Search Results (656)

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

This article considers the causes of inter-column pressures (ICP) in wells and their impact on operational reliability. The analysis of Karachaganak field well stock for the period from 2001 to 2024 demonstrates that inter-column pressures manifest in a time frame of five to six years following drilling. These pressures are characterized by a spontaneous emergence and subsequent dissipation. This study proposes a mechanism where the formation of ICP is influenced by multiple factors, including cementing defects, as well as physical and chemical processes. Additionally, the geological heterogeneity of the section has been identified as a contributing factor. The results of studies employing a mobile laboratory and pumping unit are presented. The mobile laboratory unit (MLU) operates with pressure sensors in the range of 0–100 MPa (accuracy ±0.5%), a pump rate of 0.5–20 L/min, and an injection pressure up to 70 MPa; fluid sampling is performed by a discrete sampler with a volume of 500 mL. These allow the identification of sources and channels of fluid migration into the inter-column space, as well as the carrying out of technological operations to reduce and eliminate ICP. This paper sets out a risk-oriented method of inter-column pressure assessment. The proposed risk-based method classifies wells into three risk levels (low, medium, high) based on a composite index R = (P/Pmax) + (V/Vmax) + (C/Cmax) where P is annulus pressure, V is escaped fluid volume per day, C is concentration of H₂S, CO₂, or mercaptan, respectively, and threshold values are Pmax = 35 MPa (API RP 90), Vmax = 50 m³/day, and Cmax = 10 ppm for H₂S. This method takes into account not only the pressure value, but also the volume of escaping fluid and the concentration of aggressive components. It is concluded that an integrated approach to diagnostics and management of inter-column pressures is necessary. This approach should be supported by technological solutions that ensure increased reliability and environmental safety of well operation. Full article

Hydraulic fracture network initiation and propagation in tight sandstone are strongly controlled by mineral heterogeneity and fluid–solid interaction. However, existing numerical models still have limited capability in simultaneously representing multi-mineral distributions and dynamically coupled fracture-fluid processes. In this study, a two-dimensional polygonal discrete element fluid–solid coupled model was established based on mineralogical images of tight sandstone. Compared with conventional continuum-based approaches, the proposed model is better suited to describing fracture initiation, branching, and network evolution in multi-mineral granular media. Under dimensionless operating conditions calibrated against field data, coupled and uncoupled formulations were systematically compared to evaluate the role of hydro-mechanical interaction during hydraulic fracturing. The coupled simulations generated consistently more fractures than the uncoupled simulations over the investigated injection-rate range, with an average increase of 28.7% and a maximum increase of 67.2%. Compared with the uncoupled model, the coupled model also predicted higher breakdown pressures and stronger fracture-tip pressure concentrations, and the breakdown pressure increased with injection rate. Under low injection rates, the coupled formulation reproduced pressure-buildup-driven fracture-tip advance, whereas the uncoupled formulation failed to sustain fracture propagation. Under higher injection rates, the coupled formulation produced multilayered and highly branched fracture networks, while the uncoupled formulation mainly generated simple first-order branching. These results demonstrate that hydro-mechanical coupling is a controlling mechanism for fluid-energy dissipation, fracture-tip pressure evolution, and complex fracture network formation in tight sandstone. This study provides an image-based polygonal DEM framework for evaluating hydro-mechanical fracture network evolution in multi-mineral tight sandstone. 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

Hydraulic fracturing is critical for unconventional oil and gas development, yet perforation-induced initial damage impairs the integrity of the casing–cement sheath–formation assembly, causing fracturing fluid channeling and reduced stimulation efficiency. A stress-seepage coupling numerical model was established to simulate interface fracture initiation, propagation, and sealing failure, quantifying axial and circumferential channeling evolution at the cement–formation interface. Key parameters (casing eccentricity, cement elastic modulus, injection rate, and minimum horizontal in situ stress) were systematically analyzed. Results show fluid preferentially migrates through perforation-weakened zones, with channeling initiating via axial debonding, then circumferential propagation, and finally dominant axial extension. Casing eccentricity exacerbates channeling, while higher cement elastic modulus or in situ stress mitigates it significantly; injection rate affects channeling length but not fracture initiation/propagation pressures. This study provides theoretical and practical guidance for fracturing channeling risk control. 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

