Download or read book Quantification of Nonequilibrium Phase Behaviour of Alkane Solvents CO2 alkaline Water heavy Oil Systems Under Reservoir Conditions written by Zulong Zhao and published by . This book was released on 2022 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: 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.

Download or read book Nonequilibrium Phase Behaviour and Mass Transfer of Alkane Solvents s CO2 Heavy Oil Systems Under Reservoir Conditions written by Yu Shi and published by . This book was released on 2017 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: 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.

Download or read book Phase Behaviour of Alkane Solvent s CO2 Water Heavy Oil Systems at High Pressures and Elevated Temperatures written by Xiaoli Li and published by . This book was released on 2015 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Phase Behaviour and Mass Transfer of Solvent s CO2 heavy Oil Systems Under Reservoir Conditions written by Huazhou Li and published by . This book was released on 2013 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Quantification of Phase Behaviour and Physical Properties of Solvents Heavy Oil Bitumen Water Systems at High Pressures and Elevated Temperatures written by Zehua Chen and published by . This book was released on 2019 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: 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.

Download or read book Mass Transfer of Alkane Solvents CO2 Heavy Oil Systems in the Absence and Presence of Porous Media Under Reservoir Conditions written by Hyun Woong Jang and published by . This book was released on 2021 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: 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).

Download or read book Phase Behaviour of Solvent s Water Heavy Oil Systems at High Pressures and Elevated Temperatures Based on Isenthalpic Flash written by Desheng Huang and published by . This book was released on 2020 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: 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.

Download or read book Enhanced Heat and Mass Transfer for Alkane Solvent s CO2 Heavy Oil Systems at High Pressures and Elevated Temperatures written by Sixu Zheng and published by . This book was released on 2016 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: 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.

Download or read book Hydrocarbon Phase Behavior written by Tarek H. Ahmed and published by Butterworth-Heinemann. This book was released on 1989 with total page 440 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Experimental and Numerical Studies of Solvent Non Equilibrium Dissolution and Exsolution Behavior in a Heavy Oil System written by Hongyang Wang and published by . This book was released on 2020 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: One of the most important mechanisms of foamy oil is the solvents' non-equilibrium dissolution and exsolution behavior. Therefore, the real-time capturing of these dynamic properties is crucial in analyzing how foamy oil evolves under non-equilibrium state. In this research, various of solvent dissolution and exsolution tests were conducted in real-time visualization systems for direct quantifications of foamy oil behavior. Test conditions include visualization in both bulk phase and porous media. For bulk phase, visualization tests were realized in a high-pressure Hele-Shaw-like visual cell, and for porous media, a high-pressure etched glass micromodel was used. Tested solvent-heavy oil systems include CO2-heavy oil and CO2-C3H8-heavy-oil system. For the purpose of formulating an equilibrium PVT properties package to compare with non-equilibrium state, two-phase flash and live oil liquid-phase properties were measured by differential liberation tests. CO2 dissolution and exsolution behavior have been tested in the visual cell. Pressure decay curves and oil swelling factor curves were achieved prior to numerically determine CO2 intra-phase diffusion coefficient in oil phase. After diffusion stage, pressure depletion tests were conducted. It was found that foamy oil stability increased with higher initial GOR, higher pressure depletion rate, higher pressure drawdown level and longer solvent-heavy oil contact time from foamy oil volumetric curves. Constant Composition Expansion (CCE) tests with different pressure depletion rates have been conducted for CO2-C3H8-heavy oil system in a closed system in the visual cell. Physical parameters such as phase volume ratio, solvent exsolution sequence and deviated vapor-liquid-equilibrium (VLE) K value, etc., have been achieved experimentally to show the solvent non-equilibrium exsolution behavior. Single bubble exsolution and dissolution behavior tests have generated a bubble- mass-with-pressure/time relationship and have successfully guided the simulation study. Solvent diffusion and post-diffusion depletion tests conducted in micromodel have shown that the residual oil distribution and gravity would affect solvent solubility. Two types of static CCE tests as well as foamy oil continuous convective flowing (CCF) tests have been conducted to investigate foamy oil stability under static and convective conditions, and the vapor phase volume ratio indicated a higher foamy oil stability under convective conditions. Solvent flooding and post-flooding depletion tests have been carried out to study how efficient a cyclic solvent injection process could boost up the recovery factor. The qualitative phenomenon such as solvent viscous fingering was directly visualized. Numerical simulations have been conducted to quantify and validate the experiments. CO2 diffusion coefficients in oil phase and its kinetic exsolution rates were determined by history matching pressure decay curves and transient foamy oil volume curves. Identical foamy oil stability was found both experimentally and numerically. Dynamic adjustment of VLE K value and kinetic reaction model were applied to simulate CO2-C3H8 mixture solvent exsolution behavior in the visual cell. Non-equilibrium K values were achieved. Experimental single bubble exsolution behavior was incorporated into simulation and achieved successful history matching. SCCE and CCF tests were simulated by kinetic reactions and it was found that the optimized reaction frequency factors indicated a higher foamy oil stability under convective conditions. Pressure decay tests in micromodel system have been simulated, and the solvent effective diffusion coefficient in porous media have been achieved as well as the solvent non-equilibrium dissolution kinetic reaction frequency factors, which was in accordance with the dissolution rate of the single bubble tests.

