Oil In Porous Media Research Articles

Analytical Solutions for 1D Countercurrent Imbibition in Water-Wet Media

Summary Analytical solutions for the initial stage of 1D countercurrent flow of water and oil in porous media are presented. Expressions are obtained for the time dependence of the water saturation profile and the oil recovered during spontaneous countercurrent imbibition in rod-like, cylindrical, and spherical cores, for which water is the wetting liquid. Some of the analytical solutions are found to be in good agreement with existing numerical solutions and available experimental data for oil recovery from cores with strong water wettability.

Modeling foamy oil flow in porous media II: Nonlinear relaxation time model of nucleation

In a previous communication, hereafter called Part I, we presented a model of the flow of foamy oil in porous media in situations in which the bubbles do not coalesce to produce the percolation of free gas so that the gas moves with the oil as it evolves. A central role in that theory is an equation of state, called the solubility isotherm, which describes an equilibrium between the fraction of dispersed gas ϵ and the pressure below the bubble point pressure. A rate equation governing the return to equilibrium was postulated and it requires a value for the relaxation constant multiplying ϵ. The theory developed in Part I was applied to experimental data and good agreements were achieved except for sharp transients at early times such as those that occur for sudden drops of pressure at the open end of the closed sand pack. In the present theory we introduce two rates and two relaxation times to describe the dynamics of relaxation of the system to an equilibrium state; one rate for ϵ and the other for the pressure p as was suggested already in Part I. However, we found that constant relaxation times could not be found to fit all the available data. We interpret this in terms of bubbles nucleating more slowly at initial drawdowns, and more rapidly as gas and vapor is released when the pressure is held below the bubble point. This feature has been more or less successfully addressed by the introduction of two relaxation functions of the gas fraction ϵ which allows us to describe the low rates of evolution of ϵ when ϵ is zero or close to it. The relaxation functions were fit to one rate of depletion in a depletion experiment in which oil is pulled out of a closed sand pack at a constant rate. With this selection of the relaxation function established, the set of governing PDEs is fixed and may be used to predict the results of other experiments. The prediction of the pressure profiles for other greatly different rates of depletion is satisfactory. Moreover, the experimental results processed in Part I, are improved by the new theory with the same fitting.

Transport of organic components from immobile and bypassed oil in porous media

AbstractAn experimental study, as well as theoretical and numerical models, are used to validate a methodology to exploit conventional geochemical data with regard to the concentration profiles of organic components occurring naturally in hydrocarbon reservoir oils. The experiment was designed to study transport of organic compounds from bypassed oil during water injection using a homogeneous oil‐filled core sample, which was made heterogeneous by drilling a hole through its central axis and filling it with a highly permeable material. Under the present conditions, diffusion coefficients are the most important parameters controlling the transport, and the effect of partitioning could be accounted for by a simple normalization. The experimental results are well described by a simple 2‐D analytical model that assumes instantaneous removal of solutes from the oil–water interface. The experimental results are also well described by two numerical models, of which one is a full‐featured reservoir scale model, suitable for applications of the methodology to reservoir‐scale cases.

Impacts of Initial Gas-to-Oil Ratio (GOR) on SAGD Operations

Abstract This study addresses the important role of initial gas-to-oil ratio (GOR) in steam assisted gravity drainage (SAGD) operations. A numerical model using CMG's STARS was validated through history matching of laboratory experiments conducted at the Alberta Research Council. The impacts of initial GOR on process performance were then studied using field scale numerical simulations. The results indicate that high initial GOR may have beneficial effects, namely, reduction of oil viscosity, and improvement of the oil-to-steam ratio (OSR). A detrimental impact, however, is also shown as the gas impedes the rate of steam chamber growth, and hence reduces oil production rates. Further analysis indicated that this is because of a "dynamic vacuum" effect due to steam condensation at the front of the steam chamber. This dynamic vacuum effect dominates the diffusion process and creates a gas-rich zone at the front of the steam chamber, thereby resisting further growth of the steam chamber and slowing oil production. The same effect occurred when noncondensable gas was co-injected with steam in either live oil or dead oil reservoirs. This study addresses the important role of initial gas-to-oil ratio (GOR) in steam assisted gravity drainage (SAGD) operations. A numerical model using CMG's STARS was validated through history matching of laboratory experiments conducted at the Alberta Research Council. The impacts of initial GOR on process performance were then studied using field scale numerical simulations. The results indicate that high initial GOR may have beneficial effects, namely, reduction of oil viscosity, and improvement of the oil-to-steam ratio (OSR). A detrimental impact, however, is also shown as the gas impedes the rate of steam chamber growth, and hence reduces oil production rates. Further analysis indicated that this is because of a "dynamic vacuum" effect due to steam condensation at the front of the steam chamber. This dynamic vacuum effect dominates the diffusion process and creates a gas-rich zone at the front of the steam chamber, thereby resisting further growth of the steam chamber and slowing oil production. The same effect occurred when noncondensable gas was co-injected with steam in either live oil or dead oil reservoirs. Introduction It is generally assumed that when the steam assisted gravity drainage (SAGD) process is applied to a heavy oil reservoir with a high initial gas-to-oil ratio (GOR), there is better production than for a reservoir with a low initial GOR. This is a fairly common assumption for good reasons; the mobility of live oil in porous media is usually higher(1) than that of dead oil. The present numerical study was initiated to investigate this assumption. The approach involves the history match of 1D laboratory tests and field scale simulations. The history match was used to verify the numerical techniques and to provide reliable parameters for the use of field scale simulations. The results support the commonly believed assumption of viscosity reduction in 1D live/dead oil experiments. In field scale simulations, production predictions were compared for reservoirs with different initial GORs. There were additional effects beyond viscosity reduction.

