Gas-bearing Properties Research Articles

Pore Structure and Gas Content Characteristics of Lower Jurassic Continental Shale Reservoirs in Northeast Sichuan, China

The Jurassic shale in the northeastern Sichuan Basin is one of the main target intervals for continental shale gas exploitation. Research on the pore structure and gas-bearing properties of shales is the key issue in target interval optimization. Through core observation, geochemistry, bulk minerals, scanning electron microscopy, nitrogen adsorption, and isothermal adsorption experiments, various lithofacies with different pore structure characteristics were clarified. In addition, the factors that control gas-bearing properties were discussed, and a continental shale gas enrichment model was finally established. The results show that the Jurassic continental shale in the northeastern Sichuan Basin can be classified into six lithofacies. Organic pores, intergranular pores, interlayer pores in clay minerals, intercrystalline pores in pyrite framboids, and dissolution pores can be observed in shale samples. Pore structures varied in different shale lithofacies. The contact angle of shales is commonly less than 45°, leading to complex wettability of pores in the shales. Free gas content is mainly controlled by the organic matter (OM) content and the brittleness in the Jurassic shale. The adsorbed gas content is mainly controlled by the OM content, clay mineral type, and water saturation of the shales. The enrichment mode of the Lower Jurassic continental shale gas in the northeastern Sichuan Basin is established. Paleoenvironments control the formation of organic-rich shales in the center part of lakes. The "baffle" layer helps the confinement and high pressure, and the complex syncline controls the preservation, forming the enrichment pattern of the complex syncline-central baffle layer.

Formation conditions and the main controlling factors for the enrichment of shale gas of Shanxi Formation in the southeast of Ordos Basin, China

Based on the dissection of the geological characteristics of typical shale gas wells, the relationship between reservoir-forming factors and shale gas enrichment is deeply analyzed, and the controlling factors of shale gas enrichment are summarized. An analysis of data from drilling, logging, testing, and shale sample has revealed that the factors contributing to the formation of shale gas reservoirs in marine–continental transitional facies of Shanxi Formation in the southeast of Ordos Basin are highly heterogeneous. This is mainly reflected in the rapid spatial change of shale organic matter, physical properties, and other parameters of the shale in this area. The shale found in the Shanxi Formation has a high content of organic carbon (TOC), with an average of 2.24%. The kerogen type is mainly type Ⅲ, and the average value of RO is 2.48%, indicating that it is in the high mature-overmature stage and is a high-quality source rock. The rock composition is rich in clay (40.5%–88.5%), mainly composed of illite-mongolian mixed layer and kaolinite, and its relatively high specific surface area is beneficial for improving the gas adsorption capacity of the shale. Thin sandstone interbeds, measuring less than 3 m are widely distributed in the Shanxi Formation and have good physical conditions. With an average porosity 3.37% and an average permeability of 0.1 mD. The natural gas generated by the shale can be transported to these sandstone interlayers (laminae) in a short distance, which is beneficial for improving the gas-bearing property of the shale. The gas-bearing property of the Shanxi Formation in the study area is affected by different lithologic assemblages. The gas-bearing property of the thick mudstone-coal assemblage of the second member of the Shanxi Formation is the best, with more than 80% of the samples having a gas content of over 1 m3/t. This study suggests that the high thermal evolution degree of shale, special marine–continental transitional facies reservoir conditions, and good preservation conditions are the main factors affecting the enrichment of shale gas in the study area. This makes the shale gas of the Shanxi Formation in the southeast of the Ordos Basin have certain potential for exploration and development, and delineates the enrichment targets of shale gas in the Zichang-Yan'an-Fuxian and Yichuan areas.

