Phase Behavior Of Fluids Research Articles

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.

Effects of quantum correction on the density profile, adsorption, and phase behavior of confined hydrogen and deuterium fluids in small systems: A DFT study

The density functional theory based on the effective Wigner-Kirkwood potential is employed to investigate the effects of quantum correction on the structure, adsorption, and phase behavior of hydrogen and deuterium fluids confined in nano-spherical pores. Results show that quantum correction in the classical method for hydrogen and deuterium fluids influences all their thermodynamic properties when confined in nano-pores. Moreover, they indicate that the repulsion between quantum-mechanical molecules and intermolecular energy effects play important roles in the structure and thermodynamic properties of confined fluids before they come into contact at low temperatures or densities. The wall pressure of the fluid at the wall of the pore increases but the height of the profile in the center of the pore decreases with increased quantum effect, or the de Boer's quantumness parameter Λ. At low temperatures and low density limits, the adsorption and structure of the fluid in the pore are determined by the intermolecular energy effect; this will be reversed for high density limits in which the entropy effect is the dominant factor. It is shown in this study that, at low bulk density limits, the rising trend of adsorption takes a more steep slope in the classical fluid than in the deuterium one and that it is steeper in the deuterium fluid than it is in the hydrogen one; this behavior is reversed for high bulk density limits. Finally, it is shown that the critical temperature decreases with increasing Λ. Also, the locus of the phase transition is shown to shift toward higher values of bulk density as a result of increasing values of quantum effect, Λ.

Stability of a columnar liquid crystalline phase in isomeric derivatives of the 1,4-dihydrobenzo[e][1,2,4]triazin-4-yl: Conformational effects in the core

Fluid phase behaviour of three isomeric 1,3,6-trisubstituted benzo[e][1,2,4]triazin-4-yl derivatives with the half-disc molecular architecture was examined in the pure form and in binary mixtures. Results indicate that the position of substitution with two wedge-shaped 3,4,5-tridodecyloxyphenyl groups and one Ph group has dramatic impact on the Colh phase stability, which ranges from 73 °C to presumably below −60 °C. Analysis of electronic and steric factors suggests that the intermolecular interactions of the wedge-shaped substituents are dominant and through their conformational behaviour they affect packing of the column's core and hence phase stability.

New empirical correlations for predicting Minimum Miscibility Pressure (MMP) during CO2injection; implementing the Group Method of Data Handling (GMDH) algorithm and Pitzer’s acentric factor

Miscible injection of carbon dioxide (CO2) with ability to increase oil displacement as well as to reduce greenhouse effect has become one of the pioneering methods in Enhanced Oil Recovery (EOR). Minimum Miscibility Pressure (MMP) is known as a key indicator to ensure complete miscibility of two phases and maximum efficiency of injection process. There are various experimental and computational methods to calculate this key parameter. Experimental methods provide the most accurate and valid results. However, such methods are time consuming and expensive leading researchers to use mathematical methods. Among computational methods, empirical correlations are the most straight-forward and simple tools to precisely estimate MMP, especially for gases with impurities.Furthermore, in predicting the miscibility state of oil–gas system, phase behavior is a vital issue which should be taken into account to achieve reliable results. In this regard, equations of state have an indisputable role in predicting the phase behavior of reservoir fluids. Remarkable improvements have been introduced to elevate performance of equations of state, based on Pitzer’s acentric factor. Hereupon, this study aims to enumerate acentric factor of injected gas (impure CO2) as a correlating parameter alongside conventional parameters including reservoir temperature, oil constituents (molecular weight of C5+, ratio of volatiles to intermediates) and critical properties of injected gas (pseudo-critical pressure & temperature).Thus, in this study an effective empirical correlation is created, implementing the Group Method of Data Handling (GMDH) algorithm along with including the acentric factor of injected gas, which eventuated to precise predictions of MMP for impure CO2injection. The GMDH is one of the most robust mathematical modeling methods for predicting physical parameters using linear equations.A comparison with well-known correlations, demonstrated at least 2% improvement in average absolute error with enumerating the acentric factor and the final error was equal to 12.89%.

Does capillary evaporation limit the accessibility of nonaqueous electrolytes to the ultrasmall pores of carbon electrodes?

