CO2 Miscible Flooding Research Articles

Nanoconfinement effect on the miscible behaviors of CO2/shale oil/surfactant systems in nanopores: Implications for CO2 sequestration and enhanced oil recovery

Currently, CO2 flooding is the most promising carbon capture, utilization, and storage (CCUS) technology in the energy industry. Understanding the nanoconfinement effect on the CO2-oil miscible process is crucial for accurately determining the minimum miscibility pressure (MMP) of CO2/oil in shale reservoirs. In this study, we conducted molecular dynamics (MD) simulations to investigate the effects of pore size, surfactants, and pore type on the MMP of nanoconfined CO2/shale oil/surfactant systems. Validations against experimental data show a deviation of 2.98 % in the CO2 MMP. The MMPs under nanoconfinement are found to be significantly lower than those in bulk phase conditions (up to 22.94 %). The simulation results reveal that decreasing pore size can enhance the miscibility of CO2 and oil by increasing the CO2 adsorption ratio, improving CO2-surfactant interactions, and inhibiting the tendency of CO2 molecules to self-aggregate. The enhancement of CO2-oil miscibility caused by surfactants is ranked by CFP > SF > SDS according to the mixing degrees (Dmix) and the spatial distribution of CO2 around surfactant molecules. In addition, pore type exhibits various abilities in influencing the MMP, owing to their different mineral surface properties and ability to influence CO2-surfactant interactions. Nanopores with stronger hydrophobicity and a denser CO2 distribution around surfactant molecules have lower MMPs. The results show that the order of MMP in terms of pore types is Quartz < Kaolinite < I/M clay. This study elaborates the micro-mechanisms of surfactant-assisted CO2-oil miscibility under nanoconfinement, offering valuable insights for effectively designing CO2 miscible flooding in shale oil reservoir development.

Experimental study on the mass transfer and microscopic distribution characteristics of remaining oil and CO2 during water-miscible CO2 flooding

Accurate understanding and quantitative characterization of the microscopic distribution and mobilization mechanisms of remaining oil are crucial for further enhancing oil recovery during CO2 flooding. In this study, miscible CO2 flooding experiments after water flooding were performed to investigate the mass transfer and microscopic distribution characteristics of remaining oil and CO2 using micro-computed tomography technique. Additionally, the distribution characteristics of multiphase fluids (oil, water and CO2) in the pores were comprehensively investigated. Furthermore, the mass transfer effects during the miscible CO2 flooding process, as well as the CO2 sequestration ratio (SR) and sequestration factor (SF) were systematically examined. The experimental results show that the ultimate oil recovery factor after miscible CO2 flooding were 80.9 %, 70.7 %, and 64.7 %, respectively. During the water flooding stage, the produced oil mainly consisted of light hydrocarbons (C5–C16), followed by medium hydrocarbons (C17–C27). The remaining oil was mainly in cluster and network pattern, followed by multiple and oil film pattern. After miscible CO2 flooding, the produced gas mainly consisted of CO2 and CH4, with a significant increase in the mass fraction of light hydrocarbons (C5–C16) in the produced oil. The remaining oil was mainly in multiple and singlet pattern, followed by network and film pattern, with a small portion in cluster pattern. The higher the displacement rate, the smaller the SR, but most of the injected CO2 (SR > 70 %) was retained in the porous media, demonstrating the feasibility of CO2 geological sequestration during the miscible flooding process.

Experimental study on immiscible and miscible dynamic characteristics of CO2 and crude oil in visual slim tube