Comparison and Verification of Gas-Bearing Parameter Evaluation Methods for Deep Shale Based on the Pressure Coring Technique

Gas-bearing properties, such as gas-in-place (GIP) content and adsorbed gas ratio (AGR), have drawn considerable attention because they are essential for shale gas resource evaluation and sweet spot forecasting. The above-mentioned metrics have been determined using a variety of approaches, but they lack systematic comparison and accuracy verification, particularly for deep shale gas, where conventional methods frequently fall short. A total of 30 shales were taken for the investigation utilizing pressure and conventional coring methods from Wufeng and Longmaxi Formations in the Sichuan Basin, China. For pressure coring samples, we developed the experimental protocols and a GIP content classification scheme that categorizes the GIP content into four categories: lost gas (estimated using the temperature-corrected pressure-holding ratio), extracted gas from depressurization, degassed gas, and residual gas. The four pressure coring samples from well Y206 with measured GIP content range from 2.84 to 5.58 m3/tonne, with an average of 4.72 m3/tonne. In contrast to the calculated GIP content of the pressure coring samples, the validity of the current GIP content evaluation methodologies has been confirmed. The comparison results demonstrate that the GIP content assessed using the United States Bureau of Mines (USBM) method is frequently underestimated for samples from conventional coring and notably overstated for samples from pressure coring. The polynomial fitting method dramatically overestimated the GIP content. With its accurate time-dependent boundary conditions and strict theoretical foundation, the simplified carbon isotope fractionation (s-CIF) model exhibits the highest level of accuracy in determining GIP content. Additionally, the s-CIF model can find yet another crucial parameter of AGR. Shale samples from well Y206 had an average AGR of 20.4% but a range from 12.2 to 33.2%. The examination of the influencing factors demonstrates that the lost gas ratio, AGR, and diffusion coefficient are responsible for controlling the calculation error of the USBM method. The lost gas ratio prior to core retrieval increases with decreasing AGR (or increasing diffusion coefficient), which increases the computation error of the USBM method.

Physical property differences of source rocks in the Lucaogou Formation and adsorption ability variation under their influence

Shale gas exploration is very important for the China in the further. There are many findings of shale gas in Northwest China, especially in Junggar Basin Permian Lucaogou Formation of the Xinjiang Uygur Autonomous Region. However the basic geological characteristics of Lucaogou Formation is not still clear. In order to solve this problems, Quanzijie shale gas collected from the southern margin of the Junggar Basin is taken as the study area, and shale gas resources are investigated and evaluated using the organic-rich shale section. On this basis, the investigation and evaluation of shale gas resources in the Lucaogou Formation is performed. The reservoir performance, preservation conditions, compressibility, and gas-bearing properties of gas-bearing shale intervals are identified. The results are as follows: The vertical and horizontal lithological and lithofacies variations of the source rocks of the Lucaogou Formation are clarified. This layer is characterized by the upward thinning of grain size and the upward darkening of color in the vertical direction. The layer can be divided into upper and middle-lower sections, with organic shale being most developed in the upper section, and sandstone and dolomite being more developed in the middle and lower area. The main hydrocarbon source rocks are developed in the upper area of the Lucaogou Formation. The total thickness of the hydrocarbon source rocks is 78.12–513.73 m. The lithology is mainly gray-black shale, silty mudstone, and oil shale. The average organic carbon content is 4.86%. The maturity of the organic matter is mainly 0.7–0.8%. The shale reservoirs have a high content of brittle minerals, but the physical properties both of the shale and sandstone reservoirs are poor. These are generally ultra-low porosity and ultra-low permeability reservoirs, in which the oil and gas reservoir space is mainly fractures.

Research on Intelligent recognition of Rock samples based on Deep Learning method

Rock sample recognition plays an important role in oil and gas exploration and mineral resources exploration. At present, the main rock sample identification methods are logging, seismic, gravity and magnetism, geochemistry, hand samples and thin slice analysis and so on. In particular, the mainstream thin section analysis requires professionals to analyze the rock slices manually, but manual detection and preparation of rock slices take a long time. In order to reduce the workload and shorten the time period, the image depth learning method is used to establish the model. After the cuttings and core samples are collected by the industrial camera in the mud logging site, the real-time automatic identification and classification of rock samples and the evaluation of oil and gas-bearing properties are realized. In this paper, the file in .JPG format is cut to discard the information that does not contain rock at the edge. Then it was divided into 4* 4, 6*6, 8*8, 10*10 segments. After image enhancement, the transfer learning method is used to train the neural network using Desnet201 in the built-in library of torch, and the Desnet201 network is selected as our neural network framework. Then the last softmax layer is changed into a multi-layer perceptron with three hidden layers, and the improved Desnet201 is used as a model to identify rock types in this paper.

