Phase Boundaries of Microemulsion Systems as a Way of Characterizing Hydrocarbon Mixtures

1981 ◽  
Vol 21 (06) ◽  
pp. 763-770 ◽  
Author(s):  
Kishor D. Shah ◽  
Don W. Green ◽  
Michael J. Michnick ◽  
G. Paul Willhite ◽  
Ronald E. Terry
Keyword(s):  
Crude Oil ◽  
Phase Boundary ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Single Phase ◽  
Carbon Number ◽  
Phase Boundaries ◽  
Titration Method ◽  
Lower Phase ◽  
Surfactant System

Abstract Phase behavior of microemulsions composed of TRS 10-80, brine (10.6 mg/g NaCl), isopropyl alcohol, and mixtures of pure hydrocarbons was studied to determine the location of phase boundaries of the single-phase microemulsion region. Studies were conducted on pseudoternary phase diagrams where the pseudocomponents were isopropanol, brine, and a constant ratio of surfactant to hydrocarbon (S/H). Phase boundaries were determined be the titration method developed by Bowcott and Schulman, which was extended to systems of interest for oil recovery by Dominguez et al.The titration method involves the addition of brine to a single-phase microemulsion until phase separation occurs. Then the system is titrated to transparency by addition of isopropanol. Dominguez et al. demonstrated the applicability of the titration method for systems containing pure alkanes. They found upper and lower phase boundaries (high and low alcohol concentrations) for the microemulsion regions on S/H pseudoternary diagrams that were represented by linear relationships between the volume of alcohol and the volume of brine required to attain a single-phase microemulsion. This region, termed Region 4, bounded by linear phase boundaries, extends over a wide range of brine concentrations including regions of interest to enhanced oil-recovery processes. The research reported in this paper extends the work of Dominguez et al. to mixtures of pure hydrocarbons. The locations of the lower phase boundaries for Region 4 were determined for four types of mixtures prepared with pure hydrocarbons ranging from C6 to C18.In all phase behavior experiments, the lower phase boundary of Region 4 was a straight line when volume of alcohol was plotted against volume of brine. Furthermore, the slope of this phase boundary was found to be a linear function of alkane carbon number (ACN) for pure hydrocarbons and equivalent alkane carbon number (EACN) for mixtures of pure hydrocarbons.The correlation of a property of the phase diagram (the slope of the lower phase boundary) with EACN suggests a new approach to characterization of hydrocarbon/surfactant systems. In our experience, the EACN determined from phase behavior studies is more reproducible than the EACN determined from methods involving measurements of interfacial tensions. This method has potential for characterization of surfactant/hydrocarbon systems for complex mixtures of hydrocarbons, including crude oils. Introduction The design of a surfactant system for an enhanced oil-recovery application typically requires much effort, expense, and time. The surfactant system, usually consisting of a petroleum sulfonate and an alcohol dissolved in a brine solution, must be tailormade for a given crude oil/reservoir brine system where it will be applied. The process in finding the optimal system involves varying the components in the surfactant system in compatibility tests, phase behavior studies, physical property measurements, and displacement tests in both Berea and actual reservoir rock.One of the most important considerations in this screening procedure is matching the sulfonate to the crude oil of interest. This can be difficult since both the sulfonate and the crude oil are complex mixtures of pure components. It would be advantageous if each could be characterized by some physical property. SPEJ P. 763^

The Topology of Phase Boundaries for Oil/Brine/Surfactant Systems and Its Relationship to Oil Recovery

1982 ◽  
Vol 22 (01) ◽  
pp. 28-36 ◽  
Author(s):  
M. Bourrel ◽  
C. Chambu ◽  
R.S. Schechter ◽  
W.H. Wade
Keyword(s):  
Phase Boundary ◽  
Phase Behavior ◽  
Phase Diagrams ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Single Phase ◽  
Phase Region ◽  
Alcohol Concentration ◽  
Phase Boundaries ◽  
Single Phase Region

