Frontal-Stability Analysis of Surfactant Floods

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 471-482 ◽  
Author(s):  
Shayan Tavassoli ◽  
Gary A. Pope ◽  
Kamy Sepehrnoori
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Mobility Control ◽  
Surfactant Flooding ◽  
Control Cost ◽  
Fine Grid ◽  
Heterogeneous Reservoirs ◽  
Vertical Permeability ◽  
Reservoir Conditions ◽  
The Stability

Summary Recent surfactant-flooding experiments have shown that very-efficient oil recovery can be obtained without mobility control when the surfactant solution is injected at less than the critical velocity required for a gravity-stable displacement. The purpose of this study was to develop a method to predict the stability of surfactant floods at the reservoir scale on the basis of gravity-stable surfactant-flooding experiments at the laboratory scale. The scaleup process involves calculation of the appropriate average frontal velocity for the reservoir flood. The frontal velocity depends on the well configuration. We have performed systematic numerical simulations to study the effect of key scaling groups on the performance of gravity-stable surfactant floods. We simulated 3D heterogeneous reservoirs by use of a fine grid and a third-order finite-difference method to ensure numerical accuracy. These simulations have provided new insight into the behavior of gravity-stable surfactant floods, and in particular the importance of the microemulsion properties. The capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. When a surfactant flood can be performed without polymer (or foam) for mobility control, cost and complexity are significantly reduced. Advantages are especially significant when the reservoir temperature is high and the use of polymer becomes increasingly difficult. Our simulations show that gravity-stable surfactant floods can be very efficient using horizontal wells in reservoirs with high vertical permeability.

scholarly journals Concentration, Brine Salinity and Temperature effects on Xanthan Gum Solutions Rheology

2019 ◽  
Vol 29 (1) ◽  
pp. 69-79 ◽  
Author(s):  
Mateus Ribeiro Veiga de Moura ◽  
Rosângela Barros Zanoni Lopes Moreno
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Rheological Behavior ◽  
Xanthan Gum ◽  
Salt Content ◽  
Petroleum Industry ◽  
Mobility Control ◽  
Solution Viscosity ◽  
Heterogeneous Reservoirs ◽  
Reservoir Conditions

AbstractXanthan gum is a biopolymer used in several different industries for a variety of applications. In the Petroleum Industry, xanthan gum has been applied in Enhanced Oil Recovery (EOR) methods for mobility control due to its Non-Newtonian rheological behavior, relative insensitivity to salinity and temperature compared to other conventional synthetic polymers, as well as its environmentally-friendly characteristics. As challenging reservoir conditions arise, candidate polymers should meet the screening factors for high salinity, high temperatures and heterogeneous reservoirs. This paper aims to evaluate the effects of temperature and monovalent salts on the rheological behavior of xanthan gum for Enhanced Oil Recovery purposes. We tested polymer solutions with brine salinities of 20,000/110,000/220,000 ppm of Sodium Chloride in a rheometer at temperatures of 23, 50, and 77°C. The results acquired showed that temperature plays a key role in viscosity and salinity protected the solution viscosity against negative thermal effects, unusually a turning point is observed where the increase in the monovalent salt content enhanced the polymeric solution viscosity. Such investigations coupled with a detailed discussion presented in the paper contribute to understand critical aspects of xanthan gum and its capability to provide basic requirements that fit desired screening factors for EOR.

scholarly journals Study on the Influencing Factors of the Emulsion Stability of a Polymeric Surfactant Based on a New Emulsification Device

Energies ◽  
2020 ◽  
Vol 13 (18) ◽  
pp. 4794
Author(s):  
Yusen Wei ◽  
Youming Xiong ◽  
Bumin Guo ◽  
Hongbin Yang
Keyword(s):  
Influencing Factors ◽  
Oil Recovery ◽  
High Speed ◽  
Emulsion Stability ◽  
Surfactant Solution ◽  
Polymeric Surfactant ◽  
Sieve Plate ◽  
Surfactant Flooding ◽  
New Device ◽  
The Stability

