Search Results (91)

In response to the problems of deteriorating quality of newly added reserves of deep and ultra-deep shale oil, significant differences in well efficiency among similar sweet spots, and difficulty in converting resources and production capacity, a deep and ultra-deep shale oil resource conversion evaluation method is proposed based on the entire process of shale oil development. Based on the production dynamics during the initial stage of production, we establish oil well classification standards for deep and ultra-deep shale oil and obtain two types of shale oil development unit classification standards. We construct well efficiency response indicators for development units, well efficiency index and well efficiency index, quantitatively characterizing the comprehensive well efficiency response within the development unit. We construct a production capacity evaluation system for the development of sweet spots that integrates resource utilization, technological economy, and business management. We use the fuzzy comprehensive evaluation method to obtain sweet spot evaluation scores and grades and quantitatively characterize the differences in production capacity construction for the development of sweet spots. On this basis, the “Resource–Productivity Matching Five Step Method” is proposed, which couples the sweet spot evaluation results with the well efficiency index to obtain the final score and evaluation results of resource conversion. The instance application of the M development unit shows that its overall resource conversion efficiency is not high, with only one type of area being a good match and the other areas being basic matches. The evaluation results are relative. This method achieves the integration of “sweet spot advantage (comprehensive score)—well efficiency response (well efficiency index)—conversion effect (final score)” and can identify false matches, improve the objectivity and reliability of evaluation results, and provide a scientific basis and technical support for shale oil block screening, well location deployment, construction planning and other research. Full article

Accurate oil–water interface measurement in small transparent test tubes is important for subsequent volume readout in laboratory analysis. However, manual observation and conventional vision-based methods are easily affected by illumination variation, wall stains, and bubbles, while deep learning detectors alone usually provide only coarse semantic perception. To address this issue, a coarse-to-fine framework is proposed for robust oil–water interface measurement. In the coarse stage, YOLOv8n is used to provide semantic constraints for subsequent processing. In the fine stage, a Fisher-discriminative chromatic-weighted brightness feature is constructed from RGB information, where the RGB weights are derived from the Fisher criterion to enhance oil–water chromatic separability rather than using fixed grayscale or empirical channel weights. This feature is then fused with a SobelY-based vertical-gradient feature to improve interface localization. A stain-aware row-aggregation strategy with effective-pixel compensation is further introduced to suppress artefact interference. The validated interface position is finally converted into a volume readout, with additional correction for bubble-induced bias. The framework was validated on sampled frames from a complete shale-oil core pressing process conducted under mixed-lighting conditions. Stage-wise evaluation and ablation results indicate that the proposed design improves readout stability under stains, bubbles, and illumination variation, achieving a mean absolute error of 0.0159 mL and keeping the maximum error below 0.03 mL in the current experimental setup. Full article

Organic-rich shales in China’s deep-water shelf environments possess significant shale gas resource potential. To investigate the reservoir development characteristics of deep-water shelf shale, 143 shale samples were collected from the low-maturity Xiamaling Formation in the Zhangjiakou area and the high to over-mature Wufeng–Longmaxi Formations in the southeastern margin of the Sichuan Basin. Basic analytical methods, including X-ray diffraction (XRD), total organic carbon (TOC) analysis, rock pyrolysis, and solid bitumen reflectance measurements, were employed alongside advanced reservoir characterization techniques such as field-emission scanning electron microscopy (FE-SEM), low-pressure CO₂/N₂ physisorption, mercury intrusion porosimetry (MIP), and focused ion beam scanning electron microscopy (FIB-SEM). This study focuses on the petrographical, geochemical, and microscopic pore structure characteristics of these marine shales. The results indicate that the mineral composition of deep-water shelf sedimentary shale is dominated by quartz, clay minerals, feldspar, calcite, dolomite, apatite, and pyrite, with quartz being the most abundant. The Xiamaling Formation shales, at low maturity, are relatively rich in siliceous components, while the high to over-mature Wufeng and Longmaxi Formation shales are richer in carbonate components. The kerogen type of organic matter in the Xiamaling Formation is primarily Types II₁ and II₂, whereas the Wufeng–Longmaxi shales are predominantly Types I and II₁. TOC content is highest in the Wufeng Formation, followed by the Longmaxi Formation, with the Xiamaling Formation exhibiting the lowest TOC levels. Pore development in the Wufeng and Longmaxi shales is significantly superior to that in the Xiamaling shales. Overall, the Wufeng and Longmaxi Formations demonstrate more favorable pore characteristics and hydrocarbon generation potential compared to the Xiamaling Formation. The Wufeng and Longmaxi Formations’ shales will be the key targets for shale gas exploration in the future. The findings of this study contribute to the understanding and development of theories of marine shale gas accumulation in China and hold both theoretical and practical significance for the efficient and rational exploitation of shale oil and gas resources. Full article

