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The distribution characteristics of carbon isotopes in sedimentary organic matter are often used as indicators for oil-source correlation, determination of organic matter origins, and paleoenvironmental analysis. However, when organic matter reaches the over-mature stage, cracking processes can lead to isotopic fractionation, resulting in anomalies such as carbon isotope reversal. This phenomenon, particularly in deep and ultra-deep petroleum systems, has long been a key and challenging issue in hydrocarbon geology research. This study examines the carbon isotopic distributionsof various solid and liquid organic materials from source rocks and reservoirs in the Anyue Gas Field, the central Sichuan Uplift, Sichuan Basin, based on existing data and relevant research. The findings indicate that paleo-oil reservoirs experienced thermal alteration, causing the early-formed liquid hydrocarbons in both source and reservoir layers to crack into gaseous hydrocarbons, residual liquid hydrocarbons, and pyrobitumen. The pyrobitumen can be categorized into in-situ pyrobitumen in source rocks and reservoir pyrobitumen. In present-day source and reservoir layers, an overall inversion is observed where kerogen has lower δ¹³C values than liquid hydrocarbons, along with a localized inversion in which saturated and aromatic hydrocarbons show higher δ¹³C values than non-hydrocarbon components and asphaltenes. Additionally, the δ¹³C values of reservoir pyrobitumen are lower than those of both kerogen and liquid hydrocarbons. Comprehensive analysis of relevant data and simulation experiments indicates that carbon isotopic enrichment during hydrocarbon cracking is the primary cause of the observed isotopic inversions in both source and reservoir samples. After high-temperature cracking, the residual liquid hydrocarbons derived from original liquid hydrocarbons in source rocks and paleo-reservoirs exhibit an overall increase in δ¹³C values of approximately 4‰. Due to varying thermal exposure in source rocks and paleo-reservoirs, the extent of δ¹³C increase differs among various group components of the residual liquid hydrocarbons. Although reservoir pyrobitumen largely inherits the isotopic signature of the original crude oil, thermochemical sulfate reduction (TSR) during its formation may also contribute to its anomalously light carbon isotopic values. In summary, the carbon isotopic inversions observed in the source and reservoir layers of the study area are primarily attributed to carbon isotopic fractionation during liquid hydrocarbon cracking—a phenomenon that may be common in deep and ultra-deep petroleum reservoirs that have experienced high temperatures.
Carbonate fractured-vuggy reservoirs in the Middle-Lower Ordovician of the Tarim Basin are strongly controlled by deep strike-slip faults. Their pronounced heterogeneity has become a key challenge to the efficient exploitation of ultra-deep oil and gas resources. In this study, a representative strike-slip fault within a carbonate outcrop on the northwestern margin of the basin was selected as the research target. By integrating multiple analytical approaches, including field structural measurements, petrographic thin-section observations, high-pressure mercury intrusion porosimetry, and rock physics experiments, the study systematically characterizes the multi-scale heterogeneity of fault-controlled carbonate fractured-vuggy reservoirs and identifies their dominant controlling factors. The development patterns of high-quality reservoir zones are also summarized. At the macro scale, fracture distribution along the fault strike is highly uneven, with the overlap segments exhibiting the highest fracture densities. Within these segments, the boundary fault zones are characterized by small breccias with high roundness, indicating strong interconnectivity. Along the dip direction, fault core zones are distinguished by abundant large fractures and vugs with only minor vein filling. These zones have porosities approximately 4~6 times those of the damage zones and compressive strengths only 25%~50% as high, making them prime sites for high-quality reservoir development. Vertically, zones of high porosity and low strength alternate with sealing layers, resulting in a discrete vertical distribution of high-quality reservoirs. At the micro scale, fault cores exhibit diverse pore types, including intracrystalline pores, intercrystalline pores, semi-filled microfractures, and microvugs. In addition, they display high surface porosity, large pore aspect ratios, numerous interconnected pore nodes, and well-developed throat channels, which together contribute to their significantly higher permeability compared with the damage zones. On this basis, the Lorenz curve method is combined with the entropy weight method, which is applied for the first time to evaluate the heterogeneity of fault-controlled carbonate fractured-vuggy reservoirs. The evaluation results indicate that these reservoirs exhibit overall strong heterogeneity, with the micro scale showing a higher degree than the macro scale. This heterogeneity is primarily governed by the coupling of fault structures and diagenetic fluid-driven dissolution-precipitation processes. Integrating these findings, three types of “sweet spot” zones are identified within the fault-controlled reservoirs: boundary fault zones in the overlap segments along the fault strike, fault core zones along the dip, and dolomitic limestone intervals in the vertical sequence. This study fills a gap in understanding the heterogeneity of fault-controlled carbonate fractured-vuggy reservoirs and provides theoretical support for improving the recovery efficiency of ultra-deep oil and gas resources.
