Search Results (38)

The Tarim Basin is currently the largest petroliferous basin in China, with hydrocarbons primarily hosted in Ordovician marine carbonate paleokarst fracture–vug reservoirs—a typical example being the Tahe Oilfield located in the northern structural uplift of the basin. The principle of “the present is the key to the past” serves as a core method for studying paleokarst fracture–vug reservoirs in the Tahe Oilfield. The deep and ultra-deep carbonate fracture–vug reservoirs in the Tahe Oilfield formed under humid tropical to subtropical paleoclimates during the Paleozoic Era, belonging to a humid tropical–subtropical paleoepikarst dynamic system. Modern karst types in China are diverse, providing abundant modern karst analogs for paleokarst research in the Tarim Basin. Carbonate regions in Eastern China can be divided into two major zones from north to south: the arid to semiarid north karst and the humid tropical–subtropical south karst. Karst in Northern China is characterized by large karst spring systems, with fissure–conduit networks as the primary aquifers; in contrast, karst in Southern China features underground river networks dominated by conduits and caves. From the perspective of karst hydrodynamic conditions, the paleokarst environment of deep fracture–vug reservoirs in the Tarim Basin exhibits high similarity to the modern karst environment in Southern China. The development patterns of karst underground rivers and caves in Southern China can be applied to comparative studies of carbonate fracture–vug reservoir structures in the Tarim Basin. Research on modern and paleokarst systems complements and advances each other, jointly promoting the development of karstology from different perspectives. Full article

During drilling in fractured formations, wellbore instability issues such as fluid loss and collapse frequently occur, severely compromising drilling safety. Traditional criteria such as Mohr–Coulomb often fail to adequately account for fracture effects, leading to inaccurate collapse pressure predictions. Taking the Tahe Oilfield as a case study, this research develops an enhanced model for predicting wellbore collapse pressure in fractured formations. Based on principles of elastic mechanics and Biot’s effective stress theory, a stress distribution model around deviated wellbores is established. The single weak plane strength criterion is integrated with the Mohr–Coulomb criterion to characterize failure mechanisms in both fractured zones and intact rock matrix. Newton’s iterative method, implemented in MATLAB, is employed to solve for collapse pressure, and a sensitivity analysis is conducted to evaluate the influence of factors such as in situ stresses and fracture orientation. A case study from Well THX demonstrates that neglecting fractures results in a symmetrical collapse pressure profile and an unduly narrow safe mud weight window. In contrast, accounting for fractures significantly increases the required mud weight and identifies an optimal azimuth range for enhancing wellbore stability. The Mohr–Coulomb criterion is shown to underestimate the necessary mud weight, which aligns with actual wellbore collapse incidents encountered during drilling. The single weak plane criterion offers more accurate predictions, recommending a higher minimum mud density and an optimized well trajectory to mitigate drilling risks. These findings offer theoretical and practical guidance for mitigating wellbore instability in fractured formations. Full article

The extra-heavy oil in the Tahe Oilfield of China has extremely high viscosity, as it is rich in the heavy components asphaltene and resin, creating significant difficulties in its exploitation and transportation. Therefore, it is important to effectively reduce the viscosity and improve the fluidity of this extra-heavy oil. The traditional viscosity reduction method suffers from a high blending ratio and a shortage of light crude oil resources for extra-heavy oil blending. In this study, coal tar and washing oil—widely available low-cost by-products of the coal chemical industry—are used for extra-heavy oil blending and viscosity reduction. Washing oil—containing light components distilled from coal tar—was highly effective in reducing the viscosity of extra-heavy oil. When the dilution ratio of washing oil is 0.25, the viscosity of extra-heavy oil is reduced to 1214 mPa·s, and the viscosity reduction rate is 99.8%, indicating that washing oil is an efficient viscosity-reducing agent in extra-heavy oil blending. GC-MS showed that the washing oil contained abundant aromatic hydrocarbons and aromatic heterocyclic rings. A multi-component viscosity reduction system using washing oil coupled with toluene, xylene, and surfactant achieved an even better viscosity reduction effect. In conclusion, we designed a low-cost, high-efficiency, multi-component, and multi-functional synergistic system for extra-heavy oil viscosity reduction in the Tahe Oilfield. In the proposed working mechanism, aromatic hydrocarbons and aromatic heterocyclic rings in washing oil can intercalate into the layered structure of dense asphaltene aggregates, thereby dispersing and dissociating them. 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

