bluuebunny/crossref_metadata_2025_split huggingface dataset:
Surfactant Flooding in Heterogeneous Formations
Authors: Lohne Arild , Fjelde Ingebret 
Published: April 2012

Abstract
The potential for surfactant flooding of oil fields can be obtained using field-scale surfactant simulation model with capillary number (Nc) dependent relative permeability, kr. Typically, kr(Nc) is solely based on core flood experiments. In this paper, surfactant recovery mechanisms in presence of heterogeneities smaller than the field simulation grid block are investigated. Effects of reducing the interfacial tension, IFT, are investigated in various models by numerical simulation of the displacement process and by steady-state upscaling. It is demonstrated that measured core-scale results should go through appropriate averaging before they are used in a field-scale surfactant model.
Macro-scale effects of IFT in presence of small-scale heterogeneities are examined separately. Capillary trapping of oil in heterogeneous formations depends on the geometric distribution of permeability and wettability and on IFT. In general, reduced IFT has little or possibly negative effect on production from water-wet, low-permeability inclusions embedded in a mixed-wet background. Production from mixed-wet, low-permeability inclusions will in general be increased at reduced IFT.
The IFT level needed to mobilize capillary trapped oil is proportional to the heterogeneity scale. At normal field flow rates, it was found that oil recovery was sensitive to variation in IFT at scales less than approximately 10 m. IFT reduction down to 1 mN/m was found sufficient for heterogeneities of length scale 10 cm. It is shown that the effect of capillary trapping in heterogeneous formations can be represented as Nc-dependent relative permeability function at the larger scale and that the larger-scale functions can be obtained from rate dependent steady-state upscaling. The macro-scale effects described here comes in addition to the measured core-scale effects, and may increase the potential for surfactant flooding.
Assessment of CO2-Soluble Surfactants for Mobility Reduction using Mobility Measurements and CT Imaging
Authors: McLendon W. J. , Koronaios P. , McNulty S. , Enick R. M. , Biesmans G. , Miller A. , Salazar L. , Soong Y. , Romanov V. , Crandall D. 
Published: April 2012

Abstract
The addition of CO2-soluble, brine-soluble, surfactants to the high pressure CO2 may facilitate the in-situ generation of CO2-in-brine foams for conformance and/or mobility control. Most of these non-ionic surfactants dissolve in CO2 to concentrations of roughly 0.05–0.10wt% at CO2 EOR conditions and stabilize CO2-in-brine foams in high pressure windowed cells. Huntsman SURFONIC® N series surfactants, branched nonylphenol ethoxylates, containing an average of 12 (N-120) or 15 (N-150) ethylene oxide repeat units were selected for mobility and CT studies detailed in this paper.
Transient mobility measurements were conducted using a water-wet Berea core (104 mD), a water-wet Bentheimer sandstone core (∼1500 mD), and several mixed wettability SACROC carbonate cores (3.6 and 8.9 mD). The CO2 was injected into a brine-saturated core at a superficial velocity of 10 ft/day, and the surfactant was either not used, dissolved only in the brine at 0.06wt%, dissolved only in the CO2 at 0.06wt%, or dissolved in both the brine and the CO2 at 0.06wt. Regardless of what phase the surfactant was dissolved in, in-situ foam generation in the relatively high permeability sandstone was evidenced by total pressure drop values that were 2–3 times greater than the test with no surfactant. The mobility reduction was more modest (20–50% increases in pressure drop) in the lower permeability SACROC cores (3.6 and 8.9 mD) when the surfactant was dissolved in the CO2. When the surfactant was dissolved in the brine, the pressure drops increased by a factor of 1.5–3 for the 8.9 mD core.
CT scanning of in-situ foam generation was then conducted by injecting high pressure CO2 into a 5wt% KI brine-saturated water-wet Berea sandstone (3–8 mD). Tests were done with no surfactant or with the surfactant dissolved either in the brine at 0.03wt% or in the CO2 at 0.06wt%. At a low and high superficial velocity values of 0.47 ft/day and 4.7 ft/day, in-situ foam generation occurred when surfactant was dissolved in the brine or the CO2, but the core was swept more effectively by the foam generated with the surfactant present in the brine.
Surfactant Optimization for EOR Using Advanced Chemical Computational Methods
Authors: Buijse Marten , Tandon Kunj , Jain Shekhar , Handgraaf Jan-Willem , Fraaije Johannes G. 
Published: April 2012

