Search Results (974)

Shale oil reservoirs exhibit ultralow permeability and complex pore structures, which result in non-Darcy low-velocity flow and cause permeability to be stress-sensitive. Moreover, two-phase flow of oil and gas frequently occurs during the depletion of shale oil reservoirs. Consequently, investigating the rate-transient behavior of shale oil wells necessitates comprehensive consideration of multiphase flow, threshold pressure gradients, and stress sensitivity. Although numerous analytical models exist for rate-transient analysis of multistage fractured horizontal wells, none of them simultaneously incorporate these critical factors. In this study, we extend the classical five-region model to incorporate multiphase flow, threshold pressure gradients, and stress sensitivity. The proposed model is solved using Pedrosa’s transformation, perturbation theory, the Laplace transform, and the Stehfest numerical inversion method. A systematic analysis of the influence of various parameters on the oil production rate and cumulative oil production is conducted, and a field case study is presented to validate the applicability and effectiveness of the model. It is found that the permeability modulus of the main fracture, the half-length of the main fracture, and the threshold pressure gradient of the unstimulated reservoir have a significant influence on cumulative oil production spanning 20 years. With a 100% relative input error, these parameters result in prediction errors of 23.77%, 16.65%, and 17.78%, respectively. In contrast, the threshold pressure gradient of the main fracture and the threshold pressure gradient of the stimulated reservoir have a negligible impact; under the same level of input error (100%), they cause only 0.36% and 0.48% prediction errors in the 20-year cumulative oil production period, respectively. This research provides an efficient and reliable framework for analyzing production data and forecasting shale oil well performance. Full article

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

Horizontal wells combined with multi-stage fracturing are key techniques for extracting tight oil formation. However, due to the ultra-low permeability and porosity of reservoirs, energy depletion occurs rapidly, necessitating external supplements to sustain production. During the hydraulic fracturing process, large volumes of fracturing fluid are injected into reservoirs, increasing its pressure to a certain extent. However, due to the oil-wet nature of the formation, the fracturing fluid cannot penetrate the rock, failing to enhance oil recovery during the shut-in period. Surfactant-based nanofluids have been introduced as fracturing fluid additives to reverse rock wettability, thereby boosting imbibition-driven recovery. Although the imbibition has been studied to inspire the tight oil recovery, few studies have demonstrated the imbibition in enhanced fossil hydrogen energy, which further promotes the imbibition recovery. In this paper, complex nanofluid dispersions (CND) have been proved to enhance the tight reservoir pressure. Through contact angle and imbibition experiments, it is shown that CND can transform oil-wet rock to water-wet, reduce the adhesion of oil, and improve the ultimate oil recovery through the imbibition effect. Then, core flow testing experiments were conducted to show CND can decrease the flow resistance and improve the swept area of the injected fluid. In the end, pressure transmission tests were conducted to show CND can enhance the formation energy and production after fracturing. Results demonstrate that CND enables the fracturing fluid to travel further away from the hydraulic fractures, thus decreasing the depletion of tight formation pressure and maintaining a higher oil production rate. Results help optimize the design of the hydraulic fracturing of tight offshore reservoirs. Full article

To address the problem of serious gas channeling during CO₂ flooding in low-permeability reservoirs, which leads to poor oil recovery, this study developed a CO₂-resistant gel using a novel CO₂-responsive polymer (ADA) for gas channel control. The ADA polymer was synthesized via free-radical copolymerization of acrylamide (AM), dimethylaminopropyl methacrylamide (DMAPMA), and 2-acrylamido-2-methylpropanesulfonic acid (AMPS), which introduced protonatable tertiary-amine groups and sulfonate moieties into the polymer backbone. Comprehensive characterizations confirmed the designed structure and adequate thermal stability of the ADA polymer. Rheological tests demonstrated that the ADA polymer solution exhibits significant CO₂-triggered viscosity enhancement and excellent shear resistance. When crosslinked with phenolic resin, the resulting ADA gel showed outstanding CO₂ tolerance under simulated reservoir conditions (110 °C, 10 MPa). After 600 s of CO₂ exposure, the ADA gel retained over 99% of its initial viscosity, whereas a conventional HPAM-based industrial gel degraded to 61% of its original viscosity. The CO₂-resistance mechanism involves protonation of tertiary amines to form quaternary ammonium salts, which electrostatically interact with sulfonate groups, creating a reinforced dual-crosslinked network that effectively protects the gel from H⁺ ion attack. Core flooding experiments confirmed its ability to enhance oil recovery by plugging high-permeability channels and diverting flow, achieving a final recovery of up to 48.5% in heterogeneous cores. This work provides a novel gel system for improving sweep efficiency and storage security during CO₂ flooding in low-permeability reservoirs. Full article

