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Adsorbed gas ratio and gas-in-place (GIP) content are two critical parameters for determining shale gas resources and devising development plans. Existing traditional methods have their limitations in solving the above issues, while a novel approach for evaluating the aforementioned key parameters was provided by the carbon isotope fractionation (CIF) model. To investigate the stable carbon isotope fractionation and shale gas content characteristics during the degassing process, 10 shale samples from Well JY A in the Jiaoshiba area of the Sichuan Basin were chosen for on-site degassing tests. The on-site degassing patterns were recorded, and the methane, ethane, and carbon dioxide isotope values were measured. The CIF model was used to evaluate the gas degassing patterns and isotope fractionation characteristics of the complete degassing process and accurately assess the in situ gas-bearing parameters of the Well JY A shale. Research has shown that during a 20 h degassing process, the methane fractionation magnitude can reach 10‰, and the ethane fractionation magnitude is about 2‰. There are no significant fractionation characteristics for carbon dioxide. The complete cumulative degassing curve exhibits a “downward convex” shape followed by an “upward convex” shape, while the complete isotope fractionation curve shows a three-stage pattern of “initially stable, then lighter, and finally heavier”. Free gas diffuses first, followed by the desorption of adsorbed gas, which lags behind significantly, and the adsorbed gas ratio controls the apparent carbon isotope fractionation. Initially, diffusion fractionation dominates, while later, adsorption–desorption fractionation gradually becomes dominant. Using the CIF model, the GIP content of shale in the Well JY A ranges 2.52–5.11 mL/g, averaging 3.56 mL/g, and the adsorbed gas ratio accounts for 4.39%–30.28%, averaging 14.64%. Using the U.S. Bureau of Mines (USBM) method, the GIP content ranges 1.49–4.14 mL/g, averaging 2.69 mL/g, which is significantly underestimated in this area.

New Middle–Lower Triassic gas reservoirs were found in the eastern margin of the Ordos Basin, which provides new possibilities for gas exploration in the Ordos Basin. However, there are few relevant studies on these gas reservoirs. In this study, we use porosity–permeability measurements, optical light microscopy, scanning electron microscopy, mercury intrusion capillary pressure experiments, core-scale low-field nuclear magnetic resonance experiments, fluid inclusion analysis, burial history reconstruction, organic geochemistry data, and wireline log data to systematically investigate the reservoir quality and accumulation pattern of Middle–Lower Triassic gas reservoirs. The Middle–Lower Triassic sandstones are mostly lithic arkose, with a small amount of feldspathic litharenite. In comparison to the upper Paleozoic tight sandstone, the Middle–Lower Triassic sandstones exhibit a superior pore structure and increased porosity and permeability. A significant portion of the Middle–Lower Triassic sandstones can be referred to as “conventional sandstones” (porosities >12% and permeabilities >1 mD). The source rocks of the Middle–Lower Triassic gas reservoirs are most likely the upper Paleozoic coal and organic-rich mudstone, and the accumulation of natural gas occurred in the Early Jurassic to Late Cretaceous. The gas accumulation in the sandstones of the Middle–Lower Triassic reservoirs was mainly driven by buoyancy. The initiation and extension of vertical faults with small displacement in the northeast margin of the Ordos Basin enabled gas to move through the faults from the deep upper Paleozoic source rocks to the Middle–Lower Triassic reservoirs. Since gas accumulation relies on buoyancy, conventional sandstone layers with good reservoir properties are more likely to reach high gas saturation and are the primary targets for exploration and development.

A series of high-pressure methane adsorption measurements were performed at various temperatures on whole shale and kerogen samples collected from the Lower Longmaxi shale in the Nanchuan area, southeast Sichuan Basin, to investigate supercritical methane adsorption properties and evaluate in-place methane storage capacity as a function of burial depth. The results show that the supercritical Dubinin–Radushkevich (SDR) model fits the excess adsorption isotherms marginally better than the supercritical Langmuir model. However, the fitted adsorbed methane density of kerogens obtained from the SDR model may be greater than the liquid methane density at the atmospheric boiling point (0.423 g/cm3). The proposed multiple regression fitting carried out in this work illustrates that approximately 57.59% (34.51–85.45%) and 37.60% (10.74–59.52%) of the methane adsorption capacity at 333.15 K can be attributed to organic matter (OM) and clay minerals (CMs), respectively, for whole shales investigated. According to thermodynamic analyses, the significant contribution of OM to the methane adsorption capacity can be attributed to the stronger affinity between kerogens and methane molecules in contrast to that between CMs and whole shales. The methane storage capacity estimated as a function of burial depth showed that the adsorbed gas storage capacity declines with increasing burial depth between 2000 and 5000 m, while the free gas storage capacity shows the opposite trends. Gas accumulation pressure primarily exerts a significant effect on the free gas storage capacity rather than adsorbed gas storage capacity, and adsorbed gas storage capacity begins to exceed free gas storage capacity at shallow burial depths for normally pressured gas accumulations. Normally pressured shale gas accumulations at shallow burial depths, which are widely distributed in the residual syncline of the study area, should be given more attention due to their relatively low development costs and relatively high storage capacity for adsorbed gas.

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.

This research proposes a new method to correct the nuclear magnetic resonance (NMR) T2spectrum at different centrifugal rotational speed states to more accurately evaluate the fluid mobility characteristics, pore connectivity characteristics, and unmoved water thickness of shale reservoir samples. The Longmaxi Shale in Southeast Chongqing was selected for this case study. Experiments, including mercury intrusion porosimetry (MIP) and NMR at dry, saturated water, and different centrifugal rotational speed states, were performed on these shale samples. The NMR T2spectrum at different centrifugal rotational speed states was corrected according to the calibration rules. Then, the characteristics of fluid mobility and pore volumes (PV) connected by different sizes of throats and unmoved fluid thickness were evaluated. The results of the connected PV from the corrected NMR were compared with those from MIP. After correcting, the signal amplitude of the NMR T2spectrum decreases with centrifugal rotational speed in order and becomes more regular without interleaving. The response signal of the NMR T2spectrum at the centrifugal state can more truly reflect the PV connected by different throat sizes. The method of correcting the NMR T2spectrum includes three advantages, namely, almost eliminating the influence of adsorbed and bound water, more accurately reflecting the response signal of movable fluid, and estimating the adsorbed water thickness. This method also has three disadvantages, namely, the NMR T2spectra must be measured at several states, corrected abnormal second minimum deviation, and contact angle accuracy error.