Occurrence and Migration Mechanisms of Methane in Marine Shale Reservoirs

The occurrence mechanism of methane is very important as evaluating the gas-bearing properties of marine shale reservoirs, and the evaluation of the development effect of shale gas wells need to focus on the migration mechanism of methane. In this study, LTNA technology and NMR technology were used to analyze the pores and methane of shale. The results show that inorganic pores have better connectivity, larger pore size, and micro–nano cracks between pores compared to organic pores. Most of the pores in shale are micropores and mesopores, which provide most of the specific surface area, but the contribution of macropores to pore volume cannot be ignored. Adsorbed gas volume depends on the pore surface area and gas pressure, while free gas volume depends on pore volume and gas pressure. The pore structure of micropores and mesopores is complex, and the specific surface area is large. The dispersion force between pore surface molecules and methane molecules is firm, which makes the pore wall an ideal enrichment space for adsorbed gas. Macropores have larger pore volumes and can store more free gas. In the process of gas well development, free gas is first discharged from pores under the action of the pressure gradient. As the pore pressure is lower than the critical desorption pressure, adsorbed gas begins to desorb in large quantities. It should be noted that the desorption process of adsorbed gas is slow and persistent, which makes it impossible for gas wells to achieve higher recovery in a shorter production cycle. Therefore, improving the recovery rate of adsorbed gas is the key to future research on shale gas development effects. This study is helpful in clarifying the occurrence and migration mechanism of methane in marine shale reservoirs and guiding the development of gas wells.

Gas-Bearing Property in Deep Marine Shale and Its Micro Controlling Factors: Evidence from the Lower Silurian Longmaxi Formation in Southern Sichuan, China

Abstract The gas content in shale reservoirs is often determined by the micro storage and sealing capacities of the reservoir. Deep shale reservoirs are in the high- or over-thermale maturity stage and have complex pore structure and connectivity, which are highly heterogeneous in vertical distribution. Research on the gas-bearing property of deep shale reservoirs is limited by these complex microscopic conditions. To analyze the gas-bearing characteristics of deep shale reservoirs, this work collected and summarized data on total organic carbon content, mineral composition, porosity, water saturation, and gas content measured on-site for the Longmaxi Formation in the Sichuan Basin in southern Sichuan, China. Then, experimental methods, such as X-ray photoelectron spectroscopy, transmission electron microscope, low-pressure N2 adsorption, spontaneous imbibition, and high-pressure methane adsorption, were used to analyze the micro storage and sealing capacities of the deep shale reservoirs. The results show that, different from shallow shale reservoirs (<3500 m), deep shale reservoirs have a higher graphitization degree and water saturation. An abundance of graphite structures often leads to weak resistance of organic matter to compression, deformation, or even collapse of pores in organic matter and severe damage to the gas storage space. However, a higher degree of graphitization can enhance the ability of the shale reservoirs to adsorb gas and self-sealing. The high water saturation in the reservoirs can interact with clay minerals and negatively affect the gas accumulation, storage, and transmission capacities of the shale reservoirs. However, the upper shale reservoirs with higher water saturation can seal the lower shale reservoirs, helping it preserve shale gas. Based on the vertical distribution of graphite structure, clay minerals contents, lithofacies, and water content in deep shale reservoirs, the essential microscopic conditions for deep shale reservoirs to have high gas content were proposed. This paper provides a detailed explanation and evaluation of deep shale’s storage and sealing capacities at the microscopic scale and can serve as a reference for further identifying the patterns for high-yield and rich shale gas reservoirs and improving deep shale gas exploration technologies.

Methane absorption of coal-measure shales with and without pore water from the Qinshui Basin, North China: Based on high-pressure methane absorption experiments