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

Class III reservoirs in the Daqing Oilfield are characterized by low permeability and strong heterogeneity, posing significant challenges to enhanced oil recovery (EOR). To improve the recovery efficiency of these reservoirs, the viscosifying ability, stability, shear resistance, and profile-control performance of fifteen polymer solutions were experimentally evaluated, and the two most compatible formulations were selected for the Daqing Class III reservoirs. Subsequently, a three-dimensional physical model equipped with real-time saturation monitoring was employed to compare the EOR performance of the selected polymers. The results indicate that a 1500 mg L⁻¹ polymer solution with a molecular weight (Mw) of 16 × 10⁶ Da and a 1200 mg L⁻¹ polymer solution with an Mw of 19 × 10⁶ Da exhibit the best compatibility with the target formation. After injecting the 1500 mg L⁻¹ (Mw = 16 × 10⁶ Da) polymer solution, the ultimate recovery reached 53.38%, with displacement efficiencies of 64.34% and 58.16% and sweep efficiencies of 92.26% and 80.35% in the high- and low-permeability layers, respectively. Injection of the 1200 mg L⁻¹ (Mw = 19 × 10⁶ Da) polymer solution yielded an overall recovery of 47.71%, corresponding to displacement efficiencies of 60.34% and 54.16% and sweep efficiencies of 88.52% and 76.38%. Consequently, the 1500 mg L⁻¹ (Mw = 16 × 10⁶ Da) polymer solution delivers the highest recovery increment in Class III reservoirs. These findings provide valuable guidance for the efficient polymer-flooding development of Class III reservoirs in Daqing and analogous formations worldwide. Full article

The ZN Oilfield shale reservoir is characterized by thin sand–shale interbeds, strong lateral and vertical heterogeneity, poor porosity–permeability, low formation pressure coefficient, and low brittleness, which together limit fracture propagation and suppress production after conventional hydraulic fracturing. To overcome these constraints, we propose an intensive-stage, closely spaced volumetric fracturing technology that couples energy-replenishment pressurization with differentiated parameter design. Numerical simulations were used to quantify how injected fluid volume affects the post-fracturing formation pressure coefficient and estimated ultimate recovery (EUR), and to determine economically optimal energy-replenishment scales. Guided by a “dual sweet spot” evaluation (geological + engineering), field designs reduced stage spacing from 80–100 m to 30–50 m and cluster spacing from 10–20 m to 6–10 m, and increased proppant and fluid intensities to ~5.0 t/m and 22.0 m³/m, respectively. Field monitoring and production data show average fracture half-length increased to 193 m, and average initial oil production per well rose from 8.8 t/d to 12.9 t/d (≈46% increase). These results demonstrate that the proposed approach effectively enlarges fracture-controlled reservoir volume, enhances formation energy, and substantially improves single-well performance in low-pressure shale oil systems. Full article

