Search Results (495)

As the retrieval of unconventional oil and gas resources extends to the deep and ultra-deep domains, the issue of cement sheath failure in shale oil wellbores seriously endangers wellbore safety, making it imperative to uncover the relevant damage mechanism and develop effective assessment approaches. In response to the limitations of conventional finite element methods in representing mesoscopic damage, in this study, we determined the mesoscopic parameters of cement paste via laboratory calibrations; constructed a 3D casing–cement sheath–formation composite model using the discrete element method; addressed the restriction of the continuum assumption; and numerically simulated the microcrack initiation, propagation, and interface debonding behaviors of cement paste from a mesomechanical viewpoint. The model’s reliability was validated using a full-scale cement sheath sealing integrity assessment apparatus, while the influences of fracturing location, stage count, and internal casing pressure on cement sheath damage were analyzed systematically. Our findings indicate that the DEM model can precisely capture the dynamic evolution features of microcracks under cyclic loading, and the results agree well with the results of the cement sheath sealing integrity evaluation. During the first internal casing pressure loading phase, the microcracks generated account for 84% of the total microcracks formed during the entire loading process. The primary interface (casing–cement sheath interface) is fully debonded after the second internal pressure loading, demonstrating that the initial stage of cyclic internal casing pressure exerts a decisive impact on cement sheath integrity. The cement sheath in the horizontal well section is subjected to high internal casing pressure and high formation stress, resulting in more frequent microcrack coalescence and a rapid rise in the interface debonding rate, whereas the damage progression in the vertical well section is relatively slow. Full article

Hot-fluid injection in thermal-enhanced oil recovery (thermal-EOR, TEOR) imposes temperature-driven volumetric strains that can substantially alter in situ stresses, fracture geometry, and wellbore/reservoir integrity, yet existing TEOR modeling has not fully captured coupled thermo-poroelastic (thermo-hydro-mechanical) effects on fracture aperture, fracture-tip behavior, and stress rotation within a displacement discontinuity method (DDM) framework. This study aims to examine the influence of sustained hot-fluid injection on stress redistribution, hydraulic-fracture deformation, and fracture stability in thermal-EOR by accounting for coupled thermal, hydraulic, and mechanical interactions. This study develops a fully coupled thermo-poroelastic DDM formulation in which fracture-surface normal and shear displacement discontinuities, together with fluid and heat influx, act as boundary sources to compute time-dependent stresses, pore pressure, and temperature, while internal fracture fluid flow (Poiseuille-based volume balance), heat transport (conduction–advection with rock exchange), and mixed-mode propagation criteria are included. A representative scenario considers an initially isothermal hydraulic fracture grown to 32 m, followed by 12 months of hot-fluid injection, with temperature contrasts of ΔT = 0–100 °C and reduced pumping rate. Results show that the hydraulic-fracture aperture increases under isothermal and modest heating (ΔT = 25 °C) and remains nearly stable near ΔT = 50 °C, but progressively narrows for ΔT = 75–100 °C despite continued injection, indicating potential injectivity decline driven by thermally induced compressive stresses. Hot injection also tightens fracture tips, restricting unintended propagation, and produces pronounced near-fracture stress amplification and re-orientation: minimum principal stress increases by 6 MPa for ΔT = 50 °C and 10 MPa for ΔT = 100 °C, with principal-stress rotation reaching 70–90° in regions adjacent to the fracture plane and with markedly elevated shear stresses that may promote natural-fracture activation. These findings show that temperature effects can directly influence injectivity, fracture containment, and the risk of unintended fracture or natural-fracture activation, underscoring the importance of temperature-aware geomechanical planning and injection-strategy design in field operations. Incorporating these effects into project design can help operators anticipate injectivity decline, improve fracture containment, and reduce geomechanical uncertainty during long-term hot-fluid injection. Full article

