Shale reservoirs are important geological sites for CO2 storage, yet the coupled effects of aqueous phase occurrence and temperature on CO2 transport and multiscale storage remain unclear. This study developed a cross-scale experimental framework combining high-temperature and high-pressure microfluidic visualization, core-scale CO2 convection-diffusion experiments, and nuclear magnetic resonance measurements during CO2 huff-n-puff. The results show that aqueous-phase occupation is the dominant control on CO2 storage efficiency. After six cycles, the effective CO2 storage efficiency reached 46.59% under pure hydrocarbon conditions but remained approximately 11% under water-bearing conditions because of pore-space competition. In the presence of water, CO2 transport shifted from continuous-front advance to snap-off, migration, and dissolution of discrete gas bubbles, producing an apparent propagation rate 8.87 times that under pure hydrocarbon conditions. At 140 °C, the apparent CO2 transport coefficient was 3.98 times that at 80 °C, while the half-life decreased by 87.57%. Increasing water content further reduced transport resistance. Water also selectively regulated hydrocarbon mobilization across pore sizes and occurrence states. Under water-bearing conditions, the increase in CO2 storage potential was more sustained in later cycles, and the incremental storage potential in the fourth cycle was 2.71 times that under pure hydrocarbon conditions, with the dominant contribution shifting from large pores to medium and small pores. Water enhanced the utilization of free hydrocarbons but inhibited the mobilization of adsorbed and strongly bound hydrocarbons. These findings provide cross-scale evidence for optimizing CO2 huff-n-puff and storage in water-bearing shale reservoirs.

Hydrogen storage in saline aquifer offers a promising route to address renewable-energy intermittency. However, the dynamic evaporation of formation water during cyclic hydrogen injection-production remains poorly constrained. We develop a modified Peng-Robinson equation of state with a temperature-dependent binary interaction coefficient to characterize phase behavior in the hydrogen-water system. It is embedded in the numerical model, and simulations indicate that formation-water evaporation overcomes the irreducible-saturation limit by transferring irreducible water into the gas phase, progressively lowering water saturation to zero and creating near-well dry-out zones. As pressure falls, the vapor-carrying capacity of hydrogen increases, producing a "trumpet effect" along flow path. Two competing effects emerge: evaporation lowers water saturation and flow resistance, partly mitigating hysteresis effect; meanwhile, evaporation drives in situ salt precipitation that progressively reduces porosity and permeability, decreasing hydrogen working-gas volume. Although single-cycle effects are modest, cumulative impacts under multi-cycle operation are non-negligible.

Current research on CO2 storage in aquifers typically focuses on high porosity and permeability formations to maximize storage capacity, often overlooking crucial factors such as long-term stability and safety. To address this gap, this study explores the potential for CO2 storage in low porosity and permeability aquifers, utilizing core samples from Ordos storage pilot site. The corresponding T2 spectra exhibit characteristic of high-left and low-right peaks, which separately influence storage capacity and flow behavior. Critical porosity and permeability thresholds were identified, distinguishing the contributions of different pores to storage efficiency. Lower temperature, higher pressure, and supercritical state extend the effective gas displacement duration, enhancing contribution of small pores to CO2 storage. CO2-water redistribution within varying pore sizes leads to the synchronous behavior between injection pressure and water saturation, helping to alleviate CO2 injection challenges. As permeability decreases and displacement cycle increases, relative permeability curves display rightward and leftward shifts, respectively. While these shifts reduce movable pore space and CO2 storage capacity, they concurrently increase residual gas and connate water saturations, thus enhancing CO2 storage stability through residual gas trapping and solubility trapping mechanisms. Nanopore CO2 adsorption further strengthens this storage stability. Low permeability aquifers, characterized by tighter grain packing, stronger cementation, and smaller pores, provide superior resistance to geochemical dissolution and mechanical damage. Consequently, these aquifers provide unique advantages in structural stability and long-term sequestration safety compared to higher permeability counterparts. Furthermore, the greater abundance of low permeability aquifers may compensate for their disadvantage of low storage efficiency.