A set of high-quality hydrogen-rich shale was found in the upper third submember of the Shahejie Formation (Es3U) in the Raoyang sag. After more than 40 years of exploration and development, oil and gas shows have been seen in many wells in this interval, and there are many wells to obtain industrial oil flow. However, the influencing factors of its shale oil enrichment are still unclear. Based on petrology, organic geochemistry, and elemental geochemistry analysis, the control effect of the characteristics of a paleosedimentary environment on lacustrine shale oil enrichment is revealed and the shale oil enrichment model is established in this paper through a comprehensive study of the occurrence and migration of elements in different sedimentary facies areas. The parameters of V/(V+Ni), δU, Sr/Cu, Rb/Sr, Zr/Rb, Zn/Al, and Sr/Ba indicate that lake water evaporates in hot and arid climate, and brief transgression events led to the increase of water salinity; the outburst of salt-eating organisms such as algae and nutrients from the provenance provided the material basis for the enrichment of organic matter. The quiet and strong reduction of paleowater provides good preservation conditions for the enrichment of organic matter. The Mg2+provided by transgression moved toward the center of the lake basin under the action of gravity, and the low-magnesium and calcium-rich saline environment was conducive to the occurrence of carbonate minerals such as calcite. Calcite and aragonite laminae were generated in the center of the sedimentation of the lake basin and interbedded vertically with the organic matter carried by fine-grained materials. The areas where carbonate-rich, calcareous, and argillaceous shales with rich organic matter are relatively developed are sweet spot reservoir areas of shale oil, which are mainly located in the center of the lake basin. In addition, the total organic matter content is high enough to meet the shale oil enrichment standards. Through the above studies, shale oil enrichment is established, which can guide shale oil exploration and development in the Raoyang depression successfully.

The pore structure and its complexity and heterogeneity control the occurrence states and fluidity of shale oil. The multifractal theory effectively characterizes the complexity and heterogeneity of the shale pore structure. In this study, serial technologies were applied to detect the pore systems of shale obtained from Dongying Sag, Bohai Bay Basin in China. The multifractal characteristics of the pore structure of the shale were analyzed based on its nuclear magnetic resonance (NMR) T2spectrum. The analysis results show that shale oil reservoirs can be classified into four types based on their T2spectra. Type I shales T2spectra show large p2 (1–20 ms), moderate p3 (>20 ms), but little p1 (<1 ms), characterized by large NMR and connected porosity, the lowest BET specific surface area (SSA), and the largest average pore throat diameter and S1contents. Large p2, moderate p1, and tiny p3 are the main distinctions of type II shales with the largest NMR porosity, large connected porosity, and BET SSA. The T2spectra of type III shales have large p1, moderate p2, and little p3, corresponding to large NMR porosity and BET SSA and the largest total organic content (TOC) and S1contents but lower connected porosity. Type IV shales have the most significant contents of micropores with the relatively largest p1 in the T2spectra characterized by the lowest NMR and connected porosity, the largest BET SSA, the lowest TOC, and S1contents but the largest clay mineral contents. Both types III and IV shales are unfavorable shale oil reservoirs. Dqdecreases monotonically as qincreases, indicating the multifractal nature of shale pore structures. D0varies from 0.88 to 1.00 (mean: 0.95), and Δα ranges from 1.24 to 2.82 (mean: 1.79), suggesting complex and heterogeneous pore structures. Types I and II shales have lower D0values than types III and IV shales. Thus, type I organic-bearing massive felsic and type II organic-rich layered calcareous shales are favorable for shale oil reservoirs with large pores and large porosity. They have the least complex pore structures among the four shale types considered.

The grading evaluation of shales helps in understanding the shale reservoir formation and sweet-spot screening of physical properties. Reservoir formation of shale is closely related to the size, distribution, and connectivity of shale pore–throats. Therefore, characterization and classification of microscopic pore–throats are the basis for shale reservoir grading. However, previous microscopic pore–throat classification schemes for materials science are unsuitable for shales with strong heterogeneity. In recent years, the author’s team has proposed a new classification method for microscopic pore–throats of shale reservoirs based on the comprehensive characterization of numerous shales with varied maturities in different basins. Results show that the microscopic pore–throats for all shales can be divided into micropores, small pores, mesopores, and macropores. The component, size, and distribution of microscopic pore–throats in shales in different basins differ due to the differences in mineral composition and diagenetic evolution of shales caused by varying depositional environments and burial histories. Correspondingly, the demarcation points of different types of pore–throats are different. After clustering statistical analysis of different types of microscopic pore–throats, shales can be divided into grade I, II, III, and IV reservoirs, regarded as good, medium, poor, and nonshale reservoirs, respectively. Grading evaluation criteria for shale reservoirs were then established. Further, a new technique for evaluating the reservoir flow zone index (FZI) and dividing flow units based on logging data was constructed using the relationship of permeability with porosity in the same hydraulic flow unit. The grading evaluation criteria can be applied to single wells, multiwells, and planes using logging data. The application in numerous shale oil and gas exploration areas in China shows that the established classification scheme can be applied to the grading evaluation and sweet-spot screening of shale reservoirs.