Abstract Surfactant/oil/water phase diagrams have become the most important screening tool used to select microemulsion systems for enhanced oil recovery. The number of phases coexisting at a given salinity, the extent of the single-phase region, and the position of the phase boundaries all have relevance with respect to oil displacement efficiency. It is shown that the phase diagrams can be made to take on different configurations depending on the alcohol cosurfactant, the salinity, the impurities present in the surfactant, and the dispersity of the surfactant mixture. Besides the importance of the phase boundary shape, this study provides further insight into factors determining the height of the binodal surface on the pseudoternary phase diagram. Results show the effect of salinity as well as the surfactant, alcohol, and hydrocarbon types on the height of the binodal surface. It is shown that salinity is the main factor; other parameters have little or no influence once a surfactant has been selected. Finally the microemulsion viscosity is shown to be related to the proximity of the formulation to phase boundaries. Extensive data for one system are presented. Introduction It is now recognized that formulating surfactant/oil/brine systems that exhibit desirable phase behavior is an important step in optimizing performance of microemulsion systems for enhanced oil recovery. Oil is displaced by a combination of mechanisms-miscible displacement, swelling of the oil phase, and low tension displacement all of which are related to the topology of the phase boundaries in composition space. To predict the outcome of a particular project, a representation of the phase boundaries and their evolution when diluted with oil or brines having various proportions of divalent ions is required. For example, successful application of the salinity gradient concept demands phase relationships specially structured to accommodate the variations in salinity experienced by the surfactant slug during the course of the flood. Recent publications have dealt with the optimal salinity as a function of total amphiphile concentration (surfactant plus cosurfactant), and reported trends that are quite different from those found if the cosurfactant (alcohol) concentration is held constant. One purpose of this paper is to demonstrate that contorted phase boundaries found by Glover et al are caused by the variation of alcohol concentration when the concentration of total amphiphile is varied and because the direction that the phase boundaries twist or rotate is controlled by the nature of the alcohol. Another important factor is the extent of the single-phase region. More precisely, the height of the demixing curve in the pseudoternary representation should be minimized. This would permit, in principle, the amount of surfactant and cosurfactant in the micellar slug to be minimized. A correlation permitting the determination of the oil, salinity, alcohol, and surfactant at which the height of the demixing curve is minimized has been reported, but few data giving the value of the minimum height have been presented. This height is an important feature of the phase boundary topology and extensive measurements are reported here. The microemulsion viscosity must be high enough to help maintain mobility control. It is sometimes difficult to achieve the required levels of viscosity. Studies of microemulsion viscosity have been reported. We provide further data here and have related the microemulsion viscosities to phase behavior. Materials and Experimental Techniques The phase diagrams have been established by two techniques: a titration procedure and a grid-point technique. SPEJ P. 28^

Phase Behavior Studies of Two Model Surfactant Systems

1982 ◽  
Vol 22 (01) ◽  
pp. 53-60 ◽  
Author(s):  
William J. Benton ◽  
Natoli John ◽  
Syed Qutubuddin ◽  
Surajit Mukherjee ◽  
Clarence M. Miller
Keyword(s):  
Aqueous Solutions ◽  
Phase Boundary ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Develop Model ◽  
Middle Phase ◽  
Lower Phase ◽  
Interfacial Tensions ◽  
Petroleum Sulfonate ◽  
Surfactant Systems

