Search Results (71)

This study investigates gas injection gravity miscible flooding to enhance oil recovery in fractured-vuggy volatile oil reservoirs of the Fuman area, Tarim Basin. The Fuman 210 reservoir, containing light oil with high maturity, large column heights, and strong fracture control, provides favorable conditions for gravity-driven flooding. Laboratory tests show that natural gas and CO₂ achieve miscibility, while N₂ reaches near-miscibility. Mixed gas injection, especially at a natural gas to nitrogen ratio of 1:4, effectively lowers minimum miscibility pressure and enhances displacement efficiency. Full-diameter core experiments confirm that miscibility improves oil washing and expands the sweep volume. Based on these results, a stepped three-dimensional well network was designed, integrating shallow injection with deep production. Optimal parameters were determined: injection rates of 50,000–100,000 m³/day per well and stage-specific injection–production ratios (1.2–1.5 early, 1.0–1.2 middle, 0.8–1.0 late). Field pilots validated the method, maintaining stable production for seven years and achieving a recovery factor of 30.03%. By contrast, conventional development relies on depletion and limited water flooding, and dry gas injection yields only 12.6%. Thus, the proposed approach improves recovery by 17.4 percentage points. The novelty of this work lies in establishing the feasibility of mixed nitrogen–natural gas miscible flooding for ultra-deep fault-controlled carbonate reservoirs and introducing an innovative stepped well network model. These findings provide new technical guidance for large-scale application in similar reservoirs. Full article

Gel foam exhibits excellent applicability in fractured-vuggy reservoirs, effectively plugging flow channels and enhancing oil recovery. However, due to the harsh high-temperature environment and the complex and variable fracture-vuggy structure in reservoirs, gel foam may undergo structural changes during its migration, which can affect its flow properties and plugging efficiency. Therefore, investigating the migration characteristics of gel foam in fractured reservoirs through visual experiments is of significant practical importance. In this study, migration experiments with different foam systems were conducted using the visualized vuggy model. The migration stability of foam was characterized by combining the sweep range and liquid drainage rate, and the impact of temperature on the migration characteristics of gel foam was explored. Additionally, a profile control experiment was performed using the fractured-vuggy network model, analyzing and summarizing its mechanisms for enhancing oil recovery in fractured-vuggy reservoirs. The results showed that, in the vuggy model, compared with ordinary foam and polymer foam, gel foam showed a lower drainage rate, higher foam retention rate and wider sweep range, and could form stable plugging in fractured-vuggy reservoirs. An increased temperature accelerated the thermal expansion of gas and changes in liquid film characteristics, which led to the expansion of foam migration speed and sweep range. Although a high temperature increased the liquid drainage rate of foam, it was still lower than 3%, and the corresponding foam retention rate was higher than 97%. In addition, the gel foam had a strong profile control ability, which effectively regulated the gas migration path and improved the utilization degree of remaining oil. Compared with the first gas flooding, the recovery of subsequent gas flooding was increased by 18.85%, and the final recovery of the model reached 81.51%. Comprehensive analysis revealed that the mechanism of enhanced oil recovery by gel foam mainly included density control, foam regeneration, flow redirection, stable plugging, and deep displacement by stable gel foam. These mechanisms worked synergistically to contribute to increased recovery. The research results fully demonstrate the application advantages of gel foam in fractured-vuggy reservoirs. Full article

Underground river reservoirs are dominated by large-scale elongated caves and are typical fractured–vuggy carbonate reservoirs. This paper established physical models of underground river reservoirs with different filling modes. We first conducted bottom water flooding experiments and then studied multi-well, alternating water flooding and gas injection. The remaining oil distribution patterns and key factors under different filling modes and well locations were studied to clarify the recovery-improvement mechanisms of multi-well water and gas injection. The results show that the remaining oil after bottom water flooding can be categorized into the following five types: “insufficient well control remaining oil”, “attic remaining oil”, “bypass remaining oil”, “residual oil in filling medium”, and “shielded oil in filling medium”. Early water injection effectively recovers “insufficient well control remaining oil”, “bypass remaining oil”, and “residual oil in filling medium”. Gas injection targets included “attic remaining oil”. Late water injection can further improve recovery. When the cave is partially filled, there exists a large amount of “shielded oil in filling medium” that is difficult to recover, reducing recovery by 27% compared to unfilled cases. This study clarified the remaining oil distribution laws and water–gas flooding mechanisms for underground river reservoirs, providing guidance for efficient development. Full article

