Search Results (48)

To address the critical challenges of severe fragmentation in cuttings, persistent cuttings bed accumulation, and abrupt friction torque increases during horizontal well drilling of Jurassic continental shale oil formations in J Block, Sichuan Basin—rooted in the unique high clay content that induces colloidal stability of fine cuttings and resistance to conventional cleaning—this study innovatively proposes a coupled prevention–removal hole-cleaning technology. The core methodology integrates three synergistic components: (1) orthogonal numerical simulations to optimize drilling parameters, reducing the cuttings input rate by 43.48% through “hydraulic carrying + mechanical agitation” synergy; (2) a modified Moore model with horizontal section correction factors to quantify slip velocity of cuttings, lowering the prediction error from ±20% to ±5%; and (3) a helical groove cutting removal sub with 60 m optimal spacing, enhancing local turbulence intensity by 42% to disrupt residual cuttings bed. Field validation in Well J110-8-1H demonstrated remarkable improvements: a 50% reduction in sliding friction, a 25% decrease in rotational torque, and 40% shortening of the drilling cycle. This integrated technology fills the gap in addressing the “fragmentation–colloidal stability” dilemma in shale with high clay contents, providing a quantifiable solution for safe and efficient drilling in similar continental formations. Full article

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

The pathways and mechanisms of primary hydrocarbon migration, which are still not well understood, are of great significance for evaluating both conventional and unconventional oil and gas resources, understanding the mechanisms of shale oil retention, and predicting sweet spots. To investigate the petrography, geochemistry, and pore systems of organic-rich mudstones and organic-lean sand-silt intervals in core samples from the Yanchang shale in the Ordos Basin, China, we conducted thin-section observation, X-ray diffraction, Rock-Eval pyrolysis, field emission scanning electron microscopy (FE-SEM), and porosity analysis. Sand-silt intervals are heterogeneously developed within the Yanchang shale. The petrology, mineral composition, geochemistry, type, and content of solid organic matter as well as the pore type, pore size, and porosity of these intervals differ significantly from those of mudstones. Compared with mudstones, sand-silt intervals typically have coarser detrital grain sizes, higher contents of quartz, feldspar, and migrated solid bitumen (MSB), larger pore sizes, higher porosity, and higher oil saturation index (OSI). In contrast, they have lower contents of clay minerals, total organic carbon (TOC), free liquid hydrocarbons (S₁), and total residual hydrocarbons (S₂). The sand-silt intervals in the Yanchang shale serve as both pathways for hydrocarbon primary migration and “micro reservoirs” for hydrocarbon storage. The interconnected inorganic and organic pore systems, organic matter networks, fractures, and sand-silt intervals form the hydrocarbons’ primary migration pathways within the Yanchang shale. A model for the primary migration of hydrocarbons within the Yanchang shale is proposed. Full article

In this study, we investigated the solvent performance of six heavy oils from Xinjiang, China, for coal–oil co-liquefaction (COCL). Autoclave experiments revealed that shale oil vacuum residue (SOVR) provided the best liquefaction performance. The oils were characterized using FT-IR, ¹³C-NMR, ¹H-NMR, and column chromatography, which revealed that they were mainly composed of aliphatic compounds, with minor aromatic and substituted aromatic compounds. The pyrolytic degradation quality indices (PDQIs), solubility parameter (δ_C), and polycyclic aromatic hydrocarbon content (H_A2 + H_A3) were calculated and correlated with liquefaction performance. The results showed a strong linear relationship between H_A2 + H_A3 and oil yield (R² = 0.90), and the aromatic content (AR) was also positively related to oil yield. This study suggests that AR content and H_A2 + H_A3 are effective indicators for evaluating the solvent performance of heavy oils in COCL. 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

During the early stages of drilling and completion in the Weiyuan shale gas wells, a large number of downhole materials were introduced, some of which inevitably remained in the wellbore or migrated into the reservoir. Over time, these residual materials underwent physicochemical reactions with reservoir minerals and fluids, gradually forming dense composite blockages that severely restricted the production efficiency of shale gas wells. The effectiveness of single-component unblocking agents in removing such blockages is limited. This study systematically analyzed the physicochemical properties of wellbore blockages in Weiyuan shale gas wells using refined chemical techniques. The results revealed that the main inorganic components of the blockages were Fe₃O₄ and SiO₂, while the organic components were primarily related to polymer materials from drilling and fracturing fluids. Based on the physicochemical characteristics of the blockages, a novel “organic dispersion and inorganic decomposition” unblocking strategy was proposed. Furthermore, an innovative approach that combined molecular simulation with laboratory experiments was employed to develop three unblocking fluid systems tailored to different blockage conditions: neutral, acidic, and composite. Performance evaluation showed that the composite unblocking fluid exhibited the best efficacy in treating these dense composite blockages, achieving a scale dissolution and dispersion efficiency of over 90%. Compared to the other two systems, the composite fluid demonstrated the longest penetration distance in simulated composite blockages, improving penetration by over 30%. In field applications, unblocking strategies were optimized based on whether the oil and casing were interconnected. For blocked wells without connectivity, a circulating wash method was used, while for interconnected wells, a dragging wash method was employed, ensuring efficient blockage removal. Full article