The tight conglomerate reservoir in the Junggar Basin exhibit complex multi-scale pore-throat structures, which obscure the dominant controls on fluid occurrence, hinder reservoir classification, and complicate the quantitative evaluation of graded reserves. To clarify the relationship between microscopic pore-throat characteristics and fluid occurrence states and achieve effective evaluation of highly heterogeneous tight conglomerate reservoirs, this study takes the Upper Urho Formation (P3w) in the CO2 flooding pilot area of the Mahu 1 well block as an example, conducting comprehensive workflow of “pore-throat structure-fluid occurrence-reservoir classification-graded reserves”. Integrating methods including cast thin sections, high-pressure mercury intrusion, and nuclear magnetic resonance (NMR) logging were integrated to characterize the lithomechanical properties and pore-throat structure parameters of different sub-layers within the main reservoir interval. Grey relational analysis further identified movable-to-total porosity (weight 0.913) and clay mineral content (weight 0.805) as the key factors controlling effective oil saturation. Based on NMR T2 spectral morphology, three-component index, IB value, and permeability, a classification standard dividing the reservoir into three types (Ⅰ~Ⅲ) was established, A methodology for calculating tiered pore-volume reserves was proposed, achieving a systematic evaluation from pore-throat structure to classified reserves. Results indicate that in the main producing interval P3w22, the lower sublayer exhibits significantly better reservoir quality than the upper. The lower section has a micron-scale pore proportion of 25.48%, an average permeability of 5.59 mD, and an effective oil saturation 15%~20% higher than the upper section. Nano-scale pores (<100 nm) represent the dominant storage space in the pilot area, containing reserves of 784.3 thousand tons (61.7% of the total). From the perspective of reservoir classification, type Ⅰ reservoirs, with the highest proportion of micron-scale pores (25.48%) and excellent oil-bearing capacity. Type II reservoirs show reduced micron-scale pores and moderate oil-bearing capacity; Type III reservoirs suffer from poor oil retention due to strong confinement by nanopores. The results of this study reveal the controlling factors of fluid distribution, establish a classification standard and tiered reserve characterization system for tight conglomerate reservoirs constrained by pore-throat structures, and provide theoretical support and technical support for the optimal selection of CO2 flooding target zones and the identification of “sweet spots” in the Mahu conglomerate oilfield.
To address the pronounced heterogeneity of deep-ultra-deep fault-controlled fractured-vuggy carbonate reservoirs in the Tarim Basin and the limited understanding of reservoir distribution and key controlling mechanisms across fault segments, this study investigates the FI6 strike-slip fault zone in the Fuman area. By integrating seismic-attribute analysis, log-based fracture identification, drilling data comparisons, and field outcrop observations, we characterize segment-dependent deformation and the internal fault-zone architecture, and elucidate how the strike-slip fault system controls reservoir development. Results show that the FⅠ6 fault zone is subdivided into linear, en-echelon fractured, left-stepping compressional, and horsetail segments. Segment-scale variations in stress regime and secondary fault arrangements control the scale and connectivity of fractures and vugs, producing a clear spatial coupling between deformation intensity and reservoir quality. Compared with weakly deformed segments, highly deformed domains show an increase in average porosity from approximately 2% to 5% and in average reservoir thickness from about 270 m to 645 m, indicating a significantly improved reservoir quality. By comparing the structural characteristics of the fault core and damage zone, we propose six representative models of internal reservoir architecture: (1) large isolated reservoirs dominated by the fault core; (2) fracture-dominated reservoirs governed by the damage zone; (3) core-zone composite fracture-cavity reservoirs; (4) intersection-controlled localized accumulations; (5) superimposed compressional breccia-cavity composites in overlapping segments; and (6) grid-like fracture-network reservoirs in horsetail terminations. Each model differs significantly in spatial morphology, pore connectivity, and accumulation mechanisms, reflecting the dominant influences of fault segmentation, stress evolution, and internal structural variation on carbonate reservoir development. These results clarify the mechanistic links between strike-slip differential deformation and reservoir heterogeneity and provide a practical basis for 3-D modeling and development planning in structurally complex carbonate settings.
