Miscible Flooding Research Articles

Understanding the Multiphysical Processes in Carbon Dioxide Enhanced-Oil-Recovery Operations: A Numerical Study Using a General Simulation Framework

Summary In this paper, we aim to enhance our understanding of the multiphysical processes in carbon dioxide (CO2)-enhanced-oil-recovery (EOR) (CO2-EOR) operations using a modeling approach. We present the development of a comprehensive mathematical model for thermal/hydraulic/mechanical (THM) simulation of CO2-EOR processes. We adopt the integrated-finite-difference method to simulate coupled THM processes during CO2-EOR in conventional and unconventional reservoirs. In our method, the governing equations of the multiphysical THM processes are solved fully coupled on the same unstructured grid. To rigorously simulate the phase behavior of a three-phase, nonisothermal system, a three-phase flash-calculation module, dependent on the minimization of Gibbs energy, is implemented in the simulator. The simulator is thus applicable to both miscible and immiscible flooding simulations under isothermal and nonisothermal conditions. We have investigated the effect of cold-CO2 injection on injectivity as well as on phase behavior. We conclude that cold-CO2 injection is an effective way to increase injectivity in tight oil reservoirs and reduces overriding effect in high-water-bearing reservoirs. Using the developed general simulation framework, we have discovered and studied several intriguing multiphysical phenomena that cannot be captured by commonly used reservoir simulators, including the temperature-decreasing phenomenon near the production well and the permeability-enhancement effect induced by the thermal unloading process. These phenomena can be captured only by the fully coupled multiphysical model. The novelty of this paper lies in its integration of multiple physical simulation modules to form a general simulation framework to capture realistic flow and transport processes during CO2 flooding, and in revealing the behavior of cold-CO2 injection under THM effects.

A non-aqueous foam concept for improving hydrocarbon miscible flooding in low permeability oil formations

Enhanced oil recovery (EOR) from carbonate formations has been challenging due to reservoir heterogeneity, unfavorable wettability, and low permeability. Thus, the application of traditional water-based EOR methods such as micellar-polymer flood in these reservoirs has been limited. With the increasing availability of natural gas, we introduce a new foam EOR concept utilizing the raw mixture of natural gas liquids (MNGLs). This process involves the injection of a non-condensable gas (i.e., nitrogen or methane) and MNGLs with dissolved non-aqueous foam stabilizing additive to maximize oil recovery based on crude oil-MNGLs miscibility and sweep efficiency due to foam improved mobility control.The objective of this study is to evaluate the performance of this unconventional foam process to improve miscible displacement in low permeability rocks. Coreflood experiments were conducted using heterogeneous carbonate cores with sub-10-mD permeability. It was found that non-aqueous foam-assisted miscible displacement can achieve promising ultimate recovery factors while significantly reducing the amount of injected MNGLs. The overall recovery could be increased up to 18% with a foaming additive dissolved in the MNGLs slug. The measured pressure drops along the core indicate that in-situ generation of foam significantly delayed the injectant breakthrough and recovered the unswept oil much further away from the injection point.

Experimental study on the CO2-decane displacement front behavior in high permeability sand evaluated by magnetic resonance imaging

CO2 flooding has been proven to be an effective method to improve oil recovery, and the interface characteristics of the displacement front directly affect the oil recovery and CO2 utilization efficiency in reservoirs. In this study, we aimed to investigate the in situ interfacial behavior during CO2 flooding using high-resolution magnetic resonance imaging (MRI). A series of CO2 flooding tests were carried out using upward and downward injection methods consisting of different rates (28, 56 and 112 pore volume (PV)/day) in porous media. The unstable CO2 front is indicated to significantly impact the gas sweep efficiency, which is not favorable for oil recovery and leads to low energy utilization efficiency. For downward injection, subordinate displacement of CO2 was observed after breakthrough, which can improve oil recovery. The optimum oil recovery and CO2 utilization factor were obtained under upward injection at a low rate in the immiscible state, which was controlled by the stable interface behavior. From the perspective of CO2 storage, miscible flooding improved the storage volume by more than 25% compared to immiscible flooding. For high permeability oil reservoirs, the oil recovery and gas sequestration can be synthetically optimized by adjusting the injection rates and phase state.