Polymeric surfactant flooding is an effective method to improve oil recovery, and the stability of the emulsion is closely related to the effect of surfactant flooding. The preparation method for a surfactant-stabilized emulsion is relatively simple, and the emulsion produced by the existing device cannot simulate the real formation conditions. To better simulate the emulsification of polymeric surfactant during formation and to study the influencing factors of emulsion stability, a new sieve plate rotary emulsification device was used to prepare emulsions instead of the traditional high-speed shear emulsifier, and the stability of emulsions prepared by different methods was compared. The parameters of the device were optimized by determining the water content, particle size, and Turbiscan Stability Index TSI (stability parameter) of the emulsion. The factors affecting the stability of the emulsion were studied by using the optimized experimental device. The results showed that the optimized parameters of the sieve plate rotary emulsification device were 5 sieve plates, diameter of 1 mm, and emulsification time of 60 min. The stability of the emulsion prepared by the new device was better than that of the emulsion prepared by the traditional high-speed stirrer, which can be attributed to the more abundant contact and mix of oil and surfactant solution. Meanwhile, as the polymeric surfactant concentration, salinity, and water–oil ratio increased, the stability of the polymeric surfactant emulsion increased. The results of this study provide a theoretical basis and guidance for better simulation of polymeric surfactant migration and emulsification during formation.

Investigation and Optimization of the Effects of Geologic Parameters on the Performance of Gravity-Stable Surfactant Floods

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 761-775 ◽  
Author(s):  
Shayan Tavassoli ◽  
Gary A. Pope ◽  
Kamy Sepehrnoori
Keyword(s):  
Salinity Gradient ◽  
Horizontal Wells ◽  
Sensitivity Study ◽  
Third Order ◽  
Fine Grid ◽  
Heterogeneous Reservoirs ◽  
Vertical Permeability ◽  
Well Spacing ◽  
Optimization Schemes ◽  
Very High

Summary A systematic simulation study of gravity-stable surfactant flooding was performed to understand the conditions under which it is practical and to optimize its performance. Different optimization schemes were introduced to minimize the effects of geologic parameters and to improve the performance and the economics of surfactant floods. The simulations were carried out by use of horizontal wells in heterogeneous reservoirs. The results show that one can perform gravity-stable surfactant floods at a reasonable velocity and with very-high sweep efficiencies for reservoirs with high vertical permeability. These simulations were carried out with a 3D fine grid and a third-order finite-difference method to accurately model fingering. A sensitivity study was conducted to investigate the effects of heterogeneity and well spacing. The simulations were performed with realistic surfactant properties on the basis of laboratory experiments. The critical velocity for a stable surfactant flood is a function of the microemulsion (ME) viscosity, and it turns out there is an optimum value that one can use to significantly increase the velocity and still be stable. One can optimize the salinity gradient to gradually change the ME viscosity. Another alternative is to inject a low-concentration polymer drive following the surfactant slug (without polymer). Polymer complicates the process and adds to its cost without a significant benefit in most gravity-stable surfactant floods, but an exception is when the reservoir is highly layered. The effect of an aquifer on gravity-stable surfactant floods was also investigated, and strategies were developed for minimizing its effect on the process.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SPE Journal ◽  
1900 ◽  
Vol 25 (02) ◽  
pp. 867-882
Author(s):  
Pengfei Dong ◽  
Maura Puerto ◽  
Guoqing Jian ◽  
Kun Ma ◽  
Khalid Mateen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Mineral Dissolution ◽  
Mobility Control ◽  
Matrix Permeability ◽  
Geochemical Properties ◽  
Remaining Oil ◽  
The Matrix ◽  
Incremental Oil Recovery ◽  
Foam Flooding

Summary The high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions. The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments. Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone. Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

Low-IFT Foaming System for Enhanced Oil Recovery in Highly Heterogeneous/Fractured Oil-Wet Carbonate Reservoirs