In this study, we present a novel microfluidic platform for tunable size-based particle separation within a straight microchannel using symmetrical viscoelastic sheath flows. The device incorporates two pairs of symmetrical microchannels for sheath fluid injection: the first pair facilitates particle focusing and separation, while the second pair enables dynamic regulation of the separation distance between particle streams. Experimental results demonstrate that a 50 ppm polyethylene oxide (PEO) solution focuses 1 μm polystyrene particles toward the channel centerline via elastic forces, whereas 5 μm particles migrate toward the channel sidewalls under dominant inertial forces, effectively overcoming the elastic effects. The interplay between inertial and elastic forces thus achieves size-dependent particle separation. Furthermore, by adjusting the flow rate of the PEO sheath in the second pair of microchannels, the separation distance between the two particle populations can be modulated in real time. Higher PEO concentrations (500 and 1000 ppm) exhibit enhanced capabilities to deflect particle flow streams. By contrast, the lower PEO concentrations like 50, 100 and 200 ppm are more versatile in adjusting the separation distance. The biological applicability of this platform is further demonstrated through the tunable separation of Escherichia coli (E. coli) and Chlorella vulgaris (C. vulgaris). This microfluidic device demonstrates significant potential for downstream particle processing applications, including real-time particle detection and targeted drug delivery. 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 capacitance resistance model (CRM) is an analytical tool widely used to forecast reservoir performance in enhanced oil recovery (EOR) methods. By representing flow dynamics and the connectivity between injection and production wells through the parameter of interwell connectivity, CRM offers fast computational processing and minimal input data requirements. These advantages make CRM a practical alternative for rapid reservoir analysis, especially when full-scale numerical simulations are infeasible due to time and budget constraints. CRM, rooted in material balance and productivity equations, uses injection/production rates and bottom-hole pressure data to construct reservoir models through optimization techniques, which can then be combined with oil fractional flow models for predictive purposes. Initially designed for waterflooding operations, CRM has seen limited but promising applications in gas injection projects, where research remains incomplete. This study presents a new formulation of CRM tailored for immiscible gas injection, incorporating the pseudo-pressure concept coupled with a saturation profile. The pseudo-pressure concept is a mathematical transformation that linearizes gas flow equations by accounting for variations in gas compressibility and viscosity with pressure. The proposed CRM was evaluated using a PUNQ-S3 benchmark reservoir model in the CMG IMEX black oil simulator, involving two injectors and four producers. History- matching results for fluid production rates showed that the newly developed CRM achieved the lowest NRMSE, outperforming other CRM models across a wide range of reservoir properties. Sensitivity analyses were conducted to examine the effects of gas and oil PVT properties on the model’s performance. The newly developed CRM, incorporating the pseudo-pressure concept and saturation profiles, demonstrates superior performance in predicting fluid production rates, achieving an average NRMSE of 15.3% in a base case scenario, compared to other tested CRM models. Additionally, the sensitivity analysis on the effect of fluid properties shows that higher gas viscosity, lower gas formation volume factor, and increasing oil API gravity improve the CRM model’s performance, and under all tested conditions the newly developed CRM provides the most accurate production history match. This study not only establishes the new CRM as a robust and accurate predictive tool for immiscible gas injection but also provides a comprehensive discussion on reservoir parameter ranges and model limitations, advancing the applicability of CRM in EOR processes. Full article

The Gulong shale oil reservoir is characterized by high clay content and strong heterogeneity, with substantial variations in mineral composition among different intervals. However, existing fracability evaluation methods for such continental shales remain inconsistent and often rely on oversimplified two-dimensional fracture descriptors, lacking a multi-parameter quantitative framework derived from three-dimensional fracture characterization. In this study, the Q1 and Q9 members of the Gulong shale oil were selected, and laboratory-scale hydraulic fracturing simulation experiments were conducted using supercritical carbon dioxide (SC-CO₂), liquid CO₂, and water as the fracturing media. Within a fractal-theory framework based on CT-derived three-dimensional reconstructions, a multi-scale evaluation index system was established by integrating fractal dimension, fracture density, and spatial connectivity. The experimental results demonstrate that fluid properties exert a decisive influence on rock failure behavior. Owing to its ultra-low viscosity and strong diffusivity, SC-CO₂ can significantly reduce formation breakdown pressure while effectively activating natural weak planes to generate a more complex fracture network. For the Q9 shale, the breakdown pressure under SC-CO₂ is reduced by 11.91% and 8.33% relative to water and liquid CO₂, respectively. Moreover, the fracture fractal dimension reaches 2.41 under SC-CO₂, which is markedly higher than the values obtained under liquid CO₂ (2.18) and water (2.12). Mineral composition and densely developed bedding are the key factors inducing fracture branching and deflection, whereas injection rate and an asymmetric stress field regulate the internal energy-release rate and stress path, thereby influencing fracture crossing capability and aperture evolution. Based on the experimental dataset, a fracture complexity index (FCI) evaluation model was developed: under SC-CO₂ fracturing, the FCI values are 8.92 for the Q9 member and 4.43 for the Q1 member, and the model predictions are in good agreement with physical observations. This work elucidates the failure mechanism of the Gulong shale under multi-field coupling and provides a theoretical basis for optimizing hydraulic fracturing and evaluating fracability in unconventional reservoirs through the proposed FCI-based assessment framework. Full article

