Theory of Multicomponent, Multiphase Displacement in Porous Media

1981 ◽  
Vol 21 (01) ◽  
pp. 51-62 ◽  
Author(s):  
Friedrich G. Helfferich
Keyword(s):  
Porous Media ◽  
Phase Equilibria ◽  
Oil Recovery ◽  
Arbitrary Number ◽  
Mobile Phase ◽  
Fluid Dynamic ◽  
Flow Behavior ◽  
Pressure Effects ◽  
Number Of Components ◽  
Two Phases

Abstract The basis of a general theory of multicomponent, multiphase displacement in porous media is presented. The theory is applicable to an arbitrary number of phases, an arbitrary number of components partitioning between the phases, and variable initial and injection conditions. Only the effects of propagation are considered; phase equilibria and dependence of fractional flows on phase compositions and saturations are required as input, but any type of equilibrium and flow behavior can be accommodated. The principal simplifying assumptions are the restriction to one dimension, local phase equilibria, volume additivity on partitioning, idealized fluid dynamic behavior, and absence of temperature and pressure effects. The theory is an extension of that of multicomponent chromatography and has taken from it the concept of "coherence" and, for practical application, the tools of composition routes and distance/time diagrams. The application of the theory to a surfactant flood is illustrated in a companion paper.1 Introduction A key problem in modern methods of enhanced oil recovery is that of multicomponent, multiphase displacement in porous media. This term means the induced flow of any number of simultaneous, not fully miscible fluid phases consisting of any number of components. The components may partition between the phases; moreover, the physical properties of the phases (densities, viscosities, interfacial tensions, etc.) depend on composition and, therefore, on partitioning of the components. Multicomponent, multiphase displacement may be viewed as a generalization and combination of two different and independent approaches. The first of these is the highly developed theory of multicomponent chromatrography,2 which allows for any number of components affecting one canother's distribution behavior but admits only one mobile and one stationary phase. This theory has to be extended to more than one mobile phase. The second is the fluid dynamic theory of immiscible displacement in porous media, allowing for more than one mobile phase but not for partitioning of components. This theory was developed in the 1940's for two mobile phases3 and so far has not been stated in general form for more than two phases. It has to be extended to include partitioning of the components between the phases and its effects on phase properties. A summary of the start of the art, including recent work on systems with up to three components and two phases, has been given by Pope.4 This paper describes the extension of the theory to multicomponent, multiphase displacement with partitioning and for arbitrary initial and boundary conditions. The theory concerns itself only with transport behavior. Phase equilibrium and flow properties of the phases (relative permeabilities) as a function of composition are considered as given. Application of the theory, therefore, requires as input either empirical correlations of experimental data on phase equilibria and properties or theories predicting these. Morever, the theory concentrates exclusively on multicomponent, multiphase effects and does not attempt to account for the complex fluid dynamic situation in real, three-dimensional, and nonuniform reservoirs.

scholarly journals Microfluidic Study of Drainage and Imbibition in Porous Media: Definition of Amott Indices

2011 ◽  
Author(s):  
Emilie Dressaire ◽  
Howard A. Stone
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Pressure Difference ◽  
Flow Behavior ◽  
Critical Role ◽  
Rock Surface ◽  
Repeat Units ◽  
Fluid Saturation ◽  
Two Phases ◽  
Wetting Fluid

