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Interfacial tension of Crude oil-brine systems in the Niger Delta

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IJRRAS 10 (3) March 2012
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INTERFACIAL TENSION OF CRUDE OIL-BRINE SYSTEMS IN THE
NIGER DELTA
Isehunwa, S.O. & Olanisebe Olubukola
Department of Petroleum Engineering, University of Ibadan, Nigeria
ABSTRACT
Interfacial tension in crude oil - brine systems is becoming very important with increasing global efforts for
increased oil reserves from enhanced oil recovery projects. Interfacial tension has direct impact on multiphase flow
and displacement processes in porous media. It also affects the behaviour of oil field emulsions. Most published
two-phase flow and displacement processes carried out under different interfacial tension have been performed for
either oil-gas or water-gas two-phase systems. This work investigated the effect of salinity, temperature and oil
viscosity on the interfacial tension of oil brine systems from five different Niger Delta reservoirs. The results show
that there is a strong relationship between temperature, salinity, oil viscosity and interfacial tension in heavy crude-
brine systems (R2 ˃ 0.88 and P ˂ 0.05), between temperature, salinity and interfacial tension in light crude-brine
systems (R2 = 0.91 and P ˂ 0.05), but no conclusive relationship in medium crudes-brine systems.
Keywords: Interfacial tension, oil-brine systems, Niger Delta, experimental design, tensiometers
1. INTRODUCTION
Interfacial tension between two immiscible fluids arises from the dissimilarity of the intermolecular forces between
the molecules in the phases. According to Shen et al [1] Interfacial tension affects two-phase flow and displacement
processes in porous media. Interfacial films could also contain ionizable groups such as asphaltenes, resins, organic
acids and solids which affect the physical properties of emulsions and the solubility of some polar organic
compounds at the oil-water interface.
Extensive survey of the literature on the interfacial tension of oil-brine systems suggests that no consistent specific
trends have been established in the changes of interfacial tension with temperature, pressure and presence of
impurities. Hjelmeland and Larrondo [2], reported this inconsistency in the trend of data on flashed crude oil and
formation brines. Similarly, Abhijit [3], noted that the behavior of interfacial tension in oil-water systems with
pressure has not yet been well understood. On the other hand, the effect of surface-active impurities on interfacial
tension have been widely reported by researchers such as McCaffery [4], Flock, et al [5] and Buckley and
Tianguang [6]. This current work investigated the relationship between temperature, salinity and oil viscosity with
the interfacial tension of brine-oil systems in the Niger Delta.
2. MATERIALS AND METHOD
Crude oil samples obtained from 5 different reservoirs and sample of automotive gas oil (diesel) were used in this
study. Viscosity was determined using a Fann rheometer while pH was measured using an analytical pH meter.
Brine solutions were prepared using distilled water treated with different concentrations of Sodium Chloride.
Interfacial tension of the oil-brine systems were measured at temperatures using the CSC-DuNouy Tensiometer. A
heating bath was used to raise sample temperatures as required. Experiments were replicated to enhance accuracy of
measurements.
Results were statistically analyzed using the Response Surface Methodology in the “S Plus” environment.
Predictive models were obtained to describe the established relationship of interfacial tension with temperature (oC),
salt concentration (ppm) and viscosity (cp) respectively. P-Values, diagnostic plots and and coefficient of correlation
were also determined.
3. RESULTS AND DISCUSSION
The physical properties of the samples determined routinely at room temperature of 290C are presented in Table 1.
Figures 1- 6 show the behavior of oil-brine interfacial tension at different temperatures and brine concentrations.
The light crude (sample B) was observed to demonstrate increasing interfacial tension with temperature. At
0.0202ppm brine concentration, the interfacial tension increased from 4.2 at 29 0C to 8.3 dynes/cm at 80 0C. The
sample also showed decrease in interfacial tension with increase in brine salinity.