A Simplified Capillary Bundle Model for CO2-Alternating-Water Injection Using an Equivalent Resistance Method

CO2-alternating-water injection is an effective way of enhancing recovery for low-permeability oil reservoirs. The injection process is one of the essential issues that are facing severe challenges because of the low permeability and poor pore space connectivity. Previous researchers mentioned that water injection ability could be decreased by around 20% after the CO2-flooding; hence, it is necessary to quantify the water injectivity variation during an alternated injection process. In this paper, a CO2 convection-diffusion model is established based on the seepage law of CO2 and dissipation effect. The relationship between the width of miscible flooding and injection time is defined. Besides, an equivalent resistance method is introduced for developing a capillary bundle model for featuring an unequal diameter for CO2 water vapor alternate flooding. CO2-oil and CO2-water interactions are analyzed using the new model. The effects of oil viscosity, pore throat ratio, CO2 slug size, and equivalent permeability of the capillary bundle on water injection are analyzed. The result indicates that water injection ability increases with the rise of CO2 slug size and equivalent permeability of the capillary bundle and decreases with the increase of viscosity and pore throat ratio.

Research for reducing minimum miscible pressure of crude oil and carbon dioxide and miscible flooding experiment by injecting citric acid isopentyl ester

The minimum miscible pressure is one of the key factors to realize miscible flooding. As the minimum miscible pressure in the research area is higher than the formation fracture pressure, miscible flooding cannot be formed. To address this problem, it is necessary to find a way to reduce the minimum miscible pressure. Citric acid isopentyl ester can not only be dissolved in crude oil, but also be dissolved in carbon dioxide. Therefore, citric acid isopentyl ester was chosen to reduce the minimum miscible pressure in this research. The effect of citric acid isopentyl ester on reducing the minimum miscible pressure was measured by the method of long slim tube displacement experiment. The minimum miscible pressure in the research area was 29.6 MPa. The experimental results show that the minimum miscible pressure could decrease significantly with increasing the injected slug size of citric acid isopentyl ester, but the decrease became smaller and smaller. The optimum injected slug size of the chemical reagent is 0.003 PV. Under the condition of the slug size, the minimum miscible pressure was 24.1 MPa. The reduction was 5.5 MPa. The reduction rate was 18.58%. The research results have important guiding significance for enhancing oil recovery in the research area.

CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs

Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of non-geomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.

A pore-scale experimental study of non-aqueous foam for improving hydrocarbon miscible flooding

Mobility control in hydrocarbon miscible flooding is crucial for commercial vitality where severe reservoir heterogeneity causes poor sweep efficiency. This study introduced a new concept of non-aqueous foam-assisted hydrocarbon miscible flooding in water-sensitive oil formations. This process involves the injection of a non-condensable gas (i.e., nitrogen or methane) and a raw mixture of NGLs (MNGLs) with a foaming additive to improve displacement and sweep efficiency. Foaming a light hydrocarbon liquid and the impact of non-aqueous foam on miscible displacement are the main focuses of this study. n-Pentane was used as a MNGLs (solvent) model for foam stability tests. Transient foam propagation and rheology were directly visualized and characterized based on the apparent gas (nitrogen) viscosity associated with foam texture and fluid saturations. Oil recovery factors were directly related to different degrees of in-situ foaming. For the injection of a solvent slug followed by a gas drive, the displacement of oil became unstable as nitrogen fingered through the solvent-oil mixing zone, resulting in a high residual liquid saturation. However, gas fingering was significantly hindered as the solvent was injected with a foaming agent. Dynamic fluid distribution indicate that the improved oil recovery could be attributed to the propagation of foam in the swept zone, which provided essential flow resistance for better displacement stability. To investigate the effect of initial gas saturation in the reservoir on flow behavior, a slug of gas was injected before solvent injection. Delayed solvent breakthrough and better sweep efficiency were observed in the presence of foam due to the reduced liquid phase mobility in preferential flow paths and the diversion of solvent into small pores by the trapped gas at the displacing front. Furthermore, it was possible to obtain stable foam flow with an apparent viscosity of 20 times greater than the solvent viscosity.

