Considering the complementarity of synchrotron radiation SAXS and nano-CT in the pore structure detection range, synchrotron radiation SAXS and nano-CT methods were combined to characterize the nano- to micro-pore structure of two bituminous coal samples. In mesopores, the pore size distribution curves exhibit unimodal distribution and the average pore diameters are similar due to the affinity of metamorphic grades of the two samples. In macropores, the sample with higher mineral matter content, especially clay mineral content, has a much higher number of pores. The fractal dimensions representing the pore surface irregularity and the pore structure heterogeneity were also characterized by synchrotron radiation SAXS and nano-CT. The fractal dimensions estimated by both methods for different pore sizes show consistency and the sample with smaller average pore diameters has a more complex pore structure within the full tested range.

Petrophysics of coals directly affects the development of coalbed methane (CBM). Based on the analysis of the representative academic works at home and abroad, the recent progress on petrophysics characteristics was reviewed from the aspects of the scale-span pore-fracture structure, permeability, reservoir heterogeneity, and its controlling factors. The results showed that the characterization of pore-fracture has gone through three stages: qualitative and semiquantitative evaluation of pore-fracture by various techniques, quantitatively refined characterization of pore-fracture by integrating multiple methods including nuclear magnetic resonance analysis, liquid nitrogen, and mercury intrusion, and advanced quantitative characterization methods of pore-fracture by high-precision experimental instruments (focused-ion beam-scanning electron microscopy, small-angle neutron scattering and computed tomography scanner) and testing methods (m-CT scanning and X-ray diffraction). The effects of acoustic field can promote the diffusion of CBM and generally increase the permeability of coal reservoirs by more than 10%. For the controlling factors of reservoir petrophysics, tectonic stress is the most crucial factor in determining permeability, while the heterogeneity of CBM reservoirs increases with the enhancement of the tectonic deformation and stress field. The study on lithology heterogeneity of deep and high-dip coal measures, the spatial storage-seepage characteristics with deep CBM reservoirs, and the optimizing production between coal measures should be the leading research directions.

Most coal reservoirs show high gas content with relatively low desorption efficiency, which restricts the efficiency of coalbed methane (CBM) extraction and single-well productivity. This review highlights the desorption hysteresis mechanism and its controlling factors as well as methods and models to reveal desorption hysteresis and potential solutions. Methane adsorption and desorption can be recorded by both gravimetric and volumetric experiments. Although different adsorption models are used, desorption is generally considered with the Langmuir model. Desorption hysteresis is influenced by the petrophysical composition, thermal maturity, pore structure distribution of the coal, reservoir temperature, and moisture and water content. Methods for calculating desorption hysteresis include the area index, hysteresis index and introduction of a hysteresis factor and a hysteresis coefficient. Molecular dynamics simulations of methane desorption are mainly based on theories of kinetics, thermodynamics, and potential energy. The interaction forces operating among coal, water, and methane molecules can be calculated from microscopic intermolecular forces (van der Waals forces). The desorption hysteresis mechanism and desorption process still lack quantitative probe methodologies, and future research should focus on coal wettability under the constraints of liquid content, potential energy adjustment mechanism, and quantitative analysis of methane desorption rates. Further research is expected to reveal the desorption kinetics of methane through the use of the solid–liquid–gas three-phase coupling theory associated with the quantitative analysis of methane desorption hysteresis, thereby enhancing the recovery rate and efficiency of CBM wells.

Studying on the pore size distribution of coal is vital for determining reasonable coalbed methane development strategies. The coalbed methane project is in progress in the southern Junggar Basin of northwestern China, where high volatile bituminous coal is reserved. In this study, with the purpose of accurately characterizing the full-scale pore size distribution of the high volatile bituminous coal of the southern Junggar Basin, two grouped coal samples were applied for mercury intrusion porosimetry, low-temperature nitrogen adsorption, low-field nuclear magnetic resonance, rate-controlled mercury penetration, scanning electron microscopy, and nano-CT measurements. A comprehensive pore size distribution was proposed by combining the corrected mercury intrusion porosimetry data and low-temperature nitrogen adsorption data. The relationship between transverse relaxation time (T₂, ms) and the pore diameter was determined by comparing the T₂ spectrum with the comprehensive pore size distribution. The macro-pore and throat size distributions derived from nano-CT and rate-controlled mercury penetration were distinguishingly analyzed. The results showed that: 1) comprehensive pore size distribution analysis can be regarded as an accurate method to characterize the pore size distribution of high volatile bituminous coal; 2) for the high volatile bituminous coal of the southern Junggar Basin, the meso-pore volume was the greatest, followed by the transition pore volume or macro-pore volume, and the micro-pore volume was the lowest; 3) the relationship between T₂ and the pore diameter varied for different samples, even for samples with close maturities; 4) the throat size distribution derived from nano-CT was close to that derived from rate-controlled mercury penetration, while the macro-pore size distributions derived from those two methods were very different. This work can deepen the knowledge of the pore size distribution characterization techniques of coal and provide new insight for accurate pore size distribution characterization of high volatile bituminous coal.

