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Phase behaviors including phase boundaries, volumes, and compositions of reservoir fluids during solvent(s)-assisted heavy oil recovery processes have been experimentally and theoretically determined in the presence of an aqueous phase. More specifically, a water-rich aqueous phase (A), an oil-rich liquid phase (L), and a solvents-rich vapor phase (V) can coexist under certain reservoir conditions. The phase boundary between AL and ALV on a pressure–temperature phase diagram, i.e., three-phase bubblepoint pressure, has been measured for C 3 H 8 –CO 2 –water–heavy oil systems at temperature ranging from 298.15 K to 383.15 K. The phase volumes of A + L and V at thermodynamic equilibrium state have been determined at temperatures of 321.55 K and 344.95 K, respectively. Moreover, the fluids in both L and V phases are sampled in an isobaric manner to perform the compositional analyses by using gas chromatography (GC) method. Meanwhile, two heavy oil samples are theoretically characterized as the multiple pseudocomponents. The Peng–Robinson equation of state (PR EOS) together with two recently developed alpha functions for water and non-water component(s) is applied as the primary thermodynamic model. A previously developed binary interaction parameter (BIP) correlation for CO 2 –water pair is combined with the van der Waals’ mixing rule to improve the phase behavior prediction for water-contained system. A volume translation method proposed by Peneloux et al. (1982) is then incorporated to correct the calculated phase volume. Without tuning any parameters, the developed water-associated and water-free mathematical models are found to be able to accurately reproduce the measured phase boundaries in the presence and absence of the aqueous phase, respectively. The three-phase bubblepoint pressure is found to be reduced in the presence of water. More accurate prediction can be achieved by considering the effect of aqueous phase. Finally, the GC analyses and flash calculations demonstrate that CO 2 is more easily to be vaporized than alkane solvent (i.e., C 3 H 8 ) when phase splitting occurs for a C 3 H 8 –CO 2 –water–heavy oil system.

In some low-permeable reservoirs, the miscibility pressure is far higher than the formation pressure, which makes it not feasible to have a CO2 miscible displacement. In this study, an oil-soluble surfactant, CAE, was designed and synthesized to reduce interfacial tension (IFT) and CO2-oil minimum miscible pressure (MMP), making it possible to release miscible displacement increasing oil recover. Experiment results showed that oil soluble surfactant can be dissolved in supercritical CO2 but not soluble in water. It is also found that the CAE preslug displacement has the higher displacement efficiency than displacement with the CAE dissolved in CO2. Based on a series of CAE preslug displacement experiments with varying CAE concentrations, the optimal injection concentration of CAE is 0.2%. Moreover the MMP determined under the CAE concentration of 0.2% is 6.1 MPa lower than that of pure CO2 displacement. It reduces the MMP more than liquid gas preslug displacement (3.2 MPa) when the same volume of ...

N-eicosane, N-tetracosane, N-octacosane and N-dotriacontane, which are heavy n-alkanes, were selected to form binary systems with CO2. The bubble point pressures of each system were obtained through a series of constant component expansion (CCE) experiments. Variation laws and mechanisms of multiphase boundary of heavy n-alkanes-CO2 systems were studied. As CO2 fraction increased, the bubble point pressure of heavy n-alkanes-CO2 systems increased greatly, and the bubble point pressure increased linearly with temperature. When CO2 molar fraction is less than 50%, the bubble point pressure of the heavy n-alkanes-CO2 systems decreased slightly with the increase of carbon number, and the decrease of pressure amplitude decreased with the decrease of CO2 mole fraction. When CO2 molar fraction was 75%, the bubble point pressure of different heavy n-alkane systems increased slightly with the increase of carbon number. When CO2 molar fraction was less than 50%, with the increase of the carbon number, the influence of temperature variation on the bubble point pressure of systems decreased. When CO2 molar fraction was equal to 75%, with the increase of the carbon number, the influence of temperature variation on the bubble point pressure of heavy n-alkanes-CO2 systems did not change. On the analysis of micro scale, the reason for variation laws above is that the long chains and large intermolecular interval of heavy n-alkane has ability to accommodate CO2 molecules and its chain is prone to twist. Key words: C16+ heavy n-alkanes, CO2, multiphase boundary, CCE experiment, bubble point pressure

