The Effect of Live Crude on Phase Behavior and Oil-Recovery Efficiency of Surfactant Flooding Systems

1983 ◽  
Vol 23 (03) ◽  
pp. 501-510 ◽  
Author(s):  
Richard C. Nelson
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Potential Problem ◽  
Average Molecular Weight ◽  
Carbon Number ◽  
Recovery Efficiency ◽  
Surfactant Flooding ◽  
Type Iii ◽  
Stock Tank ◽  
Relative Solubility

Abstract Neither pressure alone nor pressurizing with methane affects phase behavior of a particular surfactant/ brine/stock-tank-oil system. Oil-recovery efficiency in corefloods is not significantly different whether the stock-tank oil is pressurized with methane or diluted with iso-octane to the viscosity of the live crude. In contrast, phase behavior and oil-recovery efficiency do change phase behavior and oil-recovery efficiency do change upon methane pressurization when a lower-molar-volume synthetic oil is substituted for the stock-tank oil. Some thermodynamic insight regarding the different behavior of the two oils is offered. Introduction Refs. 1 through 29 are a representative selection from the many papers published on phase behavior of surfactant flooding systems. From many of the papers in that group it is apparent that the type of microemulsion (lower, middle, or upper phase) that forms when surfactant, brine, and oil are mixed is related to the relative solubility of the surfactant in the brine and in the oil. It is apparent also that surfactant systems most active in displacing oil establish a middle phase or, more precisely, a Type III Microemulsion at some point in the precisely, a Type III Microemulsion at some point in the surfactant bank. Hence, relative solubility of the surfactant in the brine and in the oil plays an important role in surfactant flooding. For phase-behavior studies and corefloods in the laboratory, the reservoir brine usually can be duplicated easily, and the extent to which the composition of that brine will change because of ion exchange can be calculated. The oil, however, presents the following potential problem. potential problem. Although phase studies and corefloods are more convenient and more precise when conducted with stock-tank oil under atmospheric pressure, many in-place crude oils contain a substantial quantity of dissolved gas that is absent from the stock-tank oil. Hence, serious errors in formulating a surfactant-flooding system are plausible if the in-place, live crude should exhibit a plausible if the in-place, live crude should exhibit a solvency for the surfactant different from the stock-tank oil. Even the common practice of diluting the stock-tank oil with hydrocarbon solvents to approximately the viscosity of the live crude does not ensure that the diluted stock-tank oil has the same solvency as the live crude for the surfactant. Alkane Carbon Number (ACN) This concern over different solvency for the surfactant between live crude and its stock-tank oil is illustrated vividly in terms of ACN. Fig. 1 is a typical plot of interfacial tension (IFT) vs. Equivalent Alkane Carbon Number (EACN) of the oil. The figure shows that ultralow IFT for a particular surfactant/brine system at a given temperature is obtained over a rather narrow range of EACN's--e.g., 7.0 to 8.2 in this illustration. If methane should behave as an alkane of carbon-number unity (e.g., if the EACN of methane equals its ACN) and if the mole-fraction-weighting rule applicable to the C5 through C 16 alkanes holds for methane, then pressurizing a stock-tank oil of 318 average molecular pressurizing a stock-tank oil of 318 average molecular weight and 7.6 EACN with 33 mol% (only 2.4 wt%) methane would shift the EACN of the oil to 5.4. SPEJ P. 501

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.