The physical properties of gas shales, especially the structural features of connected pore-fractures, are key parameters for evaluating shale gas resource potential and effective production. In this study, four major techniques, including mercury intrusion capillary pressure (MICP), low-temperature nitrogen adsorption/desorption (LT-NA/D) tests, scanning electron microscopy (SEM), and fractal theory, were adopted to establish a suitable pore size classification for gas shales from the Wufeng–Longmaxi formations in the southeastern Sichuan Basin. On the basis of the inflection points of the mercury intrusion curves, a quantitative classification for connected pore-fractures of gas shales in the study area was proposed: micropores (<10 nm), ostioles (10–25 nm), mesopores (25–100 nm), macropores (100 nm–5000 nm), and fractures (>5000 nm). This classification method was verified using fractal geometry theory and was reasonable as compared to other pore size classification methods of unconventional reservoir. The controlling factors of pore-fractures systems were also investigated according to shale compositions and SEM images. The results show that gas shales mainly developed organic matter (OM) pores, interparticle (interP) pores, and intraparticle (intraP) pores. Among them, the OM pores are composed mainly of micropores and ostioles, which can effectively increase the gas storage capacity of shale. The increase of pore content with diameter greater than 25 nm may increase the seepage capacity of gas shales. The quality of shale gas reservoirs is usually affected by multiparameter such as microscopic pore-fractures content, pore size distribution, specific surface area, porosity, and shale compositions (including minerals and OM). The gas shales could be classified into three types (i.e., types I, II, and III). Type III shale is a high-quality shale gas reservoir, which is rich in micropores (35.90–87.83 vol %), has a high total organic carbon (TOC) content (2.55–3.39%), has a high porosity (10.96–16.01%), and has good fracturing ability (the average content of quartz is 53.88%). Type I shale is a poor shale gas reservoir, but it can be used as a good gas seepage channel due to the high content of fractures and macropores (mean 39.48 vol % and 18.89 vol %). Type II shale is a transitional shale gas reservoir.

In situ gas content and adsorbed gas ratio are the key parameters for shale gas content evaluation, and they can provide important references for the selection of development target areas and optimization of later development strategies. As a new formation for shale gas exploration and development, the gas content and adsorbed gas ratio of the Permian in the Hongxing area are not clear, which limits further development work. In this study, five shale samples from the Wujiaping Formation in the Hongxing area of the Sichuan Basin were used for sealing and desorption experiments, and four methods, namely, the USBM method, the polynomial method, the Amoco method, and the CIF method, were used to evaluate the gas content of the shale, and the results of the CIF method were found to be more accurate in comparison. The in situ gas content of Permian shales in the Hongxing area ranged from 5.38 to 13.36 cm3/g, with an average value of 8.30 cm3/g, and the ratio of adsorbed gas ranged from 45.24 to 74.67%, with an average value of 54.9%. Comparison with other typical shale and coal formations in several sedimentary basins in China shows that the in situ gas content and adsorbed gas ratio of Wujiaping shale are higher than those of Longmaxi shale in the Sichuan Basin and Shahezi shale in the Songliao Basin but lower than those of Shanxi and Taiyuan coal in the Qinshui Basin. The Wujiaping shale in the study area has unique gas-bearing characteristics; the high in situ gas content shows its good resource potential, but the high adsorbed gas ratio puts forward higher technical requirements for the efficient development of this resource.

Shale oil has been found in the Paleogene lacustrine source rocks in the second (Eh32) and third beds (Eh33) of the third member of the Hetaoyuan Formation from the Biyang Depression of the Nanxiang Basin, eastern China, but the formation environments of the organic-rich shales are still unclear, which restricts the shale oil exploration. Here, this paper discusses the paleoenvironment and its control on the organic-rich shale formation. Our study suggests that shales from the Eh32and Eh33beds display some heterogeneities in total organic carbon (TOC) contents and oil potential as a result of their different paleoenvironments. During Eh33deposition, the paleoproductivity was moderate to high, which was diluted by moderate to high terrigenous detrital matter (TDM) input. During Eh32deposition, the TDM and terrigenous organic matter (TOM) inputs increased. The paleoproductivity was moderate, which was greatly diluted by the high TDM content. The redox conditions were anoxic during the two source rock intervals. Paleoproductivity is the main controlling factor of source rock formation during Eh32and Eh33depositions, which has a strong positive correlation with the burial of organic carbon. However, anoxia did not promote deposition of the richest source rocks. During Eh33deposition, shales with high contents of TOC values and better oil potential could be formed in this environment on account of the moderate to high paleoproductivity. In contrast, during Eh32deposition, high TOM input did not obviously improve the burial of organic carbon but high TDM input significantly diluted the paleoproductivity. The bottom water became semi-saline to hypersaline, but it did not enhance the anoxic environment. Shales with medium TOC values and oil potential could be formed in this environment as a result of moderate paleoproductivity.

To evaluate the amount of adsorbed methane in a shale reservoir under different conditions of temperature and pressure, the Longmaxi shale from the Py1 well of southeast Chongqing was selected as a case to establish the three compositions adsorbing methane (TCAM) method based on the results of total organic carbon, X-ray diffraction, and methane isothermal adsorption analyses. The amounts of methane adsorbed by organic matter (OM), clay, and other minerals were calculated under different conditions of temperature and pressure, followed by the evaluation of the occurrence characteristics of adsorbed gas in a shale reservoir. A comparison of data from experiments and the TCAM method with two shale samples revealed the uncertainty of TCAM. The results from the two samples range from 0.02 to 0.08 m3/t and from 0.01 to 0.09 m3/t, with average values of 0.05 and 0.04 m3/t, respectively. The methane adsorption capacities of OM, clay, and other minerals at temperatures ranging from 30 to 70 °C were 26.04–38.76, 1.83–2.76, and 0.43–0.53 m3/t, respectively, with average values of 32.86, 2.38, and 0.48 m3/t, respectively. These values are significantly reduced and are more likely to be affected by the temperature. The contributions of OM, clay, and other minerals to the total adsorbed gas are 34.83, 46.74, and 18.43%, respectively, on the basis of the limited data available. The efficient exploitation of adsorbed gas in a shale reservoir requires an increase in the reservoir temperature or a reduction in the reservoir pressure to lower than 10 MPa. The TCAM method requires the shale reservoir to be in a relatively stable sedimentary environment, to have the same diagenetic evolution, and to have the same type of OM. Once the TCAM model is established, it can be applied to the same marine shale reservoir with a similar diagenetic evolution in the same area.

