Search Results (1,087)

Due to the complex issues of low porosity and low permeability in tight sandstone reservoirs, non-unified data measurement, and the limitation of traditional methods by empirical formulas and simple statistical models, which make it difficult to couple the correlation of parameters, how to quickly clean data, establish a comprehensive geological-engineering sweet spot evaluation method, and improve prediction accuracy and engineering decision-making effectiveness have become an urgent technical challenge. This study takes the logging and fracturing construction data in the L area as the data set, uses the Pearson correlation coefficient method to verify the nonlinear characteristics of features, and constructs a geological-engineering integrated intelligent decision-making algorithm based on the collaborative optimization of a dual-branch multi-layer perceptron and attention mechanism. The training results of the dual-branch multi-layer perceptron model and traditional machine learning methods are compared and analyzed. The results show that the prediction error of the adopted dual-branch multi-layer perceptron neural network model is 5.44%. The weight of geological factors in this area accounts for 51.71%, and the engineering factors account for 48.29%. This method has been field-applied in 25 wells in the L area, with a production coincidence rate reaching 94.66%. The sweet spots of tight sandstone reservoirs are mainly the H5 and H6 submembers. The deep integration of machine learning interpretability and geological engineering practice provides a new approach for sweet spot prediction. Full article

Persistent uncertainty in translating low-field nuclear magnetic resonance (NMR) T₂ relaxation spectra into geometrically meaningful pore–throat metrics has long hindered the quantitative characterization of tight reservoirs. To address this issue, this study develops an enhanced conversion framework that incorporates scale-dependent pore geometry, enabling more realistic estimation of pore–throat radius distributions. Core samples were collected from the first member of the Shanxi Formation and the eighth member of the Shihezi Formation in the Ordos Basin. A comprehensive experimental dataset was established, including porosity and permeability measurements, X-ray diffraction (XRD) mineral analysis, NMR experiments, high-pressure mercury intrusion (HPMI), and constant-rate mercury injection (CRMI). The results demonstrate that total clay content exhibits weak correlations with pore size and porosity. In contrast, the occurrence and morphology of specific clay minerals exert significant control on pore connectivity and flow behavior. In particular, fibrous illite increases pore–throat complexity, while early chlorite coatings help preserve primary intergranular pores. A single geometric model cannot fully represent the complex pore–throat system in tight sandstones. For pores, a spherical geometry is most appropriate and indeed necessary. Smaller throats connecting these pores often exhibit geometries more consistent with cylindrical shapes. Within the coarse pore size range, large pores dominate the reservoir space and generally exhibit geometries that better conform to a spherical shape. And larger pores dominate the volumetric contribution in the coarse pore-size range. These observations suggest that a scale-dependent composite model could further improve the accuracy of NMR-based pore-size estimations. Therefore, the spherical-pore model provides a physically meaningful framework for characterizing pore structures in tight reservoirs. At the same time, incorporating scale-dependent considerations offers a promising avenue for future methodological development. Full article

Conventional Diagnostic Fracture Injection Tests (DFITs) are widely used for formation pressure estimation, but in practice, they frequently require days, weeks, or even months of extended shut-in periods, a challenge particularly pronounced when large injection volumes are coupled with ultra-low formation permeability. While recent studies have proposed various modified DFIT approaches to reduce testing time, direct physical validation confirming the reliability of the derived formation pressure estimates remains scarce in the literature. This study applies a low-rate/volume injection mini-frac approach that integrates flow regime identification and Horner analysis. Two complementary field cases are presented: a standard DFIT in a shale reservoir to validate the baseline methodology, and a low-volume mini-frac in a tight granite formation to demonstrate rapid estimation. Results show that low-volume injections exhibit a flow regime evolution identical to standard DFITs, yet this approach is expected to accelerate the transition to the pseudo-radial flow regime. To verify the reliability of formation pressure estimates derived from such methods, the formation pressure estimated in the low-rate/volume injection mini-frac case was benchmarked against a decade of continuous downhole fluid pressure monitoring data from the same well, yielding a relative error of less than 5%. The findings suggest that employing a lower injection rate and volume can improve formation pressure testing efficiency, with potential applications in unconventional hydrocarbon development and deep geo-energy engineering. Full article

