Numerical effects on the simulation of surfactant flooding for enhanced oil recovery

2021 ◽  
Author(s):  
Olaitan Akinyele ◽  
Karl D. Stephen
Keyword(s):  
Interfacial Tension ◽  
Cell Size ◽  
Oil Recovery ◽  
Flow In Porous Media ◽  
Numerical Dispersion ◽  
Sharp Change ◽  
Surfactant Flooding ◽  
Fractional Flow ◽  
Time Step ◽  
Scale Models

Abstract Numerical simulation of surfactant flooding using conventional reservoir simulation models can lead to unreliable forecasts and bad decisions due to the appearance of numerical effects. The simulations give approximate solutions to systems of nonlinear partial differential equations describing the physical behavior of surfactant flooding by combining multiphase flow in porous media with surfactant transport. The approximations are made by discretization of time and space which can lead to spurious pulses or deviations in the model outcome. In this work, the black oil model was simulated using the decoupled implicit method for various conditions of reservoir scale models to investigate behaviour in comparison with the analytical solution obtained from fractional flow theory. We investigated changes to cell size and time step as well as the properties of the surfactant and how it affects miscibility and flow. The main aim of this study was to understand pulse like behavior that has been observed in the water bank to identify cause and associated conditions. We report for the first time that the pulses occur in association with the simulated surfactant water flood front and are induced by a sharp change in relative permeability as the interfacial tension changes. Pulses are diminished when the adsorption rate was within the value of 0.0002kg/kg to 0.0005kg/kg. The pulses are absent for high resolution model of 5000 cells in x direction with a typical cell size as used in well-scale models. The growth or damping of these pulses may vary from case to case but in this instance was a result of the combined impact of relative mobility, numerical dispersion, interfacial tension and miscibility. Oil recovery under the numerical problems reduced the performance of the flood, due to large amounts of pulses produced. Thus, it is important to improve existing models and use appropriate guidelines to stop oscillations and remove errors.

Evaluation of a Composite Flooding Formula Used to Enhance the Oil Recovery of Ansai Oil Field

2020 ◽  
Vol 984 ◽  
pp. 183-188
Author(s):  
Rong Jun Zhang ◽  
Xiao Ke Wang ◽  
Jin Lin Zhao ◽  
Zheng Peng Zhou ◽  
Gang Chen
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Comprehensive Evaluation ◽  
High Surface ◽  
Evaluation Criteria ◽  
Oil Field ◽  
Chemical Flooding ◽  
Surfactant Flooding ◽  
Technical Requirements ◽  
Viscoelastic Surfactant

The composite flooding formula utilizes the characteristics of polymer flooding and surfactant flooding to compensate for the shortage of single component chemical flooding, reduce the oil-water interfacial tension to a certain extent, and broaden the maintenance range of low interfacial tension. The combined effects and synergies in the oil displacement process enhance oil recovery and allow it to adapt to a wider range of reservoir conditions. In this paper, the high surface active polymer-surfactant flooding formula suitable for the Chang 6 reservoir in Ansai Oilfield was evaluated. The general technical index of the viscoelastic surfactant fracturing fluid and the composite flooding surfactant were evaluated. The technical requirements are evaluation criteria, and comprehensive evaluation is made from several aspects such as salt tolerance, interfacial tension and emulsifying properties.

Hysteresis in Flow in Porous Media With Phase Transitions

1999 ◽  
Author(s):  
Pavel Bedrikovetsky ◽  
Dan Marchesin ◽  
Paulo Roberto Ballin
Keyword(s):  
Porous Media ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Initial Boundary ◽  
Oil Reservoirs ◽  
Flow In Porous Media ◽  
Fractional Flow ◽  
Two Phase ◽  
Initial Boundary Problem ◽  
Gas Drive

Abstract Two-phase flow with hysteresis in porous media is described by the Buckley-Leverett model with three types of fractional flow functions: imbibition, drainage and scanning. The mathematical theory for the Riemann problem and for non-self-similar initial-boundary problem is developed. The structure of the solutions is presented and the physical interpretation of the phenomena is discussed. We obtain the analytical solution for the injection of water slug with gas drive into oil reservoirs. The solutions show that the effect of hysteresis is to decrease gas flux (in the case where the drainage relative permeability lies below the imbibition relative permeability). This effect increases oil recovery for Water-Alternate-Gas injection in oil reservoirs.