The characteristics of shale oil reservoirs, such as low porosity, ultra-low permeability, and complex pore structure, are key factors affecting effective pore space and fluid migration. This study focuses on medium-to-high maturity mud shale in the Qing-1 Member of the Qingshankou Formation in the Gulong Sag. Using methods such as XRD, organic geochemical testing, and multi-scale pore characterization (FE-SEM, low-temperature CO₂–N₂ adsorption, high-pressure mercury intrusion, and CT scanning), the lithofacies and pore structure were comprehensively characterized, and their controlling factors were analyzed. The results indicate: (1) The mineral composition is dominated by felsic and clay minerals. Based on a three-level classification standard of “mineral composition–sedimentary structure–organic matter abundance”, seven subfacies were identified, with the dominant lithofacies being Felsic–Clayey Mixed Shale and Felsic-bearing Clay Shale. (2) The reservoir space consists of inorganic pores, organic pores, microfractures, and a small amount of other auxiliary pores, exhibiting “bimodal” pore size characteristics. Micro–mesopores dominate adsorption, while macropores/microfractures control free oil seepage; mesopores contribute the most to pore volume. (3) In terms of oil-bearing potential, Felsic–Clayey Mixed Shale shows prominent movable oil potential (average OSI: 133.08 mg/g; S₁ > 2 mg/g, OSI > 100 mg/g). (4) CT-based 3D stick-and-ball models indicate that Felsic–Clayey Mixed Shale has the best connectivity (connectivity rate: 30.63%), with throat radii mostly ranging from 1–15 μm and pore radii from 2–20 μm. (5) Pore development is synergistically controlled by total organic carbon (TOC, with an optimal range of approximately 1–2.5%), clay/felsic mineral ratio, and bedding/structural fractures. The formation of the pore system is the result of dynamic coupling of organic–inorganic interactions during diagenetic evolution: intergranular pores of clay minerals and microfractures jointly contribute to specific surface area and pore volume, while bedding fractures connect nanopore clusters to enhance seepage capacity. This study improves the integrated understanding of dominant lithofacies, pore structure, and oil-bearing potential in the Qing-1 Member of the Gulong Sag, providing a basis for sweet spot evaluation and development optimization. Full article

In order to address the challenges of soft coal texture, poor permeability, and wellbore instability in tectonic coal reservoirs, a new biodegradable fuzzy-ball drilling fluid combined with a bio-based surfactant and enzyme system was developed. The optimal formula was determined through single-factor experiments and orthogonal optimization: 6% KCl–2% trehalose composite base slurry + 4% carboxymethyl chitosan + 0.4% hydroxypropyl methylcellulose + 0.15% xanthan gum + 0.12% guar gum + 0.3% cocamidopropyl betaine + 0.15% lauryl alcohol + 0.2% triethanolamine, with the degrading agent consisting of 0.2% composite-modified amylase + 0.04% composite-modified cellulase. The performance evaluation results show that the drilling fluid has stable rheological properties in the temperature range of 40~60 °C (yield point-plastic viscosity ratio: 0.8~0.9) and low filtration loss (5.8~6.5 mL); it exhibits excellent inhibition on tectonic coal, the inhibition rate of linear expansion rate is 72.1%, and the 14-mesh rolling recovery rate is 82.5%; at 55 °C, the gel breaking rate reaches 96.9% after 1.5 h, the mud cake removal rate reaches 98.8%, and the permeability recovery rate reaches 84.8%. After applying this drilling fluid, the unconfined compressive strength of tectonic coal increases from 1.2 MPa to 2.8 MPa (an increase of 133.3%), and the triaxial compressive strength increases from 20.1 MPa to 38.5 MPa (an increase of 91.5%); the numerical simulation shows that the radial displacement around the wellbore decreases by 62.1% and the plastic zone area shrinks by 73.2%. This novel biodegradable fuzzy-ball drilling fluid has the characteristics of efficient wellbore stabilization, easy degradation, and low formation damage, providing effective technical support for the green development of coalbed methane in tectonic coal reservoirs. Full article

Unconventional shale oil reservoirs, characterized by ultra-low porosity and permeability, severely constrain oil recovery. CO₂-enhanced oil recovery (CO₂-EOR) following hydraulic fracturing is an effective approach that combines incremental oil recovery with long-term CO₂ storage. However, CO₂ transport in the fracture–matrix system is complex, especially when molecular diffusion and geochemical reactions are coupled. This study conducts numerical simulations on a representative shale reservoir in the Ordos Basin, incorporating both mechanisms under post-fracturing injection–soaking conditions. The results show that molecular diffusion enhances CO₂ mass transfer across the fracture–matrix interface, increasing the final CO₂ sweep efficiency by 0.17 percentage points relative to convection alone, whereas geochemical reactions reduce it by about 0.3 percentage points. When both mechanisms coexist, the net effect is a decrease of approximately 0.2 percentage points in CO₂ sweep efficiency. In contrast, pressure sweep efficiency differs by less than 0.5 percentage points among all cases and stabilizes near 47%, suggesting that pressure propagation is only weakly affected by diffusion and reactions. Sensitivity analysis reveals that, among operational parameters, injection pressure and injection rate strongly affect CO₂ sweep efficiency, whereas soaking time governs pressure propagation. Among reservoir parameters, permeability has the most pronounced influence on both CO₂ and pressure sweep efficiencies, followed by temperature, while initial reservoir pressure has minimal impact. This work quantitatively elucidates the coupled roles of molecular diffusion and geochemical reactions in shale reservoirs and provides practical guidance for optimizing post-fracturing CO₂-EOR operations. Full article