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^

Application of the Theory of Multicomponent, Multiphase Displacement to Three-Component, Two-Phase Surfactant Flooding

1981 ◽  
Vol 21 (02) ◽  
pp. 191-204 ◽  
Author(s):  
George J. Hirasaki
Keyword(s):  
Partition Coefficient ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Chromatographic Separation ◽  
Partition Coefficients ◽  
Phase System ◽  
Surfactant Flooding ◽  
Two Phase ◽  
Optimal Salinity ◽  
Interfacial Tensions

Abstract The theory presented in a companion paper is illustrated for the case of three-component, two-phase (i.e., constant-salinity) surfactant flooding. The utility of this method is that, in addition to computation of specific cases, it provides a general qualitative understanding of the displacement behavior for different phase diagrams and different injection compositions. The phase behavior can be classified as to whether the partition coefficient is less than or greater than unity. The injection composition of the slug can be classified as to whether it is aqueous or oleic and whether it is inside or outside the region of tieline extensions.The theory provides an understanding of the displacement mechanisms for the three-component, two-phase system as a function of phase behavior and injection composition. This understanding aids the interpretation of phenomena such as the effects of dispersion, salinity gradient, chromatographic separation, and polymer/surfactant interaction. Introduction The phase behavior of surfactant with oil and brine is the underlying phenomenon of most surfactant-flood design philosophies. The surfactant slugs have been formulated either as (1) surfactant in water, (2) surfactant in oil, or (3) microemulsions containing both water and oil. Recovery of oil is thought to occur by solubilization, oil swelling, miscible displacement, and/or low interfacial tensions. The low interfacial tensions occur in a salinity environment such that three phases can coexist. At higher salinities the surfactant is in the oleic phase, and at lower salinities it is in the aqueous phase.Some recent investigators have preferred designing their process at a constant salinity even though their experiments indicated better oil recovery with a salinity contrast. Glover et al. point out that the optimal salinity is not constant in brines containing divalent ions and that phase trapping can result in large retention of surfactant in a system that was at optimal salinity at injected conditions. Nelson and Pope have demonstrated that good oil recovery is possible in systems containing formation brine with 120,000 ppm TDS and 3,000 ppm divalent cations if the drive salinity is sufficiently low such that the surfactant partitions into the aqueous phase. Moreover, the peak surfactant concentration in the effluent occurred in the three-phase environment where the lowest interfacial tension usually occurs.The purpose of this work is to understand better the mechanism of multiphase, multicomponent displacement so that the phase behavior can be used to advantage. The approach used is to examine in detail the displacement mechanism and behavior of a two-phase, three-component system. This understanding will build a foundation for examining more complex systems.Earlier, Larson and Hirasaki showed effects of oil swelling and the retardation of the surfactant front due to the surfactant partitioning into the oleic phase. Recently, Larson extended the work to finite slugs including oleic slugs. He showed the conditions necessary to have miscible or piston-like displacement. His work showed that systems with large partition coefficients are more tolerant to dispersive mixing. We show in this paper that his observation was probably the consequence of having a phase diagram with a constant partition coefficient. Todd et al. show the effect of the partition coefficients on the chromatographic separation and retention for a two-component surfactant system. Pope et al. evaluated the sensitivity of the performance of a surfactant flood to a number of factors. SPEJ P. 191^

Mixing Rules for Optimum Phase-Behavior Formulations of Surfactant/Oil/Water Systems

1979 ◽  
Vol 19 (05) ◽  
pp. 271-278 ◽  
Author(s):  
J.L. Salager ◽  
M. Bourrel ◽  
R.S. Schechter ◽  
W.H. Wade
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Practical Interest ◽  
Phase Region ◽  
Salinity Range ◽  
Mixing Rules ◽  
Recovery Efficiency ◽  
Middle Phase ◽  
Rich Phase ◽  
Three Phase

