The Bayan Gobi Formation is an important Early Cretaceous dinosaur fossil-bearing horizon, although the number of known dinosaur taxa remains relatively limited. Here, a new dinosaur material, primarily comprising proximal caudal vertebrae, is reported from the Bayan Gobi Formation. The specimen marks the first published dinosaur record from the Bayan Gobi Formation in the western Yin'gen-Ejinaqi Basin, further extending the geographical range of dinosaur fossils in this horizon. The specimen was discovered at a depth of 473.2m in a drill core and displays several features indicative of its ornithischian affinity: slender, distally tapering transverse processes near the neurocentral suture, positioned well below the level of the zygapophyses, and slender ossified tendons on the dorsal side of the neural arch. The proportions among the caudal vertebral elements closely resemble those of Psittacosaurus, and principal component analysis based on geometric morphometrics supports this similarity. However, given the limited material available, assignment to a specific genus or species remains uncertain. Notably, the dorsolateral surface of the 2nd to 4th caudal centra shows regularly arranged nutrient foramina, a feature not previously reported in other ornithischians, thereby providing new morphological data for dinosaurs from the Bayan Gobi Formation. However, since the new specimen may represent an immature individual and the available material is limited, it is difficult to determine whether this feature reflects interspecific, interindividual, or ontogenetic variation.

The Benbatu sandstone-type uranium deposit is in the southeast part of the Bayingobi basin. This study examines the geological characteristics, geochemistry, C-O isotopes, micro area scanning, and fluid inclusions in the orebearing sandstones of the Benbatu uranium deposit. It classifies the alteration mineral combination, defines the stage of uranium mineralization and establishes both the mineralization laws and the uranium mineralization model. The favorable stratigraphic structure of the Lower Cretaceous lower member of the Bayingobi Formation (falling stage system tract), 1st and 2nd members of the upper Bayingobi Formation (lowstand + transgressive system tract) laid a foundation for migrating the ore-forming fluids along faults and the inflation of supergene fluids into the basin. The uranium mineralization period can be divided into two stages. The early alteration mineral combinations primarily include hematite, calcite, automorphic dolomite, automorphic fluorapatite, and pyrite. The late stage of mineralization includes limonite, fine-grained dolomite, fine-grained fluorapatite, pyrite, calcite, and illite. The early ore-forming fluids with the faults mainly originated from the deep part of the basin, with temperatures of 105-165 degrees C and salinity levels of 5 %-9%. In the late stage of mineralization, the oreforming fluid is primarily epigenetic fluid, with a temperature of 60-105 degrees C and a salinity of 1.5 %-5%. The temperature and salinity of the ore-forming fluids have the characteristic of gradually evolving from high to low from the early to late stages of mineralization. The ore has undergone significant water and rock interaction, where uranium, lithophile, chalcophile, and rare earth elements were substitute the elements in the fine crystalline fluorapatite or adsorbed on its surface by fine-crystalline fluorapatite during the mineralization process. The U content of ore is negatively correlated with SiO2, Al2O3, K2O, and NaO content and positively correlated with other elements (P, Sr, Ca, and Fe2+).

At present, researchers are committed to studying new intelligent response materials to deal with severe water pollution problems. Using PU sponge as the substrate, dopamine was first modified to construct a rough surface while introducing active groups. The monomer N-isopropylacrylamide (NIPAM) and itaconic acid (IA) were grafted and polymerized onto the polydopamine coating on the sponge surface by vinyltrimethoxysilane (VTMS). The obtained DINA-PU sponge has good temperature response and switchable wettability characteristics, and has good adsorption-desorption cycle function. Moreover, a micro-filtration device was designed to separate heavy (light) oil-water mixtures. The separation efficiency can reach more than 95 % and 99 % for heavy and light oil water, respectively. In addition, the adsorption capacity of the material for methylene blue (MB) can reach 660 mg center dot g- 1 . The separation efficiency in the oil-water separation-dye adsorption integrated separation experi- ment can reach more than 99 %.