Porous carbons have been widely utilized as electrode materials for capacitive energy storage. Whereas the importance of pore size and geometry on the device performance has been well recognized, little guidance is available for identification of carbon materials with ideal porous structures. In this work, we study the phase behavior of ionic fluids in slit pores using the classical density functional theory. Within the framework of the restricted primitive model for nonaqueous electrolytes, we demonstrate that the accessibility of micropores depends not only on the ionic diameters (or desolvation) but also on their wetting behavior intrinsically related to the vapor-liquid or liquid-liquid phase separation of the bulk ionic systems. Narrowing the pore size from several tens of nanometers to subnanometers may lead to a drastic reduction in the capacitance due to capillary evaporation. The wettability of micropores deteriorates as the pore size is reduced but can be noticeably improved by raising the surface electrical potential. The theoretical results provide fresh insights into the properties of confined ionic systems beyond electric double layer models commonly employed for rational design/selection of electrolytes and electrode materials.

The impact of near-wellbore wettability on the production of gas and condensate: Insights from experiments and simulations

Condensate banking commonly occurs in gas-condensate reservoirs resulting in a reduction in well productivity. This phenomenon is linked to the phase behavior of the reservoir fluid, the drawdown management technique, as well as the trapping of liquid hydrocarbons due to strong rock-fluid interactions. Wettability alteration to neutral-wetting near the wellbore has been identified as a possible solution to alleviate the problem. In this work, we investigate optimizing wettability conditions towards maximizing productivity. A range of wetting conditions is examined, experimentally, and using numerical simulation techniques. The results show that it is possible to target an optimum wettability state that maximizes gas well deliverability. A signature of these optimum conditions is identified in the trend of spontaneous imbibition tests. Complete reversal of wetting conditions can result in better well productivity than the original wetting state, but in some cases it can reduce the amount of condensate recovered. This puts into question the common perception that an increase in the recovery of heavy components should be expected when liquid-wetting is reduced.

Phase Behavior Measurements and Modeling for N2/CO2/Extra Heavy Oil Mixtures at Elevated Temperatures

Recently, a new technology, the so-called multithermal fluids huff and puff, to exploit extra heavy oil reservoirs has been applied successfully in several shallow heavy oil reservoirs in China. However, the use of this technology in deep extra heavy oil reservoirs is rare. Successful application of this technique in deep extra heavy oil reservoirs requires a good knowledge of the phase behavior and physical properties of multithermal fluids and extra heavy oil mixture. The major components of multithermal fluids mixtures are steam, N2, and CO2. In this work, targeting the application of multithermal fluids injection in heavy oil reservoirs, we conduct PVT experiments on the N2/CO2/heavy oil mixtures under deep reservoir conditions and develop equation of state models for representing these PVT data. Experimentally, it is found that CO2 solubility in extra heavy oil decreases with an increasing temperature at given pressure. Contrary to CO2, N2 solubility in extra heavy oil increases with an increasing te...

PVT analyses as an effective tool in the hand of the petroleum engineer. Part 2: phase behaviour of hydrocarbon fluids

PVT analyses as an effective tool in the hand of the petroleum engineer. Part 2: phase behaviour of hydrocarbon fluids

EOS lumping optimization using a genetic algorithm and a tabu search

To reduce CPU time in compositional petroleum simulation models (e.g. compositional reservoir simulations), a minimum number of components should be used in the equation of state (EOS) to describe the fluid phase and volumetric behavior. A ″detailed” EOS model often contains from 20 to 40 components, with the first 10 components representing pure compounds and the remaining components represent a split of the heavier C6+ material in single-carbon-number (SCN) fractions. A ″pseudoized” (or lumped) EOS model might contain only 6–9 lumped components. The selection of which components to lump together is difficult because of the huge number of possible combinations.This paper describes an automated method to find the best pseudoized EOS model based on an initial detailed SCN EOS model. The method is based on (1) a fitness function quantifying the quality of match between a pseudoized EOS model and the detailed SCN EOS model from which it is derived, (2) a genetic algorithm used to obtain a first initial solution and (3) a tabu search to refine this initial solution and find the optimal lumping scheme. The method allows for a set of constraints to be imposed on the lumping of components, such as (1) not lumping certain components (e.g. CO2), (2) forcing lumping of some components (e.g. i−C4 and n−C4).The proposed procedure was successfully able to find the optimal lumped EOS from a detailed SCN EOS with 34 components for three scenarios with different number of components in the lumped EOS (15, 9 and 6). The runtime is ranging from 10 to 45 min.

