scholarly journals Consideration of Application Possibility of Biosurfactant and Alkaline-surfactant-polymer (B-ASP) with Ultra-low Crude Oil/Brine Interfacial Tension for Enhancement of Oil Recovery

2021 ◽  
Vol 64 (2) ◽  
pp. 84-91
Author(s):  
Xin WANG ◽  
Hongze GANG ◽  
Jinfeng LIU ◽  
Shizhong YANG ◽  
Bozhong MU
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Oil Recovery ◽  
Alkaline Surfactant Polymer

On Interfacial-Tension Measurements to Estimate Minimum Miscibility Pressures

2008 ◽  
Vol 11 (05) ◽  
pp. 933-939 ◽  
Author(s):  
Kristian Jessen ◽  
Franklin M. Orr
Keyword(s):  
Phase Equilibrium ◽  
Interfacial Tension ◽  
Crude Oil ◽  
Oil Recovery ◽  
Gas Oil ◽  
Bubble Behavior ◽  
Two Phase ◽  
Rising Bubble ◽  
Water Alternating Gas ◽  
Multicomponent Gas

Summary Measurements of the interfacial tension (IFT) of mixtures of a reservoir fluid and injection gas at various pressures have been proposed as an experimental method for predicting the minimum miscibility pressure (MMP) in an experiment referred to as the vanishing-IFT (VIT) technique. In this paper, we analyze the accuracy and reliability of the VIT approach using phase equilibrium and slimtube experimental observations and equation-of-state (EOS) calculations of the behavior of VIT experiments for the same systems. We consider 13 gas/oil systems for which phase equilibrium and density data and slimtube measurements of the MMP are available. We show that tuned EOS characterizations using 15 components to represent the gas/oil systems yield calculations of phase compositions and densities and calculated MMPs that reproduce the experimental observations accurately. We assume that IFTs can be calculated with a parachor expression, and we simulate the behavior of a series of VIT experiments with different mixture compositions in the VIT cell. We show that compositions of mixtures created in the VIT cell are not, in general, critical mixtures and that calculated estimates of the MMP obtained by the VIT approach depend strongly on the composition of the mixture used in the experiment. We show also that those MMP estimates may or may not differ significantly from values obtained in slimtube displacements. Fortuitously chosen mixture compositions can result in VIT-experiment estimates that agree well with slimtube MMPs, while for other mixtures, the error of the estimates can be quite large. In particular, we show that errors in the VIT-technique estimate of the MMP are often large for gas/oil systems for which the first-contact miscibility pressure (FCMP) is much larger than the slimtube MMP. We conclude, therefore, that the VIT experiment is not a reliable single source of information regarding the development of multicontact miscibility in multicomponent gas/oil displacements. Introduction Many oil fields are now candidates for enhanced-oil-recovery processes such as tertiary gasfloods or miscible water-alternating-gas injection schemes. The MMP is an important parameter in the design and implementation of these displacement processes and, hence, it is equally important that the MMP be determined by a method that is both reliable and accurate. Several methods have been proposed for measurement of the MMP. The slimtube-displacement experiment is the most commonly used approach (Yellig and Metcalfe 1980; Holm and Josendal 1982; Orr et al. 1982). Because of the time-consuming process of performing multiple slimtube-displacement experiments, alternative experimental approaches have been proposed. Some investigators have suggested use of a rising-bubble experiment, in which observations of bubbles of injection gas rising through oil (Christiansen and Haines 1987; Eakin and Mitch 1988; Novosad et al. 1990; Sibbald et al. 1991; Mihcakan and Poettmann 1994), are a basis of a method for determining the MMP. Zhou and Orr (1988) concluded that the changes in bubble behavior observed in the rising-bubble experiment are caused primarily by changes in IFT as components in the bubble dissolve in the oil and components in the oil transfer to the bubble. They showed that rising-bubble experiments could be used to measure the MMP for vaporizing gas drives, but are less accurate for condensing gas drives, while a drop of oil falling through gas could be used to determine the MMP for condensing gas drives. Whether either a falling-drop or a rising-bubble experiment could be used to determine the MMP accurately in condensing/vaporizing gas drives such as those described by Zick (1986), Stalkup (1987), and Johns et al. (1993) has not been determined. Rao and coworkers proposed a different use of IFT observations to determine the MMP (Rao 1997, 1999; Rao and Lee 2002, 2003; Ayirala et al. 2003; Ayirala and Rao 2004, 2006a, 2006b; Sequeira 2006). They measured IFTs for pendant drops of oil suspended in a cell containing a two-phase mixture of the injection gas and the oil. In that approach, known as the VIT experiment, the IFT is measured at a sequence of pressures, and the MMP is taken to be the pressure at which the IFT plotted as a function of pressure extrapolates to zero IFT. Orr and Jessen (2007) presented an analysis of the VIT technique based on EOS calculations for well-characterized ternary and quaternary gas/oil systems and demonstrated that the VIT experiment may give estimates of the MMP that differ significantly from the MMP based on critical tie-lines for condensing, vaporizing, and condensing/vaporizing gas drives. In this paper, we extend the analysis of Orr and Jessen (2007) and calculate the IFT behavior that would be observed in the VIT experiment for gas displacements of multicomponent crude-oil systems. We assess the accuracy of MMP estimated by the VIT approach for 13 multicomponent gas/oil displacements for which experimental phase-equilibrium and slimtube data are available, and we demonstrate that for these multicomponent crude-oil systems, the VIT approach can give estimates of the MMP that are close to the actual MMP or that are significantly in error, depending on the compositions of mixtures created in the equilibrium cell.

