Search Results (319)

The increasing need for sustainable valorization of fossil-based and waste-derived materials has gained interest in converting complex organic matrices such as kerogen into valuable chemicals. This study explores a two-step oxidative strategy to decompose and valorize kerogen-rich oil shale, aiming to develop a locally based source of aliphatic dicarboxylic acids (DCAs). The method combines air oxidation with subsequent nitric acid treatment to enable selective breakdown of the organic structure under milder conditions. Air oxidation was conducted at 165–175 °C using 1% KOH as an alkaline promoter and 40 bar oxygen pressure (or alternatively 185 °C at 30 bar), targeting 30–40% carbon conversion. The resulting material was then subjected to nitric acid oxidation using an 8% HNO₃ solution. This approach yielded up to 23% DCAs, with pre-oxidation allowing a twofold reduction in acid dosage while maintaining efficiency. However, two-step oxidation was still accompanied by substantial degradation of the structure, resulting in elevated CO₂ formation, highlighting the need to balance conversion and carbon retention. The process offers a possible route for transforming solid fossil residues into useful chemical precursors and supports the advancement of regionally sourced, sustainable DCA production from unconventional raw materials. Full article

Marine–continental transitional shale is a promising unconventional gas reservoir, playing an increasingly important role in China’s energy portfolio. However, compared to marine shale, research on marine–continental transitional shale’s fractal characteristics of pore structure and complete pore size distribution remains limited. In this work, high-pressure mercury intrusion, N₂ adsorption, and CO₂ adsorption techniques, combined with fractal geometry modeling, were employed to characterize the pore structure of the Shanxi Formation marine–continental transitional shale. The shale exhibits generally high TOC content and abundant clay minerals, indicating strong hydrocarbon-generation potential. The pore size distribution is multi-modal: micropores and mesopores dominate, contributing the majority of the specific surface area and pore volume, whereas macropores display a single-peak distribution. Fractal analysis reveals that micropores have high fractal dimensions and structural regularity, mesopores exhibit dual-fractal characteristics, and macropores show large variations in fractal dimension. Characteristics of pore structure is primarily controlled by TOC content and mineral composition. These findings provide a quantitative basis for evaluating shale reservoir quality, understanding gas storage mechanisms, and optimizing strategies for sustainable of oil and gas development in marine–continental transitional shales. Full article

Hydraulic fracturing is a crucial technology for developing unconventional oil and gas resources. However, conventional geophysical methods struggle to efficiently and accurately image proppant-connected channels created by hydraulic fracturing. The borehole-to-surface electromagnetic imaging method (BSEM) overcomes this limitation by utilizing a controlled cased well source. Placing the source close to the target reservoir and deploying multi-component receivers on the surface enable high-precision lateral monitoring, providing an effective approach for dynamic monitoring of hydraulic fracturing operations. This study focuses on key aspects of forward modeling for BSEM. A three-dimensional finite-volume method based on the Yee grid was used to simulate the borehole-to-surface electromagnetic system incorporating metal casings, validating the method of simulating metal casing using multiple line sources. The simulation of the observation system and the frequency-domain electromagnetic monitoring simulation based on actual well data confirm BSEM’s high sensitivity for monitoring deep subsurface formations. Critically, well casing exerts a substantial influence on surface electromagnetic responses, while the electromagnetic contribution from line sources emulating perforation zones necessitates explicit incorporation within data processing workflows. Full article