Numerical Simulations of Surfactant Flooding in Carbonate Reservoirs: The Impact of Geological Heterogeneities Across Scales

2021 ◽  
Author(s):  
Jackson Pola ◽  
Sebastian Geiger ◽  
Eric Mackay ◽  
Christine Maier ◽  
Ali Al-Rudaini
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Spontaneous Imbibition ◽  
Numerical Dispersion ◽  
Surfactant Flooding ◽  
Production Forecast ◽  
Geological Heterogeneity ◽  
Grid Coarsening ◽  
The Impact ◽  
The Way

Abstract We demonstrate how geological heterogeneity impacts the effectiveness of surfactant-based enhanced oil recovery (EOR) at larger (inter-well and sector) scales when upscaling small (core) scale heterogeneity and physicochemical processes. We used two experimental datasets of surfactant-based EOR where spontaneous imbibition and viscous displacement, respectively dominate recovery. We built 3D core-scale simulation models to match the data and parameterize surfactant models. The results were deployed in high-resolution models that preserve the complexity and heterogeneity of carbonate formations in the inter-well and sector scale. These larger-scale models were based on two outcrop analogues from France and Morroco, respectively, which capture the reservoir architectures inherent to the productive carbonate reservoir systems in the Middle East. We then assessed and quantified the error in production forecast that arises due to upscaling, upgridding, and simplification of geological heterogeneity. Simulation results showed a broad range of recovery predictions. The variability arises from the choice of surfactant model parameterization (i.e., spontaneous imbibition vs viscous displacement) and the way the heterogeneity in the inter-well and sector models was upscaled and simplified. We found that the parameterization of surfactant models has a significant impact on recovery predictions. Oil recovery at the larger scale was observed to be higher when using the parametrization derived from viscous displacement experiments compared to parameterization from spontaneous imbibition experiments. This observation clearly demonstrated how core-scale processes impact recovery predictions at the larger scales. Also, the variability in recovery prediction due to the choice of surfactant model was as large as the variability arising from upscaling and upgridding. Upscaled and upgridded models overestimated recovery because of the simplified geology. Grid coarsening exacerbated this effect because of the increased numerical dispersion. These results emphasize the need to use correctly configured surfactant models, appropriate grid resolution that minimizes numerical dispersion, and properly upscaled reservoir models to accurately forecast surfactant floods. Our findings present new insights into how the uncertainty in production forecasts during surfactant flooding depends on the way surfactant models are parameterized, how the reservoir geology is upscaled, and how numerical dispersion is impacted by grid coarsening.

A Chemical Flooding Compositional Simulator

1978 ◽  
Vol 18 (05) ◽  
pp. 339-354 ◽  
Author(s):  
G.A. Pope ◽  
R.C. Nelson
Keyword(s):  
Interfacial Tension ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Polymer Concentration ◽  
Relative Merit ◽  
Chemical Flooding ◽  
Process Variables ◽  
Fractional Flow ◽  
One Dimensional ◽  
Complex Interactions