The Middle Jurassic Xishanyao Formation in the central section of the southern Junggar Basin has substantial amounts of low-ranked coalbed methane (CBM) recourses and is typically characterized by multi superimposed coal seams. To establish the CBM enrichment model, a series of experimental and testing methods were adopted, including coal maceral observation, pro-ximate analysis, low temperature nitrogen adsorption (LTNA), methane carbon isotope determination, porosity/permeability simulation caused by overburden, and gas content testing. The controlling effect of sedimentary environment, geological tectonic, and hydrogeological condition on gas content was analyzed in detail. The results demonstrate that the areas with higher gas content (an average of 8.57 m³/t) are mainly located in the Urumqi River-Santun River (eastern study area), whereas gas content (an average of 3.92 m³/t) in the Manasi River-Taxi River (western study area) is relatively low. Because of the combined effects of strata temperature and pressure, the gas content in coal seam first increases and then decreases with increasing buried depth, and the critical depth of the inflection point ranges from 600 m to 850 m. Affected by the changes in topography and water head height, the direction of groundwater migration is predicted from south to north and from west to east. Based on the gas content variation, the lower and middle parts of the Xishanyao Formation can be divided into three independent coal-bearing gas systems. Within a single gas-bearing system, there is a positive correlation between gas content and strata pressure, and the key mudstone layers separating each gas-bearing system are usually developed at the end of each highstand system tract. The new CBM accumulation model of the multi-coals mixed genetic gas shows that both biological and thermal origins are found in a buried depth interval between 600 m and 850 m, suggesting that the coals with those depths are the CBM enrichment horizons and favorable exploration regions in the middle section of the southern Junggar Basin. An in-depth discussion of the low-rank CBM enrichment model with multi-coal seams in the study region can provide a basis for the optimization of CBM well locations and favorable exploration horizons.

This study carries out a simulated experiment of biogenic gas generation and studies the effects of gas generation on the pore structure and molecular structure of anthracite by mercury intrusion porosimetry, X-ray diffraction (XRD) and Fourier transform infrared spectroscopy (FT-IR). The results show that methanogenic bacteria can produce biogenic gas from anthracite. CO₂ and CH₄ are the main components of the generated biogas. After generation, some micropores (<10 nm) and transitional pores (10–100 nm) in the coal samples transform into large pores. In the high-pressure stage (pressure>100 MPa) of the mercury intrusion test, the specific surface area decreases by 19.79% compared with that of raw coal, and the pore volume increases by 7.25% in total. Microbial action on the molecular structure causes changes in the pore reconstruction. The FT-IR data show that the side chains and hydroxyl groups of the coal molecular structure in coal are easily metabolized by methanogenic bacteria and partially oxidized to form carboxylic acids. In addition, based on the XRD data, the aromatic lamellar structure in the coal is changed by microorganisms; it decreases in lateral size (La) and stacking thickness (Lc). This study enriches the theory of biogenic coalbed gas generation and provides a pathway for enhancing the permeability of high-rank coal reservoirs.