This study utilizes high-resolution X-ray computed tomography (CT) to evaluate the reservoir characterization in heterogenous carbonate rocks. These rocks show a diagenetic alteration that influences the reservoir quality in the Cretaceous Qamchuqa–Bekhme formations in outcrop and subsurface sections (Gali-Bekhal, Bekhme, and Taq Taq oilfields, NE Iraq). The scanning of fifty-one directional line analyses was conducted on three facies: marine, early diagenetic (non-hydrothermal), and late diagenetic (hydrothermal dolomitization, or HTD). The facies were analyzed from thousands of micro-spot analyses (up to 5250) and computed tomographic numbers (CTNs) across vertical, horizontal, and inclined directions. The surface (outcrop) marine facies exhibited CTNs ranging from 2578 to 2982 Hounsfield Units (HUs) (Av. 2740 HU), with very low average porosity (1.20%) and permeability (0.14 mD) values, while subsurface marine facies showed lower CTNs (1446–2556 HU, Av. 2360 HU) and higher porosity (Av. 8.40%) and permeability (Av. 1.02 mD) compared to the surface samples. Subsurface marine facies revealed higher porosity, lower density, and considerably enhanced conditions for hydrocarbon storage. The CT measurements and petrophysical properties in early diagenesis highlight a considerable porous system in the surface compared to the one in subsurface settings, significantly controlling the quality of the reservoir storage. The late diagenetic scanning values coincide with a saddle dolomite formation formed under high temperature conditions and intensive rock–fluid interactions. These dolomites are related to a hot fluid and are associated with intensive fracturing, vuggy porosities, and zebra-like textures. These textures are more pronounced in the surface than the subsurface settings. A surface evaluation showed a wide CTN range, accompanied by an average porosity of up to 15.47% and permeability of 301.27 mD, while subsurface facies exhibited a significant depletion in the CTN (<500 HU), with an average porosity of about 14.05% and permeability of 91.56 mD. The petrophysical characteristics of the reservoir associated with late-HT dolomitization (subsurface setting) show two populations. The first one exhibited CTN values between 1931 and 2586 HU (Av. 2341 HU), with porosity ranging from 3.10 to 18.43% (Av. 8.84%) and permeability from 0.08 to 2.39 mD (Av. 0.31 mD). The second one recorded a considerable range of CTNs from 457 to 2446 HU (Av. 1823 HU), with porosity from 6.38 to 52.92% (Av. 20.97%) and permeability from 0.16 to 5462.62 mD (Av. 223.11 mD). High temperatures significantly altered the carbonate rock’s properties, with partial/complete occlusion of the porous vuggy and fractured networks, enhancing or reducing the reservoir quality and its storage. In summary, the variations in the CTN across both surface and subsurface facies provide new insight into reservoir heterogeneity and characterization, which is a fundamental factor for understanding the potential of hydrocarbon storage within various geological settings. Full article

This study presents an integrated workflow for the characterization of fault-controlled fractured–vuggy reservoirs, demonstrated through a comprehensive analysis of the TP12CX fault zone in the Tahe Oilfield. The methodology establishes a four-element structural model—comprising the damage zone, fault core, vuggy zone, and cavern system—coupled with a multi-attribute geophysical classification scheme integrating texture contrast, deep learning, energy envelope, and residual impedance attributes. This framework achieves a validation accuracy of 91.2%. A novel structural element decomposition–integration approach is proposed, combining deterministic structural reconstruction with facies-constrained petrophysical modeling to quantify reservoir properties. The resulting models identify key heterogeneities, including caverns (Φ = 17.8%, K = 587 mD), vugs (Φ = 3.5%, K = 25 mD), and fractures (K = 1400 mD), with model reliability verified through production history matching. Field application of an optimized nitrogen foam flooding strategy, guided by this workflow, resulted in an incremental oil recovery of 3292 tons. The proposed methodology offers transferable value by addressing critical challenges in karst reservoir characterization, including seismic resolution limits, complex heterogeneity, and late-stage development optimization in fault-controlled carbonate reservoirs. It provides a robust and practical framework for enhanced oil recovery in structurally complex carbonate reservoirs, particularly those in mature fields with a high water cut. Full article