Depressurization combined with thermal stimulation based on injection-production well patterns is considered promising for gas hydrate development. Nevertheless, its direct application to Shenhu challenging hydrates may be problematic due to the presence of low reservoir permeability and permeable boundaries. The present study proposes to improve the development potential of Shenhu hydrate by reservoir reconstruction, including boundary sealing and reservoir fracturing, and numerically investigates the production performance. The results showed that water intrusion, hot loss, and gas leakage can be effectively addressed by boundary sealing. Nevertheless, it cannot enhance productivity as thermal decomposition gas accumulated around the injection well. Conversely, reservoir fracturing can significantly improve extraction efficiency as substantial amounts of hydrates dissociate along the fractures, and the gas can be well recovered through the fractures. However, reservoir fracturing was not conducive to water control and energy utilization as it induced more severe water flooding and gas leakage. Under the synergistic effect of the two, there was no methane leakage, and the gas production rate increased with increasing fracture conductivity, while the gas-to-water ratio and energy ratio presented the opposite trend. To obtain a favorable production performance, a fracture with a conductivity of 1–10 D·cm was recommended. Therefore, the combination of boundary sealing and reservoir fracturing makes it feasible for safe and efficient extraction of offshore challenging hydrate under the injection-production mode. Full article

This study addresses the challenges of low-pressure oil well workover operations, namely, severe loss of water-based workover fluid, significant reservoir damage from conventional temporary plugging agents, and slow production recovery, by focusing on the yet-mechanistically unclear “fuzzy-ball workover fluid.” Laboratory experiments combined with field data were used to evaluate its plugging performance and reservoir-protective mechanisms. In sand-filled tubes (diameter 25 mm, length 20–100 cm) sealed with the fuzzy-ball fluid, the formation’s bearing capacity increased by 3.25–18.59 MPa, showing a positive correlation with the plugging radius. Compatibility tests demonstrated that mixtures of crude oil and workover fluid (1:1) or crude oil, workover fluid, and water (1:1:1) held at 60 °C for 80 h exhibited only minor apparent viscosity reductions of 4 mPa·s and 2 mPa·s, respectively, indicating good stability. After successful plugging, a 1% ammonium persulfate solution was injected for 2 h to break the gel; permeability recovery rates reached 112–127%, confirming low reservoir damage and effective gel-break de-blocking. Field data from five wells (formation pressure coefficients 0.49–0.64) showed per-well fluid consumption of 33–83 m³ and post-workover liquid production index recoveries of 5.90–53.30%. Multivariate regression established mathematical relationships among bearing capacity, production index recovery, and fourteen geological engineering parameters, identifying the plugging radius as a key factor. Larger radii enhance both temporary plugging strength and production recovery without harming the reservoir, and they promote production by expanding the cleaning zone. In summary, the fuzzy-ball workover fluid achieves an integrated “high-efficiency plugging–low-damage gel-break–synergistic cleaning” mechanism, resolving the trade-off between temporary-plugging strength and production recovery in low-pressure wells and offering an innovative, environmentally friendly solution for the sustainable and efficient exploitation of oil–gas resources. Full article

