Search Results (9)

Gas miscible flooding, especially CO₂ miscible flooding, is a key method for enhanced oil recovery. However, the high Minimum Miscibility Pressure (MMP) often makes true-miscible flooding impractical. A number of studies confirm the existence of a near-miscible region that also ensures high recovery. However, the exact boundary for near miscibility remains unclear, with various speculative definitions based on experimental data or by experience. In this work, a molecular-level understanding of miscibility and near miscibility and the role of the MMP reducer are achieved using the molecular dynamics method. It is found that the traditional criterion of interfacial tension being zero is not valid for the molecular dynamics method, and that the interaction energy between oil molecules suggests distinct boundary between near-miscibility and miscibility regimes. MMP reducers were found to bring the two regions closer in terms of energy, rather than actually reducing the MMP. Full article

Miscible gas flooding improves oil displacement through mass exchange between oil and gas phases. It is one of the most efficient enhanced oil recovery methods for intermediate density oil reservoirs. In this work, analytical solutions for saturation, concentration and pressure are derived for oil displacement by a partially miscible gas injection at a constant rate. The mathematical model considers two-phase, three-component fluid flow in a one-dimensional homogeneous reservoir initially saturated by a single oil phase. Phase saturations and component concentrations are described by a $2\times 2$ hyperbolic system of partial differential equations, which is solved by the method of characteristics. Once this Goursat–Riemann problem is solved, the pressure drop between two points in the porous media is obtained by the integration of Darcy’s law. The solution of this problem may present three different fluid regions depending on the rock–fluid parameters: a single-phase gas region near the injection point, followed by a two-phase region where mass transfer takes place and a single-phase oil region. We considered the single-phase gas and the two-phase gas/oil regions as incompressible, while the single-phase oil region may be incompressible or slightly compressible. The solutions derived in this work are applied for a specific set of rock and fluid properties. For this data set, the two-phase region displays rarefaction waves, shock waves and constant states. The pressure behavior depends on the physical model (incompressible, compressible and finite or infinite porous media). In all cases, the injection pressure is the result of the sum of two terms: one represents the effect of the mobility contrast between phases and the other represents the single-phase oil solution. The solutions obtained in this work are compared to an equivalent immiscible solution, which shows that the miscible displacement is more efficient. Full article

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. Full article

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. Full article

CO₂ flooding is a pivotal technique for significantly enhancing oil recovery in low-permeability reservoirs. The movement and sweeping rules at the front of CO₂ flooding play a critical role in oil recovery; yet, a comprehensive quantitative analysis remains an area in need of refinement. In this study, we developed 1-D and 2-D numerical simulation models to explore the sweeping behavior of miscible, immiscible, and partly miscible CO₂ flooding patterns. The front position and movement rules of the three CO₂ flooding patterns were determined. A novel approach to the contour area calculation method was introduced to quantitatively characterize the sweep coefficients, and the sweeping rules are discussed regarding the geological parameters, oil viscosity, and injection–production parameters. Furthermore, the Random Forest (RF) algorithm was employed to identify the controlling factor of the sweep coefficient, as determined through the use of out-of-bag (OOB) data permutation analysis. The results showed that the miscible front was located at the point of maximum CO₂ content in the oil phase. The immiscible front occurred at the point of maximum interfacial tension near the production well. Remarkably, the immiscible front moved at a faster rate compared with the miscible front. Geological parameters, including porosity, permeability, and reservoir thickness, significantly impacted the gravity segregation effect, thereby influencing the CO₂ sweep coefficient. Immiscible flooding exhibited the highest degree of gravity segregation, with a maximum gravity segregation degree (GSD) reaching 78.1. The permeability ratio was a crucial factor, with a lower limit of approximately 5.0 for reservoirs suitable for CO₂ flooding. Injection–production parameters also played a pivotal role in terms of the sweep coefficient. Decreased well spacing and increased gas injection rates were found to enhance sweep coefficients by suppressing gravity segregation. Additionally, higher gas injection rates could improve the miscibility degree of partly miscible flooding from 0.69 to 1.0. Oil viscosity proved to be a significant factor influencing the sweep coefficients, with high seepage resistance due to increasing oil viscosity dominating the miscible and partly miscible flooding patterns. Conversely, gravity segregation primarily governed the sweep coefficient in immiscible flooding. In terms of controlling factors, the permeability ratio emerged as a paramount influence, with a factor importance value (FI) reaching 1.04. The findings of this study can help for a better understanding of sweeping rules of CO₂ flooding and providing valuable insights for optimizing oil recovery strategies in the field applications of CO₂ flooding. Full article