Accurate dynamic reserve estimation is essential for effective reservoir development, particularly in fractured vuggy carbonate reservoirs characterized by complex pore structures, multiple spatial scales, and pronounced heterogeneity. Traditional reserve evaluation methods often struggle to account for the coupled behavior of pores, fractures, and vugs, leading to limited reliability. In this study, a modified material balance equation is proposed that explicitly considers the contributions of matrix pores, fractures, and vugs, as well as the influence of varying aquifer multiples. To validate the model, physical experiments were conducted using cores with different fracture–vug configurations under five distinct aquifer multiples. A field case analysis was also performed using production data from representative wells in the Fuman Oilfield. The results demonstrate that the proposed model achieves a fitting accuracy exceeding 94%, effectively capturing the dynamics of fractured vuggy systems with active water drive. The model enables quantitative evaluation of single-well reserves and aquifer multiples, providing a reliable basis for estimating effective recoverable reserves. Furthermore, by comparing simulated formation pressures (excluding aquifer effects) with actual static pressures, the contribution of external aquifer support to reservoir energy can be quantitatively assessed. This approach offers a practical and robust framework for reserve estimation, pressure diagnosis, and development strategy optimization in strongly water-driven fractured vuggy reservoirs. Full article

Complex carbonate reservoirs feature large-scale karst cavern structures, exhibiting complex pore and bottom water energy distributions, which increase the difficulty of reservoir development and require targeted research. This paper proposes a new method for dynamic reserves calculation in these reservoirs based on the Differential Processing Method (DPM) and aimed at optimizing the development of complex reservoirs. The AD22 unit of the Tarim Oilfield in Xinjiang is taken as the research object, and this reservoir features complex karst and fault characteristics, which traditional reserves calculation methods cannot effectively capture due to its complex heterogeneous distribution. This study constructs a refined reservoir numerical model through 3D geological modeling and impedance inversion techniques, calculates dynamic reserves using the DPM, and compares the result with traditional material balance and production data analysis methods. The results indicate that the DPM has an advantage in estimating the petrophysical parameters and reserve utilization in such reservoirs. The error between the constructed reservoir numerical model and the actual reservoir development historical data is only 2.04%, demonstrating a good reference value. The model shows that more than 60% of the recoverable reserves in the target unit are located in areas shallower than 160 m underground, while the current development degree is only 12.6%. The model shows that the recovery rate is low in the strong bottom water energy areas of the unit, while the recovery potential is high in the weak bottom water areas. Therefore, a differentiated development strategy based on varying bottom water energy is required to enhance development efficiency. The model indicates that this strategy can improve the comprehensive development benefits of the reservoir by 81.66% over the existing baseline, demonstrating significant potential. This study provides new ideas and methods for dynamic reserve estimation and development strategy optimization for complex carbonate reservoirs, verifies the effectiveness of the DPM in evaluating the development of complex bottom water energy reservoirs, and offers data references for related research and field applications. Full article

Fractured vuggy reservoirs exhibit intricate fracture networks, where large fractures impose significant shielding effects on smaller ones, posing formidable challenges for efficient exploitation. A systematic evaluation of foaming volume, drainage half-life, decay behavior, and viscosity under varying temperatures and salinities was conducted for conventional foam, polymer-enhanced foam, and gel foam. The results yield the following conclusions: Compared to conventional foam, polymer-enhanced foam exhibits markedly improved stability. In contrast, gel foam, cross-linked with chemical agents, maintains stability for over one week at elevated temperatures, albeit at the expense of reduced foaming capacity. The three-dimensional network structure formed post-gelation enables gel foam to retain a thicker liquid film, exhibiting exceptional foam stability. As salinity increases, the base liquid viscosity of conventional foam remains largely unaffected, whereas polymer foam shows marked viscosity reduction. Gel foam displays a non-monotonic viscosity response—initially increasing due to ionic cross-linking and subsequently declining from excessive charge screening. All three systems exhibit significant viscosity decreases under high-temperature conditions. Visualized plate fracture model experiments revealed distinct flow patterns and mobility control performance; narrow fractures exacerbate bubble coalescence under shear stress, leading to enlarged bubble sizes and diminished plugging efficiency. Among the three systems, gel foam exhibited superior mobility control characteristics, with uniform bubble size distribution and enhanced stability. Integrating the findings from the foam mobility control experiments in parallel fracture systems with the diversion outcomes of mobility control and flooding, distinct performance trends emerge. It can be seen that the stronger the foam stability, the stronger the mobility control ability, and the easier it is to start the shielding effect. Combined with the stability of different foam systems, understanding the mobility control ability of a foam system is the key to increasing the sweep coefficient of a complex fracture network and improve oil-washing efficiency. Full article

