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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 (δ 13 C 1 ) are stable and equal to the ratios of source gas (δ 13 C 0 1 ). 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 δ 13 C 1 becomes heavier. Finally, in stage IV, the desorbed gas remaining in the pore spaces diffuses out under the concentration difference, and the δ 13 C 1 becomes lighter again and finally stabilizes. In addition, a kinetic model for the quantitative description of isotope fractionation during desorption and diffusion was established.

The oil content in a produced fluid plays a crucial role in oil production engineering. In this paper, a predictive model for the oil and water proportions in produced fluid was established through nuclear magnetic resonance coupling displacement. This model successfully predicts the oil proportion in the produced fluid from each block within the Gaotaizi oil reservoir of the Songliao Basin and elucidates the reasons for its variation across different blocks. The production of pure oil in a vertical well area was attributed to the reservoir fluid exhibiting high bound water saturation, resulting in oil being the primary movable phase. In the testing and extended areas, variations in oil saturation combined with the pore size distribution governing oil and water occupancy are likely responsible for the differing oil-water ratios observed in the produced fluid. Specifically, a higher oil-to-water ratio (7:3) was produced in the testing area, while the extended area yielded a lower oil-to-water ratio (3:7). Furthermore, the model predicts an oil-to-water ratio of 4:6 for the produced fluid in the Fangxing area. To enhance oil production in the extended area, narrowing the fracture interval is proposed. However, this measure may not prove effective in other blocks.

In shale, liquid hydrocarbons are accumulated mainly in nanometer-scale pores or fractures, so the pore types and PSDs (pore size distributions) play a major role in the shale oil occurrence (free or absorbed state), amount of oil, and flow features. The pore types and PSDs of marine shale have been well studied; however, research on lacustrine shale is rare, especially for shale in the oil generation window, although lacustrine shale is deposited widely around the world. To investigate the relationship between nanometer-scale pores and oil occurrence in the lacustrine shale, 10 lacustrine shale core samples from Songliao Basin, NE China were analyzed. Analyses of these samples included geochemical measurements, SEM (scanning electron microscope) observations, low pressure CO2 and N2 adsorption, and high-pressure mercury injection experiments. Analysis results indicate that: (1) Pore types in the lacustrine shale include inter-matrix pores, intergranular pores, organic matter pores, and dissolution pores, and these pores are dominated by mesopores and micropores; (2) There is no apparent correlation between pore volumes and clay content, however, a weak negative correlation is present between total pore volume and carbonate content; (3) Pores in lacustrine shale are well developed when the organic matter maturity (Ro) is >1.0% and the pore volume is positively correlated with the TOC (total organic carbon) content. The statistical results suggest that oil in lacustrine shale mainly occurs in pores with diameters larger than 40 nm. However, more research is needed to determine whether this minimum pore diameter for oil occurrence in lacustrine shale is widely applicable.

The Lower Silurian Longmaxi Shale in Southeast Chongqing of Sichuan Basin in China is considered to be a potential shale gas reservoir by many scholars in recent years. The special shale gas well, namely, Pengye-1 well, was selected as a case study to evaluate the characteristics of the shale gas reservoir. A series of experiments were performed to analyze the geochemical, mineralogical, and petrophysical features and gas content using samples of the Longmaxi Shale from Pengye-1 well. The results show that the organic and inorganic porosities of these samples are range of 0.08-2.73% and 0.06-2.65%, with the average of 1.10% and 1.76%, respectively. The inorganic pores primarily contribute to the porosity until the TOC content is more than 3%. Organic matter plays an important role in adsorbed gas content. The adsorbed gas is dominant in the Longmaxi Shale of Pengye-1 well, which ranges from 0.46 to 2.24 cm3/g, with an average of 1.38 cm3/g. The free gas content ranges from 0.45 to 0.84 cm3/g with an average of 0.68 cm3/g, and is 24.4-49.7 percent of total gas with an average of 37.5%. The bottom part of the Longmaxi Shale is the most favorable for shale gas exploring, which is higher of brittleness mineral content, porosity and gas content. Compare with the other five shales in America, the Lower Silurian Longmaxi Shale is derived from older sedimentary periods with significantly higher thermal maturity and has experienced several periods of intense tectonic, which are unfavorable for the shale gas enrichment.

