Micro-Emulsion Phase Behavior of a Cationic Surfactant at Intermediate Interfacial Tension in Sandstone and Carbonate Rocks

2015 ◽  
Vol 137 (1) ◽  
Author(s):  
Mahmood Reza Yassin ◽  
Shahab Ayatollahi ◽  
Behzad Rostami ◽  
Kamran Hassani ◽  
Vahid Taghikhani
Keyword(s):  
Phase Behavior ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Recovery Factor ◽  
Surfactant Flooding ◽  
Permeability Ratio ◽  
Micro Emulsion ◽  
Winsor Type Iii ◽  
Optimum Salinity

Based on the conventional approach, the trapped oil in rock pores can be easily displaced when a Winsor type (III) micro-emulsion is formed in the reservoir during surfactant flooding. On the other hand, the Winsor type (III) involves three phase flow of water, oil, and micro-emulsion that causes considerable oil phase trapping and surfactant retention. This work presents an experimental study on the effect of micro-emulsion phase behavior during surfactant flooding in sandstone and carbonate core samples. In this study, after accomplishing salinity scan of a cationic surfactant (C16–N(CH3)3Br), the effects of Winsor (I), Winsor (III) and Winsor (II) on oil recovery factor, differential pressure drop, relative permeability, and relative permeability ratio were investigated extensively. To carry out a comparative study, homogeneous and similar sandstone and carbonate rocks were selected and the effects of wettability alteration and dynamic surfactant adsorption were studied on them. The results of oil recovery factor in both rock types showed that Winsor (I) and Winsor (III) are preferred compared to Winsor (II) phase behavior. In addition, comparison of normalized relative permeability ratio at high water saturations revealed that Winsor (I) has more appropriate oil and water relative permeability than Winsor (II). The results presented in this paper demonstrate that optimum salinity which results in higher recovery factor and better oil displacement may occur at salinities out of Winsor (III) range. Therefore, the best way to specify optimum salinity is to perform core flood experiments at several salinities, which cover all phase behaviors of Winsor (I), Winsor (III), and Winsor (II).

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>

A Novel Method To Model Low-Salinity-Water Injection in Carbonate Oil Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (05) ◽  
pp. 1154-1166 ◽  
Author(s):  
Emad W. Al-Shalabi ◽  
Kamy Sepehrnoori ◽  
Mojdeh Delshad ◽  
Gary Pope
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
History Matching ◽  
Water Injection ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Summary There are few low-salinity-water-injection (LSWI) models proposed for carbonate rocks, mainly because of incomplete understanding of complex chemical interactions of rock/oil/brine. This paper describes a new empirical method to model the LSWI effect on oil recovery from carbonate rocks, on the basis of the history matching and validation of recently published corefloods. In this model, the changes in the oil relative permeability curve and residual oil saturation as a result of the LSWI effect are considered. The water relative permeability parameters are assumed constant, which is a relatively fair assumption on the basis of history matching of coreflood data. The capillary pressure is neglected because we assumed several capillary pressure curves in our simulations in which it had a negligible effect on the history-match results. The proposed model is implemented in the UTCHEM simulator, which is a 3D multiphase flow, transport, and chemical-flooding simulator developed at The University of Texas at Austin (UTCHEM 2000), to match and predict the multiple cycles of low-salinity experiments. The screening criteria for using the proposed LSWI model are addressed in the paper. The developed model gives more insight into the oil-production potential of future waterflood projects with a modified water composition for injection.

A New Diagnostic Analysis Method for Waterflood Performance

2009 ◽  
Vol 12 (02) ◽  
pp. 341-351 ◽  
Author(s):  
Zhengming Yang
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Production Performance ◽  
Hydraulic Fractures ◽  
Diagnostic Analysis ◽  
Fractional Flow ◽  
Permeability Ratio ◽  
Sweep Efficiency ◽  
Widespread Application ◽  
Time Plot

Summary Despite the widespread application of reservoir simulation to study waterflood reservoirs, petroleum engineers still need simple predictive tools to forecast production decline, estimate ultimate oil recovery, and diagnose the production performance from the historical field data. On the basis of the Buckley-Leverett equation and the assumption of a semilog relationship between the oil-to-water relative permeability ratio and water saturation, a consistent analytical solution can be derived as:qoD (1 - qoD) = (EV /B)(1 / tD) where qoD is the oil fractional flow, tD is the fraction of cumulative liquid production to related formation volume, B is the relative permeability ratio parameter, and EV is the volumetric sweep efficiency. Two equivalent linear plots can be developed: a log-log plot and a reciprocal time plot. The log-log plot has a slope of -1 and intercept of EV /B. The reciprocal time plot has a slope of EV /B and an intercept value of 0. Both plots can be applied for the diagnostic analysis of waterflood reservoirs. Model and field case studies show the benefits of this technique as a production-decline analysis tool in forecasting the waterflood production decline and the ultimate oil recovery. This method can also be applied as a diagnostic tool to evaluate various aspects of waterflood performance. Examples include assessing waterflood maturity, calculating volumetric sweep efficiency, distinguishing the normal waterflood breakthrough from the premature water breakthrough through hydraulic fractures, and examining the consequences of operational changes. The appropriate use of this analytical method will help to optimize the field waterflood operation.