William J. Benton, Carnegie-Mellon U. John Natoli, Carnegie-Mellon U. Qutubuddin, Syed SPE, Carnegie-Mellon U. Mukherjee, Surajit, Carnegie-Mellon U. Miller, Clarence M., SPE, Carnegie-Mellon U. Fort Jr., Tomlinson, Carnegie-Mellon U. Abstract Phase behavior studies were carried out for two systems containing pure surfactants but exhibiting behavior similar to that of commercial petroleum sulfonates. One system contained the isomerically pure surfactant sodium-8-phenyl-n-hexadecyl-n-sulfonate (Texas 1). The other contained sodium dodecyl sulfate (SDS). Additional components used in both systems were various pure short-chain alcohols, NaCl brine and n-decane. Aqueous solutions containing surfactant, cosurfactant, and NaCl were studied over a wide range of compositions with polarizing and modulation contrast microscopy, as well as the polarized light screening technique. Viscosity measurements were conducted on selected scans of the Texas 1 system. Maxima and minima of the scans were correlated with textural changes observed with microscopy. The aqueous solutions were contacted with equal volumes of n-decane, and phase behavior and interfacial tensions were determined. The middle microemulsion phase was found to be oil continuous close to the upper phase boundary and water continuous close to the lower phase boundary. Both the Texas 1 and SDS systems showed similar behavior in that the middle microemulsion phase was observed over the entire range of surfactant concentrations studied. Introduction Surfactant systems usually consisting of petroleum sulfonate, an alcohol, salt, and water have been used for enhanced oil recovery. Various parameters important to oil recovery by surfactant flooding, such as interfacial tension and viscosity, are related strongly to the phase behavior of the microemulsion systems. The relationship of ultralow interfacial tensions to phase separation has been treated in our laboratory. The recovery of petroleum from laboratory cores and field tests appears to be related directly to phase behavior. It is important to understand phase behavior to identify the mechanisms involved and improve the efficiency of the oil-recovery process. The physicochemical aspects of the phase behavior of microemulsion systems containing commercial petroleum sulfonates as surfactants have been well documented by Healy and Reed and others. However, the systems studied were not pure, and the commercial surfactants sometimes contained as much as 40% inactive ingredients. There is a need to develop model microemulsion systems using pure components. Such systems would provide an experimental platform for verifying or interpreting the implications of any model for the phase behavior of multicomponent microemulsion systems and also allow the behavior of commercial systems to be predicted and understood. The objective of our work has been to fulfill these needs. Microemulsions have been classified as lower phase (l), upper phase (u), or middle phase (m) in equilibrium with excess oil, excess brine, or both excess oil and brine, respectively. Transitions among these phases have been studied as functions of salinity, alcohol concentration, temperature, etc. The middle-phase microemulsion is particularly significant because microemulsion/excess brine and microemulsion/excess oil tensions can be ultra low simultaneously. The concept of an optimal parameter as proposed originally by Reed and Healy when equal amounts of oil and brine are solubilized in the middle phase has been followed in this paper. We have shown earlier that the structure of petroleum sulfonate solutions exhibits a general pattern of variation with salinity. SPEJ P. 53^

Effects of Hardness and Cosurfactant on Phase Behavior of Alcohol-Free Alkyl Propoxylated Sulfate Systems

SPE Journal ◽  
2015 ◽  
Vol 20 (05) ◽  
pp. 1145-1153 ◽  
Author(s):  
Maura C. Puerto ◽  
George J. Hirasaki ◽  
Clarence A. Miller ◽  
Carmen Reznik ◽  
Sheila Dubey ◽  
...  
Keyword(s):  
Aqueous Solutions ◽  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Equilibrium Phase ◽  
Optimal Conditions ◽  
Lower Phase ◽  
Blend Ratio ◽  
Internal Olefin ◽  
Internal Olefin Sulfonate

Summary The effect of hardness was investigated on equilibrium phase behavior in the absence of alcohol for blends of three alcohol propoxy sulfates (APSs) with an internal olefin sulfonate (IOS) with a C15–18 chain length. Hard brines investigated were synthetic seawater (SW), 2*SW, and 3*SW, the last two with double and triple the total ionic content of SW with all ions present in the same relative proportions as in SW, respectively. Optimal blends of the APS/IOS systems formed microemulsions with n-octane that had high solubilization suitable for enhanced oil recovery at both ≈25°C and 50°C. However, oil-free aqueous solutions of the optimal blends in 2*SW and 3*SW, as well as in 8 and 12% NaCl solutions with similar ionic strengths, exhibited cloudiness and/or precipitation and were unsuitable for injection. In SW at 25°C, the aqueous solution of the optimal blend of C16–17 7 propylene oxide sulfate, made from a branched alcohol, and IOS15–18, was clear and suitable for injection. A salinity map prepared for blends of these surfactants illustrates how such maps facilitate the selection of injection compositions in which injection and reservoir salinities differ. The same APS was blended with other APSs and alcohol ethoxy sulfates (AESs) in SW at ≈25°C, yielding microemulsions with high n-octane solubilization and clear aqueous solutions at optimal conditions. Three APS/AES blends were found to form suitable microemulsions in SW with a crude oil at its reservoir temperature near 50°C. Optimal conditions were nearly the same for hard brines and NaCl solutions with similar ionic strengths between SW and 3*SW. Although the aqueous solutions for the optimal blends with crude oil were slightly cloudy, small changes in blend ratio led to formation of lower phase microemulsions with clear aqueous solutions. When injection and reservoir brines differ, it may be preferable to inject at such slightly underoptimum conditions to avoid generating upper phase, Winsor II, conditions produced by inevitable mixing of injected and formation brines.