To address the scientific challenges associated with complex microscopic pore structures and the unclear mechanisms of miscible gas injection in typical low-permeability carbonate reservoirs in the Middle East, online nuclear magnetic resonance (NMR) imaging experiments were conducted during water-alternating-CO₂ miscible flooding. The microscopic oil mobilization mechanisms were quantitatively investigated for different pore structure types and at various displacement stages. The results indicate that water-alternating-CO₂ miscible flooding achieves a relatively high degree of oil mobilization in large and medium pore–throat structures. This behavior is likely associated with Jamin-type flow resistance effects and flow regulation induced by gas–water alternating slugs. Differences in microscopic oil mobilization are mainly observed in mesopores (0.3–1.5 μm). The recovery degrees of mesopores in Cores 1, 2, and 3 reach 89%, 94.2%, and 78%, respectively, contributing 93.7%, 80.6%, and 50.9% to the total oil recovery. The degree of microscopic heterogeneity controls the distribution of remaining oil in core slices after breakthrough of the displacement front. In Core 1, the signal amplitude exhibits a gradual and uniform decline, indicating that gas–water alternating injection suppresses gas channeling and improves mobility control. In Core 2, the signal amplitude decreases more rapidly with increasing heterogeneity. In Core 3, the signal disparity continues to intensify, leading to the formation of dominant gas–water channeling pathways, while low-permeability pore–throat structures evolve into typical bypassed oil zones. As the CO₂–oil contact front progressively advances toward the outlet end, the swept volume gradually decreases due to the development of preferential flow channels. Consequently, significant remaining oil accumulation occurs near the outlet region. Full article

Unconventional oil and gas reservoirs naturally have low porosity and low permeability, which necessitate reservoir stimulation during production to achieve commercial exploitation. Therefore, to improve reservoir stimulation effectiveness, this study established a thermal–hydraulic–mechanical coupled numerical model suitable for hydraulic fracturing experiment scales based on rock mechanics, elasticity mechanics, damage mechanics, and flow mechanics theories, combined with maximum principal stress and Mohr–Coulomb damage criteria. The model was numerically solved within a finite element framework and used to simulate the reservoir hydraulic fracturing process. The results indicate that the propagation behavior of hydraulic fractures is controlled by reservoir rock mechanical properties, geostresses, reservoir temperatures, fracturing fluid viscosities, and injection rates. Among these, the increase in principal stress difference, reservoir temperature, fracturing fluid viscosity and injection rate promotes the propagation of hydraulic fractures along the direction of the maximum horizontal principal stress, whereas an increase in the rock’s elastic modulus reduces the propagation length of the hydraulic fractures. During fracturing, the fracturing fluid fractures the reservoir rock, significantly improving its porosity and permeability. This not only enhances the mobilization of unconventional oil and gas resources but also provides effective flow pathways for their migration, thereby ensuring the commercial viability of unconventional oil and gas resource extraction. Additionally, selecting a fracturing process that matches the geological characteristics of the study area during fracturing design is a prerequisite for improving the reservoir stimulation effect. The results of this study provide a reference for fracturing design and optimization. Full article