This study systematically investigates the combustion behavior and kinetic characteristics of oil shale semi-coke. Thermogravimetric analysis (TGA) experiments, combined with both model-free and model-based methods, were used to explore the thermal characteristics, kinetic parameters, and reaction mechanisms of the combustion process. The results show that the combustion process of oil shale semi-coke can be divided into three stages: a low-temperature stage (50–310 °C), a mid-temperature stage (310–670 °C), and a high-temperature stage (670–950 °C). The mid-temperature stage is the core of the combustion process, accounting for approximately 28–37% of the total mass loss, with the released energy concentrated and exhibiting significant thermal chemical activity. Kinetic parameters calculated using the model-free methods (OFW and KAS) and the model-based Coats–Redfern method reveal that the activation energy gradually increases with the conversion rate, indicating a multi-step reaction characteristic of the combustion process. The F2-R3-F2 model, with its segmented mechanism (boundary layer + second-order reaction), better fits the physicochemical changes during semi-coke combustion, and the analysis of mineral phase transformations is more reasonable. Therefore, the F2-R3-F2 model is identified as the optimal model in this study and provides a scientific basis for the optimization of oil shale semi-coke combustion processes. Furthermore, scanning electron microscopy (SEM) and X-ray diffraction (XRD) analyses were conducted on oil shale semi-coke samples before and after combustion to study the changes in the combustion residues. SEM images show that after combustion, the surface of the semi-coke sample exhibits a large number of irregular holes, with increased pore size and a honeycomb-like structure, indicating that the carbonaceous components were oxidized and decomposed during combustion, forming a porous structure. XRD analysis shows that the characteristic peaks of quartz (Q) are enhanced after combustion, while those of calcite (C) and pyrite (P) are weakened, suggesting that the mineral components underwent decomposition and transformation during combustion, particularly the decomposition of calcite into CO₂ at high temperatures. Infrared spectroscopy (IR) analysis reveals that after combustion, the amount of hydrocarbons in the semi-coke decreases, while aromatic compounds and incompletely decomposed organic materials are retained, further confirming the changes in organic matter during combustion. Full article

The geological structure of interbedded shale oil reservoirs is complex, later characterized by high reservoir heterogeneity and diverse reservoir spaces. These distinctive features are primarily attributed to their unique source–storage configuration. This paper comprehensively investigates the pore structure characteristics and controlling factors, which are beneficial for realizing efficient and sustainable resource utilization. The pore structure characteristics and main control factors of interbedded shale oil in the Heshuinan (HSN) area of the Ordos Basin are studied by analyzing thin sections and scanning them under an electron microscope, and using XRD analysis, a high-pressure mercury injection, a constant-rate mercury injection, and a nitrogen adsorption method. The influence of sedimentation and diagenesis on the pore structure is analyzed. Research shows that the interbedded shale oil reservoirs of the Triassic Chang 7 in the HSN area have an average porosity of 8.47% and an average permeability of 0.74 × 10⁻³ μm². The reservoirs are classified as typical ultra-low porosity, ultra-low permeability reservoirs. The various pore types in the study area are mainly residual intergranular pores and feldspar dissolution pores. The pores are mostly in the shape of parallel slits and ink-bottle-shaped. The pore-throat radii range from 0.02 μm to 200 μm. Sedimentation and diagenesis jointly control the pore structure in the study area. Sedimentation determines the material foundation of the study area. Diagenesis affects later pore development. Early compaction greatly reduces the intergranular pores, but the chlorite envelope reduces the influence of compaction to some extent. The compacted residual intergranular pores are further reduced by clay minerals, carbonate minerals, and siliceous minerals. Late dissolution promotes pore enlargement, which is the key to the formation of high-quality reservoirs. Furthermore, on this basis, this paper outlines the genetic mechanism of the Chang 7 high-quality reservoir in the HSN area to provide guidance for the exploration and development of interbedded shale oil and gas. Full article

