Miscible Conditions Research Articles

Improved Minimum Miscibility Pressure Prediction for Gas Injection Process in Petroleum Reservoir

Determination of gas–oil minimum miscibility conditions is one of the important design parameters to improve the displacement efficiency of the hydrocarbon reservoir during enhanced oil recovery with gas injection. In this work, a support vector regression (SVR) model is developed using experimental data to estimate the minimum miscibility pressure (MMP) for various reservoir fluids and injection gases. Experimental MMP data taken from the reliable literature were used as input. Each data point input includes methane and intermediate components mole percent, plus fraction properties and reservoir temperature related to reservoir fluid and CO2, H2S, N2 and intermediate mole fractions, and intermediate properties of the injected gas. Experimental MMP is regarded as the model output. The database contains 135 datasets, from which 125 datasets were used for model development, and the rest were used for model evaluation. Genetic algorithm was implemented to optimize the SVR model parameters. The proposed data-driven model was verified by statistical validation data. The model results illustrate a correlation coefficient (R2) of 0.999. In addition, the SVR results demonstrate the proposed model to be a fast tool and a robust approach to map input space to output features. The SVR model was compared to popular data-driven MMP estimation models as well. This comparison presents an acceptable accuracy relative to this estimation model. Finally, the presented model was evaluated against a comprehensive theoretical model of slim tube compositional simulation on a trusted literature dataset.

SLIM-TUBE SIMULATION MODEL FOR CO2 INJECTION EOR

A simulation model of the slim-tube test has been developed to validate the laboratory experiment and used EOS as well as to investigate the possibility of serving as a fast and reliable tool for MMP determination. Sensitivity analyses were performed by testing diff erent grid block sizes (a diff erent number of cells), changing Corey’s coeffi cients for relative permeability curves, varying fl ow rates and PVT models. Minimum miscibility pressure from the simulation model is estimated as the intersection of the two diff erent trend line curves of oil recoveries versus the injected volume of CO2. The oil recoveries were underestimated by numerical simulation on a basic case model. This is related to the usage of single “X shaped” relative permeability curves in all simulation cases, i.e. for immiscible, near miscible and miscible conditions. In addition, by fi ne tuning binary interaction parameters in the equation of the state model and introducing diff erent relative permeability curves for immiscible and near miscible cases, better matching of slim-tube simulation can be achieved.

Multiphase transient analysis for monitoring of CO2 flooding

The potential of well test technology is discussed in this paper to estimate the miscible condition and displacement fronts position during CO2 flooding. To interpret the multiphase well test curve of CO2 flooding process, an accurate compositional numerical model is developed in this study. The model includes fully EoS-based compositional nonlinear formulation, unstructured gridding and multi-segmented well. A systematic well test analysis of CO2 flooding at different regimes, including immiscible, multi-contact miscible and first-contact miscible gas injection, was performed for hydrocarbon systems with different number of components. Based on the interpretation root cause analysis, proposed in this work, the specific characteristics of the well test curve of CO2 flooding have been identified and described. These characteristics provide the guidance for the distinction among the different regime of CO2 displacement. It was demonstrated that the most important characteristics stay invariant from the number of components involved into numerical study. Finally, a tangent line method has been proposed to detect the key point on the pressure derivative curve corresponding to a CO2 front. This method allows to predict the displacement front position for problems of practical interest.

Effects of compositional variations on CO2foam under miscible conditions

Foam can mitigate the associated problems with the gas injection by reducing the mobility of the injected gas. The presence of an immiscible oleic phase can adversely affect the foam stability. Nevertheless, under miscible conditions gas and oil mix in different proportions forming a phase with a varying composition at the proximity of the displacement front. Therefore, it is important to understand how the compositional variations of the front affect the foam behavior. In this study through several core‐flood experiments under miscible condition, three different regimes were identified based on the effects of the mixed‐phase composition on CO2foam‐flow behavior: In Regime 1 the apparent viscosity of the in‐situ fluid was the highest and increased with increasing xCO2. In Regime 2 the apparent viscosity increased with decreasing xCO2. In Regime 3 the apparent viscosity of the fluid remained relatively low and insensitive to the value of xCO2. © 2017 American Institute of Chemical EngineersAIChE J, 64: 758–764, 2018

Percolation characteristics of solvent invasion in rough fractures under miscible conditions