Wellbore integrity maintenance constitutes a fundamental safety and technological challenge throughout the entire lifecycle of oil and gas wells (including production, injection, and CO₂ sequestration operations). As a critical completion phase, perforation generates a high-temperature, high-pressure shaped charge jet that impacts and compromises wellbore structural integrity. This process may induce failure in both the cement sheath body and its interfacial zones, potentially creating fluid migration pathways along the cement-casing interface through perforation tunnels. Current research remains insufficient in quantitatively evaluating cement sheath damage resulting from perforation operations. Addressing this gap, this study incorporates dynamic jet effects during perforation and establishes a numerical model simulating high-velocity jet penetration through casing–cement target–formation composites using a rock dynamics-based constitutive model. The investigation analyzes failure mechanisms within the cement sheath matrix and its boundaries during perforation penetration, while examining the influence of mechanical parameters (compressive strength and shear modulus) of both cement sheath and formation on damage characteristics. Results demonstrate that post-perforation cement sheath aperture exhibits convergent–divergent profiles along the tunnel axis, containing exclusively radial fractures. Primary fractures predominantly initiate at the inner cement wall, whereas microcracks mainly develop at the outer boundary. Enhanced cement compressive strength significantly suppresses fracture initiation at both boundaries: when increasing from 55 MPa to 75 MPa, the undamaged area ratio rises by 16.6% at the inner wall versus 11.2% at the outer interface. Meanwhile, increasing the formation shear modulus from 10 GPa to 15 GPa reduces cement target failure radius by 0.4 cm. Cement systems featuring high compressive strength and low shear modulus demonstrate superior performance in mitigating perforation-induced debonding. Full article

Offshore unconsolidated sandstone reservoirs suffer from severe sand production, which impairs wellbore stability and productivity. This study evaluates gravel packing in light-oil unconsolidated sandstone reservoirs in the Weizhou field. This paper conducts visual sand-control experiments to compare screens and gravel packs, and to quantify the effects of gravel size, packing thickness, packing density, and clay content on sand-retention behavior. On this basis, a coupled CFD–DEM model was developed to simulate sand transport and plugging within the gravel pack. Results show that gravel packing rapidly forms a stable bridging structure, reaching stabilized production 38.1% earlier than the screen and reducing sand production by 74.4%, while maintaining a stable pressure difference and limiting fine-sand breakthrough. Low-viscosity oil enhances sand carrying, increasing the stabilized pressure difference by 12% relative to water. For the low-clay fine reservoir, gravel sizes of 3–6 times the median sand size, packing thickness ≥ 25 mm, and packing density of 90–95% provide a balance between permeability and sand control. Numerical simulations identify a four-stage plugging process—initiation, surface accumulation, deep filling, and equilibrium—offering pore-scale support for the experimental observations. This study offers technical and theoretical guidance for the optimization of gravel-pack sand control in offshore light-oil unconsolidated sandstone reservoirs. Full article

Natural gas hydrates (NGHs) are a promising alternative energy source with huge global reserves, but they face significant challenges in commercial production and require more efficient exploitation methods. Based on field data from China’s first offshore NGH pilot production, this study systematically investigates the enhancement effect of boundary sealing and wellbore heating on the development of Class 1 hydrate reservoirs with five-spot wells. Numerical simulation findings illustrate that when the sealing layer thickness is 1 m and the permeability is 0.001 mD, it can effectively expand the radial propagation of pressure, promote the gas output, and significantly reduce water production. When the heating power is 100 W/m, the highest energy efficiency ratio can be achieved, which can promote dissociation and inhibit the secondary hydrate generation. The combination of two technologies shows a synergistic effect, which increases the cumulative gas production and gas-to-water ratio to 197.4% and 224.3% of the base case, respectively, achieving the optimal balance between high recovery rate and economic efficiency, which provides key insights for the effective development of Class 1 hydrate reservoirs. Full article