Experimental study of pore size distribution effect on phase transitions of hydrocarbons in nanoporous media

The phase behavior of a fluid in a nanoporous system is altered from that in the bulk due to confinement effects. There have been many experimental studies on this important effect, yet the vast majority are limited to porous media with a narrow or singular pore size distribution. However, natural porous media exhibit a broad pore size distribution. For example, in shale rocks the pore size ranges from several nanometers to hundreds of nanometers. It is not clear if a broad pore size distribution has a significant effect on the phase transition of nanoconfined fluids, and, if effects are present, how and why the phase behavior is altered. The effects of a distributed pore size on the bubble point of confined fluids as measured by differential scanning calorimetry (DSC) are not known. Here, we present an experimental study on the effect of pore size distribution on the liquid-vapor phase transition of n-hexane, n-octane and n-decane confined in nonporous media. We report a method to discretize the pore size distribution of natural shale rocks so that it can be mimicked using mixtures of synthetic nanoporous media. Using DSC, we show that the presence of a broad pore size distribution significantly alters the vapor-liquid phase transition of confined hydrocarbons. In fully saturated (i.e. filled) nanoporous media, the largest pore size dictates the onset of liquid-vapor phase transition (.i.e. bubblepoint). However, when the porous media is partially saturated, smaller pore sizes influence the bubblepoint. These findings suggest that there is a dependency of the confined fluid phase behavior on the fluid saturation in nanoporous media with a broad pore size distribution, which contributes to a broader understanding of phase transitions in natural porous media.

On the phase behavior of model fluids with square-well attraction in slit-like pores. Density functional approach

The phase behavior of a model fluid with square well inter-particle attraction in slit-like pores has been studied by using a density functional theory. The mean field theory and the first-order mean spherical approximation have been applied to account for the attractive interactions. The influence of the pore width, the gas-solid interaction energy and of the square well width on the phase behavior have been explored in detail. Dependent on the values of parameters of the model, we observed capillary condensation and capillary evaporation, in some cases layering phase transition has been obtained as well. Also, a crossover between condensation and evaporation has been described. The theory and the results obtained in the present work are valuable for future theoretical exploration of water-like and other models under confinement that intrinsically involve square well as a reference ingredient.

Multiscale Fluid-Phase-Behavior Simulation in Shale Reservoirs Using a Pore-Size-Dependent Equation of State

Summary The phase behavior of reservoir fluids plays a fundamental role in predicting well performance and ultimate recovery. The uncertainty in phase behavior is currently one of the greatest challenges in developing unconventional shale resources. The complex phase behavior is attributed to the broad range of pore sizes in shale. In macroscale geometries such as fractures and macropores, the fluid behavior is bulk-like; in nanoscale pores, the fluid behavior is significantly altered by confinement effects. The overall phase behavior of fluids in porous media of mixed pore sizes is yet to be understood. In this paper, we present a study on the effect of pore-size distribution on the phase behavior of shale-reservoir fluids in a multiscale-pore system. The global fluid-phase equilibria among different sizes of pores are simulated. A pore-size-dependent equation of state (EOS) is used to describe the fluid by the confining pore diameter. The EOS confinement parameters for fluid/pore-wall surface interaction are determined by experimental results from differential-scanning calorimetry (DSC) and isothermal adsorption of species C1–14. The multiscale phase equilibria are simulated by directly minimizing the total Helmholtz free energy. A modified Eagle Ford oil is used for the case study. Constant-composition expansions (CCEs) of dual-scale (bulk and 15 nm) and triple-scale (bulk, 15 nm, and 5 nm) systems are simulated. The first bubble emerges from the bulk region at a lightly suppressed “apparent” bubblepoint pressure. Below the bubblepoint, the liquid saturation in the bulk region drops sharply, but the fluids in the nanopores are undersaturated throughout the multistage expansions. In the end, large amounts of intermediate-to-heavy hydrocarbons are retained in nanopores, implying a significant oil-recovery loss in shale. The confinement effect also leads to near-critical phase behavior in small-scale nanopores (<5 nm).