Fluid occurrence and pore structure are prerequisites for exploring the enrichment pattern of shale oil. The Cretaceous Tengger Formation in the A’nan Sag, Erlian Basin, China, contains abundant shale oil resources. In this study, a series of NMR T2and T1–T2, combined with Rock-Eval, scanning electron microscopy (SEM), and low-temperature nitrogen adsorption–desorption (LTNA/D), were conducted to clarify the fluid occurrence and pore structure characteristics of the shale oil reservoirs. Meanwhile, the influences of the pore structure on fluid occurrence were discussed. Results suggest that the in situ occurrences and distributions of pore water and oil can be well analyzed by the NMR T1–T2technique combined with water and oil restorations. The selected shales are characterized by high contents of capillary-bound water and bound oil, and bound oil mainly contributes to shale oil, followed by adsorbed and movable oil. The shales at the as-received state have lost half of the capillary-bound water, as well as most of the bound and movable oil, while adsorbed oil is less affected. The pore spaces primarily consist of interparticle pores related to brittle granules, followed by intraparticle pores in clay mineral aggregates. The T2spectra are characterized by the dominant peak p2 ranging from 0.7 to 20 ms, corresponding to the developed mesopores (100–1000 nm). Fluid occurrence is closely related to pore structures. Capillary-bound water primarily occurs in micropores (<25 nm) and minipores (25–100 nm) and coexists with adsorbed oil. Mesopores and macropores (>1000 nm) are mainly saturated with bound and movable oil, respectively. The developed large pores generally correspond to less capillary-bound water but more shale oil, especially bound and movable oil. These findings may improve the understanding of enrichment mechanisms of shale oil and provide the references for sweet spot exploitation in the A’nan Sag, Erlian Basin.

Shale gas resources provide a new impetus to alleviate the contradiction between China’s oil and gas supply and demand. As an important part of shale gas, understanding the occurrence mechanism of adsorbed gas can help shale gas resources to be better developed and used. This time, a series of experiments, such as low-temperature nitrogen adsorption and methane isotherm adsorption, were conducted to discuss the pore structure, adsorption performance, and adsorption mechanism of shale. The results show the following: (1) Shale pores are dominated by nanopores, and pores with a pore width of less than 2 nm have the best relationship with the shale surface area and adsorption capacity. (2) Total organic carbon (TOC) plays an important role in controlling the specific surface area and methane adsorption capacity of shale. This is mainly due to the large number of micropores (pore size of <2 nm) developed in organic matter. Micropores provide the main specific surface area and adsorption sites for methane adsorption. (3) A variety of models were used to fit shale methane isotherm adsorption data. The results show that the SDR model and Langmuir model have the best fit. The methane adsorption performance of shale is controlled by many factors; the adsorption capacity becomes weaker as the temperature rises; and this influence is also affected by TOC. (4) In comparison to the adsorption capacity, the change of the adsorbed phase density is more complicated: overall, there is a weak positive correlation with TOC; as the temperature increases, the adsorbed phase density decreases. However, this law is not stable, and there are different performances in different experiments. (5) The adsorption comparison results show that the shale methane adsorption is mainly multilayer adsorption and micropore filling.

Following the marine shale gas, the continental shale gas also presents great exploration potential in China. However, few studies focused on the high-over-mature stage (HOMS) continental shale gas in terms of mineral composition, pore structure, and gas-bearing properties, as well as their comparisons with successfully marine shale gas in the same mature stage, which restricts its better potential evaluation and “sweet spots” suggestion. In this paper, the lower Cretaceous Shahezi Formation in Xujiaweizi fault depression, and the lower Silurian Longmaxi Formation in Pengshui Area, were selected as the target areas for the study of continental and marine shale gas in the HOMS. By means of thin sections, scanning electron microscopy, nitrogen adsorption, high-pressure mercury injection, and methane isothermal adsorption, a systematic comparison was carried out to reveal the differences in reservoir characterizes and gas-bearing properties, and summarize their controlling factors and “sweet spots” distribution. The type and distribution of organic matter (OM) dominate the differences between marine and continental shale in the HOMS. Compared with Longmaxi marine shale with OM of type I–II1kerogen, there are fewer biogenic siliceous, lower proportion of organic pores, and more inorganic pores (including dominant clay related pores, quartz intergranular pores, and dissolution pores) in Shahezi continental shale with OM of type III–II2kerogen, corresponding to larger average pore size and smaller specific surface area (SSA). Quartz content, porosity, and SSA are mainly controlled by TOC for marine shale, while those are controlled by deposition and burial depth for continental shale. Plain marsh shale, adjacent to a coal seam, is favorable for the development of cemented quartz grains and the limited conversion of mixed illite/smectite (I/S) to illite, which can effectively restrain the impact of burial depth on the proportion of intergranular and dissolution pores, porosity, and pore size for continental shale. I/S, rather than OM, mainly contributes to the methane adsorption capacity in continental shale, of which the adsorbed gas content is obviously lower than that of marine shale. Due to the higher pressure coefficient (PC), porosity and total gas content of marine shale still increase with increasing the burial depth, while those of Shahezi continental shale decrease rapidly due to the slight increase of PC with depth. Some exploration potential in organic-rich thick shales should be expected in the Shahezi Formation, which are developed in plain marsh or delta front with burial depths in the range of 2600–3600 m.