With the continued expansion of oil and gas exploration into deep and ultra-deep formations, the refined characterization of reservoir anisotropy and viscoelastic behavior has become an urgent and critical challenge. Systematic investigation of the seismic response of viscoelastic anisotropic formations is essential for improving the accuracy of reservoir prediction. In this study, an equivalent petrophysical model incorporating a multi-scale fracture system is introduced to elucidate the mechanisms by which reservoir physical parameters influence P-wave attenuation and dispersion. Subsequently, by enforcing stress-strain continuity at each interface and applying the composite matrix method, reflection coefficients are recursively computed for layered media and convolved with a source wavelet to generate synthetic seismic records. A forward-modeling formulation for viscoelastic anisotropic media is derived from the analytical solution of the one-dimensional wave equation. Traditional AVO forward modeling typically assumes that the media above and below a reflection boundary are infinite half-spaces, that is, the single-interface assumption. The proposed method overcomes this limitation by enabling a comprehensive description of amplitude variations with both incidence angle and azimuth, while simultaneously accounting for fluid-induced dispersion and attenuation as well as propagation effects such as interbed multiple reflections, mode conversions, and transmission losses. This leads to a more realistic representation of seismic-wave propagation in complex media. Finally, the developed viscoelastic anisotropic forward-modeling framework is applied to both simplified layered models and well-log-constrained models to investigate seismic responses under varying reservoir conditions. The results clarify how reservoir parameters such as oil saturation and fracture density influence seismic signatures, providing new theoretical support and technical guidance for fracture characterization and fluid prediction in complex reservoirs.
Seismic shear (SS) waves have been employed in hydrocarbon exploration for decades, providing valuable information on lithology and anisotropy that effectively complements compressional (PP) wave observations. However, even under depth-domain imaging conditions, PP- and SS-wave data often cannot be precisely aligned due to differences in velocity model accuracy, imaging errors, and inconsistencies in horizon interpretation. Such mismatches can introduce significant uncertainty into joint inversion, reduce the reliability of geological interpretation. To address this issue, this paper proposes a depth-domain PP-wave and SS-wave data matching method by using well and horizon constraints. Firstly, the joint depth relationships are established through well-to-seismic calibration of PP-and SS-waves on Kirchhoff prestack depth migration sections. These relationships are then used, under horizon constraints, to construct an initial stretching scale model for SS-waves, providing a global matched field that ensures consistency of key stratigraphic horizons across PP- and SS-wave sections. Although this step corrects large-scale misalignment, residual errors remain due to limitations in the stretching scale model and cumulative inaccuracies. Finally, a dynamic time warping (DTW) algorithm is applied to local nonlinear optimization. Application to field seismic data from the Sanhu area demonstrates that the proposed method effectively corrects stratigraphic misalignment, improves waveform similarity between PP- and SS-wave sections, and provides a more reliable basis for reservoir characterization and fluid interpretation.
This study focuses on the carbonate-rich shale of the lower Sha-3 to upper Sha-4 sub-members in the Dongying Sag of the Jiyang Depression within the Bohai Bay Basin. Based on the discrete element simulation and acoustic emission monitoring test methods, a numerical model for shale direct shear tests was constructed. The study systematically revealed the crack propagation laws and energy evolution characteristics under different bedding dip angles, and established a quantitative relationship between bedding dip angle, stress state, and the number of micro-fractures. The research results show that: (1) During direct shearing, high shear stress induces en echelon tensile fractures with an approximate 45° angle. After expansion, these fractures connect with shear fractures developed along the bedding to form a macroscopic fracture zone. As the bedding dip angle increases, the fracture zone gradually transitions from a stepped shape to a “zigzag” shape, exhibiting significant heterogeneity. (2) The shale fracture mechanism is dependent on the bedding dip angle: under low dip angles, shear fracture along the bedding is dominant; as the dip angle increases, the dominant fracture mechanism gradually shifts to matrix tensile-shear composite fracture. (3) The initiation stress of fractures is relatively low, and its variation with the bedding dip angle is not obvious; however, the damage stress and peak stress of fractures increase first and then decrease with the increase of the dip angle, reaching their peaks within the range of 40° to 50°. (4) Based on acoustic emission monitoring, it is found that crack propagation can be divided into three stages: initiation, rapid expansion (contributing 85% of the total number of cracks), and slow expansion. Tensile cracks account for 82.6%, while shear cracks (accounting for 17.4%) are mainly distributed along the bedding. (5) A comprehensive comparison of numerical simulation results, shale core fracture characteristics, and laboratory direct shear test results reveals similar fracture propagation laws, including shear fractures developed along the bedding plane and tensile fractures that obliquely cut (or penetrate) the bedding. The bedding dip angle is a key factor controlling the shale fracture development pattern, directly affecting the fracture propagation direction, complexity, and reconstruction volume. The findings of this study provide a theoretical basis for explaining the genetic mechanism and development pattern of natural fractures in continental shales, and also offer scientific support for the prediction of natural fractures in shale oil and gas exploration and development, which is of great significance for improving shale oil recovery efficiency and ensuring operational safety.