Simulative experiments were carried out for CO2 foam flooding process in homogeneous porous media prepared with the sand packing method, and the CO2 foam seepage characteristics in porous media were studied with CT technology. CO2 foam flooding experiments were carried out under different packing sand sizes, different surfactant concentrations and different gas-liquid ratios. CT technology was employed to visualize the displacement process and to obtain the water saturation data along the sample, and the pressure distribution in the sample during the foam seepage process was measured at the same time. Experimental results show that, CO2 foam flooding has higher pressure drop and lower water saturation entrance effect in the porous media with lower average grain sizes; when surfactant concentrations are higher than CMC (Critical Micelle Concentration), the generated foam is stable, without showing obvious difference for the foam displacement efficiency in the sample, and water saturation entrance effect gradually decreases with increase of surfactant concentrations; improving gas-liquid ratio can lead to higher foam seepage pressure drop, but has little effect on residue water saturation after foam displacement. Key words: CO2 flooding, CO2 foam, flooding experiment, seepage characteristics, CT technology, EOR

The application and characteristics of CO2 flooding in the USA were analyzed and summarized. Supporting techniques of CO2 flooding were generalized, and then the enlightenment was expounded for CO2 flooding in China. The development process and forming reasons of CO2 flooding technology were analyzed and summarized based on systematic tracking of EOR survey data all over the world and sufficient investigation of CO2-EOR technology application. With the number of CO2 flooding projects, scale and annual production as indicators, the current situation of American CO2-EOR technology was evaluated. The characteristics of the projects and development-driving force of CO2 flooding in America were also summed up. The characteristics of formation properties, crude oil properties and project timings of American CO2 miscible flooding projects were outlined emphatically. Meanwhile, the application scale and reservoir adaptability differences between American CO2 miscible and immiscible flooding were comparatively analyzed. A series of supporting techniques were illuminated with the SACROC CO2 flooding project as an example. The challenges, technical bottlenecks and suggestions were analyzed and proposed for the promotion of CO2 miscible flooding technology in China. Key words: CO2 flooding, miscible flooding, immiscible flooding, gas driving, enhanced oil recovery

The existing viscosity models, including LBC (Lohrenz-Bray-Clark) Model, CS (Pedersen) Model and PR (based on PR Equation of State) Model, could not take into account accuracy, theory strictness and calculation convenience simultaneously. This study considers temperatures, pressures and interaction between components and other affecting factors to improve the viscosity model based on PR EOS (equation of state) and finally establishes a new calculation model for CO2-crude system under high pressures and high temperatures. The accuracy of the PR model is improved by changing the dimensionless constant in the model into a function related to the system temperatures. Furthermore, the mixing-rule in viscosity calculation of mixture is modified through introducing the binary interac tion factor and effective mole fraction of CO2. Based on gas and liquid phase components of field oil samples from actual measurement, the calculation accuracy of models before and after improvement are compared, which shows that the new viscosity model is not only simple in computation, but also much more accurate, and finally meets the industrial requirements. Key words: CO2-crude system, viscosity model, PR EOS, viscosity mixing-rule

A great number of published data and our experimental results of interfacial tensions between hydrocarbon compounds and CO2 were collected and screened. Based on these experimental data, the changing laws of interfacial tensions between different kinds of hydrocarbon compounds and CO2 were obtained, interfacial tensions between different kinds of saturated chain hydrocarbons and CO2 were compared with each other, and interfacial tensions of three different binary system (monocyclic hydrocarbon compounds-CO2 system, hydrocarbon compounds monocyclic and chain structure-CO2 system and dicyclic hydrocarbon compounds-CO2 system) were compared with those of saturated chain hydrocarbon compounds-CO2 system. It is found that molecular structure is the main factor to affect the sizes of interfacial tensions between hydrocarbon compounds and CO2; when carbon numbers of different kinds of hydrocarbon compounds are equal, their proper order from big to small in interfacial tension is: polycyclic hydrocarbon, hydrocarbon monocyclic and chain structure, monocyclic hydrocarbon, saturated chain hydrocarbon. The comparison results at different pressure conditions were respectively used to establish the conversion relations in equivalent carbon number between interfacial tensions of cyclic hydrocarbon-CO2 systems and those of saturated chain hydrocarbon-CO2 systems. Key words: saturated chain hydrocarbon, cyclic hydrocarbon, CO2, interfacial tension, equivalent carbon number, conversion relation