The Talhar Shale (early Cretaceous), a key member of the Lower Goru Formation, is notably thick (averaging 70 m) and extensively found throughout the Lower Indus Basin (LIB). Despite its geologic significance, the key factors influencing organic matter (OM) accumulation are still unknown. This study aims to address this gap by analyzing both organic and inorganic geochemical data to evaluate the source rock potential, reconstructing the early Cretaceous paleoenvironment, and identifying the primary factors controlling OM accumulation in the Talhar Shale. Our findings reveal that the Talhar Shale exhibits a high total organic carbon content (averaging 2.27 wt%) and is mainly composed of type II kerogen. The shale has reached the main stage of hydrocarbon generation, affirming its status as a thermally mature and prospective source rock for oil and gas. Additionally, the high concentration of SiO2 classifies it as a siliceous shale, and most trace elements show their enrichment compared to the upper continental crust, signifying its elemental importance in the region. Redox-sensitive parameters of the analyzed early Cretaceous data indicate global oxic conditions towards the poles, compared to oxygen-deficient or anoxic conditions towards the equatorial regions. However, the oxic to suboxic conditions predominantly prevailed during the deposition of early Cretaceous Talhar Shale, with moderately higher paleobioproductivity driven by a relatively high sedimentation rate under freshwater saline conditions. Moreover, our analysis proposes paleoproductivity, paleoclimate, paleosalinity, possible high sedimentation rate, and hydro-thermal activities as the key factors influencing OM accumulation, while redox conditions appear to have played a lesser role. These results justify a more comprehensive exploration of the Talhar Shale, highlighting its potential as a source rock and its broader implications for understanding global paleoenvironmental dynamics during the early Cretaceous. This study contributes to the global discourse on paleoenvironmental reconstruction and positions the Talhar Shale as a significant geological feature within the LIB and beyond.

Evaluating oil content in high-maturity shale plays is challenging due to high levels of light hydrocarbons and nanoscale pores, making conventional methods inadequate and inefficient. This work addresses those issues using liquid nitrogen to preserve core samples and employing a high-resolution, low-field 2D NMR instrument (21.86 MHz frequency, 0.07 ms echo time). The method proposed in this study optimizes detection parameters, reduces hydrocarbon loss, and improves the efficiency of fluid monitoring and pore fluid identification. Key experimental optimizations include an echo time of 0.07 ms, T2max of 50 ms, 31 T1 steps, 1 s of waiting time, 8 scans and 4000 echoes. This reduced detection time from 15 to 3 min (5-fold improvement). A closed thawing process with an optimal thawing time of 3 min minimizes hydrocarbon loss and signal interference caused by low temperatures. This study also establishes a 2D NMR T1-T2 identification plate to characterize pore fluids in highmaturity lacustrine shale samples accurately. This method provides rapid, non-destructive, and precise analysis of shale pore fluid, effectively addressing the challenges of light hydrocarbon loss and signal overlap. It offers practical solutions for enhancing the accuracy of oil content evaluation, contributing significantly to shale oil exploration and development.