Abstract
Surfactant EOR is an attractive method to recover the residual oil left behind in the reservoir after water flooding. The formulation of an effective surfactant system is a relatively complex and often time consuming process because the surfactant activity depends on the crude oil composition and the surfactant system must therefore be tailored to the oil. In practice many surfactant (and solvent) combinations need to be tested in the laboratory to optimize the performance.
An alternative approach, which is the focus in this paper, is to start with the molecular structure of surfactant and oil and apply Molecular Modeling techniques to optimize the surfactant system. The dissipative particle dynamics (DPD) method, used in the simulations discussed in this paper is a relatively new coarse-grained (meso-scale) method especially suited to study phase behavior in multiple phase systems such as surfactant/oil/brine. The paper will discuss the basic DPD features and results of DPD calculations of surfactants at the oil/brine interface.
To simulate the microemulsion structure on molecular level it is necessary to have a physical model of the surfactant interfacial film. The first part of the paper will review the relevant microemulsion physics, in particular the bending properties of the interfacial film that determine the magnitude of the (experimentally observed) interfacial tension.
To efficiently calculate microemulsion properties such as optimum salinity, a new method, called Method of Moments, was developed and implemented on DPD level. In this method a section of the surfactant/oil/brine interface is simulated to calculate the (lateral) stress profile and its moments. Computationally the method is relatively fast and it is flexible and can handle mixtures of surfactants/solvents, complex oils, etc. Results of calculations will be discussed in the paper.
Four-Phase Equilibrium Calculations of CO2/Hydrocarbon/Water Systems Using a Reduced Method
Authors: Mohebbinia Saeedeh , Sepehrnoori Kamy , Johns Russell T. 
Published: April 2012

Abstract
Three hydrocarbon phases can co-exist at equilibrium at relatively low temperatures in many CO2 floods. Formation of an aqueous phase in contact with hydrocarbon phases is inevitable in almost all recovery processes, because of the permanent presence of water in the reservoirs either as injection fluid or as initial formation water. Successful modeling of CO2 flooding requires accounting for the presence of four phases. However, as the number of phases increase, flash calculations become more difficult and time-consuming. A possible approach to reduce the computational time of the phase equilibrium calculations is to use reduced methods. This paper presents a general strategy to model the behavior of CO2/hydrocarbon/water systems where four equilibrium phases occur using a reduced flash approach. The speedup obtained by a reduced flash algorithm compared to the conventional flash approach is demonstrated for a different number of components and phases. The results show a significant speedup in the Jacobian matrix construction and in Newton-Raphson iterations using the reduced method when four phases are present. The computational advantage of the reduced method increases rapidly with the number of phases and components. The developed four-phase reduced flash algorithm is used to investigate the effect of introducing water on the phase behavior of two West Texas oil/CO2 mixtures. The results show significant changes in the phase splits and saturation pressures by adding water to these CO2/hydrocarbon systems.
Ethoxylated Cationic Surfactants for CO2 EOR in High Temperature, High Salinity Reservoirs
Authors: Chen Yunshen , Elhag Amro S. , Poon Benjamin M. , Cui Leyu , Ma Kun , Liao Sonia Y. , Omar Amr , Worthen Andrew J. , Hirasaki George J. , Nguyen Quoc P. , Johnston Keith P. 
Published: April 2012

Abstract
Despite significant interest in CO2 foams for EOR, very few studies have reported stable foams at high temperatures and high salinities, which are often encountered in the Middle East and elsewhere. Stable CO2/water (C/W) foams at high temperatures up to 120 °C and salinities have been achieved with ethoxylated cationic surfactants. The surfactants were shown to stabilize C/W foams with high salinity brine with NaCl concentration up to 182 g/L at 120 °C, 3400 psia, and to form unstable dodecane/water emulsions with the 120 g/L NaCl brine solutions. Thus, the foams have the potential to provide mobility control to prevent loses of CO2 in high permeability regions, but simultaneously allow high permeability in the presence of residual oil. The surfactants are soluble in CO2 and thus may be injected in the CO2 phase to simplify the EOR process. The aqueous solubility of the surfactant at high temperatures is enhanced with the appropriate number of EO groups on the amine head group. Viscosities of high-pressure C/W foams (emulsions) formed with these surfactants were investigated by capillary rheology. These hybrid cationic/nonionic surfactants combine the high cloud points of ionic surfactants with high solubilities in CO2 of nonionic surfactants. Furthermore, the variation of the tail length and the degree of ethoxylation offer great flexibility for stabilizing CO2 foams for EOR at high temperatures and high salinities. Ethoxylated cocoamine exhibited lower adsorption on calcite than that on dolomite, given the presence of silica sites in the latter. High divalent ion concentrations in 22% total dissolved solids (TDS) brine contributed to the reduction of surfactant adsorption on silica sites in the dolomite powder.
Generation of Nanoparticle-Stabilized Emulsions in Fractures
Authors: Roberts M. R. , Aminzadeh B. , DiCarlo D. A. , Bryant S. L. , Huh C. 
Published: April 2012