Against the backdrop of global energy transition and strict environmental regulations, supercritical carbon dioxide (scCO₂) fracturing and oil displacement technologies have emerged as pivotal green approaches in shale gas exploitation, offering the dual advantages of zero water consumption and carbon sequestration. However, the inherent low viscosity of scCO₂ severely restricts its sand-carrying capacity, fracture propagation efficiency, and oil recovery rate, necessitating the urgent development of high-performance thickeners. The current research on scCO₂ thickeners faces a critical trade-off: traditional fluorinated polymers exhibit excellent philicity CO₂, but suffer from high costs and environmental hazards, while non-fluorinated systems often struggle to balance solubility and thickening performance. The development of new thickeners primarily involves two directions. On one hand, efforts focus on modifying non-fluorinated polymers, driven by environmental protection needs—traditional fluorinated thickeners may cause environmental pollution, and improving non-fluorinated polymers can maintain good thickening performance while reducing environmental impacts. On the other hand, there is a commitment to developing non-noble metal-catalyzed siloxane modification and synthesis processes, aiming to enhance the technical and economic feasibility of scCO₂ thickeners. Compared with noble metal catalysts like platinum, non-noble metal catalysts can reduce production costs, making the synthesis process more economically viable for large-scale industrial applications. These studies are crucial for promoting the practical application of scCO₂ technology in unconventional oil and gas development, including improving fracturing efficiency and oil displacement efficiency, and providing new technical support for the sustainable development of the energy industry. This study innovatively designed an amphiphilic modified amino silicone oil polymer (MA-co-MPEGA-AS) by combining maleic anhydride (MA), methoxy polyethylene glycol acrylate (MPEGA), and amino silicone oil (AS) through a molecular bridge strategy. The synthesis process involved three key steps: radical polymerization of MA and MPEGA, amidation with AS, and in situ network formation. Fourier transform infrared spectroscopy (FT-IR) confirmed the successful introduction of ether-based CO₂-philic groups. Rheological tests conducted under scCO₂ conditions demonstrated a 114-fold increase in viscosity for MA-co-MPEGA-AS. Mechanistic studies revealed that the ether oxygen atoms (Lewis base) in MPEGA formed dipole–quadrupole interactions with CO₂ (Lewis acid), enhancing solubility by 47%. Simultaneously, the self-assembly of siloxane chains into a three-dimensional network suppressed interlayer sliding in scCO₂ and maintained over 90% viscosity retention at 80 °C. This fluorine-free design eliminates the need for platinum-based catalysts and reduces production costs compared to fluorinated polymers. The hierarchical interactions (coordination bonds and hydrogen bonds) within the system provide a novel synthetic paradigm for scCO₂ thickeners. This research lays the foundation for green CO₂-based energy extraction technologies. Full article

Tight gas is an unconventional resource abundantly found in low-porosity, low-permeability sandstone reservoirs. Production can be significantly reduced due to water production during the development process. Therefore, it is necessary to predict water production during the logging phase to formulate development strategies for tight gas wells. This study analyzes the water production mechanism in tight sandstone reservoirs and identifies that the core of water production evaluation in the Shihezi Formation of the Linxing block is to clarify the pore permeability structure of tight sandstone and the type of intra-layer water. The primary challenge lies in the accurate characterization of bound water saturation. By integrating logging data with core experiments, a bound water saturation evaluation model based on grain size diameter and pore structure index was established, achieving a calculation accuracy of 92% for the multi-parameter-fitted bound water saturation. Then, based on the high-precision bound water saturation, a gas–water ratio prediction model for the first month of production, considering water saturation, grain size diameter, and fluid type, was established, improving the prediction accuracy to 87.7%. The bound water saturation evaluation and water production evaluation models in this study can achieve effective water production prediction in the early stage of production, providing theoretical support for the scientific development of tight gas in the Linxing block. Full article

Shale and coal in the transitional marine–continental facies of the Ordos Basin serve as unconventional natural gas reservoirs, with their pore structures controlling gas adsorption characteristics and occurrence states. To quantitatively characterize the pore structure features and differences between these two reservoirs, this study takes the Shanxi Formation shale and coal in the Daning–Jixian area on the eastern margin of the Ordos Basin as examples. Field-emission scanning electron microscopy (FE-SEM), high-pressure mercury intrusion, low-temperature N₂ adsorption, and low-pressure CO₂ adsorption experiments were employed to analyze and compare the full-scale pore structures of the shale and coal reservoirs. Combined with methane isothermal adsorption experiments, the gas adsorption capacity and its differences in these reservoirs were investigated. The results indicate that the average total organic carbon (TOC) content of shale is 2.66%, with well-developed organic pores, inorganic pores, and microfractures. Organic pores are the most common, typically occurring densely and in clusters. The average TOC content of coal is 74.22%, with organic gas pores being the dominant pore type, significantly larger in diameter than those in transitional marine–continental facies shale and marine shale. In coal, micropores contribute the most to pore volume, while mesopores and macropores contribute less. In shale, mesopores dominate, followed by micropores, with macropores being underdeveloped. Both coal and shale exhibit a high SSA primarily contributed by micropores, with organic matter serving as the material basis for micropore development. The methane adsorption capacity of coal is 8–29 times higher than that of shale. Coal contains abundant organic micropores, providing a large SSA and numerous adsorption sites for methane, facilitating gas adsorption and storage. This study comprehensively reveals the similarities and differences in pore structures between transitional marine–continental facies shale and coal reservoirs in the Ordos Basin at the microscale, providing a scientific basis for the precise evaluation and development of unconventional oil and gas resources. Full article