The specific surface area (SSA) is a crucial parameter for estimating the adsorption capacity of shale, significantly influencing its adsorption characteristics. The Brunauer-Emmett-Teller (BET) method was widely used to characterize the surface area of various porous materials. However, research on its applicability for characterizing shale surface areas, particularly concerning the adsorption mechanism of nitrogen in shale nanopores, remains limited. In this study, ultra-low-pressure nitrogen adsorption experiments and molecular simulation methods were employed to characterize the adsorption behavior of nitrogen on shale nanopore surfaces at 77 K. The results indicate that the assumptions of the classic BET isotherm model do not fully align with the state and microscopic mechanisms of nitrogen on shale surfaces. Nitrogen exhibits multilayer adsorption on shale surfaces represented by organic matter and Illite, but the initial pressure for multilayer adsorption varies with the rock phase surface. Calculating the specific surface area of organic matter in shale using the relative pressure range recommended by the classic BET theory results in a certain degree of error. Through analysis of isotherm adsorption curves, density field distributions, and intermolecular interactions, the adsorption mechanisms of nitrogen on shale pore surfaces were elucidated. It was found that for organic matter, a more suitable relative pressure range for BET calculations is 0.002–0.035, whereas for Illite, it is 0.035-0.2. This study provided crucial insights into the adsorption mechanisms of nitrogen on shale pore surfaces and the optimization of BET surface area characterization for shale nanopores, laying a theoretical foundation for predicting shale adsorption capacity and estimating in-situ natural gas in shale.

Organic pores serve as crucial storage spaces for shale gas, whose morphology and structure vary significantly among different types of organic matter, directly influencing the storage and seepage capacity of shale gas. The Upper Permian shale in the Western Hubei Trough formed in diverse sedimentary facies and has undergone multiple geological activities, resulting in strong heterogeneity of organic pores across different strata and regions. To figure out the heterogeneous characteristics of organic pores and the forming reason, the occurrence state of organic matter, pore morphology, and structural parameters (pore size, specific surface area, pore volume, and fractal dimension) of the Upper Permian shale in Western Hubei, have been discussed in detail, based on the data of field emission scanning electron microscopy and low-temperature nitrogen adsorption experiments conducted on the extracted organic matter. On this basis, fractal dimension theory was applied to discuss the heterogeneity of organic pores in different layers, and the reason for heterogeneity has been analyzed in detail. The results indicate that the occurrence mode of organic matter in different layers presents various characteristics: in the Gufeng Formation, the organic matters distribute primarily dispersed in flocculent state; at the bottom of Wujiaping Formation, they occur as isolated individuals, while the organic matters turn into discontinuous laminated distribution in the middle and upper Wujiaping Formation; in the Dalong Formation, the organic matters show continuous parallel banded distribution. Moreover, the morphology and structural parameters of organic pores exhibit obvious changes from the Gufeng Formation to the Dalong Formation: (a) the pore morphology shows the changed trend as extremely complex-simple-complex; (b) the specific surface area and pore volume follow the trend as large-small-large; (c) the pore size distribution displays in the pattern of bimodal-unimodal-bimodal; (d) the data of fractal dimension show the variation of high–low–high. Overall, the various sedimentary environments during the Upper Permian shale depositional period determined the differences in organic sources, which dominated the heterogeneity of organic pores in shale. These data clarify the development and variation characteristics of organic matter pores under different depositional environments, providing a theoretical basis for shale gas exploration and development during the transition from marine to marine–continental facies.

In this study, data obtained from the Lower Cretaceous McMurray Formation in the central Athabasca Oil Sands, northeastern Alberta, Canada, are examined and used to establish the architecture of stacked fluvial and estuarine tidal bar deposits. A total of 13 distinguishable facies (F1–F7, F8a–F8b, and F9–F13) corresponding to stacked fluvial and estuarine deposits are recognized. These facies are then reassembled into four facies associations: fluvial deposits, tidal flat, tidal bar complex, and tidal bar cap. Of these, the lower fluvial deposits show a highly eroded channel lag and tidal influences in the cross-stratified sand and wavy interbeds. The fluvial deposits pass upwards into upper tidal-dominated tidal flats and a massive homogeneous tidal sand bar complex. Very thick tidal-influenced facies (F8a–F8b, up to 22 m) caused by semi-diurnal and semi-lunar cycles are also observed in tidal flats. Based on studies of the facies and facies associations, a three-dimensional (3-D) architecture model is finally established and used to analyze the internal distribution of the stacked fluvial and estuarine deposits. This is the first time that a 3-D model of the paleo-estuary tidal bar has been constructed. The results of this study will assist future research analyzing the architecture of stacked fluvial and estuarine deposits.

