Simulation of Surfactant/Polymer Floods With a Predictive and Robust Microemulsion Flash Calculation

SPE Journal ◽  
2016 ◽  
Vol 22 (02) ◽  
pp. 470-479 ◽  
Author(s):  
Saeid Khorsandi ◽  
Changhe Qiao ◽  
Russell T. Johns
Keyword(s):  
Experimental Data ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Carbon Number ◽  
General Purpose ◽  
Accurate Estimation ◽  
Chemical Flooding ◽  
Two Phase ◽  
Data Set ◽  
Average Curvature

Summary A compositional reservoir simulator that uses a predictive microemulsion phase-behavior model is essential for accurate estimation of oil recovery from surfactant/polymer (SP) floods. Current chemical-flooding simulators, however, use Hand's model (Hand 1939) for phase-behavior calculation. Hand's model can reasonably fit a limited set of experimental data, such as those of a salinity scan, but because it is empirical, it cannot predict phase behavior outside the matched data set. Hydrophyllic/lypophyllic difference (HLD) and net-average-curvature (NAC) equation of state (EOS) (Acosta et al. 2003) has shown great performance for tuning and prediction of experimental data. In this paper, the EOS model with the extension to two-phase regions has been incorporated for the first time into UTCHEM (2000) and our in-house general-purpose compositional simulator, PennSim (2013). All Winsor regions (Type II−, II+, III, and IV) are modeled by use of a consistent physics-based EOS model without the need for Hand's approach. The new simulator is therefore able to account correctly for gridblock properties, which can vary temporally and spatially, and significantly improve the modeling of phase behavior and oil recovery. The results show excellent agreement between UTCHEM and PennSim both in composition space and for composition/saturation profiles for the 1D simulation. The effects of varying pressure, temperature, equivalent alkane carbon number (EACN), and salinity on recoveries are demonstrated also in 1D simulations.

An Equation-of-State Model To Predict Surfactant/Oil/Brine-Phase Behavior

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1106-1125 ◽  
Author(s):  
S.. Ghosh ◽  
R. T. Johns
Keyword(s):  
Experimental Data ◽  
Equation Of State ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Atmospheric Pressure ◽  
Carbon Number ◽  
Oil Reservoirs ◽  
Potential Candidate ◽  
Average Curvature ◽  
Formulation Variables

Summary Surfactant/polymer (SP) floods have significant potential to recover waterflood residual oil in shallow oil reservoirs. A thorough understanding of surfactant/oil/brine-phase behavior is critical to design SP-flood processes. Current practices involve repetitive laboratory experiments of dead crude at atmospheric pressure in a salinity scan that aims at finding an “optimum formulation” of chemicals for targeted oil reservoirs. Although considerable progress has been made in developing surfactants and polymers that increase the potential of a chemical enhanced-oil-recovery (EOR) project, very little progress has been made to predict phase behavior as a function of formulation variables such as pressure, temperature, and oil equivalent alkane carbon number (EACN). The empirical Hand (1930) plot is still used today to model the microemulsion-phase behavior with little predictive capability because these and other formulation variables change. Such models could lead to incorrect recovery predictions and improper SP-flood designs. In this research, we develop a new predictive-phase-behavior model and introduce a new factor β to account for pressure changes in the HLD equation. This new HLD equation is coupled with the net-average-curvature (NAC) model to predict phase volumes, solubilization ratios, and microemulsion-phase transitions (Winsor II–, Winsor III, and Winsor II+). The predictions of key parameters are compared with experimental data and are within relative errors of 4% (average 2.35%) for measured optimum salinities and 17% (average 10.55%) for optimum solubilization ratios. This paper is the first to use the HLD/NAC model to predict microemulsion-phase behavior for live crudes, including optimal solubilization ratio and the salinity width of the three-phase Winsor III region at different temperatures and pressures. Although the effect of pressure variations on microemulsion-phase behavior is generally thought to be small compared with temperature-induced changes, we show here that this is not necessarily the case. The predictive approach relies on tuning the model to limited experimental data (such as at atmospheric pressure) similar to what is performed for equation-of-state (EOS) modeling of miscible gasfloods. This new EOS-like model could significantly aid the design of chemical floods where key variables change dynamically, and in screening of potential candidate reservoirs for chemical EOR.