The two-phase source rocks deposited during the Lower Cretaceous in the Persian Gulf Basin play a pivotal role in the regional hydrocarbon system. However, previous studies have lacked a macroscopic perspective constrained by the Tethyan Ocean context, which has limited a deeper understanding of their developmental patterns and hydrocarbon control mechanisms. To address this issue, this study aims to clarify the spatiotemporal evolution of the two-phase source rocks and their hydrocarbon control effects, with a particular emphasis on the critical impact of terrestrial input on the quality improvement of source rocks. Unlike previous studies that relied on a single research method, this study employed a comprehensive approach, including time series analysis, sequence stratigraphy, lithofacies, well logging, well correlation, seismic data, and geochemical analysis, to systematically compare and analyze the depositional periods, distribution, and characteristics of the two-phase source rocks under different sedimentary facies in the region. The goal was to reveal the intrinsic relationship between the Neo-Tethyan Ocean context and regional sedimentary responses. The results indicate the following: (1) the late Tithonian–Berriasian and Aptian–Albian source rocks in the Northern Persian Gulf were deposited during periods of extensive marine transgression, closely aligning with the global Weissert and OAE1d anoxic events, reflecting the profound impact of global environmental changes on regional sedimentary processes; (2) in the early stages of the Neo-Tethyan Ocean, controlled by residual topography, the Late Tithonian–Berriasian source rocks exhibited a shelf–intrashelf basin facies association, with the intrashelf basin showing higher TOC, lower HI, and higher Ro values compared to the deep shelf facies, indicating more favorable conditions for organic matter enrichment; (3) with the opening and deepening of the Neo-Tethyan Ocean, the Aptian–Albian source rocks at the end of the Lower Cretaceous transitioned to a shelf–basin facies association, with the basin facies showing superior organic matter characteristics compared to the shelf facies; (4) the organic matter content, type, and thermal maturity of the two-phase source rocks are primarily controlled by sedimentary facies and terrestrial input, with the Aptian–Albian source rocks in areas with terrestrial input showing significantly better quality than those without, confirming the decisive role of terrestrial input in improving source rock quality. In summary, this study not only reveals the differences in the depositional environments and hydrocarbon control mechanisms of the two-phase source rocks, but also highlights the core role of terrestrial input in enhancing source rock quality. The findings provide a basis for facies selection in deep natural gas exploration in the Zagros Belt and shale oil exploration in the western Rub’ al-Khali Basin, offering systematic theoretical guidance and practical insights for hydrocarbon exploration in the Persian Gulf and broader tectonic domains. Full article

Injecting high-pressure fluid into a reservoir rock mass will change the mechanical properties of the rock; the strength and safety of a shale well wall are also extremely critical. In order to investigate the law of variation in water-sensitive shale strength during fracturing, an experimental study on the mechanical properties of shale under high confining pressure and water–rock coupling was carried out. Taking water-sensitive shale rock as the research object, the effects of high confining pressure and water content on the mechanical properties, residual strength, and macroscopic and microscopic failure modes of shale were analyzed. The test results show that the stress–strain curve of the shale gradually shortened with the decrease in the water content in the stage of void compaction and plastic yield, and the peak of the stress–strain curve was continuously enhanced. The water content and the peak intensity exhibited a negative linear correlation. The elastic modulus and water content showed an exponentially decreasing distribution. However, as the water content increased, the decreasing rate became slower, the softening coefficient increased, and the plastic deformation increased. The research results provide basic load parameters for the strength and safety of the casing of an oil layer under fracturing conditions. Full article

To reveal the shale oil occurrence state and its controlling factors of the Jurassic Lianggaoshan Formation in the Sichuan Basin, experimental analyses, including total organic content, X-ray diffraction, low-temperature nitrogen adsorption-desorption, nuclear magnetic resonance, conventional, and multistage rock-eval, were conducted on the shale samples. The shale oil occurrence state, the amount/proportion of adsorbed/free oil, and their control factors were clarified. Moreover, the classification evaluation standard of shale oil resources was then determined. The results show that the selected shales are characterized by large oil contents. Total oil ranges from 0.08 mg/g to 10.06 mg/g (mean 2.82 mg/g). Adsorbed oil is between 0.03 mg/g and 5.66 mg/g (1.64 mg/g), while free oil spans from 0.05 mg/g to 4.94 mg/g (1.21 mg/g). The higher the total oil content, the higher the free oil content, indicating that the free oil sweet spot corresponds to the shale oil resource sweet spot. Shale oil is mainly adsorbed in organic matter; the larger TOC content results in the higher adsorbed oil content. Residual shale oil primarily occurs in pores less than 100 nm in diameter, and a higher pore volume corresponds to a higher total oil content. The shale oil enrichment resources refer to the shale with the TOC > 1.5%, S₁ > 1.5 mg/g, and S₁/TOC > 45 mg/g. This study is helpful for the prediction of shale oil resources and optimizing sweet spots in the Jurassic Lianggaoshan Formation of the Sichuan Basin. Full article