Oil shale in situ conversion provides an important pathway for developing medium- to deep-buried, low-grade, and thin oil shale resources. Among the available approaches, the in situ conversion technology triggered by the topochemical reaction method, hereafter referred to as the TSA method, induces local oxidation reactions of pyrolysis residuals, fixed carbon, and reactive organic matter through preheating and oxygen-containing gas injection. The released in-formation heat then supports continued kerogen cracking and reaction-front propagation. This review summarizes the TSA method from a process-oriented perspective, linking reaction mechanisms, engineering controls, geochemical process identification, pilot tests, economic–environmental constraints, and scale-up evaluation. Existing studies indicate that the TSA method has formed a technical chain involving reaction initiation, heat/reaction-front propagation, oil and gas recovery, and process monitoring. Pilot tests provide evidence for operational feasibility, but not yet for full commercial feasibility. Thermal simulation results show that oil and gas generation and expulsion become significant above ~350 °C, and that 375–425 °C can be used as an important reference window for temperature control rather than a fixed optimum for all oil shale reservoirs. Geochemical indicators can provide complementary constraints for identifying reaction progress, especially when calibrated with produced oil and gas. Further development should focus on fracture-network control, heat-transfer enhancement, oxygen-supply regulation, multi-well coordination, equipment reliability, economic evaluation, groundwater protection, and CO₂ emission accounting. These issues are critical for advancing the TSA method toward larger-scale, low-carbon, and well-regulated application. Full article

Lithofacies characterization of organic-rich shales constitutes the essential foundation for sweet spot evaluation in lacustrine shale oil systems. This study targets the first member of the Upper Cretaceous Qingshankou Formation (K₂qn¹) in the southern Songliao Basin. Based on systematic core description of 908 m of core from eight cored wells, combined with 123 total organic carbon (TOC) measurements, 47 whole-rock X-ray diffraction (XRD) analyses, 29 major- and trace-element analyses, and six maceral identification datasets (≥500 organic particles counted per sample), together with conventional well log data from 75 wells (measured vitrinite reflectance $R_o$ = 0.34%–1.38%, mean = 0.94%), we establish an integrated lithofacies classification scheme incorporating the TOC as a classification parameter and develop a log-based lithofacies identification workflow. Eight lithofacies are recognized within K₂qn¹ across the study area, of which three are organic-rich. The high-TOC clay-rich mudstone-grade laminated shale deposited in a deep lake setting (LF-A; mean TOC = 3.18%, clay minerals ≥50%, formed under saline and strongly anoxic-euxinic conditions; mean paleosalinity = 8.06‰, V/(V + Ni) = 0.75–0.97) and the high-to-moderate-TOC felsic mudstone-grade laminated shale deposited in a semi-deep lake setting (LF-B; mean TOC = 2.18%, felsic minerals ≥50%, formed under brackish-to-saline anoxic conditions; mean paleosalinity = 5.10‰, V/(V + Ni) = 0.70–0.84) constitute the dominant organic-rich lithofacies. From Y1 to Y3, the cumulative thickness of organic-rich lithofacies expands from approximately 10 m to approximately 25 m. Areally, the mean TOC increases systematically from 1.65% in the southern delta-front zone to 2.74% in the northern deep lake center, reflecting an enrichment pattern governed primarily by paleoproductivity and modulated jointly by preservation conditions and terrigenous dilution. The log-based identification workflow, established by integrating a modified ΔlogR method with multiple linear regression, achieves a TOC prediction coefficient of determination of $R^2=0.86$ in the calibration well and lithofacies identification accuracies ranging from 64.6% to 94.0% in validation wells, with the highest performance observed in the delta-front facies zone. These results provide quantitative constraints for the genetic interpretation and log-based identification of organic-rich lacustrine shales. Full article