Formation water evaporation has received limited attention in the context of CO2 saline aquifer storage. To address this gap, a CO2-H2O phase equilibrium model was developed and validated to characterize subsurface water evaporation behavior. The results reveal that the presence of gaseous or supercritical CO2 is a prerequisite for effective water evaporation, which is primarily governed by thermodynamic conditions and phase transitions. While rising temperature consistently promotes evaporation, the influence of pressure exhibits a turning trend-initially suppressing, then enhancing it. Core-scale simulations reveal that formation water migration is governed by two coupled mechanisms: displacement and evaporation. Formation water evaporation eliminates the constraint of irreducible water saturation, thereby expanding the effective pore space for fluid flow. To overcome the limitations of conventional relative permeability curves that ignore evaporation effects, a correction method is proposed to improve the accuracy of gas-liquid flow simulation. Field-scale simulation results demonstrate that evaporation is most pronounced in near-wellbore region, extending from several to dozens of meters due to cumulative effects. This localized phenomenon is governed by high pore-volume displacement and low water vapor saturation. Although salt precipitation induced by evaporation can reduce permeability, this adverse effect is generally outweighed by the enhancement resulting from the reduction in irreducible water saturation. Overall, evaporation influences fluid flow primarily through four mechanisms: reducing irreducible water mole fraction, enhancing gas-phase flow capacity, lowering CO2 injection pressure, and improving effective pore-throat radius for fluid flow. Collectively, formation water evaporation exerts a predominantly positive effect on CO2 saline aquifer storage.

Evaporation is one of the primary mechanisms in subsurface fluid migration, prevalent in gas-liquid multiphase flow processes within porous media. However, less emphasis has been placed on fluid evaporation during its flow from well to formation. This study investigates the behavior of formation water evaporation and its impact on CO2 storage through high-volume CO2 displacement experiments coupled with online nuclear magnetic resonance testing. The retrograde crossover phenomenon of water recovery under varying temperatures is observed during high-volume CO2 displacement. The color change in silica gel provides clear evidence of formation water evaporation which leads to the crossover. Initially, formation water migration is primarily driven by CO2 displacement; however, as gas saturation exceeds 40 %, evaporation replacing displacement becomes the dominant migration mechanism. The primary migration mechanism shifts during this process. Evaporation typically occurs at inlet of the core, or near-wellbore area in field applications. Pronounced CO2 override flow phenomenon is observed, which significantly enhances the water evaporation and gas channeling in the upper part of porous media. A sufficient cumulative CO2 injection volume is necessary for significant formation water evaporation. Increasing temperature within an enclosed space does not significantly enhance water evaporation. Conversely, both isothermal depressurization and vacuum evacuation with an open boundary can markedly increase water evaporation. These outcomes document that open boundary, fluid flow, and high-volume CO2 injection are prerequisites for effective formation water evaporation. Furthermore, high formation temperature, large pressure difference, and slow injection speed promote earlier and more intense formation water evaporation. The effects of evaporation on filtration are twofold: on one hand, the reduction in irreducible water saturation enhances permeability; on the other hand, salt precipitation resulting from evaporation decreases permeability. Therefore, rationally utilizing formation water evaporation mechanism can lower flow resistance near wellbore, reduce injection pressure, improve sweep efficiency, and increase CO2 storage capacity.

Flue gas poses subsurface direct storage inefficiency due to its high non-CO2 content, while surface separation, desulfurization and denitrification processes require additional equipment and financial resources. To address these challenges, flue gas subsurface component separation and CO2 sequestration within aquifer were proposed in this paper. CO2 migrates notably slower than N2, leading to the gathering of N2 at gas flooding front and the occurrence of CO2 hysteresis during flue gas filtration within the aquifer. The phenomenon, characterized by gas composition deviations from the original injection mole fractions of N2 and CO2, is referred to as the flue gas component separation. Numerical simulation results indicate that the solubility difference between N2 and CO2 is the primary force driving the separation of components, and the asynchronous filtration velocities of the gas and aqueous phases further promote the separation. Thus, simultaneous N2 separation and CO2 storage can achieve by the optimized gas-water alternate injection, and the efficiencies of N2 separation and CO2 storage are inversely correlated. Increasing N2 mole fraction within the injected flue gas enhances the efficiency of N2 separation, while having a slight effect on CO2 storage. Water vapor in flue gas condenses and integrates into the liquid phase, while O₂ component is produced slightly later than N₂, leading to a marginal reduction in N₂ separation efficiency. The synergistic influences of aquifer temperature and pressure exhibit bidirectionality, stemming from the shift between the dominant factors between CO2 dissolution and gas sweep efficiency. Conditions of relatively lower aquifer temperatures and moderate pressures, particularly in medium permeability aquifers, are more favorable for enhancing N₂ separation and CO₂ storage. This proposal method holds the potential for efficient subsurface separation of flue gas components and concurrent underground storage of CO2, thereby contributing to the reduction of greenhouse gas emissions and mitigation of climate change.