IJRRAS 10 (3) ● March 2012
Isehunwa & Olubukola Interfacial Tension of Crude Oil-Brine Systems
461
Table 1: Average Properties of Sample Crude oils
OIL SAMPLES
DENSITY
(g (g/cm3)
VISCOSITY
(cp)
SPECIFIC
GRAVITY
pH
Classification
A
21
0.9275
49.0
0.9276
6.5
Heavy
B
39
0.8316
2.5
0.8317
5.2
Light
C
29
0.8796
6.5
0.8798
6.2
Medium
D
34
0.8556
6.0
0.8557
7.5
Medium
E
15
0.9634
50.5
0.9635
7.6
Heavy
F
32
0.8675
4.0
0.8676
7.4
AGO
Samples A, C, D and E gave decreasing interfacial tension with increasing temperature. This is consistent with the
work of Taha Oshaka and Al- Shiwaish [7], on the effect of brine salinity on interfacial tension in a Saudi Arabian
reservoir. It should be observed however, that the decrease was more pronounced in the heavy crudes A and E. On
the other hand, Sample F, which is AGO (diesel), showed an increase in interfacial tension with temperature and an
inconsistent decrease in interfacial tension with increasing brine concentration. This agrees with the observation by
Princen et al [8], that interfacial tension of modern day engine oils does not follow the same pattern as in natural
crude because they often contain additives which could distort their properties.
The generalized model that relates interfacial tension of oil-brine systems with temperature, salinity and oil viscosity
is given by equation (1):
Y = a + bX1 + cX2 + cX3 ………………………….(1)
Where,
Y = Interfacial Tension, Dynes/cm
X1 = Temperature (oC)
X2 = Salt concentration (ppm)
X3 = Viscosity (cp)
a, b, c, and d are empirical constants obtained using response surface methodology and listed in Table 2
Table 2: Empirical Constants
Oil Sample
A
b
C
d
A
3.5040
-0.0170
-14.4896
0.0429
B
3.6626
0.0506
-39.4118
0.0058
C
11.4459
-0.0489
5.9472
0.1585
D
11.1350
-0.0166
-1.1300
0.5800
E
24.2263
-0.0647
-58.6613
0.4100
F (AGO)
20.3605
-83.9374
0.3042
0.0763
The R2 and P-values obtained are given in Table 3. These values show that in the heavy crudes (samples A and E),
all the regressor variables considered were insignificant indicating that they all contributed to the interfacial tension
response. It can therefore be strongly concluded that interfacial tension of heavy crudes depend on temperature, salt
concentration and viscosity.
For the Medium crudes (samples C and D), there was a greater variability in both correlation coefficients and P-
values as shown in Table 3. Temperature did not contribute significantly (P ˃ 0.05) to the interfacial tension of
Sample D. Also, it can be observed that sample C gave a rather low R2 (0.38) and significant values (P ˃ 0.05) for
all variables. It can be concluded that Sample C is either contaminated or its interfacial tension depended on other
variables not fully captured in this work. It can therefore be concluded that the contributing factors to interfacial
tension response in medium crude systems is yet to be fully determined.
IJRRAS 10 (3) ● March 2012
Isehunwa & Olubukola Interfacial Tension of Crude Oil-Brine Systems
462
For the light crude system (Sample B), temperature and salinity related significantly (R2 = 0.91 and P ˂ 0.05) with
interfacial tension. However, viscosity did not contribute to the interfacial tension response.
A close study of equation (1) and the empirical constants given in Table 2 confirms all the above observations.
Table 2 shows that in all cases, interfacial tension increases with viscosity, with the minimum effects observed in
light crude systems.
