Abstract: This paper reports a laboratory study of foams intended to improve immiscible gas flooding in oil production. The study is relevant for both continuous and Water Alternating Gas (WAG) injection schemes. The effect of oil on the longevity of nitrogen and air foams was studied in bulk for a selected set of surfactants. Foam heights were measured in a glass column as a function of time, in the absence and presence of mineral and crude oils. The column experiments indicated that foam longevity increases as the carbon chain length in the oil molecule increases, i.e. foam is generally more stable in the presence of higher-viscosity oils. The surfactant formulation that gave the most stable foam in the presence of oil was used in core floods. Oil recovery from natural sandstone cores with CO2 and with N2 foams was studied with the aid of X-ray Computed Tomography, while the injection rates, foam quality and surfactant concentration were varied. The core floods revealed that foam increases oil recovery by as much as 20% of the oil initially in place (OIIP) as compared with water flooding, while gas injection increases oil recovery by 10% only. Thus, foam can achieve an additional recovery of up to 10% relative to gas injection. This confirms that foam is potentially an efficient Enhanced Oil Recovery (EOR) method.
Abstract: The aim of this paper is to provide a perspective on the effect of gas type on the permeability of foam films stabilized by different types of surfactant and to present a critical overview of the tracer gas experiments, which is the common approach to determine the trapped fraction of foam in porous media. In these experiments some part of the gas is replaced by a “tracer gas†during the steady-state stage of the experiments and trapped fraction of foam is determined by fitting the effluent data to a capacitance mass-transfer model.
We present the experimental results on the measurement of the gas permeability of foam films stabilized with five surfactants (non-ionic, anionic and cationic) and different salt concentrations. The salt concentrations assure formation of either common black (CBF) or Newton black films (NBF). The experiments are performed with different single gasses. The permeability of the CBF is in general higher than that of the NBF. This behavior is explained by the higher density of the surfactant molecules in the NBF compared to that of CBF. It is also observed that the permeability coefficient, K(cm/s), of CBF and NBF for non-ionic and cationic surfactants are similar and K is insensitive to film thickness. Compared to anionic surfactants, the films made by the non-ionic surfactant have much lower permeability while the films made by the cationic surfactant have larger permeability. This conclusion is valid for all gasses. For all types of surfactant the gas permeability of foam film is largely dependent on the dissolution of gas in the surfactant solution and increases with increasing gas solubility in the bulk liquid.
The measured values of K are consistent with rapid diffusion of tracer gasses through trapped gas adjacent to flowing gas in porous media, and difficulties in interpreting the results of tracer-foam experiments with conventional capacitance models. The implications of the results for foam flow in porous media and factors leading to difficulties in the modeling of trapped fraction of foam are discussed in detail. To avoid complications in the interpretation of the results, the best tracer would be one with a permeability close to the permeability of the gas in the foam. This puts a lower limit on the effective diffusion coefficient for tracer in an experiment.
Abstract: The efficiency of mixing in density-driven natural-convection is largely governed by the aquifer permeability, which is heterogeneous in practice. The character (fingering, stable mixing or channeling) of flow-driven mixing processes depends primarily on the permeability heterogeneity character of the aquifer, i.e., on its degree of permeability variance (Dykstra-Parsons coefficient) and the correlation length. Here we follow the ideas of Waggoner et al. (1992) to identify different flow regimes of a density-driven natural convection flow by numerical simulation. Heterogeneous fields are generated with the spectral method of Shinozuka and Jan (1972), because the method allows the use of power-law variograms. In this paper, we extended the classification of Waggoner et al (1992) for the natural convection phenomenon, which can be used as a tool in selecting optimal fields with maximum transfer rates of CO2 into water. We observe from our simulations that the rate of mass transfer of CO2 into water is higher for heterogeneous media.
Abstract: We report the study of flow of CO2 and N2 foam in natural sandstone cores containing oil with the aid of X-ray computed tomography. The study is relevant for enhanced oil recovery (EOR). The cores were partially saturated with oil and brine (half top) and brine only (half bottom) to mimic the water−oil transition occurring in oil reservoirs. The CO2 was used either under subcritical conditions (P = 1 bar) or under supercritical (immiscible (P = 90 bar) and miscible (P = 137 bar)) conditions, whereas N2 remained subcritical. Prior to gas injection the cores were flooded with several pore volumes of water. In a typical foam experiment water flooding was followed by the injection of 1−2 pore volumes of a surfactant solution with alpha olefin sulfonate (AOS) as the foaming agent. We visually show how foam propagates in a porous medium containing oil. At low-pressure experiments (P = 1 bar) in the case of N2, weak foam could be formed in the oil-saturated part. Diffused oil bank is formed ahead of the foam front, which results in additional oil recovery, compared to pure gas injection. CO2 hardly foams in the oil-bearing part of the core, most likely due to its higher solubility. Above the critical point (P = 90 bar), CO2 injection following the slug of surfactant reduces its mobility when there is no oil. Nevertheless, when the foam front meets the oil, the interface between gas and liquid disappears. The presence of the surfactant (when foaming supercritical CO2) did not affect the oil recovery and pressure profile, indicating the detrimental effect of oil on foam stability in the medium. However, at miscible conditions (P = 137 bar), injection of surfactant prior to CO2 injection significantly increases the oil recovery.