Adsorption Thicknesses of Confined Pure and Mixing Fluids in Nanopores.

In this paper, adsorption thicknesses of confined pure and mixing fluids in nanopores are quantitatively determined and their influential factors are specifically evaluated. First, a new analytical formulation is developed thermodynamically to calculate the adsorption thicknesses. Second, a new generalized equation of state (EOS), which considers the confinement effect-induced phenomena, is developed analytically for calculating the thermodynamic confined fluid phase behavior. Third, the modified model based on the generalized EOS and coupled with the parachor model is applied to calculate the vapor-liquid equilibrium (VLE) and fluid adsorptions for the pure CO2, alkanes of C1-C10, and two mixtures of CO2-C10H22 and CH4-C10H22 in nanopores. Finally, the following five important factors are studied to evaluate their effects on the adsorption thickness: temperature, pressure, pore radius, wall-effect distance, and feed gas-to-liquid ratio (FGLR). The proposed modified EOS is found to be accurate for the VLE and adsorption isotherm calculations. The adsorption thicknesses of confined pure or mixing alkanes are increased with the increasing carbon number but decreased with the temperature increase. For the alkanes of C1-C10, the degree of temperature effect is strengthened with the carbon number increase. Moreover, the adsorption thicknesses are significantly decreased with the pore radius increase until rp = 50 nm, after which they have slight changes or are even constant at any pore radii. On the other hand, the wall-effect distance (δp) increase causes the adsorption thickness to be linearly increased at δp/ rp ≥ 0.02. In addition, the effects of the FGLR and pressure on the adsorption thicknesses at the nanoscale are found to be negligible.

Phase-Behavior Modeling of Oils in Terms of Saturates/Aromatics/Resins/Asphaltenes Fractions

Summary One of the key steps toward improving the predictability of air-injection-based processes relies on the development of accurate phase-behavior models of the oil. Historically, for in-situ combustion (ISC) in heavy oils and bitumens, phase behavior was often ignored because the physical aspects of the process (e.g., distillation) were not considered to be as significant as the oxidation reactions. However, this step is important for several reasons. First, the compositional model should reflect the phase behavior of the original fluids. Second, reaction rates are dependent on the concentrations of the reactants, which in turn are affected by the volatility of the components. This is particularly important for lighter oils (but not unimportant for heavier oils), where the phase equilibrium between the liquid and vapor can have a significant effect on the flammability range for vapor-phase combustion at given temperature and pressure conditions. Finally, for the case of lighter oils, a good phase-behavior model is required to capture the compositional effects of the resulting flue-gas drive. This study presents a practical work flow to develop a phase-behavior model in terms of saturates/aromatics/resins/asphaltenes (SARA) fractions that is aligned with the reaction-modeling approach used in most kinetic models. The methodology requires conventional-oil-characterization (i.e., dependent on distillation cuts) and conventional-phase-behavior experiments (e.g., differential liberation), as well as oil characterization in terms of SARA fractions. The first step of the method consists of splitting the heaviest oil fraction (i.e., plus fraction), followed by lumping all of the single-carbon-number (SCN) components, in such a way that the new oil characterization honors the SARA data available, such as composition and the physical properties of each fraction (e.g., molecular weight). In addition, the gas components (e.g., methane) would be treated as additional components as necessary. The second step is to tune an equation of state (EOS), in terms of the SARA-based model, to match the relevant laboratory experiments. Finally, the tuned EOS would be used to export the equilibrium constants (K-value tables) to the thermal numerical simulator. Different examples on the application of the phase-behavior-modeling work flow are presented and discussed in detail for heavy and light oils. This work opens up opportunities to model the ISC process for any oil (i.e., light or heavy) using the currently available kinetic models, which in turn is an important step toward improving the predictability of ISC processes using reservoir simulation.