Supercritical carbon dioxide (SC-CO₂) fracturing has emerged as an environmentally friendly alternative to conventional water-based hydraulic fracturing; however, its inherently low viscosity restricts proppant-carrying efficiency and reduces fracture conductivity. To address this limitation, this study systematically investigates the rheological behavior and sand-carrying mechanisms of CO₂ dry fracturing fluid under various thermodynamic and compositional conditions. Rheological measurements were conducted to evaluate the effects of thickener concentration, temperature, and pressure on viscosity, while visualized experiments were performed to examine the influence of injection rate, sand ratio, thickener concentration, and temperature on proppant migration and deposition. A numerical model developed in Fluent was further employed to simulate the temporal evolution of proppant transport within the fracture. The results show that higher thickener concentrations and injection rates significantly enhance proppant transport distance and uniformity, whereas elevated temperature and sand ratio promote localized settling. The simulation results agree well with the experimental observations, validating the model’s reliability. This study elucidates the coupled effects of rheology and operating parameters on CO₂ dry fracturing behavior and provides theoretical and experimental guidance for optimizing CO₂-based fracturing fluids in low-permeability reservoirs. Full article

Conventional thermal recovery techniques face challenges in low-permeability heavy oil reservoirs due to low recovery factors and poor economic viability. To address these challenges, low-temperature oxidation (LTO) during oxygen-reduced air flooding was employed to achieve in situ oil upgrading and enhance oil recovery. Static oxidation tests at oxygen concentrations of 5%, 10%, 15%, and 21% were designed to analyze the produced gas composition and the physical properties of the oil following oxidation. We further employed Differential Scanning Calorimetry (DSC) and Thermogravimetric (TG) analysis to evaluate the oxidation behavior of crude oil under the same oxygen concentration conditions. Finally, long-core displacement experiments were performed to assess how the oxygen concentration influences the recovery efficiency. The results showed that under the tested conditions, oxygen consumption exceeded CO₂ generation, indicating that low-temperature oxygen addition reactions (formation of oxygenated species) dominated over complete oxidation. As the oxygen concentration increased, the oxidized crude oil exhibited a higher viscosity. At higher oxygen concentrations (15% and 21%), the asphaltene content increased significantly, resulting in poorer fluidity. The activation energy in the LTO stage decreased with increasing oxygen concentration, as revealed by kinetic analysis over the range of 5% to 21%. The LTO stage dominated the crude oil oxidation process. However, the heat release during this stage was less affected by the oxygen concentration. Consequently, increasing the oxygen concentration contributed only marginally to elevating the reservoir temperature. For the studied reservoir, oxygen-reduced air flooding with a 5% oxygen concentration achieved a final recovery factor of 34.82%. This represented a 1.76% improvement over conventional air flooding, thereby enabling economically efficient reservoir development. Full article

Due to the strong heterogeneity of the reservoir, early gas breakthrough and low CO₂ displacement efficiency are common issues in the CO₂ flooding process of domestic gravel reservoirs. This study focuses on a gravel reservoir in Xinjiang, proposing a quantitative evaluation method that combines early gas breakthrough identification and the inversion of gas channel characteristic parameters. The aim is to provide theoretical support and technical guidance for gas breakthrough risk warning, injection-production system optimization, and control measures during the CO₂ flooding process. The research method includes the following several key steps: first, clarifying the criteria for determining the time of gas breakthrough and proposing a classification method for early gas breakthrough types based on CO₂ concentration levels; second, adopting a “matrix-dominant gas channel” dual-medium model, considering the geometric and physical characteristics of inter-well gas channels, and deriving a theoretical calculation formula with gas breakthrough time and CO₂ concentration in the produced gas as the target; third, using actual gas breakthrough time and CO₂ concentration as constraints, constructing a method to invert the characteristic parameters of gas channels, quantitatively representing key parameters such as gas channel thickness ratio, permeability variation, and equivalent permeability; finally, through the combined analysis of CO₂ concentration and gas channel characteristic parameters, establishing a method for identifying gas channel types suitable for domestic gravel reservoirs. The practical application results show that the test area has formed localized dominant gas channels, but the overall stage is still in the early phase of weak gas breakthrough. Most gas breakthrough phenomena are weak, with only a few well groups experiencing severe gas breakthrough issues. The gas channel thickness ratio is generally less than 0.05, and the permeability variation mainly ranges from 2 to 20. The gas channels are primarily of the fracture type, with some areas also containing ordinary fractures and main control fractures. The method proposed in this study, which combines early gas breakthrough identification with the inversion of gas channel characteristic parameters, not only provides a new approach to revealing the characteristics of gas breakthrough during CO₂ flooding but also offers solid theoretical and technical support for optimizing CO₂ flooding technology and controlling gas breakthrough risks. Full article