The wettability of reservoir rocks plays a critical role in oil recovery operations. This property is traditionally defined in terms of the contact angle between the fluid-fluid interface and the solid surface. In natural porous media, it has been preferred to characterize the wettability and its effects on fluid flow behavior in terms of Amott indices, through the capillary pressure-fluid saturation relationship. This “bulk” definition is based on the steady states reached by the two phases, the wetting one and the non-wetting one, upon drainage (removal of the wetting fluid) and imbibition (removal of the non-wetting fluid). These indices provide some indirect indication of the rock surface chemistry and porosity structure. Previous studies on Amott indices have mostly focused on numerical modeling of rocks. In this paper, we present an experimental study on two phase flow in regular lattices of glass microchannels. A wet etching technique is used to fabricate 2D networks composed of hundreds of repeat units. The repeat units are square, hexagonal, or triangular, with a lattice parameter of about 100 micrometers. Controlling and varying the microchannel wettability, network geometry, and fluid properties allow correlating the physical chemistry of the system and the characteristics of the multiphase flow. We perform drainage-imbibition cycles by controlling the pressure difference across the device. For each pressure difference, we record and characterize the distribution of the two phases at equilibrium. Our results capture the dependance of the Amott index on both fluid and network properties. The values obtained are consistent with previous studies on wetting phenomena at the pore level. The drainage-imbibition cycles also provide information on the patterns of invasion. We show that the study of the cycles can further predictability of Amott indices.

scholarly journals Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Polymers ◽  
2018 ◽  
Vol 10 (11) ◽  
pp. 1225 ◽  
Author(s):  
Xiankang Xin ◽  
Gaoming Yu ◽  
Zhangxin Chen ◽  
Keliu Wu ◽  
Xiaohu Dong ◽  
...  
Keyword(s):  
Porous Media ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Flow Behavior ◽  
Polymer Flooding ◽  
Oil Reservoirs ◽  
Flow In Porous Media ◽  
Newtonian Flow ◽  
Heavy Oil Reservoirs

The flow of polymer solution and heavy oil in porous media is critical for polymer flooding in heavy oil reservoirs because it significantly determines the polymer enhanced oil recovery (EOR) and polymer flooding efficiency in heavy oil reservoirs. In this paper, physical experiments and numerical simulations were both applied to investigate the flow of partially hydrolyzed polyacrylamide (HPAM) solution and heavy oil, and their effects on polymer flooding in heavy oil reservoirs. First, physical experiments determined the rheology of the polymer solution and heavy oil and their flow in porous media. Then, a new mathematical model was proposed, and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed considering the non-Newtonian flow. The designed simulator was validated by comparing its results with those obtained from commercial software and typical polymer flooding experiments. The developed simulator was further applied to investigate the non-Newtonian flow in polymer flooding. The experimental results demonstrated that the flow behavior index of the polymer solution is 0.3655, showing a shear thinning; and heavy oil is a type of Bingham fluid that overcomes a threshold pressure gradient (TPG) to flow in porous media. Furthermore, the validation of the designed simulator was confirmed to possess high accuracy and reliability. According to its simulation results, the decreases of 1.66% and 2.49% in oil recovery are caused by the difference between 0.18 and 1 in the polymer solution flow behavior indexes of the pure polymer flooding (PPF) and typical polymer flooding (TPF), respectively. Moreover, for heavy oil, considering a TPG of 20 times greater than its original value, the oil recoveries of PPF and TPF are reduced by 0.01% and 5.77%, respectively. Furthermore, the combined effect of shear thinning and a threshold pressure gradient results in a greater decrease in oil recovery, with 1.74% and 8.35% for PPF and TPF, respectively. Thus, the non-Newtonian flow has a hugely adverse impact on the performance of polymer flooding in heavy oil reservoirs.

scholarly journals Numerical Simulation of Two-Phase Flows in Heterogeneous Porous Media

2020 ◽  
Vol 21 (2) ◽  
pp. 339
Author(s):  
I. Carneiro ◽  
M. Borges ◽  
S. Malta
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Water Injection ◽  
Heterogeneous Porous Media ◽  
Flow In Porous Media ◽  
High Porosity ◽  
Two Phase ◽  
Recovery Method ◽  
Porosity And Permeability

In this work,we present three-dimensional numerical simulations of water-oil flow in porous media in order to analyze the influence of the heterogeneities in the porosity and permeability fields and, mainly, their relationships upon the phenomenon known in the literature as viscous fingering. For this, typical scenarios of heterogeneous reservoirs submitted to water injection (secondary recovery method) are considered. The results show that the porosity heterogeneities have a markable influence in the flow behavior when the permeability is closely related with porosity, for example, by the Kozeny-Carman (KC) relation.This kind of positive relation leads to a larger oil recovery, as the areas of high permeability(higher flow velocities) are associated with areas of high porosity (higher volume of pores), causing a delay in the breakthrough time. On the other hand, when both fields (porosity and permeability) are heterogeneous but independent of each other the influence of the porosity heterogeneities is smaller and may be negligible.