The progress in petroleum geochemical investigations requires continuously more innovative and accurate tools for the characterization of petroleum geochemical aspects such the source input, depositional environment, type of oils as well as the oil maturation level. Studies previously highlighted the importance of the oil maturity level in the variation of the carbon isotope compositions of individual aromatic compounds but no research has clearly proposed a practical use of these isotopic variations for oil maturation indication. Through a successful separation of oil aromatic fractions into sub-fractions, the present research focused on the gas chromatography-mass spectrometry (GC-MS) and gas chromatography-isotope ratio mass spectrometry (GC-IRMS) analyses of selected alkylnaphthalenes and alkylphenanthrenes from aromatic fractions of Tarim Basin (NW China), Termit Basin (Niger), Bongor Basin (Chad), and Fushan Depression (South China Sea) crude oils to investigate and fill this knowledge gap. The results showed that the carbon isotope trends of individual aromatic compounds in crude oils with increase of the methylation and the number of aromatic rings is an innovative tool for characterizing crude oil maturation stage. In combination with the calculated vitrinite reflectance values (RC-TNR-2), the carbon isotope trends of individual aromatic compounds (1,2,6-TMN, 1,2,5-TMN, 1,3,6,7-TeMN, 9-MP and 1-MP, from bottom to up, respectively) so called "aromatic isotopic maturation indicator" enabled the characterization of two distinct maturation stages. The depletion trend corresponding to a higher value of 1,2,6-TMN relative to 1-MP and an enrichment trend indicating a lower value of 1,2,6-TMN compared to 1-MP. Our investigation revealed that the depletion trend indicates a high maturation stage (R-C-TNR-2 > 2 %), suggesting that the studied oils have already reached the cracking stage (Tarim), while the enrichment trend corresponding to lower maturation stage (R-C-TNR-2 < 2 %) indicates that the oil samples have not yet reached the oil cracking stage (Termit, Bongor and Fushan). The findings of this study provide additional insights into the main factors driving variations in oil composition within diverse geological settings and reveal that the key step of a successful use of the aromatic isotopic composition trends as crude oils' thermal maturity indicator begins with a careful selection of the maturity-controlled aromatic compounds as achieved in this study.

Traditional amide-based hydrate inhibitors, vital for preventing blockages, face limitations due to increasingly stringent environmental regulations. This study focuses on modifying poly(N-vinylcaprolactam) (PVCap) to improve its inhibition and biodegradation properties, by introducing –OH, –NH2, or –COOH groups into the molecular structure. The results revealed that the –OH group significantly improved both hydrate inhibition and biodegradability, while the –COOH and - NH2 groups had moderate and counter-effects, respectively. Compared to end hydroxyl modification, multiple –OH groups in the vinylcaprolactam/vinylalcohol copolymer weaken the inhibition effect, despite enhancing biodegradability. Optimal hydrophilicity was found to enhance PVCap's KHI performance, emphasizing the delicate balance needed to optimize stability and effectiveness. PXRD, Raman spectroscopy and interfacial tension tests were used to elucidate the impact of the modified PVCaps on hydrate structure and gas–liquid interfacial properties. The results further highlighted the significance of appropriate amphiphilicity in augmenting the KHI effect of the modified PVCaps.

The structures, sedimentary fill and magmatic rocks of sedimentary basins are the products of regional tectonic evolution and are crucial to studying the basin's tectonic–palaeogeographical environment and regional tectonic evolution. The present study discusses the zircon U–Pb dating of volcanic rock samples, in situ Hf isotope and whole-rock geochemistry analysis, and the palaeogeographical, sedimentary filling and tectonic background of the Bayingobi basin through outcrop and core descriptions of Meso-Cenozoic strata, stratigraphic correlation and lithofacies analysis. The U–Pb age of the volcanic rocks is 132–102 Ma, and the in situ Hf isotopic values range from −20.99 to +29.48. The 87 Sr/ 86 Sr and 143 Nd/ 144 Nd isotopic ratios of the volcanic rocks are 0.707049–0.879761 and 0.511846–0.512540, respectively, and the Nd isotopic values range from −0.62 to −6.83. The volcanic rocks in the basin have the characteristics of continental margin island arc volcanic rocks (CAA) with loss of Nb and Ta and enrichment of Pb, originating mainly from dehydration melting of the subducting plate. The lower Cretaceous Bayingobi, Suhongtu and Yingen Formations developed specifically delta–lacustrine deposits. The lower and upper member of the Bayingobi Formation was deposited in the Berriasian to Valanginian and Valanginian to late Aptian, respectively. The Suhongtu Formation was deposited during the late Aptian to early Albian and was controlled by the strike of the Engeer Us fault. The Yingen Formation was deposited in the late faulted depression stage in the late Albian. Because of the subduction of the Mongol–Okhotsk Ocean plate in the Early Cretaceous, several depressions (sags) were formed in the Bayingobi basin, accompanied by the eruption of continental plate margin island arc magmas. With the closure of the Mongol–Okhotsk Ocean in the late Early Cretaceous, the basin was uplifted as a whole and the Upper Cretaceous Ulansuhai Formation was deposited. Supplementary material : Supplementary figures and tables are available at https://doi.org/10.6084/m9.figshare.c.7105807