Abstract Many formulations used in surfactant flooding involve blends of surfactants designed to glue the best oil-recovery efficiency. Because oil-recovery efficiency usually is presumed to relate closely to surfactant/brine/oil phase behavior, it is of interest to understand the effect of mixing surfactants or of mixing oils on this phase behavior.We show that a correlation defining optimal behavior as a function of salinity, alcohol type and concentration, temperature, WOR (water/oil ratio), and oil type can be extended to mixtures of sulfonated surfactants and to those of sulfonates with sulfates and of sulfonates with alkanoates, provided the proper mixing rules are observed. provided the proper mixing rules are observed. The mixing rules apply to some mixtures of anionic and nonionic surfactants, but not to all. These mixtures exhibit some properties that may be of practical interest, such as increased salinity and practical interest, such as increased salinity and temperature tolerance. Introduction Recent studies have shown that formulation of the surfactant/brine/oil system is a key factor governing the performance of microemulsions designed to recover residual oil. These studies demonstrate that all optimal formulations exhibit characteristic properties that are remarkably similar. In general, properties that are remarkably similar. In general, the optimal microemulsion can solubilize large quantities of oil and connate water; in the presence of excess quantities of oil and water, a third surfactant-rich middle phase is formed. The interfacial tensions (IFT's) between the excess phases and the surfactant-rich phase are both low - about 10 dyne/cm (10 mN/m). Given an oil/brine system from a particular reservoir, one can achieve this formulation by varying the surfactant or the cosurfactant. Different oils, brines, or temperatures require formulations correspondingly altered to maintain optimal conditions. Previous studies have shown that the three-phase region exists over a range of values when one parameter, such as cosurfactant concentration, parameter, such as cosurfactant concentration, salinity, temperature, etc., is varied systematically (often called a scan). Thus, some ambiguity may exist with regard to the selection of those parameters representing the optimal formulation. Clearly, the optimum is that which recovers the most oil. However, tests are laborious, difficult to reproduce precisely, and sensitive to other factors, such as precisely, and sensitive to other factors, such as mobility, surfactant retention, wettability, etc. Therefore, it is desirable to impose an alternative definition that can be used for screening, though the final design still is dictated by core floods.Healy and Reeds have shown that the optimal formulation for oil recovery closely corresponds to that for which the IFT's between the excess oil and water phases and the surfactant-rich phase are equal. An almost equivalent criterion also was shown to be that point in the three-phase region for which the volume of oil solubilized into the middle phase equals the volume of brine. Furthermore, Salager et al. have used still another criterion that seems to be essentially equivalent to those used by Healy and Reed - an optimal salinity is defined as the midpoint of the salinity range for which the system exhibits three phases.These criteria are useful because they permit the screening of microemulsion systems using simple laboratory tests. SPEJ P. 271

scholarly journals Effect of Baggase NaLS Surfactant Concentration to Increase Recovery Factor

2019 ◽  
Vol 2 (1) ◽  
Author(s):  
Arinda Ristawati ◽  
Sugiatmo Kasmungin ◽  
Rini Setiati
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Surfactant Concentration ◽  
Recovery Factor ◽  
Test Results ◽  
Surfactant Flooding ◽  
Middle Phase ◽  
Basic Substance ◽  
Surfactant Phase ◽  
Behavior Test

<p class="NoSpacing1"><em>Surfactant flooding may increase oil recovery by lowering interfacial tension between oil and water. Bagasse is one of the organic materials which contain fairly high lignin, where lignin is the basic substance of making Natrium Lignosulfonate (NaLS) Surfactant. In this research, bagasse based surfactant was applied for surfactant flooding. The research was divided into two sections, namely: phase behavior test and NaLS Surfactant flooding where the water contained 70,000 ppm NaCl. Two surfactant concentrations which were used were 0.75% and 1.5% NaLS surfactant. Phase behavior tests were carried out to find the middle phase emulsion formation. Based on phase behavior test results, the percentage of emulsion volume for 0.75% and 1.5% NaLS is 13.75% and 8.75%, respectively. NaLS surfactant flooding was performed for to obtain the best recovery factor. FTIR equipment used determine recovery factor. The optimum condition was obtained at 0.75% NaLS surfactant concentration where the recovery factor was 4.4%.</em><em></em></p>

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.

