Lacustrine shales in the Sichuan Basin host abundant hydrocarbon resources totaling 6 × 10¹² m³ (gas equivalent), predominantly as condensate reservoirs. Compared to marine shale gas reservoirs, these lacustrine shales display distinctive lithofacies characteristics, elevated clay contents, and unique gas reservoir types, primarily distributed in shallow to semi-deep lacustrine sedimentary environments of the Qianfoya/Lianggaoshan formations, as well as the Dongyuemiao and Daanzhai members of the Ziliujing Formation, of the Jurassic. Presently, the Critical development challenges include short production plateau, rapid decline rates, and low estimated ultimate recovery (EUR) per well, undermining economic viability.. This study systematically analyzes three Jurassic lithofacies assemblages and identifies critical fracturing constraints as follows. First, Strong heterogeneity arising from multi-lithofacies combinations restricts fracture propagation and proppant transport, limiting the stimulated reservoir volume. Second, the high clay content induces hydration swelling, impairing long-term fracture conductivity. Third, the dynamic stress-seepage coupling in multi-scale, multi-porosity, multi-phase systems complicates hydrocarbon flow mechanisms, highlighting inadequacies in current geoengineering models and numerical simulations. Essential research priorities, thereby, include fracture network formation in highly heterogeneous shales, fluid-rock coupled pore-fracture evolution incorporating spatiotemporal fluid distribution, and multi-phase flow modeling within complex porous media. Consequently, we propose an integrated “multi-lithofacies/multi-porosity/multi-scale/multi-phase” geoengineering optimization framework (i. s., “modeling-fracturing-simulation”) to establish a comprehensive “theory-technology-demonstration” solution for economically viable shale resource development.

The minimum sand thickness for clastic reservoirs at medium burial depth between 2500 and 3500 meters to be predictable with current techniques is generally no more than 5 to 10 meters, while prediction of ultra-thin reservoirs with a thickness less than 5 meters remains a tough challenge. Based on the post-stack seismic data acquired and processed at different times from blocks 14 and 17 in the Andes of Ecuador, this study uses the post-stack consistent processing method driven by the structural trend surface to suppress and eliminate the interference of phase, energy, frequency and closure error on thin-bed reflection and reduce reservoir prediction uncertainty. The time-frequency attenuation, high-precision synthetic seismogram calibration method is employed to erase the accumulative time shift caused by formation absorption, accurately calibrate and analyse reflection characteristics of thin layers, and determine the minimum predominant frequency for resolving ultra-thin reservoirs. The weak reflection coefficient of thin layers is also effectively restored by using the high-resolution processing technology on post-stack broadband signals of “steady-state time-frequency-varying wavelet” without well data driving. The algorithm and workflow of facies-controlled waveform inversion are optimized based on broadband seismic waveform constraints. A series of technologies have then been developed and applied to the blocks, from which some tidal channel sand bodies of only 2 to 5 meters thick and 3000 meters deep were successfully mapped. The drilling results of new appraisal wells and development wells verified that a prediction accuracy of at least 90 % with the methods has been reached.

The Sichuan Basin and its periphery are rich in shale gas resources. However, diverse sedimentary facies and intricate structures result in significant variations in shale gas productivity across shale gas wells during fracturing tests. Consequently, some fracturing techniques that are effective in high-productivity wells may be subjected to limited popularization. Therefore, there is an urgent need to develop specialized fracturing schemes for different types shale gas. To achieve efficient shale gas recovery, we compare the geological and engineering parameters of blocks with proven shale gas reserves within the Sichuan Basin. These parameters, along with the sedimentary facies types, lithofacies assemblages, burial depths, and pressure systems, are used to classify the shale gas into six types: marine overpressured type of medium-shallow burial depth (burial depth less than 3500 m), deep overpressured marine type (burial depth more than 3500 m), deep normally pressured marine type, new marine type, deep overpressured type of transition from continental to marine sedimentation, and overpressured continental type of medium-shallow burial depth. Our findings, obtained from numerical simulations and experiments, are as follows: (1) Natural fractures and complex in-situ stress distributions cause uneven fracture propagation and merging. Optimizing perforation parameters and employing the temporary plugging technique can effectively control fracture morphologies and enhance stimulated reservoir volume (SRV); (2) Interlayers and laminae affect vertical fracture height growth, as well as the proppant migration and placement morphology. Increasing the amount of preflush of high viscosity for fracturing and small-particle-size proppant, is conducive to the fracture longitudinal penetration layers and balanced proppant support; (3) Strong hydration of shales with high clay content can lead to the deterioration of shale mechanical properties and exacerbation of proppant embedment, while optimizing the type and dosage of additives in fracturing fluid systems can inhibit shale hydration. We formulate the optimal design principles and techniques for volume fracturing of horizontal wells in various shale gas reservoirs. The methodology has been successfully applied to the development of deep high-pressure shale gas reservoirs with complex tectonic stress field in the Dingshan block, deep normally pressured shale gas reservoirs in the Lintanchang block, the new-type shale gas reservoirs in marine clastic rocks in the Jingyan-Qianwei block, the shale gas reservoirs of the marine-continental transitional facies in the Dalong Formation in Puguang area, and lacustrine shale gas reservoirs in the Qianfoya Formation, resulting in significant improvement in single well productivity. This study provides valuable experience and reference for efficient fracturing and commercial exploitation of various complex shale gas reservoirs.