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.

Solution Properties and Phase Behavior of Ammonium Hexylene Octyl Succinate in Water and Water-Oil System

1970 ◽  
Vol 3 (1) ◽  
Author(s):  
Md. Hamidul Kabir ◽  
Ravshan Makhkamov ◽  
Shaila Kabir
Keyword(s):  
Critical Micelle Concentration ◽  
Phase Behavior ◽  
Liquid Crystalline ◽  
Carbon Number ◽  
Phase Region ◽  
Solution Properties ◽  
Middle Phase ◽  
Two Phase ◽  
Lamellar Liquid Crystal ◽  
Drug Ingredient

The solution properties and phase behavior of ammonium hexylene octyl succinate (HOS) was investigated in water and water-oil system. The critical micelle concentration (CMC) of HOS is lower than that of anionic surfactants having same carbon number in the lipophilic part. The phase diagrams of a water/ HOS system and water/ HOS/ C10EO8/ dodecane system were also constructed. Above critical micelle concentration, the surfactant forms a normal micellar solution (Wm) at a low surfactant concentration whereas a lamellar liquid crystalline phase (La) dominates over a wide region through the formation of a two-phase region (La+W) in the binary system. The lamellar phase is arranged in the form of a biocompatible vesicle which is very significant for the drug delivery system. The surfactant tends to be hydrophilic when it is mixed with C10EO8 and a middle-phase microemulsion (D) is appeared in the water-surfactant-dodecane system where both the water and oil soluble drug ingredient can be incorporated in the form of a dispersion. Hence, mixing can tune the hydrophile-lipophile properties of the surfactant. Key words: Ammonium hexylene octyl succinate, mixed surfactant, lamellar liquid crystal, middle-phase microemulsion. Dhaka Univ. J. Pharm. Sci. Vol.3(1-2) 2004 The full text is of this article is available at the Dhaka Univ. J. Pharm. Sci. website

A Ternary, Two-Phase, Mathematical Model of Oil Recovery With Surfactant Systems

1984 ◽  
Vol 24 (06) ◽  
pp. 606-616 ◽  
Author(s):  
Charles P. Thomas ◽  
Paul D. Fleming ◽  
William K. Winter
Keyword(s):  
Mathematical Model ◽  
Oil Recovery ◽  
Arbitrary Number ◽  
The Other ◽  
Phase System ◽  
Chemical Flooding ◽  
Two Phase ◽  
Oil Displacement ◽  
Surfactant Systems ◽  
And Diffusion

Abstract A mathematical model describing one-dimensional (1D), isothermal flow of a ternary, two-phase surfactant system in isotropic porous media is presented along with numerical solutions of special cases. These solutions exhibit oil recovery profiles similar to those observed in laboratory tests of oil displacement by surfactant systems in cores. The model includes the effects of surfactant transfer between aqueous and hydrocarbon phases and both reversible and irreversible surfactant adsorption by the porous medium. The effects of capillary pressure and diffusion are ignored, however. The model is based on relative permeability concepts and employs a family of relative permeability curves that incorporate the effects of surfactant concentration on interfacial tension (IFT), the viscosity of the phases, and the volumetric flow rate. A numerical procedure was developed that results in two finite difference equations that are accurate to second order in the timestep size and first order in the spacestep size and allows explicit calculation of phase saturations and surfactant concentrations as a function of space and time variables. Numerical dispersion (truncation error) present in the two equations tends to mimic the neglected present in the two equations tends to mimic the neglected effects of capillary pressure and diffusion. The effective diffusion constants associated with this effect are proportional to the spacestep size. proportional to the spacestep size. Introduction In a previous paper we presented a system of differential equations that can be used to model oil recovery by chemical flooding. The general system allows for an arbitrary number of components as well as an arbitrary number of phases in an isothermal system. For a binary, two-phase system, the equations reduced to those of the Buckley-Leverett theory under the usual assumptions of incompressibility and each phase containing only a single component, as well as in the more general case where both phases have significant concentrations of both components, but the phases are incompressible and the concentration in one phase is a very weak function of the pressure of the other phase at a given temperature. pressure of the other phase at a given temperature. For a ternary, two-phase system a set of three differential equations was obtained. These equations are applicable to chemical flooding with surfactant, polymer, etc. In this paper, we present a numerical solution to these equations paper, we present a numerical solution to these equations for I D flow in the absence of gravity. Our purpose is to develop a model that includes the physical phenomena influencing oil displacement by surfactant systems and bridges the gap between laboratory displacement tests and reservoir simulation. It also should be of value in defining experiments to elucidate the mechanisms involved in oil displacement by surfactant systems and ultimately reduce the number of experiments necessary to optimize a given surfactant system.