Flue gas poses subsurface direct storage inefficiency due to its high non-CO2 2 content, while surface separation, desulfurization and denitrification processes require additional equipment and financial resources. To address these challenges, flue gas subsurface component separation and CO2 2 sequestration within aquifer were proposed in this paper. CO2 2 migrates notably slower than N2, 2 , leading to the gathering of N2 2 at gas flooding front and the occurrence of CO2 2 hysteresis during flue gas filtration within the aquifer. The phenomenon, characterized by gas composition deviations from the original injection mole fractions of N2 2 and CO2, 2 , is referred to as the flue gas component separation. Numerical simulation results indicate that the solubility difference between N2 2 and CO2 2 is the primary force driving the separation of components, and the asynchronous filtration velocities of the gas and aqueous phases further promote the separation. Thus, simultaneous N2 2 separation and CO2 2 storage can achieve by the optimized gas-water alternate injection, and the efficiencies of N2 2 separation and CO2 2 storage are inversely correlated. Increasing N2 2 mole fraction within the injected flue gas enhances the efficiency of N2 2 separation, while having a slight effect on CO2 2 storage. Water vapor in flue gas condenses and integrates into the liquid phase, while O2 component 2 component is produced slightly later than N2, 2, leading to a marginal reduction in N2 2 separation efficiency. The synergistic influences of aquifer temperature and pressure exhibit bidirectionality, stemming from the shift between the dominant factors between CO2 2 dissolution and gas sweep efficiency. Conditions of relatively lower aquifer temperatures and moderate pressures, particularly in medium permeability aquifers, are more favorable for enhancing N2 separation 2 separation and CO2 2 storage. This proposal method holds the potential for efficient subsurface separation of flue gas components and concurrent underground storage of CO2, 2 , thereby contributing to the reduction of greenhouse gas emissions and mitigation of climate change.

CO2 saline aquifer storage represents a promising strategy for mitigating the environmental impact of greenhouse gas emissions. However, the long-term effects of CO2 dissolved in formation water on rock minerals remain insufficiently understood. This study utilizes cast thin section analysis, scanning electron microscopy, and energy dispersive spectrometry techniques to perform a comprehensive microscopic investigation on this issue. Experimental results from sandstone core samples drilled from the Ordos pilot field reveal that feldspar minerals predominantly undergo geochemical dissolution, while quartz and clay minerals primarily exhibit physical alterations. Feldspar minerals, including albite, potassium feldspar, and anorthite, exhibit significant geochemical dissolution, characterized by cleavage plane dissolution, swelling, selective dissolution, and in-situ accumulation of dissolution products. This process leads to the formation of secondary minerals such as quartz, kaolinite, and illite, along with various microscopic structures like vugs, pits, and filamentous remnants. Alterations in quartz include the formation of stress-induced microfractures, the attachment of mineral clasts, the precipitation of geochemical reaction products, and pore blockage. In clay minerals, the formation, closure, interconnection, and reconfiguration of microfractures are evident characteristics, particularly at the nanoscale. The products of CO2-H2O-rock interactions typically comprise a complex mixture of physical and chemical products, marked by intricate elemental compositions and diverse structural forms, including blocky, granular, powdery, filamentous, and floc-like structures. This work reveals the distinctive chemical dissolution mechanisms of sandstone with complex mineral compositions, clarifies the CO2-induced physical alteration behavior of multiple minerals and identifies the multi-scale migration mechanisms of products generated by CO2-H2O-rock interactions. Moreover, these interactions have a dual impact: they enhance the porosity and permeability, while also potentially compromising the structural integrity of the rock and formation. This research provides a foundation for assessing the impact of CO2 storage on fluid flow and evaluating environmental safety concerns, such as CO2 leakage and geological subsidence.