Figure 1: Effect of Temperature and Salinity on Interfacial Tension For Sample A
Figure 2: Effect of Temperature and Salinity on Interfacial Tension For Sample B
IJRRAS 10 (3) ● March 2012
Isehunwa & Olubukola Interfacial Tension of Crude Oil-Brine Systems
463
Figure 3: Effect of Temperature and Salinity on Interfacial Tension For Sample C
Figure 4: Effect of Temperature and Salinity on Interfacial Tension For Sample D
IJRRAS 10 (3) ● March 2012
Isehunwa & Olubukola Interfacial Tension of Crude Oil-Brine Systems
464
Figure 5: Effect of Temperature and Salinity on Interfacial Tension For Sample E
Figure 6: Effect of Temperature and Salinity on Interfacial Tension OF Diesel (Sample F)
IJRRAS 10 (3) ● March 2012
Isehunwa & Olubukola Interfacial Tension of Crude Oil-Brine Systems
465
Table 3: Correlation coefficient and P-values of Interfacial Tension Predictive models
Sample
Model Parameters
P-Value
Correlation coefficient (R2)
A
Intercept
0.0000
0.8803
X1
0.0458
X2
0.0001
X3
0.0004
B
Intercept
0.0001
0.9135
X1
0.0000
X2
0.0000
X3
0.6306
C
Intercept
0.0074
0.3849
X1
0.1582
X2
0.5872
X3
0.7717
D
Intercept
0.0000
0.8642
X1
0.4793
X2
0.0000
X3
0.1395
E
Intercept
0.0000
0.972
X1
0.0000
X2
0.0000
X3
0.0004
F
Intercept
0.0808
0.6264
X1
0.0000
X2
0.8795
X3
0.4969
4. CONCLUSION
Based on this study of interfacial tension in oil-brine systems in the Niger Delta, the following conclusion can be
reached:
1) Temperature, brine salinity and oil viscosity affect the behaviour of oil-brine systems. The relationship is well
defined in heavy oil and light oil systems, but not very conclusive in medium oil-brine systems
2) Interfacial tension increases with increasing temperature in light oil-brine systems but decrease with increasing
temperature in heavy crude-brine systems.
3) Interfacial tension is inversely correlated with salinity at specific temperatures for oil-brine systems.
4) Refined products like automotive gas oil may not exhibit the same behaviour pattern of interfacial tension like
natural crude because of the presence of additives.
5. REFERENCES
[1]. Shen , P., Zhu, B., Li, X., Zhon, T. and Wang H., The Influence of Interfacial Tension on Water-Oil Two-Phase Relative
Permeability, Paper SCA 2005-68 presented at the International Symposium of the Society of Core Analysts in Toronto,
August 2005.
[2]. Hjelmeland, O.S., and Larrondo, L.E., Experimental Investigation of the effects of Temperature, Pressure and Crude Oil
Composition on Interfacial Properties. Paper SPE 12124, 1983.
[3]. Abhijit D.Y., Petroleum Reservoir Rock and Fluid Properties, Taylor and Francis Group, LLC. CRC Press, Boca
Raton. 2006. Pp 109-118.
[4]. McCaffery, F.G., Measurement of Interfacial Tension and Contact Angles at High Temperature and Pressure. SPEJ. 11
(3), 1972 pp 26-32
[5]. Flock, D.L., Le, T.H. and Gibeau, J.P., The Effect of Temperature on the Interfacial tension of Heavy Crude Oils using
the Pendent Drop Apparatus. JCPT, 1986.
[6]. Buckley, J. S. and Tianguang, F, 2005 Crude Oil/Brine Interfacial Tensions Paper SCA 2005-01 presented at the
International Symposium of the Society of Core Analysts in Toronto, August 2005.
[7]. Taha Okasha, M., and Abdul-Jalil Al- Shiwaish, A., Effect of Brine Salinity on Interfacial Tension in Arab-D Carbonate
Reservoir, Saudi Arabia Paper SPE 119600 presented at the 2009 Middle East oil and Gas Show and conference, Bahrain.
[8]. Princen, H.M., Zia, Y.Z and Mason, S.G., Measurement of Interfacial Tension from the Shape of a Rotating Drop, J.