The Dongpu Depression is a rift lake in the Bohai Bay Basin of eastern China, where abundant oil and gas resources were discovered. Previous geochemical investigations of Dongpu Depression oils have revealed a notable lack of data regarding the isotopic compositions of individual polycyclic aromatic hydrocarbons (PAHs) from the discovered Cenozoic crude oils. Using gas chromatography-mass spectrometry (GC-MS) and gas chromatography-isotope ratio mass spectrometry (GC-IRMS), a novel approach combining molecular parameters and stable carbon isotope compositions of individual PAH was applied to study the depositional environment conditions, the different source inputs, the maturation stage and to identify the potential family of five crude oils selected from Dongpu Depression. A decrease of Ga/C30H together with low Pr/Ph ratios and changes in isotopic compositions indicate that the five Dongpu Depression oils were derived from OM deposited in an anoxic saline environment with a stratified water column where mixing of saline water and freshwater occurred. The low isoprenoid, tricyclic and tetracyclic terpane ratios in combination with the delta C-13 values of 1,6-DMN, 1,2,5-TMN, 1,3,6,7-TeMN, 9-MP and 1-MP attest that their sources have a mixed origin with high aquatic organism (planktonic) input and a lower land plant (C-3 plant) contribution. The delta C-13 values of phenanthrene between-30.0 %o and-20.0 %o indicate that the studied Dongpu Depression oils belong to a single family generated from the peak to the late oil generation stage (RcTNR-2 between 0.85 and 1.15 %). A correlation with various basins indicates that oil samples featured by delta C-13 values of Phen between-30.0 %o and-20.0 %o correspond to crude oils derived from mixing of aquatic and high plant contributions with different degrees of mixtures, which have not yet reached their cracking stage (Rc < 2.0 %). Crude oils from the Carboniferous and Mesozoic-Cenozoic Tarim rocks, Australian petroleum systems, Termit Basin, Bongor Basin, Fushan Depression and the studied Dongpu Depression oils belong to that group of oils. Crude oils characterized by lighter phenanthrene isotopic compositions (delta C-13 values of Phen <-30.0 %o) are mainly derived from marine/aquatic input and have already entered the cracking window (Rc > 2.0 %). This group of oils is represented in this study by the Cambrian-Ordovician Tarim Basin oil samples. The research shows the importance of the aromatic isotopic compositions in petroleum system characterization and could be used as a reference for a practical exploration campaign of petroleum.

Sand production can lead to various problems, including erosion in production flow lines that may lead to total production loss for extended periods and costly workover operations. The extent of erosive damage is determined by many factors, among which the flow and sand rates are the most significant. Three main issues must be addressed to ensure an efficient production operation: Sand erosion estimation, Sand monitoring (settling and deposition), and maintaining optimum production rates. If sand production exceeds certain levels, i.e., allowable sand rate, the erosion in the production network becomes problematic. Sand production has been problematic in some wells in Reservoir X. Core, and historical production data was used to build a comprehensive model using Schlumberger PIPESIM™ hydraulic modelling. The software allows for detailed modelling of the production network by which erosion rate, erosion hotspots, and deposition of the produced sand can be quantitatively analyzed. Considering an allowable erosion rate of 0.3 mm/year, the model outcomes indicate that sand erosion is critical in wells J-1, J-2, and L-2. The next step was identifying the hotspots where the produced sand is deposited in the abovementioned wells. The modelling results indicated that sand deposition is primarily severe in the teeline between the platforms. Moreover, the gas-oil ratio was identified as the most influential factor in the sand deposition. Lastly, a sensitivity analysis was conducted on the allowable flow rates and maximum (technical) allowable sand production and erosion rates to find optimum production rates from reservoir X.