Surface roughness and flow rate effects on the solvent transport under miscible conditions in a single fracture are studied. Surface replicas of seven different rocks (marble, granite, and limestone) are used to represent different surface roughness characteristics each described by different mathematical models including three fractal dimensions. Distribution of dyed solvent is investigated at various flow rate conditions to clarify the effect of roughness on convective and diffusive mixing. After a qualitative analysis using comparative images of different rocks, the area covered by solvent with respect to time is determined to conduct a semi-quantitative analysis. In this exercise, two distinct zones are identified, namely the straight lines obtained for convective (early times) and diffusive (late times) flow. The bending point between these two lines is used to point the transition between the two zones. Finally, the slopes of the straight lines and the bending points are correlated to five different roughness parameters and the rate (Peclet number).It is observed that both surface roughness and flow rate have significant effect on solvent spatial distribution. The largest area covered is obtained at moderate flow rates and hence not only the average surface roughness characteristic is important, but coessentially total fracture surface area needs to be considered when evaluating fluid distribution. It is also noted that the rate effect is critically different for the fracture samples of large grain size (marbles and granite) compared to smaller grain sizes (limestones).Variogram fractal dimension exhibits the strongest correlation with the maximum area covered by solvent, and display increasing trend at the moderate flow rates. Equations with variogram surface fractal dimension in combination with any other surface fractal parameter coupled with Peclet number can be used to predict maximum area covered by solvent in a single fracture, which in turn can be utilized to model oil recovery, waste disposal, and groundwater contamination processes in the presence of fractures.

Field-scale simulation of CO2 enhanced oil recovery and storage through SWAG injection using laboratory estimated relative permeabilities

Numerical simulations are widely used to investigate the performance of simultaneous water and gas (SWAG) injection in an oil field. However, they usually use two-phase water and gas relative permeability functions (krg) and one of the known correlations (e.g., Stone, Baker) to calculate oil relative permeability in a three-phase displacement. Moreover, the same krg is used for all SWAG injections, irrespective of miscibility conditions or fraction of gas injected (FGI).Recent experiments have shown that gas relative permeability functions in three-phase SWAG are significantly different from the conventionally used two-phase functions. This paper investigates the impact of using experimentally estimated three-phase gas relative permeability functions on co-optimization study of CO2 storage and enhanced oil recovery (EOR). A three-dimensional, layered reservoir model initially saturated with oil and connate water is used to examine different injection schemes for co-optimizing oil recovery and CO2 storage efficiency. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane by molar fraction. Numerical simulations are run at 70 °C and at three pressures (1300, 1700, and 2100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. SWAG displacements are run at an FGI of 0.5 for immiscible, near-miscible and miscible conditions. Then the effect of FGI dependent relative permeability on co-optimization of CO2 storage and EOR is investigated in the near-miscible condition for FGI values 0.25, 0.5, 0.75 and 1.0.Experimentally estimated three-phase gas relative permeability results in lower CO2 mobility. This leads to higher CO2 saturation and lower water saturation at the end of simulation. The significant increase in CO2 storage efficiency and hence the co-optimization function are more prominent in near-miscible and miscible displacements than in immiscible. Although, for the homogeneous model, ultimate oil recovery is the same when two-phase or experimentally estimated three-phase relative permeabilities are used, ultimate recovery value is significantly affected in the heterogeneous reservoir model.

Mixing and spreading of multiphase fluids in heterogeneous bimodal porous media

We investigate the impact of heterogeneous bimodal porous media on fluid mixing and spreading in viscously-unstable flows. Previous studies have mostly studied miscible mixing and spreading behavior in unimodal media. We characterize the temporal evolution of these processes in bimodal media and under both miscible and partially miscible conditions. We model advection-diffusion transport of a finite volume of $$\hbox {CO}_2$$ diluting within a rectilinear background flow of a multicomponent compressible hydrocarbon fluid. Accurate numerical simulations are performed to capture the details of hydrodynamic instabilities as well as the heterogeneity channelling. Thermodynamic phase behavior and Fickian diffusion are represented based on rigorous equation of state. We generate by means of a Markov Chain approach the permeability fields that represent facies architecture by volume fractions of each facies unit. Our results show that bimodal media significantly alter the flow pattern and spreading dynamics, especially at lower proportions of the high-permeability facies. However, we find the miscible mixing to be less sensitive to bimodal media, as a result of a delicate balance between fingering and permeability channeling. On other hand, spreading is usually lower in partially miscible flows, but this can be overridden by channeling due to bimodal media. The new hydrothermodynamic mechanisms that predominantly drive most of the mixing in partially miscible systems are still in effect even in bimodal media regardless of the facies architecture. Therefore, partially miscible mixing is negligibly impacted by bimodal heterogeneity. Our qualitative and quantitative results elucidate the key flow processes resulting from bimodal structures, and also rationalize the distinct mixing and spreading behaviors that emerge differently from the interplay between hydrothermodynamic mechanisms and flow channeling.