A SIMPLIFIED OXIDATION MODEL FOR TWO-PHASE FLOW IN POROUS MEDIA

This paper describes a simplified mathematical model for thermal recovery by oxidation for flow of oxygen and oil in porous media. Some neglected important physical effects include gravity, compressibility and heat loss to the rock formation, but heat longitudinal conduction and capillary pressure difference between the phases are considered. The mathematical model is obtained from the mass balance equations for air and oil, energy balance and Darcy's law applied to each phase. Based on this model some typical features in low temperature oxidation concerning the wave structure are captured. Numerical simulations showing saturations and temperature profiles are reported.

A SIMPLIFIED OXIDATION MODEL FOR TWO-PHASE FLOW IN POROUS MEDIA

This paper describes a simplified mathematical model for thermal recovery by oxidation for flow of oxygen and oil in porous media. Some neglected important physical effects include gravity, compressibility and heat loss to the rock formation, but heat longitudinal conduction and capillary pressure difference between the phases are considered. The mathematical model is obtained from the mass balance equations for air and oil, energy balance and Darcy's law applied to each phase. Based on this model some typical features in low temperature oxidation concerning the wave structure are captured. Numerical simulations showing saturations and temperature profiles are reported.

A New Method for Group Analysis of Petroleum Fractions in Unconsolidated Porous Media

Abstract A fast and accurate method for the group analysis of crude oils in porous media that describes petroleum components (especially heavy fractions) has been developed. NMR structure group analysis is used as the tool for the characterization of crude oils. This method is proposed as an alternative to existing complicated and laborious methods of characterization of extracted oil samples. Currently, group analysis of heavy fractions of crude oils is being investigated by means of chromatographic methods, such as the SARA (saturates-aromatics-resinsasphaltenes) test. These methods are usually expensive, and require considerable work from qualified personnel. Furthermore, these methods cannot be used for estimating the oil components in situ. The basis of determining crude oil components using NMR is the difference of the nuclei mobility in the different hydrocarbons during the NMR testing period. A combination of solvent extraction, NMR testing and data processing gives a series of NMR terms that are then used to specify hydrocarbon mixtures and their components both in the bulk phase and in unconsolidated porous media. Introduction NMR logging tools are currently used for determining reservoir properties such as porosity(1, 2), permeability(1-4), as well as mobile and immobile fluids(5-7). Recent developments in NMR research offer tools for separating water, oil, and gas from the combined NMR signal(7, 8). Very little is known about the use of NMR logging tools for the in situ characterization of crude oils(1). With respect to heavy oil and bitumen formations, NMR logging has not been very successful in characterizing crude oil. The reason for the lack of such success is the fact that the NMR logging tools cannot detect the spectra from most heavy oil and bitumen formations. It should be noted that high field NMR technology has solved such problems in the past, but such technology cannot be used downhole. A fundamental objective of the research performed in our laboratory is to extend the use of NMR logging tools to all heavy oil and bitumen formations. To this end, the NMR characteristics of heavy oils in porous media were investigated(9, 10). The objective of our work is to isolate the oil signal from the combined NMR spectrum of the formation, and then shift it towards the relaxation time range that can be detected by the conventional NMR logging tools. Once this goal is achieved, NMR logs of heavy oil and bitumen formations can become successful in the analysis of oil downhole. This objective was accomplished in the material presented in this paper through a series of experiments that addressed the following issues:Relaxation interactions in mixtures of simple organic liquids with water.Relaxation interactions in mixtures of simple organic liquids. Relaxation interactions in mixtures of simple organic liquids with solvents.Relaxation times of conventional crude oils with and without solvents present.Relaxation times of heavy crude oils and bitumen with and without solvents present.Relaxation times of heavy crude oils and bitumen with and without solvents in unconsolidated sands and with variable connate water saturation.

