Phase Behavior Of Hydrocarbons Research Articles

Investigation of the confinement effect on fluid-phase behavior in shale oil reservoirs during CO2 injection process

AbstractDue to the confinement effect of nanopores, the fluid-phase behavior of shale oil reservoirs is much different from that of conventional reservoirs. The accurate description of the phase change characteristics of fluid in nanopores is the basis to design development plan, production system, and EOR methods of shale oil reservoirs. In this study, molecular dynamics simulation was employed to analyze the phase behavior of single-component system and hydrocarbon–CO2 mixture system in organic nanopores. The results show that the confinement effect on the phase change pressure of the single-component system is influenced by the distribution of the electron cloud. The phase change pressure of hydrocarbons with even distribution of the electron cloud would be increased, while that of CO2 would be decreased due to the instantaneous dipole moment. In addition, as the length of carbon chains increases, the confinement effect on hydrocarbons becomes stronger. When the temperature increases, the confinement effect becomes weaker. In the hydrocarbon–CO2 mixture system, when the occurrence condition changes from bulk to the nanopore of 5 nm, the bubble point pressure decreases by 39.21–68.85%, and the critical temperature and pressure decrease by 75.98% and 7.13%, respectively. On the whole, the P–T phase envelope is shrunken under the confinement effect. CO2 is much easier to be miscible with shale oil in nanopores. Moreover, full mixing and keeping in single liquid phase of CO2–hydrocarbons mixture system can reduce the adsorption of hydrocarbons on organic pore walls. Therefore, CO2 injection could be a feasible method to enhance oil recovery in the matrix of shale oil reservoirs.

Phase behavior of single and multi-component liquid hydrocarbons in real reservoir rocks

Phase-alteration phenomenon has a considerable influence on the dynamics and distribution of fluids in porous media. One of the major factors affecting the phase behaviour of fluids in reservoirs is the capillarity effect, which becomes unavoidably significant as the media becomes tighter (confinement effect) and contains more pores at nano sizes. Comprehending the nature of vaporization and condensation of hydrocarbon in such confined media is important for accurate modelling of two-phase envelopes and thereby the performance of energy production from hydrocarbon reservoirs. This paper studies the vaporization of single- and multicomponent hydrocarbons in different types of rocks (namely sandstones, limestones, tight sandstones, and shales). The vaporization temperatures were measured experimentally in each rock type and compared with boiling points measured at bulk conditions to investigate the deviation between the phase-change temperatures in capillary media and bulk values. The deviation between the measured vaporization temperatures and the bulk measurements ranged from 4.4% (1.6% in Kelvin unit) to 19.7% (5.2% in Kelvin unit) with single-component solvents and 1.4% (0.4% in Kelvin unit) to 27.6% (5.3% in Kelvin unit) with the hydrocarbon mixtures. The vaporization temperatures, obtained from the experiments, were also compared with the computed two-phase envelopes, calculated by the classical Peng-Robinson Equation of State. The deviation percentages of measured vaporization temperatures from the computed values were at least 4.4% (1.6% in Kelvin unit) with single-component solvents and 2.1% (0.7% in Kelvin unit) with the hydrocarbon mixtures.

Comprehensive Outlook into Critical Roles of Pressure, Volume, and Temperature (PVT) and Phase Behavior on the Exploration and Development of Shale Oil

Shale oil has received increasing attention as an essential replacement for conventional oil resources. Shale oil recovery is a complex process controlled by interactions of many factors whose impact could be significantly different from conventional reservoirs. This study hence aims to fill the gaps in the literature by studying various aspects of the phase behavior of shale oil and their significance in different aspects of the recovery from oil shale. In the first part of this study, the standard practices, including experimental and theoretical methods for calculating the pressure, volume, temperature (PVT), and phase behavior of shale oil, is discussed in detail. Next, the effects of factors such as the composition of fluids, pore structure, and capillary forces on the phase behavior of hydrocarbon fluids are explained. The third part focuses on applying phase behavior for oil shale development. Moreover, the geological and geochemical processes that lead to the maturity of kerogen, the formation of shale oil, and the experimental methods by which those processes are currently studied are scrutinized. By studying the thermal and burial history of the hydrocarbon-generating strata and hydrocarbon-generating kinetics, the shale formation’s oil and gas phase distribution can be predicted. Consequently, the sweet spots for the recovery of light condensate oil can be more accurately determined. The application of enhanced oil recovery methods is an inevitable part of recovery from conventional and unconventional formations. Therefore, the last part of this study analyses the changes in the phase behavior of shale oil when an external component, i.e., CO2 or CH4, is injected into the reservoir. Reviewing the literature revealed that a more accurate prediction of hydrocarbon phase behavior can be made by combining different disciplines of science to achieve optimized plans for efficient shale oil development, making shale oil a more economically viable energy resource.