scholarly journals Variations of Micropores in Oil Reservoir Before and After Strong Alkaline Alkaline-surfactant-polymer Flooding

2016 ◽  
Vol 9 (1) ◽  
pp. 257-267
Author(s):  
Yongqiang Bai ◽  
Yang Chunmei ◽  
Liu Mei ◽  
Jiang Zhenxue
Keyword(s):  
Quantitative Analysis ◽  
Crude Oil ◽  
Oil Recovery ◽  
Chemical Flooding ◽  
Sem Images ◽  
Force Microscopy ◽  
Micropore Structure ◽  
Asp Flooding ◽  
Before And After ◽  
Alkaline Surfactant Polymer

Enhanced oil recovery (EOR) provides a significant contribution for increasing output of crude oil. Alkaline-surfactant-polymer (ASP), as an effective chemical method of EOR, has played an important role in advancing crude oil output of the Daqing oilfield, China. Chemical flooding utilized in the process of ASP EOR has produced concerned damage to the reservoir, especially from the strong alkali of ASP, and variations of micropore structure of sandstones in the oil reservoirs restrain output of crude oil in the late stages of oilfield development. Laboratory flooding experiments were conducted to study sandstones’ micropore structure behavior at varying ASP flooding stages. Qualitative and quantitative analysis by cast thin section, scanning electric microscopy (SEM), atomic force microscopy (AFM) and electron probe X-Ray microanalysis (EPMA) explain the mechanisms of sandstones’ micropore structure change. According to the quantitative analysis, as the ASP dose agent increases, the pore width and pore depth exhibit a tendency of decrease-increase-decrease, and the specific ASP flooding stage is found in which flooding stage is most affective from the perspective of micropore structures. With the analysis of SEM images and variations of mineral compositions of samples, the migration of intergranular particles, the corrosions of clay, feldspar and quartz, and formation of new intergranular substances contribute to the alterations of sandstone pore structure. Results of this study provide significant guidance for further application to ASP flooding.

Competing Roles of Interfacial Tension and Surfactant Equivalent Weight in the Development of a Chemical Flood

1982 ◽  
Vol 22 (04) ◽  
pp. 472-480 ◽  
Author(s):  
S.L. Enedy ◽  
S.M. Farouq Ali ◽  
C.D. Stahl
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Oil Recovery ◽  
Salt Concentration ◽  
Surfactant Concentration ◽  
Evolutionary Process ◽  
Chemical Flooding ◽  
Equivalent Weight ◽  
Residual Oil ◽  
Tertiary Oil Recovery