Foam in Porous Media: Characteristics and Potential Applications

1970 ◽  
Vol 10 (04) ◽  
pp. 328-336 ◽  
Author(s):  
S. H. Raza
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Foaming Agent ◽  
Reservoir Rocks ◽  
Recovery Processes ◽  
Potential Applications ◽  
Foam In Porous Media

Abstract A laboratory study was made of the variables which affect the generation, propagation, quality und nature of foam produced inside a porous medium. It is shown that foam can be generated and propagated in porous media representative of reservoir rocks at pressure levels ranging from atmospheric to 1,000 psig, and under pressure differentials ranging from 1.0 to 50 psi/ft. The quality of foam depends on the type of foaming agent, the concentration of foaming solution, the physical properties of the porous medium, the pressure level, and the composition and saturation of fluids present. The nature of foam depends upon the type of foaming agent and its concentration in the foaming solution. The study shows that the flow behavior of foam in a porous medium is a complex one which cannot he correctly described in terms of the high apparent viscosity of foam. Also, the concept of relative permeability is not applicable to the flow of foam due to the associative nature of its components. On the basis of the discussed characteristics of foam, several applications of foam are suggested in oil recovery processes.

Pseudo-Plastic Behavior of a Film Foam Flow with Carbon Dioxide as the Internal Gas Phase

2011 ◽  
Vol 221 ◽  
pp. 15-20 ◽  
Author(s):  
Dong Xing Du ◽  
Ying Ge Li ◽  
Shi Jiao Sun
Keyword(s):  
Porous Media ◽  
Shear Rate ◽  
Gas Phase ◽  
Oil Recovery ◽  
Apparent Viscosity ◽  
Flow Behavior ◽  
Plastic Behavior ◽  
Straight Tube ◽  
Foam Flow ◽  
Co2 Foam

There are many attractive features for using CO2 foam injection in Enhanced Oil Recovery (EOR) processes. For understanding CO2 foam rheology in porous media, an experimental study is reported in this paper concerning CO2 film foam flow characteristics in a vertical straight tube. Foam is treated as non-Newtonian fluid and its pseudo-plastic behavior is investigated based on power law constitutive model. It is observed the CO2 film foam flow shows clear shear-thinning behavior, with flow consistency coefficient of K=0.15 and flow behavior index of n=0.48. The apparent viscosity of flowing CO2 film foam is under the shear rate of 50s-1 and under the shear rate of 1000s-1, which are 19 and 3 times higher than the single phase water. It is also found CO2 foam has lower apparent viscosity than the foam with air as the internal gas phase, which is in consistence with experimental observations for lower CO2 foam flow resistance in porous media.

scholarly journals Pore-Scale Simulations of CO2/Oil Flow Behavior in Heterogeneous Porous Media under Various Conditions

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 533
Author(s):  
Qingsong Ma ◽  
Zhanpeng Zheng ◽  
Jiarui Fan ◽  
Jingdong Jia ◽  
Jingjing Bi ◽  
...  
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Heterogeneous Porous Media ◽  
Co2 Injection ◽  
Injection Velocity ◽  
Recovery Efficiency ◽  
Small Pore ◽  
Miscible Flooding ◽  
Oil Flow