CO₂ enhanced shale gas recovery (CO₂-ESGR) has attracted extensive attention as it can improve the shale gas recovery efficiency and sequestrate CO₂ simultaneously. In this study, the relationship between mineral composition, pore structure, CH₄ and CO₂ adsorption behavior as well as selective adsorption coefficient of CO₂ over CH₄ ({\alpha }_{{CO}_2/{CH}_4}) in marine and continental shales at different temperatures was investigated. The results illustrated that shale with higher total organic carbon (TOC), higher clay minerals and lower brittle mineral contents has a larger micropores and mesopores volume and specific surface area. TOC content was positively correlated with fractal dimension D_f. Both CH₄ and CO₂ adsorption capacity in shale have positive correlations with TOC and clay mineral content. CO₂ adsorption capacity of the all the tested shale samples were greater than CH₄, and the {\alpha }_{{CO}_2/{CH}_4} of shale were larger than 1.00, which indicated that using CO₂-ESGR technology to improve the gas recovery is feasible in these shale gas reservoirs. A higher TOC content and in shale corresponding to a lower {\alpha }_{{CO}_2/{CH}_4} due to the organic matters show stronger affinity on CH₄ than that on CO₂. Shale with a higher brittle mineral content corresponding to a higher {\alpha }_{{CO}_2/{CH}_4}, and no obvious correlation between {\alpha }_{{CO}_2/{CH}_4} and clay mineral content in shale was observed due to the complexity of the clay minerals. The {\alpha }_{{CO}_2/{CH}_4} of shale were decreased with increasing temperature for most cases, which indicated that a lower temperature is more favorable for the application of CO₂-ESGR technique.

Adsorbed gas content is an important parameter in shale gas reservoir evaluations, and its common calculation method is based on core experiments. However, in different areas, the correlations between the adsorbed gas content and well logging data might differ. Therefore, a model developed for one specific area cannot be considered universal. Based on previous studies, we studied the relationships between temperature, TOC, organic matter maturity and adsorbed gas content and revealed qualitative equations between these parameters. Then, the equations were combined to establish a new adsorbed gas content calculation model based on depth and total organic carbon (TOC). This model can be used to estimate the adsorbed gas content using only conventional well logging data when core experimental data are rare or even unavailable. The method was applied in the southern Sichuan Basin, and the adsorbed gas content results agree well with those calculated using the Langmuir isothermal model and core experimental data. The actual data processing results show that the adsorbed gas content model is reliable.

The lower Cambrian Niutitang Formation is of crucial importance for shale gas target reservoirs in western Hubei, China; however, little work has been done in this field, and its shale gas accumulation and enrichment mechanism are still unclear. Based on survey wells, outcrop data, and large numbers of tests, the geological conditions of shale gas accumulation were studied; moreover, the factors that influence the gas content were thoroughly discussed. The results show that the Niutitang Formation (Є₁n) can be divided into three sections: the first section (Є₁n¹), the second section (Є₁n²), and the third section (Є₁n³). The Є₁n² is the main shale gas reservoir. The deep shelf facies is the main sedimentary facies and can be divided into three main lithofacies: argillaceous siltstone, carbonaceous shale and carbonaceous siliceous rock. The total organic carbon (TOC) content shows gentle growth trends until bottom of the Є₁n² and then decreases rapidly within the Є₁n¹, and the TOC content mainly ranges from 2% to 4% horizontally. The calcite and dolomite dissolution pores, clay intergranular pores and organic pores are the main pore types and the micropore types are clearly related to the mineral compositions and the TOC content. Vertically, the gas content is mainly affected by the TOC content. Horizontally, wells with high gas contents are distributed only southeast of the Huangling anticline, and the combination of structural styles, fault and fracture development, and the distribution of the regional unconformity boundary between the upper Sinian Dengying Formation (Z₂d) and the Є₁n² are the three most important factors affecting the gas content. The favorable areas must meet the following conditions: a deep shelf environment, the presence of the Є₁n¹, wide and gentle folds, far from large normal faults that are more than 5 km, moderate thermal evolution, and greater than 500 m burial depth; this includes the block with the YD2–ZD2 wells, and the block with the Y1 and YD4 wells, which are distributed in the southern portion of the Huangling anticline and northern portion of the Xiannvshan fault.

Pyrite is one of the important components of shale and plays a crucial role in shale gas enrichment. However, currently there are just a few studies on this subject matter. Therefore, the characteristics of pyrite in organic-rich shale section of the Longmaxi Formation and its impact on shale gas enrichment was studied in this paper by using outcrops, drilling cores, thin sections and test data. Result shows that pyrite occurred in different forms (macro-micro scale) in the Longmaxi Formation in the southeast Sichuan Basin. The formation and content of pyrite has a close relation with TOC content. Pyrite may catalyze the hydrocarbon generation of organic matter. Interparticle pores within the pyrite framboids and organic matter pores in the pyrite-organic matter complex are well-developed in the Longmaxi Shale, which serves as a major reservoir space for shale gas. Pyrite can promote shale gas enrichment by absorbing shale gas on its surface and preserving free gas in the interparticle pores and organic matter pores. In addition, as a kind of brittle mineral, pyrite can improve the brittleness of shale reservoir and increase the micro-nano pore system in shale reservoir, thereby improving the transmission performance of shale reservoir and boosting shale gas recovery.