Colloidal and Interface Sci., 23, 1967, 99-107.
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Water-oil relative permeability characterizes two-phase flow and displacement processes, and its functional form is difficult to determine in a particular reservoir study. Adding various chemical agents into the displacing aqueous phase during alkaline-surfactant-polymer combination chemical flooding in oil production significantly changes interfacial tension (s) on water-oil interfaces, and also increases the degree of difficulty in measuring such changes in the laboratory or field. To overcome the limitations of the existing laboratory measurements of relative permeability (which are applicable only for high ranges of interfacial tension [e.g., s > 10–2 mN/m], we present a comprehensive experimental study of two-phase relative-permeability functions in much lower, more realistic interfacial tension water-oil systems. In particular, we havedevelop an improved steady-state method of measuring water-oil relative permeability curves;proven that a critical interfacial tension value (sc) exists such that interfacial tension has little impact on relative permeability for s > sc , while if s < sc, relative permeabilities to both water and oil phases will increase with decreasing interfacial tension; andshown that a logarithmic relationship exists between water-oil two-phase relative permeability and interfacial tensions. The experimental results reported here and conceptual models proposed here will be useful for feasibility studies, optimal designs, and numerical simulations of different chemical flooding operations in oil reservoirs. Introduction With simultaneous increasing demand for oil and large decreases worldwide in newly discovered oil reserves in the past few decades, more efficient development of oil and gas from existing reservoirs, using enhanced oil recovery (EOR) methods, has received greater attention, in the energy industry. As a result of industry-wide efforts to improve oil recovery rates, many EOR techniques have been developed and applied to various oil fields. In general, EOR methods, such as chemical flooding, miscible flooding, and thermal recovery techniques, rely on altering the mobility and/or the interfacial tension (IFT) between the displacing and displaced fluids to improve sweep or displacement efficiency. Among the various EOR approaches developed, chemical flooding, with various chemical surfactants added into injected fluids, is among the most promising, cost-effective, and widely used methods. To evaluate such chemically enhanced EOR approaches for their efficiency or suitability to a given reservoir, investigators resort to quantitative studies of laboratory experiments and field applications, requiring many physical parameters. Among these parameters and correlations, water-oil two-phase relative permeability is perhaps the most important constitutive relation that characterizes two-phase flow and displacement processes in porous media. Because of the additional interactions between fluid (water and oil) phases, chemical components, and solid porous rock, flow behavior within chemical flooding is in general more difficult to characterize than that within oil displacement in conventional water flooding. Even with the significant progress made in understanding chemical flooding over the past few decades, it remains a challenge to quantitatively assess such flow behavior. It is even more difficult to predict whether this technique can be successfully applied to a given field condition. One of the primary difficulties is the lack of physical insight or constitutive correlations (e.g., relative permeability curves) for describing mutual effects or interplay between phases during chemical flooding processes, a deficiency that hinders quantitative analysis (such as numerical modeling studies) of laboratory or field studies. The primary goals in reservoir EOR operations are to displace or mobilize more remaining oil from existing formations than can be achieved using conventional waterflooding techniques. Remaining oil left in reservoirs after long-time recovery operations is normally discontinuously distributed in pores. From the viewpoint of fluid flow mechanics, there are two main forces acting on residual oil drops: viscous and capillary forces. Microscopic displacement efficiency with an EOR method depends on the relative influence or ratio of these two forces, which is often described by defining a capillary number1 as the ratio of viscous forces and capillarity:
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A strong foundation in reservoir rock and fluid properties is the backbone of almost all the activities in the petroleum industry. Suitable for undergraduate students in petroleum engineering, Petroleum Reservoir Rock and Fluid Properties, Second Edition offers a well-balanced, in-depth treatment of the fundamental concepts and practical aspects that encompass this vast discipline. New to the Second Edition & Introductions to Stone II three-phase relative permeability model and unconventional oil and gas resources & Discussions on low salinity water injection, saturated reservoirs and production trends of five reservoir fluids, impact of mud filtrate invasion and heavy organics on samples, and flow assurance problems due to solid components of petroleum & Better plots for determining oil and water Corey exponents from