Abstract
We investigated the ability of a dispersion of specially surface-treated nanoparticles to stabilize an oil/water emulsion of prescribed internal structure created by flow within a fracture. We hypothesize that for a set of conditions (nanoparticle concentration, salinity, aqueous to organic phase ratio) a critical shear rate exists. That is, for flow rates that exceed this critical shear rate, an emulsion can be created.
Flow experiments were conducted within fractured cylinders of Boise sandstone and of Class H cement. The Boise sandstone core (D = 1 in and L = 12 in) was cut down its length and propped open to a specific aperture with beads. The fracture was saturated with dodecane which was displaced with nanoparticle dispersion, and vice versa while pressure drop across the fracture was recorded. Class H cement cylinders (D = 1 in and L = 3 in) were allowed to set, then failed in tension to create a rough-walled fracture along their length. These fractured cement cylinders were then sealed and encased in epoxy to isolate the fractures. CT scans of the encased fractures were used to determine the aperture width, which is utilized when calculating the shear rate inside of the fracture maintained during an experiment. A dispersion of surface-modified silica nanoparticles and decane were co-injected into both the Boise sandstone and cement fractures and the pressure drop was measured across the fractures at a variety of shear rates. The effluent of each experiment was collected in sample tubes.
Observation of the effluent and pressure drop data both support our hypothesis of emulsion generation being possible once a critical shear rate has been reached. Alteration of the injected phase ratio and increased residence time of the two phases inside of a fracture both affect the amount of emulsification occurring within the fractures. Increasing the residence time of both phases within a fracture allows for more opportunities for emulsification to occur, resulting in a greater amount of emulsion to be generated. Injection of high or low volumetric ratios of nanoparticle dispersion to organic phase results in little amounts of emulsion generation; however, between the nanoparticle dispersion to organic phase ratios of 0.25:1 and 2:1 significant amounts of emulsion are generated once a critical shear rate has been reached.
Measurement and Analysis of Surfactant Retention
Authors: Solairaj Sriram , Britton Christopher , Kim Do Hoon , Weerasooriya Upali , Pope Gary A. 
Published: April 2012

Abstract
Surfactant retention is one of the most important variables affecting the economics of chemical flooding and varies widely depending on the surfactant structure, mineralogy, salinity, pH, Eh, microemulsion viscosity, crude oil, co-solvent and mobility control among other variables. We have done a large number of dynamic surfactant retention measurements over a wide range of conditions using a variety of new-generation surfactants to recover crude oils from both sandstone and carbonate cores. Surfactant retention values for both surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) floods were measured and correlated with pH, total acid number (TAN) of the oil, temperature, co-solvent concentration, salinity of the polymer drive, mobility ratio, and molecular weight of the surfactant. Surfactant retention values ranged from about 0.01 to 0.37 mg/g of rock. SP and ASP formulations included mixtures of anionic and nonionic surfactants with and without co-solvents. The retention of anionic surfactants of all types was found to be similar on both sandstones and carbonate rocks.
Effect of Spontaneous Formation of Nanoparticle Stabilized Emulsion on the Stability of a Displacement
Authors: Aminzadeh B. , DiCarlo D. A. , Roberts M. , Chung D. H. , Bryant S. L. , Huh C. 
Published: April 2012

Abstract
Injecting nanoparticles into the subsurface can have a potential impact on altering both oil recovery and/or CO2 sequestration. In this work we conduct core floods in which a CO2-analogue fluid (n-octane) displaces brine with and without dispersed nanoparticles. We find that the floods with nanoparticles cause a greater pressure drop, and a change in flow pattern compared to the floods without. Emulsion formation is inferred by measuring the saturation distribution and pressure drop along the core. The results suggest that nanoparticle stabilized emulsion is formed during a drainage process (at low shear rate condition) which acts to reduce the mobility of the injected fluid.
We also perform imbibition experiments, where the nanoparticle dispersion in brine displaces n-octane. Here we observe little difference in the flow pattern and pressure drop as a function of nanoparticle concentration. There is an observed accumulation of nanoparticles at the imbibition front, which suggests that nanoparticles may be used as a tracer of the displacement front.
Improved Oil Recovery by Chemical Flood from High Salinity Reservoirs
Authors: Shiau B. J. , Hsu Tzu-Ping , Wan Wei , Lin Zhixun , Roberts Bruce L. , Harwell Jeffrey H. 
Published: April 2012