Hydrothermodynamic mixing of fluids across phases in porous media

AbstractWe investigate the coupled dynamics of fluid mixing and viscously unstable flow under both miscible (single‐phase) and partially miscible (two‐phase) conditions, and in both homogeneous and heterogeneous porous media. Higher‐order finite element methods and fine grids are used to resolve the small‐scale onset of fingering and tip splitting. An equation of state determines the thermodynamic phase behavior and Fickian diffusion. We compute global quantitative measures of the spreading and mixing of a diluting slug to elucidate key differences between miscible and partially miscible systems. Hydrodynamic instabilities are the main driver for mixing in miscible flow. In partially miscible flow, however, we find that relative permeabilities spread the two‐phase zone. Within this mixing zone dissolution and evaporation drive mixing thermodynamically while reducing mobility contrasts and thus fingering instabilities. The different mixing dynamics in systems involving multiple phases with mutual solubilities have important implications in hydrogeology and energy applications, such as geological carbon sequestration and gas transport in hydrocarbon reservoirs.

Water film rupture in blocked oil recovery by gas injection: Experimental and modeling study

Water shielding phenomenon generally occurs after waterflooding in water-wet rocks, and impedes direct contact between the oil and the injected gas in tertiary gas injection processes. In this work, a set of visualization experiments were performed on micromodel patterns including designed dead-end pores with a film of water on the surface of pore bodies, which is a more realistic representation of porous media. The experiments were conducted at different miscibility conditions, and the required time for water to be displaced from the throat by the swelling of oil was measured for first contact miscible (n-C5/CO2) and immiscible (n-C10/CO2) systems. In the next step, a model was proposed to simulate the results of the experiments, based on the work of Bijeljic et al. (2003). As the impact of non-ideal mixing in this process has not been previously discussed in the available literature, the new model was developed by taking into account the changes in the partial molar volumes of oil and gas components using the PR and the SRK equations of state, and also by considering the mass transfer from the surrounding water on the pore body into the shielded oil. The rupture times predicted by the model were compared with the measured experimental data, as well as those reported by Campbell and Orr (1985). It was found that inclusion of partial molar volumes of components improves the accuracy of the model. The results also revealed the significant role of the water film on the pore body surfaces in mass transfer rate between the phases in water-wet media. The close agreement between the results of the model proposed in this study and the experimental data shows that it can be helpful for developing more accurate multiphase compositional models.

Experimental and simulation determination of minimum miscibility pressure for a Bakken tight oil and different injection gases

Abstract The effective development of unconventional tight oil formations, such as Bakken, could include CO 2 enhanced oil recovery (EOR) technologies with associated benefits of capturing and storing large quantities of CO 2 . It is important to conduct the gas injection at miscible condition so as to reach maximum recovery efficiency. Therefore, determination of the minimum miscibility pressure (MMP) of reservoir live oil–injection gas system is critical in a miscible gas flooding project design. In this work, five candidate injection gases, namely CO 2 , CO 2 -enriched flue gas, natural gas, nitrogen, and CO 2 -enriched natural gas, were selected and their MMPs with a Bakken live oil were determined experimentally and numerically. At first, phase behaviour tests were conducted for the reconstituted Bakken live oil and the gases. CO 2 outperformed other gases in terms of viscosity reduction and oil swelling. Rising bubble apparatus (RBA) determined live oil–CO 2 MMP as 11.9 MPa and all other gases higher than 30 MPa. The measured phase behaviour data were used to build and tune an equation-of-state (EOS) model, which calculated the MMPs for different live oil-gas systems. The EOS-based calculations indicated that CO 2 had the lowest MMP with live oil among the five gases in the study. At last, the commonly-accepted Alston et al. equation was used to calculate live oil–pure CO 2 MMP and effect of impurities in the gas phase on MMP change. The Bakken oil–CO 2 had a calculated MMP of 10.3 MPa from the Alston equation, and sensitivity analysis showed that slight addition of volatile impurities, particularly N 2 , can increase MMP significantly.