New ways of probing surface nuclear relaxation and microdynamics of water and oil in porous media

The microdynamics of water and oil in macroporous media with SiO 2 or CaCO 3 surfaces has been probed at various temperatures by magnetic field-cycling measurements of spin-lattice relaxation rates. These measurements and an original theory of surface diffusion allow us to obtain surface dynamical parameters such as surface correlation times, residence times and diffusion coefficients. A coefficient of affinity of the liquids for the pore surface is deduced.

Surface and Volume Diffusion of Water and Oil in Porous Media by Field Cycling Nuclear Relaxation and Pgse NMR

AbstractThe microdynamics of water and oil in macroporous media with SiO2 or CaCO3 surfaces has been probed at various temperatures by magnetic field-cycling measurements of the spin-lattice relaxation rates. These measurements and an original theory of surface diffusion allowed us to obtain surface dynamical parameters, such as a coefficient of surface affinity of the liquid molecules and the surface diffusion coefficient. The water surface diffusion coefficients are compared to the volume self-diffusion coefficients of water in pores, measured by PGSE method, the latter values being more than an order of magnitude higher than the surface ones. Complementary information on the nature of the solid-liquid interface was given by NMR chemical shift experiments at high magnetic field.

Visualization and Measurement of Gas Evolution and Flow of Heavy and Light Oil in Porous Media

Summary In a number of experiments, the efficiency of solution-gas drive for both light and heavy oils was studied. In these experiments a special coreholder was used to visually observe the formation of gas bubbles on the rock surface of a Berea core and the production from the core outlet. The results from all the experiments reveal that the critical gas saturation for three hydrocarbon liquids; 1. a light model oil, 2. an 11-API gravity oil, and 3. a 35-API gravity oil, does not exceed 3%. However, the gas mobility for the heavy oil is very low and for the light model oil very high. Consequently, solution-gas drive for a heavy oil of 11-API gravity is more efficient than for a light oil.

Mechanisms of Wetting Alteration by Crude Oils

SummaryPolar crude oil components can adsorb on mineral surfaces and alter their wetting properties. Extrapolating from laboratory observations of wetting alteration to reservoir conditions is difficult because of the chemical complexity of the crude oils, the variability of mineral surfaces, and the presence of brine. It is essential to recognize that the polar components of crude oils can adsorb by several distinct mechanisms, depending on factors that include brine composition and the solvent quality of the oil for its asphaltenes. In this article, several important mechanisms are identified. These have been demonstrated by experimental observations of contact angles between pure fluids on flat surfaces after exposure to crude oil. The consequences of these mechanisms for wetting alteration by different crude oils in porous media are examined.

The effect of wettability on foam sensitivity to crude oil in porous media

We evaluated foam-oil sensitivity in oleophilic (oil- or intermediate-wetting) media compared with hydrophilic (water-wetting) media. The porous media used were either Berea sandstone or glass microvisual cells with and without Quilon C coating (hydrophilic or oleophilic). Dynamic contact angle measurements on untreated and Quilon C-treated glass showed that the treatment makes the glass microvisual cells intermediately wet. Microvisual studies showed that foams tend to be more sensitive (less effective) to oil at residual oil saturation when the pores are intermediately wet as opposed to water-wet. These studies show that, at least for glass plates, the surfactants can adsorb and partially reverse the wettability, back towards water-wet. Coreflood tests using treated and untreated Berea sandstone rock show that the Quilon C treatment also changed the wettability of the rock away from water-wetting. In most cases the foam effectiveness was reduced in oleophilic rock over hydrophilic rock (oil-free). At residual oil saturation foam effectiveness for most foams was further reduced in oleophilic-treated rock over hydrophilic rock. This work confirms earlier suggestions that foam effectiveness may be reduced in porous media of intermediate or oleophilic wettability and that the foam effectiveness may be further reduced at residual oil saturation. Surfactant selection for field use should be made taking into account the actual reservoir conditions under which they will be used, including nature of the oil, S or and wettability. The results of this research should provide some guidance for this purpose.