A New Three-Phase Flash Algorithm Considering Capillary Pressure in a Confined Space

Tight/shale reservoirs are extensively containing nanopores, and the confined space in nanopores can greatly alter the phase behavior of reservoir fluids due to the strong capillarity effect. Many researches have been recently conducted to investigate the effect of capillary pressure in nanopores on altering the oleic-vapor two-phase equilibria. Few attempts have been made to describe the effect of capillarity on the aqueous-oleic-vapor three-phase equilibria. This work proposes a new algorithm for performing three-phase pressure-temperature (P-T) flash coupled with capillary effect. This algorithm considers two capillary pressures that exist across the two interfaces dividing the three phases in a nanopore. When describing the three-phase equilibria, two types of reservoir wettability are considered: water-wet formation and oil-wet formation. In each case, distribution of the three phases in a nanopore is determined based on the spreading coefficient which refers to the spreading ability of an oleic phase over the spreading ability of an aqueous phase. Example calculations are conducted to show the robustness of the new algorithm as well as to study the effect of capillarity on the three-phase equilibria. Computation results show that the three-phase P-T envelope for a given hydrocarbons/water mixture in a nanopore can be significantly altered by capillary pressure, but how the envelope moves will depend on the wettability of the nanopore and the spreading coefficient. The general trend is that both the upper branch (i.e., the oleic-aqueous/vapor-oleic-aqueous boundary) and the lower branch (i.e., the liquid-vapor/liquid-liquid-vapor boundary) of the three-phase envelope tend to move downward. Compared to the water-wet case, the oil-wet nanopore will shift the three-phase boundaries in a much larger degree. In addition to the alteration of the three-phase envelope, the presence of capillarity will also lead to the alteration of the phase fractions and phase compositions in the nanopore. Nanofluidic experiments should be conducted in the future to verify the findings obtained from the calculations.

Direct visualization and molecular simulation of dewpoint pressure of a confined fluid in sub-10 nm slit pores

The fluid phase behavior characterization at nanoscale is a challenging and significant problem for many processes such as polymer analysis, drug delivery, carbon dioxide storage, and petroleum production, among others. It is commonly accepted that the fluid phase behavior in sub-10 nm pores is considerably different than the phase behavior in bulk environment. In this study, experiments using the lab-on-a-chip approach has been conducted to measure and visualize n-Butane condensation pressure in nano-scale slit pores of 50 nm, 10 nm, and 4 nm. The result shows that n-Butane dewpoint pressure can deviate as high as 14% from its original value due to the confinement effect. Molecular simulation has also been performed with a purpose to model the experimental results. The simulation results show a good agreement with the experimental data and prove the significant impact of the confinement effect.

Progress in the Physisorption Characterization of Nanoporous Gas Storage Materials

Abstract Assessing the adsorption properties of nanoporous materials and determining their structural characterization is critical for progressing the use of such materials for many applications, including gas storage. Gas adsorption can be used for this characterization because it assesses a broad range of pore sizes, from micropore to mesopore. In the past 20 years, key developments have been achieved both in the knowledge of the adsorption and phase behavior of fluids in ordered nanoporous materials and in the creation and advancement of state-of-the-art approaches based on statistical mechanics, such as molecular simulation and density functional theory. Together with high-resolution experimental procedures for the adsorption of subcritical and supercritical fluids, this has led to significant advances in physical adsorption textural characterization. In this short, selective review paper, we discuss a few important and central features of the underlying adsorption mechanisms of fluids in a variety of nanoporous materials with well-defined pore structure. The significance of these features for advancing physical adsorption characterization and gas storage applications is also discussed.

Phase Behavior in Shale Organic/Inorganic Nanopores From Molecular Simulation

Summary Production from shale reservoirs is receiving more attention from the petroleum industry. However, there are many complexities associated with optimal production of shale reservoirs. One complexity is the unclear fluid-phase behavior in shale nanopores. In the shale nanopores, the interaction between the pore wall and fluid molecules can significantly change the fluid-phase behavior from the bulk (unconfined) condition. Therefore, the type of pore material can influence the fluid-phase behavior. There have been several recent efforts to model the confined fluid-phase behavior in shale reservoirs. However, the effect of pore material on fluid-phase behavior in shale reservoirs has not been addressed in the previous studies. In this paper, to have a better understanding of phase diagrams in different shale environments, we perform molecular simulations with three materials (two inorganic minerals and one kerogen) and two types of nanopores (slit and cylinder) to model the confined-phase behavior of pure fluids (methane and propane) and one ternary fluid (C1/C3/nC5). From the pure-fluid simulations in the pores of three diameters (4, 7, and 10 nm), confined liquid densities are decreased, whereas vapor densities are increased in the slit and cylinder pores. When pore diameters are increased, critical points are shifted to low densities and high temperatures. Critical temperature and density under confinement can deviate as high as 15 and 60%, respectively, from the original values in bulk. Molecular simulations are conducted for the ternary fluid in the slit and cylinder pores at 160°F. Under confinement, there is a large shift in the nC5 composition of the vapor phase in the ternary diagrams, whereas only small changes have been observed in the ternary diagrams of liquid phase. The density difference between two phases is reduced. Additional tests are performed at one typical shale temperature (290°F) for this ternary fluid in both nanopore types. Phase separation is observed in the slit-pore tests, although only one phase is formed in the tests of the cylinder pores. Because the cylinder pore has more adsorption surface area compared with the slit pore, a stronger adsorption effect is introduced in all tests of the cylinder pores. Based on the comparison of all results (pure fluids and ternary fluid) from the three materials, the calcite pores provide a stronger confinement effect on fluids, and the other two materials have a similar confinement effect on the phase diagrams.