This study evaluated the potential and environmental benefits of using oil shale residue as a replacement for fine aggregate in concrete through a series of experiments. Initially, the crushing value test confirmed the oil shale residue’s value at 16.7%, meeting the load-bearing standards for fine aggregates, thus proving its viability as a complete substitute. Further, the oil shale residue was treated with a 60 mg/L concentration of Tween 80 and other surfactants for oil removal. The treated concrete specimens demonstrated excellent compressive performance and a dense internal structure. Building on this, the mechanical properties of the oil shale residue concrete were explored across different replacement ratios (from 40% to 100%), revealing an increase in compressive strength with higher replacement ratios. In the durability tests, compared to the JZ group, the oil shale residue concrete modified with desulfurization gypsum exhibited a 0.03% reduction in mass loss rate and a 10.13% reduction in relative moving elasticity modulus loss rate, particularly noticeable after 175 freeze–thaw cycles where specimens B1 to B4 exhibited no significant damage, highlighting its remarkable durability. Overall analysis indicated that using oil-removed oil shale residue as a substitute for fine aggregate in concrete, combined with desulfurization gypsum modification, not only enhances concrete performance but also significantly reduces the consumption of natural aggregates and environmental pollution, promoting resource utilization and sustainable development. Full article

Following hydraulic fracturing operations within shale reservoirs, there frequently exists a considerable volume of residual oil that remains encapsulated within the matrix, thereby impeding the singular shale well’s productivity from attaining projected yields. In pursuit of augmenting the recovery efficiency of shale oil, the industry has widely adopted a post-fracture shut-in strategy within shale oil wells. This methodology is predicated on the aspiration to escalate both the production output and the recovery factor of the oil well by leveraging the imbibition and displacement mechanisms of the fracturing fluid throughout the shut-in interval. There are many kinds of surfactants, and how to select surfactants suitable for shale reservoirs from these many surfactants has become a key issue in improving shale reservoir recovery. In this study, a new surfactant screening method for improving imbibition recovery in shale reservoirs is proposed. An interfacial tension test, contact angle test, and anti-adsorption test are carried out for the collected surfactant products, and the interfacial tension, contact angle, and anti-adsorption are gradually used as indicators. The type of surfactant is initially screened. On this basis, the static imbibition experiment of shale is made to determine the type and concentration of surfactants suitable for shale oil development. The results show that the surfactants screened by this method have the characteristics of decreasing oil–water interfacial tension, varying rock wettability, and strong anti-adsorption, which can effectively improve imbibition efficiency. The study results herein can provide technical support for optimizing shale oil surfactants and provide a new idea for improving oil exploitation in low-permeability reservoirs. Full article

The feasibility of the autothermic pyrolysis in situ conversion (ATS) process for low-grade oil shale (OS) has not been determined. In this research, the pyrolysis and combustion properties of Tongchuan OS, with a 4.04% oil yield, were systematically analyzed. The findings revealed that temperatures between 350 and 425 °C favored oil production, while temperatures from 450 to 520 °C resulted in a higher rate of gaseous generation. At 300 °C, the volume expansion and ignition coking caused by the large amount of bitumen generated resulted in severe pore plugging, which significantly increased the combustion activation energy of the residue, while the presence of substantial flammable bitumen also significantly decreased the ignition and combustion temperatures. From 300 to 520 °C, the combustion performance of residue decreases continuously. In addition, pyrolysis residues of Tongchuan exhibited a slightly higher calorific value, between 425 and 520 °C, owing to its higher fixed carbon content (10.79%). Based on the ideal temperature screening method outlined for Tongchuan OS, the recommended preheating temperature for Tongchuan OS was 425 °C, while the optimum temperature for the retorting zone should be 510 °C, considering a heat utilization rate of 40%. These findings contribute valuable insights for the application of the ATS process to low-grade OS. Full article

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. Full article