Production Optimization is a significant method for oilfields to control water cut and stabilize oil production. When the oilfield enters the high or ultra-high water cut stage, it becomes particularly important to use production optimization methods for improving the water-flooding efficiency. Currently, the commonly used production optimization methods are based on reservoir simulators. Such methods require lots of forward simulations during optimizing, which results in low computational efficiency. It's not applicable to the reservoir without numerical simulation models. Thus, a new production optimization method based on the reservoir proxy model is proposed in this work. Firstly, the dynamic production data of the oilfield are collected and preprocessed for training the Extreme Gradient Boosting model, and constructing the proxy model for water cut prediction of producers and the reservoir. Then, an optimal control model for minimizing the water cut of the reservoir can be constructed based on the proxy model. Finally, an optimal injection-production scheme can be obtained by using the differential evolution algorithm. For the evaluation and verification purposes, the proposed method is applied to a well block from SL oilfield, China. Empirical results demonstrated that the proposed method can effectively improve the water-flooding efficiency.

In-depth water flooding profile modification is a new problem for low permeability formation under fracturing. Profile control study for in-depth cross flow which couples fracture and matrix is neither comprehensive nor complete at present. Artificial hydraulic fracturing core is manufactured to conduct core flood experiment. In-depth profile modification mechanisms of gel-nitrogen-foam are revealed based on microstructure analysis and mechanical stability evaluation. The instantaneous stability and durability of gel-nitrogen-foam are evaluated by breakthrough pressure and residual resistance factor. Weak movement ability restrains the distribution of gel in cross zone and bubble burst effect declines the active time of nitrogen-foam. Gel-nitrogen-foam displays promised profile modification performance based on synergistic effect which combines movement ability of nitrogen-foam and durability of gel. Nuclear magnetic resonance (NMR) test result shows that sweep area of matrix significant increases after profile modification, which indicates that enhance oil recovery (EOR) main contributes by the remaining oil in matrix nearby injection fracture. The optimized gas/liquid ratio and injection volume are 1.95 and 2.8 PV separately with incremental EOR of 9.74%. Coupling laboratory experiment with numerical simulation, this work offers a new insight of in-depth cross flow profile modification mechanism for formation under fracturing from macroscopic and microscopic views.

Excessive water production is an enduring problem in the oil industry that has always been an unbearable burden on the environment and a great damage to the ultimate oil recovery. Gel treatment has been routinely used for decreasing water production. Disproportionate permeability reduction (DPR) is a natural phenomenon in some polymer gels that can reduce the permeability to water more than to oil. The conformance improvement treatments with DPR can effectively reduce the water cut without substantially reducing the oil productivity in fractured reservoirs. At present, there are no widely accepted mechanisms of oil-phase permeability development and DPR. In this paper, nuclear magnetic resonance is applied to study the mechanisms of oil-phase permeability development, DPR, and permeability influence by scanning different core samples treated with Cr(III)–acetate–hydrolyzed polyacrylamide polymer gels. Results show that the permeability difference leads to a certain alteration in NMR T2 curves, but final c...

Alkali–surfactant–polymer (ASP) flooding, which can reduce interfacial tension (IFT) and the mobility ratio between oil and water phases, has been proven to be effective for enhancing oil recovery in laboratory experiments and field pilots. However, the study of interactions within alkali–surfactant–polymers for chemical flooding is neither comprehensive nor complete until now. Laboratory experiments were conducted and a corresponding numerical simulation model was established to characterize multiple component interactions during the ASP flooding process. Synergistic effects of multiple component interactions on viscosity variation, IFT reduction, and multicomponent adsorption were studied separately. ASP solution viscosity shows non-linear variation behavior with an increasing polymer concentration. Alkali decreases the molecular hydraulic radius of a polymer, and then limits its contribution to viscosity. Oil–water interfacial tension decreases with the join in of polymer which can act as an alternative effect to replace surfactant adsorbed on a mineral surface. Petroleum acid will react with alkali and produce petroleum soap to perform a synergetic action with the surfactant on IFT reduction. Adsorption fraction and diffusion rate of a surfactant will diminish due to rheology improvements caused by a polymer. Alkali can protect a surfactant from adsorption consumption by competitive adsorption. A viscosity non-linear logarithm mixing method, IFT reduction–relative permeability curve interpolation method, and a multicomponent adsorption isotherm model were developed to characterize and simulate the synergistic effects obtained by experiments. A novel ASP flooding numerical simulation model was constructed which coupled the synergistic effects simulation methods of viscosity variation, IFT reduction, and multicomponent adsorption. The numerical simulation result based on the proposed model has better agreement with experiment results compared with that of the traditional model. Validation results proved the effectiveness of the proposed model which can be used to enhance a synergistic mechanism study and field application of ASP flooding.