Abstract: We report an experimental study of the behavior of CO2 and N2 foams in granular porous media using X-ray computed tomography. In the experiments either CO2 or N2 gas is forced through natural porous media initially saturated with a surfactant solution, a process known as surfactant-alternating-gas or SAG. The CO2 was either under sub- or supercritical conditions, whereas N2 remained under subcritical conditions at all experimental conditions. We found that CO2 injection following a slug of surfactant can considerably reduce its mobility and promote higher liquid recovery at the experimental conditions investigated. Foaming of CO2 builds-up a lower pressure drop over the core at both low and high pressures than N2. Both gases require space to develop into foam. The space is longer for N2 (larger entrance effect) and increases with increasing gas velocity. Moreover, the ultimate liquid recovery by CO2 foam is always lower than by N2 foam. The possible mechanisms explaining the observed differences in foaming behavior of the two gases are discussed in detail.
Abstract: Concern over global warming has increased interest in quantification of the dissolution of CO2 in (sub-)surface water. The mechanisms of the mass transfer of CO2 in aquifers and of transfer to surface water have many common features. The advantage of experiments using bulk water is that the underlying assumptions to the quantify mass-transfer rate can be validated. Dissolution of CO2 into water (or oil) increases the density of the liquid phase. This density change destabilizes the interface and enhances the transfer rate across the interface by natural convection. This paper describes a series of experiments performed in a cylindrical PVT-cell at a pressure range of pi = 10−50 bar, where a fixed volume of CO2 gas was brought into contact with a column of distilled water. The transfer rate is inferred by following the gas pressure history. The results show that the mass-transfer rate across the interface is much faster than that predicted by Fickian diffusion and increases with increasing initial gas pressure. The theoretical interpretation of the observed effects is based on diffusion and natural convection phenomena. The CO2 concentration at the interface is estimated from the gas pressure using Henry’s solubility law, in which the coefficient varies with both pressure and temperature. Good agreement between the experiments and the theoretical results has been obtained.
Abstract: The problem of formation damage (i.e., permeability reduction due to injection of particulates), is a matter of interest in several engineering fields. In the previous attempts to model the external cake formation, cake thickness has been considered to be only dependent on time; even though in practical applications, the dependency of the cake profile on space can be important. In this article, a novel model has been developed to describe the steady state external filter cake thickness profile along the wellbore. A set of equations is derived from the force balance for a deposited particle on the cake surface and the volume conservation of the fluid in the wellbore. These equations are combined with Darcy's law in radial geometry and the equation of flow in the wellbore, and solved numerically to obtain the cake thickness and fluid velocity profiles along the wellbore.
Abstract: The gas permeability of equilibrium foam films stabilized with an α-olefin sulfonate surfactant was measured. The permeability coefficient, K (cm/s), was obtained as a function of the electrolyte (NaCl) concentration, surfactant concentration, and temperature. The addition of salt to the film-forming solution leads to a decrease of the film thickness, which was complemented by an increase of K up to a certain value. Above that critical salt concentration, the gas permeability decreases even though the film thickness also decreases. We explain this effect as a result of interplay of the film thickness and the adsorption monolayer permeability for the permeability of the whole film, i.e., the thermodynamic state of the film. The classical theories that explain the process were applied. The gas permeability of the film showed an unexpected increase at surfactant concentrations well above the critical micelle concentration. The origin of this effect remains unclear and requires further studies to be clarified. The experiments at different temperatures allowed the energy barrier of the permeability process to be estimated.
Abstract: The mass transfer of gas through foam films is a prototype of various industrial and biological processes. The aim of this paper is to give a perspective and critical overview of studies carried out to date on the mass transfer of gas through foam films. Contemporary experimental data are summarized, and a comprehensive overview of the theoretical models used to explain the observed effects is given. A detailed description of the processes that occur when a gas molecule passes through each layer that forms a foam film is shown. The permeability of the film-building surfactant monolayers plays an important role for the whole permeability process. It can be successfully described by the models used to explain the permeability of surfactant monolayers on aqueous sub-phase. For this reason, the present paper briefly discusses the surfactant-induced resistance to mass transfer of gases through gas–liquid interface. One part of the paper discusses the experimental and theoretical aspects of the foam film permeability in a train of foam films in a matrix or a cylinder. This special case is important to explain the gas transfer in porous media or in foams. Finally, this paper will highlight the gaps and challenges and sketch possible directions for future research.
