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Based on core observation, cast and fluorescent thin sections, FESEM and ESEM, coquina in Da'anzhai Member of Jurassic in Sichuan Basin were examined systematically. Together with production data and logging evaluation, a method for lacustrine coquina evaluation based on geological theory was established up. In the article, two aspects of the study were elaborated, characteristics of favorable reservoirs, and a "five‐step" evaluation method for favorable coquina reservoir. According to the correlation between porosity and production data, porosity is not effective in finding high quality coquina reservoir of this area. Whereas micro research of reservoir samples from a high productivity well revealed that sparry coquina is the best lithofacies, with the most developed micro storage space of various kinds. After the favorable reservoir was sorted out, a five‐step method evaluating the coquina reservoir was worked out. Correlation of GR value and rock types suggests that GR<30 API is an effective evaluation parameter in identifying profitable reservoir lithofacies. Meanwhile, the combination of profitable reservoir rock thickness and production data revealed that the reservoirs with the highest potentiality are those with thickness of 3–18 m. Fractures are more developed in faults, folds and structural noses in the study area. Organic acid is discharged massively before the peak of hydrocarbon generation, leading to the formation of dissolution pores in the reservoir. The evaluation of organic acid was made by using the source rock indexes. After evaluating the four factors, and compiling their distribution maps, the maps were overlapped to predict favorable reservoir zones, and 7 first class and 9 second class favorable zones of coquina were picked out. [ABSTRACT FROM AUTHOR]

Black shale deposits are usually regarded to be deposited in a relatively slack and deep water environment. The gravity flows that can greatly affect the shale depositional process are well documented in many marine basins, with much less attention paid to the counterpart in lacustrine settings. The Upper Triassic Chang 7 Member in the Ordos Basin, which contains thick black shale and well developed gravity flow deposits provides a good opportunity to investigate the influence of gravity flows on shale development in lacustrine settings. We integrate X-ray diffraction, thin section petrography analysis, major and trace element analysis, total organic carbon testing, electron microscopy, and energy spectrum analysis on shale to reveal such complicated process. Based on the development of silty laminas and thickness of the laminaset/bedding, we classified the Chang 7 shale into five lithofacies. Each lithofacies was unique in terms of laminar morphology, texture, and composition, indicating different depositional processes. Proxies of paleo-water depth, paleo-settling rate, paleo-productivity, paleo-redox, and clastic influx also revealed that these five lithofacies deposited in different depositional settings. We propose new depositional models to explain such heterogenous shale deposits and suggest the paleo-productivity has the strongest influence on the accumulation of organic matter. • Five lithofacies with eleven subtypes of laminas have been classified, which were deposited in gravity flow influenced lacustrine settings. • Different depositional models were proposed to detail the origin of 11 subtypes of laminas. • These models also explain how gravity flows influenced the deep-water deposition in different ways, resulting in various lithofacies of shale. • Paleo-productivity has the strongest influence on organic matter accumulation. [ABSTRACT FROM AUTHOR]

The paper takes the Upper Carboniferous Taiyuan shale in eastern uplift of Liaohe depression as an example to qualitatively and quantitatively characterize the transitional (coal-associated coastal swamp) shale reservoir. Focused Ion Beam Scanning Electron Microscope (FIB-SEM), nano-CT, helium pycnometry, high-pressure mercury intrusion and low-pressure gas (N 2 & CO 2 ) adsorption for eight shale samples were taken to investigate the pore structures. Four types of pores, i.e., organic matter (OM) pores, interparticle (InterP) pores, intraparticle (IntraP) pores and micro-fractures are identified in the shale reservoir. Among them, intraP pores and micro-fractures are the major pore types. Slit-shaped pores are the major shape in the pore system, and the connectivity of the pore-throat system is interpreted to be moderate, which is subordinate to marine shale. The porosity from three dimension (3D) reconstruction of SEM images is lower than the porosity of helium pycnometry, while the porosity trend of the above two methods is the same. Combination of mercury intrusion and gas absorption reveals that nanometer-scale pores provide the main storage space, accounting for 87.16% of the pore volume and 99.85% of the surface area. Micropores contribute 34.74% of the total pore volume and 74.92% of the total pore surface area; and mesopores account for 48.27% of the total pore volume and 24.93% of the total pore surface area; and macropores contribute 16.99% of the total pore volume and 0.15% of the total pore surface area. Pores with a diameter of less than 10 nm contribute the most to the pore volume and the surface area, accounting for 70.29% and 97.70%, respectively. Based on single factor analysis, clay minerals are positively related to the volume and surface area of micropores, mesopores and macropores, which finally control the free gas in pores and adsorbed gas content on surface area. Unlike marine shale, TOC contributes little to the development of micropores. Brittle minerals inhibit pore development of Taiyuan shale, which proves the influence of clay minerals in the pore system. [ABSTRACT FROM AUTHOR]