During deepwater drilling operations in the Baiyun block of the eastern South China Sea, high-temperature and high-pressure formation leakage was frequently encountered. Traditional plugging materials lacked adequate stability under these conditions and failed to establish reliable plugs. As the development of the Baiyun Block progressed, it was found that the formation temperature at the BY5 area well reached 182.2 °C at a depth of 4527 m. At a depth of 5206 m, the bottom-hole temperature of the well increased to 223.81 °C, and the pressure rose to 10 MPa. An urgent need has emerged to develop a plugging system capable of operating stably under high-temperature and high-pressure conditions to enhance the safety and success rate of deepwater drilling. In this study, a high-temperature-resistant polymer for controlling leakage rate, an inorganic pressure-bearing particulate material with supporting capability, and a gel that gradually solidifies under high-temperature conditions were developed. Through systematic optimization, a synergistic plugging system was established. Laboratory evaluations demonstrated that the system maintained favorable fluidity and structural integrity under high-temperature and high-pressure conditions, rapidly constructed stable plugging layers across fractures of varying widths, and withstood high differential pressures while resisting backflow-induced erosion. The results indicate that the system exhibits significant plugging performance and strong potential for engineering application, providing reliable technical support for deepwater oil and gas development. Full article

Efficient cutting transport is crucial in challenging drilling environments such as ultra-short-radius horizontal wells. Flexible drill pipes, designed for complex wellbore geometries, offer a potential solution. However, the cutting transport behavior within them remains poorly understood. To improve wellbore cleaning and drilling efficiency, this study investigates the underlying transport mechanisms. The investigation employs a coupled CFD-DEM approach to model cutting transport in flexible drill pipes. This method combines fluid dynamics and particle motion simulations to analyze the interaction between drilling fluid and cuttings, evaluating the impact of factors such as rotational speed, flow rate, and fluid properties on cleaning efficiency. The results indicate that increasing the flow rate at a constant rotational speed significantly reduces the cutting concentration. Nevertheless, beyond a critical flow rate of 1.5 m/s, further increases yield diminishing returns in cleaning efficiency due to transport capacity saturation. In contrast, increasing the rotational speed at a fixed flow rate of 1.42 m/s has a less pronounced effect on cutting transport and increases frictional torque, thereby reducing energy efficiency. Higher rotational speeds primarily enhance the suspension of fine cuttings, with minimal impact on larger particles. Additionally, the rheological properties of the drilling fluid play a key role. A higher flow behavior index increases viscosity near the wellbore, improving transport performance. Conversely, a higher consistency index enhances the fluid’s carrying capacity but increases annular pressure drop, which imposes greater demands on pump capacity. Thus, optimal drilling performance requires balancing pressure losses and cleaning efficiency through comprehensive parameter optimization. Full article

Commercialization of natural gas hydrates still faces challenges. Before large-scale production becomes feasible, efficient exploitation methods must be continuously explored. Based on field data from China’s first trial production, a novel five-spot radial wells system design, combined with boundary sealing and wellbore heating, is proposed to improve production capacity. Simulation results indicate that boundary sealing can inhibit water invasion and concentrate energy, thereby promoting hydrate dissociation. The radial laterals significantly expand the drainage area and increase pressure propagation. Wellbore heating can accelerate the dissociation of hydrates while inhibiting secondary hydrate generation. The combined application of these technologies has significantly increased the cumulative gas production and gas-to-water ratio to 244.9% and 134.6% of the base case, respectively, providing theoretical references for the effective exploitation of Class 1 hydrate reservoirs. Full article

Ultra-deep fault-controlled carbonate reservoirs exhibit strong heterogeneity, multi-scale fracture–cavity systems, and complex geological controls, which render conventional analytical well testing methods inadequate. This study proposes a geological model-based numerical well testing framework incorporating adaptive meshing, noise reduction, and machine-learning-assisted inversion. A multi-step workflow was established, including (i) single-well geological model extraction with localized grid refinement to capture near-wellbore flow behavior, (ii) pressure data denoising and preprocessing using low-pass filtering, and (iii) surrogate-assisted parameter inversion and sensitivity analysis using particle swarm optimization (PSO) to construct diagnostic type curves for different fracture–cavity control modes. The methodology was applied to different wells, yielding inverted fracture permeabilities ranging from approximately 140 to 480 mD and cavity permeabilities between about 110 and 220 mD. Results show that the numerical well testing method achieved an 85.7% interpretation accuracy, outperforming conventional approaches. Distinct parameter sensitivities were identified for single-, double-, and multi-cavity systems, providing a systematic basis for production allocation strategies. This integrated approach enhances the reliability of reservoir characterization and offers practical guidance for efficient development of ultra-deep carbonate reservoirs. Full article

