Immiscible CO2 Research Articles

Pore-scale numerical modeling of relative permeability curves for CO2\u2013oil fluid system with an application in immiscible CO2 flooding

CO2 injection is considered as one of the proven EOR methods and is being widely used nowadays in many EOR projects all over the globe. The process of in situ displacement of oil with CO2 gas is implemented in both miscible and immiscible modes of operation. In some oil reservoirs, CO2 miscibility will not be attained due to fluid composition characteristics as well as in situ pressure and temperature conditions. Laboratory determination of gas–oil relative permeability curves is usually performed with air, nitrogen, or helium gases, and the results are then implemented for both natural depletion processes (especially in reservoirs with “solution gas” or “gas cap” drive mechanisms) and gas injection processes. For the gas injection processes, it is therefore necessary to find out how selection of the gas phase would affect the relative permeability curves when the intention of developing the curves is to use them for immiscible CO2 displacement. In this study, a reservoir simulator was first used to quantitatively analyze the effect of variation in relative permeability data (due to the use of different gas phases) on production performance of a reservoir. Then, computational analysis was performed on changes in relative permeability curves upon using different gas phases with the aid of pore-scale modeling using statistical methods. To predict gas–oil relative permeability curves, a Shan–Chen-type multi-component multiphase Lattice Boltzmann pore-scale model for two-phase flow in a 2D porous medium was developed. Fully periodic and “full-way” bounce-back boundary conditions were applied in the model to get infinite domain of fluid with nonslip solid nodes. Incorporation of an external body force was performed by Guo scheme, and the influence of pore structure and capillary number on relative permeability curves was also studied for CO2–oil as well as N2–oil fluid pairs. The modeled relative permeability curves were then compared with experimental results for both these fluid pairs.

Visualization of asphaltene deposition effects on porosity and permeability during CO2 flooding in porous media

In the present study, three types of experiments on immiscible CO2 flooding in porous media were conducted and high-resolution images of asphaltene precipitation obtained using X-ray micro-CT scanner. It was found that the effective oil mobility is reduced due to the adsorption of deposited asphaltene onto the rock which blocks the pore throats, whereby the formation wettability is changed and both the effective porosity and permeability are reduced. The deposited asphaltene cannot be redissolved or displaced by the reinjected crude oil, and the formation damage is irreversible. In addition, the porosity-based permeability model was applied to study the effective permeability reduction that results from porosity reduction. The porosity-based permeability was calculated based on the Kozeny–Carman equation and experimental data. The effective permeability variation rate obtained by the porosity-based permeability model agreed well with the results obtained by Darcy’s law, which demonstrates that the method is feasible in evaluating the effective permeability variation rate based on the porosity of the cores acquired from micro-CT images.

Investigation of immiscible CO2 and C1 injection and comparison with water injection for enhanced oil recovery in naturally fractured reservoirs

ABSTRACTReservoir oil and gas content tends to rise up to the surface as long as their potential energy levels are sufficient. In order to amplify this energy, either during the time when oil is uprising on its inherent energy or since after, so as to facilitate the traveling of oil to the surface, enhanced oil recovery (EOR) methods come into play. Furthermore, the increasing demand for oil from one hand, and the shrinkage of producible reserves on the other hand, have made it unavoidable to undertake EOR techniques. Built in this research was a 10-element model of reservoir fluid to simulate its behavior. Furthermore, slim tube simulation was undertaken to determine minimum miscibility pressure for various gases. Then, different scenarios of natural depletion, CO2 injection, methane injection, and water injection were simulated by ECLIPSE 300 software package with the results of different scenarios compared. The results indicated water injection to be associated with higher recovery factor.

Characterization of Produced and Residual Oils in the CO2 Flooding Process

In immiscible CO2 flooding processes, the injected CO2 extracts light and intermediate components from reservoir hydrocarbons, changing the properties of both the produced and residual oils. CO2 injection also increases asphaltene precipitation, which further causes adverse effects on the oil effective permeability, operational facilities, and the oil recovery. In this study, six CO2 flooding followed by blowdown processes are carried out in the laboratory under four CO2 injection pressures and two temperatures, and the properties of produced and residual oils are further characterized. It is found that uneven residual oil distribution occurred due to the coupled effects of viscous fingering and oil properties changes during CO2 flooding process. Characterization of the produced oil shows that both the produced oil density and viscosity decrease when CO2 injection pressure increases. The asphaltenes content of the oil produced after CO2 breakthrough is found to be relatively lower than that of the oil sam...