Capillary condensation and evaporation of n-butane and iso-butane in nanoporous media: Experimental study of the effects of pore size and temperature using an automated gravimetric apparatus

Understanding the confinement-induced phase behavior of fluids stored in nanometer-sized pores of solid materials is paramount in various science and engineering applications. Experimental findings describing fluid phase behavior in confinement are often used to develop the efficient and accurate equation of state models that can then provide a cost-effective approach to predict such information for different applications. However, there is a scarcity of experimental data in the literature that can offer insights into the confinement effects under varying conditions. The present work endeavors to provide new experimental data on the effects of pore size and temperature on the confined phase behavior of two chemical species (n-Butane and iso-Butane) and thereby improve the current understanding of the impact of these parameters on capillary condensation, evaporation, and hysteresis. We use a patented gravimetric apparatus that was upgraded in this study by the development and incorporation of advanced automated data acquisition modules. The automation module improved the data collection quality by fine-tuning the fluid injection and withdrawal processes which significantly enhanced the accuracy and precision of the measured isotherms. The capillary condensation and evaporation processes were then studied using a nanoporous material known as Mobil Composition of Matter No. 41 (MCM-41), a mesoporous medium with well-defined pore shape and sizes. The isotherms were obtained for a wide range of temperatures (−7, −3, 0, 7, 8.7, 17, and 27 °C) and using MCM-41 with various pore sizes (60, 80, 100, and 120 Å). The accuracy of the measurements was validated against the phase behavior data of bulk n-Butane and iso-Butane reported by the National Institute of Standards and Technology (NIST). The capillary condensation pressures obtained from the isotherms for different pore sizes agreed with the trends reported in the literature. The results show that the capillary condensation pressures of the fluids increase with the pore size and temperature. The measured isotherms and capillary condensation pressures provide new data sets on the condensation characteristics of n-Butane and iso-Butane. They are expected to contribute to the fundamental understanding of the confined phase behavior of hydrocarbons and thereby advance the development of improved equations of state models that can accurately describe the phase behavior of fluids in nanoporous media. PC-SAFT/Laplace EOS was used to model the phase behavior of the fluids under confinement. The predictions from the PC-SAFT model agree with previous data therefore the results from this study can be integrated into building more robust models.

Development of a Downhole Measurement System for Phase Behavior of Reservoir Crude Oils and Retrograde Condensates

This article reviews the scientific findings that were integrated into a downhole prototype to measure hydrocarbon phase behavior. While laboratory measurements of bubble point pressure (Pb), asphaltene onset pressure (AOP), and dewpoint pressure (Pd) are well established and have been extensively studied, such measurements of reservoir crude oils are novel downhole due to their operational, hydraulic, and interpretational complexities. Furthermore, such laboratory measurements typically take several hours to complete and can only be carried out by skilled personnel. For the downhole measurement, novel science and understanding were developed to reduce the measurement time to minutes and to automate the workflow. This article reviews the science and technology that enabled these downhole measurements to be made rapidly and provides field examples of how sampling is optimized and quality is validated in real time.

Phase Behavior of Single and Multi-Component Hydrocarbons at Nano-Capillary Scale

Phase Behavior of Single and Multi-Component Hydrocarbons at Nano-Capillary Scale

Adsorption, selectivity, and phase behavior in organic nanopores for shale gas and oil development

In a shale gas and oil reservoir, hydrocarbon fluids are stored in organic nanopores with sizes on the order of ∼1–100 nm. The adsorption, selectivity, and phase behavior of hydrocarbons in the nanopores are crucial for estimating the gas-in-place and predicting the productivity. In this study, to understand the characteristics of the phase behavior of multicomponent hydrocarbon systems in shale reservoirs, the phase behavior of a CH4/n-C4H10 binary mixture in graphite nanopores was investigated by Grand Canonical Monte Carlo (GCMC) molecular simulation. The method for determining the dew-point pressure and bubble-point pressure in the nanopores was explored. The condensation phenomenon was observed owing to the difference in the adsorption selectivities of the hydrocarbon molecules on the nanopore surfaces, and hence the dew-point pressure (and bubble-point pressure) of hydrocarbon mixtures in the nanopores significantly shifted. The GCMC simulations reproduced both the higher and lower bubble-point pressures in nanopores in previous studies. This work highlights the crucial role of the selectivity in the phase behavior of hydrocarbons in nanopores.