Aiming to investigate the unclear lower limit of microscopic pore mobilization during CO₂ pre-fracturing in the shale oil reservoirs of the Ma51X well block, this study integrates high-temperature and high-pressure (110 °C 70 MPa) CO₂ huff-n-puff with nuclear magnetic resonance (NMR) experiments. The results demonstrate the following: (1) under high-temperature (110 °C) and ultra-high-pressure (70 MPa) conditions, the lower limit of mobilizable pores for CO₂ to displace reservoir crude oil reaches 1.7~2.2 nm; (2) the dominant mobilized pore range for CO₂ is 5.1~38.5 nm, and macropore abundance directly dictates the macroscopic sweep coverage of CO₂; (3) the modification effect of CO₂ on pore structure is primarily concentrated within the mesopore-to-macropore systems, and with an increase in huff-n-puff cycles, crude oil in mesopores progressively migrates toward macropores; and (4) multi-cycle CO₂ huff-n-puff exhibits a cyclic performance pattern characterized by dominance in the initial cycle and subsequent attenuation. This study precisely delineates the lower limit of mobilizable pores for crude oil in the shale oil reservoirs of the Ma51X well block, providing a robust theoretical foundation for the efficient development of this formation and analogous ultra-low permeability reservoirs. Full article

The physicochemical mechanisms and numerical characterization of amine-ether gemini surfactant emulsion flooding remain insufficient, limiting its field application in low-permeability reservoirs. This study developed a refined numerical simulation method that integrates full-process emulsion kinetics, including generation, coalescence, dispersion-assisted oil displacement, and demulsification, with graded emulsion characterization using the differentiated inaccessible pore volume (IPV) and residual resistance factor (RRF). Core-flooding validation demonstrated that the model accurately reproduced the key dynamic responses of water cut reduction and oil production increase, with a relative error of about 3.0%. Mechanistic analysis showed that the enhanced oil recovery performance arose from the combined effects of ultralow interfacial tension and emulsion-induced profile control. Relative to conventional surfactant flooding, emulsion flooding increased oil recovery by an additional 4.8–5.0% and lowered water cut by about 12 percentage points. For the Shengli Oilfield pilot block, the optimized injection design involved a surfactant concentration of 1.2 wt.%, an injection rate of 60 m³/d, a slug size of 0.01 PV, an injection–production ratio of 0.95, and a stepwise concentration-decline strategy. The field pilot further confirmed the applicability of the method: daily oil production of the well group increased by 46.5%, while comprehensive water cut decreased by 8.6 percentage points. These results demonstrate the value of the proposed method for both mechanistic characterization and field design of amine-ether gemini surfactant emulsion flooding in heterogeneous low-permeability reservoirs. Full article