The injection of fuel-generated CO2 into oil reservoirs will lead to two benefits in both enhanced oil recovery (EOR) and the reduction in atmospheric emission of CO2. To get an insight into CO2 miscible flooding performance in oil reservoirs, a multi-compositional non-isothermal CO2 miscible flooding mathematical model is developed. The convection and diffusion of CO2-hydrocarbon mixtures in multiphase fluids in reservoirs, mass transfer between CO2 and crude, and formation damages caused by asphaltene precipitation are fully considered in the model. The governing equations are discretized in space using the integral finite difference method. The Newton-Raphson iterative technique was used to solve the nonlinear equation systems of mass and energy conservation. A numerical simulator, in which regular grids and irregular grids are optional, was developed for predicting CO2 miscible flooding processes. Two examples of one-dimensional (1D) regular and three-dimensional (3D) rectangle and polygonal grids are designed to demonstrate the functions of the simulator. Experimental data validate the developed simulator by comparison with ID simulation results. The applications of the simulator indicate that it is feasible for predicting CO2 flooding in oil reservoirs for EOR.

An improved CO2–oil minimum miscibility pressure (MMP) correlation has been successfully developed to more accurately determine the CO2–oil MMP for a wide range of live and dead crude oils. Experimentally, slim-tube tests have been conducted to determine the CO2–oil MMPs for four crude oil samples with high molecular weights of C7+ fraction. Theoretically, the newly developed CO2–oil MMP correlation is originated from a CO2–oil MMP database from the literature that covers 51 CO2–oil MMP data for various live and dead oil samples, especially those with high C7+ molecular weights. The new CO2–oil MMP correlation is expressed as a function of reservoir temperature, C7+ molecular weight, and mole fraction ratio of volatile components (N2 and CH4) to intermediate components (CO2, H2S, and C2–C6). Compared to nine commonly used CO2–oil MMP correlations in the literature, it is found that the new CO2–oil MMP correlation provides the best reproduction of the literature CO2–oil MMP data with a percentage average a...

It is a challenging task to model nonequilibrium gas flows within a continuum-fluid framework. Recently some extended hydrodynamic models in the Navier-Stokes formulation have been developed for such flows. A key problem in the application of such models is that suitable boundary conditions must be specified. In the present work, a generalized second-order slip boundary condition is developed in which an effective mean-free path considering the wall effect is used. By combining this slip scheme with certain extended Navier-Stokes constitutive relation models, we obtained a method for nonequilibrium gas flows with solid boundaries. The method is applied to several rarefied gas flows involving planar or curved walls, including the Kramers' problem, the planar Poiseuille flow, the cylindrical Couette flow, and the low speed flow over a sphere. The results show that the proposed method is able to give satisfied predictions, indicating the good potential of the method for nonequilibrium flows.

CO2 flooding is one of the most effective and used methods for enhanced oil recovery (EOR) approaches. The number of CO2 flooding projects has increased rapidly in China and around the world. Compositional simulation is required for evaluating CO2 flooding in EOR operations, especially for miscible or nearly miscible flooding when black-oil simulation is no longer adequate. The simulation method proposed here is a multi-dimensional, three-phase, and compositional modeling approach, which is applicable to both porous and fractured reservoirs. In the model formulation, a generalized multi-continuum approach is adopted to handle flow and transport in naturally fractured reservoirs and the mass flux of each mass component is contributed by advection and diffusion processes. In addition, precipitation of heavy oil components and absorption of CO2 on the solid grains are modeled based on reversible linear or nonlinear isotherms. The governing partial differential equations for conservation of each component are discretized using a finite volume method and the resulting discrete equations are solved fully implicitly by Newton-Raphson iteration. The equation of state (EOS) by Soave-Redlich-Kwong is used to calculate the physical properties of fluids. Research has shown that the flash calculations with EOS in compositional simulation are computationally intensive and may not be reliable at near critical conditions. Therefore, a K-value based approach, improved by Almehaideb et al. (2002), is used for partitioning of oil components and CO2 between oil and CO2 phases. In addition, the laboratory measured oil and CO2 phase compositional data can be used alternatively to account for compositional effect in this model. Two numerical examples are presented to show that the proposed modeling method is efficient for simulation of CO2 flooding processes in EOR operations.