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

The fourth member of the Triassic in the Tahe Oilfield, as one of the key strata for clastic rock reservoirs, poses significant challenges to oil and gas exploration due to unclear identification of its depositional environments and sedimentary microfacies. Based on the guidance of sequence stratigraphy and sedimentological theories, this study comprehensively analyzed well logging data from more than 130 wells, core analysis from 9 coring wells (including lithology, sedimentary structures, and facies sequence characteristics), 3D seismic data (covering an area of 360 km²), and regional geological background. Combined with screening and settling method granularity experiments, the sedimentary characteristics of the sand body in the fourth member were systematically characterized. The results indicate the following: (1) In the Tahe Oilfield, the strata within the fourth member of the Triassic are predominantly characterized by marginal lacustrine subfacies deposits, with delta-front subfacies deposits developing in localized areas. (2) From the planar distribution perspective, influenced by the northwestern provenance, a small deltaic depositional system developed in the early stage of the fourth member in the northwestern part of the Triassic Akekule Formation. This system was dominated by subaqueous distributary channel sand bodies, which were subjected to erosion and reshaping by lake water, leading to the formation of several stable sand bars along the lake shoreline. In the later stage of the fourth member, as the lake level continued to recede, the area of deltaic deposition expanded westward, and deltaic deposits also developed in the central to slightly eastern parts of the study area. Based on this, a depositional model for the fourth member of the Triassic in the Tahe Oilfield has been established. (3) In the Tahe Oilfield, the sand bodies within the fourth member of the Triassic system gradually pinch out into mudstone, forming lithological pinch-out traps. Among these, the channel sand bodies and long belt sand ridges, due to their good sorting and high permeability, become favorable reservoirs for oil and gas accumulation. This study clarifies the sedimentary model of the fourth member and reveals the spatial differentiation mechanism of sand bodies under the control of lake-level fluctuations and ancient structures. It can provide exploration guidance for delta lake sedimentary systems similar to the edge of foreland basins, especially for efficient development of complex lithological oil and gas reservoirs controlled by multistage lake invasion–lake retreat cycles. Full article

The carbonate fracture-cave reservoir in the Tahe oilfield, China, encounters development challenges because of its substantial burial depth (exceeding 5000 m). Its characteristics are low permeability, pronounced heterogeneity, extensive karst cavern systems, diverse connection configurations, and intricate spatial distribution. Prolonged conventional water flooding leads to predominant water channels, resulting in water channeling and limited sweep efficiency. Surfactant flooding is usually adopted in these conditions because it can mitigate water channeling and enhance sweep efficiency by lowering the interfacial tension (it refers to the force that is generated due to the unbalanced molecular attraction on the liquid surface layer and causes the liquid surface to contract) between oil and water. Nonetheless, the Tahe oilfield is a carbonate reservoir where surfactant is prone to loss near the well, thereby limiting its application. High-pressure injection flooding technology is an innovative method that utilizes injection pressure higher than the formation rupture pressure to alter reservoir permeability, specifically in low-permeability oil fields. Because of the high fluid flow rate, the contact time with the interface is decreased, enabling the ability for surfactants to reach the deep reservoir. In this article, based on the mixed adsorption mechanism of two surfactants and the hydrophilic and lipophilic equilibrium mechanisms, a set of high-temperature and high-salinity resistance surfactant systems appropriate for the Tahe oilfield is developed and its associated performance is evaluated. An oil displacement experiment is carried out to examine the effect of surfactant flooding by high-pressure injection. The results demonstrate that the ideal surfactant system can lower the interfacial tension to 10⁻² mN/m and its capacity to reduce the interfacial tension to 10⁻² mN/m after different aging periods. Besides, the surfactant system possesses excellent wettability (wetting angle changed from 135° to 42°) and certain emulsifying abilities. The oil displacement experiment shows that the oil recovery rate of surfactant flooding by high pressure reaches 26%. The effect of surfactant flooding by high-pressure injection is better than that of high-pressure injection flooding. Full article