relative permeability data & Inclusion of Rachford-Rice flash function, Plateau equation, and skin effect & Improved introduction to reservoir rock and fluid properties & Practice problems covering porosity, combined matrix-channel and matrix-fracture permeability, radial flow equations, drilling muds on fluid saturation, wettability concepts, three-phase oil relative permeability, petroleum reservoir fluids, various phase behavior concepts, phase behavior of five reservoir fluids, and recombined fluid composition & Detailed solved examples on absolute permeability, live reservoir fluid composition, true boiling point extended plus fractions properties, viscosity based on compositional data, and gas-liquid surface tension Accessible to anyone with an engineering background, the text reveals the importance of understanding rock and fluid properties in petroleum engineering. Key literature references, mathematical expressions, and laboratory measurement techniques illustrate the correlations and influence between the various properties. Explaining how to acquire accurate and reliable data, the author describes coring and fluid sampling methods, issues related to handling samples for core analyses, and PVT studies. He also highlights core and phase behavior analysis using laboratory tests and calculations to elucidate a wide range of properties.
Article
The wettability of the fluid/rock system affects the distribution of fluids within a porous medium; this distribution in turn strongly affects displacement behavior and oil recovery efficiency. This paper is an investigation of the influence of temperature, pressure, and oil composition on the wettability of a specific carbonate reservoir. Contact-angle measurements were used to quantify wettabilities on calcium-carbonate crystals. The experimental conditions included varying temperature and pressure for both dead crude oil and oil recombined to the original bubblepoint. In addition to quantification of wetting properties, interfacial tension (IFT) between oil and water was measured, and formation of rigid films was observed. A complete reversal from a predominantly oil-wet system at lower temperatures to a predominantly water-wet system at higher temperatures was found. Pressure alone had little effect on the wettability of the system. IFT between crude oil and brine showed an increase with increase in temperature under anaerobic conditions, whereas at aerobic conditions, IFT decreased with increase in temperature. The tendency to form rigid films at the crude-oil/brine interface was found to be temperature-dependent. The formation of rigid films was stronger at lower temperatures. Introduction For some time, researchers have recognized that wettability affects the distribution of fluids within a porous medium, which in turn strongly affects the displacement behavior, relative-permeability characteristics, and consequently, the oil production. The mechanisms that result from this phenomenon and the factors that influence wettability are not satisfactorily understood, possibly because of the lack of an accurate definition of wettability and a method to quantify it in porous media. The method most widely used to evaluate the wetting characteristics of a solid surface is contact-angle measurements, which can be related to processes taking place in the porous medium. This method is discussed place in the porous medium. This method is discussed in detail in Ref. 11. Considerable controversy exists, however, concerning the validity of using a smooth, flat, homogeneous solid surface to measure contact angles and then extrapolating the results to reservoir systems where the solid surface is rough and heterogeneous. Contact angles are a function of the IFT at the solid/ liquid and liquid/liquid interfaces. For reservoir fluids, IFT's are expected to be affected by changes in temperature that result from the presence of surface-active materials in the crude oil. Pressure may also be important in reservoir systems because of its effect on hydrocarbon and other gases in solution. The adsorption of surface-active material at the brine/oil interface will also cause film formation at the interface, and these films will possess properties that are different from those of the bulk fluids. It has been claimed that rigid films will have the greatest influence on the interfacial and flow properties of the fluids in porous media. A more detailed description of the dependence of contact angle on IFT and its application to oil recovery processes can be found in Ref. 11. As pointed out, wettability is closely related to oil/brine IFT; hence the study of IFT and film formation may explain changes in contact angle or wetting behavior of solid surfaces. Only a few investigations that deal with wettability of real reservoir systems at high pressure and temperature have been reported in the literature. Because we knew that temperature and pressure might play an important role in IFT and wettability, this study was undertaken to evaluate the effect of those factors on the interfacial properties of an Alberta carbonate oil reservoir. Experiments were carried out with reservoir-produced brine and both stock-tank oil and live oil. Calcium-carbonate crystals were used to represent the pore walls of the reservoir. The contact-angle method was used to quantify wettability, and the pendant drop method was used to study both IFT and film formation.