Development of the Surfactant-Based Chemical EOR Formula for Low Permeability Reservoirs

2021 ◽  
Author(s):  
Nancy Chun Zhou ◽  
Meng Lu ◽  
Fuchen Liu ◽  
Wenhong Li ◽  
Jianshen Li ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Aqueous Solubility ◽  
Low Permeability ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Key Factors ◽  
Low Salinity ◽  
Low Tension ◽  
Low Permeability Reservoirs

Abstract Based on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding. Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions. Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs. In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.

scholarly journals Curvature-Based Equation of State for Microemulsion-Phase Behavior

SPE Journal ◽  
2018 ◽  
Vol 24 (02) ◽  
pp. 647-659 ◽  
Author(s):  
V. A. Torrealba ◽  
R. T. Johns ◽  
H.. Hoteit
Keyword(s):  
Equation Of State ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Industrial Applications ◽  
Data Availability ◽  
Behavior Modeling ◽  
Average Curvature ◽  
Wide Range ◽  
Definition Of ◽  
Spheroidal Geometry

Summary An accurate description of the microemulsion-phase behavior is critical for many industrial applications, including surfactant flooding in enhanced oil recovery (EOR). Recent phase-behavior models have assumed constant-shaped micelles, typically spherical, using net-average curvature (NAC), which is not consistent with scattering and microscopy experiments that suggest changes in shapes of the continuous and discontinuous domains. On the basis of the strong evidence of varying micellar shape, principal micellar curves were used recently to model interfacial tensions (IFTs). Huh's scaling equation (Huh 1979) also was coupled to this IFT model to generate phase-behavior estimates, but without accounting for the micellar shape. In this paper, we present a novel microemulsion-phase-behavior equation of state (EoS) that accounts for changing micellar curvatures under the assumption of a general-prolate spheroidal geometry, instead of through Huh's equation. This new EoS improves phase-behavior-modeling capabilities and eliminates the use of NAC in favor of a more-physical definition of characteristic length. Our new EoS can be used to fit and predict microemulsion-phase behavior irrespective of IFT-data availability. For the cases considered, the new EoS agrees well with experimental data for scans in both salinity and composition. The model also predicts phase-behavior data for a wide range of temperature and pressure, and it is validated against dynamic scattering experiments to show the physical significance of the approach.

Effect of Common Impurities on the Phase Behavior of Carbon-Dioxide-Rich Systems: Minimizing the Risk of Hydrate Formation and Two-Phase Flow

SPE Journal ◽  
2011 ◽  
Vol 16 (04) ◽  
pp. 921-930 ◽  
Author(s):  
Antonin Chapoy ◽  
Rod Burgass ◽  
Bahman Tohidi ◽  
J. Michael Austell ◽  
Charles Eickhoff
Keyword(s):  
Experimental Data ◽  
Carbon Dioxide ◽  
Phase Behavior ◽  
Water Content ◽  
Thermodynamic Model ◽  
Two Phase Flow ◽  
Hydrate Formation ◽  
Experimental Methodology ◽  
Phase Flow ◽  
Two Phase