Low-permeability reservoirs at the high-water-cut stage commonly suffer from dominant water channel development, poor sweep of weakly connected zones, and inefficient mobilization of remaining oil. Existing profile control or oil displacement agents can improve either flow diversion or microscopic oil displacement, but their single-agent evaluation does not fully explain the coupled process of sweep expansion and remaining oil mobilization. To address this issue, this study focuses on a previously optimized HK-0417/ALT-603 composite system and investigates its synergistic behavior at pore, core, and well group scales. Microscopic visualization displacement experiments were used to identify streamline redistribution and remaining oil evolution. Natural core experiments were conducted to evaluate injectivity adaptability and plugging persistence. Under slug injection conditions, the Box–Behnken design was employed to optimize the injection parameters. Finally, the field pilot response was analyzed based on production data from test wells in the Changqing Oilfield. The results show that the combination system simultaneously achieves streamline expansion and residual oil reduction: the injected fluid is redistributed toward weakly swept zones, large continuous oil bodies are fragmented and dispersed, and both sweep efficiency and oil displacement efficiency are superior to those of individual agents. Natural core experiments indicate that the injection pressure difference is generally controllable in cores with permeabilities ranging from 1.76 to 7.02 mD, and the plugging rate during subsequent water flooding reaches 75.47–80.54%. Response surface optimization yields the following optimal parameter combination: profile control slug volume = 0.41 pore volume (PV), oil displacement slug volume = 0.61 PV, injection rate = 0.19 mL/min, with a corresponding predicted enhanced oil recovery (EOR) of 18.52%. In the field pilot, the cumulative injection volumes of the two injectors are 41,898 kg and 61,472 kg, respectively. The injection pressure in the well group increases from 5.8 MPa to 7.0 MPa, the comprehensive water cut decreases from 90.6% to 85.3%, and the monthly decline rate is reduced from 0.5% to 0.2%. The proposed system mainly acts by increasing flow resistance and redirecting flow in high-water-cut channels, while it enhances oil detachment through interfacial tension reduction in oil-bearing pores. After optimizing the slug parameters, the field pilot exhibits a clear phased response and promising application potential. Full article

The Quemocuo area in the Qiangtang Basin is a key prospect for permafrost gas hydrate exploration in China. This study investigates source-reservoir-caprock characteristics and their control on gas hydrate accumulation based on drilling results from wells QK-8 and QK-9, integrated with multiple analytical methods. Two high-quality marine source rocks with cumulative thickness ~1000 m exhibit TOC values of 0.74–2.5%, Type II₂ kerogen, and vitrinite reflectance (Ro) of 1.37–2.94%, indicating high to over-mature thermal evolution primarily generating dry thermogenic methane. Gas logging shows hydrocarbon anomalies with a maximum desorbed gas content of 90 mL, confirming strong gas generation capacity. Although reservoir matrix properties are poor (porosity mostly <5%, permeability < 0.2 × 10⁻³ μm²), multi-phase tectonics and dissolution formed a secondary fracture-vug system. Permafrost conditions are favorable (thickness 100–120 m; geothermal gradient 4.5–4.7 °C/100 m), with extremely low permeability at high ice saturations, forming an effective multi-level seal together with thick mudstones. A key novel finding is the significant mixing of biogenic and thermogenic gases, with the biogenic component interpreted to originate from overlying Jurassic-Quaternary low-maturity strata, facilitated by late tectonic uplift and fault conduits. NW-trending faults connect deep thermogenic reservoirs and provide pathways for shallow biogenic gas migration. For the first time, this study establishes a region-specific composite accumulation model for the Qiangtang Basin, characterized by “lower generation and upper storage, fault-fracture conduit and permafrost sealing”, which reveals fault-controlled migration, fracture-vug-controlled storage, permafrost-controlled sealing, and mixed gas enrichment under a high geothermal gradient. Full article

Low porosity and ultra-low permeability are common characteristics of shale reservoirs. Traditional imbibition theory is unable to adequately describe fluid transport behavior in nanopores or capture microscopic mechanisms. In this study, imbibition efficiency was defined as the proportion of oil molecules displaced outside the initial oil phase region relative to the initial oil quantity. This study investigates shale oil spontaneous imbibition mechanisms by integrating molecular dynamics (MD) simulations with machine learning (ML) approaches. MD simulations were performed under baseline conditions of 353 K and 10 MPa, with additional simulations at temperatures ranging from 323 to 393 K, across quartz, calcite and dolomite, and at surfactant concentrations of 0.1% to 0.4% to analyze the influencing factors. Wettability differences among minerals were assessed indirectly through analysis of water density distributions, hydrogen bonding, and water–surface interaction energies, which consistently indicated that dolomite exhibits the strongest hydrophilic character, followed by calcite, with quartz showing the weakest water affinity. Results show that increased temperature, enhanced mineral hydrophilicity, and an optimal surfactant concentration of 0.3% significantly improve imbibition efficiency. Using four algorithms—Support Vector Regression trained, Gradient Boosting Regression Tree, XGBoost, and Random Forest—on the 36 MD-derived datasets, we built an ML model as a proof of concept. The Random Forest model performed the best after cross-validation and hyperparameter adjustment, with a validation R² of 0.81. The novelty of this study therefore is a proof of concept demonstrating the feasibility of MD with ML integration for imbibition prediction, while clearly identifying limitations and directions for future improvement. This provides theoretical foundations for optimizing shale reservoir development and field-scale recovery enhancement. Full article