Download or read book Quantification of Mutual Mass Transfer of Gas Light Oil Systems at High Pressures and Elevated Temperatures written by Xiaomeng Dong and published by . This book was released on 2019 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Numerous tight oil resources that are characterized by both low porosity and permeability have been found in North America during past decades. Due to the extremely low permeability, water injection has found its limitation with its relatively low injectivity. Alternatively, gas injection, such as CO2, N2, hydrocarbon gas, and flue gas, has been made physically possible for enhancing oil recovery under certain conditions, during which molecular diffusion is of great importance. Due to the affordability and sustainability of CO2, N2 and flue gas have been found to be costeffective for enhancing hydrocarbon recovery to a certain extent. Physically, there exists two-way mass transfer between the injected gas and light oil, though the light component extraction has been theoretically neglected. Therefore, it is essential to quantify the mutual mass transfer of gas-light oil systems under reservoir conditions. In this study, a novel and pragmatic technique has been developed to quantify mutual mass transfer between a gas and light oil by dynamic volume analysis. Experimentally, diffusion tests for a CO2-light oil system, a N2-light oil system, and two flue gas-light oil systems, have been conducted at a constant temperature and pressure with a pressure/volume/temperature (PVT) system, while the dynamic swelling factors of oil phase are measured and recorded continuously during the experiments. Gas samples have been collected at end of each diffusion experiment to measure gas compositions by performing gas chromatography (GC) analysis. Theoretically, by combining Fick's second law and Peng-Robinson equation of state, the diffusion coefficients of both gas components and oil phase can be determined once the discrepancies between the measured and calculated dynamic swelling factors and gas compositions have been minimized simultaneously. At end of diffusion experiments, the swelling factor measured for the CO2-light oil system is 1.029, which is higher than that of N2-light oil system (i.e., 1.005). For the two flue gas-light oil systems, the enriched flue gas, which has a higher CO2 concentration, results in a higher swelling factor (i.e., 1.013) at end of diffusion experiment, comparing with that of flue gas-light oil system (i.e., 1.009). Besides, based on the GC analysis results, light components have been found in the gas phase, which proves that there exists two-way mass transfer between gas and oil phases. For the CO2-light oil system and N2-light oil system, at temperature of 336.15 K, the diffusion coefficients of CO2 and N2 are determined to be 12.87×10-9 m2/s at pressure of 2170 kPa and 1.35×10-9 m2/s at pressure of 5275 kPa, respectively. The diffusion coefficients of light oil in gas phase are determined to be 6.04×10-11 m2/s for the CO2- light oil system and 0.26×10-11 m2/s for the N2-light oil system under the corresponding conditions. Similarly, for the enriched flue gas-light oil system, the individual diffusion coefficients determined for CO2 and N2 are 8.35×10-9 m2/s and 1.52×10-9 m2/s at temperature of 336.15 K and pressure of 5275 kPa, respectively, while that of oil in gas phase is 0.07×10-11 m2/s. For the flue gas-light oil system, at the same condition, the individual diffusion coefficients calculated for CO2 and N2 are 6.42×10-9 m2/s and 2.19×10-9 m2/s, respectively, while that of oil in gas phase is 0.08×10-11 m2/s.