Revisiting Kelvin equation and Peng\u2013Robinson equation of state for accurate modeling of hydrocarbon phase behavior in nano capillaries

The thermodynamics of fluids in confined (capillary) media is different from the bulk conditions due to the effects of the surface tension, wettability, and pore radius as described by the classical Kelvin equation. This study provides experimental data showing the deviation of propane vapour pressures in capillary media from the bulk conditions. Comparisons were also made with the vapour pressures calculated by the Peng–Robinson equation-of-state (PR-EOS). While the propane vapour pressures measured using synthetic capillary medium models (Hele–Shaw cells and microfluidic chips) were comparable with those measured at bulk conditions, the measured vapour pressures in the rock samples (sandstone, limestone, tight sandstone, and shale) were 15% (on average) less than those modelled by PR-EOS.

Modeling the equilibrium of two and three-phase systems including water, alcohol, and hydrocarbons with CPA EOS and its improvement for electrolytic systems by Debye-Huckel equation

Calculation of the phase equilibrium of hydrocarbons in the presence of electrolyte solutions is one of the most important and practical topics in chemical and petroleum engineering. The aim is to obtain an improved thermodynamic model that can predict the phase behavior of hydrocarbons along with electrolyte solution and alcohol with a good approximation. In this work, various equilibrium data published by previous researchers were collected, and then phase behavior of different systems including water, alcohol, and hydrocarbons was modeled using cubic plus association equation of state. Moreover, modified cubic plus association equation of state by Debye-Huckel equation was utilized for the prediction of the phase behavior of different systems containing salt. The results showed, for systems without electrolyte components, the cubic plus association equation of state predicts the phase behavior of these mixtures very well and the absolute average deviation value in these mixtures was between 1 and 10% for different systems. In recent decades, several equations of state have been proposed to predict the behavior of electrolyte mixture but, to the best of our knowledge, they did not consider all four components (hydrocarbon, water, alcohol, and salt) at the same time. In this research, an equation of state was presented to predict the phase behavior of systems that simultaneously contain hydrocarbons, water, alcohol, and salt in a mixture that considers both hydrogen bonds and ion interactions. The electrolytic cubic plus association equation is an equation that considers the effect of hydrogen bonds between different components as well as the effect of forces between existing ions. The results obtained for predicting electrolyte systems using the electrolytic cubic plus association equation showed that this equation can predict the phase behavior of these mixtures satisfactorily. The error value obtained for electrolytic systems and tangible components was between 1 and 12%.

Wettability effects on phase behavior and interfacial tension in shale nanopores

Nanoconfinement effects lead to the anomalous phase behavior of hydrocarbons in nanopores. Besides the capillary pressure, the critical properties’ shift and curvature-dependent effect are found to be wettability-dependent parameters. In this work, we propose novel methods to correlate the macroscopic contact angle to the critical properties’ shift and curvature-dependent effect with an in-depth analysis of the microscopic interactions, including molecule-wall interactions and intermolecular interactions at the liquid-vapor interface. Then, we extend the Peng-Robinson equation of state model to investigate the effects of wettability on the phase behavior and interfacial tension (IFT) of nanoconfined hydrocarbons. Our results show that the nanoconfinement effects are not only dependent on the pore size but also on the wettability of the pore wall. In nonhydrocarbon-wet nanopores, the nanoconfinement effects are limited, and the bubble point pressure (Pb) and IFT are close to the bulk values. In hydrocarbon-wet nanopores, with the pore radius smaller than 50 nm, the nanoconfinement effects become visible and they are further strengthened as the contact angle decreases. The calculated results suggest that under reservoir temperature for Eagle Ford reservoir with the pore size of 10 nm, the suppression of Pb and IFT with completely oil-wet cases are nearly six-fold and ten-fold higher than that of intermediate-wet cases.