Feasibility of miscible CO2 flooding in hydrocarbon reservoirs with different crude oil compositions

Miscible CO2-based enhanced oil recovery (CO2-EOR) flooding has been used, on many occasions, to maximize the recovery by mobilizing the residual oil. The success of this method, however, depends highly on the minimum miscibility pressure (MMP), the compatibility of CO2 with the reservoir rock and fluids. Although there have been several studies on the application of CO2-EOR, the impact of oil compositions associated with MMP on the feasibility of this technique has not been addressed elsewhere. In this study, a simulation study was carried out to investigate the effect of three different oil compositions on the miscibility and ultimate oil recovery of miscible CO2-EOR method. The results obtained indicated the oil type does not pose a significant impact on the success of miscible CO2-EOR. It was also found that the ultimate recovery of oil increases in a short period of time by injecting CO2 at the miscible conditions at the early stage of natural production. Comparatively, the reservoir with the fluid sample S2 seems to be a suitable choice for the miscible CO2 flooding once the recovery factor was considered together with the total amount of the fluid injected and produced.

Numerical Validation of Asphaltene Precipitation and Deposition during CO2 miscible flooding

Asphaltene precipitation, flocculation, and deposition can significantly reduce oil production by impacting wellbores, flowlines, and more importantly, formations’ pore space around the well. Any alteration in the temperature, pressure and fluid composition can trigger asphaltene deposition. The ability to predict the occurrence and magnitude of the asphaltene deposition is a major step for flow assurance. An accurate prediction of the deposition envelope enables the operator to systematically categorize different cases based on their impact on the production. This critical knowledge can be used to predict the occurrence and magnitude of asphaltene deposition, which could potentially save the expense of installing unnecessary equipment and injecting chemical inhibitors when they are not needed.Predicting asphaltene-related flow assurance issues requires robust physically-based modeling capabilities for capturing the asphaltene’s deposition tendencies as a function of the prevailing field’s operating conditions. Although available simulators are found to be useful for predicting asphaltene’s phase behavior, precipitation tendency, and instability curves, they often overlook important physical characteristics of the asphaltenes. These properties may have a detrimental role in obtaining a realistic representation of the asphaltene deposition behavior.In this paper, the experimental and the numerical investigations are combined to present a comprehensive methodology for studying the thermodynamics of asphaltene precipitation and deposition. A wide range of pressures and CO2 concentrations are covered that are relevant to actual CO2 flooding in a Middle East oil reservoir. To do so, a series of lab experiments including routine and special PVT analyses where the Asphaltene Onset Pressure (AOP) and Saturation Pressures (Psat) were measured for different mixtures of CO2 and the reservoir oil. Maximum of 50 mol% CO2 concentration mixture was tested to measure the AOP and Psat. The amount of asphaltene precipitation was found between 0.25 and 4 wt% for the mixtures of 10–50 mol% CO2 concentration. Furthermore, detailed recommendations are presented in this paper to tune an EOS for running compositional simulations when unstable asphaltene is reported based on the lab experimental measurements.

Determination of minimum miscible pressure in CO2-crude oil system of Changqing Oilfield

Carbon dioxide miscible flooding in low permeability sandstone reservoir can greatly enhance the recovery, the minimum miscible pressure (MMP) is the starting point of miscible flooding. Its determination is very important for oilfield development. In this paper, the internationally widely accepted thin tube experiment method and the bubble riser method are used to compare the minimum miscible pressure. Research results show that the minimum miscibility pressure obtained by slender tube displacement experiment is 22.12 MPa. The minimum miscible pressure measured by the bubbler method is 32.33 MPa, and the error result is large.

Effect of Pore-Throat Microstructures on Formation Damage during Miscible CO2Flooding of Tight Sandstone Reservoirs