Background and Objectives: Neovascular age-related macular degeneration (nAMD), including typical nAMD (tAMD) and polypoidal choroidal vasculopathy (PCV), is a leading cause of visual impairment. This study investigated the real-world short-term outcomes of faricimab, a bispecific antibody targeting Ang-2 and VEGF-A, in patients with treatment-naïve or -refractory nAMD. Materials and Methods: This retrospective study analyzed treatment-naïve or -refractory nAMD eyes receiving one, two, or three monthly intravitreal faricimab injections. Primary outcomes were changes in best-corrected visual acuity (BCVA) and central foveal thickness (CFT) one month after the last injection. Secondary outcomes included the dry macula rate (absence of subretinal and intraretinal fluid) and subgroup comparisons between tAMD and PCV. Results: After a single injection, both treatment-naïve (n = 76) and -refractory (n = 44) eyes showed significant CFT reduction (p < 0.0001) but no significant BCVA improvement (p > 0.05). Dry macula was achieved in 63.2% of treatment-naïve and 71.4% of treatment-refractory eyes. In 38 treatment-naïve eyes receiving three injections, both CFT and BCVA significantly improved from baseline (p < 0.001 and p = 0.02, respectively), with a 94.7% dry macula rate. Subgroup analysis of those receiving three injections revealed that PCV eyes exhibited significant visual improvement, whereas tAMD eyes did not. No serious systemic or ocular adverse events were observed over the short-term follow-up period. Conclusions: Intravitreal faricimab is effective for both treatment-naïve and -refractory nAMD in the short term. While anatomical improvements were comparable between subtypes, the PCV subgroup showed a trend toward greater visual improvement in this small cohort; however, this may be influenced by the significantly younger age of PCV patients. These findings are exploratory and require validation in larger, age-matched prospective studies. Full article

Tight oil reservoirs are characterized by poor petrophysical properties. After hydraulic fracturing, the low flowback rate of fracturing fluid readily leads to the formation of a water invasion zone in the near-wellbore region, which severely restricts the performance of Carbon dioxide (CO₂) huff-n-puff. To clarify the damage mechanism of the water invasion zone on CO₂ huff-n-puff in tight oil reservoirs and determine the key regulatory parameters, tight cores with a relative water invasion zone length Δδ = 0.3 were adopted as the research subject. Five groups of injection–soaking–production time combinations were designed, and single-factor analysis was implemented using the control variable method. Integrated with numerical simulation and nuclear magnetic resonance (NMR) testing, the influence of the water invasion zone, pore crude oil mobilization characteristics, and parameter regulation effects were systematically explored. The results demonstrate that the water invasion zone occupies effective pore throats to form a continuous water-phase barrier, hindering CO₂ seepage and mass transfer. After four huff-n-puff cycles, the cumulative recovery factor of the water-invaded model is 4.13 percentage points lower than that of the water-free model. After four huff-n-puff cycles, the cumulative recovery factor of the water-invaded model is 4.13 percentage points lower than that of the water-free model. The NMR T₂ spectra of cores with and without water invasion exhibit remarkable discrepancies: the water-free core presents a unimodal structure, while the water-invaded core features a distinctive bimodal structure, with obvious staged characteristics in crude oil mobilization. The recovery factor declines nonlinearly and sharply with the increase of Δδ, verifying that the water invasion zone length is the dominant controlling factor. The regulation effects of injection, soaking, and production time differ significantly: injection time serves as the pivotal parameter for enhancing oil recovery. Prolonging injection time can strengthen displacement intensity and dismantle the water-phase barrier, thereby elevating the recovery factor, whereas soaking time and production time have no significant improvement effect. The results can provide valuable references for the parameter optimization of CO₂ huff-n-puff in water-invaded tight oil reservoirs. Full article