Natural gas injection is considered for enhanced oil recovery (EOR) in a high saturation pressure reservoir in block B111 of the Dagang oilfield, China. To investigate the interaction characteristics of injected natural gas and crude oil, the ability for dissolution–diffusion and miscibility–extraction of natural gas in crude oil was tested using a piece of high-temperature and high-pressure PVT equipment. The physical properties and minimum miscible pressure (MMP) of the natural gas–crude oil system and their interaction during dynamic displacement were analyzed using the reservoir numerical simulation method. The results show the following: (1) Under static gas–oil contact conditions, natural gas has a significant dissolution–diffusion and miscibility–extraction effect on the crude oil in block B111, especially near the gas–oil interface. The content of condensate oil in gas phase is 10.14–18.53 wt%, while the content of dissolved gas in oil phase reaches 26.17–57.73 wt%; (2) Under the reservoir’s conditions, the saturated solubility of natural gas injected in crude oil is relatively small. The effect of swelling and viscosity reduction on crude oil is limited. As the pressure increases with more natural gas dissolved in crude oil, the phase state of crude oil can change from liquid to gas; accordingly, the density and viscosity of crude oil will be greatly reduced, presenting the characteristics of condensate gas; (3) The MMP of natural gas and crude oil is estimated to be larger than 40 MPa. It mainly forms a forward-contact evaporative gas drive in block B111. The miscible state depends on the maintenance level of formation pressure. The injected natural gas has a significant extraction effect on the medium and light components of crude oil. The content of C2–C15 in the gas phase at the gas drive front, as well as the content of CH₄ and C16+ in the residual oil at the gas drive trailing edge, will increase markedly. Accordingly, the residual oil density and viscosity will also increase. These results have certain guiding significance for understanding gas flooding mechanisms and designing gas injection in block B111. Full article

Low-permeability near-critical volatile reservoirs are characterized by light oil, complex fluid phase, and strong reservoir inhomogeneity, etc. Purely injecting CO₂ will create a series of problems, such as serious gas channeling, low sweep efficiency, and low oil recovery. Therefore, in this paper, through a combination of experiments and simulations and in the process of studying the problem from simple to complex, we carried out phase equilibrium experiments for CO₂-near-critical volatile oil and CO₂-near-critical volatile oil-formation water, as well as experiments for minimum miscible pressure of slim-tube with pure CO₂ and CO₂–water co-injection to the comparative study of the miscible characteristics and displacement oil efficiency between pure CO₂ injection and CO₂–water co-injection. It provides an important reference for improving oil recovery by CO₂–water co-injection in low-permeability near-critical volatile reservoir. The results of CO₂-near-critical volatile oil/CO₂-near-critical volatile oil-formation water phase equilibrium experiments show that the saturation pressure, density, and gas–oil ratio of the system increase, and the viscosity decreases with the increase in CO₂ injection. In the three-phase system of CO₂-near-critical volatile oil-formation water, the CO₂ content in the flash gas of crude oil, gas–oil ratio, and gas–water ratio are negatively correlated with the water saturation. The results of slim-tube experiments and simulations on the miscible characteristics and displacement oil efficiency of pure CO₂ injection and CO₂–water co-injection show that the recovery degree of crude oil under CO₂–water co-injection is higher than that of pure CO₂ injection, and the CO₂ dissolved transition section in oil and gas is shorter and the gas breakthrough time is later under CO₂–water co-injection, which effectively increases the sweep efficiency and improves the degree recovery of crude oil. When CO₂–water co-injection, the ratio of water is higher, the later the gas–oil ratio rises, the later the CO₂ breakthrough, and the higher the degree of crude oil recovery. It indicates that when CO₂–water co-injection, the ratio of water is higher, the more CO₂ is dissolved in water, which effectively inhibits the occurrence of gas channeling and increases the sweep area, thus improving the degree recovery of crude oil. The research results of this paper provide an experimental basis and theoretical foundation for CO₂–water co-injection for enhanced crude oil recovery in low-permeability near-critical volatile reservoirs. Full article