Investigation of Cyclic $$\text {CO}_{2}$$ CO 2 Injection Process with Nanopore Confinement and Complex Fracturing Geometry in Tight Oil Reservoirs

Carbon dioxide is one of the capable processes in improving oil recovery from low-permeable oil reservoirs. However, the evaluation of cyclic $$\text {CO}_{2}$$ injection process with nanopore confinement effect in tight reservoirs is deficient in the oil industry. The nanopores confinement plays a significant role in low-permeable formations, creating a high capillary pressure which substantially influences fluid phase behavior and fluid flow in tight reservoirs. In order to consider the effect of nanopore confinement in unconventional reservoirs, the conventional methods need to be modified. Thus, we evolve an effective model for cyclic $$\text {CO}_{2}$$ injection process considering the effect of complex fracture geometry with nanopore confinement on the production from tight formations. Firstly, the reservoir fluid properties with nanopore confinement are estimated. Secondly, the minimum miscibility pressure is measured and verified with experimental data. Lastly, the well performance of cyclic $$\text {CO}_{2}$$ injection process in unconventional tight reservoirs is evaluated based on few parameters such as $$\text {CO}_{2}$$ diffusivity and matrix permeability. The results show that the combined effect of capillary pressure and $$\text {CO}_{2}$$ dispersion has significantly influenced the oil production efficiency from tight oil reservoirs. The oil recovery factor of cyclic $$\text {CO}_{2}$$ injection process at five years boosts from 14.67% as primary recovery to 22.54% due to $$\text {CO}_{2}$$ molecular diffusion effect with overall 7.87% incremental recovery. Moreover, the incremental oil recovery of cyclic $$\text {CO}_{2}$$ injection process is increased further by 1.7% while taking into consideration the combine effect of capillary pressure and $$\text {CO}_{2}$$ diffusion on the oil recovery. This study provides an appropriate method for predicting the production of cyclic $$\text {CO}_{2}$$ injection process with a complex fracture geometry, considering the capillary pressure and $$\text {CO}_{2}$$ diffusion on well performance of tight oil reservoirs.

Brownian Motion at Lipid Membranes: A Comparison of Hydrodynamic Models Describing and Experiments Quantifying Diffusion within Lipid Bilayers.

The capability of lipid bilayers to exhibit fluid-phase behavior is a fascinating property, which enables, for example, membrane-associated components, such as lipids (domains) and transmembrane proteins, to diffuse within the membrane. These diffusion processes are of paramount importance for cells, as they are for example involved in cell signaling processes or the recycling of membrane components, but also for recently developed analytical approaches, which use differences in the mobility for certain analytical purposes, such as in-membrane purification of membrane proteins or the analysis of multivalent interactions. Here, models describing the Brownian motion of membrane inclusions (lipids, peptides, proteins, and complexes thereof) in model bilayers (giant unilamellar vesicles, black lipid membranes, supported lipid bilayers) are summarized and model predictions are compared with the available experimental data, thereby allowing for evaluating the validity of the introduced models. It will be shown that models describing the diffusion in freestanding (Saffman-Delbrück and Hughes-Pailthorpe-White model) and supported bilayers (the Evans-Sackmann model) are well supported by experiments, though only few experimental studies have been published so far for the latter case, calling for additional tests to reach the same level of experimental confirmation that is currently available for the case of freestanding bilayers.