CO2 flooding for oil recovery is a dynamic process that requires further investigation of oil-gas interface change characteristics, interfacial mass transfer processes, and oil-gas composition variation during both immiscible and miscible displacement. Understanding these factors is crucial for better comprehending their impact on CO2-enhanced oil recovery (EOR). This research used a jointly developed CO2 miscible visual flooding experimental apparatus to study the horizontal dynamic characteristics of CO2 and crude oil under different pressures and flow rates in visual slim tube. At 10 MPa, the stratification results of CO2 and crude oil indicate that the experiment is immiscible flooding. The contact angle (7.9°) between the two phases of CO2 and crude oil at the flow rate of 15 cm/min is larger than that (5.2°) at 1.5 cm/min, and the grey scale of CO2 increases at 100 cm/min. The quantity, individual content, and shape of the light and medium hydrocarbon components condensed on the inner wall of the tube vary with different flow rates. At 15 MPa, the appearance of the CO2 and crude oil transition interval proves that the experiment is miscible flooding. At different flow rates, the inclination angle and distribution of black stripes vary. The whole transition interval is divided into 6 intervals, and the transition interval lengthens with increasing fluid velocity. The experiments visually demonstrate the occurrence of the miscible phase, and identify experimental pressure and fluid flow rate as key factors influencing the miscibility of CO2 and crude oil.

Characteristics and Mechanisms of CO2 Flooding with Varying Degrees of Miscibility in Reservoirs Composed of Low-Permeability Conglomerate Formations

The reservoir type of the MH oil field in the Junggar Basin is a typical low-permeability conglomerate reservoir. The MH oilfield was developed by water injection in the early stage. Nowadays, the reservoir damage is serious, and water injection is difficult. There is an urgent need to carry out conversion injection flooding research to improve oil recovery. The use of CO2 oil-flooding technology can effectively supplement formation energy, reduce greenhouse gas emissions, and improve economic benefits. In order to clarify the feasibility of CO2 flooding to improve oil recovery in conglomerate reservoirs with low permeability, strong water sensitivity, and severe heterogeneity, this paper researched the impact of CO2 miscibility on production characteristics and mechanisms through multi-scale experiments. The aim was to determine the feasibility of using CO2 flooding to enhance oil recovery. This study initially elucidated the oil displacement characteristics of varying degrees of miscibility in different dimensions using slim tube experiments and long core experiments. Subsequently, mechanistic research was conducted, focusing on the produced oil components, changes in interfacial tension, and conditions for pore mobilization. The results indicate that the minimum miscibility pressure (MMP) of the block is 24 MPa. Under the slim tube scale, the increase in the degree of miscibility can effectively delay the gas breakthrough time; under the core scale, once the pressure reaches the near mixing phase, the drive state can transition from a non-mixed “closed-seal” to a “mixed-phase” state. Compared to the immiscible phase, the near-miscible and completely miscible phase can improve the final recovery efficiency by 9.27% and 18.72%. The component differences in the displacement products are mainly concentrated in the high-yield stage and gas breakthrough stage. During the high-yield stage, an increase in miscibility leads to a higher proportion of heavy components in the produced material. Conversely, in the gas breakthrough stage, extraction increases as the level of mixing increases, demonstrating the distinct extracting characteristics of different degrees of mixed phases. The core experiences significant variations in oil saturation mostly during the pre-gas stage. CO2 miscible flooding can effectively utilize crude oil in tiny and medium-sized pores during the middle stage of flooding, hence reducing the minimum threshold for pore utilization to 0.3 μm.

A new empirical correlation of MMP prediction for oil – impure CO2 systems

CO2 flooding is a widely-used technique for enhancing oil production, with miscible CO2 flooding exhibiting higher recovery potential compared to both immiscible and near-miscible CO2 flooding. However, the problem of insufficient CO2 supply is increasingly critical in many reservoirs. When faced with a shortage of gas supply, the key to the successful implementation of miscible CO2 flooding lies in accurately predicting the MMP of impure CO2. This study leverages MMP data derived from both experimental and simulation results, utilizing both linear and nonlinear regression methodologies to formulate empirical correlations for MMP prediction. In addition, ridge regression is used to solve collinearity problem.Compared with former investigations, the impure CO2 correlation proposed in this study integrates the ratio of the specific injection gas mole fraction to the crude oil mole fraction as novel independent variables. This inclusion reflects the actual interaction between the specific injection gas and crude oil during the miscibility process. Furthermore, the correlation can be linearized to the greatest extent through this way and such linearization illustrates the fundamental concepts more distinctly, offering a more practical and comprehensible approach. This formula combines the prediction of the minimum miscible pressure with the interaction mechanism of the miscible process, and the dominant factors in the miscible process can be determined. In terms of reducing the minimum miscible pressure, the interaction between C4 + C5 in the injected gas and C1 + N2 in the crude oil component is the strongest, while the interaction between N2 in the injected gas and C2-6 in the crude oil was most significant in increasing the minimum miscible pressure by comparison.The correlations presented for impure CO2 yield an average absolute deviation of 2.18 % and sustain a relative deviation within ± 10 %, surpassing previously published correlations. This study highlights the accuracy and effectiveness of the developed correlations for estimating MMP for impure CO2. The suggested MMP correlation offers a practical and efficient means of determining MMP for the implementation of impure CO2 miscible flooding in the field.