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2243-2259 ◽  
Author(s):  
Pengfei Dong ◽  
Maura Puerto ◽  
Guoqing Jian ◽  
Kun Ma ◽  
Khalid Mateen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Surfactant Solution ◽  
Capillary Forces ◽  
Mobility Control ◽  
Carbonate Reservoirs ◽  
Residual Oil ◽  
High Permeability ◽  
The Matrix ◽  
Foam Flooding

Summary Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding. A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10−2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.

scholarly journals Analysis of a model for foam improved oil recovery

2014 ◽  
Vol 751 ◽  
pp. 346-405 ◽  
Author(s):  
P. Grassia ◽  
E. Mas-Hernández ◽  
N. Shokri ◽  
S. J. Cox ◽  
G. Mishuris ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Numerical Schemes ◽  
Improved Oil Recovery ◽  
Heterogeneous Reservoirs ◽  
Long Time ◽  
Porous Reservoir ◽  
Tension Term ◽  
Sharp Corners ◽  
Pressure Driven

AbstractDuring improved oil recovery (IOR), gas may be introduced into a porous reservoir filled with surfactant solution in order to form foam. A model for the evolution of the resulting foam front known as ‘pressure-driven growth’ is analysed. An asymptotic solution of this model for long times is derived that shows that foam can propagate indefinitely into the reservoir without gravity override. Moreover, ‘pressure-driven growth’ is shown to correspond to a special case of the more general ‘viscous froth’ model. In particular, it is a singular limit of the viscous froth, corresponding to the elimination of a surface tension term, permitting sharp corners and kinks in the predicted shape of the front. Sharp corners tend to develop from concave regions of the front. The principal solution of interest has a convex front, however, so that although this solution itself has no sharp corners (except for some kinks that develop spuriously owing to errors in a numerical scheme), it is found nevertheless to exhibit milder singularities in front curvature, as the long-time asymptotic analytical solution makes clear. Numerical schemes for the evolving front shape which perform robustly (avoiding the development of spurious kinks) are also developed. Generalisations of this solution to geologically heterogeneous reservoirs should exhibit concavities and/or sharp corner singularities as an inherent part of their evolution: propagation of fronts containing such ‘inherent’ singularities can be readily incorporated into these numerical schemes.

Foam Diversion in Heterogeneous Reservoirs: Effect of Permeability and Injection Method

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1402-1415 ◽  
Author(s):  
A. H. Al Ayesh ◽  
R.. Salazar ◽  
R.. Farajzadeh ◽  
S.. Vincent-Bonnieu ◽  
W. R. Rossen
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Gas Injection ◽  
Surfactant Solution ◽  
Model Parameters ◽  
High Permeability ◽  
Fractional Flow ◽  
Injection Method ◽  
Heterogeneous Reservoirs ◽  
Irreducible Water Saturation

Summary Foam can divert flow from higher- to lower-permeability layers and thereby improve the injection profile in gas-injection enhanced oil recovery (EOR). This paper compares two methods of foam injection, surfactant-alternating-gas (SAG) and coinjection of gas and surfactant solution, in their abilities to improve injection profiles in heterogeneous reservoirs. We examine the effects of these two injection methods on diversion by use of fractional-flow modeling. The foam-model parameters for four sandstone formations ranging in permeability from 6 to 1,900 md presented by Kapetas et al. (2015) are used to represent a hypothetical reservoir containing four noncommunicating layers. Permeability affects both the mobility reduction of wet foam in the low-quality-foam regime and the limiting capillary pressure at which foam collapses. The effectiveness of diversion varies greatly with the injection method. In a SAG process, diversion of the first slug of gas depends on foam behavior at very-high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. (2015). Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This favors diversion away from high-permeability layers that receive a large surfactant slug. However, there is an optimum surfactant-slug size: Too little surfactant and diversion from high-permeability layers is not effective, whereas with too much, mobility is reduced in low-permeability layers. For a SAG process, injectivity and diversion depend critically on whether foam collapses completely at irreducible water saturation. In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with injection time. Injectivity is extremely poor with foam injection for these extremely strong foams, but for some SAG foam processes with effective diversion it is better than injectivity in a waterflood.