The Influence of Phase Behavior on Surfactant Flooding

1979 ◽  
Vol 19 (06) ◽  
pp. 411-422 ◽  
Author(s):  
Ron G. Larson
Keyword(s):  
Porous Media ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Method Of Characteristics ◽  
Ternary Diagram ◽  
Base Case ◽  
Surfactant Flooding ◽  
Miscible Displacements ◽  
Tie Lines ◽  
Shed Light

Abstract This paper analyzes by mathematical modeling the role of phase behavior in surfactant flooding. In the absence of dispersion, miscible, immiscible, and semimiscible displacements are distinguished by the position of the injected composition relative to the position of the injected composition relative to the binodal envelope and extended tie lines. Even with dispersion, these concepts prove useful in analyzing slug miscibility breakdown in surfactant floods. Introduction Two design philosophies of tertiary oil recovery by surfactant flooding exist. In one, the chemical slug is designed to be miscible in some proportions with reservoir oil and brine, the goal being miscible displacement of resident oil. The second philosophy is to attain, rather than miscibility, philosophy is to attain, rather than miscibility, ultralow interfacial tension (IFT) between the slug fluid and resident oil. Correlations obtained by immiscible displacements of oil from natural and artificial porous media show that the saturation of residual oil (i.e. trapped, unrecoverable oil) decreases as IFT decreases. In reality, the distinction between philosophies is a matter of degree. Miscible displacements have regions of immiscibility. (e.g., the oil/brine bank). Furthermore, advocates of miscible displacements concede that breakdown into immiscible displacement occurs in the later stages of their processes; others argue that the breakdown occurs processes; others argue that the breakdown occurs early and that miscible displacements are, by and large, immiscible. On the other hand, since most slug formulations advocated by both schools are single phases capable of absorbing some amount of oil and phases capable of absorbing some amount of oil and brine without splitting into multiple phases, even chemical flood displacements designed to be immiscible are miscible for some time, however short. A related area of contention concerns the alleged advantages or disadvantages of formulating oil-rich, as opposed to brine-rich, slugs. Another area of contention concerns whether small, high-concentration chemical slugs are preferred to larger, lower-concentration slugs. The purpose of this paper is to shed light on these questions by paper is to shed light on these questions by incorporating equilibrium phase concepts as represented on a ternary diagram into the simulation of surfactant flood displacements. This study indicates that immiscible and miscible displacements are, in fact, closely related. Specifically, miscible recovery of oil is enhanced if the multiphase region of the ternary diagram contains a substantial subregion of ultralow tension. Furthermore, the success of miscible displacements is affected strongly not only by the position of the slug composition relative to the multiphase envelope on a ternary diagram but also by the position of slug composition relative to the tie lines, with better oil recovery attained when the injected composition point lies away from the region through which point lies away from the region through which extended tie lines pass. Thus, this study stresses the importance of the partition coefficient, a parameter shown to be important in an earlier study. For the purpose of this study, two simulation techniques for three-component, one- and two-phase flow in porous media were developed, each with its own restrictions. The first, a method-of-characteristics scheme (extended from a method developed earlier) allows phase volumes to change by solubilization of components phase volumes to change by solubilization of components but considers only continuous injection of micellar fluid, not the more realistic slug injection. The second method is a finite-difference approach that handles slug injection and solubilization and builds in dispersion, which cannot be considered when the method of characteristics is used. Because of the large number of parameters that arise in this study, base-case values (Table 1) of all parameters have been selected. For all results given in parameters have been selected. For all results given in this paper, the value of each parameter is the base-case value, unless otherwise specified. SPEJ P. 411

A Study of Oil Displacement by Microemulsion Systems Mechanisms and Phase Behavior

1980 ◽  
Vol 20 (06) ◽  
pp. 459-472 ◽  
Author(s):  
G.P. Willhite ◽  
D.W. Green ◽  
D.M. Okoye ◽  
M.D. Looney
Keyword(s):  
Interfacial Tension ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Surfactant Solution ◽  
Residual Oil ◽  
Surfactant Flooding ◽  
Displacement Efficiency ◽  
High Concentration ◽  
The Core ◽  
Oil Displacement