The characteristics of produced oils in the miscible CO2 displacement process

CO2 flooding is an effective technique for enhancing oil recovery by changing the hydrocarbon fluid’s characteristics. One of the fundamental mechanisms of the interaction between CO2 and hydrocarbon fluid by miscible CO2 injection is the extraction phenomenon of the hydrocarbon components by CO2. It results in altered produced and residual oil characteristics. This study aims to examine the characterizations of produced oil during the process of CO2 displacement. It is critical to anticipate any issues that can arise from miscible CO2 flooding, such as asphaltene deposition. A light-dead oil sample from an Indonesian oil field was used in this investigation. The miscible CO2 displacement process was conducted by a slim tube experiment at operating temperature of 90°C and 70°C, which represents the reservoir and surface temperature, respectively. The properties of produced oil were further characterized by analyzing the composition based on its polarity, including saturate, aromatic, resin, and asphaltene. The results show that increasing injection pressures decrease resin and asphaltene fractions in produced oil. Furthermore, the proportions of asphaltene and resin fractions in the crude sample exhibit a significant decrease when conducted at a lower temperature in comparison to when carried out at a higher temperature. This study helps to explain how the displacement process by CO2 affects the properties of the produced oil.

Analyzing the Microscopic Production Characteristics of CO2 Flooding after Water Flooding in Tight Oil Sandstone Reservoirs Utilizing NMR and Microscopic Visualization Apparatus

The microscopic pore structure of tight sandstone reservoirs significantly influences the characteristics of CO2 flooding after water flooding. This research was conducted using various techniques such as casting thin sections, high-pressure mercury injection, scanning electron microscopy, nuclear magnetic resonance (NMR) testing, and a self-designed high-temperature and high-pressure microscopic visualization displacement system. Three types of cores with different pore structures were selected for the flooding experiments and the microscopic visualization displacement experiments, including CO2 immiscible flooding, near-miscible flooding, and miscible flooding after conventional water flooding. The characteristics of CO2 flooding and the residual oil distribution after water flooding were quantitatively analyzed and evaluated. The results show the following: (1) During the water flooding process, the oil produced from type I and type III samples mainly comes from large and some medium pores. Oil utilization of all pores is significant for type II samples. The physical properties and pore types have a greater impact on water flooding. Type I and II samples are more suitable for near-miscible flooding after water flooding. Type III samples are more suitable for miscible flooding after water flooding. (2) In CO2 flooding, oil recovery increases gradually with increasing pressure for all three types of samples. Type II core samples have the highest recovery. Before miscibility, the oil recovered from type I and type II samples is primarily from large pores; however, oil recovery mainly comes from medium pores when reaching miscibility. As for the type III samples, the oil produced in the immiscible state mainly comes from large and medium pores, and the enhanced oil recovery mainly comes from medium and small pores after reaching the near-miscible phase. (3) It can be seen from the microscopic residual oil distribution that oil recovery will increase as the petrophysical properties of the rock model improve. The oil recovery rate of near-miscible flooding after water flooding using the type II model is up to 68.11%. The oil recovery of miscible flooding after water flooding with the type III model is the highest at 74.57%. With increasing pressure, the proportion of flake residual oil gradually decreases, while the proportion of droplet-like and film-like residual oil gradually increases. Type II samples have a relatively large percentage of reticulated residual oil in the near-miscible stage.

Comprehensive Review of the Determination and Reduction of the Minimum Miscibility Pressure during CO2 Flooding.