Abstract: Alpha olefin sulfonate (AOS) surfactants have shown outstanding detergency, lower adsorption on porous rocks, high compatibility with hard water and good wetting and foaming properties. These properties make AOS an excellent candidate for foam applications in enhanced oil recovery. This paper summarizes the basic properties of foam films stabilized by an AOS surfactant. The foam film thickness and contact angle between the film and its meniscus were measured as a function of NaCl and AOS concentrations. The critical AOS concentration for formation of stable films was obtained. The critical NaCl concentration for formation of stable Newton black films was found. The dependence of the film thickness on the NaCl concentration was compared to the same dependence of the contact angle experiments. With increasing NaCl concentration the film thickness decreases gradually while the contact angle (and, respectively the free energy of film formation) increases, in accordance with the classical DLVO theory.
The surface tension isotherms of the AOS solutions were measured at different NaCl concentrations. They coincide on a single curve when plotted as a function of mean ionic activity product. Our data imply that the adsorption of AOS is independent of NaCl concentration at a given mean ionic activity.
Abstract: Carbon dioxide (CO2) has found wide application in the water-alternating-foam (WAF) processes for enhanced oil recovery (EOR), but few research works have been reported concerning the effect of water solubility on the CO2 foam rheology in a porous medium. In this paper, an X-ray computed tomography (CT) study is carried out to investigate CO2 foam flow in a consolidated Bentheimer sandstone core saturated with surfactant solution under different system pressures. As a contrast gas with much lower solubility, nitrogen foam flow is also investigated to show the essence of gas solubility effects. Careful considerations were made on the selection of contrast gases, surfactant, and experimental procedures to focus on the effect of water solubility of the gas on foam rheology in porous media. It is observed from the experiments that CO2 foam has lower pressure loss and clearly suppressed entrance effect. With the increment of system pressure, the liquid saturation increases and the pressure loss decreases significantly for CO2 foam flow in the sample core, while little change can be observed for N2 foam flow. It can be concluded that water solubility is one of the important influential factors for CO2 foam rheology in porous media.
Abstract: The mass transfer of CO2 into water and aqueous solutions of sodium dodecyl sulphate (SDS) is experimentally studied using a pressure, volume, temperature (PVT) cell at different initial pressures and a constant temperature (T = 25°C). It is observed that the transfer rate is initially much larger than expected from a diffusion process alone. The model equations describing the experiments are based on Fick's Law and Henry's Law. The experiments are interpreted in terms of two effective diffusion coefficients—one for the early-stages of the experiments and the other one for the later stages. The results show that at the early stages, the effective diffusion coefficients are one order of magnitude larger than the molecular diffusivity of CO2 in water. Nevertheless, in the later stages the extracted diffusion coefficients are close to literature values. It is asserted that at the early stages, density-driven natural convection enhances the mass transfer. A similar mass transfer enhancement was observed for the mass transfer between a gaseous CO2 rich phase with an oil (n-decane) phase. It is also found that at the experimental conditions studied addition of pure SDS does not have a significant effect on the mass transfer rate of CO2 in water.
Abstract: In this paper we investigate the mass transfer of CO2 injected into a homogenous (sub)-surface porous formation saturated with a liquid. In almost all cases of practical interest CO2 is present on top of the liquid. Therefore, we perform our analysis to a porous medium that is impermeable from sides and that is exposed to CO2 at the top. For this configuration density-driven natural convection enhances the mass transfer rate of CO2 into the initially stagnant liquid. The analysis is done numerically using mass and momentum conservation laws and diffusion of CO2 into the liquid. The effects of aspect ratio and the Rayleigh number, which is dependent on the characteristics of the porous medium and fluid properties, are studied. This configuration leads to an unstable flow process. Numerical computations do not show natural convection effects for homogeneous initial conditions. Therefore a sinusoidal perturbation is added for the initial top boundary condition. It is found that the mass transfer increases and concentration front moves faster with increasing Rayleigh number. The results of this paper have implications in enhanced oil recovery and CO2 sequestration in aquifers.
Abstract: We investigate the deep-bed ï¬ltration of micron-sized hematite particles suspended in distilled water
during flow in siliceous granular porous media, where particle retention is mostly due to surface van der Waals and electrostatic interactions. We show that x-ray computed tomography enables three-dimensional images of the ï¬ltration process to be generated. The one-dimensional ï¬ltrate concentration proï¬les obtained by averaging the images over sections perpendicular to the flow direction are rapidly decaying functions of the distance from the porous medium inlet and slide upward in the course of time, consistently with theï¬ltration model presented by Herzig et al. (Ind. Eng.Chem. 62,8, 1970). Finally, the ï¬ltration coefï¬cient is found to decrease rapidly as a function of time: This in dicates that the attractive interaction responsible for the retention of the hematite
particles is strongly attenuated as the particles accumulate of the pore surfaces.
