Early pressurized flowback after large-scale hydraulic fracturing increases blowout risk in high-temperature, high-pressure and sand-laden wells. This study proposes a whole-process mechanical evaluation framework for a controllable downhole blowout-prevention workstring consisting of a retrievable hanger packer and a pressure-actuated valve. Finite-element models are developed to evaluate run-in stability under casing constraints, shut-in sealing and anchoring performance based on local nonlinear contact behavior, and load transients during unsetting and fishing under staged displacement and pressure loading. The results indicate stable run-in without unacceptable stress or instability, a self-energizing sealing response under the design differential pressure, and that the shut-in pressure limit is primarily governed by the anchoring anti-uplift capacity rather than the string body strength. Peak hook-load events are concentrated during shear-pin release and elastomer pressure-release. The proposed methodology supports design verification and determination of safe operating windows for post-fracturing well-control operations.

The development of tight heavy-oil reservoirs is severely hampered by the high viscosity and poor mobility of crude oil caused by strong intermolecular stacking interactions among asphaltenes, coupled with the substantial adsorption loss and inadequate deep transport capacity of conventional displacement agents. By targeted penetrant delivery, a novel nanoemulsion system with a well-defined “core–shell” architecture was synthesized to address these critical challenges. The physicochemical properties, stability and oil displacement performance were evaluated. The prepared nanoemulsion exhibited an ultrasmall and uniform particle size distribution between 10 nm and 20 nm. It also demonstrated exceptional dispersibility in aqueous media and remarkable thermal and salinity stability under reservoir conditions. Furthermore, an ultralow critical micelle concentration of approximately 0.01% could be achieved and the oil–water interfacial tension was reduced to 7.3 × 10−2 mN/m, significantly outperforming the conventional surfactant AES. Core flooding tests revealed that the proposed nanoemulsion enhanced oil recovery by 37.1% and attained a displacement efficiency of 68.9% in oil-wet capillary models. Molecular dynamics simulations further elucidated the underlying synergistic mechanism. The hydrophilic shell minimized adsorption on rock surfaces, facilitating deep migration within nanoporous channels. The hydrophobic core, containing terpinene as a penetrant, effectively disrupted the π-π stacking of asphaltenes due to its nonplanar molecular configuration. This disruption transformed the asphaltene aggregates from a tightly packed state to a dispersed state, resulting in substantial viscosity reduction. This work elucidated the mechanism of asphaltene aggregate disruption by nanoemulsions at the molecular level, offering a promising and theoretically grounded strategy for the efficient exploitation of tight heavy-oil reservoirs.

Gas-liquid hydrocyclones are urgently required in the fields of petroleum, chemical industry and environmental protection due to their significant advantages. However, the lack of discrete bubble deformation and separation mechanism limits their widespread application. In this study, the dynamic behavior of discrete bubbles in hydrocyclone was innovatively investigated via high-speed video and simulations under different operating parameters. Meanwhile, the morphological evolution mechanism of bubbles from deformation to nucleation was revealed. The axisymmetric shear stress within the hydro-flow field is a critical factor influencing bubble breakup, with the average maximum shear stress responsible for this phenomenon measuring 122.98 N/m2. Furthermore, the specific influence of operating parameters on bubble dynamics was elucidated. As inlet velocity increased, the variation in bubble surface area ratio (lambda) became more pronounced, resulting in enhanced bubble deformation. Additionally, as bubble size increased, the number of non-deformable particles also rose, leading to more significant deformation and fragmentation of the bubbles. Moreover, the effects of overflow split ratio and inlet velocity on gas-core morphology were examined. The enrichment effect of the flow field on the gas phase was enhanced with an increased overflow split ratio, leading to improved gas-liquid separation efficiency due to a more compact gas core morphology. Simultaneously, as inlet velocity increased, a stronger centrifugal force field was generated. Notably, the gas core became more stable under the influence of the radial pressure gradient force, thereby facilitating gas-liquid separation. These findings provide informed viewpoints for the design and parameter optimization of efficient gas-liquid separation equipment.