Pore and throat blockage and wettability alteration caused by asphaltene deposition are serious problems during the injection of CO2 into subsurface reservoirs for enhanced oil recovery (EOR). During miscible CO2 flooding, the efficacy and distribution of fluid flow in sandstone reservoirs are controlled by the pore-throat microstructure of the rock. Furthermore, CO2 injection promotes asphaltene precipitation on pore surfaces and in the pore throats, decreasing the permeability and altering reservoir wettability. In this work, miscible CO2 flooding experiments under reservoir conditions (up to 70 ± 0.1 °C, 18 MPa) were carried out on four samples with very similar permeabilities but significantly different pore size distributions and pore-throat structures to study the effects of the pore-throat microstructure on formation damage. The features of the pore-throat structure were evaluated by fractal theory, based on constant-rate mercury intrusion (CRMI) tests. Reservoir rocks with smaller pore-throat sizes and more heterogeneous and poorer pore-throat microstructures were found to be more sensitive to asphaltene precipitation, with corresponding 14–22% lower oil recovery factors (RFs) and 4–7% greater decreases in permeability compared to more homogeneous rocks and rocks with larger pore throats. However, the water-wettability index of cores with larger and more connected pore-throat microstructures was found to drop by an extra 15–25% compared to the water-wettability decrease found for heterogeneous cores. We attribute these observations to an increase in asphaltene precipitation caused by the larger sweep volume of injected CO2, which occurs in rocks with larger and more homogeneous pore throats. In addition, we observed that rocks with more homogeneous pore-throat microstructures also exhibit homogeneity in the consequent distribution of formation damage.

Yushulin Oilfield CO2- Comparison of minimum miscibility pressure test results for crude oil system

Miscible displacement of carbon dioxide in low permeability sandstone reservoirs can greatly improve oil recovery. The minimum miscible pressure is the starting point of miscible flooding. Its determination is very important for oilfield development. In this paper, the error analysis of the results measured by empirical formulas is carried out by the internationally accepted slim tube experiment method. Research results show that the minimum miscibility pressure obtained by slender tube displacement experiment is 22.12 MPa. The maximum, minimum and average miscibility pressures predicted by empirical formula method are 32.33 MPa, 7.85 MPa and 19.76 MPa, respectively. The relative error of the average minimum miscibility pressure predicted by all empirical formulas is 10.67%. The least relative error is the Yelling and Metcalfe correlation method, the relative error is 8.82%.

Relative Permeability Characteristics During Carbon Capture and Sequestration Process in Low-Permeable Reservoirs.

The injection of carbon dioxide (CO2) in low-permeable reservoirs can not only mitigate the greenhouse effect on the environment, but also enhance oil and gas recovery (EOR). For numerical simulation work of this process, relative permeability can help predict the capacity for the flow of CO2 throughout the life of the reservoir, and reflect the changes induced by the injected CO2. In this paper, the experimental methods and empirical correlations to determine relative permeability are reviewed and discussed. Specifically, for a low-permeable reservoir in China, a core displacement experiment is performed for both natural and artificial low-permeable cores to study the relative permeability characteristics. The results show that for immiscible CO2 flooding, when considering the threshold pressure and gas slippage, the relative permeability decreases to some extent, and the relative permeability of oil/water does not reduce as much as that of CO2. In miscible flooding, the curves have different shapes for cores with a different permeability. By comparing the relative permeability curves under immiscible and miscible CO2 flooding, it is found that the two-phase span of miscible flooding is wider, and the relative permeability at the gas endpoint becomes larger.

Guest Editorial: Why Should SPE Members Be Interested in Carbon Capture and Storage?

Guest editorial As chairperson of the SPE Carbon Capture Utilization and Storage (CCUS) Technical Section, I have frequently seen and heard the debate about CO2 and climate change at conferences, meetings, and in SPE Connect forums, often very vigorous, deep into the nuts and bolts of climate science, and with passionate discussions both pro and con. From a purely cynical point of view, I could make the argument that the debate is already over, as it is largely political, it doesn’t matter what we think, we are stuck with results that can significantly impact our industries, and we should do what we can to minimize the damage. However, I prefer to look at this more as an opportunity, a way to advance our social license, and as a series of technical issues that members of SPE are uniquely qualified to address. Since the first commercial CO2 project in Scurry County, Texas, in 1972, more than 150 additional CO2 EOR projects have been put in place worldwide. These projects initially depended on natural CO2 and were located near three large natural CO2 resources: McElmo Dome in Colorado, Bravo Dome in New Mexico, and Jackson Dome in Mississippi. More than 100 current CO2 EOR projects are located in the Permian Basin and Gulf Coast as a result. These projects were not initiated to save the planet or to sequester CO2; they were created by brilliant engineers and scientists trying to squeeze additional resources from declining reservoirs, and they continued because they were economical and extended the lives of fields. CO2 EOR in miscible or near-miscible floods can revitalize mature fields, with a typical tertiary response on the order of the secondary recovery efforts in both duration and volumes. In the past, projects have been limited by chemistry, CO2 supply, and infrastructure. According to a report by the US Bureau of Ocean Energy Management, only about 3–4% of potential US CO2 EOR sites—that is, those with proper pressure, temperature, and permeability for miscible flooding—are currently under flood. The remaining sites are awaiting available CO2, and, perhaps more importantly, favorable economics compared to other investment opportunities, such as unconventionals, where Permian shale oil is being produced for as low as $25 per barrel. Over 1 Bcf of natural CO2 is injected into the Permian Basin every day, and estimates are that between 800 million and 1 billion metric tons of CO2 have been stored during the past 45 years of CO2 EOR development in the region, more or less incidentally to the primary goal of producing incremental oil. This is very significant, because you are looking at numbers, which are on at least the same order of magnitude that the Paris Climate Agreement says we need to store over the next 20 years, and it has been done voluntarily, with existing technology, and with many more fields available for potential development.