The characteristics of two-phase flow in heterogeneous shale porous structures are of critical importance for oil and gas extraction and for evaluating the efficiency of underground resource recovery and carbon sequestration. However, although non-isothermal two-phase flow has been investigated in previous studies, systematic research on non-isothermal CO₂–crude oil displacement in heterogeneous shale porous structures remains relatively scarce. In this study, a multi-phase simulator was employed to simulate non-isothermal CO₂–crude oil displacement in heterogeneous porous structures, and the effects of injection rate, injection temperature, and wettability on two-phase flow characteristics in heterogeneous porous media were systematically analyzed. The results indicate that changes in the viscosity ratio between the displacing and displaced phases—induced by heat transfer—may be a key factor governing immiscible two-phase interfacial dynamics and flow behavior in heterogeneous porous structures. Injection temperature exerts a significant influence on both the main flow channels and local flow pathways within the porous structure; increasing the injection temperature of the displacing phase can effectively enhance displacement efficiency, with the steady-state CO₂ saturation increasing from 43.15% to 50.62% as the injection temperature increased from 293.15 K to 363.15 K. In addition, increasing the injection rate improves CO₂ sweep efficiency, with the steady-state CO₂ saturation increasing from 45.35% to 55.98% as the injection rate increased from 50 to 250 μm/s; however, excessively high injection rates lead to non-piston-like displacement and premature fluid breakthrough, and the CO₂ saturation decreased to 49.81% at 350 μm/s. Under strongly water-wet conditions, the CO₂ saturation after displacement stabilization is higher. Full article

The multi-cycle high-rate injection and production operations in Underground Gas Storage (UGS) facilities converted from depleted fracture-pore carbonate gas reservoirs induce complex rock–fluid interactions that threaten long-term integrity and performance. This study experimentally investigates the petrophysical responses of the Xiangguosi (XGS) UGS carbonate reservoirs in China using multi-cycle stress sensitivity tests, fines migration experiments, and water evaporation–salt precipitation analyses. SEM observations distinguish the contributions of crack closure and matrix compression to permeability evolution. Results show a sharp contrast in mechanical damage: high-quality rocks present negligible permanent deformation (<8% Young’s modulus reduction), whereas poor-quality rocks suffer catastrophic deterioration (>60%). Fines migration exhibits a three-stage behavior under cyclic flow, with water saturation significantly aggravating permeability impairment. A critical salinity threshold (220,000 ppm) is identified for the transition between drying-enhanced storage and salt plugging. Permeability declines sharply despite a slight porosity increase due to selective salt clogging of key pore throats, revealing a clear porosity–permeability decoupling. Salt deposition under movable water conditions can reduce UGS capacity by up to 1.45%. Reservoir heterogeneity, microfractures, karst structures, and initial petrophysical properties dominate the storage and flow space evolution. This work provides a predictive framework for optimizing injection–production strategies and improving the performance of complex carbonate UGS. Full article

This research presents a two-dimensional transient thermo-hydraulic model designed to study how temperature and pressure change within a wellbore during CO₂ tubing fracturing. The model integrates one-dimensional axial compressible flow with radial heat transfer across the tubing, annulus, casing, cement sheath, and surrounding geological formation. Using the predicted temperature and pressure distributions, the phase behavior of the fracturing fluid along the wellbore is assessed. To enhance the accuracy of phase predictions, a visualization experiment is performed on a CO₂-based fracturing fluid containing 5 wt% of the thickener HPG. The critical transition conditions obtained experimentally are used to adjust the model accordingly. The study systematically examines the influence of key operational parameters such as injection rate, wellhead pressure, injection temperature, and the geothermal gradient of the formation. Findings reveal that injection conditions mainly govern the temperature and velocity fields, while heat transfer from the formation has a lesser impact during short-term injections. Pressure steadily decreases along the wellbore due to friction and fluid compressibility. A method based on density gradients is introduced to determine the depth at which phase transitions occur. Overall, this work offers a practical approach for predicting thermo-hydraulic behavior and phase changes during CO₂ fracturing processes. Full article