Download or read book A Simplified Method for Computing Phase Behavior of Crude Oil carbon Dioxide Mixtures written by Sabry Abdel-Aliem El-Sayed Mohammed and published by . This book was released on 1988 with total page 436 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Petroleum Abstracts Literature and Patents written by and published by . This book was released on 1987 with total page 1348 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Phase Behavior of Water Hydrocarbon Systems written by Rahim Masoudi and published by LAP Lambert Academic Publishing. This book was released on 2011-12 with total page 264 pages. Available in PDF, EPUB and Kindle. Book excerpt: Thermodynamic description and prediction of the complex multi-phase systems, prone to gas hydrate and salt formation, is crucial to the economical and safe design and operation of oil and gas production and transportation facilities, in particular in offshore and deepwater regions. The topics presented in this book included modelling of the phase behaviour and gas solubility in the water-hydrocarbon systems in the presence of electrolyte solutions with/without hydrate organic inhibitors, as well as development of tools and methods to predict gas hydrate formation and salt precipitation problems associated with petroleum exploration and production. A new thermodynamic approach capable of predicting vapour-liquid-solid equilibria (VLSE) in systems containing electrolytes or electrolyte and organic inhibitors at conditions relevant to subsea transportation of oil and gas is presented.Various generic correlation for predicting the hydrate suppression temperature as well as the compatibility concerns of different hydrate and scale inhibitors are also described. Potential of using gas hydrate technology for different processess is also explained.

Download or read book Characterization of Reservoir Fluids Based on Perturbation from N alkanes written by Ashutosh Kumar and published by . This book was released on 2016 with total page 397 pages. Available in PDF, EPUB and Kindle. Book excerpt: Reliable design of gas and/or steam injection for enhanced oil recovery requires compositional reservoir simulation, in which phase behavior of reservoir fluids is represented by an equation of state (EOS). Various methods for reservoir fluid characterization using an EOS have been proposed in the literature. Conventional characterization methods addressed the challenge of the reliable prediction of the condensation/vaporization mechanisms in gas injection processes. It is even more challenging to characterize reservoir fluids for multiphase behavior consisting of three hydrocarbon phases. Complex multiphase behavior was observed experimentally for many gas floods. The importance of considering multiphase behavior in gas flooding simulation was also demonstrated in the literature. However, no systematic method has been proposed, especially for three-phase characterization. The main objective of this research is to develop a reliable method for multiphase fluid characterization using an EOS. The Peng-Robinson EOS is used with the van der Waals mixing rules in this research. The fluid types considered are gas condensate, volatile oil, black oil, heavy oil, and bitumen. The most important difference from the conventional methods is that, in this research, reservoir fluids are characterized by perturbation of the EOS model that has been calibrated for n-alkanes, in the direction of increasing level of aromaticity. This methodology is referred to as perturbation from n-alkanes (PnA), and used consistently throughout the dissertation. The experimental data required for the characterization methods presented in this dissertation are the saturation pressure and liquid densities at a given temperature, in addition to compositional information. Other types of experimental data, such as minimum miscibility pressures, liquid dropout curves, and three-phase envelopes, are used to test the predictive capability of the PR EOS models resulting from the PnA method. First, the PnA method is applied to simpler phase behavior that involves only two phases of vapor and liquid. The Peng-Robinson EOS is calibrated for vapor pressures and liquid densities for n-alkanes from C7 to C100. Two different characterization methods are developed for two-phase characterization using the PnA method. In one of them, fluid characterization is performed by adjusting critical pressure, critical temperature, and acentric factor. In the other, fluids are characterized by directly adjusting the attraction and covolume parameters for each pseudocomponent. Then, the PnA method is extended to three phases. Unlike for two phases, the Peng-Robinson EOS is calibrated for three-phase data measured for n-alkane/n-alkane and CO2/n-alkane binaries. A new set of binary interaction parameters (BIPs) is developed for these binaries, and applied for reservoir fluid characterization. The PnA method applied for two and three phases results in three different methods of fluid characterization. They are individually tested for many different reservoir fluids to demonstrate their reliability. The validation of the methods is based on experimental data for 110 fluids in total (50 gas condensates, 15 volatile oils, 35 black oils, 4 heavy oils, and 6 bitumens). Results consistently show that the use of the PnA method with the PR EOS yields a systematic, monotonic change in phase behavior predictions from n-alkanes. The two characterization methods developed for two phases do not require volume shift to obtain accurate predictions of compositional and volumetric phase behavior. However, they may not give reliable predictions for three phases. The three-phase characterization presented in this research is the most comprehensive method that can predict reliably two and three phases. However, volume shift is required for matching density data in this last method. Therefore, it should be used with a proper understanding of the relationship among different EOS-related parameters and their effects on phase behavior predictions.

