Phase Behaviour of Alkane Solvent(s)-CO2- Water-Heavy Oil Systems at High Pressures and Elevated Temperatures PDF Download
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Author: Xiaoli Li
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Languages : en
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Author: Xiaoli Li
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Languages : en
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Author: Desheng Huang
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Languages : en
Pages : 0
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The hybrid steam-solvent injection processes have been proved to be a promising technique for enhancing heavy oil recovery as they combine the advantages from both heat transfer of steam and mass transfer of solvent(s) to further reduce the viscosity of heavy oil. Multiphase isenthalpic flash calculation is required in compositional simulations of the aforementioned processes, which involve vapour, oleic, and aqueous three-phases since water is inevitably associated with steam injection processes. As such, it is of fundamental and pragmatic importance to accurately quantify the phase behaviour of solvent(s)/water/heavy oil systems at high pressures and elevated temperatures by use of isenthalpic flash algorithms. A modified correlation and a new enthalpy determination algorithm have been developed to more accurately predict ideal gas heat capacities and enthalpies for normal alkanes/alkenes and hydrocarbon fractions, respectively. By assuming that only the presence of water and solvents with high solubilities in water is considered in the aqueous phase, a robust and pragmatic water-associated isenthalpic flash (WAIF) model has been developed to perform multiphase isenthalpic flash calculations for solvent(s)/water/heavy oil mixtures at high pressures and elevated temperatures. The new isenthalpic flash model developed in this work can handle multiphase equilibria flash calculations at high pressures and elevated temperatures. Subsequently, phase boundaries of C3H8/CO2/water/heavy oil mixtures in both the pressure-temperature (P-T) and enthalpy-temperature (H-T) phase diagrams have been determined, respectively. Experimentally, the phase boundary pressures are determined for three C3H8/CO2/water/heavy oil mixtures by using a conventional pressurevolume- temperature (PVT) setup in the P-T phase diagram. Theoretically, the previously developed WAIF model and the new isenthalpic determination algorithm together with the new alpha functions for water and non-water components are applied as the thermodynamic model to reproduce the multiphase boundaries of the aforementioned systems. The water-associated model is able to provide a good prediction of the experimental measurement in terms of phase boundaries and phase compositions. In addition, a new algorithm is developed to determine vapour/liquid/ liquid (VL1L2) phase boundaries of alkane solvent(s)/CO2/heavy oil mixtures. A new thermodynamic model based on the modified Peng-Robinson equation of state (PR EOS) together with the Huron-Vidal mixing rule is developed to experimentally and theoretically quantify the phase behaviour of dimethyl ether (DME)/water/heavy oil mixtures which include polar components. The new model is capable of accurately reproducing the experimentally measured multiphase P-T and H-T boundaries, phase volumes, and swelling factors, while it can also be used to determine DME partition coefficients and DME solubility.
Author: Zulong Zhao
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Languages : en
Pages : 0
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During the primary stage, the in-situ generated foamy oil has been found to be responsible for an unexpected high recovery factor, a remarkably low gas-oil ratio (GOR), and a higher-than-expected well production rate. Such a phenomenon can also be artificially induced by injecting alkane solvents (e.g., methane and propane) or CO2 to a heavy oil reservoir; however, the gas exsolution of foamy oil is not yet well understood due mainly to the complicated physical processes. On the other hand, the associated emulsifications resulted from the in-situ generated surfactant(s) during alkaline flooding in a heavy oil reservoir lead to an increase in oil recovery, though no theoretical models have been made available to quantify such physical phenomena at high pressures and elevated temperatures. Physically, both gas exsolution and emulsification are closely associated with the nonequilibrium phase behaviour. Therefore, it is of fundamental and pragmatic importance to accurately quantify the nonequilibrium phase behaviour of the alkane solvent(s)-CO2/alkaline water-heavy oil systems under reservoir conditions. A novel and pragmatic technique has been developed and validated to quantify gas exsolution of alkane solvent(s)-CO2-heavy oil systems under nonequilibrium conditions. Experimentally, constant composition expansion (CCE) tests of alkane solvent(s)-CO2- heavy oil systems are conducted with a visualized PVT cell. Theoretically, a mathematical model which integrates the Peng-Robinson equation of state (PR EOS), Fick's second law, and nonequilibrium boundary conditions has been developed. It is found that the rising of experiment temperature and pressure has negative effects on diffusion coefficient during gas exsolution processes. At a higher temperature, a larger CO2 diffusion coefficient is observed, whereas, for alkane solvents (i.e., CH4 and C3H8), a lower diffusion coefficient is attained. Also, experimental and theoretical techniques have been developed to quantify the emulsion behaviour of alkaline water-heavy oil systems at high pressures and elevated temperatures. Experimentally, oil in water (O/W) emulsions with different settling times were prepared in order to track the continuous water content distribution along time. Theoretically, two groups of population balance equations (PBEs) were applied to quantify the phase behaviour during the emulsion destabilization. By applying the emulsion inversion point (EIP) as the boundary condition, the newly developed model is able to reproduce the dynamic water content distribution in the dual-emulsion systems. Due to the corresponding changes of oil viscosity and interfacial tension (IFT), either an increase in temperature or a decrease in pressure leads to a smaller EIP and higher coalescence efficiency. As a weak alkali, Na2CO3 facilitates the stabilization of the emulsion and inhibits the influence of higher temperatures, while NaOH solution-heavy oil systems achieve emulsion inversion more easily.