Oil production and reservoir damage during miscible CO2 injection

The blockage and alteration of wettability in reservoirs caused by asphaltene deposits are problems that contribute to poor oil recovery performance during carbon dioxide (CO2) injection. Oil production and reservoir damage are both controlled by macroscopic interlayer heterogeneity and microscopic pore-throat structure and may be optimized by the choice of flooding method. In this work, the residual oil distribution and the permeability decline caused by organic and inorganic precipitation after miscible CO2 flooding and water-alternating-CO2 (CO2-WAG) flooding have been studied by carrying out core-flooding experiments on a model heterogeneous three-layer reservoir. For CO2, flooding experimental results indicate that the low-permeability layers retain a large oil production potential even in the late stages of production, while the permeability decline due to formation damage is larger in the high-permeability layer. We found that CO2-WAG can reduce the influence of heterogeneity on the oil production, but it results in more serious reservoir damage, with permeability decline caused by CO2–brine–rock interactions becoming significant. In addition, miscible CO2 flooding has been carried out for rocks with similar permeabilities but different wettabilities and different pore-throat microstructures in order to study the effects of wettability and pore-throat microstructure on formation damage. Reservoir rocks with smaller pore-throat sizes and more heterogeneous pore-throat microstructures were found to be more sensitive to asphaltene precipitation, with corresponding lower oil recovery and greater decreases in permeability. However, it was found that the degree of water wetness for cores with larger, more connected pore-throat microstructures became weaker due to asphaltene precipitation to pore surfaces. Decreasing the degree of water wetness was found to be exacerbated by increases in the sweep volume of injected CO2 that arise from cores with larger and better connected pore throats. Erosion of water wetness is a disadvantage for enhanced oil recovery operations as asphaltene precipitation prevention and control measures become more necessary.

非纯二氧化碳近混相驱可行性研究

非纯二氧化碳近混相驱可行性研究

Carbon dioxide transport in radial miscible flooding in consideration of rate-controlled adsorption

As an important technology in improving oil recovery, CO2 miscible flooding has achieved great success in many oil fields. However, studies on CO2 transport in porous media are mostly based on equilibrium adsorption in one-dimensional displacement where rate-controlled adsorption is not taken into consideration. In this work, we develop a radial convection–dispersion model, which simultaneously combines rate-controlled adsorption, convection, and dispersion. Based on this model, four dimensionless groups representing CO2 dispersion, adsorption capacity, flow rate, and kinetic rate groups are proposed for the first time. Subsequently, the Barakat–Clark forward and backward difference methods are combined to solve the mathematical model. CO2 concentration and adsorption at different positions in the porous media (including the effluent concentration and adsorption histories) are then calculated. Furthermore, the effects of the parameters on CO2 transport behavior are studied in detail. The results reveal that CO2 gradually moves forward with the increase in the CO2 injection volume. Once CO2 reaches a certain position, its concentration there increases and an S-shaped curve is formed. Moreover, the adsorption capacity at this position also increases significantly, and the changing rate is much higher than CO2 concentration. CO2 effluent concentration grows more uniform, and the breakthrough occurs earlier with increased dispersion velocity and CO2 injection rate and decreased adsorption capacity and adsorption rate. The mathematical model developed in this study is of great importance in predicting CO2 transport behavior in radial miscible flooding.