Download or read book A Comprehensive Study and Mechanism Investigation for Alkaline Heavy Oil Recovery Process written by Zhiyu Xi and published by . This book was released on 2019 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Alkaline flooding is an important branch of chemical enhanced oil recovery (EOR). The complexity of alkaline flooding study is mainly embodied by its chemical reaction required by alkalis to react with oil acids. Consequently, in-situ surfactants are generated for various emulsification phenomenon. It is known that alkaline flooding performance in oil recovery is subjected to the emulsion type generation, thus, of great importance to alkaline flooding study is its mechanism investigation and saponification rate examination. In this study, a modified bottle test method that assesses major emulsion type formation for preliminary prediction of alkaline flooding performance in oil recovery is introduced. Homogenization and Karl-Fischer water content titration techniques were applied in the modified bottle test to overcome the emulsion preparation and analysis difficulties. In addition, sandpack alkaline flooding tests were conducted to prove the prediction reliability of the modified bottle test through identifying effluent emulsions. It is found either water in oil emulsion or oil in water emulsion could be representatively prepared in bottle test based on reaction environments identical to flooding tests' conditions. Taking advantages of bottle test's superior efficiency in simultaneous multi-case study, alkaline flooding screening test can be easily conducted applying statistical techniques to provide prior visions regarding dominating driving mechanism of oil recovery. This research verified a practical solution to representative emulsion preparation and phase volume quantification in the bottle test especially when it comes to high viscous heavy oil; therefore, mechanism investigation regarding alkaline flooding could be easily conducted. Besides, the CMGTM alkaline flooding simulation model was built considering the saponification reaction rate of immiscible fluids. A novel experiment design of alkali- heavy oil reaction system was proposed and implemented to measure reagents' reaction rate at various temperatures through monitoring pH change by electrode. Through which the Arrhenius constant and activation energy were calculated. In addition, the stoichiometry for emulsification reaction was proposed according to bottle test results. The simulation model was history matched founded on reaction data thus model uncertainty was mitigated by reducing number of unconstrained parameters. Oil recovery predictions have been conducted using the history matched model and the optimized injection strategies were addressed.

Download or read book Phase Behavior Calculations for Systems with Hydrocarons Water and CO2 written by Ramagopal Nutakki and published by . This book was released on 1991 with total page 562 pages. Available in PDF, EPUB and Kindle. Book excerpt: Copyright by the author.