A Dual-Grid, Implicit, and Sequentially Coupled Geomechanics-and-Composition Model for Fractured Reservoir Simulation

SummaryIn the development of fractured reservoirs, geomechanics is crucial because of the stress sensitivity of fractures. However, the complexities of both fracture geometry and fracture mechanics make it challenging to consider geomechanical effects thoroughly and efficiently in reservoir simulations. In this work, we present a coupled geomechanics and multiphase-multicomponent flow model for fractured reservoir simulations. It models the solid deformation using a poroelastic equation, and the solid deformation effects are incorporated into the flow model rigorously. The noticeable features of the proposed model are it uses a pseudocontinuum equivalence method to model the mechanical characteristics of fractures; the coupled geomechanics and flow equations are split and sequentially solved using the fixed-stress splitting strategy, which retains implicitness and exhibits good stability; and it simulates geomechanics and compositional flow, respectively, using a dual-grid system (i.e., the geomechanics grid and the reservoir-flow grid). Because of the separation of the geomechanics part and the flow part, the model is not difficult to implement based on an existing reservoir simulator. We validated the accuracy and stability of this model through several benchmark cases and highlighted the practicability with two large-scale cases. The case studies demonstrate that this model is capable of considering the key effects of geomechanics in fractured-reservoir simulation, including matrix compaction, fracture normal deformation, and shear dilation, as well as hydrocarbon phase behavior. The flexibility, efficiency, and comprehensiveness of this model enable a more realistic geocoupled reservoir simulation.

Modeling the effect of dynamic adsorption on the phase behavior of hydrocarbons in shale and tight reservoirs

It is known that in shale and tight reservoirs, adsorption significantly affects hydrocarbon reserves and the processes of their production. This fact is reflected in the methods for calculating reserves and evaluating the production potential of shale and tight deposits. To calculate the initial content of the components, multi-component adsorption models are used. The impact on hydrocarbon production is taken into account through special dynamic permeability models for shale reservoirs. According to laboratory studies, adsorption can lead to significant changes not only in volume, but also in the composition of the produced fluids and their phase behavior. Previously, this effect could not be reproduced on the basis of mathematical models. The method proposed in this article allows modeling the phase behavior of a hydrocarbon mixture taking into account the dynamic adsorption/desorption of components in the process of pressure change. The method is applicable in the simulations of multi-component (compositional) flow and PVT-modeling on real objects. The phase behavior of hydrocarbons with pressure depletion in shale reservoirs has been simulated. It is shown that the neglect of the dynamic effect of adsorption / desorption leads to significant errors in predicting the saturation pressure, as well as the dynamics of changes in the composition of the produced fluid and of hydrocarbon component recovery.

Phase behavior of hydrocarbons in nano-pores

Inside nanopores, solid-fluid interactions are of the same order of magnitude as intermolecular interactions of fluid molecules. This fact strongly modifies the thermodynamic properties of confined fluids with respect to bulk phases. Tight oil and shale gas reservoirs, where the proportion of micro (below 2 nm) and mesopores (between 2 and 50 nm) can reach more than 20% of the volume distribution, represent an environment with such problems and industrial challenges to hydrocarbon fluid pressure/volume/temperature (PVT) modeling. This study provides a detailed understanding of the thermodynamic behavior of confined fluid and reference data of the thermodynamic properties of pure components (methane, ethane, n-pentane, n-decane) and mixtures (methane/ethane, ethane/n-pentane) confined in graphite slit pores. Furthermore, a detailed explanation of the different pressures considered in a porous medium with nano-pores is given. The Gibbs Ensemble Monte Carlo (GEMC) NVT simulation is used for pure components instead of the more traditional Grand Canonical Monte Carlo ensemble (GCMC) simulation to get more precise results of liquid and vapor confined pressure avoiding the phase change location determination problem. The evolution of critical temperature and pressure versus pore radius is compared to literature correlations and confined vapor and liquid densities are calculated. A new and robust method in the GEMC ensemble called GEMC NPT Bubble point Monte Carlo (BPMC) completed with GEMC NVT simulations has been developed to get thermodynamic properties including pressures at equilibrium of confined mixtures. Pressure versus density diagrams, pressure versus molar fraction isotherms and examples of pressure versus temperature diagram for a specific composition are built. The phase envelope of the confined fluid is shifted and closes with respect to phase envelope of bulk fluid. The critical temperature and pressure are shifted from the bulk value to a lower value and the bubble point pressure is decreased as the dew point pressure is increased. With regards to the selectivity of the confined system compared to the bulk fluid, for the methane/ethane and ethane/n-pentane mixtures, the heavier component is preferentially adsorbed in the vapor phase and the lighter component is preferentially adsorbed in the liquid phase. All these results for pure components and mixtures provide relevant information concerning the understanding of the phase behavior in confined systems such as shale gas and tight oil reservoirs, emphasizing the difference from the bulk fluid. Furthermore all these data may be used as references for pore radius dependent equation of state (EOS) calibration.