It is well known that the existing horizontal-well-drilling and hydraulic fracturing technology used to achieve large-scale, cost-effective production from immature to low–moderate-maturity continental shale in China, where the organic matter mainly exists in solid form, is fairly ineffective. To overcome the obstacles, in situ conversion technology seems feasible, while implementing it in the target layer along with estimating the amount of expected recoverable hydrocarbon in such shale formations seems difficult. This is because there are no guidelines for choosing the most appropriate method and selecting relevant key parameters for this purpose. Hence, based on thermal simulation experiments during the in situ conversion of crude oil from the Triassic Chang 73 Formation in the Ordos Basin and the Cretaceous Nenjiang Formation in the Songliao Basin, this deficiency in knowledge was addressed. First, relationships between the in situ-converted total organic carbon (TOC) content and the vitrinite reflectance (Ro) of the shales and between the residual oil volume and the hydrocarbon yield were established. Second, the yields of residual oil and in situ-converted hydrocarbon were measured, revealing their sensitivity to fluid pressure and crude oil density. In addition, a model was proposed to estimate the amount of in situ-converted hydrocarbon based on TOC, hydrocarbon generation potential, Ro, residual oil volume, fluid pressure, and crude oil density. Finally, a method was established to determine key parameters of the final hydrocarbon yield from immature to low–moderate-maturity organic material during in situ conversion in shales. Following the procedure outlined in this paper, the estimated recoverable in situ-converted oil in the shales of the Nenjiang Formation in the Songliao Basin was estimated to be approximately 292 × 108 tons, along with 18.5 × 1012 cubic meters of natural gas, in an area of approximately 8 × 104 square kilometers. Collectively, the method developed in this study is independent of the organic matter type and other geological and/or petrophysical properties of the formation and can be applied to other areas globally where there are no available in situ conversion thermal simulation experimental data. [ABSTRACT FROM AUTHOR]

To better determine the sweet spot in the vertical profile of the Longmaxi Formation, the shale heterogeneity was systematically investigated. A series of experiments were conducted on 40 shale samples collected from the Lower Silurian Longmaxi Formation in the Weiyuan shale gas field. The results indicated that total organic carbon (TOC), the mineral composition, methane adsorption capacity, and porosity of the four sub‐layers in the Longmaxi shale varied significantly. In terms of the TOC, the mid‐lower Long111 had the highest value, followed by Long113, while the TOC values of Long112 and Long114 were quite low. As for mineral composition, the mid‐lower Long111 had the highest quartz content, Long112 and Long113 had equivalent quartz, carbonate, and clay mineral contents, and Long114 had higher clay mineral and carbonate contents, but a lower quartz content. Shale porosity and methane adsorption capacity were the highest in the mid‐lower Long111, followed by Long113, Long112, Long114, and the upper Long111. The micro‐heterogeneity represented by the fractal dimension ranged from 2.590 to 2.750, with an average of 2.670. The mid‐lower Long111 had the largest fractal dimension, followed by Long113, Long112, Long114, and the upper part of Long111 had the smallest fractal dimension. The sedimentary environment controls the macro‐heterogeneity in the vertical profile. The micro‐heterogeneity depends on diagenesis, which can be investigated by the different effects of minerals on micropore development. The strong micro‐heterogeneity results in better preservation conditions for shale gas. The mid‐lower Long111 was rich in gas generation material (TOC) with enough storage space and is characterized by good preservation conditions, leading to the highest gas content of the four sub‐layers. In addition, the high brittle mineral content is conducive to fracturing and the formation of a fracture network. Thus, the middle ‐Long111 is the "sweet spot" in the vertical profile for the shale gas development. [ABSTRACT FROM AUTHOR]

Transitional shale is very different from marine shale with respect to mineral composition and pore structure. Insights into the effects of rock composition on pore structure can aid understanding of the storage and migration mechanisms of shale gas in a reservoir. To investigate the compositional effects on pore structure, a combination of geochemical and petrophysical experiments were conducted on four bulk shale samples and their corresponding extracted organic matter (OM) and clay mineral samples. The experimental results show that the removal of OM using H 2 O 2 during clay mineral extraction oxidizes and removes pyrite and siderite from the samples while other inorganic phases remain unaffected. OM hosted more abundant micropores compared with clay minerals, while mesopores and fine-macropores are dominant in clay minerals. Effects of the OM and clay minerals on pore volume and surface area are quantitatively evaluated on the basis of weight-normalized pore-size distribution (PSD) curves of extracted OM and clay mineral samples. In terms of the CO 2 adsorption, contribution from OM and clay minerals to micropore volume (MIV) are 19.43–32.92% and 18.75–39.05% respectively, and to micropore surface area (MIS) are 19.30–32.28% and 16.42–35.72%. Other minerals (other than organic matter and clay minerals) account for 34.29–48.93% of the MIV and 39.75–52.98% of the MIS. N 2 adsorption results reveal that the pore volume and surface area are mainly attributable to the clay minerals, providing 54.37–80.75% of the BJH pore volume (BJHV) (average 65.83%) and 70.68–87.04% of the BET surface area (BETS) (average 78.71%). The primary medium for pore development in marine shale is OM, whereas pores in the transitional shale are mostly found in the clay and other inorganic minerals. Therefore, the hydraulic fracturing design and drilling-related operations involved in the exploitation of transitional shale gas should be appropriately adjusted and improved in order to accommodate intrinsic characteristics of the transitional shale gas reservoir. • Organic matter(OM) and clay minerals were isolated from shale samples. • Pore size distribution of bulk, and corresponding OM and clay samples were tested. • Composition effects on pore structure were quantitatively calculated. [ABSTRACT FROM AUTHOR]