With the increasing oil demand, more attention has been paid to enhancing oil recovery in old oil fields. CO2 flooding is popular due to its high oil displacement efficiency and ability to reduce greenhouse gas emissions. Laboratory experiments and on-site application cases have shown that the minimum miscibility pressure has a greater impact on CO2 flooding than other factors. If the reservoir pressure is below the minimum miscible pressure, then there is CO2 immiscible flooding. Both theoretical analysis and experimental results show that the recovery rate of CO2 miscible flooding is 2-5 times higher than that of immiscible flooding. If the reservoir pressure is increased by water flooding before CO2 injection, it is easily limited by the physical property parameters. Therefore, accurately determining and effectively reducing the minimum mixing pressure has become the focus of research. Currently, there are two types of methods for determining the minimum miscible pressure: experimental and theoretical methods. The experimental method is generally considered more accurate, including the slim tube test, rising bubble apparatus, and vanishing interfacial tension, etc. However, it is worth noting that the minimum miscibility pressure is dynamically changing, and there will be high economic costs if measured repeatedly through experimental methods during reservoir development. Therefore, it is recognized that the minimum mixing pressure can be determined at any time using theoretical calculation of initial data, which will reduce economic and time costs to a high degree. In this paper, the theoretical calculation method is divided into empirical correlation, state equation, and artificial intelligence algorithm. The techniques for reducing the minimum miscibility pressure can be classified into two categories: miscible solvents and surfactant methods. The miscible solvent method can be further divided into monocomponent and polycomponent methods. This paper compares the advantages and disadvantages of the existing techniques for measuring and reducing MMP and selects the best method.

New models for estimating minimum miscibility pressure of pure and impure carbon dioxide using artificial intelligence techniques

CO2 miscible flooding stands out as one of the most-commonly employed and promising processes in enhanced oil recovery. The key factor for ensuring success in designing and executing CO2 injection projects lies in the precise determination of the Minimum Miscibility Pressure (MMP). Despite significant research endeavors in measuring and predicting the MMP through the use of empirical, analytical, numerical, and experimental approaches, the need for a comprehensive, accurate, efficient, and easy-to-use model remains. In response to this gap, our study developed various predictive models with 205 datasets, including well-established ones such as Artificial Neural Network (ANN), Random Forest (RF), and K-Nearest Neighbors (KNN) along with employing the Gradient Boosting Algorithm (GBA) with the Grid Search (GS) as a novel approach to predict the MMP of both pure and impure CO2. The performance of these models was validated by comparing them with previously published models, using relevant performance metrics such as R2 (coefficient of determination) and MAPE (mean absolute percentage error). Our results demonstrated that the GBA model with GS optimization exhibited remarkable superiority in terms of performance and accuracy in both scenarios, outperforming previously published models as well as the developed ANN, RF, and KNN models. For pure CO2, it achieved an impressive R2 value of 0.999 on the training set and a relatively high value of 0.910 on the validation set. Additionally, the model showed remarkably low MAPE values of 0.0705 % on the training set and 9.238 % on the validation set. Similarly, for impure CO2, the GBA model with GS optimization achieved an R2 value of 0.999 on the training set and a relatively high value of 0.865 on the validation set. The model also exhibited low MAPE values of 1.66 % on the training set and 6.798 % on the validation set. These findings highlight the potential of the GBA model with GS optimization as a valuable approach for accurately estimating the MMP, offering a cost-effective and efficient approach for designing and optimizing CO2 flooding operations in enhanced oil recovery processes.

Assisted Upscaling of Miscible CO2-Enhanced Oil Recovery Floods Using an Artificial Neural Network-Based Optimisation Algorithm

