Search Results (25)

Autonomous inflow control devices (AICDs) offer a promising means of delaying early water breakthrough in heavy oil horizontal wells; yet, current design practices remain largely empirical. A three-dimensional, field-calibrated computational fluid dynamics (CFD) model was developed to establish a mechanistic basis that solves the transient Navier–Stokes equations for turbulent two-phase flow via a volume-of-fluid formulation. Pressure-controlled inflow boundaries were tuned to build up data from four Colombian heavy oil producers, enabling a quantitative comparison with production logs. Model predictions deviate by no more than ±14% for oil rate and ±10% for water rate over a 500-day horizon, providing confidence in subsequent scenario analysis. Replacing a slotted liner completion with optimally sized AICDs lowers cumulative water-cut by up to 93%, reduces annular friction losses by 18%, and cuts estimated life cycle CO₂ emissions per stock-tank barrel by 82%. Sensitivity analysis identifies nozzle diameter as the dominant design variable, with a nonlinear interaction between local drawdown pressure and the oil–water viscosity ratio. These findings demonstrate that CFD-guided AICD design can materially extend wells’ economic life while delivering substantial environmental benefits. The validated workflow establishes a low-risk, physics-based path for tailoring AICDs to reservoir conditions before field deployment. Full article

The fluid properties of low-saturation reservoirs (LSRs) produced after fracturing are complex and diverse, which makes it difficult to predict the post-fracturing productivity of oil–water two-phase flow and results in a low prediction accuracy. Therefore, based on elliptical seepage theory and nonlinear steady-state seepage formula, a new method for predicting the post-fracturing productivity (PFP) of oil–water two-phase flow in vertical wells in LSRs after fracturing is proposed in this paper. The Li Kewen model is preferred for accurately calculating oil–water relative permeability. Based on the elliptical fracture morphology, a quantitative prediction model for the PFP of oil–water two-phase flow is established. This model incorporates a starting pressure gradient (SPG) to depict the non-Darcy flow seepage law in low-permeability reservoirs. Hydraulic fracturing fracture length, width and permeability are obtained using logging curves and fracturing data, and this model can be applied to the quantitative prediction of PFP of oil–water two-phase flow in LSRs. The research results show that the conformity rate of oil production is 77.5%, and that of water production is 73.2%, with an improvement of over 15% in the interpretation conformity rate. Compared with actual well test productivity, the mean absolute error of the oil productivity prediction is 3.51 t/d, and the mean absolute error of the water productivity prediction is 12.37 t/d, which meet the requirements of field productivity quantitative evaluation, indicating the effectiveness of this quantitative prediction method for predicting the PFP of oil–water two-phase flow. Full article

Understanding the structural evolution of two-phase fluid flow in fractured rock is of great significance for related rock engineering, including underground oil and gas extraction, contaminant storage and leakage, etc. Considering that rock fracture is the fundamental element of fractured rock, we conduct a series of numerical simulations to investigate the role of fracture aperture, surface roughness and shear displacement in the transition of two-phase fluid flow. The roughness fracture surfaces were generated by a MATLAB code we developed according to successive random addition algorithms. The level set method was applied to describe two-phase fluid flow and the numerical solution of the governing equations in COMSOL 6.2, and its effectiveness was verified by comparing it with the results of previous experiments. Numerical simulation results indicated the following: the water saturation (S_w) in the fracture decreases with an increase in the gas–water flow rate ratio; with an increase in roughness, the water saturation contained within the fracture gradually increases; the effect of fracture roughness on the two-phase fluid flow structure is enhanced; with an increase in dislocations, the water saturation in the low-roughness fracture increases, and the water saturation in the high-roughness fracture first increases and then decreases. The results of this study can provide reference significance for the study of gas–water two-phase fluid flow and provide theoretical guidance in related engineering. Full article