The Qingshankou Formation (K₂qn) represents a key interval for lacustrine shale oil accumulation in the Songliao Basin. However, the spatial heterogeneity of organic-rich shales and their controlling mechanisms remain poorly constrained. Here, we investigate the Qijia–Gulong and Sanzhao sags by integrating drilling, well-log, geochemical, and mineralogical data to systematically evaluate source rock characteristics and their dominant controls. Based on well-log data from 442 wells, total organic carbon (TOC) was continuously predicted using an improved ΔlogR method. In addition, mineral compositions and lithofacies distributions were quantitatively characterized for representative wells in the eastern and western sags by combining X-ray diffraction (XRD) data with a deep residual shrinkage network (DRSN) model. The results reveal a dual depocenter pattern within K₂qn across the study area. The Qijia–Gulong Sag is characterized by thicker mudstone successions (30–600 m), higher sedimentation rates, and stronger stratigraphic continuity, whereas the Sanzhao Sag exhibits comparatively thinner deposits (30–300 m). Significant differences are also observed in organic matter type and thermal maturity: the Qijia–Gulong Sag is dominated by Type II₁ kerogen with higher maturity (R_o = 1.0%–1.5%), while the Sanzhao Sag mainly contains Type I kerogen with relatively lower maturity (R_o = 0.8%–1.3%). Despite this, TOC values in the Sanzhao Sag are markedly higher than those in the Qijia–Gulong Sag, with average values of 3.34% and 2.19%, respectively. These differences reflect the coupled control of palaeoenvironmental conditions and terrigenous input on organic matter enrichment. Elevated salinity and enhanced water-column stratification in the Sanzhao Sag promoted the development of reducing conditions favorable for organic matter preservation, resulting in higher TOC contents. In contrast, although the Qijia–Gulong Sag experienced high sedimentation rates and developed thick shale sequences, strong terrigenous input and dilution effects limited organic matter enrichment, while simultaneously leading to higher thermal maturity. Consequently, two distinct enrichment modes are identified in the study area: a “high-salinity stratification–efficient preservation” mode and a “high maturity–thick shale development” mode, which together govern the spatial heterogeneity of shale oil resources. Full article

A climatic transition from arid to humid conditions occurred during the deposition of the Permian Pingdiquan Formation in the Shishugou Sag, Junggar Basin, Northwest China. This study reconstructs the paleoenvironmental evolution and organic matter (OM) enrichment mechanisms recorded in six stratigraphic intervals, with emphasis on the two oil shale units formed during the transgressive system tracts (TST1 and TST2). Geochemical, elemental, and biomarker data reveal that climate, salinity, and redox conditions fluctuated significantly and jointly governed OM enrichment, with paleoclimate acting as the primary background control by regulating lake hydrology, salinity, and preservation. During the early stage (SQ1), an arid climate prevailed, the TST1 oil shale formed during a transient freshening event in a deep stratified lake. Dominant algal productivity and minimal terrigenous input favored excellent preservation, yielding the highest TOC and superior hydrocarbon potential. In contrast, during the humid stage (SQ2), the TST2 oil shale was deposited in a moderately deep, weakly reducing, and slightly saline lake. Although preservation was less efficient, enhanced primary productivity under humid conditions compensated for OM loss, producing abundant but slightly lower quality OM. These results establish two depositional models, an arid freshening model (TST1) and a humid salinization model (TST2). Both transient freshening under arid conditions and salinization during humid periods facilitated the accumulation of organic-rich source rocks through different balances between productivity and preservation. This highlights the complex response of lacustrine source rock development to climatic variability. The occurrence of similar organic-rich source rocks can be anticipated under comparable paleoenvironmental transitions, particularly in saline lakes characterized by frequent fluctuations in water salinity and paleoclimate. Full article