High-pressure water injection (HPWI) refers to injecting water into the formation under conditions where the injection pressure is higher than or close to the formation fracture pressure. This technique can effectively improve the water absorption capacity of low-permeability reservoirs and maintain the formation pressure above the bubble point. It is a key technology for solving the problem of “difficult injection and difficult recovery” in low-permeability reservoirs, thereby achieving increased injection and enhanced production. However, due to the lack of a unified understanding of the mechanisms of dynamic micro-fractures and the mechanism of pore volume expansion and permeability enhancement during HPWI, the technology has not been widely promoted and applied. Based on an in-depth analysis of the mechanism of high-pressure water injection and by building a geological model for an actual oilfield development block, the “compaction–expansion” theory of rocks is used to characterize the variation in reservoir properties with pore pressure. This model is used to simulate the reservoir’s pore volume expansion and permeability enhancement effects during high-pressure water injection. The research results show the following: (1) HPWI can increase the effective distance of injected water by changing the permeability of the affected area. (2) During HPWI, the effective areas in the reservoir are divided into three regions: the enhanced-permeability zone (EPZ), the swept zone without permeability enhancement, and the unswept zone. Moreover, the EPZ expands significantly with higher injection pressure, rate, and volume. However, the degree of reservoir heterogeneity will significantly affect the effect of HPWI. (3) Simulation of two production modes—“HPWI–well soaking–oil production” and “simultaneous HPWI and oil production”—shows that under the first production mode, the degree of uniformity of the production wells’ response is higher. However, in the production wells in the EPZ, after a certain stage, an overall water flooding phenomenon occurs. In the second mode, the production wells in the water channeling direction show an alternating and rapid water-flooding phenomenon, while the production wells in the non-water channeling areas are hardly affected. Meanwhile, for local production wells with poor effectiveness of high-pressure water injection, hydraulic fracturing can be used as a pilot or remedial measure to achieve pressure-induced effectiveness and improve the sweep efficiency of the injected water. The results of this study explain the mechanisms of volume expansion and permeability enhancement during high-pressure water injection, providing guiding significance for the on-site application and promotion of high-pressure water injection technology in low-permeability reservoirs. Full article

To address interlayer interference during multi-layer commingled production in gas reservoirs with pressure differences, this study investigates the low-permeability gas reservoir in the central Linxing area of the Ordos Basin. High-temperature, high-pressure physical simulation experiments were conducted to systematically study single-layer, two-layer, and three-layer commingled production under different pressures (13, 15, and 17 MPa). A large-scale physical simulation system, capable of withstanding 100 °C and 50 MPa, was constructed for the dynamic monitoring of multi-layer commingled production. This system accurately characterized the instantaneous gas production, cumulative gas production, and pressure drop behavior of individual layers under both single-layer and commingled production conditions. The results indicate that significant interlayer interference occurs during multi-layer commingled production. This interference is primarily manifested as a capacity inhibition effect, where the high-pressure layer suppresses the production of the low-pressure layer. Typical phenomena accompanying this effect include ‘backflow’ and ‘staggered production peaks’. Quantitative analysis indicates that the cumulative gas production for two-layer and three-layer commingled production is 3.2% and 9.06% lower, respectively, than the summed production from equivalent single-layer operations. Notably, in the three-layer commingled production scenario, the productivity of the low-pressure layer (Q5) was reduced by 19.87%, a significantly greater loss compared to the 4.39% reduction observed in the high-pressure layer (T2). Furthermore, the study demonstrates that the severity of interlayer interference is positively correlated with the interlayer pressure difference. Additionally, as the number of commingled layers increases, the interference effect exhibits a superimposed enhancement characteristic. Full article

Multistage hydraulic fracturing enhances recovery from low-permeability reservoirs. Understanding stress shadow effects and fracture reorientation is essential for optimizing multistage fracturing. This study develops a fully coupled 3D hydromechanical model based on the finite–discrete element method (FDEM) to simulate echelon hydraulic fractures in dual-well systems under varying well spacings and initial perforation lengths. Results show that fracture interactions are highly sensitive to spacing and initiation asymmetry. Closely spaced fractures generate strong stress shadows, influencing propagation depending on geometry and timing. A theoretical model incorporating induced stress and the weight function further clarifies stress shadow mechanisms, introducing disturbance factors to describe promotion or inhibition effects between fractures. The findings reveal an optimal well spacing that maximizes fracture complexity and reservoir stimulation, while pronounced initiation asymmetry leads to dominant–subordinate propagation and reduced efficiency. This integrated framework improves understanding of fracture evolution and guides fracturing optimization in tight formations. Full article