Molecular simulation of the constant composition expansion experiment in shale multi-scale systems

The phase behavior of hydrocarbons in shale reservoirs has garnered increasing attention in the petroleum industry. Significant differences in the phase behavior of petroleum fluids between conventional reservoirs and shale reservoirs have been observed. Because of the existence of nano-scale porous media in shale reservoirs, there are substantial surface fluid interactions that can lead to a heterogeneous distribution of molecules and an alteration of the fluid phase behavior. In this work, for the first time, we use molecular simulations to investigate the confinement effect on the phase behavior of reservoir fluids in a multi-scale (nano-scale + macro-scale) media. The model has a confined region that mimics the nano-scale porous media and a bulk region that represents the macro-scale porous media (macropores and fractures) in shale reservoirs. For the first time, we use the Gibbs ensemble Monte Carlo (GEMC) simulation at imposed pressures to simulate the constant composition expansion (CCE) experiment for multi-component hydrocarbon mixtures in a multi-scale porous media. Our results show that because of the confinement effect, the composition of the bulk and the confined regions differ significantly. In our molecular simulations, the composition of the lighter components in the bulk region increases, while heavier components are mainly trapped in the confined region. These changes in the composition cause a significant shift or disappearance of the saturation pressure in the bulk region of the multi-component multi-scale hydrocarbon systems.

A PC-SAFT model for hydrocarbons III: Phantom dipole representation of dipole induced dipole interactions in unsaturated hydrocarbons

Inclusion of polar contributions into the statistical associating fluid theory class of equations of state has been demonstrated to allow for the accurate prediction of solution non-idealities of mixtures composed of paraffins and polar molecules. However, as we demonstrate in this paper, these theories necessarily overpredict the non-idealities in mixtures composed of polar molecules with unsaturated hydrocarbons. The reason for this is that the dipole moment of the polar molecule polarizes the unsaturated bond resulting in a significant dipole-induced dipole attraction. We develop a simple, general and predictive methodology to incorporate this missing physics into the dipolar contribution to the theory. The new approach is shown to accurately predict the phase behavior of unsaturated hydrocarbons with polar molecules.

Geochemical factors controlling the phase behavior of Eagle Ford Shale petroleum fluids

Petroleum types in the Eagle Ford resource play span the range from black oil to dry gas and are produced along regional trends that are largely maturity controlled. A total of 61 shale samples covering all maturity zones were evaluated to document organic richness, organic matter type, and maturation characteristics using established geochemical parameters. Pyrolysis experiments were then performed to simulate the generation of petroleum fluids. Termed the “PhaseSnapShot” approach, one or more target wells with known fluid properties were used as reference; a match with that composition was made using next-formed fluids generated from the shale in a closely located well of slightly lower thermal maturity than the target well(s). Phase behavior predictions from the model were calibrated using a regional pressure–volume–temperature (PVT) database compiled from the public domain. The conceptual model that best matched the PVT data were comprised of two reactive components: (1) a mixture of kerogen and bitumen that generated petroleum within the low permeability shale matrix and (2) bitumen in zones of enhanced porosity within the matrix. The combined generation of gas from both of these components as well as the strong retention of C7+ fluids in the matrix during production were required to match the calibration data. Retention of oil was needed over a broad thermal maturity range (Rock-Eval Tmax release: 440°C –475°C). A key result of this forward model is that phase behavior and bulk compositional properties of hydrocarbons can be quickly and effectively predicted using mature shale samples as long as calibration data from PVT reports are available.

Evolving generalized correlations based on Peng-Robinson equation of state for estimating dynamic viscosities of alkanes in supercritical region

Viscosity is an essential factor to characterize phase behavior of hydrocarbons. As appropriate correlations for supercritical hydrocarbons in industrial operations are not available, in the present work, two generalized correlations are proposed to estimate the viscosity of commonly used hydrocarbons (i.e. methane, ethane, propane, i-butane, n-butane, n-pentane, n-hexane, and n-heptane). Subsequently, the cubic correlation is suggested and verified by experimental data. This correlation has a few numbers of adjusting parameters, low average absolute error (in 5.41%–6.72% range) while can cover wide ranges of pressure and temperature. Consequently, results confirm great satisfactory performance and accuracy of the developed models to estimated supercritical fluid viscosity by applying the novel strategy.