Study on Validation of the OPM Reservoir Simulator by Comparative Solution Project

The Open Porous Media (OPM) reservoir simulation toolkit is a free and open-source development in the reservoir simulation world and one that has received very little attention. OPM Flow is a fully-implicit, black-oil simulator capable of running industry-standard simulation models, which encourage open innovation and reproducible research on modeling and simulation of porous media processes. This study validates and assesses the capabilities of OPM Flow comparing with the industry standard ECLIPSE simulator. Several tests were conducted in order to validate the simulator, including a zero- balance test, symmetrical well test, three simulation models based on the SPE Comparative Solution Project, and a real world dataset from the Norne oilfield in Norway. This variety of tests covers a wide range of reservoir types and specific operating conditions which are representative of expected applications of the software. By comparison it is concluded that OPM Flow reservoir simulator can be considered a validated and capable reservoir simulator that is able to compete with Schlumberger ECLIPSE in many cases and shows great potential for future development. In addition, a basic user interface for queuing and running simulations through the OPM Flow simulator was developed using the Python programming language as well as some modifications to the miscible flooding solver.

Development of a fast EoS based compositional model for three-phase core flooding

Compositional simulators are of great importance to model core flow experiments and enhanced oil recovery processes. In the present study, a semi-implicit, three dimensional EoS-based formulation is developed for modeling and simulation of core-flooding process. The model treats three-phase flow in cylindrical coordinates with no need to use an iterative numerical method. Overall composition, pressure and water saturation are calculated implicitly for each grid block. Using this approach, a linear set of equations with constant coefficients would be solved at each time step. It is assumed that there is no mass transfer between hydrocarbon phases and water phase. In addition, a new technique has been suggested to calculate transmissibility coefficients in each direction, which is a major problem in compositional modeling. Each transmissibility coefficient is divided into two general parts which are treated differently. The first part is constant and the second part is time-dependent. This model yields a robust and fast calculation procedure, which is validated using Eclipse simulation results. Simulation of several miscible flooding processes were performed using Eclipse core-flood models in order to compare the results with the developed in-house model. Results are matched reasonably while the computing time is considerably decreased using the in-house model. It is shown that using second Stone’s relative permeability model and Advanced Peng–Robinson Equation of State, best results are achieved with an average absolute relative deviation of 7.7% from Eclipse results for ultimate recovery factor. In addition, sensitivity analysis has been performed on several input data including time-step size and block number. Results show that in a reasonable range of these parameters, convergence problems are not encountered. We have developed an in-house simulator based on our model, which can be a basis for other compositional simulation purposes. In addition to decreasing computing time, convergence problems encountered in most implicit techniques would be avoided as well.

A black-oil approach to model produced gas injection in both conventional and tight oil-rich reservoirs to enhance oil recovery

A robust compositionally extended black-oil simulation approach is developed, which is capable of including the effect of large gas-oil capillary pressure for first contact miscible (FCM), and immiscible gas injection. The simulation methodology is applied to gas flooding in both high and very low permeability reservoirs. For a high permeability conventional reservoir, simulations use a five-spot pattern with different reservoir pressures to mimic both FCM and immiscible displacements. The results show that the simple modified black-oil approach can model well both immiscible and miscible floods, as long as the minimum miscibility pressure (MMP) is matched. For a tight oil-rich reservoir, primary depletion and huff-n-puff gas injection are simulated including the effect of large gas-oil capillary pressure in flow and in flash calculation on recovery. Finally, a dynamic gas-oil relative permeability correlation that accounts for the compositional changes owing to the produced gas injection is introduced and applied to correct for changes in interfacial tension (IFT), and its effect on oil recovery is examined. The results show that the new black-oil approach can model these processes well and could be implemented when fully compositional simulations are computationally too time consuming. For the first time, a black-oil type reservoir simulation method is used to simulate near-miscible and immiscible produced gas injection enhanced oil recovery. It provides a fast and robust alternative for large-scale reservoir simulation with the purpose of flaring/venting reduction through reinjecting the produced gas into the reservoir for EOR.