The oil field enters a low-production liquid and high-water-cut stage, where the oil–water two-phase flow becomes increasingly complex and diverse. Traditional production profile logging interpretation methods often face significant errors and limitations. To improve interpretation accuracy, this study begins by examining the impact of flow rate and water cut on the oil–water two-phase flow pattern (defined as the characteristic distribution and movement of oil and water phases in the flow, which varies depending on flow conditions such as flow rate and water cut) through numerical simulations and surface experimental observations. The flow characteristics of the oil–water two-phase flow are clarified. Next, the data from surface experiments are collected using a multi-component logging tool, and artificial intelligence algorithms are employed to identify flow patterns and provide data support for production profile interpretation. The genetic algorithm–backpropagation (GA-BP) algorithm is used for flow type classification, with the flow pattern recognition accuracy reaching 93.75% when compared to the experimental results. Finally, the surface experimental data and flow patterns are input into the grey wolf and falcon optimization algorithm–radial basis function (GHOA-RBF) algorithm for training and prediction. The results show that the GHOA-RBF algorithm, incorporating flow patterns, exhibits superior prediction accuracy. Specifically, the coefficient of determination (R²) for oil flow is 0.996, and for water flow, it is 0.993, outperforming traditional RBF neural networks and the GHOA-RBF algorithm without flow pattern incorporation. This demonstrates that this study provides new theoretical support for production profile logging interpretation, with significant practical implications. However, limitations include the reliance on experimental data, which may not fully capture all field conditions, and the computational efficiency of the algorithm, which may need optimization for large-scale applications. Full article

Gas reservoirs play an increasingly important role in oil and gas consumption and safety in China. To study the problem of erosion and wear caused by gas-carrying particles in the process of gas extraction from gas storage reservoirs, a mathematical model of gas–liquid–solid three-phase erosion of gas storage reservoir columns was established through theories of multiphase flow and particle motion. Based on this model, the effects of the water volume fraction, gas extraction rate, particle mass flow rate, particle size, and bending angle on the erosion location and rate of the pipe columns were investigated. The findings indicate that when the water content volume fraction is low, the water production volume minimally affects the maximum erosion rate of pipe columns. Conversely, the gas extraction rate exerted the most significant influence on the column erosion, showing a power function relationship between the two. When gas extraction volume exceeds 60 × 10⁴ m³/d, the maximum erosion rate surpasses the critical erosion rate of 0.076 mm/a. This coincided with the increased sand mass flow rate, although the maximum erosion rate of the pipe columns remained relatively steady. The salt mass flow rate demonstrated a linear relationship with the erosion rate, with the maximum erosion rate exceeding the critical erosion rate of 0.076 mm/a. The maximum erosion rate of the pipe columns increased, stabilized with larger sand and salt particle sizes, and exhibited an increasing trend with the bending angle. For gas extraction volumes exceeding 46.4 × 10⁴ m³/d and salt mass flow rates exceeding 22 kg/d, the maximum erosion rate of pipe columns exceeds the critical erosion rate of 0.076 mm/a. The conclusions of this study are of some importance for the clarification of the influencing law of pipe column erosion under high temperature and high pressure in gas storage reservoirs and for the formulation of measures for the prevention and control of pipe column erosion in gas storage reservoirs. Full article

Light non-aqueous phase liquids (LNAPLs), which include various petroleum products, are a significant source of groundwater contamination globally. Once introduced into the subsurface, these contaminants tend to accumulate in the vadose zone, causing chronic soil and water pollution. The vadose zone often contains lens-shaped bodies with diverse properties that can significantly influence the migration and distribution of LNAPLs. Understanding the interaction between LNAPLs and these lens-shaped bodies is crucial for developing effective environmental management and remediation strategies. Prior research has primarily focused on LNAPL behavior in homogeneous media, with less emphasis on the impact of heterogeneous conditions introduced by lens-shaped bodies. To investigate the impact of lens-shaped structures on the migration of LNAPLs and to assess the specific effects of different types of lens-shaped structures on the distribution characteristics of LNAPL migration, this study simulates the LNAPL leakage process using an indoor two-dimensional sandbox. Three distinct test groups were conducted: one with no lens-shaped aquifer, one with a low-permeability lens, and one with a high-permeability lens. This study employs a combination of oil front curve mapping and high-density resistivity imaging techniques to systematically evaluate how the presence of lens-shaped structures affects the migration behavior, distribution patterns, and corresponding resistivity anomalies of LNAPLs. The results indicate that the migration rate and distribution characteristics of LNAPLs are influenced by the presence of a lens in the gas band of the envelope. The maximum vertical migration distances of the LNAPL are as follows: high-permeability lens (45 cm), no lens-shaped aquifer (40 cm), and low-permeability lens (35 cm). Horizontally, the maximum migration distances of the LNAPL to the upper part of the lens body decreases in the order of low-permeability lens, high-permeability lens, and no lens-shaped aquifer. The low-permeability lens impedes the vertical migration of the LNAPL, significantly affecting its migration path. It creates a flow around effect, hindering the downward migration of the LNAPL. In contrast, the high-permeability lens has a weaker retention effect and creates preferential flow paths, promoting the downward migration of the LNAPL. Under conditions with no lens-shaped aquifer and a high-permeability lens, the region of positive resistivity change rate is symmetrical around the axis where the injection point is located. Future research should explore the impact of various LNAPL types, lens geometries, and water table fluctuations on migration patterns. Incorporating numerical simulations could provide deeper insights into the mechanisms controlling LNAPL migration in heterogeneous subsurface environments. Full article

