Search Results (89)

In managed pressure drilling (MPD), wellbore flow states cannot be obtained in real time, so kick intervention decisions rely on the empirical judgment of engineers, which introduces a significant lag. The central hypothesis of this study is that fusing a physics-constrained transient two-phase flow model with real-time surface measurements through data assimilation can reconstruct the unobservable downhole flow state and, on this basis, enable quantitative and earlier prediction of the safe intervention timing than empirical judgment alone. To this end, this paper proposes a method for real-time inversion of wellbore flow states and safety intervention timing prediction based on the Ensemble Kalman Filter (EnKF). Using a transient wellbore gas–liquid two-phase flow model as the EnKF model operator, the method continuously assimilates real-time casing pressure, standpipe pressure (SPP), and pit gain data. This process dynamically corrects model prediction bias while maintaining multiphase flow physical constraints. Thus, the method achieves high-precision dynamic inversion of wellbore pressure profiles and gas holdup distributions. On this basis, the authors use the inverted states as initial conditions to calculate safety casing pressure with the multiphase flow model. The method then predicts intervention timing by combining three trigger conditions: safety casing pressure, pit gain, and the density difference between the inlet and outlet. The authors validated the method using kick scenarios from Well L and Well Z in the Shunbei block. The results showed that the mean absolute errors (MAEs) for casing pressure inversion were 0.113 MPa and 0.135 MPa, respectively. The MAEs for SPP were 1.324 MPa and 0.954 MPa. The MAEs for pit gain were 0.174 m³ and 0.114 m³. The inverted spatiotemporal distribution of gas holdup reflected the entire process of gas migration and expansion in the wellbore. Prediction results for intervention timing showed that the method issued early warning signals approximately 53 min and 29 min earlier than actual field operations. This method provides a quantitative decision-making basis with safety redundancy for MPD field operations. Full article

Deep unconventional oil and gas reservoirs are critical to hydrocarbon exploration and development in China. However, their complex geological and petrophysical features, including high temperature, high pressure, high salinity, multiple pressure systems, and intricate pore–fracture structures, make them highly susceptible to formation damage during drilling, completion, stimulation, and production. Effective reservoir protection is therefore essential for minimizing damage and improving development efficiency. This paper systematically reviews recent advances in reservoir protection for deep unconventional reservoirs, with a focus on evaluation methods and protective materials. Laboratory evaluation methods, including permeability recovery, nuclear magnetic resonance, pressure decay, and spontaneous imbibition, together with field-based approaches such as well testing and production decline analysis, are summarized and assessed for their applicability to complex damage characterization. Major damage mechanisms, including liquid-phase trapping, solid invasion, sensitivity damage, stress sensitivity, and wettability alteration, are analyzed with emphasis on working fluid–reservoir interactions under multi-field coupling conditions. Recent progress in protective materials is also reviewed, covering polymer-based materials such as gel sealing agents, delayed-swelling hydrogels, water-/oil-soluble temporary plugging agents, and film-forming polymers, as well as ultrafine CaCO₃ and fiber-based materials. In addition, related protection technologies, including temporary plugging, film-forming fluid-loss control, underbalanced drilling, and low-damage completion fluids, are discussed. Existing models developed for conventional sandstone reservoirs are insufficient for deep unconventional systems. Future research should prioritize integrated evaluation and protection methods tailored to deep tight, shale, and fractured–vuggy carbonate reservoirs. This review provides a basis for understanding complex damage mechanisms, developing functional protective materials, and advancing integrated reservoir protection technologies for the efficient development of deep unconventional resources. Full article

Fractured–vuggy carbonate reservoirs are characterized by highly discrete storage structures, and the number, spatial distribution, and volume of cavities strongly affect well-test responses and reservoir development decisions. This study develops a PEBI-grid finite-volume implementation of a wave–seepage-coupled model for pressure-transient interpretation in reservoirs containing irregular cavities. The objective is not to introduce a new general-purpose finite-volume method but to embed irregular cavities as special control volumes into a locally orthogonal PEBI grid so that the cavity volume, geometry, and well–cavity distance can be represented explicitly in bottom-hole pressure calculations. The model is formulated as a thickness-averaged two-dimensional system in which the fracture–matrix region is treated as an equivalent seepage continuum, and each cavity is assigned a spatially uniform pressure governed by a wave–seepage exchange relation. For the limiting case of zero cavity volume, the numerical bottom-hole pressure agrees closely with the analytical solution and the material-balance estimate. A further cylindrical-cavity benchmark against an analytical wave–seepage solution gives a pressure-drawdown relative L2 error of 4.38%, where the relative L2 error denotes the Euclidean norm of the pressure error vector normalized by that of the reference solution, providing additional validation of the cavity-coupled formulation. Sensitivity analysis shows that increasing the cavity volume delays the characteristic extrema of the pressure derivative and strengthens the contrast between the minimum and maximum, whereas increasing the well–cavity distance mainly shifts the onset of the cavity-dominated response and weakens its amplitude. A field pressure-buildup case from the Fuyuan oilfield is interpreted using the proposed workflow. The matched model indicates a pentagonal cavity with a volume of 169,770 m³, a well–cavity distance of 158.4 m, a permeability of 5.535 md, and an initial reservoir pressure of 86.66 MPa. The results demonstrate that the proposed PEBI-FVM wave–seepage-coupled model can support practical well-test interpretation of irregular cavities, while its reliability depends on the validity of the equivalent-continuum and uniform-cavity-pressure assumptions. Full article