Abstract Microemulsions located in a narrow single-phase region on the phase diagram for the quaternary system consisting of nonane, isopropyl alcohol, Witco TRS 10-80 petroleum sulfonate, and brine were used to investigate the effect of phase behavior on displacement efficiency of the micellar flooding process. Microemulsion floods were conducted at reservoir rates in 4-ft (1.22-m) Berea cores containing brine and residual nonane. Two floods were made using large (1.0-PV) slugs. A third flood used a 0.1-PV slug followed by a mobility buffer of polyacrylamide. Extensive analyses of the core effluents were made for water, nonane, alcohol, and mono- and polysulfonates. An oil bank developed which broke through at 0.08 to 0.1 PV, and 48 to 700/0 of the oil was recovered in this bank which preceeded breakthrough of monosulfonate and alcohol. Coincidental with the arrival of these components of the slug, the effluent became a milky white macroemulsion which partially separated upon standing. Additional oil was recovered with the macroemulsion. Ultimate recoveries were 90 to 100% of the residual oil. Low apparent interfacial tension was observed between the emulsion and nonane. Alcohol arrived in the effluent at the same time as monosulfonate even though there was extensive adsorption of the sulfonate. Further, alcohol appeared in the effluent well after sulfonate production had ceased, indicating retention of the alcohol in the core. A qualitative model describing the displacement process was inferred from the appearance of the produced fluids and the analyses of the effluents. Introduction Surfactant flooding (micellar or microemulsion) is one of the enhanced oil recovery methods being developed to recover residual oil left after waterflooding. Two approaches to surfactant flooding have evolved in practice. In one, relatively large volumes (0.25 PV) of low-concentration surfactant solution are used to create low-tension waterfloods.1,2 Oil is mobilized by reduction of interfacial tension to levels on the order of about 10−3 dyne/ cm (10−3 mN/m). The second approach involves the application of small volumes (0.03 to 0.1 PV) of high-concentration solutions.3,4 These solutions are miscible to some extent with the formation water and/or crude oil. Consequently, miscibility between the surfactant solution and oil and/or low interfacial tensions contribute to the oil displacement efficiency. The relative importance of these mechanisms has been the subject of several papers5,6 and discussions.7,8

Parametric Review of Surfactant Flooding at Tertiary Stage to achieve the accuracy for proposing the Screening Criteria

2020 ◽  
Vol 13 ◽  
Author(s):  
Muhammad Usman Tahir ◽  
Liu Wei
Keyword(s):  
Oil Recovery ◽  
Critical Review ◽  
Fluid Viscosity ◽  
Recovery Efficiency ◽  
Surfactant Flooding ◽  
Screening Criteria ◽  
Reservoir Fluid ◽  
Tertiary Stage ◽  
Basic Parameters ◽  
Original Oil In Place

Abstract:: A critical review of previous studies is presented based on the contextual research background of surfactant flooding in this study. The parameters focused to achieve the analysis include permeability, salinity, temperature, and vis-cosity from different surfactant flooding operations. The principal theme of this review is to provide the regression analy-sis technique that may adopt to analyze the collected data and conduct contextual research. The set of analytical discus-sion is accomplished by extracting and plotting the basic parameters against recovery at Original Oil in Place (OOIP) and tertiary stages. Further, the success rate of such studies is compared to the grounds of oil recovery efficiency at different stages. Moreover, the failure of the surfactant flooding project can also be ensured by the outcomes of this study. It is revealed from this study that the recovery efficiency of surfactant flooding can be obtained maximum at lower per-meability ranges, however, other parameters such as salinity and temperature may possess some influence on recovery. In fact the fluid viscosity of reservoir fluid is inversely rated to recovery. The salinity, temperature and viscosity ranges for efficient surfactant flooding ranges may drop within the range from 1400 to 132606 ppm, 25 to 126 °C, and 1.9 to 150 cP respectively.

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.

Sign in / Sign up

Export Citation Format

Share Document