The friction surfacing (FS) process has emerged over the past few years as a method for joining both similar and dissimilar materials, for volume damage repair of defective components, and for corrosion protection. The possibility to produce a metallic coating by FS, without melting the material, classifies this technique as distinct from other standard methods. This unconventional deposition method is based on the severe plastic deformation that appears on a rotating metallic rod (consumable material) pressed against the substrate under an axial load. The present study aims to investigate the tribological properties and corrosion resistance provided by the aluminum-based FS coatings deposited onto a structural S235 steel substrate and further modified by plasma electrolytic oxidation (PEO). During the PEO treatment, the formation of a ceramic film is enabled, while the hardness, chemical stability, corrosion, and wear resistance of the modified surfaces are considerably increased. The morpho-structural characteristics and chemical composition of the PEO-modified FS coatings are further investigated using scanning electron microscopy combined with energy dispersive spectroscopy analysis and X-ray diffraction. Dry sliding wear testing of the PEO-modified aluminum-based coatings was carried out using a ball-on-disc configuration, while the corrosion resistance was electrochemically evaluated in a 3.5 wt.% NaCl solution. The corrosion rates of the aluminum-based coatings decreased significantly when the PEO treatment was applied, while the wear rate was substantially reduced compared to the untreated aluminum-based coating and steel substrate, respectively. Full article

Unconventional hydrocarbon reservoirs with low matrix permeability (<0.3 mD), high temperatures, and sour conditions present significant challenges for stimulation and production enhancement. This study examines field trials for a large oil and gas operator in the UAE, focusing on tight carbonate deposits with reservoir temperatures above 93 °C and high sour gas content. A novel multi-stage chemical stimulation workflow was created, beginning with a pre-flush phase that alters rock wettability and reduces interfacial tension at the micro-scale. This was followed by a second phase that increased near-wellbore permeability and ensured proper acid placement. The treatment’s core used a thermally stable, corrosion-resistant retarded acid system designed to slow reaction rates, allow deeper acid penetration, and build prolonged conductive wormholes. Simulations revealed considerable acid penetration of the formation beyond the near-wellbore zone. The post-treatment field data showed a tenfold improvement in injectivity, which corresponded closely to the acid penetration profiles predicted by modeling. Furthermore, oil production demonstrated sustained, high oil production of 515 bpd on average for several months after the treatment, in contrast to the previously unstable and low-rate production. Finally, the findings support a reproducible and technologically advanced stimulation technique for boosting recovery in ultra-tight carbonate reservoirs using the acid retardation effect where traditional stimulation fails. Full article

As an important unconventional oil and gas resource, tight oil exploration and development is of great significance to ensure energy supply under the background of continuous growth of global energy demand. Low-porosity and low-permeability reservoirs are characterized by tight rock properties, poor physical properties, and complex pore structure, and as a result the fine calculation of logging reservoir parameters faces great challenges. In addition, the crude oil in this area has high viscosity, the formation water salinity is low, and the oil reservoir resistivity shows significant spatial variability in the horizontal direction, which further increases the difficulty of oil and water reservoir identification and affects the accuracy of oil saturation calculation. Targeting the above problems, the Nutcracker Optimization Algorithm (NOA) was used to optimize the hyperparameters of the random forest classification model, and then the optimal hyperparameters were input into the random forest model, and the conventional logging curve and oil test data were combined to identify and classify the reservoir fluids, with the final accuracy reaching 94.92%. Compared with the traditional Hingle map intersection method, the accuracy of this method is improved by 14.92%, which verifies the reliability of the model for fluid identification of low-porosity and low-permeability reservoirs in the research block and provides reference significance for the next oil test and production test layer in this block. Full article