Determination and controlling of gas channel in CO2 immiscible flooding

In order to study the effect of gas channel on CO2 flooding in porous medium, the gas flow velocity is divided into two parts: gas breakthrough stage and gas channeling stage. The breakthrough velocity has an exponential relationship with concentration in the frontal zone of gas area, while the channeling velocity has a linear relationship with injection pressure drop. A new method is proposed to determine the gas channeling time by using the trend line of gas–oil ratio in gas breakthrough and gas channeling stage. The production characteristics in CO2 flooding show that recovery greatly improves after the gas breakthrough at the outlet of core sample, and most of the oil displaces before gas channeling. Thus, the extension of the stage between gas breakthrough and gas channeling becomes a key factor to improve CO2 recovery efficiency. Improving the injection pressure drop increases the dissolved gas diffusion, which will improve the oil displacement efficiency of simultaneous oil and gas production stage, but it also increases gas channeling velocity, which will increase the gas/oil ratio sharply and result in ineffective gas injection. An optimal displacement pressure can control the diffusion rate, the channeling rate and improve the recovery of CO2 flooding effectively. Keeping a constant pressure drop, increasing of injection pressure can not only increase the diffusion rate, but also reduce the gas channeling velocity. The achievement of a lower gas channeling velocity is advisable for extending the stage of gas–liquid production, and improving the immiscible CO2 recovery significantly.

Performance of immiscible and miscible CO<SUB align="right">2 injection process in a tight carbonate reservoir (experimental and simulation approach)

In this study, the technical feasibility of CO2 injection in a core sample of a tight carbonate reservoir was investigated under various operating conditions. First, the minimum miscibility pressure (MMP) of CO2/oil system was determined to be 1,907 Psia. The effects of the operating pressure as well as the injection flow rate of CO2 on the oil recovery were examined. The results showed that at the operating pressures far below the MMP, the ultimate oil recovery factor is considerably low and increases as the pressure approaches near-miscible condition. When injection pressure was increased to 2,000 Psia, the ultimate oil recovery factor reached 0.81 and further increase in injection pressure did not significantly improve the recovery factor. For injection pressures lower than MMP (i.e., immiscible condition), increasing injection flow rate of CO2 resulted in lower oil recovery, while at the pressures near and above the MMP, the ultimate oil recovery was much less dependent on CO2 injection flow rate. All the test results were simulated using the CMG package, ver. 2011 and attempt was made to history match the experimental results. In this process, relative permeability curves were used as matching parameter. The simulation results were in good agreement with experimental values. [Received: March 12, 2013; Accepted: August 4, 2013]

Marangoni flow: An unknown mechanism for oil recovery during near-miscible CO2 injection

Abstract Previously, we investigated the effect of interfacial tension gradient induced convective fluxes – Marangoni flow – on the recovery of bypassed oil during near-miscible and immiscible CO 2 injection in a 1D-matrix/fracture model. In the current study, the impact of Marangoni flow on oil recovery is studied during CO 2 injection into a matrix (flooding) using experimental results combined with analytical calculations. CO 2 injection is conducted at different pressures below the critical point where the oil/gas interface exists. The ternary system of CO 2 /C10/C3 was compared with a binary system of CO 2 /C10 as the zero level of the Marangoni flow. In this manner, the influence of other conventional recovery mechanisms can be simultaneously eliminated. The results show that there is good agreement between the recovery differences of these two systems and the Marangoni number derived from analytical estimations. Therefore, in the multi-component systems of hydrocarbons, where IFT increases with CO 2 concentration, Marangoni flow improves oil recovery by about 35%. During CO 2 flooding, it postpones the breakthrough time by conducting the oil towards the gas channel and guaranteeing the continuity of recovery. The level of recovery enhancement in the ternary system is proportional to the Marangoni number, and is maximized at a near-critical state, but vanishes towards the critical point. In far from critical region, the Marangoni effect is relatively weak.