Abstract A one-dimensional, compositional, chemical-flood simulator was developed to calculate oil recovery as a function of several major process variables. The principal relationships included are phase behavior and interfacial tensions as a function of electrolyte and surfactant concentrations, and polymer viscosity as a function of electrolyte and polymer viscosity as a function of electrolyte and polymer concentration. Emphasis was on studying the polymer concentration. Emphasis was on studying the process itself, especially complex interactions that process itself, especially complex interactions that occur because of two- and three-phase behavior, interfacial tension, fractional flow, dispersion, adsorption, cation exchange, chemical slug size, and polymer transport. Introduction Nelson and Pope reported laboratory flow results in which phase behavior plays a key role in oil recovery by chemical flooding. They show that many characteristics of chemical floods can be explained by considering the equilibrium mixing and transport of surfactant/brine/oil systems in light of phase behavior observed in external mixtures. phase behavior observed in external mixtures. Although based on highly idealized representations of the key properties involved, we believe that the simulator described here can yield significant insight into phase-related process mechanisms, such as "oil swelling," the interactions among process variables, and the relative merit of various process variables, and the relative merit of various chemical flooding strategies. The framework for systematically improving the compositional aspects of numerical simulation of chemical flooding is evident with our approach. This is because a completely compositional model based on total concentrations, rather than saturations, is assumed from the start. Then, the calculation of phase concentrations, and from them phase saturations, for any desired number of phase saturations, for any desired number of components and phases with any type phase behavior is a relatively simple matter. Conceptually, mathematically, and numerically, this approach is simpler and easier to use than the traditional approach used in reservoir engineering simulation, although in principle they can be made equivalent. The cases illustrated here are for up to six components and up to three phases, using highly simplified representations of the binodal and distribution curves for the surfactant/brine/oil systems and the properties of the various phases that form. Even so, as many as 64 parameters are required to specify the process. ASSUMPTIONS, EQUATIONS, AND NUMERICAL TECHNIQUE The basic assumptions of the model are as follow.The system is one-dimensional and homogeneous in permeability and porosity.Local thermodynamic equilibrium exists everywhere.The total mixture volume does not change when mixing individual components (delta VM = 0).Gravity and capillary pressure are negligible.Fluid properties are a function of composition only.Darcy's law applies.Physical dispersion can be approximated adequately with numerical dispersion by selecting the appropriate grid size and time step. Additional assumptions are required to model various properties such as interfacial tension, viscosity, etc. However, for the most part, these are changed readily by the user and are not considered as basic as the above assumptions, which also can be relaxed, but only with considerably more effort. The auxiliary assumptions will be given, therefore, with the specific examples discussed below. Given the above assumptions, the continuity equations for each component i and np phases are (1) SPEJ P. 339

Investigation of Reduced Interfacial Tension by Surfactant Flooding in Mixed-Wet Reservoirs

2021 ◽  
Author(s):  
Usman Aslam
Keyword(s):  
Interfacial Tension ◽  
Capillary Pressure ◽  
Enhanced Oil Recovery ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Simulation Studies ◽  
Surfactant Flooding ◽  
Gravity Segregation ◽  
Simulation Results ◽  
Capillary Pressure Curves