Accurate identification of karst caves from seismic data is crucial for carbonate reservoir characterization, as these caves often serve as primary hydrocarbon storage spaces and migration pathways. However, it remains challenging due to the highly nonlinear relationship between seismic waveforms and cave geometries, as well as the noise propagation in skip connections inherent to U-Net-based methods. To address these limitations, this paper proposes UKAN-CBAM, a novel 3D network that synergistically integrates Tokenized Kolmogorov–Arnold Network (Tok-KAN) modules and Convolutional Block Attention Modules (CBAM) within a U-shaped encoder–decoder architecture. Unlike U-Net, which relies on linear convolutional kernels, the Tok-KAN modules employ learnable spline-based activation functions to better capture the nonlinear relationships between seismic waveforms and cave geometries. Furthermore, CBAM embedded in each skip connection adaptively recalibrates features along the channel and spatial dimensions, thereby suppressing noise and sharpening cave boundaries. Trained on synthetic data and validated on physical modeling data from the Sichuan Basin and field data from the Tarim Basin, UKAN-CBAM consistently outperforms U-Net, ResUNet, UNet-CBAM, and coherence attributes across multiple evaluation metrics. The proposed network delineates caves with improved continuity and sharper boundaries while reducing false positives, demonstrating strong generalization capability. The results indicate that the synergistic design of KAN’s nonlinear modeling and CBAM’s attention mechanism effectively mitigates the limitations of traditional approaches for karst cave identification. Full article

Water management in high-temperature and high-salinity reservoirs remains a critical challenge for oilfield operations, with conventional polymer gel systems exhibiting insufficient thermal stability and salt tolerance under extreme conditions. Here, we establish an integrated computational–experimental platform combining density functional theory (DFT) and molecular dynamics (MD) simulations to rationally design a novel AM/AMPS/AMB (Acrylamide/2-acrylamido-2-methylpropanesulfonic acid/sodium 3-acrylamido-3-methylbutanoate) terpolymer gel plugging agent tailored for the Tahe Oilfield (140 °C, Ca²⁺/Mg²⁺ 10,000 mg L⁻¹). Density functional theory (DFT) calculations of fourteen functional monomers identified AMB as the optimal candidate, achieving further hydrogen bond interactions that stabilize the crosslinked architecture under extreme conditions. This computational pre-screening reduced experimental iterations by over 60% and significantly shortened development cycles compared to conventional trial-and-error approaches. Experimentally, the optimized terpolymer exhibited a 40% increase in storage modulus (150 Pa) relative to AM/AMPS binary systems, 25% improvement in thermal stability (residual carbon at 300 °C), and plugging efficiency exceeding 92% in core flooding tests. Full article

Fracture–vuggy carbonate reservoirs contain discrete caves, fractures, conduits, and vugs, which makes recoverable-reserve evaluation strongly dependent on connected volume rather than on total pore volume alone. This study develops a unit-scale dynamic reserve-updating method for the S48 unit, Tahe Oilfield, by coupling a water-body-corrected material-balance equation, a heterogeneity-corrected waterflood characteristic curve, and iterative geological-model calibration. The main methodological contribution is to convert static fracture–vug architecture into dynamically constrained connected subsystems: the parameter Rwo quantifies connected/injected water volume at the fracture–vug unit scale, whereas the coefficient M corrects the apparent slope of waterflood curves for non-uniform sweep and preferential pathways. The revised workflow was calibrated against pressure, production, injection-response, and history-matched simulation data. Sensitivity analysis indicates that the estimated reserve-utilization degree increased from 48.77% +/− 4.8 percentage points during natural depletion to 74.1% +/− 6.7 percentage points after gas injection, reflecting staged reserve mobilization within the tested uncertainty range. The method is intended for field-scale reserve updating in reservoirs with sufficient pressure-production data; its transferability remains limited by static-model quality, channeling intensity, and the single-unit validation scope of this study. Full article

