Reservoir Recovery Research Articles

Surfactant-Enhanced Assisted Spontaneous Imbibition for Enhancing Oil Recovery in Tight Oil Reservoirs: Experimental Investigation of Surfactant Types, Concentrations, and Temperature Impact

Surfactant-assisted spontaneous imbibition is an important mechanism in enhanced oil recovery by capillary pressure in low permeability and tight oil reservoirs. Though many experiments have been conducted to study the mechanism of enhanced oil recovery by surfactant-assisted spontaneous imbibition, the effects of surfactant type, concentration, and temperature have not been well studied. Using tight sandstone outcrop core samples with similar permeability and porosity, this paper experimentally studies surfactant-assisted spontaneous imbibition using three different surfactant types, i.e., sodium dodecylbenzene sulfonate (SDBS), cocamidopropyl betaine (CAB), and C12–14 fatty alcohol glycoside (APG). In addition to the type of surfactant, the effect of the surfactant concentration and the temperature is also investigated. The study results show that the ultimate oil recovery of spontaneous imbibition with formation water and denoised water is about 10%. Surfactant can significantly improve the oil recovery of spontaneous imbibition by reducing the interfacial tension between oil and water, emulsifying crude oil and improving oil mobility. APG showed better performance compared to SDBS and CAB, with a maximum oil recovery factor of 36.19% achieved with formation water containing 0.05% APG surfactant. Lower concentrations (0.05% APG) in the formation water resulted in a higher oil recovery factor compared to 0.1% APG. Increasing temperature also improves oil recovery by reducing oil viscosity. This empirical study contributes to a better understanding of the mechanism of surfactant-assisted spontaneous imbibition and enhanced oil recovery in tight oil reservoirs.

Effect of irreversible and unstable processes on reservoir recovery

Hysteresis behaviour, during filtration, is caused by lithological differences in geo-fluid-dynamical media, geological-physical characteristics, and properties of saturating fluids. Typically, irreversible changes are caused by excessive external loads on the investigated porous media. The proposed solutions are part of a new concept of unsteady water flooding, which allows for early prediction of water breakthrough into production wells. This text discusses the negative impact of hysteresis phenomena on oil recovery and proposes a solution. To solve this task, control parameters, based on growth models and catastrophe theory, are selected so to predict local instability and irreversibility before the bifurcation moment., Herewith it is necessary to develop technologies, which can prevent irreversible changes in permeability, capillary retention of oil, oil degassing, and to consider the unstable behavior of the displacement front. Systemic optimization of oil field development aims to increase oil production, effectively mobilize, save injected and recovered water and gas. Keywords: hysteresis; instability; irreversible changes in permeability and porosity; phase transition; capillary forces; oil recovery.

Investigation of CO2-EOR and storage mechanism in Injection-Production coupling technology considering reservoir heterogeneity

Heterogeneous reservoirs offer greater potential for increased oil production and carbon storage capacity when using CO2 injection-production coupling technology in a broader range of geological formations. However, the impact of heterogeneity on the mechanisms and effectiveness of CO2 utilization and storage remains unclear. This study comprehensively investigates the mechanisms of enhanced oil recovery and the sequestration potential of CO2 injection-production coupling technology in heterogeneous reservoirs using both microscopic visualization experiments and macroscopic core experiments. The results reveal that during continuous gas flooding, CO2 forms rapid flow channels, leading to the formation of oil films and columnar residual oil in high-permeability zones, while small pores remain unaffected. Meanwhile, under high-speed injection conditions, the overall microscopic recovery rate increases by 13.8%. However, a higher proportion of porous residual oil is retained in low-permeability zones. During asynchronous injection-production cycles, the microscopic recovery rate remains above 86%, indicating a more thorough utilization of porous residual oil, which is predominantly present in membranous and angular corner configurations. The mechanisms of enhanced oil recovery include the increase in energy, dissolution expansion, and displacement-transport mechanisms. In asynchronous injection-production mode, macroscopic recovery rates are all above 80%. Additionally, with an increase in permeability contrast, the CO2 utilization efficiency rises from 5.9% to 8.6%, demonstrating the high potential of injection-production coupling technology for enhanced oil recovery and geological carbon sequestration in heterogeneous reservoirs. This study provides theoretical support for CO2 injection development and geological sequestration in heterogeneous reservoirs.