Author: Huazhou Li
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Languages : en
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Author: Zehua Chen
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Languages : en
Pages : 0
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Due to the excess heat loss of steam assisted gravity drainage (SAGD) processes and low oil production rate of solvent-based processes, the expanding solvent SAGD (ES-SAGD) process has been considered as a promising technique for enhancing heavy oil/bitumen recovery. The main ES-SAGD mechanisms include the heat transferred and dissolution of solvents into the heavy oil/bitumen to swell it and reduce its viscosity, which is closely related to the phase behaviour of solvents-heavy oil/bitumen-water systems. Thus, it is of fundamental and practical importance to accurately quantify the phase behaviour and physical properties of the aforementioned systems. A pragmatic technique has been developed to optimize the reduced temperature for acentric factor for the Peng-Robinson equation of state (PR-EOS) and Soave-Redlich- Kwong equation of state (SRK-EOS) by minimizing the deviation between the measured and calculated vapour pressures. The reduced temperature has its optimum value of 0.59 for the two EOSs, while 0.60 is recommended for practical use. The mutual solubility for n-alkanes/n-alkylbenzenes-water pairs is correlated using the PR-EOS together with the two newly modified alpha functions. The binary interaction parameters (BIPs) for both aqueous phase and liquid hydrocarbon phase are generalized as functions of reduced temperatures and carbon numbers of hydrocarbons, reproducing the experimental measurements well. Then, the modified PR-EOS model is successfully applied to predict the multi-phase compositions and three-phase upper critical ending points (UCEPs) for n-alkane-CO2-water mixtures. A new correlation has been developed to calculate the redefined acentric factor for pseudocomponents (PCs), while new BIP correlations are proposed respectively for ii toluene-water pair and heavy oil/bitumen-water pairs. The BIP correlation for heavy oil/bitumen-water pairs is validated by the measured water solubility in other oils. The newly developed model is found to accurately predict the measured ALV/AL (A is the aqueous phase, L represents the oleic phase, and V denotes the vapour phase) and LV/L boundaries with an overall average absolute relative deviation (AARD) of 4.5% and solvent solubility in the oleic phase with an overall AARD of 9.4%, respectively. Two new methods have been proposed to predict the density/swelling factor for solvents-heavy oil/bitumen/water mixtures, i.e., one is a new volume translation (VT) strategy for PR-EOS, while the other is the ideal mixing rule with effective density (IME) calculated using a newly developed tangent-line method. It is found that both of these two methods are accurate enough, while the IM-E is better than the VT PR-EOS. Experiments for C3H8/CO2-Lloydminster heavy oil/water systems have been performed in a temperature range of 328.7-432.3 K. A dynamic volume analysis method is proposed to simultaneously simulate the total volume and height of vapour/oleic phase interface, while a new framework incorporated with the modified PR-EOS can be used to accurately predict the solvent solubility, phase boundary, and phase density for the aforementioned systems. Also, six widely used mixing rules have been respectively evaluated, while water is incorporated using the ideal mixing rule. The order of the best ones in their accuracy is the volume-based power law > the weight-based power law > the weight-based Cragoe's mixing rule. The effective density rather than real density of dissolved gas should be used for all the volume-based mixing rules.