Heterogeneity is an important pore structure characteristic of shale formations that can impact reservoir transport properties. To better understand the heterogeneity intrinsic to the shale pore structure, gas adsorption and multifractal theory were combined to analyze data from artificially matured shale samples under both anhydrous and hydrous pyrolysis conditions. We compared two sets of samples: one that was kept intact (not treated with organic solvent), and the other set that was treated with an organic solvent to remove any liquid petroleum that was produced during the pyrolysis process. The results revealed differences in the pore structure parameters of the aliquots under these two pyrolysis conditions as well as treated vs. intact. Furthermore, at the same pyrolysis temperature, the disparity in surface area and pore volume before and after extraction of petroleum was found to be greater with anhydrous compared to hydrous pyrolysis conditions. Regardless of the pyrolysis conditions, when the pyrolysis temperature is under 400°C, pore structural heterogeneity following extraction of petroleum is often small compared to the situation when yield is still present in the pores. As a result, the movable oil under both maturity routes can increase pore structure heterogeneity. Considering the results, when analyzing shale adsorption data for pore structure heterogeneity, experimental design would have an impact on the final outcome and data interpretation. This is the first study that investigates the effect of the movable oil and solvent extraction process on pore structure heterogeneity in relation to the thermal evolution of shale in the presence and absence of water.

Accurate estimation of minimum miscibility pressure (MMP) is crucial for assessing the efficiency of most miscible and immiscible processes, specifically CO2-based enhanced oil recovery (EOR) methods and Carbon capture utilization and sequestration (CCUS). The experimental procedure for MMP prediction is often time-consuming and costly. On the other hand, the empirical models that have been historically used could work based on limited input parameters, ignore the importance of others and are not necessarily accurate. The novelty of the current study is using an explainable deep-learning approach, Recurrent neural network (RNN), to train a model using a multi-dimensional (22 features) dataset with 544 rows of data. The Dataset comprises mole fractions of injected gas (pure and impure CO2). Out of those features, eight subsets of parameters (labelled X_1 to X_8) were used to develop models. The multi-dimensionality of the dataset makes it suitable to study the effects of various parameters on MMP, specifically in conditions of interest to CCUS-EOR applications. Among the multiple inputs tested, the model trained with X_1 and X_8 input parameters (including mole fraction of different hydrocarbon and nonhydrocarbon components and reservoir temperature) resulted in the most accurate estimations of MMP (R2 = 0.99). To further enhance the explainability of the model, feature importance and shapely values analysis were conducted on the developed models, and the impact of each input feature on MMP was elaborated. Temperature, volatile/intermediate, and nonhydrocarbon components are the most influential parameters depending on the subset of parameters chosen. Moreover, the developed model using X_8 inputs performed significantly better (37 % more accurately) than three well-known empirical models from the literature.

Enhancing our understanding of the excess adsorption capacity in shale gas reservoirs is paramount for accurately predicting production capabilities and refining extraction processes. A significant factor in this calculation is the accessible volume, which can only be measured indirectly using helium as a proxy. In this study, hybrid grand canonical Monte Carlo/molecular dynamics (GCMC/MD) simulations were employed to scrutinize the accessible volume and quantify the excess adsorption capacities of various gases in kerogen matrices, characterized by diverse micropore distributions at 363.15 K (90 degrees C) and pressures up to 50 MPa. We evaluated multiple approaches to determine accessible volume in simulations, emphasizing the importance of selecting a probe size that reflects the actual size of the adsorbate. The simulation outcomes reveal that accessible volumes derived from the helium expansion method, mimicking the traditional experimental techniques, tend to be overestimated by around a factor of two. This finding challenges the reliability of such measurements and suggests a need for their recalibration based on computer simulation models. Furthermore, when our simulations were compared with various theoretical adsorption isotherm models, the more advanced Supercritical DubininRadushkevich and Supercritical Brunauer-Emmett-Teller models demonstrated better accuracy in predicting absolute adsorption values compared to the more conventional Langmuir model. However, neither model accurately predicted the absolute adsorption quantities, indicating room for improvement. Finally, the simulations underscore the significant adsorption capacity of CO2 compared to other gases, highlighting its promising role in facilitating enhanced gas recovery and geological sequestration within shale formations.