Nanoparticle-Enhanced Water-Based-Emulsion Fracturing Fluid for Improved Imbibition Recovery in Unconventional Reservoirs: Performance and Mechanism

Summary The conventional friction reducer, typically a water-in-oil (W/O) emulsion, used in slickwater, encounters challenges related to poor environmental friendliness, limited stability, and low activity, hindering its widespread applicability. In this study, we synthesized a water-based emulsion through water dispersion polymerization, incorporating nanoparticles (NPs) into the process to enhance the stability and activity of the polymer emulsion. The result is an environmentally friendly, oil-phase-free, instantly dissolution, and highly efficient friction reducer, intended to optimize the utilization efficiency of slickwater. The NP-enhanced water-based emulsion demonstrated a consistent and spherical dispersion, featuring an average particle size of ~10 μm, maintaining stability for more than 6 months. With rapid dissolution in water, achieved within a mere 38 seconds, it facilitated continuous on-the-fly mixing. Slickwater composed of this emulsion exhibited outstanding application performance, yielding a remarkable 76% reduction in pipeline friction. The presence of NPs and specific monomers facilitated the formation of a spatial network structure that maintains high temperature/shear resistance even after prolonged shear. Moreover, the system exhibited an exceptional capacity for imbibition oil production. Indoor spontaneous imbibition experiments showed a final recovery rate of 32.41% in tight oil cores (~10% higher than conventional systems), and imbibition depth reached 40.2 mm (1.2-fold increase compared with traditional systems). Field experiments were conducted in a tight oil reservoir to validate practical applications; the results further validated the effectiveness of the novel system. The treated wells showcased rapid oil production, reaching an average daily production rate of 55.8 t/d and water content as low as ~31%, satisfying the predicted production target.

Design of Janus Nanoparticles for Mobility Control in Heterogeneous Reservoirs.

Unfavorable mobility ratios in heterogeneous reservoirs have resulted in progressively poor waterflood sweep efficiency and diminishing production. In order to address this issue, our study has developed amphiphilic-structured nanoparticles aimed at enhancing the microscopic displacement capability and oil displacement efficiency. First, the transport process of Janus nanoparticles in porous media was investigated. During the water flooding, Janus nanoparticle injection, and subsequent water flooding stages, the injection pressure increased in a "stepped" pattern, reaching 0.023, 0.029, and 0.038 MPa, respectively. Second, emulsification effects and emulsion viscosity experiments demonstrated that the amphiphilic structure improved the interaction at the oil-water interface, reducing the seepage resistance of the oil phase through emulsification. In porous media, Janus nanoparticles transported with water exhibit 'self-seeking oil' behavior and interact with the oil phase, reducing the viscosity of the oil phase from 19 to 5 mPa·s at 80 °C. Finally, the core model displacement experiment verified the characteristics of Janus nanoparticles in improving the oil-water mobility ratio. Compared with the water flooding stage, the recovery percent increased by 20.8%, of which 13.7% was attributed to the subsequent water flooding stage. Utilizing the asymmetry of the Janus particle structure can provide an effective path to enhanced oil recovery in inhomogeneous reservoirs.

Experimental Study on Improving Oil Recovery Mechanism of Injection–Production Coupling in Complex Fault-Block Reservoirs

In order to improve the effect of injection–production coupling development to improve crude oil recovery in complex fault-block reservoirs, we carried out a physical simulation experiment based on a sandpack model of transforming water-driven development into injection–production coupling development and quantitatively evaluated the influence of rounds of injection pressure coupling on the crude oil mobilization in reservoirs with different permeability levels and on oil recovery. Meanwhile, the characteristics of residual oil were studied via a numerical simulation method. The mechanism of increased oil production via injection–production coupling development was revealed by analyzing the water and oil contents, formation pressure, and streamline fields through the establishment of mechanism models. The results of the physical experiment show that injection–production coupling can improve the recovery effect of medium- and low-permeability reservoirs by 55.66%. With an increase in the injection pressure, the oil recovery percentage of the low-permeability sandpack model at 20 MPa is 100%, and this study finds that injection–production coupling is the main way to develop the recoverable oil in a low-permeability reservoir. The numerical simulation results show that among the four remaining oil distribution types (interwell-enriched, low-permeability zone-enriched, well network imperfection, and mismatch between injection and production), the interwell-enriched type of the remaining oil reserves accounts for the highest proportion (48.52%). The simulation results of the mechanism model show that water-driven development easily leads to streamline solidification, resulting in ineffective circulation of the injected water. Compared with conventional water-driven development, the pressure propagation range is significantly increased in injection–production coupling development. The reservoir streamline distribution is more continuous and uniform, and the flooding wave is wider in volume and range. This research provides a theoretical basis for the injection–production coupling technology policy in complex fault-block reservoirs.