With the promotion of the strategy of reducing costs and increasing efficiency in oilfields, unsteady water injection has gradually become a key technology to improve the development effect of water flooding. In order to solve the problems of unclear mechanism and unclear injection-production parameters of unsteady water injection and production, the mechanism and mechanism of unsteady water injection and oil displacement were revealed through indoor visualization experiments, numerical simulation, seepage signal processing, seepage mechanics theory, etc., the key factors of unsteady water injection reservoir screening were proposed, and a differentiated injection-production parameter determination method was constructed considering the heterogeneity of the reservoir. The results show that the unsteady water injection is mainly driven by the positive and negative pressure difference, supplemented by capillary force. Reservoir heterogeneity coefficient, water cut, and injection-production cycle are the main controlling factors affecting the development effect. Unsteady water injection should consider the heterogeneity of the reservoir and design differentiated injection-production parameters in order to play an effective role in oil flooding. The research results have been applied to typical low-permeability and high-water-cut reservoirs, and the development results have been very good, which proves the reliability of the method, and the method established in this study can provide theoretical and methodological support for the popularization of unsteady water injection technology.
In the Haiba block of the Zhaotong demonstration area, shallow shale gas reservoirs are characterized by shallow burial depth, low formation pressure, and large variation in formation dip angle. The flowback process during well testing in these reservoirs is marked by a long gas breakthrough time, a high gas breakthrough flowback rate, and low stabilized gas testing rates. Improper flowback can lead to wellbore proppant settling, liquid loading, and loss of fracture volume, requiring an optimized flowback strategy to ensure safety and efficiency. This study presents a systematic analysis of flowback data from 71 wells in this block, identifying three distinct flowback stages: pure liquid flowback, gas breakthrough, and stabilized gas flowback. Using a fracture compression model and rate-transient analysis, the variations in effective fracture volume and fracture half-length under different flowback strategies were examined. The results show that a fast flowback strategy can cause an irreversible loss of up to 30% of the effective fracture volume, whereas a slow flowback strategy can reduce this loss to about 12%. To minimize this irreversible fracture loss, key flowback issues and controlling factors for these shallow shale gas wells were addressed. The well-opening pressure was determined by analyzing the effective stress within fractures. A wellbore proppant settling model and a fracture proppant flowback model were developed, yielding the critical flow rate in the wellbore required to carry proppant and the critical flow rate in fractures that triggers proppant flowback. Based on multiphase flow theory, the minimum bottomhole pressure for fluid unloading and the critical gas rate for liquid lifting were also determined. Accordingly, a comprehensive optimization strategy was proposed, encompassing appropriate well opening timing, wellbore sand cleanout, proppant flowback prevention, and assurance of fluid drainage, and the flowback optimization diagram was developed. Field application results indicate that this diagram enables a synergistic optimization of fracturing effectiveness and production efficiency: under similar reservoir conditions and stimulation measures, the estimated ultimate recovery increased by 20%. This study marks a transition of flowback management from an empirical approach to a quantitative one, and the proposed critical criteria and optimization diagram have broad applicability, providing a technical reference for flowback optimization in other unconventional oil and gas wells.