Fluid–fluid interactions in a system of CO 2 , oil, surfactant solution, and brine at high pressures and temperatures – A Malaysian reservoir case

In this study, the interactions of fluids involved in foam assisted CO2 enhanced oil recovery process are studied at the prevailing conditions of a shallow Malaysian (sandstone) oil reservoir (pressure of 70–200 bar, and temperature of 102 °C). The equilibrium CO2 solubility into the reservoir brine, and crude oil, and the effect of foaming agent surfactants on the CO2 solubility into the aqueous phase are measured by using an equilibrium high pressure cell. The interfacial tension (IFT) measurements of gas–liquid and liquid–liquid systems are accomplished by utilizing the axisymmetric drop shape analysis (ADSA) adapted in a pendant drop tensiometer. Two in-house developed surfactants (FomaxII and FomaxVII) are compared with the industrial bench-mark surfactant, alpha olefin sulfonate (AOS), for the structure–property analysis. FomaxVII is a blend of anionic and amphoteric surfactants, with a short-branched chain structure which contains CO2-philic groups. FomaxII is a blend of anionic surfactants, with long, straight-tail hydrocarbon structure. The results show that the dissolution of CO2 into the aqueous phase increased significantly in the presence of 1 wt% surfactants at the reservoir prevailing conditions. A relationship was also observed between the surfactant molecular structure and its effect on the CO2/aqueous phase interface. The results of this study are useful to evaluate the mechanisms of immiscible CO2 flooding as well as to design the foam assisted CO2-EOR applications for the case Malaysian or similar oil reservoir.

Evaluation of miscible and immiscible CO2 injection in one of the Iranian oil fields

Carbon dioxide (CO2) flooding is one of the most important methods for enhanced oil recovery (EOR) because it not only increases oil recovery efficiency but also causes a reduction of greenhouse gas emissions. It is a very complex system, involving phase behavior that could increase the recovery of oil by means of swelling, evaporation and decreasing viscosity of the oil. In this study, a reservoir modeling approach was used to evaluate immiscible and miscible CO2 flooding in a fractured oil field. To reduce simulation time, we grouped fluid components into 10 pseudo-components. The 3-parameter, Peng–Robinson Equation of State (EOS) was used to match PVT experimental data by using the PVTi software. A one-dimensional slim-tube model was defined using ECLIPSE 300 software to determine the minimum miscibility pressure (MMP) for injection of CO2. We used FloGrid software for making a reservoir static model and the reservoir model was calibrated using manual and assisted history matching methods. Then various scenarios of natural depletion, immiscible and miscible CO2 injection have been simulated by ECLIPSE 300 software and then the simulation results of scenarios have been compared. Investigation of simulation results shows that the oil recovery factor in miscible CO2 injection scenario is more than other methods.

Oil Recovery Performance of Immiscible and Miscible CO2 Huff-and-Puff Processes

The recovery performance of immiscible and miscible CO2 huff-and-puff processes for enhanced oil recovery (EOR) in a light crude oil sample was experimentally investigated. The minimum miscibility pressure (MMP) of the original light crude oil–CO2 system was determined by means of the vanishing interfacial tension technique and found to be MMP = 9.18 MPa. Then, the solubility of the CO2 in the light crude oil and oil swelling factor due to the CO2 dissolution in the oil phase were determined at T = 30 °C and various equilibrium pressures ranging from atmospheric pressure to Peq = 12.55 MPa. Later, series of immiscible and miscible CO2 huff-and-puff tests were designed and carried out at various operating pressures (i.e., Pop = 5.38–10.34 MPa). The results of the experiments showed that for secondary CO2 huff-and-puff tests performed at the operating pressures below the MMP, the ultimate oil recovery factor is quite low. It was also found that in immiscible CO2 huff-and-puff (i.e., Pop < MMP) scenarios, the oil recovery factor substantially increased as the operating pressure approached near-miscible conditions. The oil recovery factor almost reached its maximum value at operating pressure near MMP (i.e., miscible condition), and further increase of operating pressure beyond MMP did not improve the recovery factor at all. The tertiary mode of miscible CO2 huff-and-puff was also examined, and it was revealed that the oil recovery is significantly improved after a waterflooding process. The oil recovery mechanisms during the CO2 huff-and-puff were mainly recognized to be interfacial tension reduction, oil swelling, and extraction of lighter components by CO2, especially during miscible CO2 injections. In addition, the average asphaltene content of produced oil and the permeability reduction of the porous medium as a result of asphaltene precipitation were measured in each test. It was found that the amount of precipitated asphaltene in the porous medium as well as permeability reduction are considerably higher in near-miscible and miscible CO2 huff-and-puff tests compared to those in immiscible cases. The compositional analysis of remaining oil from CO2 huff-and-puff tests at immiscible and miscible conditions also showed that lighter components of oil are extracted by CO2, leading the remaining oil to become heavier with greater amounts of heavy hydrocarbons (i.e., C30+). However, it was observed that the extraction of lighter components during miscible injection processes is more predominant than that during immiscible injections, resulting in the production of higher quality oil.