Oil recovery performance and permeability reduction mechanisms in miscible CO2 water-alternative-gas (WAG) injection after continuous CO2 injection: An experimental investigation and modeling approach

Asphaltene deposition and inorganic deposition are a serious problem because it may lead to the clogging of the reservoir and the reducing of oil production during miscible CO2 water-alternative-gas (CO2-WAG) injection or continuous CO2 injection process. In this study, first of all, the minimum miscibility pressure (MMP) of the crude oil-CO2 system was measured by using the slim-tube apparatus and obtained to be 22.95MPa. Then, the composite long coreflood experiment was conducted under miscible condition (i.e., Pop>MMP) to determine the ultimate recovery factor (RF) and the permeability reduction caused by asphaltene deposition and inorganic deposition in a tight sandstone reservoir. The results of the experiment found that, after the CO2 breakthrough (BT) of continuous CO2 flooding, the ensuing miscible CO2–WAG injection is able to enhance effectively the ultimate RF from 51.97% to 73.15% under miscible condition. It was obtained that the permeability reduction of the reservoir core as a result of asphaltene deposition is represented an increased wave-like pattern along the flow direction in the CO2-WAG injectionafter continuous CO2 injection process, which is comparable to the predicted results calculated by the solubility model. In addition, the permeability reduction due to inorganic deposition is also shaped as a wave-like mode along the flow direction, which is corresponding to the results of the content change of mineral ions in brine. Moreover, it was also found that the permeability reduction due to asphaltene deposition is much larger than the permeability reduction as a result of inorganic deposition and mainly occurs in the middle and rear of the reservoir in the miscible CO2–WAG injection after the continuous CO2 injection. Thus, for the ensuing miscible CO2–WAG injection after the continuous CO2 injection, such as Jilin reservoir, the injection of chemical inhibitor into the middle and rear of the reservoir is recommended as an effective and economical means to reduce the risk of asphaltene deposition and then sustain the oil production.

Oil Recovery Performance and CO2 Storage Potential of CO2 Water-Alternating-Gas Injection after Continuous CO2 Injection in a Multilayer Formation

In this study, oil recovery performance and carbon dioxide (CO2) storage potential of a CO2 water-alternating-gas (CO2-WAG) injection after continuous CO2 injection process for multilayer formation were experimentally determined under immiscible and miscible conditions. First, a slim-tube apparatus was used to measure the minimum miscibility pressure (MMP) of a CO2–crude oil system (MMP = 22.79 MPa), which was applied as a guide for follow-on investigations. Afterward, the CO2-WAG injection after the continuous CO2 injection for a triple-layer system, horizontally placed and parallel-connected, was conducted to evaluate the capacity of enhanced oil recovery and CO2 storage potential of the multilayer formation at different operating pressures and a reservoir temperature of 98 °C. Results revealed that the oil recovery of the entire system was determined by the recovery of a layer with the highest permeability, which was more than 90% of the entire system recovery provided by the highest permeability layer...

Experimental investigation of miscibility conditions of dead and live asphaltenic crude oil\u2013CO2 systems

Carbon dioxide (CO2) injection is a well-established enhanced oil recovery method. The optimization process of CO2 injection is usually performed through estimation of two physical properties, i.e., minimum miscibility and first-contact miscibility pressures (MMP and FCMP) for the crude oil–CO2 system. In this experimental study, the equilibrium IFT of the crude oil–CO2 system is measured at (313.15 and 323.15 K) for two oil types (i.e., live and dead crude oil) using the axisymmetric pendant drop shape analysis method. Vanishing interfacial tension technique is also applied to estimate the MMP and FCMP. The experimental results demonstrate that IFT decreases with different trends as the equilibrium pressure increases for the systems of live oil/CO2 and dead oil/CO2 systems. The IFT test results demonstrate that the estimated MMP and FCMP values of crude oil–CO2 system increase with temperature. It was also observed that the presence of methane gas in the oil phase increases the MMP value, whereas it decreases the FCMP.

