middle basins are the main directions of continental shale gas exploration. Inter-laminar cracks and intergranular pores are well developed in continental shale. The coupling of various organic matter types and thermal evolution results in the symbiosis of shale oil and shale gas, which will become an important field for further exploration of continental shale gas. (4) The marine–continental transitional shale, which mainly formed in Late Carboniferous-Permian, is characterized by cyclic association with sandstone, mudstone, coal and carbonate. Diagenetic fractures are well developed in transitional shale. The favorable structural and diagenetic preservation are the two major factors for the enrichment of this type of shale gas. The flat-lagoon and delta sedimentary systems, middle-large superimposed and small-middle residual basins, and deep layers with quality caprock and good structural preservation are the favorable directions for shale gas exploration in transitional facies.

Development Model of Shallow Lithologic Traps and Natural Gas Accumulation Mechanisms in Marine Deep-Water Areas: A Case Study in the Qiongdongnan Basin, South China Sea

Development Model of Shallow Lithologic Traps and Natural Gas Accumulation Mechanisms in Marine Deep-Water Areas: A Case Study in the Qiongdongnan Basin, South China Sea

Structure, burial, and gas accumulation mechanisms of lower Silurian Longmaxi Formation shale gas reservoirs in the Sichuan Basin (China) and its periphery

Structure, burial, and gas accumulation mechanisms of lower Silurian Longmaxi Formation shale gas reservoirs in the Sichuan Basin (China) and its periphery

Superimposed Pattern of the Southern Sichuan Basin Revealed by Seismic Reflection Profiles Across Lushan–Chishui, China

Abstract The Sichuan Basin is a typical intracraton superimposed basin. It is rich in oil and gas resources in the different sets of sedimentary sequences. It underwent multistage tectonic evolution, which resulted in different types of prototype basins. However, there are still many different opinions on the types and superimposed patterns of the Sichuan Basin in different geologic periods, which largely affect the understanding of the mechanism of effective oil and gas accumulation and preservation. This paper aims to re-recognize several prototype types of the Sichuan Basin by discussing the prototype basins and their superimposed models to deepen the significance of superimposed basin evolution for hydrocarbon accumulation. The regional geological and drilling data are used for a detailed interpretation of seismic reflection profiles across Lushan–Chishui. Then, five regional unconformities are identified with the equilibrium profiles technique which is used to flatten the formation interface in different geologic periods. Based on the unconformities, the southern Sichuan Basin is divided into six tectonic layers, each of which is regarded as a prototype basin: a pre-Sinian crystalline basement (AnZ), a marine rift cratonic basin (Z–S), a marine intracratonic sag basin (P2l–T2l), a marine–continental downfaulted basin (T3x1–T3x3), a continental depressed basin (T3x4–J), and a foreland basin (K–Q). The different prototype basins are vertically superimposed to form a “layered block” geologic structure of the multicycle basins. Affected by the late-stage tectonic transformation, the geologic structure of vertical stratification underwent a strong transformation, which had a profound impact on oil and gas accumulation with the characteristics of early accumulation and late adjustment.