Due to the high computing cost of the fine-scale compositional simulations needed to effectively model miscible CO2 flooding, upscaling techniques are needed to approximate the behaviour of these fine-scale grids on more realistic coarse-scale models. The use of transport coefficients to better represent small-scale interactions, such as the time-dependent flux of the components within the hydrocarbon phases (molecular diffusion), and the pseudoisation of relative permeabilities to ensure the matching of large-scale effects, such as the volumetric fluxes of the phases, are two of these procedures. Most times, a mismatch between the phase fluxes of the integrated fine-scale and that of the coarse-scale is observed. By adjusting or calibrating some of the generated coarse-scale pseudo functions, such as the transport coefficients, absolute permeability, or relative permeability endpoints, the accuracy of the upscaling results can be improved. This procedure can be treated a reservoir history matching problem which is typically computationally expensive. In this study, we provide a framework for representing the dynamics of small-scale molecular diffusion and macro-scale heterogeneity-induced channelling related to miscible CO2 displacements on upscaled coarser grid reservoir models. The method used was based on the pseudoisation of relative permeability and transport coefficients and was applied to two benchmark reservoir models from the Society of Petroleum Engineers (SPE). Our results demonstrated that using effectively calibrated transport coefficients improved the upscaling results, so that the calculated pseudo-relative permeability functions can be ignored. We proposed a unique approach to upscaling miscible floods that utilised a genetic algorithm and a neural-network-based proxy model to minimise the associated computing cost. The data-driven approximation model considerably decreased the computing cost associated with the assisted tuning technique, and the optimisation algorithm was used to reduce the error between the predictions of the upscaled models. In conclusion, the methodology described in this study effectively captured the small- and large-scale behaviour related to the miscible displacements on upscaled coarse-scale reservoir models while reduced associated computational costs.

Investigation on the flow behavior and mechanisms of water flooding and CO2 immiscible / miscible flooding in shale oil reservoirs

Shale reservoirs represent a significant untapped source of recoverable oil, and even a slight increase in recovery can yield substantial benefits. In recent years, there has been a growing interest in the development of shale reservoirs due to their vast potential. Shale reservoirs are characterized by their intricate pore structures, ultra-low porosity, and extremely low permeability. Consequently, fluid flow within shale formations is highly complex, and the distribution of shale oil is diverse. There is an urgent need to conduct research into the flow behavior of shale reservoirs and the modes of crude oil occurrence within them, in order to support effective shale oil extraction in the field. In this work, we established a MCMP-MRT-LBM model considering nano-scale confinement effects such as slip and adsorption. The model is employed to simulate single pore channels and blind-end pores to investigate the distinct mechanisms involved in water flooding, CO2 immiscible flooding, and CO2 miscible flooding. Subsequently, the research explores the fluid flow characteristics associated with these three development methods within porous media, as well as the distribution of remaining oil. Then we compared the oil displacement efficiency, swept volume, actual liquid injection volume and displacement front position of the three fluids in porous media. The results reveal that water flooding exhibits superior displacement performance in single pore channels, while CO2 miscible flooding proves to be the most effective method for exploiting oil in blind-end pores. In porous media, CO2 miscible flooding successfully mitigates fingering phenomena and efficiently recovers crude oil located at blind-end and corner regions of the pores. The recovery efficiency achieved through CO2 miscible flooding is approximately 30% higher than that of water flooding and about 10% greater than CO2 immiscible flooding.

Visualization of CO2-oil vanishing interface to determine minimum miscibility pressure using microfluidics

The determination of the minimum miscibility pressure (MMP) assumes paramount significance in evaluating CO2 enhanced-oil recovery strategies. We created a microfluidic method for determining the MMP of CO2 and oil samples by integrating the direct observation of the vanishing interface and the analysis of fluorescence intensity exhibited by oil samples. A microfluidic chip is designed with closed-end microchannels to mimic the blind-end fractures which contributes to reveal the complete picture of residual oil mobilization during CO2 miscible flooding. The maximum deviation of 3.83 % and 5.47 % unequivocally attested to the accuracy of our method by comparing measured MMPs with those reported in the literature and theoretically calculated in this study. The effects of alkane types, temperature and oil compositions on MMP was investigated. The MMPs for binary synthetic oils (C8 + C14) increased non-linearly with contents of tetradecane and increased significantly at C14 > 75 vol%. MMPs of nine n-alkanes, seven binary synthetic oils, four ternary synthetic oils and kerosene were provided reliably as the unprecedented new data. Such unique advantages as in-situ visualization, chip pattern customizability, user-independence, and the clear criterion render this research highly valuable for determining the MMP as well as elucidating the microscopic mechanisms underlying residual oil mobilization.