Numerous models have been used to describe the isotherm adsorption of supercritical methane in porous media. Many models assume that the adsorbed phase density does not change with pressure during the adsorption process. However, recent studies show that this assumption is unreasonable, and the resulting error is enormous. Therefore, we propose an improved isotherm adsorption model in shale that assumes that the adsorbed phase density keeps changing and that adsorbed phase volume remains constant during the adsorption process [the variable density adsorption (VD) model]. A logarithmic function is used to describe the change of the adsorbed phase density during the adsorption process. The product of the adsorbed phase density and volume is used to calculate the adsorption capacity. The fitting results for large amounts of methane adsorption data show that this assumption is reasonable. The fitting results are consistent with the molecular simulation, and it will be more convenient to obtain the truly adsorbed phase volume and density. The adsorbed phase volume and density obtained by the VD model show a good positive correlation with the total organic carbon, specific surface area, and micropore volume, which indicates the rationality of adsorption parameters fitted by the model. As a result of the correct calculation of the adsorption phase density, the gas in place (GIP) obtained by the VD model is lower than the supercritical Dubinin–Radushkevich model. The new model proposed this time provides a new tool for the study of shale methane isotherm adsorption and a new model for the calculation of GIP. Using this model, the adsorbed phase density and volume of methane can be obtained more conveniently and accurately. This will be a milestone in the VD model.

Tight sandstone gas reservoirs have poorer porosity–permeability relationships, so conventional reservoir classification schemes can hardly satisfy the classification and evaluation demand of this type of reservoirs. To solve this problem, this paper took the Permian tight sandstone gas reservoir in the Linxing Block along the eastern margin of the Ordos Basin as an example to describe the micro-structures of the tight sandstone reservoirs by means of high-pressure mercury injection, nuclear magnetic resonance (NMR), scanning electron microscope (SEM) and so on. Then, the control effect of micro-structure parameters on the macrophysical properties was studied. Finally, classification and evaluation of tight sandstone reservoirs were carried out on this basis. And the following research results were obtained. First, NMR can identify the distribution of pores of different sizes, and high-pressure mercury injection can reflect the pore–throat configuration and percolation capacity of a reservoir. Second, both methods are better coincident in the description results. With an increase of the right peak of T2spectra, the mercury intrusion curve presents a concave shape and the pore throat radius increases while the pore type gradually changes from intragranular dissolution pores and intercrystalline pores to intergranular pores and intergranular dissolution pores and the reservoir quality gets better. Third, micro-pore structure controls reservoir physical properties and fluid mobility. And the porosity of large pores is best correlated with the effective porosity, so it can be used to evaluate the reservoir capacity of tight sandstone. Fourth, the throat radius R15obtained by high pressure mercury injection is in the best correlation with porosity and permeability, so it can be used to evaluate the percolation capacity of tight sandstone. Fifth, by combining the porosity of large pores with the R15, the tight sandstone reservoirs in the Linxing Block are classified into 4 categories, and the classification results are in a good agreement with the on-site well test data. It is concluded that the combination of high-pressure mercury injection and NMR can effectively identify the key parameters which reflect the reservoir capacity and percolation capacity of tight sandstone, and improve the reliability and integrity of reservoir classification. And by selecting the key parameters that reflect reservoir capacity and percolation capacity, it can provide guidance for the classification and evaluation of tight sandstone reservoirs.

The gas in-place (GIP) content and the ratio of adsorbed/free gas are two key parameters for the assessment of shale gas resources and have thus received extensive attention. A variety of methods have been proposed to solve these issues, however none have gained widespread acceptance. Carbon isotope fractionation during the methane transport process provides abundant information, serving as an effective method for differentiating the gas transport processes of adsorbed gas and free gas and ultimately evaluating the two key parameters. In this study, four stages of methane carbon isotope fractionation were documented during a laboratory experiment that simulated gas transport through shale. The four stages reflect different transport processes: the free gas seepage stage (I), transition stage (II), adsorbed gas desorption stage (III) and concentration diffusion stage (IV). Combined with the results of decoupling experiments, the isotope fractionation characteristics donated by the single effect (seepage, adsorption-desorption and diffusion) were clearly revealed. We further propose a technique integrating the Amoco curve fit (ACF) method and carbon isotope fractionation (CIF) to determine the dynamic change in adsorbed and free gas ratios during gas production. We find that the gases produced in stage I are primarily composed of free gas and that carbon isotope ratios of methane (δ13C1) are stable and equal to the ratios of source gas (δ13C01). In stage II, the contribution of free gas decreases, while the proportion of adsorbed gas increases, and the δ13C1 gradually becomes lighter. With the depletion of free gas, the adsorbed gas contribution in stage III reaches 100%, and the δ13C1becomes heavier. Finally, in stage IV, the desorbed gas remaining in the pore spaces diffuses out under the concentration difference, and the δ13C1becomes lighter again and finally stabilizes. In addition, a kinetic model for the quantitative description of isotope fractionation during desorption and diffusion was established.