Kinetic analysis of in situ combustion processes with thermogravimetric and differential thermogravimetric analysis and reaction tube experiments

This research comprises the determination of kinetic parameters of in situ combustion processes by reaction tube and thermal (thermogravimetric analysis (TGA)/differential thermogravimetric analysis (DTGA)) experiments. A previously developed laboratory model and a Du Pont 9900 thermalanalyzer unit were used to run the experiments. Three reaction regions for combustion of crude oil in porous media were observed in the reaction tube and TGA/DTGA experiments and are defined as low temperature oxidation, fuel deposition and high temperature oxidation. The kinetic parameters are calculated for each reaction region using Weijdema's reaction model in reaction tube experiments. The Arrhenius model is applied to determine the kinetic parameters from TGA/DTGA thermograms and a comparison is made between kinetic results.

Influence of reservoir rock composition on crude oil pyrolysis and combustion

The principal objective of this study was to investigate the influence of reservoir rock composition on the pyrolysis and combustion behavior of crude oils in porous media in relation to in situ combustion (ISC) as a thermal oil recovery process. Using sand pack of varying mineralogical composition and different crude oils, pyrolysis and combustion tests were performed to examine how the clays affect the amount of fuel and its reactivity during the ISC process. From the experimental results, it appears that clay minerals present in the matrix enhance fuel deposition during the pyrolysis process and also catalyze the oxidation of fuel.

Generalized entering coefficients: a criterion for foam stability against oil in porous media

The unique mobility-control properties of foam in porous media make it an attractive choice as an injection fluid for enhanced oil recovery. Unfortunately, in many cases oil has a major destabilizing effect on foam. Therefore, it is important to understand how oil destabilizes foam and what surfactant properties lead to increased stability against oil. To explain the stability of foam in porous media in the presence of oil, we generalize the ideas of spreading and entering behavior using Frumkin-Deryaguin wetting theory. This formulation overcomes the inherent deficiencies in the classical spreading and entering coefficients used to explain foam stability against oil. We find that oil-tolerant foam can be produced by making the oil surface ``water wet``. To test our theoretical ideas, we measure foam-flow resistance through 45--70 {mu}m glass beadpacks, surface and interfacial tensions, and disjoining pressure isotherms for foam and pseudoemulsion films for a variety of surfactant/oil systems. Most notably, we measure pseudoemulsion-film disjoining pressure isotherms for the first time and directly establish that pseudoemulsion film stability controls the stability of the foam in the systems we tested. Moreover, we demonstrate the correspondence between stable pseudoemulsion films, negative entering behavior, and oil-tolerant foams.

A Pore-Level Investigation of Foam/Oil Interactions in Porous Media

SummaryDirect visual studies of foam flow in etched-glass micromodels containing residual oil demonstrate that foam decays as a result of breakage of pseudoemulsion films. Foam films collapse whenever nearby thin aqueous films separating gas bubbles and oil rupture. Consequently, surfactant formulation for foam insensitivity to oil in porous media should be based on stabilizing pseudo-emulsion films.

Reaction Kinetics of Fuel Formation for In-Situ Combustion

Summary Chemical reactions believed to cause fuel formation for in-situ combustion have been studied and modeled. A thin, packed bed of sand/oil mixture is heated under nitrogen flow at linearly increasing temperatures, simulating the approach of a combustion front. Analysis of gases produced from the reaction cell revealed that pyrolysis of crude oil in porous media goes through three overlapping stages: distillation, mild cracking (visbreaking), and severe cracking (coking). Expressions that govern the rates of the two cracking reactions are derived, and a technique is outlined to obtain initial estimates for their parameters from the experimental data. The parameters of a proposed distillation function, as well as refined estimates for the cracking reaction parameters, are obtained by non-linear regression methods based on an overall kinetic model. Successful matching of the experimental data, including the total amount of fuel deposited, was achieved with this model. It was found that fuel formation was a result of two successive cracking reactions that the oil undergoes at temperatures above 280° C [536°F]. Also, distillation of crude oil at temperatures below 280°C [536°F] played an important role in shaping the nature and extent of the cracking reactions. The operating pressure and the rate of heating of the sand/oil sample were found to affect the fuel-formation process only through the influence exerted on distillation. Clay minerals showed a catalytic effect on the cracking reactions, especially coking. Finally, the asphaltene fraction of a crude oil was found to correlate with the fuel content of that oil.