To accelerate the exploration and development of Jurassic shale oil in the Sichuan Basin and to establish an effective volumetric fracturing technology, the mechanical properties of reservoir rocks, fracture propagation behavior, and proppant distribution characteristics were investigated through core mechanical testing and true triaxial hydraulic fracturing experiments. These results were used to propose a targeted fracturing strategy suitable for Jurassic shale reservoirs characterized by multi-lithology combinations and abundant natural fractures. Geological model simulations were further employed to optimize critical design parameters, including cluster spacing, injection parameters, stimulation scale, and the selection of fracturing fluids and proppants. The final design adopted a cluster spacing of 6-10 m in shale intervals and 8-12 m in sandstone intervals. A proppant intensity of 2.0 m3/m and a fluid intensity of 30 m3/m were determined to be optimal. A mixed-proppant system was selected, consisting of 70/140-mesh fine proppant for supporting bedding-plane fractures and 30/50-mesh ceramic proppant for enhancing the conductivity of the main hydraulic fractures, applied at a ratio of 7:3. Slickwater was used as the fracturing fluid. Based on these results, a volumetric fracturing technology characterized by "full-length horizontal penetration and differentiated close-cutting" was developed. Field test results show that post-fracturing daily oil and gas production reached 112.8 m3 and 1.145x105 m3, respectively, demonstrating significant productivity enhancement and achieving a breakthrough in Jurassic shale oil exploration in the Sichuan Basin. The findings provide an important engineering reference for volumetric fracturing in similar shale reservoirs in future development areas.

High-pressure, low-yield gas wells in the Songliao Basin suffer from bottom-hole liquid loading and hydrate blockage as formation water production increases. Conventional downhole throttling lacks active liquid drainage, and methanol injection is costly and only partially effective. To overcome these limitations, this study develops an integrated downhole throttling-atomization-drainage device. The structure features a spiral channel for cyclonic gas–liquid separation and a downstream atomizing nozzle with a crushing unit for secondary atomization. Laboratory high-speed imaging experiments compare the proposed device with a conventional nozzle without a spiral element. Results show that the conventional nozzle produces a liquid column core and subsequent wall film accumulation, whereas the spiral atomizing nozzle generates a fully dispersed spray field without observable wall wetting. Field application in a Songliao Basin well, with the device installed at 1503 m and a 4 mm orifice, was conducted without methanol injection. After installation, wellhead tubing pressure decreased from 13 to 4.5 MPa, daily water production increased from 1.0 to 2.4 m3, and no hydrate formation was observed. These results demonstrate that the integrated downhole throttling-atomization-drainage technology effectively mitigates both hydrate blockage and bottom-hole liquid loading in high-water-producing gas wells.

Hydraulic fracturing is critical to the development of unconventional reservoirs, as it enables effective interaction with complex natural fracture networks. However, the mechanical behavior and damage evolution mechanisms of fractured rock masses remain insufficiently understood. In this study, acoustic wave testing and uniaxial compression experiments were conducted to investigate the effects of natural fracture orientation and number on the mechanical properties, failure modes, and damage evolution of shale. In addition, we employ the finite-discrete element method (FDEM) to simulate the full-field stress evolution of rock masses with complex natural fracture systems. The results indicate that with increasing prefabricated fracture angles, shale exhibits a tendency toward different fracture modes. The mechanical properties of the rock show a “U-shaped” evolution with increasing fracture angle, and the degradation of mechanical properties becomes more pronounced as the number of natural fracture sets increases. During loading, the fracture behavior of shale containing natural fracture networks is jointly controlled by the rock matrix and the fracture networks, while the influence of the matrix gradually weakens with increasing fracture density. The distribution of complex natural fracture systems has a significant impact on full-field stress evolution and ultimately governs the fracture mode of the rock. Rock specimens with fracture networks are prone to stress concentration at fracture tips in the central region. This stress concentration subsequently propagates, induces failure, and the specimens fail primarily in tensile-shear fracture modes.

A comprehensive understanding of spontaneous imbibition mechanisms in fractured porous media is crucial for optimizing the development and sustainable utilization of geo-energy resources. This study employs advanced pore-scale simulation techniques to investigate counter-current spontaneous imbibition behavior in natural fractured porous media. Through digital rock physics technology, we accurately reconstructed both matrix and fracture structures from low-permeability sandstone cores. The study revealed two distinct snap-off phenomena in natural fractured porous media: (1) fracture-dominated snap-off, which plays a pivotal role in oil–water phase redistribution, and (2) matrix-dominated snap-off, which exhibits relatively minor effects on fluid phase redistribution. Three key geometric parameters significantly influence the spontaneous imbibition process in natural fractured porous media: the pore–throat ratio of matrix, the throat size distribution at the matrix–fracture junctions, and the fracture architecture. The relatively large pore–throat ratio in natural fractured porous media significantly inhibits the spontaneous imbibition capacity of water, consequently leading to reduced oil recovery efficiency. In addition, the systematic analysis focused on three critical controlling factors of fluid properties: wettability characteristics, viscosity ratio, and interfacial tension, with particular emphasis on their influence on interaction mechanism between fracture and matrix. Increasing interfacial tension or decreasing contact angle can promote deeper water penetration into the matrix, thereby improving oil recovery efficiency. Furthermore, our findings indicate that higher viscosity ratios enhance non-wetting phase mobility, facilitating more efficient spontaneous imbibition processes. These findings provide valuable insights for optimizing water injection strategies in unconventional reservoirs, such as oil shale formations.