Pore-scale modeling of preformed particle gel (PPG) extrusion in porous media

Preformed particle gel (PPG) is a promising profile control agent for enhanced oil recovery in heterogeneous reservoirs. For an improved sweep, the remigration behavior of PPG once blocked by pore throats is of crucial importance. In this paper, the process of a hyper-elastic particle passing through a pore throat is simulated, allowing investigation of the extrusion mechanism of PPG with deformation under a certain hydraulic pressure. The results reveal that PPG is subjected to a varying resistance during the process of entering, penetrating and leaving the throat. The maximal radial resistance occurs when the particle center arrives at the narrowest throat, whereas the maximal axial resistance occurs before that. In the meantime, it is shown that the particle gel bears over 80% body strain during the extrusion process through frictional pore throat. The hydraulic pressure needed for the PPG extrusion through the pore throat depends on the mechanical behaviors (hyper-elasticity of PPG, and friction coefficient of the PPG-throat interface) and geometrical properties (the particle size, and the shape of throat wall) of the PPG-throat system. Based on the simulation results, an empirical model is finally established to predict the required driving pressure. Eventually, the pore-scale model is upscaled and employed to attain effective pressure windows for profile-control in a reservoir scale formation with 10 times permeability heterogeneity.

Evaluation of Recovery of Tight Sandstone Gas Reservoirs Based on a Seepage Steady-State Model

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.

A two-phase, multi-component model for efficient CO2 storage and enhanced gas recovery in low permeability reservoirs

Introduction: Carbon dioxide (CO2) enhanced gas recovery represents a viable strategy for sequestering CO2 while concurrently augmenting gas production from subsurface reservoirs. Gas reservoirs, as inherent geological formations, are optimal repositories for gaseous compounds, rendering them suitable for CO2 storage. Nevertheless, the economic viability of pure CO2 storage necessitates integration with oil and gas recovery mechanisms to facilitate widespread CO2 utilization.Method: This study addresses the complexities of CO2 enhanced gas recovery through a comprehensive approach that combines theoretical model and numerical simulations. A numerical model is developed to simulate three-component diffusion involving CO2, and methane (CH4) in a two-phase system comprising gas and water.Results: The investigation systematically explores the process of enhanced CH4 extraction and CO2 injection into the reservoir and examines the influencing factors on extraction. Simulation results reveal a power-law decrease in CH4 production rate, stabilizing at a constant extraction rate. Enhanced CH4 extraction benefits from increased porosity, with higher porosity levels leading to greater CH4 extraction. Permeability augmentation positively influences CH4 production, although with diminishing returns beyond a certain threshold. The CO2 injection rate shows a direct proportionality to CH4 production. However, elevated CO2 injection rates may increase reservoir pressure, potentially causing cap rock damage and CO2 gas flushing.Discussion: This study contributes valuable theoretical insights to the field of CO2 enhanced gas recovery engineering, shedding light on the intricate dynamics of multi-component fluid transport processes and their implications for sustainable CO2 utilization.

Exploring pore-scale production characteristics of oil shale after CO2 huff ‘n’ puff in fractured shale with varied permeability