Shale oil in continental faulted basins of eastern China, represented by Jiyang Depression, has achieved breakthroughs in productivity. However, challenges such as deep burial, high formation pressure, and poor crude oil mobility pose significant obstacles to achieving high and stable production. Hydraulic fracturing is required to form complex fracture networks for stimulation. Factors such as the lamellar structure of shale, geomechanical conditions, and fracturing operation parameters affect fracture propagation. Therefore, this study establishes a numerical model of fracture propagation in lamina-developed shale using the discrete element software PFC2D 6.0, conducts simulation analysis of fracture propagation laws under in situ stress conditions, and characterizes the influence of lamellar structure and construction technology on fracture complexity. The results show that, for lamina-developed shale, the initiation pressure decreases with increasing injection rate; as the difference between the two horizontal principal stresses increases, hydraulic fractures gradually tend to propagate toward the direction of the maximum principal stress; under high injection pressure, a complex network of short fractures is formed, while, under low injection pressure, the length of the main fracture is prompted to increase. High density (9–10 strips/100 mm) enhances lamina penetration, favoring extension toward maximum horizontal principal stress; low density (4–5 strips/100 mm) strengthens lamina guidance, with fractures propagating along laminae near the injection hole. This research clarifies the mechanisms of fracture initiation and propagation in laminated shale, providing theoretical and technical support for optimizing hydraulic fracturing designs. Full article

Horizontal well drilling is the mainstream technology for developing deep oil and gas resources. Engineering practice has demonstrated that hydraulic oscillators can solve the problem of the backing pressure of pipe strings and improve drilling efficiency. However, the design of excitation parameters for hydraulic oscillators is currently largely based on idealized friction models and does not fully consider the nonlinear characteristics of friction between the drill string and the formation, resulting in a lack of quantitative basis for parameter selection under different operating conditions. A series of laboratory friction tests was conducted to systematically characterize the dependence of interfacial friction behavior on sliding velocity across different combinations of drill string materials, drilling fluid systems, and rock lithologies. Based on the experimentally determined velocity–friction relationships, a drill string dynamic model incorporating a hydraulic oscillator was developed in which nonlinear frictional effects at the interface were explicitly represented. Using this modeling framework, parametric simulations were carried out to examine how variations in excitation amplitude and excitation frequency influence drag reduction performance under diverse operating conditions. The simulation results indicate that the contribution of drill string material to overall drag reduction effectiveness is comparatively limited, whereas drilling fluid type plays a dominant regulatory role. Oil-based drilling fluids significantly enhance drag reduction performance relative to water-based systems and exhibit greater responsiveness to adjustments in excitation parameters. Rock lithology exerts a pronounced influence on the effectiveness of drag reduction. When water-based drilling fluids are used, the overall performance ranks from highest to lowest as limestone, shale, and sandstone. In contrast, under oil-based drilling fluid conditions, the relative ordering shifts to shale, followed by sandstone, and then limestone. Excitation amplitude is the dominant parameter in enhancing drag reduction capability, and in most cases, its incremental effect exceeds that of excitation frequency; however, under certain specific operating conditions, increasing the excitation frequency can provide additional drag reduction benefits. Based on the above findings, a hydraulic oscillator excitation parameter design method was proposed that matches drilling conditions and formation characteristics by distinguishing between different drilling fluid environments and lithologies, with amplitude as the primary control parameter and frequency as a supplementary parameter. This method provides a theoretical foundation for the design of output parameters of hydraulic oscillators operating under diverse working conditions. Full article

Lacustrine shales are key targets for shale oil exploration, yet the quantitative characterization of their complex and heterogeneous pore systems remains a significant challenge, constraining effective reservoir evaluation and development. This study investigates lacustrine shales from the Second Member of the Kongdian Formation by integrating N₂ adsorption, mercury intrusion porosimetry, and focused ion beam scanning electron microscopy with fractal analysis. A Mamba-based deep learning model was applied to improve two-dimensional (2D) pore segmentation, and three-dimensional (3D) pore surface point clouds were reconstructed for 3D surface fractal characterization to reduce artifacts associated with conventional 3D reconstruction. The results indicate that the pore system is dominated by inorganic pores, mainly irregular interparticle pores and dissolution pores, while organic pores are scarce. Pore sizes are predominantly concentrated in the range of 5 to 200 nm. Adsorption-derived fractal dimensions exhibit systematic lithofacies differences, with D₁ and D₂ averaging around 2.47 and 2.56, respectively. These trends are consistent with the 3D pore surface fractal dimension derived from pore surface point clouds (mean 2.48), which supplements the bulk statistical results with direct geometric quantification of surface roughness. The heterogeneity of the pore system is influenced by the coupled effects of mineral composition, organic matter content, and diagenesis. Specifically, the enrichment of clay minerals and dolomite increases the irregularity of pore morphology and results in higher fractal dimensions. In contrast, samples enriched in feldspars and calcite are supported by a rigid granular framework that corresponds to lower 3D surface complexity. Ultimately, these fractal dimensions effectively quantify pore network complexity and reservoir heterogeneity in the Kong 2 shales, offering quantitative support for reservoir characterization and lacustrine shale oil exploration. Full article