Author: Sixu Zheng
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Languages : en
Pages : 0
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The tremendous heavy oil reserves have recently attracted considerable attention for sustaining the increasing global oil consumption. Heavy oil reservoirs are characterized by high oil viscosity and drastic drop of reservoir pressure in a short period during production, imposing great challenges to recover such heavy oil resources. In practice, conventional steam-based thermal recovery techniques are generally ineffective or uneconomical in thin heavy oil reservoirs due to operational and environmental constraints. Since CO2 is a highly soluble, low cost, and environment-friendly injectant, hot CO2 injection is alternatively considered to be a promising technique for enhancing heavy oil recovery from these thin reservoirs. Not only does it take advantages of both thermal energy and dissolution of solvents to recover heavy oil resources, but also it contributes to the alleviation of carbon footprint. Compared with the CO2-alone processes, addition of alkane solvents to the CO2 stream leads to enhanced viscosity reduction and swelling effect of heavy oil. Thus, it is of fundamental and practical importance to study the underlying mechanisms of hot alkane solvent(s)-CO2 processes for enhancing heavy oil recovery at high pressures and elevated temperatures. In order to more accurately determine the equilibrium phase properties for alkane solvent(s)-CO2-heavy oil systems with the Peng-Robinson equation of state (PR EOS), heavy oil is characterized as multiple pseudocomponents, while a volume translation strategy is employed to improve its prediction performance. The binary interaction parameter (BIP) correlations are tuned with the experimentally measured saturation pressures for the same heavy oil. Such volume-translated PR EOS with a modified alpha function incorporating the tuned BIP correlations is capable of accurately predicting the saturation pressures and swelling factors of the aforementioned systems. The alkane solvent-CO2-heavy oil pressure decay systems under a constant temperature have been theoretically modelled to not only examine the effect of adding alkane solvents into CO2 stream, but also determine both apparent diffusion coefficient of a gas mixture and individual diffusion coefficient of each component in heavy oil. It is found that alkane solvents (i.e., C3H8 and n-C4H10) diffuse much faster than CO2 in heavy oil at reservoir temperature. Compared to pure CO2, addition of C3H8 into the CO2 stream tends to accelerate the swelling of heavy oil under similar conditions. Experimental and theoretical techniques have also been developed to couple heat and mass transfer for hot CO2-heavy oil systems with and without addition of alkane solvents. Both molecular diffusion coefficient of each component and apparent diffusion coefficients of alkane solvent(s)-CO2 mixtures are determined once the discrepancy between the measured and calculated dynamic swelling factors has been minimized. The thermal equilibrium is found to achieve in a much shorter time than mass equilibrium. CO2 diffusion coefficient in heavy oil increases with temperature at a given pressure. Compared with hot CO2 injection, addition of C3H8 into hot CO2 stream contributes to an enhanced swelling effect of heavy oil. A higher concentration of C3H8 in the CO2-C3H8 mixture tends to accelerate gas diffusion and thus induce a stronger oil swelling. Among the n-C4H10-heavy oil system, n-C4H10-CO2-heavy oil system, and C3H8-n-C4H10-CO2- heavy oil system, smaller dynamic swelling factors are obtained for the n-C4H10-heavy oil system, while the largest dynamic swelling factor of 1.118 at the end of diffusion test is achieved for the C3H8-n-C4H10-CO2-heavy oil system.