The coal-measure shale in the Qinshui Basin, North China has a high thermal maturity and a huge shale gas resource, but studies related to its gas-bearing property (GBP) are lack. In this paper, shale samples taken from the carboniferous coal-measure strata in the Yangquan block of Qinshui Basin were mainly investigated on their pore water contents and occurrence characteristics, and their high-pressure methane adsorption capacities under the dry and moist conditions. The results show that the pore water in the shale is in an ultra-low saturation state, occurring mainly in clay minerals (91% on average), significantly decreases its effective pore structure parameters, especially the nonmicropore specific surface areas (by 70.21% on average), and reduces its methane adsorption capacity (by 33% on average at 30 °C), with the adsorbed methane occurring mainly in micropores and controlled by the TOC content. The adsorption of methane on the shale is an exothermic process, and both the shale adsorption capacity and adsorbed methane density are reduced with increasing temperature. Pore water not only has a competitive adsorption with methane, but also weakens the adsorbed methane inter-molecular interaction forces, decreasing the methane adsorption capacity, especially under the low temperature and pressure conditions. The GBP models of a selected shale under the dry and moist conditions further indicate that pore water also decreases the adsorbed gas percentage to some extent, especially at a burial depth < 1500 m, and the adsorbed gas is dominant in the shale. These GBP characteristics of coal-measure shale should pay a great attention in the future exploration and development of shale gas in the Qinshui Basin.

Fractal Analysis and Classification of Pore Structures of High-Rank Coal in Qinshui Basin, China

The influence of high-rank coal’s pore characteristics on the physical properties, gas-bearing properties, and exploitation of coal reservoirs is becoming more and more prominent. How to establish the classification to describe the pore networks combining quantitative and qualitative characteristics has emerged as a major problem, which may offer a scientific foundation to deepen the understanding of this issue. In this research, the structure and fractal characteristics of reservoir pores were determined after analyzing 20 high-rank coal samples from Xinjing Coal Mine in the Qinshui Basin with the application of the high-pressure mercury intrusion method (HPMI) and argon ion polishing–field emission scanning electron microscopy (AIP–FESEM). The results show that the tested coal samples were bipolar distributed, with transitional pores and micropores dominating the pore volume, followed by macropores. The Menger sponge fractal models manifested two or three distinct straight-line segments with demarcation points of 65 nm and 1000 nm. A natural classification with three major pore types of diffusion pores (D-pores), seepage pores (S-pores), and pico pores (P-pores), demarcated by pore size intervals of 65 nm and 1 nm and seven sub-types, was established to relate pores to pore networks based on these fractal characteristics and the kinetic characteristics of methane molecules. This classification scheme can characterize the relationship between pore types and the corresponding major occurrence and transport mechanisms of the gas. In addition, P-pores and D-pores are predominately nanoscale OM pores with three major genetic types of organic constituent interparticle pores (5–200 nm), metamorphic pores (&lt;5 nm), and intermorphic pores (&lt;5 nm). S-pores are more complex in origin and shape features, and the major types include outgas pores, plant tissue residual pores, mineral-related pores, and microfractures. The mean radius (Pa), total pore volume (Vt), apparent porosity (Φ), and volume ratio of macro- and mesopores were positively correlated with the fractal dimension D1 of S-pores (&gt;65 nm). Since fractal analysis is a more comprehensive characterization of reservoir structure and quantitatively reflects the pore structure, undulating state, and roughness of the inner surface, fractal parameters can be used as an important index to describe the pore structure characteristics of high-rank coal reservoirs.

Natural Fracture Development Characteristics and Their Relationship with Gas Contents-A Case Study of Wufeng-Longmaxi Formation in Luzhou Area, Southern Sichuan Basin, China.

Natural fractures are critical factors that should be considered in shale reservoir evaluation, storage condition analysis, horizontal well design, and fracturing stimulation, which also play a non-negligible role in the occurrence state of shale gas in the reservoir. This paper discussed the influence of fracture development on gas-bearing properties based on the analysis results of core observation, scanning electron microscopy, mineral composition, and gas-bearing properties after the development characteristics of fractures and their longitudinal variation law were clarified. In this way, the development characteristics of organic-rich marine shale fractures in the Longmaxi Formation in the 203 well area of the Luzhou member of the Sichuan Basin and their effects on the gas-bearing properties can be analyzed. The results show that the Longmaxi Formation shale develops shear fractures, extensional fractures of tectonic origin, bedding fractures, dissolution fractures, and abnormally high-pressure fractures of nonstructural origin. Specifically, interlayer fractures, intercrystalline fractures, organic matter contraction fractures, and fractures between clay layers are microfractures. Fracture development is characterized by short longitudinal extension, small opening, high degrees of composite filling, and large density changes, with calcite and pyrite as the filling materials. The fracture density has a “three-stage” variation pattern longitudinally, and the bottom is dominated by thin siliceous shale development, together with a small amount of shale mixed with calcareous and calcareous materials. Moreover, the fracture is dominated by “splitting” and “shearing” failure, crossing stratification with the fracture density. The highest fracture density was found in the 2 sub-layer, featuring the joint development of horizontal and vertical fractures, which form the mesh fracture system through mutual cutting and restriction. The lithofacies in the 4 sub-layer are dominated by clay siliceous shale with a small amount of mixed shale of calcareous and siliceous materials. The formation of fractures always expands along the lamellation direction, which has concentrated development members of top and bottom fractures, with the development of horizontal fractures dominated and vertical fractures less developed. Furthermore, a synergistic effect can be found among the total organic carbon (TOC) content, fracture density, and gas-bearing property of the shale in Longmaxi Formation. It is worth noting that a high TOC content and siliceous content are conducive to the formation of microfractures, while the development of fracture contributes to the total gas-bearing property, especially to the increase in free gas content. To be concrete, the free gas content in the fracture development member accounts for more than 55% of the total gas content, thanks to a channel provided by fractures for the desorption of shale gas.