Miscible and near-miscible flooding are used to improve the performance of carbon-dioxide-enhanced oil recovery in heterogeneous porous media. However, knowledge of the effects of heterogeneous pore structure on CO2/oil flow behavior under these two flooding conditions is insufficient. In this study, we construct pore-scale CO2/oil flooding models for various flooding methods and comparatively analyze CO2/oil flow behavior and oil recovery efficiency in heterogeneous porous media. The simulation results indicate that compared to immiscible flooding, near-miscible flooding can increase the CO2 sweep area to some extent, but it is still inefficient to displace oil in small pore throats. For miscible flooding, although CO2 still preferentially displaces oil through big throats, it may subsequently invade small pore throats. In order to substantially increase oil recovery efficiency, miscible flooding is the priority choice; however, the increase of CO2 diffusivity has little effect on oil recovery enhancement. For immiscible and near-miscible flooding, CO2 injection velocity needs to be optimized. High CO2 injection velocity can speed up the oil recovery process while maintaining equivalent oil recovery efficiency for immiscible flooding, and low CO2 injection velocity may be beneficial to further enhancing oil recovery efficiency under near-miscible conditions.

Mass Transfer Between Phases in a Porous Medium: A Study of Equilibrium

1965 ◽  
Vol 5 (01) ◽  
pp. 51-59 ◽  
Author(s):  
P. Raimondi ◽  
M.A. Torcaso
Keyword(s):  
Mass Transfer ◽  
Porous Media ◽  
Partition Coefficient ◽  
Oil Recovery ◽  
Carrier Phase ◽  
Peak Height ◽  
Lower Velocity ◽  
Immobile Phase ◽  
Two Phases ◽  
Gas Drive

Abstract To study mass transport in systems simulating oil recovery processes, different porous media were saturated with a mobile (carrier phase) and a stationary phase. Slugs of carrier phase containing a small amount of solute were displaced with pure carrier phase. By analogy to the chromatographic processes, the velocity of the solute can be predicted from a knowledge of the partition coefficient and the saturation provided that equilibrium between the two phases exists. Equilibrium was found to exist for different porous media, solutes and rates. The conditions were varied over the range normally encountered in the laboratory and in the field. The longitudinal dispersion of a solute undergoing interphase mass transfer was also investigated. Introduction The production of hydrocarbons by gas cycling, enriched gas drive and CO2 or alcohol displacement involves, among other factors, relative motion between two phases and compounds, hereafter called solute, which are soluble in both phases. The solute is carried forward by the faster flowing phase at a lower velocity than the average velocity of that phase. Retardation of the solute is caused by chromatographic absorption and desorption in the slower flowing phase and by the degree of departure from equilibrium. At equilibrium the concentration of solute in the two phases can be related by the equation* (1) where Csw and Cso are the concentration of solute in the aqueous and oleic phases respectively and K is the equilibrium ratio, or partition coefficient. Displacement theories must contain an explicit assumption with regard to equilibrium, i.e., whether the compositions can be related by Eq. 1. The existance of equilibrium depends, in general on the relative velocity between the phases. Unfortunately, other factors such as gravity segregation and viscous fingering, also depend on velocity. For this reason, whenever effects of rate on displacement were observed, it was practically impossible to discern what caused them - lack of equilibrium or the factors mentioned above. Equilibrium between phases has been the subject of extensive studies in fields such as extraction or chromatography. It has received only small attention in flow through the type of porous media encountered in oil production. For this reason a method was developed which makes it possible to study the movement of a solute as it is affected by rate, type of porous media, partition coefficient and carrier phase, but in the absence of segregation or fingering. The information obtained enables one to determine when the assumption of equilibrium can be made. Briefly, the method consists of (1) saturating the core with a mobile and an immobile phase, (2) injecting a slug made up of the same fluid as the mobile phase and a small concentration of mutually soluble solute, (3) measuring the lag and the peak height of the slug at arrival and (4) correlating these variables with fluid properties such as partition coefficient and mixing constants of the medium. PROPOSED MECHANISM The principles of chromatography are combined with the equation of longitudinal mixing to predict the velocity of a solute slug compared to the bulk velocity and the peak height of a slug. The equation so obtained is valid under equilibrium conditions only. Therefore, a comparison between experimental and predicted results will give a measure of departure from equilibrium. This work was done with either the oleic or the aqueous phase being immobile. For simplicity, the following development is based on the case where the oleic phase is immobile. However, the treatment is the same in either case. SPEC P. 51ˆ

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