A review on the application of differential scanning calorimetry (DSC) to petroleum products

Differential scanning calorimetry (DSC) can be used to obtain a variety of thermodynamic or kinetic data of petroleum products. The application of DSC to petroleum fluids includes characterization of crude oils, studying bulk and confined space phase behavior of hydrocarbons, and evaluating the glass transition in crude oils. In addition, the kinetic data of the pyrolysis, combustion, and oxidation of crude oils can be obtained using DSC. In this work, a comprehensive review of the application of DSC to petroleum-based products is provided that integrates different approaches in the literature in order to provide a constructive platform for future studies. Also, the limitations of the method are elaborated in detail, and recommendations are provided to appropriately optimize the accuracy and applicability of DSC to study petroleum products. The impact of different operating parameters in using DSC including the thermal scanning rate, pressure, modulating temperature program, and analysis method is systematically discussed. Also, the effect of neglecting thermal radiation in DSC experiments is highlighted to ensure that future studies consider this important phenomenon once analyzing the raw data. As well, the advantage of coupling DSC with other analytical techniques is carefully reviewed to underline that precious information that can be obtained once DSC is integrated with other methods. This comprehensive review expresses that DSC has different themes of applications to the research and development in petroleum industry. Due to its simplicity, precious and rapid data collection features, DSC is one of the primary methods for characterizing petroleum fluids. Yet, further advancements both in the equipment design and in data analysis is urged to improve the applicability of DSC to crude oils and their fractions.

Comparison of Peng-Robinson Equation of State With Capillary Pressure Model With Engineering Density-Functional Theory in Describing the Phase Behavior of Confined Hydrocarbons

Summary The Peng-Robinson equation of state (PR-EOS) (Robinson and Peng 1978) with capillary effect has been used extensively to describe the phase behavior of hydrocarbons under nanoconfinement in shale reservoirs. In nanopores, surface adsorption may be significant, and molecular distribution is heterogeneous. Although the PR-EOS cannot consider these effects, statistical thermodynamic approaches such as density-functional theory (DFT) can explicitly consider the intermolecular and fluid/surface interactions. In this work, we compare the phase behavior of pure hydrocarbons and mixtures in nanopores from the PR-EOS with capillary effect and engineering DFT. We apply the Young-Laplace (YL) equation, assuming zero contact angle to calculate the capillary pressure in the PR-EOS with capillary effect. On the other hand, we extend the PR-EOS to inhomogeneous conditions with weighted-density approximation (WDA) in engineering DFT. For pure components, both approaches predict that the dewpoint temperature increases in hydrocarbon-wet nanopores. Although engineering DFT predicts that the confined dewpoint temperature approaches bulk saturation point when pore size approaches 30 nm, the saturation point obtained from the PR-EOS with capillary effect approaches bulk only when the pore size is as large as 1000 nm. With engineering DFT, the critical points in nanopores deviate from those in bulk, but no change is observed from the PR-EOS with capillary-effect model. The difference on the dewpoint temperature between the PR-EOS with capillary effect and engineering DFT decreases as the system pressure approaches the critical pressure. At low-pressure conditions, the PR-EOS with capillary-effect model becomes unreliable. For binary mixtures, both approaches predict that the lower dewpoint decreases and the upper dewpoint increases. More interestingly, phase transition can still occur when the system temperature is higher than the bulk cricondentherm point. Engineering DFT predicts that the confined lower dewpoint approaches bulk when pore size approaches 20 nm, whereas the dewpoint obtained from the PR-EOS with capillary effect approaches bulk only when the pore size is as large as 100 nm. This work illustrates that assuming homogeneous distributions in nanopores may not be appropriate to predict the phase behavior of hydrocarbons under nanoconfinement.

Prediction of the phase behavior of BTEX and alkane hydrocarbons in the presence of Tri-Ethylene Glycol (TEG) solvent

ABSTRACTA computational framework according to the CPA Equation of state by considering hydrogen bonding association and solvation effects has been proposed for accurate prediction of phase behavior of complex mixtures of triethylene glycol (TEG), BTEX aromatic hydrocarbons (benzene, toluene, ethylbenzene, and o-xlylene) and alkanes (methane, ethane, propane). The overall average absolute deviation between the predicted and measured phase compositions, regarding 150 data points is about 2.40% suggesting the accuracy of the presented approach. The presented model can be used for accurate design of BTEX containing natural gas dehydration plants in petroleum industry.