Abstract Low-field nuclear magnetic resonance (LF-NMR), high-speed centrifuge and low-pressure nitrogen adsorption (LPNA) experiments were conducted on shale samples from the Lower Silurian Longmaxi Formation to measure pore-throat parameters of the shale reservoir. We measured bound water saturation, helium porosity, bulk density, specific surface area, and pore-size distribution to evaluate reservoir quality. The thickness of the bound water film was calculated based on the equation established from these parameters, showing that its thickness ranges from 1.07 nm to 2.73 nm, with a mean of 1.72 nm. In addition, Grand Canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations were carried out to estimate the methane adsorption capacity and the number of the adsorbed layers in pores with different sizes at the given temperature and pressure (393.15 K, 65 MPa). The simulation results demonstrate that methane is unanimously adsorbed into pores <1.52 nm in diameter. Shale gas was present in both free and adsorbed states when the pore size was larger than 1.52 nm, and two layers were adsorbed on each pore wall. By combining the thicknesses of bound water film and adsorbed layers, the pore-throat lower limit for the shale gas reservoir was calculated to be about 4.96 nm. Highlights • Experiments and molecular simulation were used to determine the lower threshold of pore diameter in shale reservoir. • Based on NMR and LPNA experiments, the bound water film was determined to be 1.72 nm. • Reliable force field was adopted on both OM and illite during GCMC simulation to determine the methane adsorption layers. • The lower threshold pore diameter for shale reservoir was 4.96 nm. [ABSTRACT FROM AUTHOR]

Due to the large thickness and richness of organic matter in Longmaxi shale, southeastern Chongqing is considered as the most promising area for shale gas exploration and development and was a focus of numerous research interests in China. Characterization on the pore system of organic rich shale is significant for the reserve estimation and better understanding the production mechanism of shale gas plays. Shale composition, detected by X-ray diffraction, indicates that brittle minerals, especially quartz was the most prevalent component，with average contents of 41.72 wt.%. Pore types was classified by using a combination of argon-iron milling and field emission scanning electron microscopy (FESEM), and six types of pores were observed in rock images. High pressure mercury intrusion and low pressure N 2 adsorption were performed to extract the pore size distribution of Longmaxi shale. The results show that the nanopore was the major pore type in shale samples, which accounts for 95.6% of the pore volume. In the nanopore system, pore with diameters between 2 nm and 10 nm is the major component that contributes 76% of the total pore volume and 78% of the whole inner surface area. Furthermore, the dominant pore shape was interpreted from the adsorption-desorption hysteresis loop shape, and the typical slit-shaped pores were identified in the examined shale samples. Based on single factor analysis method, organic matter richness is the main controlling factor for the volume of nanopore and the specific surface area. No direct correlation between brittle minerals and nanopores, but high quartz and calcite content makes it much easier for the formation to generate natural fractures and to be hydraulically fractured. The study can inspire and guide shale gas exploration and exploitation southeastern Chongqing to some extent. [ABSTRACT FROM AUTHOR]