Abstract
Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+, Mg2+, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 0.5 pore volumes of surfactant/polymer + 0.5 pore volumes of polymer drive, experimental results show the oil recovery ranging from 46 % to 89% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 185,000 mg/L total dissolved solids (TDS). The test is considered to be a technical success and confirms the effectiveness of the high-salinity surfactant-polymer formulation (0.4 wt% of surfactant and 1,800 ppm of polymer loading). The Sor was reduced from 25% to 7% resulting in approximately 72 % of the residual oil being mobilized. A pilot test at the same reservoir is scheduled to be performed in 2012 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
New Correlation to Predict the Optimum Surfactant Structure for EOR
Authors: Solairaj Sriram , Britton Christopher , Lu Jun , Kim Do Hoon , Weerasooriya Upali , Pope Gary A. 
Published: April 2012

Abstract
It is well known that the oil recovery efficiency of chemical EOR depends on microemulsion phase behavior and interfacial tension (IFT). The surfactants needed to obtain good phase behavior and ultra-low IFT vary greatly with oil characteristics and reservoir conditions. Hence, it is often necessary to test many surfactant formulations before finding a highly effective one. Based on both sound principles and extensive experience, one would expect to find a relationship between the optimum surfactant structure, the oil characteristics, the brine, and the temperature. Salager's equation (Salager et al., 1979, Anton et al., 2008) shows it is possible to correlate some of these variables to classical surfactant structure. We now have many new surfactants with widely different structures and many more good formulations with a wider range of oils, temperature and so forth. Thus, it becomes imperative to study the underlying trend and to identify the most important variables affecting the optimum surfactant structure. A new correlation has been developed using an extensive data set taking into account the effect of propylene oxide number (PON), ethylene oxide number (EON), temperature, brine salinity and the equivalent alkane carbon number (EACN) of the oil. The new correlation will help in identifying the most important variables and also to improve our understanding of the relationship among variables affecting optimum surfactant structure. In particular, the new equation can be used to predict the optimum carbon number of the surfactant hydrophobe. Results show that larger hydrophobes are needed as either the temperature or the equivalent alkane carbon number (EACN) of the oil increases. The surfactant formulations used for this study include mixtures of sulfate, sulfonate, carboxylate and non-ionic surfactants. This is a new and highly significant advance in the optimization of chemical EOR processes that will greatly reduce the time and cost of the effort required to develop a good formulation as well as to improve its performance.
Alkaline Surfactant Polymer Flooding using a Novel Class of Large Hydrophobe Surfactants
Authors: Liyanage Pathma J. , Solairaj Sriram , Arachchilage Gayani W , Linnemeyer Harold C , Kim Do Hoon , Weerasooriya Upali , Pope Gary A. 
Published: April 2012

Abstract
With recent advances in Alkaline-Surfactant-Polymer (ASP) flooding, the demand for high performance EOR surfactants is rapidly increasing. This is accompanied by the need for a diverse raw material base. We have successfully developed and tested a novel class of hydrophobes for anionic surfactants that satisfy this need at low cost. The hydrophobe for these novel surfactants is Tristyrylphenol (TSP), which is based on the petrochemical feed stocks, phenol and styrene. TSP based surfactants have unique structural features that can be exploited to fit many EOR surfactant needs. We illustrate the performance of this class of TSP surfactants for a waxy crude oil with a high acid number. Selecting a formulation proved difficult due to the high molecular weight of the crude. The TSP surfactant has four benzene rings that enhanced the solubility of the heavy components of the crude oil, including asphaltenes, making it an attractive choice. The dead crude oil was diluted with either decalin or cyclohexane to match the equivalent alkane carbon number (EACN) of the live crude oil. The TSP alkoxy sulfate molecules with varying lengths of propoxy (PO) and ethoxy (EO) chains were tested in microemulsion phase behavior experiments in order to obtain ultra-low IFT at optimum salinity with low microemulsion viscosities. The ASP formulation was successfully tested in reservoir core floods using both surrogate oil and live oil.
The Science of Membrane Technology to Further Enhance Oil Recovery
Authors: Henthorne Lisa , Wodehouse Jim 
Published: April 2012

Abstract
There are various membrane technologies available in the marketplace today to tailor water quality to the specific needs of an enhanced oil recovery (EOR) operation. Membrane technology has been proven and used offshore in the sulphate removal process (SRP) since DOW Filmtec and Marathon first introduced the membrane system in 1991. By the end of 2008, SRP systems were installed on over 44 offshore production facilities around the world.
The changing needs of the oil and gas industry are dictating the development of new technologies and the application of proven technology in novel ways to meet the industry demand. These new applications and technologies have the potential to impact production on a global scale. For instance, optimizing water chemistries throughout a CEOR flood by carefully choosing membrane and polishing technologies can favorably change CEOR project economics and therefore further enhance oil recovery by expanding the number of reservoirs globally in which CEOR is economically attractive.
This paper will discuss what can be achieved with today's technology and the results from recent pilot testing of RO technology adapted from brackish water applications to be used to selectively remove ions for seawater-based EOR applications.