A novel methodology was developed based on oil-based foam to systematically investigate foamy oil stability. The first step was to generate an oil-based analogue model that has similar characteristics of foamy oil. Then, the effects of the key factors were investigated with the created oil-based foam by a new experimental procedure. Moreover, a statistical approach was utilized to ensure reliability of the experimental data. Finally, we proposed a new method to describe foamy oil rupture and simulate its defoaming kinetics. The results showed that the oil-based foam can be precursors to studies on actual foamy oil and other petroleum foams. [GRAPHICS] .

Alkali-surfactant-polymer (ASP) flooding, which can reduce interfacial tension (IFT) and the mobility ratio between oil and water phases, has been proven to be effective for enhancing oil recovery in laboratory experiments and field pilots. However, the study of interactions within alkali-surfactant-polymers for chemical flooding is neither comprehensive nor complete until now. Laboratory experiments were conducted and a corresponding numerical simulation model was established to characterize multiple component interactions during the ASP flooding process. Synergistic effects of multiple component interactions on viscosity variation, IFT reduction, and multicomponent adsorption were studied separately. ASP solution viscosity shows non-linear variation behavior with an increasing polymer concentration. Alkali decreases the molecular hydraulic radius of a polymer, and then limits its contribution to viscosity. Oil-water interfacial tension decreases with the join in of polymer which can act as an alternative effect to replace surfactant adsorbed on a mineral surface. Petroleum acid will react with alkali and produce petroleum soap to perform a synergetic action with the surfactant on IFT reduction. Adsorption fraction and diffusion rate of a surfactant will diminish due to rheology improvements caused by a polymer. Alkali can protect a surfactant from adsorption consumption by competitive adsorption. A viscosity non-linear logarithm mixing method, IFT reduction-relative permeability curve interpolation method, and a multicomponent adsorption isotherm model were developed to characterize and simulate the synergistic effects obtained by experiments. A novel ASP flooding numerical simulation model was constructed which coupled the synergistic effects simulation methods of viscosity variation, IFT reduction, and multicomponent adsorption. The numerical simulation result based on the proposed model has better agreement with experiment results compared with that of the traditional model. Validation results proved the effectiveness of the proposed model which can be used to enhance a synergistic mechanism study and field application of ASP flooding.

基于材料力学与界面化学基本原理,研究了纤维在孔隙中的分布形态,分析了纤维属性参数对堵水阻力的影响规律,建立了纤维堵水阻力计算模型.基于絮凝体的流变特性,研究了絮凝体堵水前后形态变化,采用屈服应力法和相界面法分别建立了絮凝体单独作用时的阻力计算模型.将两阻力计算模型进行耦合,得到了纤维-絮凝体一维二元网络联合堵水体系阻力计算模型.该模型揭示了纤维-絮凝体微观作用机理,为复合堵剂体系的理论研究提供了新的思路.

According to the teaching status of the flow in porous media and petrophysics experiments,as well as high temperature and high pressure environment and strong abstraction in some experiments,the presentation-assimilationdiscussion ("PAD") mode of experiment teaching has been presented based on the simulation experimental platform and modularized teaching method.First of all,the experimental content is modularized,15 experiments are divided into 6 modules.Secondly,students take one week to absorb experiment content using the simulation experimental platform,which is safe and repeatable.Finally,classroom discussions and group experiments are conducted.The results show that the PAD mode has improved the students' enthusiasm and participation,and the effect of theory and experiment teaching has been improved obviously.Meanwhile,it is also a bold attempt and innovation for students and teachers.

Aiming at the phenomena which may occur after proifle control, such as decrease in water injectivity index, decrease in water content and increase in oil production, the proifle control effective evaluation indicator system which can be quantized is established. On this basis, the multi-indicator evaluation&classiifcation method for proifle control well groups is established by using the fuzzy clustering theory. In light of the result of classiifcation, the differentiation adjustment measures are brought forth for different types of proifle control well groups:this type of proifle control agent is continuously used for the well groups with good comprehensive assessment of proifle control effect;for the well groups with poor comprehensive assessment, based on the main indicators affecting the assessment result, by further analyzing the distributive location, physical property parameter and proifle-control injection parameter characteristic of this block, this reason of poor adaptability of this type of proifle control agent is found and the proifle control plan is adjusted. Such method has been used to classify 16 proifle control well groups in a block of Fuyu Oilifeld, the proifle control program for well groups with poor effect has been adjusted, and thereafter, the oil production per well has increased by 472 t in average, with the effect rate of proifle control reaching 81%. The established classiifcation and differentiation adjustment strategy for proifle control well group may be used to evaluate the proifle control effect of fractured reservoir, and can provide the guidance for subsequent formulation of adjustment measures.