Lower Cambrian Organic-Rich Shales in Southern China: A Review of Gas-Bearing Property, Pore Structure, and Their Controlling Factors

The Lower Cambrian shales are widely developed in southern China, with greater thicknesses and higher TOC contents. Although the shale gas resource potential has been suggested to be huge, the shale gas exploration and development is not satisfactory. At present, the gas-bearing property evaluation of the Lower Cambrian shale is still a hot spot of concern. According to previous works, this paper systematically summarizes the gas-bearing characteristics and controlling factors of the Lower Cambrian shales in southern China. The buried depth of Lower Cambrian shales mainly ranges from 3000 m to 6000 m, and the thickness of organic-rich shale intervals ( TOC &gt; 2 % ) varies from 20 m to 300 m. The TOC content and EqVRo value are generally up to 2%-10% and 2.5%-6.0%, respectively. The gas content of the Lower Cambrian shales in the Weiyuan-Qianwei block of the Sichuan Basin and the western Hubei area generally exceeds 2 m3/t, and gas composition is dominated by CH4. In southeastern Chongqing, northwestern Hunan, and northern Guizhou areas, the gas content of the Lower Cambrian shales is generally &lt;2 m3/t, and the N2 content is generally &gt;60%. In the Lower Yangtze region, the Lower Cambrian shale reservoirs basically contain no gas. Higher maturity, lower porosity, and less-no organic pores are suggested to be responsible for low gas contents and/or the predominate of N2 in shale gas reservoirs. Strong tectonic deformation is an important factor leading to the massive gas loss from shale reservoirs, thus resulting in no gas or only a small amount of N2 in the Lower Cambrian shales. In a word, the Lower Cambrian shale gas plays with low maturity and relatively stable tectonic condition, especially deep-ultradeep zones, may be the favorable targets for shale gas exploration.

Classification and Evaluation of Volcanic Rock Reservoirs Based on the Constraints of Energy Storage Coefficient

The current classification and evaluation methods of volcanic rock reservoirs have low accuracy and cannot effectively provide guidance for the selection of volcanic rock gas reservoirs, which have efficient properties for gas production. In this research, we have analyzed the lithology, lithofacies, reservoir space type, pore combination mode, and reservoir microscopic characteristics of volcanic reservoirs using the energy storage coefficient as a constraint. Then, the method of reservoir classification was proposed. The results showed the following: 1) The energy storage coefficient can better characterize the single-layer productivity of gas wells. The volcanic rock reservoirs in the Wangfu gas field can be subdivided into three categories by considering the energy storage coefficient. 2) Type I reservoirs mainly develop structural fractures–matrix dissolution pores, structural fractures–intercrystalline micropores, and matrix dissolution pores. Type II reservoirs mainly develop matrix dissolution pores and residual intergranular pores, and Type III reservoirs are dominated by structural fractures. From Type I to Type III reservoirs, the skewness of the mercury intrusion curve and the sorting coefficient deteriorated, and the physical properties of the reservoir and the maximum mercury saturation and other parameters also decreased, whereas the displacement pressure and the median saturation pressure increased. 3) The characteristics of conventional and special logging curves of typical reservoirs were comprehensively analyzed, and the combination of sensitivity parameters reflecting gas-bearing properties and logging curves was optimized. Furthermore, a reservoir classification chart was established, and the results enabled to confirm the choice of the reservoir and demonstrated that the standard classification has high accuracy. 4) The diagenesis processes such as weathering, leaching, and dissolution improved the physical properties of the reservoir. The research results can effectively provide guidance for the evaluation of the “sweet spot” of volcanic rock reservoirs.