Nitrogen foam is a promising enhanced oil recovery (EOR) technique with significant potential for tertiary oil recovery. This improves the efficiency of the oil displacement during the gas drive processes while expanding the swept volume. However, in the high-temperature, high-salinity reservoirs of the Tahe Oilfield, conventional N₂ foam systems show suboptimal performance, as their effectiveness is heavily limited by temperature and salinity. Consequently, enhancing the foam stability under these harsh conditions is crucial for unlocking new opportunities for the development of Tahe fracture-vuggy reservoirs. In this study, the Waring–Blender method was used to prepare weathered coal particles as a foam stabilizer. Compared to conventional foam stabilizers, weathered coal particles were found to enhance the stability of the liquid film under high-temperature and high-salinity conditions. Firstly, the foaming properties of the six foaming agents were comprehensively evaluated and their foaming properties were observed at different concentrations. YL-3J with a mass concentration of 0.7% was selected. The foaming stabilization performance of four types of solid particles was evaluated and weathered coal solid particles with a mass concentration of 15% and particle size of 300 mesh were selected. Therefore, the particle-reinforced foam system was determined to consist of “foaming agent YL-3J (0.7%) + weathered coal (15.0%) + nitrogen”. This system exhibited a foaming volume of 310 mL at 150 °C and salinity of 210,000 mg/L, with a half-life of 1920 s. Finally, through interfacial tension and viscoelastic modulus tests, the synergistic mechanism between weathered coal particles and surfactants was demonstrated. The incorporation of weathered coal particles reduced the interfacial tension of the system. The formation of a skeleton at the foam interface increased the apparent viscosity and viscoelastic modulus, reduced the liquid drainage rate from the foam, and mitigated the disproportionation effect. These effects enhanced the temperature, salinity resistance, and stability of the foam. Consequently, they contributed to the stable flow of foam under high-temperature and high-salinity conditions in the reservoir, thereby improving the oil displacement efficiency of the system. Full article

The fracture-cavity carbonate reservoir in Tahe oilfield is buried deep (more than 5000 m). The reservoir has low permeability, strong heterogeneity, large size, diverse forms of connectivity, and complex spatial distribution. In conventional water flooding, it is difficult to improve oil recovery effectively because of small water flood sweep and large injection pressure. Pressure flooding is a new water injection technique that can change the reservoir pore space. Combined with an oil displacement agent, pressure flooding is expected to improve the recovery rate of carbonate reservoirs. In this paper, the influence factors of pressure flooding technology are studied, and a set of surfactant systems suitable for high-temperature and high-salt reservoirs is developed. The results show that only an appropriate injection flow can produce microfractures. Only an appropriate displacement rate can optimize the effects of pressure flooding. With an increase in crude oil viscosity, the recovery rate after pressure flooding decreases gradually. A complex fracture network is formed in reservoirs after pressure flooding. The new surfactant system has good interfacial tension reduction properties and excellent stability. Pressure flooding experiments with the addition of a surfactant showed that the system can help to improve the recovery of pressure flooding. Full article