Asphaltene, which exists in crude oil, is a high molecular weight, polar component. It is widely believed that asphaltene may precipitate and plug pores of reservoir rock and induce wettability alteration for the changes in oil composition, reservoir pressure and temperature. Therefore, alphaltene precipitation in the pores of oil formation definitely leads to formation damage and wettability alteration. The mechanisms caused asphaltene precipitation have been researched in labs and the key factors to effect the precipitation have been well understood, but prediction for its quantitative damages for oil formation, wettability alteration and their effects on percolation performance are still uncertain. In this work, a mathematical model considering asphaltene precipitation and wettability alteration is presented and an oil field scaled numerical simulator is developed to predict for asphaltene precipitation problems in the development of oil field. The simulation results show that the porosity and permeability in the vicinity of production wellbore decrease dramatically for asphaltene precipitation. The water-cut increases for the increase in the effective permeability of oil phase and the decrease in the effective permeability of water for the wettability alteration induced by asphaltene deposition onto the pore surfaces.

Injection of CO2 into oil reservoirs is a smart operation for the fact that it is not only to enhance oil recovery (EOR), but also to reduce carbon dioxide emission as it is one of greenhouse gases. However, either in a CO2 miscible or in a CO2 immiscible displacement process, the injected CO2 into the oil formation can induce flocculation and deposition of asphaltene. This can cause numerous production problems with a detrimental effect on the permeability and oil production. Moreover, wettability of oil reservoir rock may change for asphaltene adsorption on pore surfaces due to the polarity of asphaltene. Based on the understanding the behavior of this organic matter under reservoir conditions, a mathematical model considering asphaltene precipitation and wettability alteration is presented and an oil field scaled numerical simulator is developed to predict for asphaltene precipitation problems during CO2 flooding. The simulation results show that the porosity and permeability in the area swept by CO2 and the vicinity of injection well bore decrease for asphaltene precipitation, pressure gradients become larger than numerical results ignoring asphaltene precipitation. Before CO2 breakthrough at production wells, the performance of production wells has not been affected obviously by asphaltene deposition. However, after CO2 breakthrough at production wells, the formation damage occurs in the vicinity of production well bore and leads to decrease dramatically in permeability and production rate.

Summary When some heavy-oil reservoirs are produced using gas drive, they show three important features: low production gas/oil ratios, higher-than-expected production rates, and relatively high oil recovery. The mechanism for this unusual behavior remains controversial and poorly understood, though the term "foamy oil" is often used to describe such behavior. The impetus for this work stems from some recent projects performed in the Orinoco belt, Venezuela. There exist nearly one trillion bbl of heavy oil (oil in place) in this region on the basis of a recent evaluation. Two crucial issues must be addressed before or during designing production projects: What is a suitable method for evaluating the foamy-oil drive mechanism that plays a major role during such oil recovery, and how do we obtain a reasonable percentage of ultimate oil recovery? Unfortunately, it is still difficult to give good explanations for these two issues, although several studies were performed. This paper attempts to present better explanations for these two issues using experimental drainage in a long laboratory core in simulated reservoir conditions. Our experiments show that ultimate oil recovery for the heavy oil in the Orinoco belt can be as high as 15-20%. This high recovery comes from three contributions: fluid and rock expansion, foamy-oil drive, and conventional-solution-gas drive. Approximately 3-5% of recovery is from fluid and rock expansion, 11-16% from foamy-oil drive, and 2-4% from conventional-solution-gas drive. This ultimate-oil-recovery percentage is much higher than the 12% that has been used in the field-development plan for the Orimulsion project. The experiments performed and their findings obtained in this paper are representative at least in the Orinoco belt region.