The Tarim Basin harbors abundant deep to ultra-deep hydrocarbon resources, yet detailed oil-source correlation remains to be further investigated. As a potential key source rock, the organic geochemical characteristics of the Yuertus Formation (Є 1 y) warrant additional research. This study integrates biomarker, carbon, and sulfur isotope data from Є 1 y source rocks in existing wells and outcrops across the eastern, northern, and northwestern Tarim Basin to better constrain the distribution, hydrocarbon generation potential, biomarker features, and oil-source relations of Є 1 y. Results reveal that Є 1 y exhibits diverse lithofacies, including calcareous mudstones, siliceous shales, and shales as potential source rocks. The calcareous mudstone shows the highest total organic carbon (TOC) content (up to 29.8%), characterized by Type II kerogens and mature to over-mature thermal maturity. Stable biomarkers including triaromatic steroids (TAS), triaromatic dinoflagellate steroids (TDSI), and aryl isoprenoids (1-alkyl-2,3,6-trimethylbenzenes, ATMBs) reveal significant differences among the three lithological types of source rocks: Calcareous mudstones exhibit biomarker distribution patterns similar to those of classical Ordovician source rocks (C 26 R + C 27 S TAS < C 28 S TAS, TDSI < 0.6), while simultaneously containing high abundances of ATMBs characteristic of the Є 1 y. Siliceous rocks display typical Cambrian characteristics with low C 28 TAS, high TDSI, but absence of ATMBs. Shales present typical Cambrian features with low C 28 TAS, high TDSI, and low ATMBs. Oil-source correlation based on n- alkane’ carbon and sulfur isotopes suggests that calcareous shales are likely one of the primary sources for currently explored oils. These findings enrich the fundamental understanding of deep and ultra-deep hydrocarbon exploration in the Tarim Basin and provide new insights into the reassessment of oil-source relations.

Understanding the adsorption mechanisms of CO 2 and N 2 in illite, one of the main components of clay in shale, is important to improve the precision of the shale gas exploration and development. We investigated the adsorption mechanisms of CO 2 and N 2 in K-illite with varying pore sizes at the temperature of 333, 363 and 393 K over a broad range of pressures up to 30 MPa using the grand canonical Monte Carlo (GCMC) simulation method. The simulation system is proved to be reasonable and suitable through the discussion of the impact of cation dynamics and pore wall thickness. The simulation results of the excess adsorption amount, expressed per unit surface area of illite, is in general consistency with published experimental results. It is found that the sorption potential overlaps in micropores, leading to a decreasing excess adsorption amount with the increase of pore size at low pressure, and a reverse trend at high pressure. The excess adsorption amount increases with increasing pressure to a maximum and then decreases with further increase in the pressure, and the decreasing amount is found to increase with the increasing pore size. For pores with size greater larger than 2 nm, the overlap effect disappears.

Hydrocarbon resource potential evaluation represents the primary and core component of whole petroleum system studies. However, compared with the substantial progress achieved in understanding hydrocarbon generation mechanisms, quantitative assessments of hydrocarbon generation amounts from source rocks in the Songliao Basin remain relatively limited. Given that the genetic method is capable of comprehensively reflecting both the intrinsic hydrocarbon generation potential and conversion efficiency of source rocks and is supported by robust geological principles, this study was conducted within a genetic framework. Stratigraphic data and lithological descriptions from more than 2000 wells in the northern Songliao Basin, logging data from 387 wells, and measured basic geochemical data from 201 wells were integrated. Combined with the ΔlogR method, original hydrocarbon generation potential restoration techniques, and results from thermal simulation experiments, the planar distributions of key geochemical parameters of the first member of the Qingshankou Formation were systematically characterized. On this basis, the hydrocarbon generation potential and total hydrocarbon generation amounts of different structural units within the Songliao Basin were quantitatively evaluated. The results indicate that the cumulative hydrocarbon generation of the first member of the Qingshankou Formation reached approximately 506.55 × 108 t. Among the structural units, the Qijia–Gulong Sag contributed 266.13 × 108 t, the Sanzhao Sag 132.71 × 108 t, the Longhupao Terrace 66.81 × 108 t, and the Daqing Placanticline 40.90 × 108 t. These results demonstrate significant heterogeneity in hydrocarbon generation capacity among different structural units, with the Qijia–Gulong Sag identified as the most important hydrocarbon generation center in the study area. This study provides a critical quantitative foundation for whole petroleum system research in the northern Songliao Basin. It not only supplies essential data support for subsequent resource apportionment of conventional and shale hydrocarbons but also offers important constraints for analyses of reservoir-type distribution and hydrocarbon accumulation mechanisms.