Hydrogen (H₂) storage in subsurface formations has recently gained attention as a promising large-scale energy storage solution. Although previous studies have revealed distinct displacement behaviors between H₂ and other gases such as nitrogen (N₂) and carbon dioxide (CO₂) in high-permeability sandstones, the mechanisms governing H₂ migration in tight formations remain largely unexplored. To provide experimental observations that may help improve the understanding of H₂ migration in tight reservoirs, we conducted H₂ flooding experiments on a tight sandstone sample from the Ordos Basin under pore fluid pressures of 0.5, 1, and 2 MPa. Dynamic core flooding processes were monitored using a low-field nuclear magnetic resonance (NMR) analysis system. The capillary number (Nc) in this work ranged from 1.7 × 10⁻⁹ to 3.4 × 10⁻⁹, indicating a capillarity-dominated flow. H₂ saturation in the tight sandstone increased from 41.9% to 53.3% and then to 57.7% with increasing pore fluid pressure. Under a pore fluid pressure of 0.5 MPa, H₂ initially displaced water in small pores (T₂ < 10.5 ms), leading to prolonged fluctuations in water content over 136 min before significant displacement occurred in large pores (10.5 ms < T₂ < 6579.3 ms). In contrast, at a pore fluid pressure of 2 MPa, the water in large pores was more significantly impacted, with a marked decrease in water saturation observed after 8 min of flooding. These findings provide direct experimental evidence of pressure-dependent and pore-scale selective displacement patterns of H₂ in tight sandstone, offering new insights into the fluid dynamics that control hydrogen injectivity and storage efficiency in low-permeability reservoirs. Full article

The efficient development of low-permeability reservoirs is critically constrained by severe geological heterogeneity, marginal permeability (<10 mD), and the consequent prevalence of low-productivity wells. Conventional intermittent production management, reliant on empirical fixed-cycle schedules, fails to adapt to dynamic reservoir behavior and wellbore conditions, leading to suboptimal energy efficiency and recovery. This study presents a physics-constrained, data-driven framework for adaptive intermittent production optimization, specifically designed to address the coupled geological-engineering complexities of such reservoirs. The methodology integrates three core innovations: (1) a hybrid flowing bottomhole pressure (FBHP) decline model coupling a “Three-Segment” wellbore pressure calculation with inflow performance relationship (IPR) curves, enabling dynamic characterization of pressure depletion; (2) a shut-in pressure buildup prediction framework combining a physically interpretable dual-exponential recovery mechanism—representing near-wellbore elastic expansion and far-field formation recharge—with a Random Forest Regression algorithm to capture the influence of geological and operational heterogeneity; and (3) a “Dual-Curve Intersection Method” that autonomously determines optimal pumping and shut-in durations by intersecting predicted pressure decline and recovery curves under geological constraints. Field implementation on 15 low-production wells in the Jiyuan Oilfield—a representative low-permeability asset—demonstrated robust performance: average pump efficiency improved from 14.3% to 14.49%, and average single-well electricity savings reached 15.61%. This work establishes a closed-loop intelligent control framework that bridges reservoir geology, wellbore hydraulics, and machine learning, offering a scalable solution for enhancing energy efficiency and production sustainability in low-permeability and unconventional resources. Full article