Phosphatic bioclastic laminae distributed along bedding planes have been recently discovered within the Jurassic Lianggaoshan Formation shale in the eastern Sichuan Basin. However, their characteristics and potential as shale oil and gas reservoirs remain unclear. To reveal their microscopic pore structure characteristics and development model, this study focuses on samples of phosphatic bioclastic laminae obtained from drilling cores in the Fuxing area of eastern Sichuan. A multi-scale analytical approach was employed, integrating micro-X-ray fluorescence spectroscopy (μ-XRF), field emission scanning electron microscopy (FE-SEM), nitrogen adsorption, nuclear magnetic resonance (NMR), and geochemical analyses. The results indicate that the phosphatic bioclastic laminae are primarily composed of apatite and calcite and formed in a low-energy, anoxic, semi-deep to deep lacustrine environment. They exhibit an average total porosity of 4.84% and an average TOC of 1.99 mg/g. It is 14.7% and 17.8% higher than the clay laminae, and 255.9% and 109.57% higher than the calcareous bioclastic laminae. The pore system is dominated by mesopores and macropores, encompassing multiple pore types including dissolution pores, interparticle pores, interlayer pores, organic matter-hosted pores, and micro-fractures. Notably, a well-connected nanometer-scale pore network developed within fish bone fragments contributes substantially to the storage space. These intervals integrate high organic matter richness with superior reservoir properties, demonstrating typical “source-reservoir integration” characteristics. Their pore structure is synergistically regulated by sedimentary–diagenetic processes, with a core mechanism of primary biogenic pore foundation–late diagenetic dissolution enhancement–micro-fracture connectivity. This study systematically elucidates, for the first time, the reservoir formation mechanism of the phosphatic bioclast-rich laminae in the Lianggaoshan Formation. It confirms their potential as “geological-engineering” dual sweet spots for shale oil and gas exploration, providing a new basis for sweet spot prediction and exploration deployment targeting similar phosphatic bioclastic laminae in the Sichuan Basin and analogous regions. Full article

The second member of the Paleogene Funing Formation (E₁f₂) in the Gaoyou Sag, Subei Basin, is a promising shale oil target, yet its organic matter (OM) enrichment mechanisms remain poorly understood. This study integrates petrological and multi-proxy geochemical analyses to investigate lithofacies, paleoenvironmental evolution, and OM enrichment of the E₁f₂ shale. Seven lithofacies types transition upward from laminated (submembers III to V) to blocky structures (submembers I to II). TOC and hydrocarbon potential increase stepwise from bottom to top, with Type II OM dominant. The paleoenvironment evolved from arid, saline, and semideep lacustrine with strong terrigenous input (V); through semiarid to arid, brackish to saline, and semideep to deep lacustrine with peak productivity (III to IV); to humid to semiarid, fresh to brackish, and deep lacustrine with minimal terrigenous input (I to II). Anoxia persisted throughout. OM enrichment is jointly controlled by paleoclimate, water depth, paleosalinity, and terrigenous input, with paleoproductivity subordinate and redox conditions insignificant. Critically, terrigenous input exerts a non-linear dual control, defining an optimal window where nutrient supply, dilution, and oxidation are balanced. The highest OM enrichment in submembers I to II results precisely from terrigenous input falling within this window. This challenges productivity/preservation-dominant paradigms and provides a new framework for shale oil sweet-spot prediction in saline lacustrine basins. Full article