Abstract: In this paper we follow a similar procedure as proposed by Koval (1963) to analytically model the performance of gravitationally unstable flow in porous media. The Koval model is analogous to the Buckley-Leverett method and multiplies the heterogeneity index of the system as an input (H-factor) with the fluid-flow (here gravity) induced instability factor, E to obtain the Koval factor KG = HE. This paper only considers the gravity induced instability factor E (H=1). The Koval factor is implemented in a modified fractional flow function that includes a dilution effect when the CO2 moves away from the interface to describe countercurrent gravity flow. The pseudo two-phase flow problem provides the average concentration of CO2 in the brine as a function of distance. The KG-factor can be used in commercial simulators to account for the density-driven natural convection, which cannot be currently captured because the grid cells are typically orders of magnitude larger than the wavelength of the initial fingers. Such natural convection effects occur in storage of greenhouse gases in aquifers and EOR processes using carbon dioxide or other solvents.
A comparison of the analytical model with the horizontally-averaged concentrations obtained from 2-D numerical simulations provides a correlation for calculation of the KG-factor for different Rayleigh numbers. The model shows a rarefaction followed by shock-like behavior because the CO2 concentration decreases away from the gaseous CO2-liquid interface. The agreement between the analytical model and full numerical simulation is practically acceptable. We leave the introduction of the heterogeneity factor for future work.
Notes: Density-driven natural convection, CO2, CO2 sequestration, Gravitationally unstable flow
Abstract: Accurate modeling of an Alkali Surfactant Polymer (ASP) flood requires detailed representation of
the geochemistry and, if natural acids are present, the saponification process. Geochemistry and
saponification affect the propagation of the injected chemicals and the amount of generated natural
soaps. These in turn determine the chemical phase behavior and hence the effectiveness of the ASP
process.
In this paper it is shown that by coupling the Shell in-house simulator MoReS with PHREEQC a
robust and flexible tool has been developed to model ASP floods. PHREEQC is used as the chemical
reaction engine, which determines the equilibrium state of the chemical processes modeled. MoReS
models the impact of the chemicals on the flow properties, solves the flow equations and transports
the chemicals.
The validity of the approach is confirmed by benchmarking the results with the ASP module of the
UTCHEM simulator (UT Austin). Moreover, ASP core floods have been matched with the new tool.
The advantages of using PHREEQC as the chemical engine are its rich database of chemical species
and its flexibility to change the chemical processes to be modeled. Therefore, the coupling procedure
presented in this paper can also be extended to other chemical-EOR methods.
Abstract: In order to design and analyze Alkaline Surfactant Polymer (ASP) pilots and to generate reliable ASP field
forecasts a robust scalable modeling workflow for the ASP process is required. A starting point of such a
workflow is to carry out ASP coreflood tests and history match those using numerical models. This allows
validation of the models and generates a set of chemical flood parameters that can be used for field-scale
simulation forecasts.
It is well established that lowering of interfacial tension due to mixing of in-situ generated soap with
injected surfactant and improved mobility control due to the polymer play a crucial role in the ASP
process. Therefore, all models for the ASP process take into account these mechanisms in one way or the
other. However, ASP models can differ in the detail in which (geo-)chemical reactions and the phase
behavior are addressed. Inclusion of more details into the numerical model could result in better
understanding and more accurate prediction, but it comes at a price, viz. it requires more measured input
data and increases computational time. Thus, depending on the accuracy requirements, available
experimental data and time the modeling of ASP flood can be performed using different simulation
approaches.
This paper describes several modeling approaches for ASP. We start with a brief description of these
methods and their input requirements. Then we compare the ASP core flood simulation results
demonstrating the advantages and disadvantages of presented approaches. Finally we give
recommendations and guidelines on how and when the proposed models could be used.
Abstract: Efficient storage of carbon dioxide (CO2) in aquifers requires dissolution in the aqueous phase. Firstly, the volume available for gaseous CO2 is far less than for the CO2 to be dissolved in the water initially present in the aquifer. Secondly, the partial molar volume of CO2 in the gas phase is about twice as large as the partial molar volume of CO2 in water, meaning that storage in the water phase leads to less pressure increase per amount of sequestered CO2. Transfer of CO2 from the gas phase to the aqueous phase would be slow if it were only driven by diffusion. However, dissolution of CO2 in water forms a mixture that is denser than the original water or brine. This causes a local density increase, which induces natural convection currents accelerating the rate of CO2 dissolution.
This study presents a set of high pressure visual experiments, based on the Schlieren technique, in which we observe the effect of gravity-induced fingers when sub- and super-critical CO2 at in situ pressures and temperatures is brought above a liquid, e.g., water, brine or oil. A short but comprehensive description of the Schlieren set-up and the transparent pressure cell is presented. The initial experiments are confined to bulk-phase situations, i.e., in the absence of a porous medium. The experiment is able to demonstrate the initiation and development of the gravity induced fingers. The concentration gradient is high near the gas-liquid interface. The experiments show that natural convection currents are weakest in highly concentrated brine and strongest in oil. The set-up can screen aqueous salt solutions or oil for their relative importance of natural convection flows.