Extensive field data indicates that the dominant flow pattern in gas wells is typically annular mist flow, with the liquid phase predominantly existing as liquid film and liquid droplets in waterproducing gas wells. In actual water-producing gas wells, the liquid phase exists simultaneously in the forms of liquid films and droplets. The liquid film moves along the inner wall of the wellbore, while the droplets are carried by the gas phase in the form of mist. This results in both the droplet model and the liquid film model being unable to accurately predict the critical liquid carrying velocity. Therefore, in this study, a new critical liquid carrying velocity model is proposed, which builds upon the mechanisms of liquid film shear and droplet entrainment. This model integrates the process by which liquid films are fragmented into droplets through waveinduced shear. Then, the proposed model is compared with classical critical liquid carrying models and filed experimental data from 50 gas wells with different pressure and tubing size, The results demonstrate that the proposed model significantly enhances the accuracy of liquid loading predictions, achieving an overall accuracy of 98 %, with one misjudged gas well. Finally, the impacts of liquid production, liquid phase composition, tubing diameter, pressure gradient, and temperature on the critical liquid carrying velocity are investigated using the proposed model. The results demonstrate that the critical liquid carrying velocity increases with an increase in pipe diameter, liquid production, and pressure gradient, with the pipe diameter exerting a greater influence than liquid production and pressure gradient.

The single-well injection and production technology separates oil and water from high water-cut produced fluid in the wellbore,and the hydrocyclone is a key equipment for the efficient operation of this technology.To further improve the downhole oil-water separation performance of hydrocyclone,by combining cyclone separation principle and 3D printing technology,a central-axial hydrocyclone for oil-water separation was proposed.With the help of numerical simulation,together with experiment,the flow field distribution inside the cyclone and the oil-water separation efficiency under different operating parameters(incl.oil droplet size,inlet flow rate,and split ratio)were systematically analyzed.The results show that the maximum separation efficiency of the cyclone is realized when the oil volume fraction is 4%,the oil droplet size is 0.7 mm,the inlet flow rate is 6.33 m/s,and the split ratio is 30%.Under these operating conditions,the simulated and experimental separation efficiencies reach 98.8% and 98.0%,respectively.The numerical simulation and experiment yield consistent results in respect of oil nucleus position and separation efficiency,verifying the feasibility of the proposed central-axial hydrocyclone.The study results provide a reference for the development and application of efficient downhole oil-water separation equipment.

The rock mechanical parameters and failure morphology characteristics of shale are essential technical parameters and references for the selection of favorable intervals and process optimization in stimulation and reconstruction. In view of the abundant development of foliation fractures, severe heterogeneity, and unclear fracture morphology in the Gulong shale, through rock mechanical testing and hydraulic fracturing physical simulation, key mechanical parameters and quantitative relationships of anisotropy for the entire layer series of Gulong shale were obtained, and the influence of anisotropy and foliation differences in mechanical parameters on the shape of artificial fractures was clarified. The experimental results show that the rock mechanical parameters and failure morphology of Gulong shale exhibit significant brittleness characteristics, which changes the understanding of using clay content to distinguish the fracturability of shale reservoirs. Affected by foliation development and heterogeneity, the differences in rock mechanical parameters and anisotropy between parallel and vertical foliation directions are severe, with high compressive strength and Young’s modulus in parallel foliation directions, and low tensile strength and fracture toughness. The degree of foliation fracture development has a significant impact on the initiation pressure and swept volume of artificial fractures. After hydraulic fracturing, artificial fractures exhibit a complex network morphology resembling a “banyan tree” with crisscrossing patterns in the horizontal direction, with complex morphology but limited fracture length and height extension. This is an important factor that restricts the volume and effectiveness of the reconstruction.