To investigate the triaxial compression creep deformation behavior and failure mechanisms of shale, this study conducted stepwise incremental loading creep tests on Wufeng Formation shale of Changning under confining pressures of 10 MPa, 30 MPa, and 50 MPa. The characteristics of axial, radial, and volumetric creep curves were analyzed. Combining computed tomography (CT) and scanning electron microscopy (SEM) techniques, the macroscopic and microscopic creep failure mechanisms of shale were systematically examined. A damage model was employed to fit and predict the long-term creep behavior of shale. The results indicate that: Volumetric creep effectively characterizes the evolutionary features of shale creep, with creep crack initiation stress and damage stress threshold corresponding to approximately 60% and 80% of peak strength, respectively. Shale creep failure is predominantly governed by microcrack initiation and coalescence, forming spatially distributed shear fracture networks characterized by shear-compaction bands and branched cracks. Multiple subparallel fractures develop within the shear-compaction bands, while extensive branching cracks readily form in surrounding regions. The damage model accurately predicts the long-term creep behavior of shale. Parameter A, associated with loading stress and elastic modulus, serves as the primary controlling factor for creep. This research can be applied to the analysis of the influence of shale creep on wellbore stability and artificial fracture closure during the drilling and fracturing processes of shale oil and gas reservoirs.
Rate of penetration (ROP) prediction is of great significance to drilling engineering and can provide important reference basis for drilling optimization, resource allocation, safety guarantee. In recent years, artificial intelligence has sparked a new round of intelligent transformation, promoting the intelligent transformation and upgrading of drilling engineering and giving rise to a large number of new ROP prediction methods. However, there is still a lack of systematic summary and analysis of these new ROP prediction methods at present. This paper, through systematic research and refinement of the main ROP prediction models and methods at home and abroad, summarizes and expounds the development background and theoretical principles of three types of ROP prediction methods: explicit ROP equation, numerical simulation, and artificial intelligence model. It also deeply analyzes the key technical problems and challenges faced by various ROP prediction methods in practical applications at present. It is also pointed out that the ROP prediction method integrating mechanism and data is an important direction to break through the existing bottlenecks and also the mainstream trend of future technological development. Based on this, combined with the development trend of intelligent drilling and the main bottlenecks of the ROP prediction model, five future development directions are proposed: ① Automated and intelligent drilling equipment; ② A dedicated mechanism and data fusion model for ROP prediction; ③ Environmental response mechanism of ROP prediction model based on embodied intelligence, swarm intelligence, reinforcement learning and online learning; ④ A general ROP intelligent prediction model based on large models and transfer learning algorithms; ⑤ Closed-loop optimization of ROP prediction model based on scientific knowledge discovery.
The conical polycrystalline diamond compact (PDC) cutter demonstrates significant advantages in deep hard rock formations due to its excellent impact resistance, wear resistance, and efficient rock-breaking capabilities. To further enhance its rock-breaking efficiency in deep hard rock conditions, systematic optimization of the rock-breaking parameters of the conical PDC cutter is required. This paper focuses on the penetration-cutting combined rock-breaking process of the cutter during actual drilling, establishes a numerical calculation model for the conical PDC cutter breaking granite, and designs an orthogonal experimental scheme to conduct numerical simulations. Based on the results of the orthogonal experiments, the stepwise regression method is employed to fit and analyze key rock-breaking parameters such as cutting force, penetration ability, and mechanical specific energy. Subsequently, a multi-objective optimization method based on the non-dominated sorting genetic algorithm is applied to optimize and select the geometric parameters (cutter diameter, cone apex angle, cone apex radius) and operational parameters (inclination angle, weight on bit) of the conical PDC cutter. The research results indicate that, under the conditions of this study, the optimal geometric parameter combination for the conical PDC cutter is a bit diameter of 16 mm, a cone apex angle of 60°, and a cone apex radius of 1 mm, while the optimal operational parameter configuration is a bit inclination angle of 36° and a weight on bit of 925.65 N. The optimized mechanical specific energy is reduced by 10.99% compared to the initial combination. This study can provide theoretical and practical guidance for the optimization design of conical PDC bits.