Shale oil reservoirs, as an unconventional hydrocarbon resource, have the potential to substitute conventional hydrocarbon resources and alleviate energy shortages, making their exploration and development critically significant. However, due to the low permeability and the development of nanopores in shale reservoirs, shale oil production is challenging and recovery efficiency is low. During the imbibition stage, fracturing fluid displaces the oil in the pores primarily under capillary forces, but the complex pore structure of shale reservoirs makes the imbibition mechanism unclear. This research studies the imbibition flow mechanism in nanopores based on the capillary force model and two-phase flow theory, coupled with numerical simulation methods. The results indicated that within a nanopore diameter range of 10–20 nm, increasing the pore diameter leads to a higher imbibition displacement volume. Increased pressure can enhance the imbibition displacement, but the effect diminishes gradually. Under the water-wet conditions, the imbibition displacement volume increases as the contact angle decreases. When the oil phase viscosity decreases from 10 mPa·s to 1 mPa·s, the imbibition displacement rate can increase by 72%. Moreover, merely increasing the water phase viscosity results in only a 5% increase in the imbibition displacement rate. The results provide new insights into the imbibition flow mechanism in nanopores within shale oil reservoirs and offer a theoretical foundation and technical support for efficient shale oil development. Full article

Since reservoirs with permeability less than 10 mD are characterized by high injection difficulty, high-pressure drop loss, and low pore throat mobilization during the water drive process, CO₂ is often used for development in actual production to reduce the injection difficulty and carbon emission simultaneously. However, microfractures are usually developed in low-permeability reservoirs, which further reduces the injection difficulty of the driving medium. At the same time, this makes the injected gas flow very fast, while the gas utilization rate is low, resulting in a low degree of recovery. This paper conducted a series of studies on the displacement effect of CO₂-soluble foaming systems in low-permeability fractured reservoirs (the permeability of the core matrix is about 0.25 mD). For the two CO₂-soluble blowing agents CG-1 and CG-2, the effects of the CO₂ phase state, water content, and oil content on static foaming performance were first investigated; then, a more effective blowing agent was preferred for the replacement experiments according to the foaming results; and finally, the effects of the blowing agents on sealing and improving the recovery degree of a fully open fractured core were investigated at different injection rates and concentrations, and the injection parameters were optimized. The results show that CG-1 still has good foaming performance under low water volume and various oil contents and can be used in subsequent fractured core replacement experiments. After selecting the injection rate and concentration, the blowing agent can be used in subsequent fractured cores under injection conditions of 0.6 mL/min and 2.80%. In injection conditions, the foaming agent can achieve an 83.7% blocking rate and improve the extraction degree by 12.02%. The research content of this paper can provide data support for the application effect of a CO₂-soluble blowing agent in a fractured core. Full article

Multiphase fluids are common in many industries, such as oil and petrochemical, and volume fraction measurement of their phases is a vital subject. Hence, there are lots of scientists and researchers who have introduced many methods and equipment in this regard, for example, photon attenuation sensors, capacitance-based sensors, and so on. These approaches are non-invasive and for this reason, are very popular and widely used. In addition, nowadays, artificial neural networks (ANN) are very attractive in a lot of fields and this is because of their accuracy. Therefore, in this paper, to estimate volume proportion of a three-phase homogeneous fluid, a new system is proposed that contains an MLP ANN, standing for multilayer perceptron artificial neural network, a capacitance-based sensor, and a photon attenuation sensor. Through computational methods, capacities and mass attenuation coefficients are obtained, which act as inputs for the proposed network. All of these inputs were divided randomly in two main groups to train and test the presented model. To opt for a suitable network with the lowest rate of mean absolute error (MAE), a number of architectures with different factors were tested in MATLAB software R2023b. After receiving MAEs equal to 0.29, 1.60, and 1.67 for the water, gas, and oil phases, respectively, the network was chosen to be presented in the paper. Hence, based on outcomes, the proposed approach’s novelty is being able to predict all phases of a homogeneous flow with very low error. Full article