Recent studies have indicated that the injection of carbon dioxide (CO2) can lead to increased oil recovery in fractured shale reservoirs following natural depletion. Despite advancements in understanding mass exchange processes in subsurface formations, there remains a knowledge gap concerning the disparities in these processes between the matrix and fractures at the pore scale in formations with varying permeability. This study aims to experimentally investigate the CO2 diffusion behaviors and in situ oil recovery through a CO2 huff ‘n’ puff process in the Jimsar shale oil reservoir. To achieve this, we designed three matrix-fracture models with different permeabilities (0.074 mD, 0.170 mD, and 0.466 mD) and experimented at 30 MPa and 91 °C. The oil concentration in both the matrix and fracture was monitored using a low-field nuclear magnetic resonance (LF-NMR) technique to quantify in situ oil recovery and elucidate mass-exchange behaviors. The results showed that after three cycles of CO2 huff ‘n’ puff, the total recovery degree increased from 30.28% to 34.95% as the matrix permeability of the core samples increased from 0.074 to 0.466 mD, indicating a positive correlation between CO2 extraction efficiency and matrix permeability. Under similar fracture conditions, the increase in matrix permeability further promoted CO2 extraction efficiency during CO2 huff ‘n’ puff. Specifically, the increase in matrix permeability of the core had the greatest effect on the extraction of the first-cycle injection in large pores, which increased from 16.42% to 36.64%. The findings from our research provide valuable insights into the CO2 huff ‘n’ puff effects in different pore sizes following fracturing under varying permeability conditions, shedding light on the mechanisms of CO2-enhanced oil recovery in fractured shale oil reservoirs.

Calculation Method of the Phase Recovery of Gas Cap Reservoir with Bottom Water

In gas cap reservoirs underlain by bottom water, the connection between the reservoir and the aquifer leads to an increasing invasion of bottom water as reservoir development progresses. The average formation pressure of the reservoir will change, and the separated phase recovery of the gas cap reservoir with bottom water will be affected by the change in the average formation pressure. The traditional average formation pressure calculation formulas do not consider the water influx, so the accurate calculation of separated recovery cannot be obtained by those calculation methods. The development of gas cap reservoirs with bottom water presents several challenges, including the simultaneous production of oil and gas, undetermined rates of bottom water influx, and uncertain formation pressure and gas-to-oil ratios. These factors contribute to substantial discrepancies between theoretical calculations and actual observations. A more accurate and comprehensive approach is required to address these issues and enable a precise determination of the phase separated recovery in gas cap reservoirs with bottom water. The volume-deficit method is integrated with the Fetkovich quasi-steady state method for water influx. The water-influx prediction is incorporated into the material balance equation, which is further refined by introducing the Fetkovich model to enhance the estimation of the average formation pressure. The average formation pressure, once determined, is utilized in conjunction with the established relationships among this pressure, surface oil production, gas production, and the dissolved gas–oil ratio. Through the application of mass conservation principles, the varying degree of phase recovery, as influenced by fluctuations in the average formation pressure, is calculated. The precision of this refined method has been validated by a comparison with outcomes generated by simulation software. The results reveal a commendable accuracy: an error in the average formation pressure calculation is found to be merely 2.61%, while the errors in recovery degrees for gas cap gas, dissolved gas, and oil-rim oil are recorded at 2.73%, 2.94%, and 1.28%, respectively. These minor discrepancies indicate a good level of consistency and affirm the reliability of this advanced methodology, as demonstrated by passive assessments. This paper provides a method to accurately calculate the phase recovery without some oil- and gas-production data, which provides accurate data support for the actual production evaluation and subsequent development measures.

Study on optimization and mechanism of CO2 injection to enhance oil recovery in mid-deep heavy oil reservoirs

In order to improve the oil recovery of mid-deep heavy oil reservoirs, this study investigates the efficiency of enhanced oil recovery and the mechanisms of oil displacement in mid-deep heavy oil reservoirs using different injected gases (N2, CH4, CO2) and development approaches (gas flooding and gas huff-n-puff) through a series of experiments. These experiments include high-pressure physical properties tests of crude oil after gas injection, displacement efficiency tests of gas injection, and displacement efficiency tests of gas huff-n-puff. The results indicate that for mid-deep heavy oil reservoirs, the preferred optimal injection gas is CO2, with gas huff-n-puff being the most effective development method. Furthermore, a numerical simulation study was conducted to explore the adaptability parameters of CO2 huff-n-puff development in different well patterns, encompassing variables such as the amount of gas injected per cycle, crude oil viscosity, reservoir permeability, and oil layer thickness.

Experimental Study on the Mechanism and Law of Low-Salinity Water Flooding for Enhanced Oil Recovery in Tight Sandstone Reservoirs.