The response characteristics of transverse relaxation time (T2) of key experimental parameters [waiting time (TW), number of scans (NS) and echo number (NECH)], sample size and probe fluid, are analysed systematically based on NMR experiments of oil- and gas-bearing shales from the Shahejie Formation in Dongying sag and the Wufeng and Longmaxi Formations in the southern Sichuan Basin. The results indicate that: 1) the optimised NMR parameters for TW, NS and NECH are 1,500 ms, 64 and 6,000, respectively, which will ensure higher accuracy and signal-to-noise ratio (SNR); 2) the total signal amplitude of the T2spectrum increases with decreasing grain size. The T2spectra of shale which grain size bigger than 10 mesh can characterize the shale PSD; 3) water porosity clearly decreases with increasing brittle minerals but decreasing clay content than n-dodecane-saturated porosity, which indicates the hydration of clay and brittle minerals together controls the reconstruction of PSD. [Received: May 30, 2018; Accepted: October 24, 2018]

With the worldwide increasing concern regarding environmental protection and controlling carbon emission, carbon dioxide (CO2) displacement in the subsurface becomes a vital process in environmental engineering and petroleum engineering. In this study, we propose a new “D3Q27” three fluid phase lattice Boltzmann method (TPLBM) based on a multiple relaxation time algorithm to study the flow behavior of three fluids, water, CO2, and oil in this study. A series of TPLBM simulation studies are carried out on a three-dimensional digital replica of a rock (sandstone) to investigate the microprocesses and mechanisms of CO2displacement from its oil–water–CO2systems. Data gathered from high-resolution X-ray computed tomography scanning of a sandstone sample from Daqing oilfield, Longhupao, Songliao Basin, China, is used to construct the rock replica. TPLBM numerical simulations are conducted to analyze the microdisplacement of CO2in sandstone under different injection conditions. The results show that the displacement efficiency is higher at higher injection rates and pressure differences, with a constant total volume of injected CO2. The optimal injection rate and pressure difference for CO2displacement in sandstone are identified. The average ultimate CO2displacement efficiency is 90.1% when the injection rate remains constant, whereas the average ultimate CO2displacement efficiency is 95.8% when the injection pressure difference remains constant. The proposed method offers a new method for analyzing the pore-scale three fluid phase flow in sandstone.

Lacustrine shales with complex mineral compositions and rock formations are associated with different lithofacies, and shale oil contents vary significantly depending on the lithofacies. This study examines lacustrine shales from the Funing Formation, Gaoyou Sag, Subei Basin using scanning electron microscopy, total organic carbon (TOC), Rock-Eval pyrolysis, X-ray diffraction, thin section, and nuclear magnetic resonance T1–T2to determine the key factors controlling oil content in different shale lithofacies. Shale lithofacies were determined based on the mineral composition, rock structure, and organic matter content. The micro-distributions of shale oil in different lithofacies were disclosed. The results show that the studied shales in Gaoyou Sag are primarily divided into massive felsic-rich, stratified felsic-rich, laminated felsic-rich, laminated felsic, laminated calcareous-rich, and laminated calcareous shales. Massive felsic-rich shales have the largest TOC, S1, and free oil contents associated with organic-rich shales. Stratified felsic-rich shales have the larger TOC, S1, and free oil contents, followed by the laminated felsic-rich and felsic shales. However, laminated calcareous-rich shales are characterized by larger TOC but lower S1and free oil contents, whereas laminated calcareous shales have the lowest organic matter and oil contents. Shale oil content is mainly affected by the organic matter content and the development of reservoir space. Massive felsic-rich shales are characterized by almost all pores saturated with oil. The oil contents in stratified felsic-rich, laminated felsic-rich, laminated felsic, and laminated calcareous-rich shales are primarily affected by the development of reservoir spaces, followed by organic matter abundance. However, laminated calcareous shales are the opposite. Interparticle pores at the edge of granules are the most developed pores, whereas interparticle pores associated with quartz are generally saturated with oil, followed by those related to calcite or dolomite. Intraparticle pores in clay minerals are usually free of oil. Moreover, shale oil primarily occurs in large interparticle pores. The organic-rich massive felsic-rich and organic-bearing laminated felsic-rich shales are favorable for shale oil enrichment, and organic-bearing laminated felsic-rich shales with larger pores and interlayer micro-fractures may be the optimal lithofacies for shale oil. This study provides insight into the micro-distribution of shale oil in different lithofacies, which will guide shale oil development in the Gaoyou Sag, Subei Basin.

The pore size distribution (PSD) and fluid mobility parameters are vital parameters for predicting rock properties and the reservoir quality classification. Because of the characteristics of strong heterogeneity, a complex pore-throat structure, and a wide PSD of glutenite, it is more difficult to acquire the full-range PSD and fluid occurrence states of glutenite. This paper investigates the full-range PSD, the distribution, and the controlling factors of the movable oil in glutenite based on various experiments. X-ray diffraction, casting thin sections, scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), high-pressure mercury intrusion, and nuclear magnetic resonance (NMR)–centrifugation experiments were conducted on 18 glutenite samples from the Mahu Sag, Junggar Basin, China. A new method for characterizing the full-range PSD of glutenite was proposed by integrating LTNA and NMR–centrifugation experiments, and the full-range PSD is in good agreement with the casting thin sections and SEM images. Moreover, in terms of the distribution patterns of the T2spectra under the n-dodecane saturation condition, the glutenite samples are divided into four categories (i.e., type-I, type-II, type-III, and type-IV). From type-I to type-IV, both the pore size and the movable oil saturation of glutenite samples show a gradually decreasing trend. In addition, the movable oil mainly occurs in the pore-throat configurations of type-A, type-B, and type-C in glutenite. The development of the different types of pore-throat configurations is controlled jointly by the sedimentary compositions and mineral compositions. For higher quartz clastic and feldspar mineral contents and lower calcite and clay mineral contents, glutenite is more developed in type-A, type-B, and type-C pore-throat configurations. The above findings will provide intellectual support for identifying high-quality glutenite reservoirs and improving the productivity of glutenite oil reservoirs.