Fluid flow in fractured-vuggy carbonate reservoirs is characterized by extreme multiscale heterogeneity, where the coexistence of tight matrix rock and macroscopic cave challenges traditional Darcy-based continuum models. This paper presents a semi-analytical solution for two-phase immiscible displacement in a one-dimensional composite porous–cavernous–porous (PCP) system. The main feature of the model is that the cave region is treated separately from the porous domains: classical Darcy flow is used in the surrounding matrix, whereas an idealized free-flow representation is introduced for open caves based on a simplified one-dimensional treatment of the cave momentum balance. To elucidate the impact of distinct flow regimes on displacement dynamics, three physical models are compared for the cave region: (1) an open-cave model represented by a simplified free-flow formulation; (2) a filled-cave non-Darcy model governed by the Forchheimer equation using the Ergun correlation; and (3) a creeping-flow model governed by Darcy’s law. A piecewise semi-analytical solution procedure is established to enforce flux continuity, characterize interfacial state remapping, and determine the downstream front under global water-balance closure. The results show that both cave geometry and internal cave-flow mechanism critically control water-front advancement. While the open-cave model exhibits piston-like displacement behavior with high local displacement efficiency but stronger preferential flow, the Forchheimer model shows that inertial resistance can modify the saturation profile and delay breakthrough relative to the Darcy prediction. The proposed framework provides an idealized theoretical reference for benchmarking numerical simulators and for interpreting waterflooding behavior in complex vuggy reservoirs under one-dimensional, incompressible, gravity-free, and capillarity-free conditions. Full article

Carbonate reservoirs exhibit complex combinations of pores, fractures, and vugs, and their strong heterogeneity makes pore-scale displacement mechanisms and recovery enhancement difficult to predict. In this study, six microfluidic glass-etched models representative of pore-type, vuggy, and fracture-pore carbonate reservoirs were designed from cast thin sections of the S oilfield. Experiments were conducted to investigate the effects of different factors on microscopic displacement behavior and residual-oil distribution. The results show that microscopic residual oil in carbonate reservoirs mainly occurs as film flow, droplet flow, columnar flow, multi-pore flow, and cluster flow, with cluster flow dominating the late stage of development in all model types. Under waterflooding, pore-type reservoirs exhibit the most uniform sweep and the highest recovery factor (44.26%), whereas vuggy reservoirs readily develop preferential flow channels and show the lowest recovery factor (41.58%). For fracture-pore reservoirs, injection perpendicular to the fracture provides the best performance, and wider or denser fractures improve displacement efficiency. Compared with gas flooding, waterflooding increases recovery by 10.48% in pore-type reservoirs and by 16.44% in fracture-type reservoirs. High-rate waterflooding and mid-stage flow diversion further improve recovery by 9.05–10.87% and 17.12–19.63%, respectively. These results provide pore-scale evidence for optimizing development strategies for carbonate reservoirs. Full article

The Dengying Formation gas reservoir in the Penglai gas field, located in the central Sichuan Basin, exhibits substantial resource potential and promising development prospects. This reservoir is characterized by well-developed fractures and dissolution cavities, strong heterogeneity, complex gas–water relationships, and widespread edge–bottom water. During production, edge–bottom water is prone to channeling and intrusion through high-permeability pathways, which severely constrains well productivity and overall gas recovery. To address these challenges, this study takes a fractured-vuggy carbonate edge–bottom water gas reservoir as an example. By integrating large-scale physical simulation with cross-scale numerical simulation, a rational production allocation method suitable for strongly heterogeneous gas reservoirs has been developed. The research results indicate that: (1) Large-scale physical simulation experiments demonstrate that for fractured-vuggy bottom water gas reservoirs, implementing rate reduction and pressure control after water breakthrough can effectively suppress water invasion and coning, extend the stable production period, and increase the recovery factor by approximately 16%; (2) Based on the dynamic characteristics of water invasion, key similarity criteria including the Bond number, capillary number, gravity–viscous force ratio, and geometric–temporal similarity ratio were selected to establish a scientific parameter design method for cross-scale numerical simulation; (3) By considering factors such as reservoir type and aquifer energy, single-well mechanistic models were used to determine appropriate production rates for individual wells, enabling rapid optimization of production allocation plans. This provides crucial guidance for efficient gas well development and surface facility planning. Full article