As a type of multilateral wells, fishbone wells have the advantages of expanding oil drainage areas and increasing single well controlled reserves. However, there exists obvious productivity interference between branches of fishbone wells. In order to study the influence of fishbone wellbore structural parameters on productivity interference between branches, the method of water-electricity simulation experiments was adopted in this paper. The concepts of productivity interference coefficient and pressure propagation coefficient were proposed. The dependence of the productivity interference coefficient on wellbore morphological parameters was quantified. Research shows that the productivity interference coefficients of fishbone wells increase with the increase in the number of branches and decrease with the increase in branch length and branch angle. The productivity interference phenomenon between branches is caused by pressure interference. Increasing branch spacing by changing morphological parameters is the key to controlling productivity interference. The research results verify the productivity prediction model of fishbone wells and they also have important guiding significance for reasonable well placement and optimization design. Full article

Supercritical carbon dioxide (CO₂) is a promising working fluid for geothermal energy extraction due to its superior heat extraction capacity and high fluidity within reservoirs. However, significant thermal energy is lost during transportation along the production well. This study develops a mathematical model coupling heat transfer and CO₂ compressibility to investigate strategies for improving heat transfer efficiency from the reservoir to the surface. The influence of mass flow rate (20 kg/s; 25 kg/s and 30 kg/s) and outlet back pressure (8 MPa; 9 MPa and 10 MPa) on system performance is evaluated. Results indicate that the amount of geothermal energy delivered to the surface increases linearly with mass flow rate. Compared to water, CO₂ exhibits a 65.5% greater temperature drop along the wellbore but reduces the pressure drop by 50%. A lower outlet back pressure is recommended to enhance both heat transfer and operational safety. The model offers valuable insights into assessing the geothermal potential of depleted high-temperature gas reservoirs. Full article

The separate-layer gas injection technology is a key means to improve the effect of refined gas injection development. Currently, the measurement and adjustment of separate injection wells primarily rely on manual experience and automatic measurement via instrument traversal, resulting in a long duration, low efficiency, and low qualification rate for injection allocation across multi-layer intervals. Given the different CO₂-containing natural gas injection rates across different intervals, this paper establishes a coupled flow model of a separate-layer gas injection wellbore–gas distributor–formation based on the energy and mass conservation equations for wellbore pipe flow, and develops a solution method for determining gas nozzle sizes across multi-layer intervals. Based on the maximum allowable gas nozzle size, an optimization method for multi-layer collaborative allocation of separate injection wells is established, with minimum wellhead injection pressure and layered injection allocation as the optimization objectives, and the opening of gas distributors for each layer as the optimization variable. Taking Well XXX as an example, the optimization process of allocation schemes under different gas allocation requirements is simulated. The research shows that the model and method proposed in this paper have high calculation accuracy, and the formulated allocation schemes have strong adaptability and minor injection allocation errors, providing a scientific decision-making method for formulating refined allocation schemes for separate-layer gas injection wells, with significant theoretical and practical value for promoting the refined development of oilfields. Full article