Abstract: The efficiency of the mixing in the density-driven natural-convection phenomenon is largely governed by the aquifer permeability, which is heterogeneous in practice. The character (fingering, stable mixing or channeling) of flow-driven mixing processes depends primarily on the permeability heterogeneity character of the aquifer, i.e., on its degree of permeability, variance (Dykstra-Parsons coefficient) and the correlation length. Here we follow the ideas of Waggoner et al. (1992) to identify different flow regimes of a density-driven natural convection flow by numerical simulation. Heterogeneous fields are generated with the spectral method of Bruining et al. (1997), because the method allows the use of power-law variograms. We observe from our simulations that the rate of mass transfer of CO2 into water is higher for the heterogeneous media.
Abstract: This paper introduces a novel enhanced-oil-recovery concept for naturally-fractured reservoirs. We use foam to create a viscous pressure drop along the fracture that is directly transferred to the oil-bearing matrix and accelerates the oil production. We developed an expression that predicts the maximum oil rate depending on the injected gas rate and properties of the foam generated in the fracture. The results of the numerical simulation are in good agreement with the developed model.
Abstract: Volumetric shrinkage due to methane desorption from the coal matrix has significant influence on the stress regime and fracture permeability in coal. Permeability changes (due to primamry depletion) up to two orders of magnitude have been reported from the Fairway region in the San Juan Basin. Several analytical models have been developed to predict changes in fracture permeability in coal as a function of stress and sorption induced coal swelling/shrinkage. Coal can be considered as a highly crosslinked macromolecular network structure, where aromatic clusters of graphite like complexes are connected by aliphatic chains. All sorption processes in coal are characterized by relaxational mechanisms of such crosslinked complexes. Any relaxational mechanism is indicative of swelling related stresses in coal. Variations in the effective horizontal stresses under uniaxial strain conditions are effected as a function of the reservoir pressure reduction during primary drawdown, which includes a cleat compression term and a matrix shrinkage/swelling term that have opposite effects on fracture
permeability.
The matrix shrinkage/swelling term have been revisited a theory proposed to explain the coupling of swelling stress to porosity change in coal as a function of the change in diffusion coefficient, the Langmuir constants, cleat compressibility and material properties.
Abstract: The ability of foam to control the gas mobility in porous media is determined in part by the trapped (stationary) fraction of foam, Xt. The common approach to determining Xt is to replace some part of the gas by a “tracer gas†during the steady-state stage of the experiments and fitting the effluent data to a capacitance mass-transfer model. Diffusion between bubbles is quantified by the film permeability coefficient, K (cm/s). We measured the film permeability coefficient of different gases for foam films made of four surfactants. The results show that the value of K is largely dependent on the dissolution of gas in the surfactant solution and increases with increasing gas solubility in the bulk liquid. The measured values of K are consistent with rapid diffusion of tracer through trapped gas adjacent to flowing gas in porous media, and difficulties in interpreting the results of tracer-foam experiments with conventional capacitance models. Effective diffusion coefficients of gases through trapped foam can be estimated from K. These diffusion coefficients differ substantially, and this implies swelling or shrinkage of trapped gas from diffusion. The implications of the results for foam flow in porous media is discussed in detail and some suggestions are given to improve the measurements and modeling of trapped fraction of foam.
Abstract: Foam is widely used to divert acid or abandon the high permeable layers. In this type of application foam should considerably reduce gas mobility. The nature of the gas and the surfactant may influence foaming behavior and thus the efficiency of the foam. In this paper an experimental study of the behaviorof CO2 and N2 foams in granular porous media using X-ray Computed Tomography is reported. In the experiments gas is forced through natural porous media initially saturated with a surfactant solution, a process known as SurfactantAlternatingGas (SAG). The CO2 was either under sub- or super-critical conditions whereas N2 remained under subcritical conditions in all experiments. Alpha Olefin Sulfonate (AOS) surfactant was used as foaming agent. We found that injection of gas following a slug of surfactant can considerably reduce gas mobility and promote higher liquid recovery at the experimental conditions investigated. Foaming of CO2 builds-up a lower pressure drop over the core at both low and high pressures than N2. Both gases require a certain penetration depth to develop into foam. This length is longer for N2 (larger entrance effect) and increases with growing gas velocity. Moreover, the ultimate liquid recovery by CO2 foam is always lower than by N2 foam. The possible mechanisms explaining the observed differences in foaming behavior of the two gases are discussed in detail.
Abstract: We report an experimental study of CO2 and N2 foam flows in natural sandstone cores containing oil with the aid of X-ray Computed Tomography. The study is relevant for Enhanced Oil Recovery (EOR). The cores were partially saturated with oil and brine (half top) and brine only (half bottom) to mimic the water-oil transition occurring in oil reservoirs. The CO2 was used either under sub- or under super-critical (immiscible and miscible) conditions, whereas N2 remained subcritical. Prior to gas injection the cores were flooded with several pore volumes of water. In each experiment water flooding was followed by the injection of 1-2 pore volumes of a surfactant solution with Alpha Olefin Sulfonate (AOS) as the foaming agent. We visually show how foam propagates in a porous medium containing oil.