Currently, research surrounding low-salinity water flooding predominantly focuses on medium- to high-permeability sandstone reservoirs. Nevertheless, further investigation is necessary to implement this technique with regard to tight sandstone reservoirs. The present study comprises a series of experiments conducted on the crude oil and core of the Ordos Chang 6 reservoir to investigate the influence of ionic composition on low-salinity water flooding in tight oil reservoirs. The change in wettability on the rock surface was analyzed by using the contact angle experiment. The change in recovery rate was analyzed using a core displacement experiment. The reaction between rock fluids was analyzed using an ion chromatography experiment. Additionally, a nuclear magnetic resonance (NMR) experiment was used to analyze the mobilization law of crude oil and the change in wettability on the scale of the rock core. This led to a comprehensive discussion of the law and mechanism of enhancing the recovery rate via low-salinity water flooding from various perspectives. Experiments show that low-salinity water flooding is an effective technique for enhancing recovery in tight sandstone reservoirs. Altering the ionic composition of injected water can improve the water wettability of the rock surface and enhance recovery. Decreasing the mass concentration of Ca2+ or increasing the mass concentration of SO42- can prompt the ion-exchange reaction on the rock surface and detachment of polar components from the surface. Consequently, the wettability of the rock surface strengthens, augmenting the recovery process. Nuclear magnetic resonance experiments evidence that low-salinity water injection, with ion adjustment, significantly alters the interactions between the rock and fluid in tight sandstone reservoirs. As a result, the T2 signal amplitude decreases significantly, residual oil saturation reduces considerably, and the hydrophilic nature of the rock surface increases.

Experimental investigation of CO2 huff-n-puff in tight oil reservoirs: Effects of the fracture on the dynamic transport characteristics based on the nuclear magnetic resonance and fractal theory

CO2 huff-n-puff is a promising method for enhancing oil recovery in tight reservoirs while simultaneously contributing to CO2 geological storage. However, the performance of this method is significantly affected by fractures resulting from hydraulic fracturing and natural fractures. The impact of fracture on oil transport behavior in different pores remains unclear and warrants further investigation. In this study, CO2 huff-n-puff experiments were conducted under induced fracture conditions. A new method for quantifying the relationship between transverse relaxation time T2 and pore radius was proposed by fitting the slopes of the T2 spectrum and the pore size distribution (PSD) curve derived from Micro X-ray computed tomography (Micro-CT). The impact of the fracture on the effective utilization limit was explored, and the fractal dimensions of different cycles were evaluated during CO2 huff-n-puff. The results showed that the oil recoveries of the fracture-free and the fractured samples were 19.97% and 31.16%, corresponding to the effective utilization limits of 1.52 μm and 0.96 μm, respectively. Moreover, based on the fractal characteristics of the whole process of CO2 huff-n-puff, the pore system was divided into micropores (<0.20 μm), small pores (0.20–0.63 μm), intermediate pores (0.63–2.00 μm), and large pores (>2.00 μm). Furthermore, the incremental recovery for each cycle mainly comes from large pores and gradually decreases as the fractal dimension is less than 2.85. The fracture has a significant impact on the migration characteristics of crude oil. The incremental oil in the intermediate pores of the fractured sample, caused by negative convection, was 2.88 times greater than that of the fracture-free sample. Finally, it was found that the gravity effect was more prominent, significantly affecting the remaining oil distributions in fractured reservoirs.

Scaling up in situ combustion process for enhanced oil recovery in water-flooded light oil reservoirs from laboratory to field implementation

Aiming at low permeability, high water content light reservoir with a recovery rate higher than 20%, an improved air injection enhanced heat flooding technology is applied by combining the combustion reaction flow and flue gas flooding mechanism. The method involves the injection of air into the reservoir, which reacts with the crude oil at temperatures ranging from 220 to 300 °C. This reaction consumes part of the oil, enabling effective evaporation and flow of the remaining oil. This process combines combustion reaction flow with flue gas flooding, using high-temperature oxidation reactions to mobilize residual oil. Experimental results from combustion tube tests demonstrate stable reaction fronts, peak temperatures reaching up to 550 °C, and a significant increase in recovery rates, reaching 73.8% in some cases. Field applications of this technology require maintaining high air flux and burning rates in low-permeability zones to ensure effective heat-driven evaporation. The geological model of the well group shows that the recovery factor of the target block can be increased by more than 20% by air injection based on the water drive recovery factor of 28%–30%. The oil exchange ratio can be less than 4000 sm3/m3 by optimizing the air injection rate and oxygen content. The research results provide technical feasibility for heat flooding to significantly improve oil flow and recovery in low-permeability light oil reservoirs.

New Model for Predicting Production Capacity of Horizontal Well Volume Fracturing in Tight Reservoirs.