Gas–oil–water three-phase slug flows in pipes commonly exist in the oil and gas industry as oil fields are becoming mature and water production is becoming inevitable. Although studies on multiphase flows in pipes have been ongoing for decades, most previous research has focused on gas–liquid or oil–water two-phase flows, with limited studies on gas–liquid–liquid flows. This leads to limited modeling studies on gas–liquid–liquid flows. One factor contributing to the complexity of the gas–liquid–liquid flow is the mixing between the oil and water phases, which have closer fluid properties and low interfacial tension. Restrictions or piping components play a crucial role in altering phase mixing. Unfortunately, modeling studies that consider the effects of these restrictions are limited due to the scarcity of experimental research. To address this gap, we conducted experimental studies on a gas–liquid–liquid flow downstream of a restriction and developed a new mechanistic modeling approach to predict the pressure gradient. Our model focuses on the flow pattern where the oil and water phases are partially mixed. This work emphasizes the modeling approach. The model evaluation results show that the model outperforms other existing models, with an average absolute relative error of 6.71%. Additionally, the parametric study shows that the new modeling approach effectively captures the effects of restriction size, water cut, and gas and liquid flow rates on the three-phase slug flow pressure gradient in horizontal pipes. Most previous slug flow modeling work assumes either a stratified flow or fully dispersed flow between the oil and water phases. This work provides a novel perspective in modeling a three-phase slug flow in which the oil and water phases are partially mixed. In addition, this novel approach to modeling the restriction effects on the pressure gradient paves the way for future modeling for different types of piping components or restrictions. Full article

Shale oil in China is widely distributed and has enormous resource potential. The pores of shale are at the nanoscale, and traditional research methods encounter difficulty in accurately describing the fluid flow mechanism, which has become a bottleneck restricting the industrial development of shale oil in China. To clarify the distribution and migration laws of fluid microstructure in shale nanopores, we constructed a heterogeneous inorganic composite shale model and explored the fluid behavior in different regions of heterogeneous surfaces. The results revealed the adsorption capacity for alkanes in the quartz region was stronger than that in the illite region. When the aperture was small, solid–liquid interactions dominated; as the aperture increased, the bulk fluid achieved a more uniform and higher flow rate. Under conditions of small aperture/low temperature/low pressure gradient, the quartz region maintained a negative slip boundary. Illite was more hydrophilic than quartz; when the water content was low, water molecules formed a “liquid film” on the illite surface, and the oil flux percentages in the illite and quartz regions were 87% and 99%, respectively. At 50% water content, the adsorbed water in the illite region reached saturation, the quartz region remained unsaturated, and the difference in the oil flux percentage of the two regions decreased. At 70% water content, the adsorbed water in the two regions reached a fully saturated state, and a layered structure of “water–two-phase region–water” was formed in the heterogeneous nanopore. This study is of great significance for understanding the occurrence characteristics and flow mechanism of shale oil within inorganic nanopores. Full article

As an important indicator for measuring the effectiveness and level of oil and gas field development, recovery rate has always been a focus in the research of oil and gas fields. Reservoirs of tight sandstone gas formations have significant characteristics of low porosity, high permeability, and high water content, which leads to greater difficulty in their development and makes it challenging to evaluate the recovery rate. Newtonian mechanics, as an important component of the mechanical system, is an innovative application of classical mechanics in the field of seepage mechanics when applied to the two-phase flow of gas and water. Firstly, starting from the perspective of mechanics analysis, we derive a steady-state model for gas–water two-phase infiltration and obtain the productivity equation based on this model. Then, according to the steady-state model, we establish a method to calculate the effective control radius of gas reservoirs under different production conditions and reservoir physical properties. Finally, using Matlab 2018a programming based on the productivity equation, we calculate the gas recovery under different conditions during constant pressure drop production and constant production rate production. The results indicate that the effective control radius of the reservoir decreases with an increase in the economic ultimate daily gas production, increases with an increase in production pressure difference, slightly decreases with an increase in startup pressure gradient, and correspondingly increases with an increase in microtube radius and quantity. Regardless of whether it is production with a fixed pressure drop or production with a fixed production rate, the gas recovery decreases as the production pressure drop and bottomhole abandonment pressure increase, but it increases as the proportion of the single-well control radius increases. In production with a fixed pressure drop, the gas recovery remains consistent across different reservoir quality indices. However, in production with a fixed production rate, the gas recovery initially increases rapidly and then gradually slows down as the reservoir quality index increases, and there is an obvious critical permeability (0.1 mD). The research findings are based on the mechanical analysis of porous media, delving into the laws governing fluid flow during infiltration. The derived infiltration model can be used to calculate the effective control radius and evaluate recovery rates, providing practical guidance for reservoir development. Full article