Surfactant Retention in Berea Sandstone- Effects of Phase Behavior and Temperature

1982 ◽  
Vol 22 (06) ◽  
pp. 962-970 ◽  
Author(s):  
J. Novosad
Keyword(s):  
Porous Media ◽  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Liquid Interface ◽  
Divalent Ions ◽  
Surfactant Precipitation ◽  
Wide Range ◽  
Solid Liquid Interface ◽  
Solid Liquid

Novosad, J., SPE, Petroleum Recovery Inst. Abstract Experimental procedures designed to differentiate between surfactant retained in porous media because of adsorption and surfactant retained because Of unfavorable phase behavior are developed and tested with three types of surfactants. Several series of experiments with systematic changes in one variable such as surfactant/cosurfactant ratio, slug size, or temperature are performed, and overall surfactant retention then is interpreted in terms of adsorption and losses caused by unfavorable phase behavior. Introduction Adsorption of surfactants considered for enhanced oil recovery (EOR) applications has been studied extensively in the last few years since it has been shown that it is possible to develop surfactant systems that displace oil from porous media almost completely when used in large quantities. Effective oil recovery by surfactants is not a question of principle but rather a question of economics. Since surfactants are more expensive than crude oil, development of a practical EOR technology depends on how much surfactant can be sacrificed economically while recovering additional crude oil from a reservoir.It was recognized earlier that adsorption may be only one of a number of factors that contribute to total surfactant retention. Other mechanisms may include surfactant entrapment in an immobile oil phase surfactant precipitation by divalent ions, surfactant precipitation caused by a separation of the cosurfactant from the surfactant, and surfactant precipitation resulting from chromatographic separation of different surfactant specks. The principal objective of this work is to evaluate the experimental techniques that can be used for measuring surfactant adsorption and to study experimentally two mechanisms responsible for surfactant retention. Specifically, we try to differentiate between the adsorption of surfactants at the solid/liquid interface and the retention of the surfactants because of trapping in the immobile hydrocarbon phase that remains within the core following a surfactant flood. Measurement of Adsorption at the Solid/Liquid Interface Previous adsorption measurements of surfactants considered for EOR produced adsorption isotherms of unusual shapes and unexpected features. Primarily, an adsorption maximum was observed when total surfactant retention was plotted against the concentration of injected surfactant. Numerous explanations have been offered for these peaks, such as a formation of mixed micelles, the effects of structure-forming and structurebreaking cations, and the precipitation and consequent redissolution of divalent ions. It is difficult to assess which of these effects is responsible for the peaks in a particular situation and their relative importance. However, in view of the number of physicochemical processes taking place simultaneously and the large number of components present in most systems, it seems that we should not expect smooth monotonically increasing isotherms patterned after adsorption isothemes obtained with one pure component and a solvent. Also, it should be realized that most experimental procedures do not yield an amount of surfactant adsorbed but rather a measure of the surface excess.An adsorption isotherm, expressed in terms of the surface excess as a function of an equilibrium surfactant concentration, by definition must contain a maximum if the data are measured over a sufficiently wide range of concentrations. SPEJ P. 962^

Generation of Ultralow Tensions Over a Wide EACN Range Using Pennsylvania State U. Surfactants

1983 ◽  
Vol 23 (01) ◽  
pp. 73-80 ◽  
Author(s):  
E.E. Klaus ◽  
J.H. Jones ◽  
R. Nagarajan ◽  
T. Ertekin ◽  
Y.M. Chung ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Narrow Range ◽  
Carbon Number ◽  
Cyclic Ethers ◽  
Equivalent Weight ◽  
High Concentration ◽  
Low Concentration ◽  
Surfactant Solutions ◽  
Wide Range