Gas channeling phenomena in carbonate fracture-vuggy reservoirs frequently occur, primarily in the form of negative pressure gas channeling and displacement gas channeling, with the possibility of mutual conversion between the two. This is accompanied by the risk of hydrogen sulfide (H₂S) release from the reservoir, which poses significant challenges to controlling safety. Currently, liquid bridging and gel plugging technologies are effective methods for mitigating complex issues such as downhole overflow, fluid loss, and heavy oil backflow. This paper focuses on the development and optimization of key treatment agents, including high-temperature-resistant polymers and crosslinking agents, to formulate a high-temperature chemical gel plugging agent. A gel-breaking, high-strength colloidal chemical gel plugging agent system capable of withstanding temperatures up to 150 °C was developed, and it has an apparent viscosity of about 7500 mPa·s, an energy storage modulus and a loss modulus of 51 Pa and 6 Pa, respectively, after gel formation at elevated temperatures, and an apparent viscosity retention rate of the gel of greater than 82% after aging for 9 d at a temperature of 150 °C. This system forms a stable gas isolation barrier in the wellbore, with performance remaining stable after 7 to 12 days of aging, and the degradation rate reaches 99.8% after 24 h at 150 °C. This technology is of significant importance in solving complex issues such as overflow, fluid loss, and heavy oil backflow in gas injection and recovery wells in high-temperature, high-pressure reservoir conditions. Full article

Due to the fracture caverns in fractured-vuggy reservoirs, channeling frequently occurs during water injection or gas injection. The stability of the oil–water/oil–gas interface during water injection or gas injection in fractured-vuggy reservoirs significantly affects the displacement efficiency. However, there is a lack of in-depth understanding of the stability of the gas–water interface migration during water injection or gas injection in such reservoirs. In order to deal with this problem, this study combines indoor 3D visualization physical simulation experiment and fracture-cavity reservoir flow simulation. The law of interface transport and oil recovery in the process of injection of gas/water considering the degree of filling of fracture holes was studied and the influence of formation on crude oil viscosity, gas injection speed, inclination angle and other factors on the stability of the interface was compared. Results show that, under the influence of gravity differentiation, the oil–water interface of high-viscosity crude oil fluctuates obviously after water breakthrough, and the oil–water interface tends to be unstable, forming uneven oil cones. By reducing the gas drive speed, water invasion can be effectively inhibited to achieve a stable interface which accordingly improves the oil recovery. Full article

Due to the complex reservoir types and strong heterogeneity of fractured–vuggy reservoirs with aquifers, evaluating such reservoirs’ dynamic reserves and aquifer size is challenging. This paper established a segmented elastic-drive material balance equation based on the material balance principle by combining the functional relationships among the crude oil volume factor, crude oil compressibility, and formation pressure. The PELT algorithm was used to segment the water invasion stages, and nonlinear least squares fitting was employed to determine the rock compressibility, dynamic reserves, and aquifer size of fractured–vuggy reservoirs. This study shows that production in fractured–vuggy reservoirs with aquifers can be divided into three stages: no water invasion, initial water invasion, and full water invasion. Rock compressibility and dynamic reserves can be calculated using production data from the no water invasion stage, while the aquifer size can be determined from data in the water invasion stage. Influenced by connectivity and production regulations, aquifers may not be fully affected by pressure waves, causing the aquifer size to increase gradually until stabilization. Compared with numerical simulation data, the method presented in this paper achieves errors of 0.34%, 0.67%, and 1.19% for rock compressibility, dynamic reserves, and aquifer size, respectively. Full article

Acid fracturing has become a crucial technology for developing carbonate reservoirs, playing a particularly significant role in enhancing oil and gas recovery. However, the retention and flowback behaviors of residual acid in fractured-vuggy carbonate reservoirs after acid fracturing remain poorly understood, and this uncertainty significantly hinders the efficient development of such reservoirs. In this study, the micro-computed tomography images of carbonate rocks were used to extract actual fracture–vug structures. A microscopic flow model for fractured-vuggy carbonate reservoirs was then designed and fabricated using wet etching techniques. Microfluidic experiments were performed to investigate the invasion and flowback behavior of residual acid within these reservoirs. This study introduces a novel approach by integrating actual fracture-vuggy structures from micro-CT images into a microfluidic model, providing a more realistic representation of fractured-vuggy carbonate reservoirs compared to previous studies that relied on simplified or idealized geometries. Additionally, the invasion coefficient (the ratio of acid invaded area to total pore area) and flowback rate (the proportion of residual acid expelled during flowback) were introduced to quantitatively assess the efficiency of acid invasion and flowback under varying flow rates, viscosities, and the presence or absence of surfactants. The results demonstrate that the invasion coefficient of residual acid increases with the injection rate, while the flowback rate decreases as the injection rate is reduced. A higher viscosity of the oil phase hinders acid invasion and results in slower flowback due to increased flow resistance in the micro model. However, the final flowback rate is higher with a higher viscosity oil phase compared to a lower viscosity phase. The addition of surfactants enhances the efficiency of acid invasion and flowback, increasing the invasion coefficient by up to 5% and the flowback rate by up to 3%. Full article