The study and exploration practice of shale gas accumulation has focused on the static system comparison, key parameters analysis, reservoir characteristics, enrichment mode etc. However, the research on dynamic recovery from the original hydrocarbon generation of shale gas to the present gas reservoir is still lacking. The burial history of shale gas reservoir can reflect the overall dynamic process of early formation and later transformation of shale gas reservoir. It controls the material basis of shale gas, the quality of reservoir physical properties, preservation conditions, gas content and formation energy, which is the core and foundation of shale gas accumulation process research. Herein, based on the five typical wells data in the Northeast Yunnan, including geochronological data, measured R_o values, core description records, well temperature data, paleoenvironment, paleothermal, etc., the burial history, thermal evolution history and hydrocarbon generation history of the Lower Silurian Longmaxi Formation were systematically restored via back stripping method and EASY%R_o model. The results show that 1) the differences in the burial history of marine shale in Longmaxi Formation can be divided into syncline type and anticline type. 2) The shale gas accumulation process can be divided into four stages, namely the source-reservoir-cap sedimentation period, initial accumulation period, main accumulation period, and adjustment period. 3) Based on the characteristics of burial history and preservation conditions, the areas with wide and gentle anticline, far away from the denudation area, and buried deeply with good fault sealing ability are priority structural locations for the shale gas exploration in northeast Yunnan.

Marine-continental transitional shale is a potential energy component in China and is expected to be a realistic field in terms of increasing reserves and enhancing the natural gas production. However, the complex lithology, constantly changing depositional environment and lithofacies make the quantitative determination of the total organic carbon (TOC) suitable for marine shales not necessarily applicable to transitional shales. Thus, the identification of marine-continental transitional organic-rich shales and the mechanism of organic matter enrichment need to be further studied. As a typical representative of transitional shale, samples from Well MY-1 in the Taiyuan Formation in the southern North China Basin, were selected for TOC prediction using a combination of experimental organic geochemical data and well logging data including natural gamma-ray (GR), density (DEN), acoustic (AC), neutron (CNL) and U spectral gamma-ray (U), and TH spectral gamma-ray (TH). The correlation coefficient, coefficient of determination, standard deviation, mean squared error (MSE) and root mean squared error (RMSE) were selected to conduct the error analysis of the evaluation of different well log-based prediction methods, involving U spectral gamma logging, ΔlogR, and multivariate fitting methods to obtain the optimal TOC prediction method for the Taiyuan transitional shale. The plots of TOC versus the remaining volatile hydrocarbon content and the generation potential from Rock Eval show good to excellent potentials for hydrocarbon generation. The integrated results obtained from the various log-based TOC estimation methods indicate that, the multivariate fitting method of GR-U-DEN-CNL combination is preferable, with the correlation coefficients of 0.78 and 0.97 for the entire and objective interval of the Taiyuan Formation respectively, and with the minimum MSE and RMSE values. Specifically, the U spectral gamma logging method based on single logging parameter is also a better choice for TOC prediction of the high-quality intervals. This study provides a reference for the exploration and development of unconventional shale gas such as transitional shale gas.

Due to discrepancies in pore structure, the productivity of shale gas reservoirs under different diagenesis stages varies greatly. This study discussed the controlling of sedimentation and diagenesis on shale pore structure in typical marine, transitional, and continental shales, respectively. Continental shale samples from the Shuinan Formation, Jiaolai Basin, transitional shale samples from the Taiyuan, Shanxi and Xiashihezi Formations, Ordos Basin, and marine shale samples from the Longmaxi Formation, Sichuan Basin, were collected. Scanning electron microscope with argon ion polishing, high-pressure mercury injection, and low-temperature nitrogen adsorption experiments were conducted to acquire pore structure parameters. And the diagenetic stage of the reservoir was classified according to thermal maturity, organic geochemical parameters, and mineral composition. Our results exhibit that continental, transitional, and marine shales are period A, period B of the middle diagenetic stage, and the late diagenetic stage, respectively. For pore structure, micropore (0–2 nm) and mesopore (2–50 nm) controlled pore volume and specific surface area of transitional and marine shales, and specific surface area of continental shale have similar results, while micropore, mesopore, and macropore (>50 nm) all have a significant proportion of pore volume in continental shale. The pore structure characteristics and controlling factors exhibit a pronounced difference in different diagenesis stages, the compaction and cementation in period A of the middle diagenesis stage is relatively weak, intergranular pore and interlayer pore of clay minerals are well preserved, and moldic pore and dissolved pore developed as well; organic matter is in high maturity in period B of the middle diagenesis stage, organic matter pore developed correspondingly, while the intergranular pore developed poorly affected by compaction, notably, the carbonate is negligible in transitional shale, and the interlayer pore of clay minerals are well preserved with weak cementation; while dissolution and metasomatism controlled the pore structure in the late diagenesis stage in marine shale, the primary pores were poorly preserved, and the organic matter pore and carbonate dissolved pore developed. Results from this work are of a specific reference for shale gas development under different diagenesis stages.