At low-pressure experiments (P=1 bar) in the case of N2, weak foam could be formed in the oil-saturated part. Diffused oil bank is formed ahead of the foam front, which results in additional oil recovery, compared to pure gas injection. CO2 hardly foams in the oil-bearing part of the core, most likely due to its higher solubility. Above critical point (P=90 bar), CO2 injection following the slug of surfactant reduces its mobility in absence oil. Nevertheless, when the foam front meets the oil it becomes highly diffuse. The presence of the surfactant (when foaming super-critical CO2) hardly improves oil recovery and or modifies the pressure drop profile, indicating the detrimental effect of oil on foam stability in the medium in this specific case. However, at miscible conditions, injection of surfactant prior to CO2 injection significantly increases the oil recovery.
Abstract: Foam is widely used in oil and gas recovery operations as a mobility control and profile correction agent. A brief list of foam applications includes acid diversion during matrix stimulation, gas blocking and enhanced oil recovery. This paper aims to study the dynamics of foam flooding assisted liquid displacement in a porous media. We report core-flood experiments performed using Bentheimer sandstone and N2 foam with the aid of X-ray computed tomography. A detailed description of CT images and quantification of local fluid saturation revealed that foam is formed in-situ and giving a mobility control. Furthermore, oil can be produced by a liquid slug induced by this strong immiscible foam front
Abstract: Typically, conventional reservoir simulators underestimate the recovery factor of heavy oil reservoirs under solution gas drive. We hypothesize that natural surfactants in oil (e.g. asphaltenes) cause this phenomenon in two ways: 1) by hindering the mass transfer rate of gas molecules through the gas-oil interface and 2) by enhancing the solubility of gas in the heavy oil. We investigate effect of surfactants on mass transfer rate of gas through gas-water interface and on the solubility of gas in oil. In bulk experiments, we observe that the addition of sodium dodecyl sulfate (SDS) does not influence the gas transfer rate while in the presence of a porous medium the growth of gas bubbles becomes increasingly difficult with increasing SDS concentration, which indicates that the interaction of the grain with fluids is an essential element in bubble growth in porous media. The effect a non-ionic surfactant on the solubility of methane in n-dodecane is also examined. The bubble point pressures of the gas+oil+surfactant system are determined experimentally.It is found that the bubble point pressures of the system decrease with increasing surfactant concentration, i.e., the surfactant enhances the solubility of methane in the oil.
Abstract: Global warming has increased interest in quantification of the dissolution of CO2 in (sub)-surface water. CO2 is present above the surface water. Dissolution of CO2 into water (or oil) causes a density increase, with respect to pure water (or oil). This density effect causes natural convection, which enhances the mass transfer rate across the interface. This article describes a series of experiments performed in a cylindrical PVT-cell at a pressure range of pi=10-50 bar, where a fixed volume of CO2 gas was brought into contact with a column of distilled water. The results show that the mass transfer rate across the interface is much faster than predicted by Fickian diffusion. This mass transfer rate increases with increasing initial gas pressure and in the long term it is controlled by diffusion.
A theoretical interpretation of the observed effects has been proposed, based on diffusion and natural convection phenomena. The CO2 concentration at the interface is estimated from the gas pressure using Henry’s solubility law, in which the coefficient varies with both pressure and temperature. Good agreement between the experiments and the theoretical results has been obtained.
Abstract: The interactions between foam films play an important role in interpreting the experimental data and developing general theories of foam rheology and motion. Foam films are suitable tools for studying the interactions between interfaces. The measurement of the gas permeability of the foam films gives valuable information about the stability and lifetime of the foams. Part of this information can be obtained from gas permeability experiments with foam or single foam films. Even more, as it was shown the interaction between the adsorbed monolayers forming the foam film changes the film structure and its gas permeability accordingly. Alpha Olefin Sulfonate (AOS) surfactants have shown outstanding detergency, lower adsorption onto porous media, high compatibility with hard water,good wetting and foaming properties. These make AOS an excellent candidate for foam applications in enhanced oil recovery. We measured the basic properties (thickness, contact angle, adsorption density) of foam films stabilized by an Alpha Olefin Sulfonate (AOS) surfactant. Furthermore, the gas permeability coefficient, k, of films was measured as a function of surfactant and salt concentration. It was observed that the thinner Newton Black Films (NBFs) are less permeable to gases than thicker Common Black Films (CBFs). This result was interpreted using adsorption densities calculated from measured surface tension data. It was concluded that the gas permeability of foam films is independent of the number of surfactant molecules adsorbed on the film surface. The interaction between foam films are most likely the reason for the unexpected permeability behavior of foam films stabilized with AOS.