Abstract Surfactant flooding has long been considered a reliable solution for enhanced oil recovery, either by reducing oil-water interfacial tension (IFT) or through wettability alteration. This paper reveals the effect that reduced IFT has on capillary trapping in heterogeneous reservoirs. This effect is investigated through various numerical experiments on different simulation models where rock capillary pressure is assumed to scale with IFT. Capillary contrast on the scale of a few centimeters to a few tens of meters is reduced in the presence of surfactants. This reduction in IFT, under very specific circumstances, creates favorable conditions for increased or accelerated hydrocarbon production from mixed-wet reservoirs. The focus of this study is to ascertain the effectiveness of surfactant flooding in mixed-wet reservoirs. Simulation studies of different mechanisms which are believed to occur in mixed-wet reservoirs are presented. Simulation results indicate the promising effect of surfactant flooding on oil recovery, depending on the type of reservoir. Detailed fine-scale simulation studies are carried out with representative relative permeability and imbibition capillary pressure curves from mixed-wet cores. By designing and selecting a series of surfactants to lower the IFT to the range of 10-3dynes/cm, a recovery of 10 to 20% of the original oil-in-place is technically and economically feasible. The efficiency of surfactant flooding is investigated through sensitivity scenarios on formation rock/fluid parameters, including permeability, interfacial tension, rate flow, etc. Geological heterogeneity (layering and heterogeneous inclusions), imbibition capillary pressure curves, viscous/capillary balance (Nc), and gravitational forces were all found to have an impact on recovery by surfactant flooding. Numerical model dimensions, permeability, IFT, density contrast between oil and water, and injection flow rates were found to be the critical parameters influencing simulation results. Gravity segregation, typically ignored in earlier studies, was found to have a significant effect on reservoir performance. Two different numerical models, with and without impermeable shale streaks, were used to capture the gravity segregation effect. The results revealed that the reduction in interfacial tension helps gravity to segregate oil and water, ultimately resulting in improved oil recovery. Moreover, results from the numerical simulation studies revealed that either an inexpensive or a good quality surfactant at low concentration can be used to obtain the same enhanced oil recovery. The effect of change in oil relative permeability curvature, due to reduced interfacial tension, also revealed a reduction in the remaining oil saturation with an increase in the capillary number.

The Role of Emulsification and Interfacial Tension Ift For the Enhanced Oil Recovery Eor in Surfactant Flooding

2021 ◽  
Author(s):  
Xiaoxiao Li ◽  
Xiang'an Yue ◽  
Jirui Zou ◽  
Lijuan Zhang ◽  
Kang Tang
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Flow Rate ◽  
Oil Recovery ◽  
Surfactant Flooding ◽  
Displacement Efficiency ◽  
Oil Viscosity ◽  
Oil Film ◽  
Oil Flow ◽  
Emulsifying Capacity

Abstract In this study, a visualized physical model of artificial oil film was firstly designed to investigate the oil film displacement mechanisms. Numerous comparative experiments were conducted to explore the detachment mechanisms of oil film and oil recovery performances in different fluid mediums with flow rate. In addition, the of influencing factors of oil film were comprehensively evaluated, which mainly includes: flow rate, surfactant behaviors, and crude oil viscosity. The results show that, (1) regardless of the viscosity of crude oil, flow rate presents a limited contribution to the detachment of oil film and the maximum of ultimate oil film displacement efficiency is only approximately 10%; (2) surfactant flooding has a synergistic effect on the oil film displacement on two aspects of interfacial tension (ITF) reduction and emulsifying capacity. Giving the most outstanding performance for two oil samples in all runs, IFT reduction of ultra-low value is not the only decisive factor affecting oil film displacement efficiency, but the emulsifying capability plays the key role to the detachment of oil film due to effect of emulsifying and dispersing on oil film; (3) the increasing flow rate of surfactant flooding is able to enhance the detachment of oil film but has an objective effect on the final oil film displacement efficiency; (4) flow rate have the much influence on the detachment of oil film, but the most easily controlled factor is the surfactant property. The finding provides basis for oil film detachment and surfactant selection EOR application.

Interfacial Tension Measurement of Light Oil from Thailand to Enhance Oil Recovery for Surfactant Flooding Application

2017 ◽  
Vol 890 ◽  
pp. 235-238 ◽  
Author(s):  
Chitipat Chuaicham ◽  
Kreangkrai Maneeintr
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Surfactant Concentration ◽  
High Salinity ◽  
Surfactant Flooding ◽  
Sodium Dodecylbenzenesulfonate ◽  
The North ◽  
Light Oil ◽  
Enhance Oil Recovery

To enhance oil recovery, surfactant flooding is one of the techniques used to reduce the interfacial tension (IFT) between displacing and displaced phases in order to maximize productivity. Due to high salinity of crude oil in the North of Thailand, surfactant flooding is a suitable choice to perform enhanced oil recovery. The objective of this work is to measure the IFT and observe the effects of parameters such as pressure, temperature, concentration and salinity on IFT reduction. In this study, sodium dodecylbenzenesulfonate is used as surfactant to reduce IFT. The results show that the major factor affecting reduction of IFT is surfactant concentration accounting for 98.1%. IFT reduces with the increase of salinity up to 86.3% and up to 9.6% for temperature. However, pressure has less effect on IFT reduction. The results of this work can apply to increase oil production in the oilfield in the North of Thailand.