Nitrogen injection technology has become an important production technology after water injection development in the karst fracture-vuggy reservoir in Tahe Oilfield. However, due to the influence of reservoir heterogeneity and the high mobility of gas fluid, nitrogen easily forms a dominant channel and gas channeling occurs, and the recovery effect time is short. Based on this, a visual surface karst model is designed and created to study nitrogen foam-assisted gas drive. The results show that after gas channeling occurs in the dominant channel of nitrogen flooding, foam injection-assisted gas flooding can improve oil recovery. In the longitudinal direction, foam-assisted gas drive mainly displaces the remaining oil because of gravity differentiation and the reduction of oil–water interfacial tension. In the horizontal direction, foam-assisted gas drive is mainly used to block the large pore cracks and dominant channels, promote the gas to turn into large tortuous and small cracks, and expand the swept efficiency of the gas. After forming the dominant channel, injecting 0.3 pv salt-sensitive foam with a gas–liquid ratio of 2:1 in the middle of the gas channel can improve the recovery rate of the model from 4% to about 25%, and the recovery rate can be increased by about 20%, which improves the effect of gas flushing and improves the development efficiency of the oil field at the same time. Full article

Reservoir productivity prediction is a key component of oil and gas field development, and the rapid and accurate evaluation of reservoir productivity plays an important role in evaluating oil field development potential and improving oil field development efficiency. Fracture-vuggy reservoirs are characterized by strong heterogeneity, complex distribution, and irregular development, causing great difficulties in the efficient prediction of fracture-vuggy reservoirs’ productivity. Therefore, a PSO-BP fracture-vuggy reservoir productivity prediction model optimized by feature optimization was proposed in this paper. The Chatterjee correlation coefficient was used to select the appropriate combination of seismic attributes as the input of the prediction model, and we applied the PSO-BP model to predict oil wells’ production in a typical fracture-vuggy reservoir area of Tahe Oilfield, China, with the selected seismic attributes and compared the accuracy with that provided by the BP neural network, linear support vector machine, and multiple linear regression. The prediction results using the four models based on the test set showed that compared with the other three models, the MSE of the PSO-BP model increased by 23% to 62%, the RMSE increased by 12 to 38 percent, the MAE increased by 18 to 44 percent, the SSE increased by 23 to 62 percent, and the R-square value increased by 2 to 13 percent. This comparison proves that the PSO-BP neural network model proposed in this paper is suitable for the productivity prediction of fracture-vuggy reservoirs and has better performance, which is of guiding significance for the development and production of fracture-vuggy reservoirs. Full article

The low comprehensive compressibility coefficient characteristic of fracture-vuggy reservoirs often leads to imprecise dynamic reserve calculations. This study introduces a novel method for estimating dynamic reserves, which incorporates a modified comprehensive compressibility coefficient to enhance accuracy. This methodology has been applied to 23 wells in the Tahe Oilfield, resulting in error rates substantially lower than those associated with traditional techniques, thereby markedly enhancing the accuracy of dynamic reserve estimations. Specifically, for karst cave and fracture-vuggy reservoirs, the error rate in dynamic reserve calculations is reduced to under 10%, surpassing conventional methods by more than fivefold. In the case of fractured reservoirs, despite minor fluctuations in error rates due to stress sensitivity, diversion capacity, and channel variations, the proposed method still demonstrates a significant reduction in error rates compared to standard practices. Full article