During throttling and pressure reduction, hydrates can form due to changes in pipeline pressure, particularly in natural gas with high water content. The formation of hydrates obstructs gas flow, even in minimal quantities, resulting in elevated differential pressure and accelerating hydrate formation, which leads to technical challenges such as diminished production and pressure retention. This study introduces and verifies a multi-field coupling risk prediction model for hydrate blockages in natural gas pipelines. The model integrates the temperature field, pressure field, multiphase flow theory, and hydrate clogging theory. Based on this foundation, the impacts of inlet temperature, pressure, and gas volume on the formation of hydrates in pipelines were analyzed, and the most vulnerable blocked point and the maximum formation rate were determined for different sensitivity factors. The results show that elevated inlet pressure and reduced inlet temperature enhance the maximal hydrate formation rate, while gas volume exerts a negligible influence. And increasing gas transport will move the most susceptible blockage point downstream. Finally, the original model is used to forecast actual gas hydrate plugging using time discretization and iterative calculation approaches.

CO2 injection composite fracturing is an effective method for shale oil and gas well development. The downhole casing is prone to uniform corrosion, pitting, perforation, and even corrosion fracture in the CO2 environment. Therefore, it is particularly important to reveal the physical characteristics of CO2 under actual geological conditions and the impact of CO2 corrosion on the performance of casing. A mathematical model for the temperature and pressure field of CO2 in the wellbore under fracturing conditions is established in this paper, and the temperature and pressure distribution along the depth of the well is calculated. By optimizing the CO2 state equation and using the S-W equation, Lee model, and RK model to calculate the CO2 density, viscosity and compression factor, respectively, the phase distribution pattern of CO2 along the actual wellbore is obtained. Through CO2 corrosion tests on the casing, the influence of temperature and CO2 concentration on the corrosion rate of the casing is clarified. The peak corrosion rate of Q125 steel corresponds to 80 °C, and the corrosion rate increases with the increase in CO2 concentration. Finally, a prediction model for the uniform corrosion rate of casing under different temperatures and CO2 concentration conditions is obtained, which can provide technical support for the design of CO2-enhanced fracturing technology.

In order to reveal the physical properties of CO2 under actual formation conditions, this paper establishes a mathematical model of the temperature field and pressure field in the wellbore under CO2 injection conditions, optimizes the state equation of CO2 physical-property parameters, calculates the change trend of CO2 density, viscosity, and compression factor along the wellbore, and obtains the influence law of CO2 corrosion on the casing and interface. The viscosity showed a downward trend along the well depth; the compression factor showed an upward trend. The surfaces of the three casings were smooth and flat without obvious defects, the cement structure was dense, and there was no obvious pore structure. After corrosion, with the increase of Cr content, the change of interfacial corrosion decreases. The morphology of the Q125 and 3Cr interface is loose after corrosion, while there is no obvious change in the 13Cr interface. With the prolongation of corrosion time, low wellbore internal pressure easily causes casing yield, and high wellbore internal pressure easily causes cement-sheath compression failure. The circumferential stress of the casing increases with the corrosion time extension, and the radial stress of the casing and cement sheath decreases first and then increases with the corrosion time. The compressive strength of the cement sheath does not exceed the compressive strength.

In the nanoscale pore mud shale reservoir in Daqing, proppant embedded prone to make artificial fracture diverting capacity, therefore, to develop different closure pressure, concentration of different particle size and composition, sanding proppant's influence on the flow conductivity of the experiment, analyze the effect of mud shale reservoir proppant embed change rules of flow conductivity. The results show that, with the increase of closing pressure, the embedment and flow conductivity both decrease to different degrees. The flow conductivity decreases rapidly in the range of 0–10 h. After 30 h, the flow conductivity basically reaches a steady state, the morphology between particles is stable, and the flow channel changes little. Different particle size of proppant on closure pressure is low, diverting capacity difference is very big, the particle size, the greater the conductivity will be high, with the increase of closure pressure, large diameter occurred more broken, different particle size of proppant diverting capacity gap is also gradually reduced, at the same time, increasing the sanding concentration can significantly reduce the embedded degree of proppant. Studying the quantitative influence of proppant embedment on fracture conductivity can provide a basis for optimization of fracturing scheme and parameter design of shale reservoir.