An Experimental and Numerical Analysis of Water-Alternating-Gas and Simultaneous-Water-and-Gas Displacements for Carbon Dioxide Enhanced Oil Recovery and Storage

Summary This paper presents an experimental and numerical study that delineates the co-optimization of carbon dioxide (CO2) storage and enhanced oil recovery (EOR) in water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) injection schemes. Various miscibility conditions and injection schemes are investigated. Experiments are conducted on a homogeneous, outcrop Bentheimer sandstone sample. A mixture of hexane (C6) and decane (C10) is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. WAG displacements are performed at a WAG ratio of 1:1, and a fractional gas injection (FGI) of 0.5 is used for SWAG displacements. The effect of varying FGI is also examined for the near-miscible SWAG displacement. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil production is defined and calculated by use of the measured data for each experiment. The results of SWAG and WAG displacements are compared with the experimental data of continuous-gas-injection (CGI) displacements. A compositional commercial reservoir simulator is used to examine the recovery mechanisms and the effect of mobile water on gas mobility. Experimental observations demonstrate that the WAG displacements generally yield higher co-optimization function than CGI and SWAG with FGI = 0.5 displacements. Numerical simulations show a remarkable reduction in gas relative permeability for the WAG and SWAG displacements compared with CGI displacements, as a result of which the vertical-sweep efficiency of CO2 is improved. More reduction of gas relative permeability is observed in the miscible and near-miscible displacements than in the immiscible displacement. The reduced gas relative permeability lowers the water-shielding effect, thereby enhancing oil recovery and CO2-storage efficiency. More water-shielding effect is observed in SWAG with FGI = 0.5 than in WAG. However, increasing FGI from 0.5 to 0.75 in the near-miscible SWAG displacement shows a significant increase in oil recovery, which is attributed to reduced water-shielding effect. So, an optimal FGI needs to be determined to minimize the water-shielding effect for efficient SWAG displacements.

A novel protocol for estimation of minimum miscibility pressure from slimtube experiments

A slimtube experiment is an industry-accepted method for estimating minimum miscible pressure (MMP) of a reservoir fluid with respect to a particular injection gas. The displacement efficiency of the gas is evaluated at immiscible as well as at multi-contact miscible pressure conditions. Although experimental protocols and operational aspects vary among investigators, the MMP is often inferred from the bend of the oil recovery curve versus pressure. From an equation of state (EOS) calibration point of view, the experiments conducted below and near the MMP are more valuable than the miscible runs. Since the number of slimtube runs is often limited to 4–6, this means that the mass transfer in the near-miscible may not be adequately captured and the uncertainty in the MMP estimation can be significant.In this work, a modification to the standard slimtube experimental protocol is presented to overcome the inconsistency in the interpretation of the MMP and to provide more information about the mass transfer in the near-miscible region close to the MMP. The new protocol takes advantage of the fact that chromatographic separation occurs during two-phase flow at pressures below the MMP and it is shown that the C1/C3 ratio in the produced gas is a very useful parameter to track as a function of pressure. If all slimtube runs are conducted at pressures below MMP, an efficient iterative procedure can be implemented to select a limited number of pressure steps leading towards the MMP.The proposed method requires compositional analysis of the produced gas, which adds to the cost of a study but may require fewer slimtube runs while yielding a more accurate estimation of the MMP.

Oil recovery and CO2 storage in CO2 flooding

ABSTRACTIn this study, the interfacial tension (IFT) of crude oil-carbon dioxide mixtures was measured to determine the minimum miscibility pressure. CO2 flooding with sand packs, long cores, and heterogeneous cores was conducted to investigate the oil recovery and storage efficiency. The experiment results show that the interfacial tension decreases linearly with increasing pressure at two different pressure ranges. Under immiscible condition, the oil recovery and storage efficiency are increased by 30.1% and 52.4% when the injection pressure is increased from 13 to 22 MPa, and improved by 16.3% and 22.04% when the permeability is decreased from 270 to 10 mD, respectively. Under miscible condition, increase of injection pressure can only lead to much slower increase of oil recovery and storage efficiency, and permeability almost has no influence on oil recovery and storage efficiency. The oil recovery and storage efficiency can be remarkably reduced by heterogeneity. Water alternating CO2 injection can improve the oil recovery and storage efficiency by 35.5% and 13.55%, respectively, compared with continuous injection.