Effect of Marangoni flow on recovery of bypassed oil during CO2 injection

We have experimentally investigated the effect of interfacial tension gradient induced convective fluxes – Marangoni flow – on the recovery of bypassed oil during near-miscible and immiscible CO2 injection in a 1D-matrix/fracture model. Hydrocarbon systems of components were designed such that the existence of Marangoni flow and its direction with respect to fracture could be managed. The results show reasonable agreement between recovery changes and Marangoni number, indicating the significant impact of Marangoni flow on the recovery of bypassed oil in porous media under high-pressure high-temperature conditions. The results of our experiments introduce the so-far neglected Marangoni phenomenon as a considerable mechanism of oil recovery in near-critical conditions.

Effect of Miscibility Condition for CO2 Flooding on Gravity Drainage in 2D Vertical System

In CO2 flooding process, gravity drainage and miscibility condition are the main factors on the efficiency of oil recovery. In this study, we observed oil recovery for different miscibility conditions in vertical oil reservoir. This was investigated in two dimensional vertical sandstone slab, where unstable gravity drainage phenomena can be formed. CO2 is injected at bottom into 100% saturated with oil and production port is open at top of the system. We have performed a series of experiments using continuous CO2 flooding for immiscible and near-miscible conditions. From the experimental results, oil recovery at near-miscible condition is 3.77 times greater than at immiscible condition, particularly in vertical system. It indicated that applying the immiscible CO2 flooding is ineffective because of gravity override of CO2 and generation of CO2 channel at upper side in vertical reservoir. Meanwhile, the results revealed that oil recovery increases considerably once miscibility is reached at outlet. That is, miscibility condition is found to be a sensitive factor on oil recovery particularly in vertical oil reservoir.

エマルション生成, CO&lt;sub&gt;2&lt;/sub&gt;フォーミィオイル生成および原位置燃焼による重質油の生産挙動について

Enhanced oil recovery (EOR) processes have been applied to improve mobility of heavy oil and bitumen. This article has introduced three topics on numerical models for heavy oil and bitumen productions based on laboratory measurements and their scaling up to field reservoir simulations using CMG STARS™.First one is CO2 gas foaming by depressurizing after immiscible CO2 dissolution in heavy oil. Saturated CO2 solubility and apparent swelling after foaming were measured on decreasing pressure processes using PVT apparatus and a high pressure cell. The numerical models of apparent viscosity and swelling ratio for foamy heavy oil have been proposed based on the measurement data and applied to a field scale oil-reservoir by Huff-n-Puff production methodThe second one is bitumen emulsion (water in oil) formed by the Steam Assisted Gravity Drainage (SAGD) method for oil-sands layers, because condensed fine water-droplets diffuse into bitumen at the steam-chamber boundary. The characteristic of heavy-oil viscosity was measured against water/oil ratio (W/O) and temperature. The model of viscosity ratio (emulsion/original) vs. W/O has been presented and investigated its effect on bitumen-production from a typical oilsands reservoir by SAGD method. Finally, it has been shown that cumulative bitumen-production increases with bitumen swelling function of W/O.The third one is heavy oil recovery by in-situ combustion with injecting air or O2 gas. Recently, the Toe-to-Heal Air Injection (THAI) method using a vertical injector and a horizontal producer is expected to be able to keep stable combustion front and oil drainage flow into the producer. Based on our numerical history-matching study on the tube combustion test for bitumen sands-pack, the reaction model consists from 3 major reactions were screened from 8 chemical reactions on Maltenes, Asphaltenes and Coke. Finally, the model was successfully applied to a heavy-oil in-situ production from a typical field oil reservoir.