Klaus, E.E., Pennsylvania State U. Jones, J.H., Pennsylvania State U. Nagarajan, R., Pennsylvania State U. Ertekin, T., SPE. Pennsylvania State U. Chung, Y.M., Pennsylvania State U. Arf, G., Pennsylvania State U. Yarzumbeck, A.J., Pennsylvania State U. Dudenas, P., Pennsylvania State U. Abstract Saturated paraffinic and naphthenic hydrocarbons without aromatics have been vapor-phase oxidized to produce cyclic ethers and lesser amounts of olefins. These cyclic ethers appear to be effective cosurfactants for the preparation of slugs containing petroleum sulfonate surfactants. The cyclic-ether/olefin mixture has been reacted with SO from oleum or liquid SO to form sulfonates comprising a mixture of mono-, di-, and polysulfonates. The reaction products consisting of the sulfonates, unreacted oxidized products, and residual hydrocarbons have been extracted with isopropanol (IPA) to give two sulfonate fractions. The first fraction is predominantly monosulfonate with lesser quantities of disulfonates. The second fraction consists primarily of di-, tri-, and polysulfonates. The monosulfonate fraction in a low-concentration slug exhibits ultralow interfacial tension (IFT) against hydrocarbons of low equivalent alkane carbon number (EACN). The behavior of this fraction is similar to that of the commercial sulfonates in that its ability to generate low IFT is confined to a narrow range of EACN. To achieve low IFT's at higher EACN in the range of a Pennsylvania crude oil, it is necessary to raise the equivalent weight of the Pennsylvania State U. monosulfonate fraction by blending with a commercial sulfonate of higher equivalent weight. Recent studies show that by mixing, the two IPA fractions of the sulfonation products. a remarkably new surfactant behavior is obtained. In contrast to the behavior of other surfactants that yield ultralow tensions over only a narrow range of values of EACN, this mixture of mono- and polysulfonates generates low IFT's over a wide range of EACN extending from C5 to C12. The salt tolerance of monosulfonates and polysulfonates, either alone or in mixtures. is rather high and even at about 4 wt% NaC1, the surfactant solutions remain stable and yield low IFT's against crude oil. Introduction Chemical flooding processes for terliary oil recovery based on both low-concentration surfactant solutions (typically 2 to 3 wt% or less) and high-concentration surfactant solutions (about 10 wt%) are being investigated in a number of laboratory and field studies. In both types of processes, the ability of surfactant solutions to lower the IFT against crude oil is a major factor determining the oil displacement efficiency. A variety of surfactants, primarily sulfonates synthesized from aromatics present in petroleum fractions, have been identified as those possessing the physical and chemical properties required for the flooding process. The surfactant slug formulations typically consist of the sulfonates, electrolytes, and cosurfactants such as alcohols. The slug, when contacted with oil, can generate a microemulsion phase coexisting with oil and water phases. Low IFT's are found to occur at those conditions that favor the formation of the preceding three phases. Several investigations have focused on determining the conditions for the three- phase formation and IFT lowering in terms of the molecular structure and the molecular weight of the surfactant, the characteristics of the oil (namely, its EACN), salinity, surfactant concentration, and the type and amount of cosurfactant, if used. SPEJ P. 73^

Digital Oil Model Development and Verification

2021 ◽  
Author(s):  
Vai Yee Hon ◽  
Ismail Mohd Saaid ◽  
Ching Hsia Ivy Chai ◽  
Noor 'Aliaa M. Fauzi ◽  
Estelle Deguillard ◽  
...  
Keyword(s):  
Molecular Structure ◽  
Crude Oil ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbon Number ◽  
Dynamics Simulation ◽  
Large Contribution ◽  
Molecular Chemistry ◽  
Chemistry Modeling ◽  
Oil Components

Abstract Advances in digital technologies have the potential to enhance model predictive capability and redefine its boundaries at various scale. Digital oil with accurate representation of atomistic components is a powerful tool to analyze both macroscopic properties and microscopic phenomena of crude oil under any thermodynamic conditions. Digital oil model presented in this paper is the key input in molecular chemistry modeling for designing chemical enhanced oil recovery formulation. Hence, it is constructed based on a fit-for purpose strategy focusing in oil components that have large contribution to microemulsion stability. Complete crude oil composition could comprise over 100,000 components. Lengthy simulation time is required to simulate all crude oil components which is impratical, despite the challenges to identify all crude oil components experimentally. Therefore, we established a practical experimental strategy to identify key crude oil components and constructed the digital oil model based on surrogate components. The surrogate components are representative molecules of the volatiles, saturates, aromatics and resins. Two-dimensional digital oil model, with aromaticity on one axis, and the size of the molecules on the other axis was constructed. We developed algorithm to integrate nuclear magnetic resonance response with architecture of the molecular structure. A group contribution method was implemented to ensure reliable representation of the molecular structure. We constructed the digital oil models for a field in Malaysia Basin. We validated the physical properties of the digital oil model with properties measured from experiment, predicted from molecular dynamics simulation and calculated from quantitative property-property relationship method. Good agreement was obtained from the validation, with less than 5% and 13% variance in crude density and Equivalent Alkane Carbon Number respectively, indicating that the molecular characteristic of the digital oil model was captured correctly. We adopted the digital oil model in molecular chemistry modeling to gain insights into microemulsion formation in chemical enhanced oil recovery formulation design. Digital oil is a robust tool to make predictions when information cannot be extracted from experimental data alone. It can be extended for engineering applications involving processing, safety, hazard, and environmental considerations.