Investigation of the Critical Velocity Required for a Gravity-Stable Surfactant Flood

SPE Journal ◽  
2014 ◽  
Vol 19 (05) ◽  
pp. 931-942 ◽  
Author(s):  
Shayan Tavassoli ◽  
Jun Lu ◽  
Gary A. Pope ◽  
Kamy Sepehrnoori
Keyword(s):  
Numerical Simulations ◽  
Critical Velocity ◽  
Oil Recovery ◽  
Horizontal Wells ◽  
Mobility Control ◽  
Oil Reservoirs ◽  
Three Dimensions ◽  
Analytical Models ◽  
Oil Viscosity ◽  
Fine Grid

Summary Classical stability theory predicts the critical velocity for a miscible fluid to be stabilized by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension (IFT) and was found to be optimistic compared with both laboratory displacement experiments and fine-grid simulations. The inaccurate prediction of instabilities on the basis of available analytical models is because of the complex physics of surfactant floods. First, we simulated vertical sandpack experiments to validate the numerical model. Then, we performed systematic numerical simulations in two and three dimensions to predict formation of instabilities in surfactant floods and to determine the velocity required to prevent instabilities by taking advantage of buoyancy. The 3D numerical grid was refined until the numerical results converged. A third-order total-variation-diminishing (TVD) finite-difference method was used for these simulations. We investigated the effects of dispersion, heterogeneity, oil viscosity, relative permeability, and microemulsion viscosity. These results indicate that it is possible to design a very efficient surfactant flood without any mobility control if the surfactant solution is injected at a low velocity in horizontal wells at the bottom of the geological zone and the oil is captured in horizontal wells at the top of the zone. This approach is practical only if the vertical permeability of the geological zone is high. These experiments and simulations have provided new insight into how a gravity-stable, low-tension displacement behaves and in particular the importance of the microemulsion phase and its properties, especially its viscosity. Numerical simulations show high oil-recovery efficiencies on the order of 60% of waterflood residual oil saturation (ROS) for gravity-stable surfactant floods by use of horizontal wells. Thus, under favorable reservoir conditions, gravity-stable surfactant floods are very attractive alternatives to surfactant/polymer floods. Some of the world's largest oil reservoirs are deep, high-temperature, high-permeability, light-oil reservoirs, and thus candidates for gravity-stable surfactant floods.

Carbon Dots Stabilized Foam for Enhanced Oil Recovery

2021 ◽  
Author(s):  
Sivabalan Sakthivel ◽  
Mazen Kanj
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
High Salinity ◽  
Foam Stability ◽  
Surfactant Solution ◽  
Oil And Gas Industry ◽  
Mobility Control ◽  
Carbon Nanodots ◽  
High Permeability ◽  
Drainage Rate

Abstract Foams are the divergent fluids that are employed in the upstream oil and gas industry to reduce fluid channeling and fingering in the high permeability region. Foams are usually generated in the high permeability reservoirs (e.g. glass beads) by the alternative injection of surfactant and gas. Conventional foaming systems exhibit stability issues at the high temperature and high salinity reservoir conditions. In this investigation, we study the stability and efficiency (in terms of both enhanced inflow performance and added oil recovery) of foams formed using surfactant solution with and without carbon Nanodots (CND). The study involved using different brine salinities, CND concentrations, temperature and pressure conditions, and types of surfactants. A multifaceted interrelationship of the various influencing mechanisms is demonstrated. Foams are examined using foam analyzer, HP/HT coreflood and microfluidic setup. In trace amounts (5-10 ppm), CND contributed to 60-70% improvement in foam stability in high salinity brine. The improvement is attributed by the reduction of the drainage rate of the lamellae and a delay of the bubble rupturing point. Both microfluidic and core-flood experiments showed noticeable improvement in mobility control with the addition of the CND. This is contributed to an improved foamability, morphology, strength, and stability of the foam.

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