In the process of constructing deep natural gas wells in Sichuan and Chongqing, gas wells encounter various technical challenges such as high temperature, high pressure, and a corrosive environment containing H2S and CO2. The corrosion of rubber materials in these acidic environments can easily lead to seal failure in downhole tools. To better investigate the corrosion resistance of rubber materials in acidic environments, we utilized a dynamic cyclic corrosion experimental device capable of simulating the service conditions experienced by downhole tools under high-temperature, high-pressure multiphase flow. Corrosion-resistance tests were conducted on fluororubbers (FKM) 1, 2, 3, and HNBR (hydrogenated nitrile-butadiene rubber) under acidic conditions (80 °C and 160 °C), along with sealing corrosion tests on O-rings. These tests aimed to analyze the mechanical properties, hardness, and corrosion resistance before and after exposure to acid media as well as the sealing performance of O-rings. Ultimately, our goal was to identify suitable rubber materials for acidic pressure environments. Experimental results revealed that all four types of rubber exhibited decreased elongation at break after undergoing corrosion testing; however, fluororubber 3 demonstrated significant susceptibility to temperature effects while the other three types showed minimal impact from temperature variations. Fluororubber 1 and fluororubber 3 displayed substantial deformation levels whereas mechanical properties greatly deteriorated for fluororubber 2. Overall, HNBR showcased superior comprehensive performance.

The wettability of shale reservoirs has an important influence on the flow of external fluids. In this paper, the effect of wettability on the self-absorption of hydraulic fracturing fluid under different pore size conditions is first analyzed. Then, the mechanism of the influence of wettability pore size on the flow coefficient is elucidated. The results show that (a) as the pore size decreases, the importance of various forces acting on the fluid during the flow process changes, and the solid-liquid interaction will greatly affect the fluid flow in the nanopore. (b) When the radius is 5, the flow enhancement increases from 0.6331 to 0.998 as the radius increases from 0 to 3.141594.(c) The shale inorganic material contains a variety of minerals, and the interaction forces between different mineral surfaces and water molecules are different, resulting in different apparent viscosities.

Vortex drainage gas recovery has been used to carry liquid from gas wells. However, the traditional vortex tools in gas wells cannot produce long effective distance spiral flow at a low gas flow rate, and their operating mechanism has not been thoroughly analyzed. In this paper, the venturi acceleration vortex tool for a horizontal gas well is designed to improve drainage performance. The tube drainage, the vortex tool, and the venturi accelerated vortex tool were applied in a horizontal tube to investigate their drainage capacities by a horizontal well multiphase flow experimental device. The influence of different gas flow rates and liquid flow rates on the length of the spiral flow and pressure drop produced by the three tools was analyzed. The results show that the vortex tool can convert the gas–liquid mixing flow into the gas–liquid separation flow, that is, the liquid flows spirally along the wall and the gas flows in the center of the horizontal tube. Compared with the vortex tool, the venturi accelerated vortex tool can form a longer and more stable spiral flow. The laminar spiral flow reduces the total pressure drop in the tube. The length of the spiral flow increases with the increase in the gas flow rate. With the increase in the liquid flow rate, the spiral flow is not clear because of the turbulent flow. The length of the spiral flow and the pressure drop for the venturi accelerated vortex tool with different gas and liquid flow rates are analyzed to guide the application of the tool. This study provides a new means for the drainage of a horizontal gas well and further clarifies the working mechanism of the vortex drainage tool.

Hydraulic fracturing technology is an effective way to develop tight sandstone reservoirs with low porosity and permeability. The tight sandstone reservoir is heterogeneous and the heterogeneity characteristics has an important influence on fracture propagation. To investigate hydraulic fracture performance in heterogeneous tight reservoir, the X-ray diffraction experiments are carried out, the Weibull distribution method and finite element method are applied to establish the uniaxial compression model and the hydraulic fracture propagation model of heterogeneous tight sandstone. Meanwhile, the sensitivity of different heterogeneity characterization factors and the multi-fracture propagation mechanism during hydraulic fracture propagation is analyzed. The results indicate that the pressure transfer in the heterogeneous reservoir is non-uniform, showing a multi-point initiation fracture mode. For different heterogeneity characterization factors, the heterogeneity characteristics based on elastic modulus are the most sensitive. The multi-fracture propagation of heterogeneous tight sandstone reservoir is different from that of homogeneous reservoir, the fracture propagation morphology is more complex. With the increase of stress difference, the fracture propagation length increases. With the increase of injection rate, the fracture propagation length increases. With the increase of cluster spacing, the propagation length of multiple fractures tends to propagate evenly. This study clarifies the influence of heterogeneity on fracture propagation and provides some guidance for fracturing optimization of tight sandstone reservoirs.

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