Article
A series of interfacial tension (IFT) measurements versus temperature were carried our at a constant pressure using the Pendent Drop apparatus. The study was conducted with seven different samples of viscous crude oil using as the aqueous phases a source water for water injection, distilled water, and heavy water. The temperatures investigated ranged from ambient 10 160 °C. For two heavy oils if was found that the IFT initially decreased then increased with temperature and for one oil there was only an increase. For all other systems IFT either remained constant or decreased with increasing temperature. To investigate this apparent anomaly of increasing IFT with increasing temperature, a series of experiments were conducted to examine the effect of oxidation of the bitumen and also the effect of intermediate or light-end hydrocarbons which may hare been lost from the heavy crude oil system during the driving process. No just explanation for the increasing IFT was established. In a system where the density difference between the oil and the aqueous phase was from 0.01 to 0.002 gcm3, the Pendent Drop maintains its integrity. However it was found that the drop does not have the necessary shape to permit the determination of an accurate tension. Consequently for the heavier crude oils, modified procedures for measuring IFT were examined and are described. To overcome this problem the density difference between the two phases was increased by using heavy water as the aqueous phase. Introduction The interfacial tension between heavy crude oil and injection water under reservoir conditions plays a significant mechanistic role in the process of enhanced oil recovery. This interaction between the oil and water phases in steam flood recovery schemes is a function of temperature, pressure, and composition of both the hydrocarbon and aqueous phases. With highly viscous crude oils, increasing the temperature of the formation is the most significant factor in mobilizing the oil. However, to improve the efficiency of this process, the use of additives such as solvents, high pH control chemicals, or surfactants co-injected with steam, has been shown to enhance the oil recovery. The dominant mechanism in these cases, is a reduction in IFT at the oil/water interface resulting in the mobilization of oil by in-situ emulsification. Both an increase in temperature and the use of certain additives are expected to cause a decrease in the IFT. The purpose of this study was to investigate this expectation for some heavy oils and waters. This study involved the examination of the effect of temperature on the IFT of a number of heavy crude oil and water systems using the Pendent Drop technique. This quantification of the IFT/temperature relationship is important in a number of areas including:the assessment of the application of chemicals in low- and high-temperature enhanced recovery processes.the study of the effect of IFT as it relates to emulsification of oil-in-water or water-in-oil.the establishment of high-temperature IFT relationships associated with thermal recovery mechanisms.