The influence of the paleoclimate on the organic matter (OM) accumulation and depositional process in the third member of the Hetaoyuan Formation shales is unclear in the Paleogene lacustrine systems in the Biyang Depression, Nanxiang Basin, Eastern China. Here, inorganic and organic geochemical analyses were performed on samples from a 25 m profile to examine the effects of paleoclimate change on the depositional environment and OM accumulation within this interval. Based on mineralogical and geochemical data from the B1 Well, two major lithofacies assemblages, calcareous mudstone-dominated (LA1) and clay-rich mudstone-dominated (LA2), were identified. Although generally anoxic bottom water was present during sedimentation, subtle differences in depositional environment and OM enrichment were found for the two lithofacies. The mineral composition and multiple geochemical proxies, including detritus index (sum of quartz, clay minerals, and feldspar contents), C-value [∑(Fe + Mn + Cr + Ni + V + Co)/∑(Ca + Mg + Sr + Ba + K + Na)], chemical index of alteration (CIA = 100 × Al2O3/(Al2O3+ CaO* + Na2O + K2O), Rb/Sr, V/(V + Ni), Sr/Ba, Pr/Ph, and gammacerane/C30hopane ratios all indicated that LA1 was deposited in a stable stratified saline lake with anoxic bottom water in a relatively cool, arid paleoclimate. However, these parameters suggested that LA2 was deposited in a brackish-to-saline lake with anoxic bottom water in a relatively warm, humid paleoclimate. Abundant OM (average total organic carbon (TOC) content 4.24 wt %) was accumulated mainly in LA1, with relatively high primary productivity suggested by high values of P/Ti, Ba/Al, 4-methylsterane/∑C29steranes index (4-MSI), ααα20RC27/ααα20RC29sterane (C27/C29), and ααα20RC28/ααα20RC29(C28/C29) sterane ratios. In contrast, in warmer, more humid conditions, the corresponding sediments in LA2 contained less OM (average TOC 2.29 wt %), consistent with ratios indicating lower primary productivity and higher detritus input. We draw the conclusions that the accumulation of higher OM in LA1 was controlled by the combination of paleoproductivity and preservation in anoxic bottom water, while the formation of the LA2 organic-rich mudstone was mainly related to primary productivity, anoxic conditions, and the dilution by terrigenous detrital matter.

The southeastern Sichuan Basin and its basin-margin transition zone (hereinafter referred to as “the basin-margin transition zone of SE Chongqing”) is the focus of normal-pressure shale gas exploration in China. In order to summarize the geological characteristics and enrichment laws of shale gas in the basin-margin transition zone of SE Chongqing, we analyzed the geological characteristics of shale gas reservoirs in the Nanchuan–Wulong area of this transition zone from the aspects of sedimentary formation, tectonic reworking and production characteristics by using geophysical, drilling, logging and testing data, and then we compared it with the overpressure shale gas reservoirs in the Jiaoshiba Block. Finally, we explored the main factors controlling the enrichment & high yields of normal-pressure shale gas in this transition zone and their hydrocarbon accumulation patterns. And the following research results were obtained. (1) Different from the over-pressure shale gas reservoirs in Jiaoshiba Block, the normal-pressure shale gas reservoirs in this transition zone are characterized by lower organic porosities, more developed micro-fractures, higher ratios of adsorbed gas, greater differences of stresses in two directions, lower geothermal gradients, lower formation pressure coefficients, higher initial fluid production rates and higher fluid flowback rates. (2) The enrichment & high yields of normal-pressure shale gas in this area is mainly controlled by three factors, i.e., carbon-rich, silicate-rich and graptolite-rich shale, organic pores, and tectonic stress field, among which, the first factor controlled by deepwater continental shelf facies is the basis of shale gas enrichment, the second is the main controlling factor of shale gas enrichment, and the third is the key factor of high-yield shale gas. (3) The hydrocarbon accumulation patterns of normal-pressure shale gas reservoirs in the transition zone can be divided into four types, including the anticline type, the syncline type, the slope type and the reverse fault type. And the enrichment & high-yield characteristics of shale gas in different hydrocarbon accumulation patterns are also clarified. In conclusion, the research results enrich the geological theory of enrichment & high-yield laws of normal-pressure shale gas and provide a support for the exploration and development of normal-pressure shale gas in complex structures.

As a non-destructive method, the proton nuclear magnetic resonance (1H NMR) technique with low echo time (TE, e.g., 0.07 ms) has been increasingly used for characterizing full pore size distribution (PSD) of shales. However, hydrogen contained in some components of the shale skeleton (e.g., kerogen and structural water) also can be detected by NMR in the case of low TE, resulting in a questionable PSD derived directly from the T2spectra of oil-saturated shale. In this study, eight shale samples with different organic and mineralogical components from the Jiyang Depression, China were investigated with regular NMR, low-temperature nitrogen adsorption (LTNA), NMR cryoporometry (NMRC), and mercury injection capillary pressure (MICP) techniques to propose a corrected NMR approach for characterizing shale PSD by considering the influence of the shale skeleton signals. The NMR relaxation characteristics (e.g., T2spectra and T1–T2map) of as-received shale, solvent-extracted and dried shale (EX), and oil-saturated shale (OS) were discussed to reveal the NMR response from the shale skeleton itself at T2below 1 ms on the T2spectra. With the new approach, the NMR T2spectra of oil occurring in the OS shale were first obtained through inversion of the differentiated T2decay curves between the T2decay curves of the EX shale and OS shale and were then converted to PSD by combination of LTNA, NMRC, and MICP results. For pores with T2less than 1 ms, the PSD obtained from NMR T2spectra of the oil signals only compared well with the results of LTNA and NMRC, with a relative error of less than 15% in pore volume. In contrast, the relative errors of PSD obtained directly from the NMR T2spectra of oil-saturated shales were up to 134%. It was found that the higher total organic carbon shale contained, the larger errors in the PSD profiles, pore volume, and porosity that were calculated directly from the oil-saturated shale’s NMR T2spectra. Compared with the traditional NMR methods, the corrected approach can provide a more accurate PSD for shales, especially for those organic-rich ones.