Modeling of Pressure and Solution Gas for Chemical Floods

SPE Journal ◽  
2013 ◽  
Vol 18 (03) ◽  
pp. 428-439 ◽  
Author(s):  
M.. Roshanfekr ◽  
R.T.. T. Johns ◽  
M.. Delshad ◽  
G.A.. A. Pope
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Atmospheric Pressure ◽  
Carbon Number ◽  
Chemical Flooding ◽  
Reservoir Pressure ◽  
Optimal Salinity ◽  
Free Gas ◽  
Cubic Equation ◽  
Solution Gas

Summary The goal of surfactant/polymer (SP) flooding is to reduce interfacial tension (IFT) between oil and water so that residual oil is mobilized and high recovery is achieved. The optimal salinity and optimal solubilization ratios that correspond to ultralow IFT have recently been shown, in some cases, to be a strong function of the methane mole fraction in the oil at reservoir pressure. We incorporate a recently developed methodology to determine the optimal salinity and solubilization ratio at reservoir pressure into a chemical-flooding simulator (UTCHEM). The proposed method determines the optimal conditions on the basis of density estimates by use of a cubic equation of state (EOS) and measured phase-behavior data at atmospheric pressure. The microemulsion phase-behavior (Winsor I, II, and III) are adjusted on the basis of this predicted optimal salinity and solubilization ratio in the simulator. Parameters for the surfactant phase-behavior equation are modified to account for these changes, and the trend in the equivalent alkane carbon number (EACN) is automatically adjusted for pressure and methane content in each simulation gridblock. We use phase-behavior data from several potential SP floods to demonstrate the new implementation. The implementation of the new phase-behavior model into a chemical-flooding simulator allows for a better design of SP floods and more-accurate estimations of oil recovery. The new approach could also be used to handle free gas that may form in the reservoir; however, the SP-flood simulation when free gas is present is not the focus of this paper. We show that not accounting for the phase-behavior changes that occur when methane is present at reservoir pressure can greatly affect the oil recovery of SP floods. Improper design of an SP flood can lead to production of more oil as a microemulsion phase than as an oil bank. This paper describes the procedure to implement the effect of pressure and solution gas on microemulsion phase behavior in a chemical-flooding simulator, which requires the phase-behavior data measured at atmospheric pressure.

Hydrocarbon Recovery From Oil Sands by Cyclic Surfactant Solubilization in Single-Phase Microemulsions

2019 ◽  
Vol 141 (8) ◽  
Author(s):  
Pushpesh Sharma ◽  
Konstantinos Kostarelos ◽  
Sujeewa S. Palayangoda
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Oil Sands ◽  
Single Phase ◽  
Open Pit ◽  
Open Pit Mining ◽  
Heavy Oils ◽  
Oil Sand ◽  
Flow Experiment ◽  
Heavy Crude

Extra heavy crude oil (bitumen) reserves represent a significant part of the energy resources found all over the world. In Canada, the “oil sands” deposits are typically unconsolidated, water-wet media where current methods of recovery, such as open pit mining, steam-assisted gravity drainage (SAGD), vapor extraction, cold heavy oil production with sand, etc., are controversial due to adverse effect on environment. Chemical enhanced oil recovery (cEOR) techniques have been applied as alternatives but have limited success and contradictory results. An alternative method is described in this paper, which relies on the application of single-phase microemulsion to achieve extremely high solubilization. The produced microemulsion will be less viscous than oil, eliminating the need for solvent addition. Produced microemulsion can be separated to recover surfactant for re-injection. The work in this paper discusses phase behavior experiments and a flow experiment to prove the concept that single-phase microemulsions could be used to recover extra-heavy oils. Phase behavior experiments showed that the mixture of alcohol propoxysulfate, sodium dioctyl sulfosuccinate, sodium carbonate, and tri-ethylene glycol monobutyl ether results in single-phase microemulsion with extra-heavy crude. A flow experiment conducted with the same composition produced only single-phase microemulsion leading to 74% recovery of the original oil in place from a synthetic oil sand. Future experiments will be focused on optimizing the formulation and testing with actual oil sands samples.