Driven by the “dual carbon” strategy, nuclear energy is increasingly recognized as a vital component of the energy mix due to its low-carbon and high-efficiency advantages. As the key raw material for nuclear power, the green extraction of uranium is of great significance. In-situ leaching (ISL) has emerged as a mainstream method for uranium extraction owing to its environmentally friendly and efficient nature. However, low-permeability uranium deposits present significant challenges during ISL, such as poor lixiviant flow and low uranium recovery rates. As a mature permeability enhancement technique, hydraulic fracturing can effectively create fracture networks through the injection of fracturing fluids, thereby improving formation permeability and enhancing lixiviant flow, which ultimately increases uranium recovery efficiency. This paper systematically reviews various ISL processes and their applicability, and thoroughly analyzes the mechanisms and current research status of advanced hydraulic fracturing technologies, including multi-stage fracturing, diversion fracturing, intelligent fracturing, acid fracturing, foam fracturing, and supercritical CO2 fracturing. Based on the resource characteristics and extraction demands of low-permeability uranium deposits, this study proposes a synergistic application of ISL and hydraulic fracturing technologies. It further explores how hydraulic fracturing can enhance formation permeability and lixiviant efficiency. A development pathway integrating multiple technologies and intelligent optimization is suggested to achieve high-efficiency resource recovery and minimized environmental risks, providing robust support for the green and sustainable development of uranium mining.
Due to the influence of shale reservoir characteristics and special seepage mechanisms, hydraulically fractured horizontal wells are commonly used for shale oil development. Production prediction is an important prerequisite for the optimization of fracturing schemes and the evaluation of economic indicators. However, commonly used production prediction methods still have limitations. Therefore, an intelligent post-fracturing production prediction method for fractured horizontal wells based on physical constraints and Fourier Neural Operator (FNO) is proposed to address the above issues. First, a mathematical model for fluid flow in fractured horizontal wells was established to derive typical solution of transient production rate. Validation using the Unsteady Production Analysis (RTA) module within commercial software confirmed high consistency between the model-generated and RTA transient production data. Subsequently, production data across diverse parameter ranges, generated from this validated seepage model, served as the FNO training dataset. Second, an FNO network was constructed and trained. Results demonstrate exceptional generalization ability, with coefficients of determination (R²) exceeding 0.99 for both training and validation sets. Finally, taking Well H1 in the Gulong shale oilfield as an example, the prediction of its oil production for the next two years was conducted.The specific steps are as follows: (1) The actual production data, geological data, and fracturing construction data of the well were collected, and the input parameters were obtained combined with well test interpretation; (2) The daily oil production of Well H1 was predicted using RTA and FNO methods respectively; (3) The two prediction methods were compared, and it was found that the prediction results of the FNO network are highly consistent with those of RTA (the coefficient of determination R² of discrete points is 0.95), which proves the accuracy and reliability of the FNO network prediction results. Moreover, the FNO network is more efficient and much faster in speed than RTA (FNO: 1-2 seconds, RTA: 600 seconds). In addition, we evaluated different intelligent production prediction models and compared the training errors of the FNO model with those of the Bi-LSTM, LSTM, and CNN models on the same dataset. The results show that the FNO model has the smallest error on the validation set and the strongest generalization ability. Therefore, the post-fracturing production prediction method for fractured horizontal wells based on the FNO network is expected to provide theoretical support for the optimization of hydraulically fractured shale oil wells and economic evaluation contributing to the efficient development of oil and gas reservoirs.
High pressure water jet technology has been widely used in oil and gas well descaling and unblocking because of its advantages of high efficiency, cleanliness and low cost. With the gradual development of oil and gas exploration and development to deep and ultra-deep depths, the application depth of water jet technology has increased significantly, and the unblocking effect of jet tools becomes worse under the condition of high confining pressure in deep wells. Although researchers have conducted extensive studies on jet flow fields and jet performance under confining pressure, the research methods remain relatively limited. Furthermore, as experimental confining pressures are typically confined to below 30 MPa, the mechanism by which high confining pressure affects jet application efficacy remains unclear. Aiming at the key problem of poor application effect of jet descaling and unblocking under high confining pressure, this paper uses the self-developed confining pressure jet comprehensive test system to carry out rock-breaking and axial dynamic pressure experiments under constant flow rate condition of confining pressure 0~100 MPa, analyzes the influence law of high confining pressure on jet rock-breaking effect and impact force. The influence mechanism of high confining pressure on the unblocking effect of water jet is revealed by combining the basic theory of water jet. Application recommendations are proposed for the jet unblocking under high confining pressure conditions in deep wells. Results: Keep the flow rate and jet distance constant, the rock-breaking depth, rock-breaking volume and jet impact force all decrease with the increase of confining pressure, and the decreasing trend decelerates with increasing confining pressure. From normal pressure to 100 MPa, the rock-breaking depth decreases by about 72%, the rock-breaking volume decreases by about 90%, and the jet impact force decreases by about 50%~60%. The decrease of jet axis dynamic pressure is due to the joint action of nozzle cavitation and the “damping effect” caused by high confining pressure environment. The main reason for the poor application effect of high confining pressure water jet is the decrease of jet impact force under confining pressure. To achieve high-efficiency jet unblocking under high confining pressure in deep wells, it is recommended to enhance jet performance under such downhole conditions and to implement a combined unblocking approach that integrates jetting with mechanical or chemical methods. This research is expected to provide a fundamental theoretical support for enhancing the application effect of water jet technology in descaling and unblocking under high confining pressure conditions in deep wells.