Tertiary Surfactant Flooding: Petroleum Sulfonate Composition-Efficacy Studies

1973 ◽  
Vol 13 (04) ◽  
pp. 191-199 ◽  
Author(s):  
Walter W. Gale ◽  
Erik I. Sandvik
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Weight Distribution ◽  
Capillary Rise ◽  
Equivalent Weight ◽  
Residual Oil ◽  
Surfactant Flooding ◽  
Petroleum Sulfonate ◽  
Low Interfacial Tension ◽  
Oil Water

Abstract This paper discusses results of a laboratory program undertaken to define optimum petroleum program undertaken to define optimum petroleum sulfonates for use in surfactant flooding. Many refinery feedstocks, varying in molecular weight and aromatic content, were sulfonated using different processes, Resulting sulfonates were evaluated by measuring interracial tensions, adsorption-fractionation behavior, brine compatability, and oil recovery characteristics, as well as by estimating potential manufacturing costs. The best combination o[ these properties is achieved when highly aromatic feedstocks are sulfonated to yield surfactants having very broad equivalent weight distributions. Components of the high end of the equivalent weight distribution make an essential contribution to interfacial tension depression. This portion is also strongly adsorbed on mineral surfaces and has low water solubility. Middle Portions of the equivalent weight distribution serve as sacrificial adsorbates while lower equivalent weight components Junction as micellar solubilizers for heavy constituents. Results from linear laboratory oil-recovery tests demonstrate interactions of various portions of the equivalent weight distribution. portions of the equivalent weight distribution Introduction Four major criteria used in selecting a surfactant for a tertiary oil-recovery process are:low oil-water interfacial tension,low adsorption,compatibility with reservoir fluids andlow cost. Low interfacial tension reduces capillary forces trapping residual oil in porous media allowing the oil to be recovered. Attraction of surfactant to oil-water interfaces permits reduction of interfacial tension; however, attraction to rock-water interfaces can result in loss of surfactant to rock surfaces by adsorption. Surfactant losses can also arise from precipitation due to incompatibility with reservoir fluids. Low adsorption and low cost are primarily economic considerations, whereas low interfacial tension and compatibility are necessary for workability of the process itself. Petroleum sulfonates useful in surfactant flooding have been disclosed in several patents; however, virtually no detailed information is available in the nonpatent technical literature. Laboratory evaluation of surfactants consisted of determining their adsorption, interfacial tension, and oil recovery properties. Adsorption measurements were made by static equilibration of surfactant solutions with crushed rock and clays and by flowing surfactant solutions through various types of cores. Interfacial tensions were measured using pendant drop and capillary rise techniques. Berea, pendant drop and capillary rise techniques. Berea, Bartlesville, and in some cases, field cores containing brine and residual oil were flooded with sulfonate solutions in order to determine oil recovery. Fluids used in these displacement tests are described in Table 1. Unless otherwise specified, displacements of Borregos crude oil were carried out with Catahoula water as the resident aqueous phase after waterflooding and displacements of phase after waterflooding and displacements of Loudon crude oil with 1.5 percent NaCl as the resident aqueous phase. In those examples where banks of surfactants were injected, drive water following the surfactant had the same composition as the resident water. Concentrations of sulfonates are reported on a 100-percent activity basis. PETROLEUM SULFONATE CHEMISTRY PETROLEUM SULFONATE CHEMISTRY A substantial portion of the total research effort TABLE 1 - PROPERTIES OF FLUIDS USEDIN FLOODING TESTS

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