A coupled method describing gas solid two-phase flow has been proposed to numerically study the bubble formation at a single orifice in gas-fluidized beds. Solid particles are traced with smoothed particle hydrodynamics, whereas gas phase is discretized by finite volume method. Drag force, gas pressure gradient, and volume fraction are used to couple the two methods. The effect of injection velocities, particle sizes, and particle densities on bubble growth is analyzed using the coupled method. The simulation results, obtained for two-dimensional geometries, include the shape and diameter size of a bubble as a function of time; such results are compared with experimental data, previous numerical results, and other approximate model predictions reported in the literature. Moreover, the flow profiles of gas and particle phases and the temperature distribution by the heat transfer model around the forming bubble are also discussed. All results show that the coupled method efficiently describes of the bubble formation in fluidized beds. The proposed method is applicable for solving gas solid two-phase flow in fluidization.

Polymer flooding has been widely used in the development of offshore oilfield as its significant EOR performance, which can achieve high oil recovery during the short service life of offshore platform. Effectiveness evaluation is an important aspect in polymer flooding application, and the results will affect the adjustment of polymer flooding. However, there is not too much study focusing on this field until now. In this paper, an evaluation model was developed to estimate the effectiveness of polymer flooding. The response characteristics of polymer flooding were studied by the core flooding experiments. The comparison experiments of water flooding and polymer flooding were conducted to investigate the dynamic performance of production parameters during the flooding process. The results showed that the most significant performance is the "U" shape of water cut curve which indicate the effectiveness of polymer flooding. It also can be observed that the injection pressure and the oil recovery will increase when polymer flooding works, and their variation ranges have positive correlation with the effectiveness of polymer flooding. To get more details of geology and production parameters affect the polymer flooding effectiveness, numerical simulation model was built based on the data of Bohai oilfield. The influences of eight optimized parameters on polymer flooding effectiveness were studied by numerical simulation. Parameter sensitivity analysis was conducted by grey correlation method and the rank can be obtained according to the influence of each parameter on polymer flooding effectiveness. The results showed that mobility ratio, permeability variation coefficient and injection time are the top three parameters which indicate that they have more important influence to polymer flooding effectiveness. Then a multi-parameter response system was developed to describe the relationship between eight parameters and polymer flooding effectiveness. Consequently, a comprehensive effectiveness evaluation model was built which include the response characteristics summarization, parameter sensitivity analysis and multi-parameter response system evaluation. The effectiveness of polymer flooding can be evaluated and its key influence factors can be obtained by this model. It has been used in the evaluation of polymer flooding in Suizhong 36-1 well group in Bohai offshore oilfield in China, with inaccuracy of 7.83%.

A high-resolution three-dimensional (3D) outcrop model of a Jurassic carbonate ramp was used in order to perform a series of detailed and systematic flow simulations. The aim of this study was to test the impact of small- and large-scale geological features on reservoir performance and oil recovery. The digital outcrop model contains a wide range of sedimentological, diagenetic and structural features, including discontinuity surfaces, shoal bodies, mud mounds, oyster bioherms and fractures. Flow simulations are performed for numerical well testing and secondary oil recovery. Numerical well testing enables synthetic but systematic pressure responses to be generated for different geological features observed in the outcrops. This allows us to assess and rank the relative impact of specific geological features on reservoir performance. The outcome documents that, owing to the realistic representation of matrix heterogeneity, most diagenetic and structural features cannot be linked to a unique pressure signature. Instead, reservoir performance is controlled by subseismic faults and oyster bioherms acting as thief zones. Numerical simulations of secondary recovery processes reveal strong channelling of fluid flow into high-permeability layers as the primary control for oil recovery. However, appropriate reservoir-engineering solutions, such as optimizing well placement and injection fluid, can reduce channelling and increase oil recovery.