The integrity of cement sheath plays a decisive role in ensuring the safe and efficient production of oil and gas wells. However, the micro-cracks inside the cement sheath make the interlayer isolation fail with the further development of the oil field. The state of cement sheath at a certain measuring point or at a certain moment is provided by traditional detection methods, which cannot meet the needs of the whole well section real-time monitoring. Distributed acoustic optical fiber sensing provides a new method for real-time monitoring of fluid leakage in micro-cracks of cement sheath. In this paper, the data of fluid leakage under different leakage sizes, leakage locations and leakage flow rates are obtained based on the distributed optical fiber monitoring wellbore integrity experimental platform. The over-subtraction factor is introduced into the traditional spectral subtraction noise reduction method, which effectively solves the negative value problem of the spectral subtraction process. The time-frequency domain characteristics of the leakage signal are extracted by combining the Short-Time Fourier Transform and the Continuous Wavelet Transform to determine the leakage location. Then, the relationship between fluid leakage flow and acoustic energy is determined by calculating the power spectrum distribution and sound pressure level of the signal. Finally, a feature recognition method based on Convolutional Neural Network (CNN) and Bidirectional Gated Recurrent Unit (BiGRU) is proposed to achieve accurate classification of leakage conditions. The results show that the improved spectral subtraction effectively suppresses broadband noise and impulse noise in the low frequency region (0-100 Hz), and the suppression amplitude reaches 100 dB to 120 dB. The acoustic energy captured by the fiber is positively correlated with the fluid leakage, and the flow rate does not change the frequency distribution characteristics, but only changes the peak value of the frequency. It is found that the CNN-BiGRU model has high accuracy and good generalization ability, which effectively identifies the spatial and temporal features of the signal. The information of interlayer isolation failure of cement sheath is effectively obtained by distributed acoustic sensor, which has certain guiding significance for cementing operation.
To address the challenges of polymer-induced plugging and reservoir damage caused by drilling and completion fluids, a novel nanocarrier-based immobilized enzyme plug-removal agent was developed in this study. α-Amylase was covalently immobilized on aminated nano-silica particles, resulting in a structurally stable biocatalyst with uniform particle size (~183 nm) and enhanced catalytic efficiency. Key preparation parameters, including enzyme-to-carrier ratio and crosslinker concentration, were systematically optimized. Comparative characterizations were conducted to analyze the molecular structure and binding mechanisms of the native and immobilized enzyme systems. Mechanistic studies have revealed that amylase undergoes a dehydration condensation reaction with the primary amine groups on the surface of aminated nano-silica, resulting in the formation of a Schiff base structure and achieving the covalent immobilization of amylase on the surface of the nanoparticles. Laboratory simulation experiments demonstrated that the developed plug-removal agent exhibited rapid and efficient removal of polymer blockage within API filter cakes and artificial sandpack, increasing the filtrate backflow volume to approximately 120 mL, with an average removal efficiency exceeding 90%. Under high-temperature (95 °C) and 3.5 MPa conditions, the permeability recovery reached 75.62%, significantly outperforming the pure enzyme formulation. The plug-removal mechanism of the novel biological enzyme-based plug-removal agent mainly involves the enzymatic hydrolysis of α-1,4 or α-1,6 glycosidic bonds within polymers. This process cleaves long-chain molecules into short-chain oligosaccharides or monosaccharides, leading to a significant reduction in viscosity and ultimately achieving efficient plug removal in the near-wellbore zone and flowback of wellbore fluids. Additionally, the novel biological enzyme-based plug-removal agent can be easily recovered through simple centrifugation from polymer degradation products, thereby demonstrating potential for multiple recycling and reuse. This work provides a novel strategy and technical solution for enhancing the adaptability and stability of enzyme-based agents for oilfield applications in complex reservoir environments.