Fault-controlled reservoirs are characterized by strong heterogeneity and diverse flow types. Existing water-coning calculation methods cannot accurately describe the complex oil–water distribution within reservoirs exhibiting a distinct “core–damage zone” architecture. To address this limitation, the main goal of this study is to develop a zonal water-coning calculation framework tailored to these highly heterogeneous structures. Methodologically, the Forchheimer equation is utilized to describe the entire reservoir system, with region-specific simplifications applied based on dominant flow mechanisms: in the high-velocity core zone, the viscous term is ignored; in the low-velocity damage zone, the inertial term is neglected; and the transition zone employs the complete Forchheimer formulation. The results indicate that the water-coning curves in the core and transition zones are significantly steeper as the radial distance decreases compared to the damage zone. Specifically, in a field application at the Fuman Oilfield, the calculated theoretical critical production rate of the core zone (5.39 × 10⁻² m³/s) is three orders of magnitude higher than that of the damage zone (1.45 × 10⁻⁵ m³/s). In conclusion, this massive zonal disparity demonstrates the severe bottleneck effect of the high-permeability core under a unified wellbore pressure drawdown, theoretically validating the necessity of deploying segmented completions and targeted water-control strategies to prevent premature water breakthrough. Full article

With the expansion of global oil and gas resource exploration and development into deep and ultra deep layers, the efficient development of deep carbonate rock fracture cave reservoirs has become the key to ensuring energy security. However, this type of reservoir commonly faces high temperatures, high salinity, and extremely strong heterogeneity, leading to increasingly severe water content spikes caused by dominant water flow channels. Although the existing traditional inorganic plugging agent has good temperature resistance, it has the defects of great brittleness and easy cracking, while the organic polymer gel is prone to degradation failure under high temperature and high salt environments. In order to solve the above problems, a new biochar-enhanced inorganic composite gel system was constructed by using biochar prepared from agricultural and forestry waste pyrolysis as a functional enhancement component. Through rheological testing, high-temperature and high-pressure mechanical experiments, long-term thermal stability evaluation, and dynamic sealing experiments of fractured rock cores, the reinforcement and toughening laws and rheological control mechanisms of biochar on inorganic matrices were systematically studied. Research has found that a biochar content of 0.5 wt% can significantly improve the micro pore structure of the matrix. By utilizing its micro aggregate filling effect and interfacial chemical bonding, the compressive strength of the solidified body can be increased to over 2 MPa, and there is no significant decline in strength after aging at 130 °C for 30 days. More importantly, the unique “adsorption slow-release” mechanism of biochar effectively stabilizes the hydration reaction kinetics at high temperatures, extending the solidification time of the system to 15 h and solving the problem of flash condensation in deep well pumping. This system exhibits excellent shear thinning characteristics and crack sealing ability, and presents a unique “yield reconstruction” toughness sealing feature. This study elucidates the multidimensional strengthening mechanism of biochar in inorganic cementitious materials, providing technical reference for stable oil and water control in deep fractured reservoirs. Full article

The Ordovician system in the Shunbei area of the Tarim Basin hosts typical ultra-deep, fault-controlled fracture–vuggy hydrocarbon reservoirs. Compared with the surrounding Tabei and Tazhong areas, the genetic types of Ordovician formation water in Shunbei are more complex, and the relationships and spatial distribution of oil, gas, and water exhibit strong heterogeneity and pronounced fault control. This study systematically collected formation water geochemical and pressure data to clarify the geochemical characteristics and origin of Ordovician formation water in the Shunbei area and to investigate the indicative relationships between ion concentrations and ionic ratios of formation water and reservoir dolomitization, hydrocarbon migration, and accumulation. Research shows that, in contrast to the Tabei and Tazhong areas, the Ordovician formation water in Shunbei is predominantly of the calcium chloride (CaCl₂) type, with enrichment in Ca²⁺ and depletion in Mg²⁺, which may be related to euhedral dolomitization. In fault-controlled fracture–vuggy reservoirs, a high desulfurization coefficient—contrary to its interpretation in conventional reservoirs—corresponds to favorable zones for hydrocarbon accumulation. The rare earth element (REE) composition of the formation water is characterized by heavy REE enrichment, a distinct negative cerium (Ce) anomaly, and a positive europium (Eu) anomaly. Combined with hydrogen–oxygen and strontium isotopic data, these features indicate that the Ordovician formation water in Shunbei represents original depositional paleoseawater that has undergone cross-formational flow and concentration. The water bodies are divided into two distinct formation water systems bounded by the Shunbei No. 5 fault zone. Favorable zones for hydrocarbon enrichment are controlled by source rock distribution, and hydrocarbons migrate together with formation water along strike-slip faults within the Shunbei area, showing a northwest-to-southeast trend. The region between the middle segments of the Shunbei No. 4 and No. 8 fault zones is identified as a favorable area for hydrocarbon accumulation. Full article