From exploration to production, the permeability of reservoir rocks is essential for various stages of all types of hydrocarbon field development. In the absence of costly reservoir rock samples, having a reliable correlation to predict rock permeability in the zone(s) of interest is crucial. To predict permeability conventionally, petrophysical rock typing is done. This method divides the reservoir into zones of similar petrophysical properties, and the permeability correlation for each zone is independently developed. The challenge of this approach is that the success depends upon the reservoir's complexity and heterogeneity and the methods and parameters used for rock typing. As a result, in the case of heterogeneous reservoirs, conventional rock typing methods and indices fail to predict the permeability accurately. The target area is a heterogeneous carbonate reservoir in southwestern Iran with a permeability range of 0.1-127.0 md. In this work, two approaches were used. First, based on permeability, porosity, the radius of pore throats at mercury saturation of 35% (r35), and connate water saturation (Swc) as inputs of K-nearest neighbors, the reservoir was classified into two petrophysical zones, and then, permeability for each zone was estimated. Due to the heterogeneous nature of the formation, the predicted permeability results needed to be more accurate. In the second part, we applied novel machine learning algorithms, modified group modeling data handling (GMDH), and genetic programming (GP) to develop one universal permeability equation for the whole reservoir of interest as a function of porosity, the radius of pore throats at mercury saturation of 35% (r35), and connate water saturation (Swc). The novelty of the current approach is that despite being universal, the models developed using GP and GMDH performed substantially better than zone-specific permeability, index-based empirical, or data-driven models used in the literature, such as FZI and Winland. The predicted permeability using GMDH and GP resulted in accurate prediction with R2 of 0.99 and 0.95, respectively, in the heterogeneous reservoir of interest. Moreover, as this study aimed to develop an explainable model, different parameter importance analyses were also applied to the developed permeability models, and r35 was found to be the most impactful feature.

The pipeline blockage caused by hydrate has become a major potential flow safety hazard in the oil/gas transportation with the development of deep-sea exploitation. However, the use of traditional amide-based hydrate inhibitors has been limited by the increasing strict environmental requirements. In this paper, hydrophilic modified poly(N-vinylcaprolactam) (PVCap) homopolymers and copolymers were synthesized respectively by introducing -OH, -NH2 or -COOH group into the molecular structure of the traditional kinetic hydrate inhibitor (KHI) PVCap through functionalization and copolymerization reaction, and influence of these groups on the inhibition and biodegradation performance of PVCap were studied. The results show that the introduction of -OH group significantly improves both the hydrate inhibition property and biodegradability of PVCap. However, the effect of -COOH group was moderate, and the -NH2 group even played a counter-effect. Compared with the end hydroxyl modification (i.e., with one -OH group on the molecular structure), the introduction of multiple -OH groups (vinylcaprolactam/vinylalcohol copolymer) weakened the inhibition effect, even though it further improved the biodegradability of PVCap. The results indicate that proper hydrophilicity could enhance the KHI performance of PVCap, but too high would limit its stability and effect. PXRD, Raman and interfacial tension test were used to determine the effect of the modified PVCaps on the hydrate structure and the gas-liquid interfacial properties, respectively, which indicated that the KHI polymers didn’t distort the hydrate structure but disrupt the hydrogen-bonded water molecular network to disturb the formation of the large hydrate cages (51262), and the small hydrophilic -OH/-COOH groups have enhanced the interaction. Additionally, appropriate amphiphilic was essential for enhancing the KHI performance of the modified PVCaps.