Abstract: Foam is an attractive option in EOR for increasing oil recovery in mature water-flooded reservoirs. In this paper we use stochastic bubble population model and complex power law rheological model, to integrate foam physics into a flow simulator. Foam displacement is examined in layered reservoirs with and without isolating shale barrier between the layers and in stochastically distributed permeability fields. It is demonstrated that in isolated layers foam propagates faster in the high permeability layer and sweeps the low permeability layer only modestly. In communicating layers, sweep efficiency is improved significantly due to cross flow. In stochastic random permeability field, foam injection increases the liquid recovery by a factor of two in comparison to gas injection
Abstract: In this paper we investigate the mass transfer of CO2 injected into a layered and anisotropic (sub)-surface porous formation saturated with water. Solutions of carbon dioxide in water and oil are denser than pure water or oil. We perform our analysis to a rectangular part of the porous medium that is impermeable at the sides except at the top, which is exposed to CO2. For this configuration density-driven natural convection enhances the mass transfer rate of CO2 into the initially stagnant liquid. The analysis is done numerically using mass and momentum conservation laws and diffusion of CO2 into the liquid. This configuration leads to an unstable flow process. Numerical computations do not show natural convection effects for homogeneous initial conditions. Therefore a sinusoidal perturbation is added for the initial top boundary condition. It is found that the development of fingers is fastest for mass transfer enhancement by natural convection is largest for large anisotropy ratio’s and smaller for small ratio's. It is found that the mass transfer increases and concentration front moves faster with increasing Rayleigh number if the high permeability layer is on top. Of particular interest is the case when the Rayleigh number for the high permeable layer is above the critical Rayleigh number (Racr = 40) and smaller than Racr for the low permeable layer. The results of this paper have implications in enhanced oil recovery and CO2 sequestration in aquifers.
Abstract: The problem of formation damage, i.e., permeability reduction due to injection of particulates, is a matter of interest in several engineering fields. In the previous attempts to model the external cake formation, cake thickness has been considered to be only dependent on time; even though, in practical applications the dependency of the cake profile on space can be important. In this paper a novel model has been developed to describe the steady state external filter cake thickness profile along the well-bore. A set of equations are derived from the force balance for a deposited particle on the cake surface and the volume conservation of the fluid in the well-bore. These equations are combined with the Darcy's law in radial geometry and the equation of flow in the well-bore, and solved numerically to obtain the cake thickness and fluid velocity profiles along the well-bore.
Abstract: Global warming has increased interest in quantification of the dissolution of CO2 in (sub)-surface water. CO2 is present above the surface water. Dissolution of CO2 into water (or oil) causes a density increase, with respect to pure water (or oil). This density effect causes natural convection, which enhances the mass transfer rate across the interface. This article describes a series of experiments performed in a cylindrical PVT-cell, where a fixed volume of CO2 gas was brought into contact with a column of distilled water. The results show that the mass transfer rate across the interface is much faster than predicted by Fick’s law. This mass transfer rate increases with increasing initial gas pressure. However, in the long term the mass transfer rate is controlled by diffusion alone. The long term behavior, therefore, allows the determination of the diffusion coefficient. Its value agrees with values presented in the literature. A similar mass transfer behavior was observed for the experiments with an oil phase (n-C10 and n-C16). Therefore analogous experiments using oil instead of water are valuable for enhanced oil recovery projects.
A theoretical interpretation of the observed effects has been proposed, based on diffusion and natural convection phenomena. The Rayleigh number is of the order of one million whereas the Schmidt number is of the order of five hundred. The ensuing equations have been solved numerically, using the finite volume approach. There is qualitative agreement between the experiment and the numerical results and similar to the experiments the mass transfer becomes diffusion like in the long term.
Abstract: In this paper we present a 1D and 2D analysis of foam development in porous media based upon a new stochastic bubble population foam model and provide a detailed experimental validation. We present systematic experiments consisting of the co-injection of N2 gas and surfactant solution in homogenous sandstone cores, varying the liquid and gas injection rates. During the experiments X-ray computed tomography (CT) scans were used to map locally the fluid saturations with high spatial and temporal resolution.
Abstract: In this paper we investigate the mass transfer of CO2 injected into a homogenous (sub)-surface porous formation saturated with a liquid. In almost all cases of practical interest CO2 is present on top of the liquid. Therefore, we perform our analysis to a porous medium that is impermeable from sides and that is exposed to CO2 at the top. For this configuration density-driven natural convection enhances the mass transfer rate of CO2 into the initially stagnant liquid. The analysis is done numerically using mass and momentum conservation laws and diffusion of CO2 into the liquid. The effects of aspect ratio and the Rayleigh number, which is dependent on the characteristics of the porous medium and fluid properties, are studied. This configuration leads to an unstable flow process. Numerical computations do not show natural convection effects for homogeneous initial conditions. Therefore a sinusoidal perturbation is added for the initial top boundary condition. It is found that the mass transfer increases and concentration front moves faster with increasing Rayleigh number. The results of this paper have implications in enhanced oil recovery and CO2 sequestration in aquifers.