Numerical analysis of water-alternating-CO2 flooding for CO2-EOR and storage projects in residual oil zones

Residual oil zones (ROZs) have high residual oil saturation, which can be produced using CO2 miscible flooding. At the same time, these zones are good candidates for CO2 sequestration. To evaluate the coupled CO2-EOR and storage performance in ROZs for Water-Alternating-CO2 (WAG) flooding, a multi-compositional CO2 miscible model with molecular diffusion was developed. The effects of formation parameters (porosity, permeability, temperature), operation parameters (bottom hole pressure, WAG ratio, pore volume of injected water), and diffusion coefficient on the coupled CO2-EOR and storage were investigated. Five points from the CO2 sequestration curve and the oil recovery factor curve were selected to help better analyze coupled CO2-EOR and storage. The results demonstrate that enhanced performance is observed when formation permeability is higher and a larger volume of water is injected. On the other hand, the performance diminishes with increasing porosity, molecular diffusion of gas, and the WAG ratio. When the temperature is around 100 °C, coupled CO2-EOR and storage performance is the worst. To achieve optimal miscible flooding, it is recommended to maintain the bottom hole pressure (BHP) of the injection well above 1.2 minimum miscibility pressure (MMP), while ensuring that the BHP of the production well remains sufficiently high. Furthermore, the tapered WAG flooding strategy proves to be profitable for enhanced oil recovery, as compared to a WAG ratio of 0.5:1, although it may not be as effective for CO2 sequestration.

Investigation of the Influence of Formation Water on the Efficiency of CO2 Miscible Flooding at the Core Scale

This study investigated the impact of formation water on the mass transfer between CO2 and crude oil in low-permeability reservoirs through CO2 miscible flooding. Formation water leads to water blocks, which affect the effectiveness of CO2 miscible flooding. Therefore, we studied the impact and mechanisms of formation water on the CO2-oil miscibility. The microscale interaction between formation water-CO2-core samples was investigated using CT scanning technology to analyze its influence on core permeability parameters. In addition, CO2 miscible flooding experiments were conducted using the core displacement method to determine the effects of formation water salinity and average water saturation on minimum miscibility pressure (MMP) and oil displacement efficiency. The CT scanning results indicate that high-salinity formation water leads to a decrease in the porosity and permeability of the core as well as pore and throat sizes under miscible pressure conditions. The experimental results of CO2 miscible flooding demonstrate that CO2-oil MMP decreases as the salinity of the formation water increases. Moreover, as the average water saturation in the core increases, the water block effect strengthens, resulting in an increase in MMP. The recovery factors of cores with average water saturations of 30%, 45%, and 60% are 89.8%, 88.6%, and 87.5%, respectively, indicating that the water block effect lowers the oil displacement efficiency and miscibility.

Oscillating electric field-induced water blocking breakthrough to facilitate CO2 miscible flooding

CO2 miscible flooding is a great promising enhanced oil recovery (EOR) method. However, the loss of fracturing fluid in the formation causes water blocking that seriously impedes the realisation of CO2 miscible flooding. To solve this problem, a strategy of applying an oscillating electric field to promote CO2 breaking through water blocking and enhance the miscibility of CO2 and oil is proposed. The electric field with the frequency of 12 THz can maximise the breakthrough efficiency of water blocking, while the 16 THz electric field is most conducive to the miscibility of CO2 and oil. Under the 12 THz oscillating electric field, the prompt destruction of the local hydrogen bonds in water blocking results in the fastest breakthrough of water blocking. However, the expansion of water blocking hinders the miscibility of CO2 and oil to some extent. 16 THz oscillating electric field can induce the electric resonance of hydrogen bonds between water molecules, uniformly breaking hydrogen bonds to the greatest extent. Compared to that under the 12 THz electric field, the miscibility of CO2 and oil under the 16 THz electric field is enhanced due to the reduced expansion of water blocking.