The Pisum sativum (PS), known as the green pea, was used in this investigation to produce a novel green surfactant. The performance of the PS green surfactant was also evaluated using various tests, including contact angle, IFT, emulsion, zeta potential, and oil recovery factor measurement in the presence of formation brine (FB) with a total dissolved solid (TDS) of 150,000 ppm. The characterization study using various tests revealed that the PS green surfactant was nonionic. The critical micelle concentration (CMC) measurement results indicated that the PS green surfactant’s CMC value is 1500 ppm. The IFT and contact angle measurements showed that the green surfactant significantly lowered the IFT and contact angles. The lowest IFT value of 3.71 mN/m and the contact angle of 57.37° were achieved at the FB concentration of 12,500 ppm (optimum salinity). The results of the emulsion tests showed that Winsor type III emulsions were achieved using PS green surfactant and crude oil. The core flooding experiments revealed that the tertiary recovery using a solution of 1500 ppm of PS green surfactant and 12,500 ppm of FB resulted in a maximum oil recovery factor of 83.55%.

Seismic petrophysics is an important link between seismic elastic properties and reservoir physical properties. Based on the petrological and microstructure characteristics of shale in the Qingshankou formation of Sanzhao sag in the north of Songliao Basin, this paper presents an anisotropy petrophysical model with complex pore structure suitable for organic shale constructed with the use of the Voigt-Reuss-Hill average model, an anisotropy self-consistent approximation+differential effective medium model, and the layering of clay and kerogen is simulated by using the Voigt-Reuss-Hill average and bond transform to achieve the simulation of shale anisotropy. Based on the proposed model, the effects of the organic volume fraction, porosity, and pore aspect ratio on rock elastic properties are discussed. The result shows that with the increase of matrix porosity, all elastic parameters show a decreasing trend; with the increase of the organic volume fraction, except shear modulus, other elastic parameters show an increasing trend. Through comparative analysis, the elastic parameters (Lamé impedance and Shear impedance) sensitive to the organic volume fraction and porosity are optimized; the seismic petrophysical cross-plot template with core calibration is constructed. The application shows that the predicted S-wave velocity based on the proposed model is in good agreement with the S-wave velocity derived from dipole source logging. Combined with the high-precision prestack elastic parameter inversion, the “sweet spot” characteristics can be well described, and the research could contribute to a better “sweet spot” description and provide a better support for shale exploration in Sanzhao sag.

Fracture toughness is an important mechanical parameter for proper modeling of reservoir stimulation which is necessary for production from tight formations. To measure fracture toughness, several models have been proposed based on nanoindentation data, however, the comparison of these models in organic rich shale is still limited in the literature. To obtain a better understanding of the suitability of these models, we applied two distinct energy based methods, one which takes advantage of the whole force-displacement curve (KIC_whole) and the other one that considers the fracturing-induced pop-in events (KIC_pop). To estimate and compare the fracture toughness from either of these methods, nanoindentation data is acquired from a sample that was collected from the Wolfcamp Formation, USA. The results showed that for the soft mechanical phase (clay minerals), the KIC_whole varied from 0.020 to 0.313 MPa m0.5 while the KIC_pop from 0.02 to 0.330 MPa m0.5. In the hard mechanical phase (carbonate and quartz), the KIC_whole was found between 0.380 and 0.84 MPa M0.5, and the KIC_pop was estimated from 0.38 to 0.780 MPa m0.5. These values for the intermediate phase was, 0.220-0.588 MPa m0.5 and 0.215-0.500 MPa m0.5, respectively for each method. Statistical analysis of the results based on the t-tests verified that the fracture toughness of different mechanical phases that is derived from these two different models is quite comparable. Overall, considering the simplicity of the calculations and the limitations in the approach that is based on pop-in events, our recommendation would be to use the whole forcedisplacement curve to obtain the fracture toughness of geomaterials.