Pressure maintenance and improving oil recovery with immiscible CO2 injection in thin heavy oil reservoirs

Techniques have been developed to experimentally and numerically evaluate performance of CO2 injection in heavy oil reservoirs for pressure maintenance purpose. More specifically, a three-dimensional (3D) physical model consisting of five vertical wells and three horizontal wells is used to examine the effect of well configurations on pressure maintenance and oil recovery with CO2 injection in heavy oil reservoirs. The initial oil saturation, oil production rate, water cut, gas–oil ratio, ultimate oil recovery, and distribution of residual oil saturation are examined under three well configurations, which can be optimized to maximize heavy oil recovery when CO2 injection is employed for pressure maintenance purpose. Subsequently, numerical simulation has been performed to match the experimental measurements. It has been found that pressure maintenance with CO2 injection is beneficial for oil recovery in heavy oil reservoirs. Compared with the conventional five-spot well configuration, the well configurations associated with horizontal well(s) are found to achieve a better performance, while the well configuration of two horizontal wells (Scenario ♯3) yields the highest oil recovery. The oil recovery of Scenario ♯3 is experimentally determined to be 38.6% of original oil in place (OOIP) after CO2 injection.

Oil recovery mechanisms and asphaltene precipitation phenomenon in immiscible and miscible CO2 flooding processes

In this paper, oil recovery mechanisms and asphaltene precipitation phenomenon of immiscible and miscible CO2 flooding processes in the tight sandstone reservoir core plugs are experimentally studied. First, the vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressure (MMP) between the original light crude oil and CO2. Second, a total of five coreflood tests are performed at the actual reservoir temperature. It is found that the oil recovery factor (RF) increases monotonically as the injection pressure increases during the immiscible CO2 flooding. The increased oil RF is attributed to the increased CO2 solubility in oil, reduced oil viscosity, increased CO2 viscosity, and reduced equilibrium interfacial tension (IFT) of the light crude oil–CO2 system. Once the injection pressure exceeds the MMP, the oil RF increases slightly and will reach an almost constant maximum value. In this case, it is the multi-contact miscibility (MCM) and the extremely low equilibrium IFT that jointly make the ultimate oil RF high and unchanged. Moreover, the oil RF after CO2 breakthrough (BT) increases slightly in the immiscible case but substantially in the miscible case. This is due to the strong light-hydrocarbons extraction by CO2 and the miscible displacement in the second case. On the other hand, the measured average asphaltene content of the produced oil and the measured oil effective permeability reduction are found to be higher in the immiscible flooding process. They both reach some lower values in the miscible case. Finally, the experimental results obtained in this study at the actual reservoir temperature of Tres=53.0°C are compared with those attained previously at the laboratory temperature of Tlab=27.0°C to examine the temperature effect on the CO2-based oil recovery process.

Measurement of Immiscible CO2 Flooding Processes and Permeability Reduction due to Asphaltene Precipitation by X-ray CT Imaging

Carbon dioxide tertiary or secondary oil recovery becomes increasingly significant to the petroleum industry. CO2 flooding can not only enhance or improve oil recovery clearly but also considerably reduce greenhouse gas emission. After CO2 was injected into an oil reservoir, it contacted the reservoir oil and, consequently, changed the equilibrium conditions and fluid properties, which may lead to the precipitation of organic solids, primarily asphaltenes. In this case, the bulk porosity reduces obviously because of asphaltene deposition, which can cause permeability reduction of a tight sandstone reservoir after immiscible CO2 flooding. In this paper, a total of three CO2 coreflood tests under immiscible conditions were performed through the so-called dry, secondary, and tertiary oil recovery processes, respectively. After or before each process, the distribution of crude oil and brine (3wt% NaCl) in the core was scanned by employing X-ray CT scanning. Comparing two CT images before and after recovery processes in one test, it is found that asphaltenes deposited onto the sand grains and thus left in the reservoir, which caused permeability reduction of a tight sandstone reservoir after immiscible CO2 flooding.

Physicochemical Characterization of Produced Oils and Gases in Immiscible and Miscible CO2 Flooding Processes