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.

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^

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

scholarly journals Hybrid Chemical Enhanced Oil Recovery Techniques: A Simulation Study

Symmetry ◽  
2020 ◽  
Vol 12 (7) ◽  
pp. 1086 ◽  
Author(s):  
Haiyan Zhou ◽  
Afshin Davarpanah
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Field Data ◽  
Polymer Flooding ◽  
Oil Field ◽  
Recovery Factor ◽  
Surfactant Flooding ◽  
Conformance Control ◽  
Recovery Techniques ◽  
Polymer Surfactant

Simultaneous utilization of surfactant and preformed particle gel (henceforth; PPG) flooding on the oil recovery enhancement has been widely investigated as a preferable enhanced oil recovery technique after the polymer flooding. In this paper, a numerical model is developed to simulate the profound impact of hybrid chemical enhanced oil recovery methods (PPG/polymer/surfactant) in sandstone reservoirs. Moreover, the gel particle conformance control is considered in the developed model after polymer flooding performances on the oil recovery enhancement. To validate the developed model, two sets of experimental field data from Daqing oil field (PPG conformance control after polymer flooding) and Shengli oil field (PPG-surfactant flooding after polymer flooding) are used to check the reliability of the model. Combination of preformed gel particles, polymers and surfactants due to the deformation, swelling, and physicochemical properties of gel particles can mobilize the trapped oil through the porous media to enhance oil recovery factor by blocking the high permeable channels. As a result, PPG conformance control plays an essential role in oil recovery enhancement. Furthermore, experimental data of PPG/polymer/surfactant flooding in the Shengli field and its comparison with the proposed model indicated that the model and experimental field data are in a good agreement. Consequently, the coupled model of surfactant and PPG flooding after polymer flooding performances has led to more recovery factor rather than the basic chemical recovery techniques.

scholarly journals Study of Low-Salinity Waterflooding for Sandstone Reservoir

2019 ◽  
Vol 1 (1) ◽  
pp. 85
Author(s):  
Dwiky Pobri Cesarian
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Water System ◽  
Recovery Factor ◽  
Breakthrough Time ◽  
Constant Flow Rate ◽  
Low Salinity Waterflooding ◽  
Salinity Increase ◽  
Water Cut ◽  
Total Oil

Recent studies showed that salinity concentration of the injected water is more important factor rather than the amount of water injected. The objectives of this study are to analyse the effect of salinity and its behaviour in waterflooding and calculating the recovery factor of the oil produced in sandtone reservoir condition. This study focuses on analysing the effect of salinity to its recovery factor, relative permeability, breakthrough time and water cut of the oil-water system. Laboratory experiment had been carried out to determine the recovery factor by using sandstone core with the dimension length and diameter of 3 in and 1.5 in, respectively. Sodium Chloride (NaCl) was used to control the salinity concentration in waterflooding with range of 1,000 ppm to 14,000 ppm. The experiment was run with constant flow rate, pressure and temperature. In this experiment, deionized water with varied salinity and paraffin oil were used to perform the waterflooding procedure. Based on the results obtained, the highest total oil recovery by waterflooding was 57.8% with 4,000 ppm as the optimum salinity, which is 14.6% higher than oil recovered by 14,000 ppm. The results also showed the change in end-point value of relative permeability. It also showed that water cut tend to increase as the salinity increase, while breakthrough time tend to decrease as the salinity increase.

scholarly journals A BASIC REVIEW ON MICRO EMULSION AS A DRUG DELIVERY SYSTEM.

2020 ◽  
Vol 9 (5) ◽  
Author(s):  
Alfisha Saifi ◽  
Kapil Kumar ◽  
Deepak Teotia
Keyword(s):  
Drug Delivery ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Targeted Delivery ◽  
Metal Cutting ◽  
Enzymatic Catalysis ◽  
Structure Type ◽  
Synthesis Of Nanoparticles ◽  
Drug Molecules ◽  
Micro Emulsion

Lipid dosage forms are attractive delivery systems for hydrophobic drug molecules. Emulsion is one of the popular system since many decades. Pharmaceutical applications of emulsions widened especially after micro emulsion emergence. Now a day Microemulsion is an emerging trade and having worldwide importance in a variety of technological applications. These applications include enhanced oil recovery, combustion, cosmetics, pharmaceuticals, agriculture, metal cutting, lubrication, food, enzymatic catalysis, organic and bio-organic reactions, chemical synthesis of nanoparticles etc. This review article deals with feature and application of microemulsion. a brief introduction and definition, structure, type, formation characteristics, stability, phase behavior and the effect of additives, pressure, temperature on the phase behavior of microemulsion . In addition to oral and intravenous delivery, they are amenable for sustained and targeted delivery through ophthalmic, dental, pulmonary, vaginal and topical routes. Microemulsions are experiencing a very active development as reflected by the numerous publications and patents being granted on these systems. They have been used to improve the oral bioavailability of various poorly soluble drugs including cyclosporine. Keywords: Microemulsion, Self micro emulsifying system, poor soluble, thermodynamically stable, Sustained & Controlled release, Drug delivery.

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