Abstract This investigation focused on developing an efficient chemical flooding process by use of dilute surfactant/polymer slugs. The competing roles of interfacial tension (IFT) and equivalent weight (EW) of the surfactant used, as well as the effect of different types of preflushes on tertiary oil recovery, were studied. Volume of residual oil recovered per gram of surfactant used was examined as a function of these variables and slug size. Tertiary oil recovery increased with an increase in the dilute surfactant slug size and buffer viscosity. However, low IFT does not ensure high oil recovery. An increase in surfactant EW used actually can lead to a decrease in oil recovery. Tertiary oil recovery was also sensitive to preflush type. Reasons for the observed behavior are examined in relation to the surfactant properties as well as to adsorption and retention. Introduction Two approaches are being used in development of surfactant /polymer-type chemical floods:a small-PV slug of high surfactant concentration, ora large-PV slug of low surfactant concentration. This study deals with the latter-i.e., dilute aqueous slugs (with polymer added in many cases) containing less than or equal 2.0 wt% sulfonates and about 0. 1 wt% crude oil. Because the dilute slug contains little of the dispersed phase, an aqueous surfactant slug usually is unable to displace the oil miscibly; however, residual brine is miscible with the slug if the inorganic salt concentration is not excessive. The dilute, aqueous petroleum sulfonate slug lowers the oil/water IFT. overcoming capillary forces. This process commonly is referred to as locally immiscible oil displacement. Objectives The objective of this work was to develop an efficient dilute surfactant/polymer slug for the Bradford crude with a variety of sulfonate combinations. Effects of varying the slug characteristics such as equivalent weight, IFT, salt concentration, etc. on tertiary oil recovery were examined. Materials and Experimental Details The petroleum sulfonates and the dilute slugs used in this study are listed in Tables 1 and 2, respectively. The crude oil tested was Bradford crude 144 degrees API (0.003 g/cm3), 4 cp (0.004 Pa.s)]. The polymer solutions were prefiltered and driven by brines of various concentrations (0.02, 1.0, and 2.0% NACl). In many cases, the polymer was added to the slug. Conventional coreflood equipment described in Ref. 3 was used. Berea sandstone cores (unfired) 2 in, (5 cm) in diameter and 4 ft (1.3 m) in length were used for all tests, with a new core for each test. Porosity ranged from 19.3 to 21.0%, permeability averaged 203 md, and the waterflood residual oil saturation averaged 33.1%. IFT's were measured by the spinning drop method. Viscosities were measured with a Brookfield viscosimeter and are reported here for 6 rpm (0.1 rev/s). The dilute slugs containing polymer exhibited non-Newtonian behavior. Without polymer the behavior was Newtonian. Sulfonate concentration in the oleic phase was determined by an infrared spectrophotometer, while the concentration in the aqueous phase was measured by ultraviolet (UV) absorbance analysis. Discussion of Results Slug development in this investigation was an evolutionary process. Dilute slugs were developed and core tested in a sequential manner (Table 2). Slugs 100 through 200 yielded insignificant ternary oil recoveries (largely because of excessive adsorption and retention), but the results helped determine improvements in slug compositions and in the overall chemical flood. This paper gives results for the more efficient slugs only. SPEJ P. 472^

scholarly journals Effect of ionic strength in low salinity water injection processes

2020 ◽  
Vol 10 (2) ◽  
pp. 17-26
Author(s):  
Gustavo Maya Toro ◽  
Luisana Cardona Rojas ◽  
Mayra Fernanda Rueda Pelayo ◽  
Farid B. Cortes Correa
Keyword(s):  
Ionic Strength ◽  
Interfacial Tension ◽  
Crude Oil ◽  
Oil Recovery ◽  
Water Injection ◽  
Spontaneous Imbibition ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Low salinity water injection has been frequently studied as an enhanced oil recovery process (EOR), mainly due to promising experimental results and because operational needs are not very different from those of the conventional water injection. However, there is no agreement on the mechanisms involved in increasing the displacement of crude oil, except for the effects of wettability changes. Water injection is the oil recovery method mostly used, and considering the characteristics of Colombian oil fields, this study analyses the effect of modifying the ionic composition of the waters involved in the process, starting from the concept of ionic strength (IS) in sandstone type rocks. The experimental plan for this research includes the evaluation of spontaneous imbibition (SI), contact angles, and displacement efficiencies in Berea core plugs. Interfacial tension and pH measurements were also carried out. The initial scenario consists in formation water (FW), with a total concentration of 9,800 ppm (TDS) (IS ~ 0.17) and a 27 °API crude oil. Magnesium and Calcium brine were also used in a first approach to assess the effect of the divalent ions. Displacement efficiency tests are performed using IS of 0.17, 0.08, and 0.05, as secondary and tertiary oil recovery and the recovery of oil increases in both scenarios. Spontaneous imbibition curves and contact angle measurements show variations as a function of the ionic strength, validating the displacement efficiencies. Interfacial tension and pH collected data evidence that fluid/fluid interactions occur due to ionic strength modifications. However, as per the conditions of this research, fluid/fluid mechanisms are not as determining as fluid/rock.

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