To quantitatively characterize the horizontal shale gas well productivity and identify the dominant productivity factors in the Weiyuan Shale Gas Field, Sichuan Basin, a practical productivity method involving multiple indicators was proposed to analyze the production performance of 150 horizontal wells. The normalized test production, flowback ratio, first-year initial production and estimated/expected ultimate recovery (EUR) were introduced to estimate the well productivity in different production stages. The correlation between these four indicators was determined to reveal their effects on production performance forecasts. In addition, the dominant productivity factors in the present stage were identified to provide guidance for production performance enhancement. Research indicates that favorable linear relations exist between the normalized test production, first-year initial production and EUR. The normalized test production is regarded as an important indicator to preliminarily characterize the well productivity in the initial stage. The first-year initial production is the most accurate productivity evaluation indicator after a year. The flowback ratio is a supplementary indicator that qualitatively represents the well productivity and fracturing performance. The well productivity is greatly dependent on the lateral target interval, drilling length of Longmaxi1₁¹ (LM1₁¹) and wellbore integrity. The first-year recovery degree of EUR is 24%–58% with a P50 value of 35%.

Shale gas is a relatively clean-burning fossil fuel, produced by hydraulic fracturing. This technology may be harmful to the environment; therefore, environmentally friendly methods to extract shale gas have attracted considerable attention from researchers. Unlike previous studies, this study is a comprehensive investigation that uses systematic analyses and detailed field data. The environmental challenges associated with shale gas extraction, as well as measures to mitigate environmental impacts from the source to end point are detailed, using data and experience from China’s shale gas production sites. Environmental concerns are among the biggest challenges in practice, mainly including seasonal water shortages, requisition of primary farmland, leakage of drilling fluid and infiltration of flowback fluid, oil-based drill cuttings getting buried underground, and induced seismicity. China’s shale gas companies have attempted to improve methods, as well as invent new materials and devices to implement cleaner processes for the sake of protecting the environment. Through more than 10-year summary, China’s clean production model for shale gas focuses on source pollution prevention, process control, and end treatment, which yield significant results in terms of resource as well as environmental protection, and can have practical implications for shale gas production in other countries, that can be duplicated elsewhere.

Lacustrine shale oil resources in China are abundant, with remarkable exploration breakthroughs being achieved. Compared to marine shale oil in North America, efficient exploration of lacustrine shale oil is more difficult; thus, selecting favorable layer and optimization zone for horizontal wells is more important. In this study, based on systematic coring of approximately 500 m fine-grained deposits of the Kong 2 Member, combining laboratory tests and log data, source rock geochemistry and reservoir physical properties, the favorable rock fabric facies for oil accumulation was analyzed and classified. First, the dominant lithologic facies, organic facies, and bed combination facies were determined based on mineral composition from logging, total organic content (TOC), and sedimentary structure. Secondly, 10 fabric facies were classified by combining these three facies, with 4 fabric facies were found to have high TOC content, high total hydrocarbon, and strong fluorescence features, indicating good shale oil enrichment. Thirdly, the distribution of the upon good fabric facies was identified to be located at the top of the Kong 2 Member, with evidences of seismic resistivity inversion, thermal maturity, structure depth, and strata thickness. And the favorable facies were found to be stably distributed lateral at the area of about 100 km². High oil flow has been detected at this layer within this area by several wells, including horizontal wells. The exploratory study of fabric facies classification and evaluation provides a new research idea for lacustrine shale oil exploration and effectively promotes breakthroughs in lacustrine shale oil exploration in Bohai Bay Basin.