Shale oil has been found in the argillaceous dolomite reservoir of the Paleogene Xingouzui Formation in the Jianghan Basin. However, the shale oil storage mechanism in these rocks remains unclear, considering that increasing attention has been paid to shales instead of argillaceous dolomites. This article illustrated the microscopic pore structure and distribution of the argillaceous dolomite reservoir, discussed the porosity enhancement potential through dolomite mineral dissolution by organic acids, and indicated the contribution of the dolomite mineral dissolution pores to the porosity. Scanning electronic microscopy images show that the argillaceous dolomite reservoirs mainly contain inorganic pores, including intercrystalline pores, intergranular pores, and dissolution pores. However, organic pores are observed to be sporadically distributed. Nano-computed tomography data show that the pores of argillaceous dolomite vary in morphology and size and are unevenly spatially distributed. There are some isolated pores and unevenly distributed throats, among which larger throats are located in areas with well-developed pores. The pores of the shale reservoirs are mainly related to the dolomite mineral rather than other minerals. With increase in the dolomite mineral content, porosity and pore connectivity are improved, indicating that a high dolomite mineral content has greatly promoted both the porosity and permeability of the argillaceous dolomite reservoir in the study area. The organic acid experiment confirmed this conclusion that the porosity enhancement potential by dissolution reactions is notable when the dolomite mineral content in the samples is over 16%. The porosity enhancement through dolomite mineral dissolution ranges from 0.48 to 4.85%, with an average of 2.34%. Thus, dissolution pores are considered to be a significant reservoir space for shale oil storage in the argillaceous dolomite reservoir in the Paleogene Xingouzui Formation from the Jianghan Basin.

The spatial-temporal relationship between high-quality source rocks and reservoirs is a key factor when evaluating the formation, occurrence, and prospectivity of tight oil and gas reservoirs. In this study, we analyze the fundamental oil and gas accumulation processes occurring in the Songliao Basin, contrasting tight oil sand reservoirs in the south with tight gas sand reservoirs in the north. This is done using geochemical data, constant-rate and conventional mercury injection experiments, and fluid inclusion analyses. Our results demonstrate that as far as fluid mobility is concerned, the expulsion center coincides with the overpressure zone, and its boundary limits the occurrence of tight oil and gas accumulations. In addition, the lower permeability limit of high-quality reservoirs, controlled by pore-throat structures, is 0.1 × 10−3μm2in the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, and 0.05 × 10−3μm2in the Lower Cretaceous Shahezi Formation (K1sh) in the northern Songliao Basin. Furthermore, the results indicate that the formation of tight oil and gas reservoirs requires the densification of reservoirs prior to the main phase of hydrocarbon expulsion from the source rocks. Reservoir “sweet spots” develop at the intersection of high-quality source rocks (with high pore pressure) and reservoirs (with high permeability).

Dynamic capillary pressure (DCP) is the capillary pressure defined under transient flow condition during displacement, and it is vital for predicting two‐phase behavior in porous media. This article studies the effect of pore scale force and interfacial area by using captivating Lattice Boltzmann method based on a pseudo‐potential model developed for simulating incompressible multiphase flow in porous media. We analyze the relationship between pore scale forces and DCP based on the energy conservation law and define DCP as a function of energy rate of pressure and viscosity of each phase. We present two‐phase displacement simulations on a computed tomography (CT) image‐based porous model and analyze the effects of injection rate and wettability on DCP based on the proposed upscaling method, where the wettability is defined as the contact angle of the nonwetting phase. The primary results show that (1) the DCP curves are higher than that of the quasi‐static capillary pressure, and a higher injection rate leads to a larger DCP and a faster saturation change. (2) Significant effects of wettability on DCP and the DCP coefficients are observed, where the DCP coefficient is defined as the ratio of the difference between DCP and static capillary pressure over the rate of change of saturation. A larger contact angle results in a higher DCP and a lower change rate of saturation, and consequently induces a larger DCP coefficient. The average DCP coefficient is found to vary from 4.56 × 106to 3.55 × 105Pa· mswhen the nonwetting phase contact angle changes from 140° to 105° in the saturation range of 0.3 to 0.8. This study indicates that the proposed upscaling method is valid to investigate the DCP of two‐phase flow in sandstone. A novel upscaling method of dynamic capillary pressure is proposedRate dependent dynamic capillary pressure is observed based on 3‐D CT image‐based porous modelSignificant effects of wettability on the dynamic capillary pressure and the dynamic capillary pressure coefficient are observed

Free oil, rather than adsorbed oil, is potentially the most producible component of tight nanoporous shale reservoirs using existing technologies. To date, a variety of geochemical parameters, mainly related to the retention, migration, and expulsion of generated oil, have been developed to estimate the free oil in shale. However, there is still a lack of theoretical models accounting for the mechanism of oil accumulation in nanoporous shale, which would help evaluate adsorbed and free oil. In this paper, models were developed to estimate the amount of oil confined in nanoporous shale and that is mainly in adsorbed and free states to describe the characteristics of oil accumulation. The models were established for an adsorption saturation situation, and simultaneously considered the multilayer adsorption of an oil mixture and the microstructure of the shale pore system (including pore-throat-fracture). As a case study, adsorbed and free oil in lacustrine shales with different lithofacies, obtained from the Dongying sag of the southeastern Bohai Bay Basin of China, were evaluated using the models. Amounts of adsorbed and free oil obtained from the models agree well with those obtained from the previously established oil saturation index method. Microscopically, the amounts of adsorbed and free oil accumulating in slit-shaped pores were comprehensively impacted by the microstructure (size and volume) of pores and the state of the oil (densities and adsorption thickness). The models may be appropriate for single or mixed liquids confined in nanoporous shales, which develop a large number of slit-shaped pores (i.e., fracture) and few spherical pores with small dimension (such as < about 10 nm in this study), and can help target areas favorable for shale oil exploitation. This study provides significant insight into the microscopic mechanism of oil accumulation in nanoporous shale.