Author: Yu Shi
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Languages : en
Pages : 0
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During primary heavy oil recovery, a unique phenomenon has been found to be closely associated with an unexpected high recovery factor, a remarkably low gas-oil ratio, and a higher-than-expected well production rate due mainly to the foamy nature of viscous oil containing gas bubbles. Even for secondary and tertiary recovery techniques, it is possible to artificially induce foamy oil flow in heavy oil reservoirs by dissolution with injected gases (e.g., CO2 and alkane solvents), which is characterized by time-dependent (i.e., nonequilibrium) phase behaviour. The entrained gas bubbles in the heavy oil are considered as the main mechanism accounting for such distinct phase behaviour. Therefore, it is of fundamental and practical importance to quantify the nonequilibrium phase behaviour and mass transfer of alkane solvent(s)-CO2-heavy oil systems under reservoir conditions. A novel and pragmatic technique has been firstly developed and validated to accurately quantify the preferential diffusion of each component in alkane solvent(s)- assisted recovery processes with consideration of natural convection induced by the heated and diluted heavy oil. The Peng-Robinson equation of state, heat transfer equation, and diffusion-convection equation are coupled to describe both mass and heat transfer for the aforementioned systems. The individual diffusion coefficient between each component of a gas mixture and liquid phase is respectively determined once either the deviation between the experimentally measured and theoretically calculated mole fraction of CO2/solvents or the deviation between the experimentally measured dynamic swelling factors and the theoretically calculated ones has been minimized. ii A robust and pragmatic technique has also been developed to quantify nonequilibrium phase behaviour of alkane solvent(s)-CO2-heavy oil systems at a constant volume expansion rate and a constant pressure decline rate, respectively. Experimentally, constant-composition expansion (CCE) tests have been conducted for alkane solvent(s)-CO2-heavy oil systems with a PVT setup, during which not only pressure and volume are simultaneously monitored and measured, but also gas samples were respectively collected at the beginning and the end of experiments to perform compositional analysis. Theoretically, mathematical formulations have been developed to quantify the amount of the evolved gas as a function of time, while mathematical models for compressibility and density of the oleic phase mixed with the entrained gas (i.e., foamy oil) are respectively formulated. In addition to a mechanistic model for quantifying a single gas bubble growth, a novel and pragmatic technique has been proposed and validated to quantify dynamic volume of foamy oil for the aforementioned systems under nonequilibrium conditions by taking preferential mass transfer of each component in a gas mixture into account. The individual diffusion coefficient of each gas component with consideration of natural convection is found to be larger than that obtained with conventional methods. An increase in either volume expansion rate or pressure decline rate would increase the critical supersaturation pressure, whereas a high temperature leads to a low critical supersaturation pressure. When pressure is below the pseudo-bubblepoint pressure, density and compressibility of foamy oil are found to sharply decrease and increase at the pseudo-bubblepoint pressure, respectively. Also, pseudo-bubblepoint pressure and rate of gas exsolution is found to be two mechanisms dominating the volume-growth rate of the evolved gas, which is directly proportional to supersaturation pressure, pressure decline rate, and concentration of each gas component under nonequilibrium conditions.
Author: Jianchao Cai
Publisher: MDPI
ISBN: 3038977942
Category : Science
Languages : en
Pages : 258
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Due to the influence of pore-throat size distribution, pore connectivity, and microscale fractures, the transport, distribution, and residual saturation of fluids in porous media are difficult to characterize. Petrophysical methods in natural porous media have attracted great attention in a variety of fields, especially in the oil and gas industry. A wide range of research studies have been conducted on the characterization of porous media covers and multiphase flow therein. Reliable approaches for characterizing microstructure and multiphase flow in porous media are crucial in many fields, including the characterization of residual water or oil in hydrocarbon reservoirs and the long-term storage of supercritical CO2 in geological formations. This book gathers together 15 recent works to emphasize fundamental innovations in the field and novel applications of petrophysics in unconventional reservoirs, including experimental studies, numerical modeling (fractal approach), and multiphase flow modeling/simulations. The relevant stakeholders of this book are authorities and service companies working in the petroleum, subsurface water resources, air and water pollution, environmental, and biomaterial sectors.