The phase state of shale oil has a significant impact on its mobility. The mineral and organic matter in shale reservoirs play an important role in oil phase. This study attempts to evaluate the properties of shale oils in different phase states and to investigate how these differences are related to initial shale composition. Samples from the first member of the Qingshankou (Q1) Formation were analyzed using X-ray diffraction, total organic carbon content, rock pyrolysis solvent extraction and group component separation. Subsequently, fluorescence techniques were used to quantitatively determine the content and properties of the free oil (FO), the adsorbed oil associated with carbonate (ACO), and the adsorbed oil associated with silicate and clay-organic complexes (AKO). The results showed that non-hydrocarbons and asphaltenes are the primary fluorescing compounds on shale grain. FO is the dominant phase in the Q1 Formation. The quantitative grain fluorescence on extraction (QGF-E) and total scanning fluorescence (TSF) spectra of ACO and AKO show a significant redshift compared to the FO. The TSF spectra of FO have a characteristic skew to the left and a single peak distribution, suggesting a relatively light hydrocarbon component. The TSF spectra of ACO show a skew to the right and an even, double-peaked distribution. The TSF spectra of AKO show a single peak with a skew to the right, indicating that ACO and AKO hydrocarbons are heavier than FO hydrocarbons. In summary, enrichment of carbonate minerals in shale may result in mis-identification of “sweet spots” when using QGF. The normalized fluorescence intensity of QGF-E and TSF are effective indexes allowing oil content evaluation. As an additional complicating factor, hydrocarbon fractionation occurs during generation and expulsion, leading to a differentiation of oil composition. And FO has high relatively light hydrocarbon content and the strongest fluidity.

Gas and water distribution is discontinuous in tight gas reservoirs, and a quantitative understanding of the factors controlling the scale and distribution of effective reservoirs is important for natural gas exploration. We used geological and geophysical explanation results, dynamic and static well test data, interference well test and static pressure test to calculate the distribution and characteristics of tight gas reservoirs in the H₈ Member of the Shihezi Formation, Sulige gas field, Ordos Basin, northwest China. Our evaluation system examines the scale, physical properties, gas-bearing properties, and other reservoir features, and results in classification of effective reservoirs into types I, II, and III that differ greatly in size, porosity, permeability, and saturation. The average thickness, length, and width of type I effective reservoirs are 2.89, 808, and 598 m, respectively, and the porosity is>10.0%, permeability is>10 × 10^–3µm², and average gas saturation is>60%. Compared with conventional gas reservoirs, tight gas effective reservoirs are small-scale and have low gas saturation. Our results show that the scale of the sedimentary system controls the size of the dominant microfacies in which tight gas effective reservoirs form. The presence of different types of interbeds hinders the connectivity of effective sand body reservoirs. The gas source conditions and pore characteristics of the reservoirs control sand body gas filling and reservoir formation. The physical properties and structural nature of the reservoirs control gas–water separation and the gas contents of effective reservoirs. The results are beneficial for the understanding of gas reservoir distribution in the whole Ordos Basin and other similar basins worldwide.

Tight sandstone reservoirs are generally characterized by complex reservoir quality, non-Darcy flow, and strong heterogeneity. Approaches utilized for evaluating physical property cutoffs of conventional reservoirs maybe inapplicable. Thus, a comprehensive investigation on physical property cutoffs of tight sandstone reservoirs is crucial for the reserve evaluation and successful exploration. In this study, a set of evaluation approaches take advantage of field operations (i.e., core drilling, oil testing, and wireline well logging data), and simulation experiments (i.e., high-pressure mercury injection-capillary pressure (MICP) experiment, oil-water relative permeability experiment, nuclear magnetic resonance (NMR) experiment, and biaxial pressure simulation experiment) were comparatively optimized to determine the physical property cutoffs of effective reservoirs in the Upper Triassic Chang 6, Chang 8 and Chang 9 oil layers of the Zhenjing Block. The results show that the porosity cutoffs of the Chang 6, Chang 8, and Chang 9 oil layers are 7.9%, 6.4%, and 8.6%, and the corresponding permeability are 0.08 mD, 0.05 mD, and 0.09 mD, respectively. Coupled with wireline well logging, mud logging, and oil testing, the cut-off of the thickness of single-layer effective reservoirs are approximately 3.0 m, 3.0 m, and 2.0 m, respectively. Depending on the cutoffs of critical properties, a superimposed map showing the planar distribution of the prospective targets can be mapped, which may delineate the effective boundary of prospective targets for petroleum exploration of tight sandstone reservoirs.