Water alternating gas (WAG) injection has been successfully applied as a tertiary recovery technique. Forecasting WAG flooding performance using fast and robust models is of great importance to attain a better understanding of the process, optimize the operational conditions, and avoid high-cost blind tests in laboratory or pilot scales. In this study, we introduce a novel correlation to determine the performance of the near-miscible WAG flooding in strongly water-wet sandstones. We conduct dimensional analysis with Buckingham’s $\pi$ theorem technique to generate dimensionless numbers using eight key parameters. Seven dimensionless numbers are employed as the input variables of the desired correlation for predicting the recovery factor of a near-miscible WAG injection. A verified mathematical model is used to generate the required training and testing data for the development of the correlation using a gene expression programming (GEP) algorithm. The provided data points are then separated into two subsets: training (67%) to develop the model and testing (33%) to assess the models’ capability. Conducting error analysis, statistical measures and graphical illustrations are provided to assess the effectiveness of the introduced model. The statistical analysis shows that the developed GEP-based correlation can generate target data with high precision such that the training phase leads to R² = 92.85% and MSE = 1.38 × 10⁻³ and R² = 91.93% and MSE = 4.30 × 10⁻³ are attained for the testing phase. The relative importance of the input dimensionless groups is also determined. According to the sensitivity analysis, decreasing the oil–water capillary number results in a significant reduction in RF in all cycles. Increasing the magnitudes of oil to gas viscosity ratio and oil to water viscosity ratio lowers the RF of each cycle. It is found that oil to gas viscosity ratio has a higher impact on RF value compared to oil to water viscosity ratio due to a higher viscosity gap between the gas and oil phases. It is expected that the GEP, as a fast and reliable tool, will be useful to find vital variables including relative permeability in complex transport phenomena such as three-phase flow in porous media. Full article

Miscible and near-miscible flooding are used to improve the performance of carbon-dioxide-enhanced oil recovery in heterogeneous porous media. However, knowledge of the effects of heterogeneous pore structure on CO₂/oil flow behavior under these two flooding conditions is insufficient. In this study, we construct pore-scale CO₂/oil flooding models for various flooding methods and comparatively analyze CO₂/oil flow behavior and oil recovery efficiency in heterogeneous porous media. The simulation results indicate that compared to immiscible flooding, near-miscible flooding can increase the CO₂ sweep area to some extent, but it is still inefficient to displace oil in small pore throats. For miscible flooding, although CO₂ still preferentially displaces oil through big throats, it may subsequently invade small pore throats. In order to substantially increase oil recovery efficiency, miscible flooding is the priority choice; however, the increase of CO₂ diffusivity has little effect on oil recovery enhancement. For immiscible and near-miscible flooding, CO₂ injection velocity needs to be optimized. High CO₂ injection velocity can speed up the oil recovery process while maintaining equivalent oil recovery efficiency for immiscible flooding, and low CO₂ injection velocity may be beneficial to further enhancing oil recovery efficiency under near-miscible conditions. Full article