Article
An apparatus has been developed for measuring interfacial tensions and contact angles at pressures from atmospheric to 10,000 psia (680 atmospheres) and temperatures from 77 °P (2SC) to 320 °F (l60 °C). This capability is required for determining oil/water interfacial tensions and oil/water/solid wetting properties of both reservoir and laboratory fluids at conditions which include those encountered in most oil reservoirs. The prime component of this apparatus is the high-pressure optical cell in which the measurements are made. To minimize contamination of the liquids by the flow system components, the test fluids can only contact titanium alloy, fused silica, Teflon and the solid substrate used in the wetting test. Interfacial tension measurements for n-dodecane/water and n-octane/water are reported. In addition, contact angle behaviour on quartz and interfacial tensions were determined for three different refined oil/brine systems. These three liquid pairs had previously been used in some hot waterflooding experiments with sandstone cores; knowledge of the interfacial tension and quartz wetting behaviour, as a function of temperature, was required as an aid in the interpretation of the waterflooding results. For the above tests, experimental conditions varied from atmospheric pressure and 77 °F to 6000 psia and 300 °F. INTRODUCTION ONE OF THE RESEARCH PROJECTS at PRR [deals with the study of interfacial phenomena in porous media. It was therefore decided to develop an apparatus capable of measuring- contact angles and interfacial tensions for temperatures from 25 °C (77 °F) to 160 °C (320 °F) and pressures from 1 atmosphere to 10,000 psia. This apparatus permits the study of reservoir and laboratory fluids over a range of conditions which include those encountered in most hydrocarbon reservoirs. Wettability is recognized to have an important bearing on the multiphase flow properties of porous media (1,2) and some recent evidence points to the possibility that a large proportion of oil producing reservoirs cannot be classed as water-wet(3). The contact angle can be used as a measure of wettability(4), even though some difficulties may arise in performing and interpreting the measurements(4). Raza et al.(5) note that it is relatively easier to obtain untontaminated reservoir fluid samples as compared to core samples. This is a point in favour of can tact angle tests. The oil/water interfacial tension (γ) does not significantly affect laboratory-measured flow properties in porous rocks (6,7) as long as γ is not less than about 1 dyne/cm. Nevertheless, measurements of interfacial tension at reservoir conditions are useful both as an indication of the degree of surface activity of a given crude oil/brine system and for assessing the alteration in the interfacial tension when chemical additives are placed in either phase. This latter use is associated with the evaluation of enhanced recovery methods based on lowering interfacial tension. In addition, knowledge of interfacial tensions of reservoir and laboratory fluids is required for adjusting laboratory capillary pressure measurements to reservoir conditions. This paper describes equipment for measuring contact angles and interfacial tensions, and presents the results of some initial experiments.
Article
Vonnegut's approximate solution for the shape of a fluid drop in a horizontal rotating tube filled with a liquid of higher density has been extended and numerical solutions based on exact equations have been presented from which it is possible to calculate the interfacial tension from the length of the elongated drop along the axis of rotation when the drop volume, speed of rotation, and density difference between the two phases are known. An experimental method is described and results are given which show good agreement with other methods. The technique is considered to be especially useful for systems in which either phase is highly viscous or viscoelastic. The proposal by Vonnegut that the method be used to measure surface pressure-area curves of insoluble monolayers is shown on theoretical grounds to have limited applicability.
Effect of Brine Salinity on Interfacial Tension in Arab-D Carbonate Reservoir, Saudi Arabia Paper SPE 119600 presented at the 2009 Middle East oil and Gas Show and conference
  • M Taha Okasha
  • Abdul-Jalil Al-Shiwaish
Taha Okasha, M., and Abdul-Jalil Al-Shiwaish, A., Effect of Brine Salinity on Interfacial Tension in Arab-D Carbonate Reservoir, Saudi Arabia Paper SPE 119600 presented at the 2009 Middle East oil and Gas Show and conference, Bahrain.
The Influence of Interfacial Tension on Water-Oil Two-Phase Relative Permeability
  • P Shen
  • B Zhu
  • X Li
  • T Zhon
  • H Wang
Shen, P., Zhu, B., Li, X., Zhon, T. and Wang H., The Influence of Interfacial Tension on Water-Oil Two-Phase Relative Permeability, Paper SCA 2005-68 presented at the International Symposium of the Society of Core Analysts in Toronto, August 2005.
Crude Oil/Brine Interfacial Tensions Paper SCA 2005-01 presented at the International Symposium of the Society of Core Analysts in Toronto
  • J S Buckley
  • F Tianguang
Buckley, J. S. and Tianguang, F, 2005 Crude Oil/Brine Interfacial Tensions Paper SCA 2005-01 presented at the International Symposium of the Society of Core Analysts in Toronto, August 2005.