Author: Hyun Woong Jang
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Languages : en
Pages : 0
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For a thin heavy oil reservoir where thermal methods are not applicable due to heat loss to over- and under-burdens, gas injection is considered to be an effective alternative. One of the major mechanisms associated with gas injection is the molecular diffusion of dissolved gas(es) which reduce the viscosity of heavy oil while inducing oil swelling. Physically, addition of a less volatile gas to a more volatile gas enhances both viscosity reduction and oil swelling, while the presence of porous media complicates such mass transfer processes. Diffusivity of dissolved gas(es) in heavy oil is often estimated as a constant, while limited attempts have been made to determine it as a function of concentration in the absence and presence of porous media. In this study, a power-law mixing rule is firstly developed to correlate apparent diffusivity of a binary gas mixture in heavy oil with the diffusivity of each pure gas based on the principle of corresponding states. Comparison of the correlated results with the measured data from literature proves that the correlation can be used to accurately predict the apparent diffusivities of binary gas mixtures. To verify the effect of a gas component on the other in a binary gas mixture diffusing in heavy oil, the cross-term diffusivities are estimated for a CO2-C3H8 mixture as well as its main-term diffusivities using the experimental data from Li et al. (2017b). It is found that the existence of a gas with a high concentration at the gas-heavy oil interface enhances the mass transfer of the other gas component through the cross-term diffusivity by generating a high concentration gradient. Then, a generalized methodology has been developed to determine the diffusivity of a gas (e.g., CO2) in a heavy oil as an exponential function of gas concentration with consideration of oil swelling applying the test data from Li et al. (2017b) and Li and Yang (2016). The obtained concentration-dependent diffusivity of CO2 is reasonable and accurate as well as it can be converted for use at different pressures and temperatures. Further, a robust and pragmatic technique has been developed for the first time to implicitly evaluate the concentration-dependency of diffusivity for each component in a binary gas mixture diffusing in heavy oil as a power function of oil viscosity. As for the C3H8/CO2-heavy oil systems, the dependency of C3H8 diffusivity on the gas concentration is significantly higher than that of CO2 diffusivity. Lastly, the conventional pressure decay technique has been improved and extended to determine the effective diffusivity of either a pure gas or each component in a binary gas mixture in an unconsolidated porous medium saturated with heavy oil. Effective diffusivities are determined by matching the measured gas compositions in liquid-phase at the end of pressure decay tests with the calculated ones. Such determined effective diffusivity of C3H8 is found to be larger than that of CO2, which is in accordance with previous studies performed for the same gases diffusing in the same bulk heavy oil, although the porous medium hinders the mass transfer of gas(es).
Author:
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Languages : en
Pages : 56
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Under previous support from the Department of Energy, an experimental facility has been established and operated to measure valuable vapor-liquid equilibrium data for systems of interest in the production and processing of coal fluids. To facilitate the development and testing of models for prediction of the phase behavior for such systems, we have acquired substantial amounts of data on the equilibrium phase compositions for binary mixtures of heavy hydrocarbon solvents with a variety of supercritical solutes, including hydrogen, methane, ethane, carbon monoxide, and carbon dioxide. The present project focuses on measuring the phase behavior of light gases and water in Fischer-Tropsch (F-T) type solvents at conditions encountered in indirect liquefaction processes and evaluating and developing theoretically-based correlating frameworks to predict the phase behavior of such systems. Specific goals of the proposed work include (a) developing a state-of-the-art experimental facility to permit highly accurate measurements of equilibrium phase compositions (solubilities) of challenging F-T systems, (b) measuring these properties for systematically-selected binary, ternary and molten F-T wax mixtures to provide critically needed input data for correlation development, (c) developing and testing models suitable for describing the phase behavior of such mixtures, and (d) presenting the modeling results in generalized, practical formats suitable for use in process engineering calculations. During the present reporting period, our solubility apparatus was refurbished and restored to full service. To test the experimental apparatus and procedures used, measurements were obtained for the solubility Of C02 in benzene at 160°F. Having confirmed the accuracy of the newly acquired data in comparison with our previous measurements and data reported in the literature for this test system, we have begun to measure the solubility of hydrogen in hexane. The measurements for this system will cover the temperature range from 160 to 280°F at pressures to 2,500 psia. As part of our model evaluation efforts, we examined the predictive abilities of an alternative approach we have proposed for calculating the phase behavior properties of highly non-ideal systems. Using this approach, the liquid phase fugacities generated from an equation of state (EOS) are augmented by a fugacity deviation function correction. The correlative abilities of this approach are compared with those of an EOS equipped with the recently introduced Wong-Sandler (MWS) mixing rules. These two approaches are compared with the current methods for vapor-liquid equilibrium (VLE) calculations, i.e., the EOS (0/0) approach with the van der Waals mixing rules and the split (y/0) approach. The evaluations were conducted on a database comprised of non-ideal low pressure binary systems as well as asymmetric high pressure binary systems. These systems are of interest in the coal liquefaction and utilization processes. The Peng-Robinson EOS was selected for the purposes of this evaluation.