scholarly journals Chemical Compositions in Modified Salinity Waterflooding of Carbonate Reservoirs -- Experiment

2021 ◽  
Author(s):  
Maxim Yutkin ◽  
Clayton J. Radke ◽  
Tadeusz Patzek
Keyword(s):  
Calcium Carbonate ◽  
Ion Exchange ◽  
Crude Oil ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Single Phase ◽  
Theoretical Framework ◽  
Mineral Dissolution ◽  
High Dispersion ◽  
Carbonate Dissolution

<br>Modified or low-salinity waterflooding of carbonate oil reservoirs is of considerable economic interest because of potentially inexpensive incremental oil<br>production. The injected modified brine changes the surface chemistry of the carbonate rock and crude oil interfaces and detaches some adhered crude oil.<br>Composition design of the modified brine to enhance oil recovery is determined by labor-intensive trial-and-error laboratory corefloods. Unfortunately, limestone,<br>which predominantly consists of aqueous-reactive calcium carbonate, alters injected brine composition by mineral dissolution/precipitation. Accordingly, the rock reactivity<br>hinders rational design of the tailored brine to improve oil recovery. <br>Previously, we presented a theoretical analysis of 1D, single-phase brine injection into calcium carbonate-rock that accounts for mineral dissolution, ion<br>exchange, and dispersion (Yutkin et. al 2021). Here we present the results of single-phase waterflood-brine experiments that verify the theoretical framework. We show that concentration histories eluted from Indiana limestone cores possess features characteristic of fast calcium<br>carbonate dissolution, 2:1 ion exchange, and high dispersion. The injected brine reaches chemical equilibrium inside the porous rock even at<br>injection rates higher than 1000 ft/day. Ion exchange results in salinity waves observed experimentally, while high dispersion is responsible for long<br>concentration history tails. <br>Using the verified theoretical framework, we briefly explore how these processes modify aqueous-phase composition during the injection of designer brines into a calcium-carbonate reservoir. Because of high salinity of the initial and injected brines, ion exchange affects injected concentrations only in<br>high surface area carbonates/limestones, such as chalks. Calcium-carbonate dissolution only affects aqueous solution pH. The rock surface composition is affected by all processes.<br><br>

Experimental Analysis of Alkali-Brine-Alcohol Phase Behavior with High Acid Number Crude Oil

2021 ◽  
pp. 1-19
Author(s):  
D. Magzymov ◽  
T. Clemens ◽  
B. Schumi ◽  
R. T. Johns
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Complex Mixture ◽  
Acid Number ◽  
Field Application ◽  
Water Interface ◽  
Total Acid ◽  
Oil Water

Summary A potential enhanced oil recovery technique is to inject alkali into a reservoir with a high-total acid number (TAN) crude to generate soap in situ and reduce interfacial tension (IFT) without the need to inject surfactant. The method may be cost-effective if the IFT can be lowered enough to cause significant mobilization of trapped oil while also avoiding formation of gels and viscous phases. This paper investigates the potential field application of injecting alkali to generate in-situ soap and favorable phase behavior for a high-TAN oil. Oil analyses show that the acids in the crude are a complex mixture of various polar acids and not mainly carboxylic acids. The results from phase behavior experiments do not undergo typical Winsor microemulsion behavior transition and subsequent ultralow IFTs below 1×10−3 mN/m that are conventionally observed. Instead, mixing of alkali and crude/brine generate water-in-oil macroemulsions that can be highly viscous. For a specific range of alkali concentrations, however, phases are not too viscous, and IFTs are reduced by several orders of magnitude. Incremental coreflood recoveries in this alkali range are excellent, even though not all trapped oil is mobilized. The viscous phase behavior at high alkali concentrations is explained by the formation of salt-crude complexes, created by acids from the crude oil under the alkali environment. These hydrophobic molecules tend to agglomerate at the oil-water interface. Together with polar components from the crude oil, they can organize into a highly viscous network and stabilize water droplets in the oleic phase. Oil-soluble alcohol was added to counter those two phenomena at large concentrations, but typical Winsor phase behavior was still not observed. A physicochemical model is proposed to explain the salt-crude complex formation at the oil-water interface that inhibits classical Winsor behavior.

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