Abstract: We present a new 2D analysis based on the recently developed stochastic bubble population foam model, focusing on the effect of the core heterogeneity. In the frame of the model presented in a parent paper in the conference, we assume that the bubble generation kinetics is dependent on layer permeability. We present experiments consisting of co-injection of N2 gas and surfactant solution in layered cores, with layering parallel and to the flow directions. The cores are obtained by combining two porous media chosen from Benteimer and Berea sandstone and sintered glass, with large permeability contrast. X-ray computed tomography (CT) scans are used to visualize and quantify local fluid distributions and differentiate foam propagation in the different layers. From both the model and the experiments we conclude that foam is primarily generated in the high-permeability layers, where it propagates at a much higher speed than in the low permeability layer. The propagation of foam in the low permeability layer requires that the pressure gradient is higher than the capillary entry pressure for the layer. The new stochastic population balance foam model reproduces rather well the main features of foam motion in heterogeneous cores containing a surfactant. Core floods combined with CT scan imaging provide valuable specific information about the effect of heterogeneity for better design of acid diversion operations.
Abstract: Foams are involved in many industrial processes, including foods and beverages, fire fighting, subsoil environmental remediation and enhanced oil recovery. In these applications, foam stability and dynamics depend on the permeability of the thin liquid films to gases. An important parameter in the description of the foam permeability is the thickness of the thin liquid films. The foam film permeability is can be measured using (laser) light interferometry. In this paper, we survey the principles of this technique and compute the expressions for the thickness for a free standing foam film. The foam film is consists of five layers: a core aqueous layer with two surfactant monolayers, each consisting of consisting of hydrocarbon tails and polar head-groups sub-layers. from its reflection intensity coefficient Ir for perpendicularly incident light.
Abstract: A new experimental methodology using X-ray Computed To-mography for studying the filtration phenomenon that occurs during the injection of water with solid particles into porous media is presented. Previously unattainable deposition profiles are used to test for conformance the widely accepted classical deep-bed filtration model, proposed by Iwasaki in 1937. An equivalent system of linear ODEs is obtained using the method of characteristics and is used in the presented analysis. Results indicate that deposition profile measurements are more valuable than typically measured effluent concentration pro-files. Furthermore, it is concluded from the presented analysis that the classical model is a valid approximation to the filtra-tion phenomenon. However, clear discrepancies between model predictions and experimental results are observed. These discrepancies could be attributed to either the kinetics equation of the classical model or the extrapolation needed to compensate for data lost due to noise. Finally, a set of recom-mendations for improved experiments is suggested.
Abstract: In this article a system of equation to describe the steady state external filter cake thickness profile along the cuboid crossflow filtration setup geometry as well as the well bore geometry are introduced. The first equation is obtained from the analysis of forces acting on a deposited particle at the outermost limit of the external cake. The second equation is obtained from the volume conversation of the transporting fluid in the given geometry. Coupling the two equations yields an implicit solution of the cake profile. Boundary conditions are required as well as the quantification of an empirical factor that can be quantified experimentally.
Experiments conducted were analysed and the empirical friction coefficient was quantified and presented. Simulations based on the developed solution are also presented.
Abstract: The production wells of an oil field do not produce oil exclusively, but also other fluids such as
gas and water depending on the nature of the underlying reservoir. As the oil field matures,
the water cut (the ratio of produced water to total extracted liquids) increases presenting the
operators of the field with one or both of the following problems:
1- disposal of the produced water
2- maintenance of the reservoir pressure, which is depleted by the production of
reservoir fluids.
Abstract: The results of this thesis give insight into the (mass)-transfer during flow of gases, especially CO2, in various gas-liquid systems. A number of experiments was performed to investigate the transport phenomena through interfaces with and without surfactant monolayers. The observed phenomena have been incorporated into physical models to predict the fate of CO2 overlaying a bulk liquid or liquid saturated porous media. Moreover, dynamics of (CO2)-foam flow in oil-free and oil-saturated porous media was studied using X-ray tomography.
Abstract: Most oil and gas reservoirs have a natural water layer called formation water beneath the
hydrocarbon layer. Also to achieve maximum oil recovery, additional water is usually
injected into the reservoir, which may be associated with hydrocarbons in the production. In
the case of some gas production, produced water can be condensed water. Thus, the liquid
that comes out of reservoir is not just hydrocarbons, but is frequently accompanied by water.
The liquid production is in the form of a mixture of free water, an oil/water emulsion and oil.
Furthermore, as an oil field matures the amount of produced water increases. This is because,
after some time, the formation waters out due to the water injection process. The water-oil
ratio varies from reservoir to reservoir. It also varies with time for a particular reservoir.
Worldwide 75% of the production is water, but in some places this percentage may increase
to 98%. Table 1-1 shows the amount of produced water and oil in North Sea.