Reaction Kinetics of In-Situ Combustion: Part 1—Observations

Abstract Continuous analysis of produced gases from a small packed bed reactor, at both isothermal and linearly increasing temperatures, has shown that combustion of crude oil in porous media follows several consecutive reactions. Molar carbon dioxide/carbon monoxide (CO2/CO) and apparent hydrogen/carbon (H/C) ratios were used to observe the transition between these reactions at different temperature levels. A new kinetic model for oxidation of crude oil in porous media is presented in Part 2 of this paper (Page 408).

The Rules for Achieving High Solubilization of Brine and Oil by Amphiphilic Molecules

Abstract The oil-recovery effectiveness of a chemical flood has been proved related to the phase behavior of the brine/oil/surfactant system. In particular, it is advantageous to formulate the system so that optimal three-phase behavior is obtained. However, it also has been demonstrated that all the optimized systems are not equivalent in terms of solubilization, interfacial tensions (IFT's), and oil-recovery efficiency. This paper addresses the conditions that promote high solubilization in microemulsions, a property correlated to the values of the IFT and therefore correlated to the ability of such systems to displace the oil in porous media. When one formulation parameter is changed, another parameter must be varied at the same time for compensation to reoptimize the system. The mechanism of solubilization is investigated experimentally by considering the usual formulation parameters: salinity, oil type, alcohol type and concentration, and surfactant structure and type (anionics and nonionics). The results are interpreted in terms of interaction energies between surfactant, oil, and water. In particular, the role of the alcohol and its impact on the solubilization by amphiphilic systems are discussed in detail and interpreted. Moreover, the concepts developed in this paper explain the effect of the surfactant structure and therefore aid in the design of amphiphilic molecules exhibiting a high solubilizing power for given conditions of brine, temperature, etc.

The Optimal Salinity Concept For Oil Displacement By Oil-external Microemulsions And Graded Salinity Slugs

Abstract Our laboratory studies showed that the concept of the optimal salinity, as derived from phase behaviour or interfacial tensions of microemulsions, is applicable to oil displacement by soluble oils in porous media. Maximal oil recovery was obtained when the salinity of connate water and polymer solution was at the optimal salinity of the surfactant formulation. In the present study, it is shown that the salinity of polymer solution is far more important than the salinity of connate water. When the salinity of polymer solution was at the optimal salinity of the surfactant formulation, high oil recovery efficiency was obtained over a wide range of connate water salinities. Evidence showed that the phase behaviour of the surfactant slug in porous media is largely determined by the salinity of the polymer solution. For better mobility control and minimum surfactant loss, a two-slug design of the surfactant formulation was employed. In this design, the first surfactant slug has an optimal salinity close to the connate water salinity and the second surfactant slug has a much lower optimal salinity. The polymer solution salinity is made equal to the optimal salinity of the second surfactant slug. With this design, high oil recovery in Berea cores can be obtained even in the presence of high-salinity (6% NaCI + 1% CaCl2) connate water. The optimal salinity concept is further extended to include the effects of mobility control and surfactant dispersion and entrapment in porous media. The proposed salinity shock design of mobility polymer solutions employs two slugs of polymer solution in which the first polymer slug is at the optimal salinity of the preceding surfactant formulation and the second polymer slug is at a much lower salinity. With this unique design, high oil recovery and high surfactant recovery can be obtained for soluble oil flooding in sand packs, and the polymer consumption can be greatly reduced. INTRODUCTION Surfactant-polymer flooding processes for enhanced oil recovery ate influenced by a number of parameters. These include reservoir capillary properties(1%4), rock wettability(4%6), reservoir brine and mineralogy(7%14), and rock-fluid interactions (15%19). Connate water salinity and reservoir minerals can affect surfactant flooding through their effects on phase- behaviour, interfacial tensions with slug and residual oil, and mobility control, as well as on surfactant loss due to adsorption, precipitation and phase entrapment processes. By incorporating small amounts of clays or minerals in sand packs, it was shown (7) that the oil recovery efficiency of soluble oil flooding processes greatly diminishes due to the presence of the clays and minerals. Even when clays or divalent cations are absent or in trace amounts, NaCI alone can effectively deteriorate the performance of oleic(8) and aqueous surfactant flooding processes (11%14). Such detrimental effects can often be minimized by means of preflush and optimal salinity design (11,20) of the surfactant slug for a given surfactant and cosurfactant system. The design basis is that for a given surfactant formulation and oil; there exists a salinity at which minimum interfacial tensions occur when surfactant, cosurfactant, oil and brine are equilibrated.