We conducted ultrasonic (1-MHz) laboratory measurements on 210 samples from the Vaca Muerta Formation (Neuquén Basin, Argentina) to determine the factors influencing acoustic velocities in siliciclastic–carbonate mudstone. We quantitatively assessed the calcium carbonate and total organic carbon (TOC) content and qualitatively identified the quartz and clay mineralogy. For brine-saturated samples, P-wave velocities ranged from 2826 to 6816 m/s, S-wave velocities ranged from 1474 to 3643 m/s, and porosity values ranged from 0.01 to 19.4%. Carbonate content percentages, found to be critically important, vary widely from 0.08 to 98.0%, while TOC ranged from 0 to 5.3%. Velocity was primarily controlled by carbonate content and, to a lesser extent, by the non-carbonate mineralogy of the rock (e.g., quartz, clay minerals). TOC content had little effect on the acoustic properties. Due to the low porosity of most samples, mineral composition had a stronger influence on velocity than porosity or pore geometry. The V_p/V_s ratio of dry samples ranged from 1.38 to 1.97 and decreased as porosity increased. In saturated samples, the V_p/V_s ratio ranged from 1.46 to 2.06 and appeared independent of porosity. A clear distinction between carbonate and mixed lithofacies under both saturated and dry conditions was observed in all samples. Full article

Coalbed methane (CBM), a significant unconventional natural gas resource, holds a crucial position in China’s ongoing energy structure transformation. However, the inherent low permeability, high brittleness, and strong sensitivity of CBM reservoirs to drilling fluids often lead to severe formation damage during drilling operations, consequently impairing well productivity. To address these challenges, this study developed a novel low-damage, plugging, and anti-collapse water-based drilling fluid gel system (ACWD) specifically designed for coalbed methane drilling. Laboratory investigations demonstrate that the ACWD system exhibits superior overall performance. It exhibits stable rheological properties, with an initial API filtrate loss of 1.0 mL and a high-temperature, high-pressure (HTHP) filtrate loss of 4.4 mL after 16 h of hot rolling at 120 °C. It also demonstrates excellent static settling stability. The system effectively inhibits the hydration and swelling of clay and coal, significantly reducing the linear expansion of bentonite from 5.42 mm (in deionized water) to 1.05 mm, and achieving high shale rolling recovery rates (both exceeding 80%). Crucially, the ACWD system exhibits exceptional plugging performance, completely sealing simulated 400 µm fractures with zero filtrate loss at 5 MPa pressure. It also significantly reduces core damage, with an LS-C1 core damage rate of 7.73%, substantially lower than the 19.85% recorded for the control polymer system (LS-C2 core). Field application in the JX-1 well of the Ordos Basin further validated the system’s effectiveness in mitigating fluid loss, preventing wellbore instability, and enhancing drilling efficiency in complex coal formations. This study offers a promising, relatively environmentally friendly, and cost-effective drilling fluid solution for the safe and efficient development of coalbed methane resources. Full article

The mechanisms underlying formation energy depletion after initial fracturing and post-refracturing production decline in shale oil horizontal wells remain poorly understood. This study proposes a novel numerical simulation framework for refracturing processes based on a three-dimensional fully coupled hydromechanical model. By dynamically reconfiguring the in situ stress field through integration of production data from initial fracturing stages, our approach enables precise control over fracture propagation trajectories and intensities, thereby enhancing reservoir stimulation volume (RSV) and residual oil recovery. The implementation of fully coupled hydromechanical simulation reveals two critical findings: (1) the 70 m fracture half-length generated during initial fracturing fails to access residual oil-rich zones due to insufficient fracture network complexity; (2) a 3–5° stress reorientation combined with reservoir repressurization before refracturing significantly improves fracture network interconnectivity. Field validation demonstrates that refracturing extends fracture half-lengths to 97–154 m (38–120% increase) and amplifies RSV by 125% compared to initial operations. The developed seepage–stress coupling methodology establishes a theoretical foundation for optimizing repeated fracturing designs in unconventional reservoirs, providing critical insights into residual oil mobilization through engineered stress field manipulation. Full article