Effect of water saturation on CO2 minimum miscibility pressure and oil displacement performance

The CO2 miscible flooding is an effective technology for development of low permeability reservoirs due to high oil displacement efficiency. However, CO2 miscible flooding for tertiary recovery technology typically occur after water flooding. Water hindered the contact and mass transfer of CO2 and oil, produce water resistance effect. Water can block CO2 and contact and mass transfer of crude oil (ie water blocking effect). The impact of this effect on the miscibility pressure and oil displacement effect is still unclear. In this study, homogeneous artificial cores with the same permeability as the reservoir were designed according to the miscible mechanism. Subsequently, the minimum miscibility pressure(MMP) between CO2 and crude oil at different water saturation was measured by the coreflood test. Based on the MMP, CO2 miscible flooding experiments were conducted by natural cores at different water saturation. The results showed that when the water saturation was 30%, 45%, and 60%, respectively, the corresponding MMP between CO2 and crude oil was 18.56, 19.48, and 21.76 MPa. The higher the water saturation, the longer the gas breakthrough time. But the oil recovery factor did not rise with the increase of water saturation. When the water saturation was 45%, the oil recovery factor in the miscible flooding experiment was the highest. In addition, the higher the water saturation, the weaker the CO2 extraction of various components in the crude oil. And the light components below C5 were most affected by water saturation. The mechanisms underlying these results are discussed. This study contributes to the development of CO2 miscible flooding reservoir plan.

Study on Enhanced Oil Recovery Mechanism of CO2 Miscible Flooding in Heterogeneous Reservoirs under Different Injection Methods.

The mechanism by which oil recovery can be enhanced by different injection methods of CO2 miscible flooding to alleviate the influence of heterogeneous reservoirs was studied to optimize the injection methods, further improving oil recovery. According to the reservoir heterogeneity characteristics of the TI oil formation group in Lunnan Oilfield, a 1 m double-layer long core was designed and prepared for four CO2 miscible displacement experiments with different injection methods. By analyzing the variation in the injection-production parameters, the displacement effects of different injection methods were compared, and the mechanism of enhanced oil recovery (EOR) was summarized. The results indicate the following. ① The displacement efficiency of the different injection methods lies in the following order. Alternate CO2-water injection, continuous CO2 flooding, cyclic CO2 flooding, and alternate CO2-hydrocarbon gas injection. ② The recovery of crude oil via CO2 miscible flooding in heterogeneous reservoirs relies on both convective diffusion and miscible mass transfer. Convective diffusion depends mainly on control of the displacement pressure differential and the plugging of preferential seepage channels in high-permeability areas, while miscible mass transfer depends mainly on the swept range of the convective diffusion and the degree of miscibility between CO2 and crude oil. ③ To improve the recovery efficiency of CO2 miscible flooding in heterogeneous reservoirs, it is necessary to choose an injection method that optimizes these two aspects.

Impact of water on miscibility characteristics of the CO2/n-hexadecane system using the pendant drop shape analysis method

Miscible CO2 flooding has shown bright prospects for improving oil recovery from unconventional reservoirs as well as for storing greenhouse gas in underground formations. Although the favorable water presence effect has been reported in the near miscible CO2 flooding practices, there is still a lack of target research works on the impact of water on the miscibility characteristics of the oil/gas systems. Therefore in this paper, the effect of water presence on the Minimum Miscibility Pressure (MMP) of the CO2/n-Hexadecane (n-C16H34) system is experimentally investigated based on the Oil Droplet Volume Measurement (ODVM) method. By pre-saturating CO2 with water in the high-pressure high-temperature cell, the water component is introduced at the CO2/oil interface. Measurement results show the water presence could result in lower MMPs of the CO2/oil system. Under five temperature levels of 40 °C, 51 °C, 61 °C, 72 °C, and 82 °C, the water presence decreases the MMPs of the CO2/n-C16H34 system from 8.2 to 7.8 MPa, from 9.6 to 8.8 MPa, from 11.6 to 10.2 MPa, from 13.0 MPa to 12.2 MPa and from 14.6 MPa to 13.2 MPa respectively. Thermodynamic calculations provide consistent results as the experimental observations, indicating the main mechanism behind the lower MMPs of the water presence CO2/oil system could be the decreased CO2 molar fraction in the water presence system. This research is expected to provide an innovative viewpoint to understand the water presence effect in the CO2 flooding processes.