The First Member of the Cretaceous Qingshankou Formation (K₂qn¹) in the Gulong Sag, Songliao Basin, contains vast shale oil resources conventionally interpreted as deposits of suspension settling in a quiescent, anoxic deep-lacustrine environment. However, this static “deep-lake” model fails to account for the strong lithofacies heterogeneity and high-energy sedimentary records observed in recently acquired core data. This study reconstructs the sedimentary dynamics of the K₂qn¹ shale through high-resolution core description, thin-section petrography, and flow-loop hydrodynamic simulations. We identify abundant sedimentary structures diagnostic of high-energy combined flows, including Hummocky Cross-Stratification (HCS), Swaley Cross-Stratification (SCS), erosional scour surfaces, and large-scale tabular intraclasts (up to 40 mm). Hydrodynamic simulations, utilizing an “equivalent substitution” method, demonstrate that the Minimum Vertical Suspension Velocity (V_mf) required to transport these large intraclasts exceeds 1.0 m/s. This threshold is 1 to 5 orders of magnitude higher than theoretical values derived from classical settling equations, confirming that the paleolake bottom was frequently perturbed by high-velocity storm-driven currents. Consequently, we propose an “Intermittent High-Energy Deposition Model,” wherein background suspension settling was punctuated by episodic storm events. We argue that these high-energy events facilitated organic matter enrichment through a “Transport-Burial Pump” mechanism, which operated in concert with the chemical stratification associated with the Oceanic Anoxic Event 2 (OAE2) to enable rapid physical burial and sealing of organic matter. These findings challenge the traditional fine-grained sedimentological paradigm and suggest that storm-reworked intervals—characterized by enhanced brittleness and hydrodynamic winnowing—constitute the primary “sweet spots” for lacustrine shale oil exploration. Full article

Natural fractures are critical controls on shale oil storage and migration in the Upper Triassic Chang 7 Member of the Ordos Basin. However, conventional identification techniques—such as mud-invasion correction, R/S rescaled range analysis, and radioactive element analysis—are time-consuming, computationally intensive, and highly dependent on specialized logging data, limiting their large-scale application. To overcome these challenges, this study develops a multi-modal deep neural network that integrates conventional well logs with borehole imaging data. A coupled convolutional neural network (CNN) and deep neural network (DNN) architecture was constructed to predict fracture occurrence, dip angle, and aperture. The model achieves dip-angle prediction accuracies of 98.82% for both training and testing datasets, while aperture prediction accuracies reach 95.97% and 95.91%, respectively. Predicted dip angles are concentrated between 65° and 80°, deviating by less than 0.48° from measured values, whereas apertures fall mainly within 0.5–4.5 cm, with deviations below 0.21 cm except in extreme cases. The CNN branch effectively extracts spatial features from imaging logs, while the DNN branch captures nonlinear relationships in conventional logs. The integrated framework substantially improves fracture characterization accuracy and efficiency. This study provides a scalable and cost-effective approach for rapid fracture identification based on conventional logging data, reducing reliance on specialized imaging logs and supporting integrated geological and engineering evaluations in shale oil reservoirs. Full article

The western region of the Tarim Basin is a typical deep and ultra-deep oil and gas reservoir with complex geological conditions in China. This area includes a thick salt–gypsum layer, high-pressure brine layers, and other formations with high pressures and a complex pressure system. These geological features present challenges such as a high risk of drilling fluid contamination by formation fluids, the deep burial of subsalt reservoirs, high temperatures, and difficulty in designing drilling fluids. In this paper, by systematically screening and optimizing key additives, a diesel oil-based drilling and completion fluid system resistant to 220 °C ultra-high temperatures with a density of 2.60 g/cm³ was developed. The overall performance was evaluated. Utilizing an independently developed high-temperature emulsifier (BZ-PSE), an organically modified lithium silicate viscosity modifier (BZ-CHT), and compounded fluid loss reducers (BZ-OLG/BZ-OSL), the system maintained excellent rheological stability (yield point > 4.3 Pa) and filtration control capacity (HTHP fluid loss < 4.8 mL) even after aging at 220 °C. The system demonstrated a resistance to contamination by 30–50% composite brines, 15% salt–gypsum cuttings, and 10% cement, proving its capability to effectively handle extremely thick mud shale, salt–gypsum layers, and high-pressure brine. Field tests were conducted in wells GL 3C, DB X, Boz 13X, and Boz 3X. The results indicated that the high-temperature, high-density diesel oil-based drilling fluids and completion fluids can effectively address the technical challenges posed by wellbore instability in thick salt–gypsum layers, high-pressure brine invasion, and performance degradation under ultra-high temperature conditions, providing reliable technical support for the safe and efficient drilling of similar complex formations. Full article