Summary Carbon dioxide (CO2) produced by carbon-capture processes is generally not pure and can contain impurities such as N2, H2, CO, H2 S, and water. The presence of these impurities could lead to challenging flow-assurance issues. The presence of water may result in ice or gas-hydrate formation and cause blockage. Reducing the water content is commonly required to reduce the potential for corrosion, but, for an offshore pipeline system, it is also used as a means of preventing gas-hydrate problems; however, there is little information on the dehydration requirements. Furthermore, the gaseous CO2-rich stream is generally compressed to be transported as liquid or dense-phase in order to avoid two-phase flow and increase in the density of the system. The presence of impurities will also change the system's bubblepoint pressure, hence affecting the compression requirement. The aim of this study is to evaluate the risk of hydrate formation in a CO2-rich stream and to study the phase behavior of CO2 in the presence of common impurities. An experimental methodology was developed for measuring water content in a CO2-rich phase in equilibrium with hydrates. The water content in equilibrium with hydrates at simulated pipeline conditions (e.g., 4°C and up to 190 bar) as well as after simulated choke conditions (e.g., at -2°C and approximately 50 bar) was measured for pure CO2 and a mixture of 2 mol% H2 and 98 mol% CO2. Bubblepoint measurements were also taken for this binary mixture for temperatures ranging from -20 to 25°C. A thermodynamic approach was employed to model the phase equilibria. The experimental data available in the literature on gas solubility in water in binary systems were used in tuning the binary interaction parameters (BIPs). The thermodynamic model was used to predict the phase behavior and the hydrate-dissociation conditions of various CO2-rich streams in the presence of free water and various levels of dehydration (250 and 500 ppm). The results are in good agreement with the available experimental data. The developed experimental methodology and thermodynamic model could provide the necessary data in determining the required dehydration level for CO2-rich systems, as well as minimum pipeline pressure required to avoid two-phase flow, hydrates, and water condensation.

A Modified HLD-NAC Equation of State To Predict Alkali/Surfactant/Oil/Brine Phase Behavior

SPE Journal ◽  
2018 ◽  
Vol 23 (02) ◽  
pp. 550-566 ◽  
Author(s):  
Soumyadeep Ghosh ◽  
Russell T. Johns
Keyword(s):  
Equation Of State ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Naphthenic Acids ◽  
Phase Region ◽  
Measured Data ◽  
Synthetic Surfactant ◽  
Chemical Flooding ◽  
Mineral Surfaces ◽  
Dimensionless Equation

Summary Reservoir crudes often contain acidic components (primarily naphthenic acids), which undergo neutralization to form soaps in the presence of alkali. The generated soaps perform synergistically with injected synthetic surfactants to mobilize waterflood residual oil in what is termed alkali/surfactant/polymer (ASP) flooding. The two main advantages of using alkali in enhanced oil recovery (EOR) are to lower cost by injecting a lesser amount of expensive synthetic surfactant and to reduce adsorption of the surfactant on the mineral surfaces. The addition of alkali, however, complicates the measurement and prediction of the microemulsion phase behavior that forms with acidic crudes. For a robust chemical-flood design, a comprehensive understanding of the microemulsion phase behavior in such processes is critical. Chemical-flooding simulators currently use Hand's method to fit a limited amount of measured data, but that approach likely does not adequately predict the phase behavior outside the range of the measured data. In this paper, we present a novel and practical alternative. In this paper, we extend a dimensionless equation of state (EOS) (Ghosh and Johns 2016b) to model ASP phase behavior for potential use in reservoir simulators. We use an empirical equation to calculate the acid-distribution coefficient from the molecular structure of the soap. Key phase-behavior parameters such as optimum salinities and optimum solubilization ratios are calculated from soap-mole-fraction-weighted equations. The model is tuned to data from phase-behavior experiments with real crudes to demonstrate the procedure. We also examine the ability of the new model to predict fish plots and activity charts that show the evolution of the three-phase region. The predictions of the model are in good agreement with measured data.

Sign in / Sign up

Export Citation Format

Share Document