Expanding swept volume technology via continuous-phase polymer solution and dispersed-phase particle gel is an important technique to increase oil production and control water production in mature waterflooding reservoirs. However, problems such as the low viscosity retention rate, deep migration, and weak mobility control of conventional polymers, and the contradiction between migration distance of particle gel and plugging strength, restrict the long-term effectiveness of oil displacement agents and the in-depth sweep efficiency expanding capability in reservoirs. Combined with the technical advantages of polymer and particle gel, a novel controllable phase-transition polymer was developed and systematically studied to gain mechanistic insights into enhanced oil recovery for mature waterflooding reservoirs. To reveal the phase-transition mechanism, the molecular structure, morphology, and rheological properties of the controllable phase-transition polymer were characterized before and after phase transition. The propagation behavior of the controllable phase-transition polymer in porous media was studied by conducting long core flow experiments. Two-dimensional micro visualization and parallel core flooding experiments were performed to investigate the EOR mechanism from porous media to pore level. Results show that the controllable phase-transition polymer could change phase from dispersed-phase particle gel to continuous-phase solution with the prolongation of ageing time. The controllable phase-transition polymer exhibited phase-transition behavior and good propagation capability in porous media. The results of micro visualization flooding experiments showed that the incremental oil recovery of the controllable phase-transition polymer was highest when a particle gel and polymer solution coexisted, followed by a pure continuous-phase polymer solution and pure dispersed-phase particle gel suspension. The recovery rate of the novel controllable phase-transition polymer was 27.2% after waterflooding, which was 8.9% higher than that of conventional polymer, providing a promising candidate for oilfield application. Full article

Hydraulic fracturing of horizontal wells is a common method for enhancing production in low-permeability and unconventional oil reservoirs. However, due to the interference between fractures, issues such as decreased production and water channeling often occur in hydraulic fracturing of horizontal wells. Therefore, studying how to mitigate the effects of fracture interference is of great significance for optimizing hydraulic fracturing design and improving oil and gas recovery rates. In this paper, an oil–water two-phase discrete fracture model was established, and the grid dissection was carried out by using the optimization method to obtain a triangular grid that can finely characterize the fracture in geometry. Then, typical discrete fracture models were designed, and the influences of the fracture permeability ratio, absolute fracture scale, oil–water viscosity ratio, and fracture length on the fracture flow interference were investigated separately. The degree of fracture interference was evaluated using the fracture fractional flow rate ratio, remaining oil saturation, and sweep efficiency. This study verified fracture interaction and identified that the threshold value of the fracture permeability ratio is 9 to classify the degree of interference. Sensitivity analysis shows that the absolute size of the fracture has a significant impact on fracture interference, while the impact of the oil–water viscosity ratio and fracture length on fracture interference is relatively small. Full article

The formation of flow-induced, oriented structures in two-phase systems, as in this study, is a phenomenon of considerable interest to the scientific and industrial sectors. The main difficulty in understanding the formation of bands of droplets is the simultaneous interplay of physicochemical, hydrodynamic, and mechanical effects. Additionally, banded structure materials frequently show multiple length scales covering several decades as a result of complex time-dependent stress fields. Here, to facilitate understanding a subset of these structures, we studied water in oil emulsions and focused on the effects of three variables specifically: the confinement factor$(Co=2R/H)$, the viscosity ratio $\left(p\right),$ and the applied shear rate $\left(\dot{\gamma }\right)$. The confinement $\left(Co\right)$ is the ratio between the drop’s diameter ($2R$) and the separation of (the gap between) the circular rotating disks ($H$) containing the emulsion. We carried out (a) observations of the induced structure under different simple shear rates, as well as (b) statistical and morphological analysis of these bands. At low shear rates, the system self-assembles into bands along the direction of the flow and stacked normal to the velocity gradient direction. At higher shear rates is possible to observe bands normal to the vorticity direction. Here, we show that a detailed analysis of the dynamics of the band structures is amenable, as well as measurements of flow field anomalies simultaneously observed. The local emulsion viscosity varies in time, increasing in regions of higher droplet concentration and subsequently inducing velocity components perpendicular to the main flow direction. Thus, the emulsion morphology evolves and changes macroscopically. A relatively plausible explanation is attributed to the competitive effects of coalescence and the rupture of drops, where $p$ values less than one predominate coalescence. Full article