Fracture–vuggy carbonate reservoirs exhibit strong heterogeneity, spatial discontinuity, and highly variable porosity, which limit the effectiveness of traditional seismic attributes and conventional inversion. Focusing on the XX well block in the Tarim Basin, this study develops a rock-physics-constrained Physics-Constrained TransUNet method for intelligent porosity prediction. A carbonate-specific rock-physics model is first established, considering mineral composition, pore type, and water saturation, ensuring physical consistency between porosity, elastic parameters, and seismic responses. On this basis, a deep-learning framework integrating U-Net multi-scale feature extraction and Transformer global modeling is constructed. By embedding rock-physics priors, regularization constraints, and log-derived porosity labels, the method forms a unified physics- and data-driven inversion scheme. Applications to multiple deep wells and 3D post-stack seismic data from the FI7 fault zone demonstrate stable training, rapid convergence, and strong capability in capturing nonlinear porosity–seismic relationships. Compared with conventional inversion, the proposed approach significantly improves prediction accuracy in cavern-dominated intervals, fractured zones, and areas with abrupt porosity changes, while maintaining robust lateral continuity. Inter-well sections and target-layer slices further verify its effectiveness in identifying fracture–dissolution–vug composite reservoirs. The method provides a practical and reliable workflow for porosity prediction in ultra-deep carbonate reservoirs, supporting fine reservoir characterization and sweet-spot evaluation. Full article

A comprehensive study on the distribution characteristics and exploitation strategies of remaining oil was carried out in the Ordovician ultra-deep fault-controlled fractured–vuggy carbonate reservoir within the Shunbei No. 1 strike–slip fault zone. This research addresses challenges such as severe watered-out and gas channeling encountered during multi-stage development, marking a shift toward a development phase focused on residual oil recovery. By integrating seismic attributes, drilling, logging, and production performance data—and building upon previous methodologies of “hierarchical constraint and genetic modeling”—a three-dimensional geological model was constructed with a five-tiered architecture: strike–slip fault affected zone, fault-controlled unit, cave-like structure, cluster fillings, and fracture zone. Numerical simulations were subsequently performed based on this model. The results demonstrate that the distribution of remaining oil is dominantly controlled by the coupling between key geological factors—including fault kinematics, reservoir architecture formed by karst evolution, and fracture–vug connectivity—and the injection–production well pattern. Three major categories with five sub-types of residual oil distribution patterns were identified: (1) local low permeability, weak hydrodynamics; (2) shielded connectivity pathways; and (3) Well Pattern-Dependent. Accordingly, two types of potential-tapping measures are proposed: improve well control through optimized well placement and sidetrack drilling and reservoir flow field modification via adjusted injection–production parameters and sealing of high-permeability channels. Techniques such as gas (nitrogen) huff-and-puff, gravity-assisted segregation, and injection–production pattern restructuring are recommended to improve reserve control and sweep efficiency, thereby increasing ultimate recovery. This study provides valuable guidance for the efficient development of similar ultra-deep fractured–vuggy carbonate reservoirs. Full article

Deeply buried carbonate successions in China’s Tarim Basin host substantial hydrocarbons. In the southern Tahe Oilfield, Middle–Lower Ordovician limestones show little evidence of subaerial weathering because the Upper Ordovician strata protected them; nevertheless, the genesis and evolution of these carbonate reservoirs remain debated. Using cores, conventional and image logs, 3D seismic interpretation, and geochemical data, this study characterizes Paleozoic faulting and diagenetic fluids in the area. Four principal fluid types are identified—meteoric water, formation water, hydrothermal fluids, and mixed fluids. Two episodes of NNW- and NNE-trending strike-slip faulting during the Middle Caledonian and Early Hercynian periods facilitated fluid migration and dissolution. Later, Late Hercynian faults acted as primary pathways for hydrothermal flow, promoting the development of hydrothermal dissolution pores and caverns. The work clarifies how the interplay between strike-slip faulting and distinct diagenetic fluids governs reservoir development, providing theoretical guidance for predicting deep carbonate reservoirs and for hydrocarbon exploration and production. Full article