Tamusu uranium deposit is located in Yingejing sag in the Bayingobi basin. A rift type structural slope zone developed northwest of the sag. Based on the study of the lithology, lithofacies, whole rock geochemistry, and fluid inclusion characteristics of the deposit, a paragenetic association sequence of altered minerals in the deposit was established, and the characteristics of the source, temperature, salinity, and evolution of the ore-forming fluid in the deposit were discussed. The stratigraphic assemblage structure of the lower member of the Bayingobi Formation (falling-stage system tract, lowstand system tract, and transgressive system tract) laid the foundation for uranium mineralization. The uranium mineralization period of ore deposit can be divided into three stages. The altered mineral assemblages of Stage 1 are mainly composed of hematite, dolomite, ironbearing dolomite, ankerite, fluorite, euhedral pyrite, and metal sulfide. Stage 2 altered mineral assemblages are dominated by limonite, euhedral-subhedral pyrite, and gypsum. The altered mineral assemblages of Stage 3 are mainly composed of layered gypsum, celestite, and barite. The early uranium ore-forming fluid mainly originated from the deep basin and percolated along the fault and sand body of the lowstand system tract to form uranium orebodies. The fluid inclusion temperature of ore-forming fluid was 211-140 degrees C, and the salinity was 4.49%-16.24%. The temperature gradually decreased as the ore-forming fluid evolved, and CO2 was released, causing dolomite, calcite, fluorite, and other minerals to precipitate in the sandstone pores. The late ore-forming fluid mainly originated from supergene oxygen water, which migrated into the basin along the erosion window at the edge of the sag. The fluid inclusion temperature of ore-forming fluid was 100-130., the salinity was 2.24%-7.02%, and the average was 4.49%. In the late stage of the supergene fluid, the fluid inclusion temperature was 55-79 degrees C, and the salinity was 4.96%-5.11%. The ore-forming fluid of the deposit gradually decreased in temperature from the early stage to the late stage of mineralization. In addition, the salinity gradually evolved from high in the early stage to low and evolved to high in the late stage. Sulfophile, lithophile, and rare earth elements precipitated first in the process of fluid action, followed by U, and Sc increased with the U content. A uranium metallogenic model of the deposit was established based on the relationship between the structural, lithology, mineralization alteration, fluid evolution, and uranium mineralization of the basin.

Shale oil has received increasing attention as an essential replacement for conventional oil resources. Shale oil recovery is a complex process controlled by interactions of many factors whose impact could be significantly different from conventional reservoirs. This study hence aims to fill the gaps in the literature by studying various aspects of the phase behavior of shale oil and their significance in different aspects of the recovery from oil shale. In the first part of this study, the standard practices, including experimental and theoretical methods for calculating the pressure, volume, temperature (PVT), and phase behavior of shale oil, is discussed in detail. Next, the effects of factors such as the composition of fluids, pore structure, and capillary forces on the phase behavior of hydrocarbon fluids are explained. The third part focuses on applying phase behavior for oil shale development. Moreover, the geological and geochemical processes that lead to the maturity of kerogen, the formation of shale oil, and the experimental methods by which those processes are currently studied are scrutinized. By studying the thermal and burial history of the hydrocarbon-generating strata and hydrocarbon-generating kinetics, the shale formation's oil and gas phase distribution can be predicted. Consequently, the sweet spots for the recovery of light condensate oil can be more accurately determined. The application of enhanced oil recovery methods is an inevitable part of recovery from conventional and unconventional formations. Therefore, the last part of this study analyses the changes in the phase behavior of shale oil when an external component, i.e., CO2 or CH4, is injected into the reservoir. Reviewing the literature revealed that a more accurate prediction of hydrocarbon phase behavior can be made by combining different disciplines of science to achieve optimized plans for efficient shale oil development, making shale oil a more economically viable energy resource.