Production prediction is the most important and comprehensive index to measure the effect of oilfield development, and it is also one of the most fundamental problems in oilfield dynamic analysis. However, the recovery prediction is often affected by many factors. Usually, the recovery is predicted by core experiments, numerical simulations, and mathematical models. The main problem is accurately predicting reservoir recovery based on existing data. This paper proposes a comprehensive prediction model for the problem of recovery. First, the correlation coefficients between 14 factors and recovery were calculated based on Pearson, Spearman, gray correlation, variance selection, univariate selection method, and tree model. Second, the weights of the factors were determined using entropy weighting, CRITIC, and hierarchical analysis to clarify the degree of contribution of different factors to the recovery. Finally, a comprehensive evaluation model was established based on the results of the weighting analysis. The results indicate that the correlation coefficient and weight of porosity, permeability, oil saturation, well spacing, cluster spacing, total fluid volume, and horizontal section length are the most relevant to the recovery. The error between the comprehensive evaluation model and the actual results is less than 3%. Therefore, the method can predict the production capacity of the tight reservoirs. The research results of this paper are of guiding significance for improving the recovery of tight reservoirs.

Research and Application of Carbon Capture, Utilization, and Storage–Enhanced Oil Recovery Reservoir Screening Criteria and Method for Continental Reservoirs in China

CCUS-EOR is a crucial technology for reducing carbon emissions and enhancing reservoir recovery. It enables the achievement of dual objectives: improving economic efficiency and protecting the environment. To explore a set of CCUS-EOR reservoir screening criteria suitable for continental reservoirs in China, this study investigated and compared the CCUS-EOR reservoir screening criteria outside and in China, sorted out the main reservoir parameters that affect CO2 flooding, and optimized the indices and scope of CCUS-EOR reservoir screening criteria in China. The weights of parameters with respect to their influences on CCUS-EOR were determined through principal component analysis. The results show that there are 14 key parameters affecting CO2 flooding, which can be categorized into four levels. For the first level, the crude oil-CO2 miscibility index holds the greatest weight of 0.479. It encompasses seven parameters: initial formation pressure, current formation pressure, temperature, depth, C2–C15 molar content, residual oil saturation, and minimum miscibility pressure. The second level consists of the crude oil mobility index, which has a weight of 0.249. This index includes four parameters: porosity, permeability, density, and viscosity. The third level pertains to the index of reservoir tectonic characteristics, with a weight of 0.141. It comprises two parameters: permeability variation coefficient and average effective thickness. Lastly, the fourth level focuses on the index of reservoir property change, with a weight of 0.131, which solely considers the pressure maintenance level. Based on the CCUS-EOR reservoir screening criteria and index weights established in this study, comprehensive scores for CCUS-EOR were calculated for six blocks in China. Among these, five blocks are deemed suitable for CCUS-EOR. Based on the comprehensive scoring results, a planning for field application of CCUS-EOR is proposed. The study provides a rational method to evaluate the CCUS-EOR reservoir screening and field application in continental reservoirs in China.

Insights into Molecular Dynamics and Oil Extraction Behavior of the Polymeric Surfactant in a Multilayered Heterogeneous Reservoir.

Interlayer heterogeneity, an inevitable and complex challenge during water flooding, seriously constrains the spread of the sweep region and oil recovery enhancement in multilayered heterogeneous reservoirs. To overcome this challenge, a novel polymeric surfactant, having an excellent performance in the reduction of interfacial tension (IFT) and the increase of viscosity of displacing fluid, is applied for enlarging the sweep resonance and increasing the oil washing efficiency. Through the molecular dynamics (MD) simulation, the molecular distributing mechanisms of the polymeric surfactant at the oil-water interface are analyzed to provide the theoretical basis for explaining the microscopic mechanism of oil extraction. To directly reflect the microscopic behavior of oil extraction, multiple transparent sand-packed models are designed to investigate the flowing behavior of different fluids and the extracted mechanisms of the remaining oil in both pore and macroscales. The multilayered heterogeneous reservoirs consisting of high-, moderate-, and low-permeability layers are fabricated to represent a heterogeneous characteristic. The recognition from the visual experiment and MD simulation can study the performance control, the extracting performance of the remaining oil, and the expression of the displacing front from different perspectives. The results from MD simulation demonstrate that the polymeric surfactant can promote the disintegration of the remaining oil and enhance its mobility. The experimental results indicate that the sweep efficiency is restricted by viscous fingering and tongue advance. Through the analysis of mathematical models, the rising mobility ratio and the location of the displacing front have a strong positive relationship with viscous fingering and tongue advance, which can reasonably explain the plugging performance of the polymeric surfactant, greatly improving the sweeping effect of the whole reservoir. Moreover, the Marangoni effect generated by the IFT gradient can induce the transformation of interfacial energy to displacement kinetic energy by the emulsification of the oil-water interface so that the remaining oil in the blind-end pore can be effectively extracted. However, by comparing data from image quantification techniques and production dynamic performance, the sweep efficiency (484%) was significantly greater than that of oil recovery (300%), demonstrating that the expanded sweep effect still plays a dominant role in the extraction of remaining oil after polymeric surfactant flooding. This study provides a novel plugging and effective washing agent that is expected to be an excellent and comprehensive method for solving the problem of low oil recovery in multilayered heterogeneous reservoirs.