Deep and ultra-deep drilling operations commonly encounter fractured and fracture-vuggy formations, where weak wellbore strength and well-developed fracture networks lead to frequent lost circulation, presenting a key challenge to safe and efficient drilling. Existing diagnostic practices mostly rely on drilling fluid loss dynamic models of single fractures or simplified discrete fractures to invert fracture geometry, which cannot capture the spatiotemporal evolution of loss in complex fracture networks, resulting in limited inversion accuracy and a lack of quantitative, fracture-network-based loss-dynamics support for bridge-plugging design. In this study, a geologically realistic wellbore–fracture-network coupled loss dynamic model is constructed to overcome the limitations of single- or simplified-fracture descriptions. Within a unified computational fluid dynamics (CFD) framework, solid–liquid two-phase flow and Herschel–Bulkley rheology are incorporated to quantitatively characterise fracture connectivity. This approach reveals how instantaneous and steady losses are controlled by key geometrical factors, thereby providing a computable physical basis for loss-zone inversion and bridge-plugging design. Validation against experiments shows a maximum relative error of 7.26% in pressure and loss rate, indicating that the model can reasonably reproduce actual loss behaviour. Different encounter positions and node types lead to systematic variations in loss intensity and flow partitioning. Compared with a single fracture, a fracture network significantly amplifies loss intensity through branch-induced capacity enhancement, superposition of shortest paths, and shortening of loss paths. In a typical network, the shortest path accounts for only about 20% of the total length, but contributes 40–55% of the total loss, while extending branch length from 300 mm to 1500 mm reduces the steady loss rate by 40–60%. Correlation analysis shows that the instantaneous loss rate is mainly controlled by the maximum width and height of fractures connected to the wellbore, whereas the steady loss rate has a correlation coefficient of about 0.7 with minimum width and effective path length, and decreases monotonically with the number of connected fractures under a fixed total width, indicating that the shortest path and bottleneck width are the key geometrical factors governing long-term loss in complex fracture networks. This work refines the understanding of fractured-loss dynamics and proposes the concept of coupling hydraulic deviation codes with deep learning to build a mapping model from mud-logging curves to fracture geometrical parameters, thereby providing support for lost-circulation diagnosis and bridge-plugging optimisation in complex fractured formations. Full article

The Zhu I Depression in the Pearl River Estuary Basin is a major oil and gas enrichment area, with complex lithology, mainly mudstone, fine sandstone and siltstone, strong heterogeneity, and extensive development of abnormal high pressure, making it difficult to predict formation pressure. The effective stress coefficient (ESC) is an important parameter in formation pressure prediction and formation stress estimation, which is usually obtained by experiments and by the empirical function formulas of ESC and porosity. However, the calculation accuracy of these empirical formulas is often affected by lithology and critical porosity, and their application in the whole area or multi-lithology formations is limited. In addition, shear wave velocity data are limited by cost and technical conditions in practical logging applications. Therefore, based on the Gassmann equation and the approximation of P-wave modulus and volume modulus, this study realizes a multi-lithology ESC estimation method using P-wave velocity, density, and porosity, and applies it to the logging of the study block. The dynamic ESC along the wellbore direction is obtained and the logging dynamic ESC estimation model is corrected to verify the reliability of the method. The results show that the logging-derived ESC is mainly distributed in the range of 0.3~0.8, while the average ESC measured in the laboratory is between 0.5 and 0.6. The ESC of the sandstone layers with high porosity is relatively large and that of the mudstone layers with low porosity is small. In the absence of shear wave velocity, this method can effectively estimate the ESC and further predict formation pressure, which plays an important role in oil exploration and development. Full article

With the advancement of petroleum engineering, the increasing complexity of formations and unpredictable conditions make wellbore pressure prediction more challenging. Accurate bottom-hole pressure (BHP) prediction is crucial for the safe and stable development of oil and gas reservoirs. Solving the partial differential equations (PDEs) governing fluid flow is key to this prediction. As deep learning becomes widespread in scientific and engineering applications, physics-informed neural networks (PINNs) have emerged as powerful tools for solving PDEs. However, traditional PINNs face challenges such as insufficient fitting accuracy, large errors, and gradient explosion. This study introduces MetaPress, a novel physics-informed neural network structure, to address inaccurate formation pressure prediction. MetaPress incorporates a meta-learning-based embedding function that integrates spatial information into the input and forget gates of Long Short-Term Memory networks. This enables the model to capture complex spatiotemporal features of flow problems, improving its generalization and nonlinear modeling capabilities. Using the MetaPress architecture, we predicted BHP under single-phase flow conditions, achieving an error of less than 2% for L2. This approach offers a novel method for solving seepage equations and predicting BHP, providing new insights for subsequent studies on reservoir fluid flow processes. Full article