To address the issue of ineffective injection resulting from the consistent channeling of injected water through highly permeable channels in ultra-deep, high-temperature, high-salinity, and strongly heterogeneous reservoirs during the production process, a gel particle profile control agent suitable for high-temperature and high-salinity conditions was chosen. With the help of the glass etching visual microscopic model and the heterogeneous long core model, the formation mechanism of a water flooding channeling path and the distribution law of the remaining oil were explored, the microscopic profile control mechanism of the different parameters was clarified, and the profile control effect of macroscopic core displacement was analyzed. The research shows that the formation mechanism of a water flooding channeling path is dominated by the distribution law of the permeability section and the connection mode between different penetration zones. The remaining oil types after water flooding are mainly contiguous block, parallel throats, and multi-branch clusters. The profile control effect of gel particles on reservoir vertical heterogeneity is better than that of reservoir lateral heterogeneity. It was found that 10 wt% submicron particles with a median diameter of 600 nm play a good role in profiling and plugging pores of 5–20 μm. In addition, 10 wt% micron-sized particles with a median diameter of 2.63 μm mainly play a strong plugging role in the pores of 20–30 μm, and 5 wt% micron-sized particles with a median diameter of 2.63 μm mainly form a weak plugging effect on the pores of 10–20 μm. The overall profile control effect of 10 wt% submicro particles is the best, and changes in concentration parameters have a more significant effect on the profile control effect. In the macroscopic core profile control, enhanced oil recovery (EOR) can reach 16%, and the gel particles show plugging, deformation migration, and re-plugging. The research results provide theoretical guidance for tapping the potential of the remaining oil in strong heterogeneous reservoirs. To date, the gel particles have been applied in the Tahe oilfield and have produced an obvious profile control effect; the oil production has risen to the highest value of 26.4 t/d, and the comprehensive water content has fallen to the lowest percentage of 32.1%. Full article

The conventional liquid acid has several shortcomings in the acidizing process of fractured-vuggy carbonate reservoirs, including high filtration loss, fast reaction rate, high friction resistance, and difficult flowback. To address these issues, a new atomizing acid acidizing technology is proposed, combining the gas injection development practice from the fractured-vuggy carbonate reservoir in the Tahe oilfield. The laboratory experiments were conducted to optimize the type and concentration of atomized acid, iron ion stabilizer, corrosion inhibitor, and atomization stabilizer. The acid atomization rate was evaluated under different combinations of gas and liquid injection flows using a self-made atomized acid well migration simulator, and the best atomization scheme was selected. Furthermore, a kinetic experiment for the acid–rock reaction was carried out to evaluate the retarding performance of the atomized acid. The optimized formula for the atomizing acid system consists of 15~25% hydrochloric acid, 0.005% atomizing stabilizer (AEO-7), 1% iron ion stabilizer (EET), 1.5% corrosion inhibitor (EEH-160), and water. The optimal gas and acid injection scheme is gas injection at 2m3/min and acid injection at 10 mL/min, which maintains an atomization rate of over 80% after the acid mist migrates through the wellbore. Compared with gelling acid, the acid–rock reaction rate of atomized acid is 8.5, 9.1, and 10.6 times slower under acid concentrations of 15%, 20%, and 25% respectively. The retarding effect of atomized acid is superior, facilitating etching and initiating underdeveloped gas drive channels and thereby increasing the probability of gas communication with new reservoirs. The research findings presented in this paper establish a theoretical foundation for the practical implementation of the atomized acid acidizing process in the field. Full article

Fractured-vuggy reservoirs are mainly composed of three types: underground rivers, vugs, and fractured-vuggy structures. Based on the similarity criterion, a 3D model can truly reflect the characteristics of the multi-scale space of a fractured-vuggy reservoir, and it can reflect fluid flow laws in the formation. Water flooding, gas flooding, and gel foam flooding were carried out in the model sequentially. Based on gas flooding, the enhanced recovery ratio of gel foam flooding in the underground river was approximately 12%. By changing the injection rate, the average recovery ratio of nitrogen flooding was 6.84% higher than that of other injection rates at 5 mL/min, and that of gel foam flooding was 1.88% higher than that of other injection rates at 5 mL/min. The experimental results showed that the gel foam induced four oil displacement mechanisms, which selectively plugged high-permeability channels, controlled the mobility ratio, reduced oil-water interfacial tension, and changed the wettability of rock surfaces. With different injection-production methods, gel foam flooding can spread across two underground river channels. Two cases of nitrogen flooding affected one underground river channel and two underground river channels. By adjusting the injection rate, it was found that after nitrogen flooding, there were mainly four types of residual oil, and gel foam flooding mainly yielded three types of remaining oil. This study verified the influencing factors of extracting residual oil from an underground river and provides theoretical support for the subsequent application of gel foam flooding in underground rivers. Full article