The Upper Carboniferous in northern Xinjiang, China was formed in a post-collisional depression and collapsed structural setting. Within the Upper Carboniferous, volcanic rocks and source rocks alternate over a wide region. At the end of the Carboniferous, these layers were uplifted by plate collisions and subsequently weathered and leached. Volcanic weathering and leaching led to the establishment of weathered crusts that can be divided into five layers. Corrosion and crumble zones in these layers form favorable reservoirs. Volcanic weathering crust formed in sub-aerially exposed paleogeomorphic areas; the five relatively continuous layers are generally preserved in paleogeomorphic lowland and slope regions, but the upper soil layer is usually absent in structurally higher parts of the rock record. The thickness of the weathered layer has a positive nonlinear exponential relationship to the duration of weathering and leaching, and the dynamic equilibrium time of weathered crust is about 36.3 Ma. The thickest weathered layer (∼450 m) is located in fracture zones. Weathered crusts are possible from a range of volcanic rocks with different lithologies, given sufficient time for weathering and leaching. The combination of volcanic weathered crust and source rocks results in three types of hydrocarbon accumulation models: (1) sequences of volcanic weathered crust interbedded with source rocks, (2) a quasi-layered weathered volcanic core located above source rocks, and (3) volcanic rocks associated with pectinate unconformities adjacent to source rocks. Each of these three types has the potential to form a giant stratigraphic reservoir of volcanic weathered crust. This knowledge has changed the traditional exploration model of searching for favorable lithologic and lithofacies zones in volcanic rocks, and has changed the viewpoint that the Carboniferous does not have the genetic potential to be the basement of the basin in northern Xinjiang. The concepts developed here are of great scientific significance and application for focusing oil and gas exploration on volcanic weathered crust. As such, the Paleozoic volcanic weathered crust in the midwestern part of China may possibly contain large-scale stratigraphic reservoirs and thus could be a new oil and gas exploration target in the future. [ABSTRACT FROM AUTHOR]

Chang 7 Shale, characterized by lacustrine black organic-rich shales and interbedded siltstones, has become a target for shale oil exploration and development in the Upper Triassic Ordos Basin, China. However, the heterogeneous enrichment of organic matter (OM) has led to controversy regarding source rock evaluation and difficulty in accurate prediction of favorable zones. Sequence stratigraphy, as a tool for prediction of sedimentary deposits has encountered challenges in lacustrine deep-water environments because of rapid facies changes and limited lateral continuity of key beds. In this study, a novel method is proposed to predict OM enrichment based on parasequences division and calibration of well logging and core lithology through analyses of thin sections and geochemical data from 238 core samples, as well as available well-logging data from a selected well. Chang 7 shales were simplified into three facies in terms of sedimentary structure and mineral composition, combining geological genesis with lateral correlation. Argillaceous laminated shale (Facies 2), with the highest average total organic carbon and S 1 + S 2 values, is the most favorable facies for shale oil exploration. The Chang 7 Member was divided into 15 parasequences and six parasequence sets, within one transgressive-regressive sequence. Depositional sequences have a significant effect on the enrichment of OM, given 1) the influence of lake-level fluctuations on OM accumulation, 2) the OM enrichment determined by shale facies, and 3) the distribution of shale facies controlled by p arasequences. In particular, the most favorable locations are the bases of parasequences (generally the lower third to half from the bottom) in the TST and early RST. The application of this method to a test well showed excellent performance based on verification from the organic geochemical data of 86 samples. Five favorable targets of Facies 2 were marked within fifteen favorable locations. By linking meter-level depositional sequences with centimeter-level OM enrichment, this study provides an alternative approach to determine the target area in a single well profile and realize isochronous inter-well prediction for deep-water shales. • Shale facies and organic matter enrichment has high degree correlation. • The favorable shale facies in the TST and early RST is controlled by parasequences. • The favorable locations are the lower third to half from the bottom of parasequences. • The favorable facies was distinguished by well-logging lithology identification. • An isochronous prediction method of organic matter enrichment was proposed. [ABSTRACT FROM AUTHOR]

The effects of petroleum retention within and expulsion from five intervals within the Triassic Chang 7 Member in the Ordos Basin in China have been demonstrated by deciphering a large suite of petrologic, organic petrographic, and organic geochemical analyses on 106 core samples. Organic properties and lithological heterogeneities control the amount and chemical composition of retained petroleum. Enrichment of aliphatic hydrocarbons in the silty, organic-lean intervals versus enrichment of aromatic fluids in the clayey, organic-rich units are probably caused by compositional fractionation occurred during primary and short-distance secondary migration. Migration of excess petroleum from organic-rich units to those organic-lean counterparts was further corroborated by the negative expulsion efficiencies calculated using a mass-balance model in the organic-lean intervals. Capillary pressure difference induced by the contrast in pore throat size of the clayey, organic-rich versus the silty, organic-lean intervals is postulated to be the major driver for the migration. A significant implication of this study is that the hydrocarbons in the first and fourth intervals constitute potential petroleum exploitation targets, given (i) improved oil quality caused by enriched aliphatic compounds versus viscous aromatic and polar compounds, (ii) lower organic matter sorption affinities, (iii) relatively high contents of brittle minerals in these two intervals. Despite its high content of retained hydrocarbons, the organic-rich fifth interval is not the best target, which is mainly due to the high sorption affinity of the organic matter structure, thereby causing low oil mobility and producibility. • The organic richness and lithological compositions control the amount and chemical composition of retained petroleum. • Primary migration leads to the fractionation of hydrocarbon compositions in organic-lean and organic-rich intervals. • Intervals with high oil saturation and negative expulsion efficiencies are potential petroleum exploitation targets. [ABSTRACT FROM AUTHOR]