Application of mathematical statistics to shale gas-bearing property evaluation and main controlling factor analysis

Gas-bearing property evaluation and main controlling factor analysis have remained a concern in shale gas research. The application of principal component analysis, an important mathematical statistical method, in gas-bearing property evaluation and main controlling factor analysis of the Longmaxi shale in the Weirong area, Sichuan Basin, was examined. The Longmaxi shale exhibits high heterogeneity, manifested in the organic matter abundance, mineral composition, and pore structure. Seven geological factors, including the temperature, pressure, TOC content, clay content, brittle mineral content, pore volume, and specific surface area (SSA), were selected in principal component analysis. Four principal components with geological significance, such as mineral composition, formation condition, pore structure, and organic matter abundance, were extracted through principal component analysis, and further constituted a comprehensive factor. Shale gas-bearing properties were evaluated according to the score of the comprehensive factor. The Longmaxi shale could be identified as exhibiting good, medium, and poor gas-bearing properties based on the comprehensive factor scores of these samples. According to each geological factor’s contribution to the comprehensive factor, combined with geological analysis, it could be considered that gas-bearing properties are primarily controlled by pore volume, SSA, and clay content, followed by TOC content, brittle mineral content, temperature and pressure.

Micro-pore structure and fractal characteristics of deep shale from Wufeng Formation to Longmaxi Formation in Jingmen exploration area, Hubei Province, China

To explore the pore structure and fractal characteristics of shale reservoirs in the Jingmen exploration area and quantitatively evaluate the heterogeneity and complexity of pores, taking Wufeng-Longmaxi formations of Well YT3 as the research object, the pore structure characteristics of shale reservoirs are analyzed by low-pressure nitrogen adsorption experiments, total organic carbon (TOC) content testing, X-ray diffraction analysis, etc., and the FHH fractal model is established based on the low-temperature nitrogen adsorption fractal geometry method. The relationship between fractal dimension and shale composition, pore structure, physical property, gas-bearing property, and burial depth is discussed. The results show that (1) The lower section of Longmaxi Formation and Wufeng Formation have significantly higher TOC concentrations than the upper section of Longmaxi Formation. With the increase of burial depth, the silicate minerals increase gradually, while clay minerals decrease. (2) The on-site desorption gas content of shale shows that the gas content of the upper section of Longmaxi Formation with low TOC abundance is lower than the lower section of Longmaxi Formation and Wufeng Formation. In terms of shale gas composition, nitrogen dominates the upper section of Longmaxi Formation, whereas methane dominates the Wufeng Formation and lower section of Longmaxi Formation. (3) The isothermal curve of shale under low-pressure nitrogen is identical to IUPAC type IV, while the adsorption hysteresis loop is similar to types H3 and H4. The pores are mainly micro medium pores distributed below 50 nm, and they are flat and slit. The lower section of Longmaxi Formation and Wufeng Formation have significantly larger adsorption volumes than the upper section of Longmaxi Formation, and the abundance of organic matter provides a large amount of organic pore storage space. (4) The BET specific surface area and BJH total pore volume in the lower section of Longmaxi Formation and Wufeng Formation with rich organic matter are significantly larger than in the upper section of Longmaxi Formation with low organic matter, whereas the average pore size is significantly smaller. (5) Shale pores have obvious fractal characteristics, with D2 being higher than D1, indicating that the pore structure is more complicated than that of the pore surface. Fractal dimension has a significant positive correlation with TOC content, BET-specific surface area, and burial depth, a weak positive correlation with quartz content and BJH total pore volume, a significant negative correlation with clay mineral content and average pore diameter, and almost no correlation with porosity and permeability. Many factors that affect the fractal dimension. Correlation analysis reveals that the mass fraction of TOC and clay mineral, specific surface area, average pore diameter, and burial depth are the main controlling factors. The fractal dimension can be utilized to quantify the complexity and heterogeneity of pore structure, which provides a concept for studying the distribution characteristics of shale pore structure and reservoir evaluation.