In blocks 14 and 17 of Ecuador, both situated in the foredeep zone of the Oriente Basin, the main oil-bearing strata comprise the M1, U, and T members of the Napo Formation. The developed oilfields in these blocks have entered a high water-cut stage, posing challenges to resource replacement. The trend surface-driven, post-stack consistent processing of seismic data, the time-frequency attenuation-based calibration and interpretation of high-precision synthetic seismograms, and anisotropic-variable-velocity mapping, are jointly applied to finely characterize low-amplitude structures, with many low-amplitude structural reservoirs discovered. Thin layers’ weak-reflection coefficients, determined through frequency-division iterative denoising, contribute to the reconstruction of effective post-stack broadband signals. With these signals as constraints, we quantitatively predict 2- to 5-m-thick tidal channel sandstones at a burial depth of 3000 m through a seismic phase-controlled nonlinear inversion of waveforms, identifying several ultra-thin lithologic reservoirs in the M1 member. Based on regional hydrodynamic conditions, the oil-water contact trends of low-amplitude structural reservoirs, and the energy characteristics of reservoirs, we determine hydrodynamic oil reservoirs in the LU member and perform step-out drilling. The observation of numerous thin sections from cores reveals the presence of glauconites as cements and particles in the quartzose sandstone reservoirs. Accordingly, a dual-component volume model of glauconites for log interpretation is developed, allowing for reservoir evaluation and identification of low-resistivity reservoirs in the UT member. Based on the characteristics of tropical rainforest surfaces and subtle reservoirs in the subsurface, we achieve progressive exploration, evaluation, and rapid production onstream following the strategy of “overall deployment, batch-wise implementation, tracking and evaluation, and timely adjustment”, with a success rate of over 90% for both exploration and appraisal wells.

To promote carbon dioxide (CO₂) emission reduction and achieve carbon neutrality, we analyze recent technical advances in carbon capture, utilization, and storage (CCUS), highlighting existing challenges and future directions. The findings indicate that the global CCUS industry is undergoing rapid growth, with the number of large-scale CCUS projects worldwide reaching up to 392 by the end of 2023, twice the number in 2022, demonstrating the preliminary commercial viability of CCUS. Significant progress have been made in the research and application of the geological storage and utilization of CO₂, including (1) the use of representative elementary volume (REV) in the characterization and modeling of geological CO₂ storage reservoirs, enabling the application of microscopic properties to macroscopic geological models; the utilization of strain tensors in the dynamic characterization and monitoring of storage reservoirs; the comprehensive application of many techniques, including geochemical imaging, micro-seismic, fiber optics, and geothermal and atmospheric monitoring for leakage detection of the CO₂ storage reservoirs; and the development of simulation techniques to simulate various CO₂ plume migration scenarios and sequestration potentials in the storage reservoirs, tailored to the various types of sedimentary reservoirs; (2) the wide application of big data technologies and artificial intelligence (AI) in CCUS, including the development of proxy models for the rapid risk assessment of CO₂ sequestration based on deep learning and coupled geomechanics and the utilization of machine learningto predict or assess the CO₂ enhanced oil recovery (EOR) and storage efficiency in residual oil zones; (3) significant progress in the new techniques for CO₂ EOR and their application in new fields. Emerging techniques, such as alternating injection of CO₂ and low mineralized water, CO₂ micro-nano bubble flooding, thickener-assisted CO₂ flooding, and CO₂ foam flooding, have shown promising results in field tests. Furthermore, the application of CO₂ flooding has expanded from medium-to low-permeability sandstone oil reservoirs and tight sandstone oil reservoirs to residual oil zones (ROZs), and shale oil and gas reservoirs. However, there are still challenges related to the safety of the long-term sequestration of captured CO₂, economic viability, and technical uncertainties. Therefore, it is necessary to further improve existing laws and regulations while vigorously developing new techniques for the geological storage and utilization of CO₂ by conducting multidisciplinary research and technological innovation, and promoting international cooperation, with a view to ensuring the safety of the long-term storage of captured CO₂ and enhancing the economic viability of commercial operations.