The Waste Oil-Based Drilling Fluids (WOBDF: 8#, 10# and 20#) from drilling platform in Nanhai Oilfield have high solid content, viscosity and density, and are difficult to be recovered, transported and recycled. The on-site use of high-speed centrifugation and thermal desorption methods cannot meet the requirement for the solid content in WOBDF, and conventional flocculants also cannot effectively remove harmful solid particles from WOBDF. In this paper, tetraethyl silicate and nano-Fe3O4 were used as raw materials, and methyl acrylate was used as graft monomer to prepare magnetic nano-cores. Then Michael addition reaction was carried out with 1,3-propanediamine and triethylenetetramine, respectively. Thus, two flocculants with magnetic cores and hyperbranched structures were successfully prepared (with 1,3-propanediamine as the end capping agent for flocculant-1, with triethylenetetramine as the end capping agent for flocculant-2). The molecular structures of the flocculants were determined by FT-IR and elemental analysis. Then, the coagulation centrifugation method was used to investigate the effects of two types of hyperbranched coagulants on the solid content, density, and viscosity of WOBDF. The results show that when the dosage of flocculant is 2.5wt%, the harmful solid removal rates of flocculant-1 for 8#, 10# and 20# drilling fluids are 82.75%, 62.30% and 70.56% respectively, and the solid content of 8#, 10# and 20# drilling fluids after treatment is was 5.21%, 15.34%, and 14.43%. The removal rates of harmful solids from 8#, 10# and 20# drilling fluids by flocculant-2 are 81.06%, 59.13% and 69.48% respectively, and the solid content of 8#, 10# and 20# drilling fluids after treatment is 5.72%, 16.63% and 14.96% respectively. After treatment, the densities of the three drilling fluids are 0.86~1.16 g·cm-3; The apparent viscosity and plastic viscosity are 52~90 mPa·s. The flocculation mechanism is related to the adsorption performance of its hyperbranched molecular structure besides charge neutralization and adsorption bridging. The treated WOBDF meets the requirements of drilling platform for offshore waste drilling fluid: the solid index of 8# drilling fluid (which has been thermal desorptioned) is 5%~7%, and the solid index of 10# drilling fluid and 20# drilling fluid (which has not been treated) is 10%~18%, which provides technical methods for the treatment of other WOBDF.
With the increasing demand for natural gas, the stable operation and safety of the natural gas pipeline network system need to pay more and more attention. Reliability management, as a further refinement of integrity management, provides a more comprehensive evaluation and management system for the functional status of both local and overall system components. It can promote the safe and stable operation of large-scale natural gas pipeline networks. Reliability allocation is an indispensable component of reliability management. By allocating system reliability indicators to each unit and clarifying the reliability requirements for each unit, it can provide reliability assurance and guidance for the operation management and maintenance of natural gas pipeline network system. But no effective reliability allocation method has been proposed for the natural gas pipeline network system with complex topology. According to the structure and process characteristics of the natural gas pipeline network system, the analytic hierarchy process (AHP) is improved to propose the hierarchical reliability allocation method for the complex structure natural gas pipeline network system in this work. Based on the functional level of “pipeline network system-pipeline system-unit”, the hierarchical model of the natural gas pipeline network system is established. The importance of supply security and the severity of consequence have been incorporated as influence factors for system gas supply reliability. Through quantitatively evaluating the factors affecting the reliability of system gas supply, the reliability allocation index of the natural gas pipeline network system is allocated to each unit step by step, to determine the reliability allocation plan for complex structure natural gas pipeline network systems. Finally, the proposed method is applied to an actual natural gas pipeline network system. Results indicate that the value of reliability allocation for compressor station units is lower than that for adjacent pipeline segment units. The value of reliability allocation for pipeline segment units is related to the distance from the demand point. Pipeline A exhibits the highest reliability requirements, with relatively balanced unit reliability allocation values and fewer critical gas supply impact units. Pipeline B has the lowest overall reliability requirements. Pipelines C and D are similar, featuring significant variations in unit reliability allocation values and a large number of critical gas supply impact units. This study proposes a hierarchical reliability allocation method suitable for complex structured natural gas pipeline systems, which improves the theoretical system of pipeline system reliability and provides the scientific basis for enhancing the reliability of pipeline systems.
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