Key parameters and dominant EOR mechanism of CO2 miscible flooding applied in low-permeability oil reservoirs

CO2 miscible flooding is a prospective production method to enhance oil recovery (EOR), especially in low-permeability reservoirs. However, there is a lack of comprehensive and systematic understanding of the key parameters and dominant EOR mechanism of CO2 miscible flooding. In this work, the sensitivity of key parameters, such as oil viscosity, permeability, permeability ratio, and pressure, is analyzed by CO2 flooding physical simulation experiments. The adjuvants for CO2 miscible flooding of the Changqing crude oils are evaluated and optimized. The production performance of overpressure CO2 miscible flooding is studied by CO2 core flood test, and the oil micro-distribution before and after CO2 miscible flooding is characterized using nuclear magnetic resonance (NMR), and the micro EOR mechanism of CO2 miscible flooding is revealed. The results show that CO2 immiscible flooding is suitable for the development of low-viscosity crude oil (<50 mPa s), especially for oil viscosity of less than 10 mPa s. CO2 miscible flooding is advisable for low-permeability and medium and high-permeability reservoirs, especially for reservoir permeability of higher than 10 mD. Above the MMP, the oil recovery factor is over 85% and the increase rate slows down with pressure, CO2 miscible flooding is preferred for the high-pressure reservoir. CO2 miscible flooding is applicable for reservoirs with a permeability ratio of less than 2.5, especially for a permeability ratio of less than 2. Compared with 0.8 times MMP pure CO2 flooding, the time of gas channeling, and oil recovery for CO2 miscible flooding is delayed from 0.69 PV to 0.76 PV, and enhanced to 93.04% from 72.61%, respectively, with the help of adjuvants for CO2 miscible flooding, NP-9. The adjuvants for CO2 miscible flooding could effectively promote the realization of miscible flooding for CO2 and crude oils with an injection pressure of less than the MMP. CO2 has excellent oil displacement ability in low-permeability reservoirs, especially for miscible flooding, and the core oil saturation is obviously reduced. Overpressure CO2 miscible flooding could expand the swept volume and more efficiently displace oil in low-permeability reservoirs compared to an injection pressure of 1.0 times MMP. After overpressure CO2 miscible flooding, the residual oil in the low-permeability cores is distributed more evenly.

Simulation of Microscopic Seepage Characteristics of Interphase Mass Transfer in CO2 Miscible Flooding under Multiphysics Field Coupling Conditions.

CO2 miscible flooding in low permeability reservoirs is conducive to significantly improving oil recovery. At present, the microscopic displacement simulation of CO2 miscible flooding is mainly reflected in the simulation of the seepage process, but the pressure control of the seepage process is lacking, and the simulation of the characterization of CO2 concentration diffusion is less studied. In view of the above problems, a numerical model of CO2 miscible flooding is established, and the microscopic seepage characteristics of interphase mass transfer in CO2 miscible flooding are analyzed by multiphysics field coupling simulations at the two-dimensional pore scale. The injection velocity, contact angle, diffusion coefficient, and initial injection concentration are selected to analyze their effects on the microscopic seepage characteristics of CO2 miscible flooding and the concentration distribution in the process of CO2 diffusion. The research shows that after injection into the model, CO2 preferentially diffuses into the large pore space and forms a miscible area with crude oil through interphase mass transfer, and the miscible area expands continuously and is pushed to the outlet by the high CO2 concentration area. The increase in injection velocity will accelerate the seepage process of CO2 miscible displacement, which will increase the sweep area at the same time. The increase in contact angle increases the seepage resistance of CO2 and weakens the interphase mass transfer with crude oil, resulting in a gradual decrease in the final recovery efficiency. When the diffusion coefficient increases, the CO2 concentration in the small pores and the parts that are difficult to reach at the model edge will gradually increase. The larger the initial injection concentration is, the larger the CO2 concentration in the large pore and miscible areas in the sweep region at the same time. This study has guiding significance for the field to further understand the microscopic seepage characteristics of CO2 miscible flooding under the effect of interphase mass transfer.