Fractured-vuggy marine carbonate reservoirs, as an unconventional energy resource, hold significant potential for exploration and development. In this study, the Manshen block of the Furman oilfield in the Tarim Basin, China, was selected as the research object. A systematic investigation was conducted on the types of marine carbonate reservoir bodies, production characteristics, and both static and dynamic connectivity. Static connectivity analysis was performed using the heat diffusion equation and the multi-source potential field method. Dynamic connectivity evaluation was carried out by combining the dynamic time warping (DTW) algorithm with the analytic hierarchy process (AHP). Well logging, core analysis, and cast-thin section experiments were utilized to determine the types of reservoir spaces. The results indicate that the main types of reservoir spaces in the study area are caves, pores, and fractures. The fractures are primarily structural, with secondary development of dissolution fractures, weathering fractures, and sutures. The productivity changes in oil wells in the study area are classified into three types: slow decline, rapid decline, and high-speed decline. Based on the connectivity coefficients, wells were divided into three connectivity groups, with the A32 well group having the highest connectivity, followed by B5 well group 1, and B5 well group 2 having the lowest connectivity. The research provides technical support for the accurate evaluation of marine carbonate reservoirs and contributes to enhancing the efficiency of oil and gas exploration and development. Full article

Reservoir space characteristics are the key to reservoir evaluation and the evaluation of reservoir capacity. The reservoir space of fracture-vuggy carbonate reservoirs is complex and diverse, and it develops from micro to macro. There is a lack of systematic study on the reservoir space of the Ordovician fracture-vuggy carbonate reservoir. Therefore, taking the Ordovician Yijianfang Formation in Yueman Block of Fuman Oilfield in Tarim Basin as an example, the microscopic reservoir space characteristics of the study area were characterized by rock thin section identification, X-ray diffraction, scanning electron microscopy, high-pressure mercury injection, and low-temperature nitrogen adsorption experiments, and the macroscopic reservoir space characteristics of the study area were characterized by core observation, drilling and logging data, and imaging logging data. The results showed that (1) the lithology of the Ordovician Yijianfang Formation in the Yueman area of Fuman Oilfield is mainly micrite and sparry grain limestone. The mineral composition is mainly calcite, accounting for 97.35%, containing a small amount of quartz and dolomite, accounting for 1.1% and 1.55%, respectively. (2) At the micro level, the reservoir space of Yijianfang Formation in Yueman Block is not developed in primary pores, mainly having developed dissolution pores, structural fractures, and pressure solution fractures, and the pore size is distributed from the nanometer to micron scale. (3) The dissolution caves in the study area are developed at the macro level, mainly including pore-type, cave-type, fracture-pore-type, and fracture-type reservoirs. The research results provide technical support for the accurate evaluation of fractured-vuggy carbonate reservoirs and the improvement of exploration and development effects. Full article

Weathered crust karst reservoirs with intricately interconnected fractures and caves are common but challenging enhanced oil recovery (EOR) targets. This paper investigated the remaining oil distribution rules, formation mechanisms, and EOR methods through physical experiments on acrylic models resembling the geological features of weathered crust reservoirs. Acrylic models with precision dimensions and morphologies were fabricated using laser etching technology. By comparing experiments under different cave filling modes and production well locations, it was shown that a higher cave filling extent led to poorer bottom water flooding recovery due to stronger flow resistance but slower rising water cut owing to continued production from the filling medium. Multi-well water and gas injection achieved higher incremental oil recovery by alternating injection–production arrangements to establish new displacement channels and change drive energy. Gas injection recovered more attic remaining oil from upper cave regions, while subsequent water injection helped wash the residual oil in the filling medium. The findings reveal the significant effects of fracture cave morphological configuration and connectivity on remaining oil distribution. This study provides new insights and guidance for EOR design optimization catering to the unique features of weathered crust karst fractured vuggy reservoirs. Full article