Experimental study of gas–oil relative permeability curves at immiscible/near miscible gas injection in highly naturally fractured reservoir

The main aim of this work is to investigate gas–oil relative permeability curves as the main flow function in different gas injection scenarios, immiscible and near miscible in case of highly fractured reservoirs.In this research, some experiments have been done on the reservoir core sample selected from sandstone formation in one of the Iranian naturally fractured oil reservoirs. The core is saturated with oil sample and CO2 is injected into oil saturated core sample. Experiments have been performed on both of the sandstone and artificial fractured sandstone, represented as no fractured and highly fractured reservoirs, based on incremental pressure algorithm approaching into near miscible condition. Inverse modeling method has been used to calculate relative permeability curves.By comparing the relative permeability curves in immiscible and near-miscible conditions, the results show that in sandstone core type this change is considerable, but in highly artificial fractured sandstone with a high ratio of artificial fractured to sandstone absolute permeability (Kef /Ks) is not substantial. Moreover the results show that in the described case of artificial fractured core type so simple conventional relative permeability methods have the same results compared to a sophisticated inverse modeling method. The other main result is the lack of miscibility activation in near miscible injection through the highly fractured reservoirs leading to viscose dominant flow rather than capillary.Finally by considering this changing behavior, a better knowledge of gas front movement through highly fractured reservoirs in low IFT regions can be obtained.

Effects of hydrocarbon solvents on simultaneous improvement in displacement and sweep efficiencies during CO2-enhanced oil recovery

ABSTRACTThe addition of hydrocarbon solvent such as liquefied petroleum gas (LPG) to the CO2 stream leads to miscible conditions in reservoirs at lower pressures by reducing the minimum miscibility pressure (MMP). Under miscible conditions, improved displacement and vertical sweepout occur simultaneously. The influences of LPG concentration and composition on the displacement and sweep efficiencies during CO2-LPG enhanced oil recovery (EOR) were investigated. Enhanced displacement efficiency was assessed through oil viscosity reduction and oil saturation change. Moreover, the miscible flooding induced by LPG addition, which resulted in increased solvent viscosity and a lower density difference between the injected fluid and reservoir oil, provided a smaller viscous gravity number, and improved the sweep efficiency, alleviating the impact of solvent gravity override. For CO2-LPG EOR, oil recovery increased up to 52% as compared with that for CO2 flooding. The amount of incremental oil recovery with 100% butane in the LPG was 16%, as compared with the 100% propane case. Mitigated gravity override enabled CO2-LPG EOR to enhance sweep efficiency. Results indicated that the compositional modeling of the EOR process with the addition of LPG provided more accurate prediction on the performance of CO2-LPG EOR.

Viscous and gravitational fingering in multiphase compositional and compressible flow

Viscous and gravitational fingering refer to flow instabilities in porous media that are triggered by adverse mobility or density ratios, respectively. These instabilities have been studied extensively in the past for (1) single-phase flow (e.g., contaminant transport in groundwater, first-contact-miscible displacement of oil by gas in hydrocarbon production), and (2) multi-phase immiscible and incompressible flow (e.g., water-alternating-gas (WAG) injection in oil reservoirs). Fingering in multiphase compositional and compressible flow has received much less attention, perhaps due to its high computational complexity. However, many important subsurface processes involve multiple phases that exchange species. Examples are carbon sequestration in saline aquifers and enhanced oil recovery (EOR) by gas or WAG injection below the minimum miscibility pressure. In multiphase flow, relative permeabilities affect the mobility contrast for a given viscosity ratio. Phase behavior can also change local fluid properties, which can either enhance or mitigate viscous and gravitational instabilities. This work presents a detailed study of fingering behavior in compositional multiphase flow in two and three dimensions and considers the effects of (1) Fickian diffusion, (2) mechanical dispersion, (3) flow rates, (4) domain size and geometry, (5) formation heterogeneities, (6) gravity, and (7) relative permeabilities. Results show that fingering in compositional multiphase flow is profoundly different from miscible conditions and upscaling techniques used for the latter case are unlikely to be generalizable to the former.

Investigation of gas injection flooding performance as enhanced oil recovery method

Asphaltene precipitation and deposition within the reservoir formation is one of the main concerns during enhanced oil recovery (EOR) processes especially during the gas injection. In the current study, different aspects of carbon dioxide (CO2) and nitrogen (N2) injection in the reservoir, was thoroughly examined. The feasibility of using these gases as the injection gas was explored using Bayesian network-based screening method. After recombination and preparation of the live crude oil, precipitation of asphaltene using vanishing interfacial tension (VIT) method and core flooding experimentation was examined. Besides, swelling test was utilized to investigate the effect of CO2 and N2 injection on the expansion of live crude oil. The obtained results showed that recovery factor (RF) of CO2 injected method in core flood test is higher than N2 injection due to higher swelling and better miscibility conditions. Although, VIT measurements showed asphaltene precipitation during CO2 injection, no sign of asphaltene deposition during core flood test at near bubble point pressure was observed.