Controlling Factors of Gas-Bearing Properties in Permian Tight Sandstone Based on Sealing Corings, Sulige Gas Field, Ordos Basin, Northern China

Gas saturation (Sg) is an important parameter for studying the gas-bearing properties of tight sandstone; however, there has been limited research on gas-bearing properties based on sealing coring. This study determines the controlling factors of the gas-bearing properties of tight sandstone in the Permian He8 Member of the Sulige Gas Field, Ordos Basin, Northern China, based on sealing coring, logging, drilling, gas testing, and laboratory analysis. The He8 Member Sg distribution is 17.9–63.8% (main range: 30–45%) and shows a downward trend from bottom to top. The Ro and hydrocarbon generation intensity of the source rock, reservoir porosity, and permeability tend to control the Sg in stages. When these parameters are less than 1.8%, 17 × 108 m3/km2, 10%, and 0.5 × 10–3 μm2, respectively, Sg increases significantly. When each parameter is greater than the aove boundary value, the change in Sg is not obvious. Four types of gas-bearing patterns of tight sandstone can be observed according to the distribution of reservoir and source rock conditions: “upper and lower constant,” “upper low–lower high,” “upper high–medium low–lower high,” and “upper high–lower low”; these patterns are mainly controlled by high maturity source rocks, reservoir physical properties, reservoir physical properties and structure, and structure, respectively. The corresponding gas test results reveal the existence of pure gas, pure gas and gas–water, gas–water, and gas-bearing water and pure water layers, respectively.

Reservoir characteristics and gas-bearing property of Wufeng-Longmaxi shale in well HY2, Hefeng area

Reservoir characteristics and gas-bearing property of Wufeng-Longmaxi shale in well HY2, Hefeng area

Influence of Organic Matter on Gas-Bearing Properties and Analysis of Sedimentary Mechanism of Organic Matter Enrichment: A Case Study on the Yangtze Region of Southern China during the Early Cambrian

Shale gas exploration requires studies on the enrichment mechanism of sedimentary organic matter. The Lower Cambrian shale is taken as a study object to analyze the effect of organic matter on gas content using TOC content and porosity analyses, isothermal adsorption experiments, and FIB-HIM scanning electron microscopy observations. Then, we selected typical wells to determine the presence of excessive silica in the siliceous minerals by quantitative calculations. Besides, we analyzed the genesis of excessive siliceous minerals using elements including Al, Fe, and Mn, thus speculating the controlling factors of the redox environment and biological productivity. Results show that total organic carbon content controls the content of free and adsorbed gas, while shale gas mainly exists in organic pores and is developed in large numbers and with high roundness, showing the characteristics of “small pores inside big pores.” In the Lower Yangtze region during the Early Cambrian, the excessive siliceous minerals were of hydrothermal origin, and there were frequent hydrothermal activities due to its closeness to plate boundaries. These activities can intensify the reducibility of the waterbody’s bottom and improve the biological productivity on its surface, resulting in the enrichment of this matter. Most excessive silicon in this region is biogenic, while only a small part is of hydrothermal and biogenic mixed origin. The enclosed waterbody of the Upper Yangtze region was far from plate boundaries and close to the semiclosed “gulf,” resulting in its delamination. The waterbody’s surface was abundant with oxygen, thus increasing the biological productivity, while the high reducibility at the waterbody’s bottom was conducive to preserving sedimentary organic matter.

Controls on the Organic Matter Accumulation of the Marine-Continental Transitional Shanxi Formation Shale in the Southeastern Ordos Basin.