Study on CO2 and CH4 Competitive Adsorption in Shale Organic and Clay Porous Media from Molecular- to Pore-Scale Simulation

Summary The elucidation of the competitive adsorption behaviors between CO2 and CH4 holds great importance in the context of improving natural gas recovery in shale reservoirs. Shale rock, as a complex porous medium, exhibits a highly interconnected multiscale pore network with pore size spanning from several to tens of nanometers. Nevertheless, accurately capturing the adsorption effects and studying the CO2/CH4 competitive adsorption within a large-scale, realistic, 3D nanoporous matrix remains a significant challenge. In this paper, we proposed a novel lattice Boltzmann method (LBM) coupled molecular simulation to investigate CO2/CH4 competitive adsorption in 3D shale nanoporous media. The initial step involves conducting Grand Canonical Monte Carlo (GCMC) simulations to simulate the competitive adsorption behaviors of CO2 and CH4 in kerogen and illite slit pores, with the aim of obtaining the atomic density distribution. Subsequently, a Shan-Chen-based lattice Boltzmann (LB) simulation is used under identical conditions. By coupling the molecular simulation results, the fluid-solid interaction parameters are determined. Finally, LB simulations are performed in designed 3D porous media, utilizing the fluid-solid interaction parameters. The effects of mineral type, CO2 concentration, and pore structure on competitive adsorption behaviors are discussed carefully. Our research offers significant contributions to the improvement of gas recovery and carbon geological sequestration through the examination of CO2/CH4 competitive adsorption in nanoporous media. Additionally, it serves as a link between molecular and pore-scale phenomena by leveraging the benefits of both molecular simulations and pore-scale simulations.

Experimental investigation of the sequence injection effect of sea water and smart water into an offshore carbonate reservoir for enhanced oil recovery

This study explores enhanced oil recovery (EOR) strategies, with a focus on carbonate reservoirs constituting over 60% of global oil discoveries. While “smart water” injection proves effective in EOR for carbonate reservoirs, offshore application challenges arise due to impractical volumes for injection. To address this, we propose a novel continuous injection approach, systematically investigating it on a laboratory scale using the Iranian offshore reservoir, Sivand. Thirty-six contact angle tests and twelve flooding experiments are meticulously conducted, with key ions, potassium, and sulfate, playing pivotal roles. Optimal wettability alteration is observed at 4 times potassium ion concentration in 0–2 times sulfate concentrations, driven by ionic strength and charge interactions. Conversely, at 3–5 times sulfate concentrations, the optimal contact angle shifts to 2 times potassium ion concentration, suggesting a mechanism change linked to increasing sulfate ion ionicity. A significant wettability alteration, evidenced by a 132.8° decrease, occurs in seawater with a twofold concentration of potassium ions and a fivefold concentration of sulfate ions. Micromodel experiments introduce an innovative alternation of smart water and seawater injections. The first scenario, smart water followed by seawater injection, reveals negligible post-seawater injection oil recovery changes. In contrast, the second scenario yields a maximum recovery of 7.9%. The first scenario, however, boasts superior overall sweep efficacy, reaching approximately 43%. This research expands understanding of smart water and seawater injection in EOR, presenting a viable solution for optimizing offshore carbonate reservoir recovery. The insights contribute to evolving EOR methodologies, emphasizing tailored strategies for varying reservoir conditions.