In this paper, the oil and gas samples produced from tight sandstone reservoir core plugs in immiscible, near-miscible, and miscible CO2 flooding processes at the reservoir temperature are experimentally characterized. First, the vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressure (MMP) of the light crude oil–CO2 system. Second, a total of five CO2-coreflood tests are conducted under immiscible, near-miscible, and miscible conditions to thoroughly study the characteristics of the produced oils and gases during each CO2 flooding process. In the immiscible case (Pinj < MMP), the produced oil becomes heavier and heavier during CO2 injection in terms of its density, viscosity, molecular weight, and hydrocarbons (HCs). The produced gas contains up to 84–96 mol % HCs (dominantly C4–7) extracted from the light crude oil by CO2 at the beginning and 85–100 mol % CO2 at the end of CO2 injection. In the near-miscible case (Pinj ≈ MMP), the heaviest oil is produced at 0.4 pore volume (PV) of the injected CO2, which is followed by a relatively lighter produced oil from CO2 breakthrough (BT) at 0.6 PV to the end of CO2 injection. The produced gas has 40–60 mol % HCs (dominantly C5–8) at the beginning and then consists of almost 100% CO2 after CO2 BT. In the miscible case (Pinj > MMP), the produced oil becomes much lighter and lighter with the injected PV. The produced gas contains 20–75 mol % HCs (mainly C5–8) at the very beginning and quickly becomes almost 100% CO2 after CO2 BT. In summary, this laboratory study provides the comprehensive characterization of the produced fluids in three distinct CO2 flooding processes. These new experimental data will help to better evaluate the field-scale CO2-enhanced oil recovery (EOR) processes and design the future CO2-EOR projects as well.

The Evaluation of Variable-Injection Rate Waterflooding, Immiscible CO2 Flooding, and Water-alternating-CO2 Injection for Heavy Oil Recovery

Despite the existence of studies for separate evaluation of waterflooding, immiscible CO2 flooding, and CO2 water-alternating gas (WAG) for heavy oil recovery, there is a lack of an experimental, comparative evaluation of these three methods. The authors conducted tests for comparative evaluation of variable-injection rate waterflood (VIWF), immiscible CO2 flood, and CO2 WAG. The results illustrate the (a) effectiveness of VIWF, immiscible CO2 flood, and CO2 WAG; (b) effect of permeability and oil viscosity on VIWF, immiscible CO2 flood, and CO2 WAG; (c) effect of injection rate on VIWF; and (d) effect of slug ratio on CO2 WAG.

Comparative evaluation of immiscible, near miscible and miscible CO2 huff-n-puff to enhance oil recovery from a single matrix–fracture system (experimental and simulation studies)

In this paper, the performance and efficiency of improved oil recovery in fractured porous media utilizing the cyclic CO2 injection process (otherwise known as CO2 huff-n-puff) are examined for immiscible, near-miscible and miscible pressure conditions. The main approach involved the comparison of simulation results to experimental data obtained from a laboratory CO2 huff-n-puff model. Previous experimental studies performed showed promising results for CO2 huff-n-puff process in a fractured model saturated with light oil. In order to upscale the experimental results and perform further studies, fully compositional simulation software was utilized to simulate the cyclic CO2 injection experiments. Prior to this, the phase behavior of a mixture of CO2 and decane (nC10) was studied and minimum miscibility pressure (MMP) of CO2–nC10 was found to be 1058psi, which was in good agreement with experimental results obtained by rising bubble apparatus (RBA) and visual tests [9,10]. The results of six sets of huff-n-puff experiments performed under constant temperature of 35°C and a wide range of pressures from 250 to 1500psi were simulated. Simulation results were in good agreement with those obtained experimentally. Throughout these studies, it has been found that near-miscible CO2 huff-n-puff process can improve the recovery factor from the light oil saturated experimental model by a factor of two. It was also discovered that the injection of CO2 at pressures much higher than the MMP was not significantly beneficial to recovery factor and may require further economical analysis. Also, cyclic CO2 performance improved greatly when conditions transitioned from immiscible to near-miscible (i.e. operating and injection pressures were increased to 1000psi) as indicated by a sharp increase in oil production.

Magnetic resonance imaging on CO2 miscible and immiscible displacement in oil-saturated glass beads pack

In this study, the displacement processes were observed as gaseous or supercritical CO 2 was injected into n-decane-saturated glass beads packs using a 400-MHz magnetic resonance imaging (MRI) system. Two-dimensional images of oil distribution in the vertical median section were obtained using a spin-echo pulse sequence. Gas channeling and viscous fingering appeared obviously in immiscible gaseous CO 2 displacement. A piston-like displacement front was detected in miscible supercritical CO 2 displacement that provided high sweep efficiency. MRI images were processed with image intensity analysis methods to obtain the saturation profiles. Final oil residual saturations and displacement coefficients were also estimated using this imaging intensity analysis. It was proved that miscible displacement can enhance the efficiency of CO 2 displacement notably. Finally, a special coreflood analysis method was applied to estimate the effects of capillary, viscosity and buoyancy based on the obtained saturation data.