The marine–continental transitional shale with favorable geological conditions for shale gas accumulation and broad resource prospects is widely distributed in China, which is also well developed in the Ordos Basin. The reservoir characteristic and gas-bearing properties of the transitional Shanxi Formation shale have been studied in previous studies. However, the factors influencing the organic matter (OM) accumulation have not been well studied, which restricts shale gas exploration and development of the Shanxi Formation in the Ordos Basin. According to analyses of organic geochemistry, mineral compositions, and major and trace elements, this paper has studied the paleoenvironment characteristic and its influence on the OM accumulation of the Shanxi Formation shale. The results indicate that the OM is characterized by the high mature stage and type III kerogen while the total organic content (TOC) of Member 1 is higher than that of Member 2. From Member 1 to Member 2, the paleowater depth gradually decreases, along with a gradually relative cold and dry climate, decreasing the terrestrial influx intensity and paleoproductivity and increasing the oxygen content in the water column. For Member 1, the OM accumulation is mainly controlled by the terrestrial influx intensity and paleowater depth, and other paleoenvironment factors have an unobvious contribution to the OM accumulation. For Member 2, the OM accumulation is commonly controlled by the weak terrestrial influx, low paleoproductivity, and oxic water column, resulting in the low TOC of Member 2. This study reveals the paleoenvironment characteristic and controls on the OM accumulation of the Shanxi Formation shale, which is beneficial to the reservoir selection of the Shanxi Formation in the southeastern Ordos Basin and the understanding of the OM accumulation in other transitional shales.

Effects of shear on development characteristics of organic matter pores in shale: A case study of shale in the Niutitang Formation of the well XAD1

The development characteristics of organic matter pores (OMPs) in shales is fundamental to the gas-bearing property of the shales. Detachment is one of the most common types of structural deformation in shale formations. To investigate the characteristics of OMPs in shear-deformed shale and the associated effects on the pore structure of shale gas reservoir, two sets of detachment zones and the intercalated non-detachment zone of shale formations in the Niutitang Formation of the Well XAD1 are studied. Based on scanning electron microscope observations and low-pressure gas adsorption tests, the impacts of shear on the shale pore structure are evaluated quantitively and the deformation mechanism for OMPs in shale is established.Results indicate that the dominant pore type of shale in the Niutitang Formation of the Well XAD1 is OMPs. With the mineral rheology, organic matters are enriched in the clay gouge, which are more prone to shear deformation compared with those outside the gouge. Under shear, pores developed within the organic matter experienced directional elongation and compression, decreasing the pore sizes and lowering the volumes of the corresponding pores <30 nm; and the contact surface between organic matter and minerals becomes dislocated and open, increasing the volumes of the corresponding pores >30 nm. The effect of shear on OMPs is dominated by pore reduction. The volume loss ratio of shale micropores in detachment zones is the highest which can reach over 90%. The impact of shear on pore structures of non-detachment zone cannot be neglected within the thickness range of 5–20 m from the detachment surface, and the degree of pore reduction gradually decreases as the distance from the detachment zones increases. It is indicated that the detachment and its adjacent horizons are not favorable for shale gas exploration because of the low porosity and adsorption capacity.

Evaluation of the Accumulation Conditions and Favorable Areas of Shale Gas in the Upper Palaeozoic Marine-Continental Transitional Facies in the Daning-Jixian Area, Ordos Basin

This study focuses on the organic-rich mud shale in the Upper Palaeozoic transitional facies in the southeastern margin of the Ordos Basin. It systematically analyzes the shale gas accumulation conditions of the organic-rich mud shale in the Lower Permian Shanxi-Taiyuan Formation, including the thickness, distribution, organic matter type and content, thermal maturity, reservoir space, gas-bearing property, and rock brittleness. The results show that the thick dark mud shale contains a high organic matter content, is a suitable kerogen type for gas generation, and exhibits moderate thermal evolution, providing excellent conditions for hydrocarbon accumulation. Residual primary pores formed by shale compaction, secondary pores formed by organic matter hydrocarbon generation, clay mineral transformation and dissolution, and fractures provide suitable reservoir spaces for shale gas. The shale in the study area has a higher gas content than the shale strata in the marine basins of the United States. In addition, the content of brittle minerals such as quartz is higher, and Poisson’s ratio is lower, facilitating the subsequent transformation. The accumulation conditions indicate the high potential of the study area for shale gas exploration and development. The geological analogy method is used to compare the study area with five major shale gas basins in the United States. The results indicate that the shale gas resources of the Shanxi-Taiyuan Formation in the study area are in the range of 2800– 3200 × 10 8 m3. The primary controlling factors affecting shale gas reservoirs in this area are the abundance of organic matter, thermal maturity, shale thickness, and quartz content. Favorable areas are predicted based on these factors.