With the unconventional energy sector (e.g., shale gas) increasingly focused on precision drilling and cost-effective extraction, slim-hole horizontal well technology is gaining prominence. However, drill string dynamics in narrow, complex fluid environments are not fully understood. This study presents a novel bidirectional fluid–structure interaction (FSI) model, uniquely integrating recursive algorithms with the Moving Particle Semi-implicit (MPS) method to couple drill string–wellbore contact with drilling fluid interactions. Key findings show that drilling fluid significantly impacts drill string behavior; for instance, it can reduce natural frequencies by 20–25%, while stiff formations amplify lateral resonance risks. Optimizing fluid properties can substantially cut energy losses, though TREE is marginally elevated when viscosity exceeds the threshold (2.5 × 10⁻⁵ m²/s). The drill string typically displaces rightward, but higher viscosity can shift it left; a moderate friction coefficient aids centering. Excessive lateral displacement impairs cuttings removal, affecting fracturing. These insights enable actionable strategies: adjusting fluid viscosity and drag reducers can optimize drill string position and enhance cleaning. This research provides a framework for energy-efficient drilling in complex reservoirs, balancing efficiency with wellbore integrity and improving outcomes in the unconventional energy sector. Full article

This paper provides a comprehensive analysis of gas field produced water from four perspectives: water sources, chemical composition, treatment methods, and application scenarios. It identifies critical challenges in current formation reinjection practices, including poor containment performance for injection layers, difficulties in optimal layer selection, and uncertainties in injection volume determination. To address these issues, systematic selection criteria for reinjection layers were established. Taking a depleted gas reservoir in the Ordos Basin as a case study, we conducted a geological analysis of candidate formations based on previous research findings. We set up three groups of schemes regarding injection wells, injection rate, and permeability inhomogeneity and studied reservoir reinjection water volume, reinjection formation pressure, reinjection waves and range, and reinjection safety using three-dimensional numerical simulation technology. Finally, we selected the preferred scheme of reinjection well location in consideration of permeability inhomogeneity, with a cumulative reinjection volume of 1554.3 × 10⁴ m³ and a change in reinjection formation pressure of 0~20 MPa. The pressure change in the upper overburden of the reinjection layer was kept within 3 MPa, a value consistent with actual historical reinjection data, confirming again the accuracy of this layer selection strategy and the aforementioned layer selection analysis and providing a basis for layer selection and reinjection safety for the assessment of recovered water reinjection in other unconventional gas reservoirs. Full article

The production of gas and condensate from liquid-rich shale reservoirs, particularly within heterogeneous lacustrine systems, remains a critical challenge in unconventional hydrocarbon exploration due to intricate multiphase hydrocarbon partitioning, including gases (C₁–C₂), volatile liquids (C₃–C₇), and heavier liquids (C₇₊). This study investigates a 120-meter-thick interval dominated by lacustrine deposits from the Lower Cretaceous Shahezi Formation (K₁sh) in the Songliao Basin. This interval, characterized by high clay mineral content and silicate–pyrite laminations, was examined to identify the factors controlling hybrid shale gas condensate systems. We proposed the Hybrid Shale Condensate Index (HSCI), defined as the molar ratios of (C₁–C₇)/C₇₊, to categorize fluid phases and address shortcomings in traditional GOR/API ratios. Over 1000 samples were treated by geochemical pyrolysis logging, X-ray fluorescence (XRF) spectrum element logging, SEM-based automated mineralogy, and in situ gas desorption, revealing four primary controls: (1) Thermal maturity thresholds. Mature to highly mature shales exhibit peak condensate production and the highest total gas content (TGC), with maximum gaseous and liquid hydrocarbons at T_max = 490 °C. (2) Lithofacies assemblage. Argillaceous shales rich in mixed carbonate and clay minerals exhibit an intergranular porosity of 4.8 ± 1.2% and store 83 ± 7% of gas in intercrystalline pore spaces. (3) Paleoenvironmental settings. Conditions such as humid climate, saline water geochemistry, anoxic bottom waters, and significant input of volcanic materials promoted organic carbon accumulation (TOC reaching up to 5.2 wt%) and the preservation of organic-rich lamination. (4) Laminae and fracture systems. Silicate laminae account for 78% of total pore space, and pyrite laminations form interconnected pore networks conducive to gas storage. These findings delineate the “sweet spots” for unconventional hydrocarbon reservoirs, thereby enhancing exploration for gas condensate in lacustrine shale systems. Full article