The Effect of Dispersed Phase Salinity on Water-in-Oil Emulsion Flow

Subscriber access provided by HACETTEPE UNIVERSITESI KUTUPHANESI

Article

The Effect of Dispersed Phase Salinity on Water-inOil Emulsion Flow Performance: A Micromodel Study Sepideh Maaref, Shahab Ayatollahi, Nima Rezaei, and Mohsen Masihi Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.7b00432 • Publication Date (Web): 24 Mar 2017 Downloaded from http://pubs.acs.org on March 30, 2017

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a free service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are accessible to all readers and citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

Industrial & Engineering Chemistry Research is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

Page 1 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Industrial & Engineering Chemistry Research

The Effect of Dispersed Phase Salinity on Water-in-Oil Emulsion Flow Performance: A Micromodel Study Sepideh Maaref1,2, Shahab Ayatollahi1*, Nima Rezaei3, and Mohsen Masihi1 1*

Sharif Upstream Petroleum Research Institute, Chemical and Petroleum Engineering Department, Sharif University of Technology, Tehran, Iran 2 Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, AB, Canada 3 Faculty of Engineering and Applied Science, Memorial University of Newfoundland, St John’s, NL, Canada *

Email: Shahab @sharif.edu

Abstract In this work, the effect of brine salinity on water-in-oil emulsion flow performance in a porous media is studied as it imposes significant challenge to oil production in petroleum industry. Crude oil sample from an Iranian oilfield and synthetic brine with different salinity (40-140 g/L salt) are used. The results show that the emulsion viscosity and interfacial tension, increase slightly with salinity, while they do not considerably affect the flow behavior. The emulsion stability analysis show that larger w/o emulsion droplets are formed for higher brine salinity, which potentially block more pore spaces through straining and interception mechanisms. This phenomenon resulted in lower emulsion recovery and higher pressure changes at higher brine salinity. The emulsion recovery at higher brine salinity was 12.5 % less than that of the lower one. The tests show that some of the captured droplets could re-entrain to the main flow stream at higher capillary numbers, resulting in better sweep efficiency.

Keywords: water-in-oil emulsion, emulsion stability, salinity, straining, interception

ACS Paragon Plus Environment


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 2 of 35

1. Introduction An emulsion is defined as a system of two immiscible liquids, one of which is dispersed as droplets (internal or dispersed phase) within another (external or continuous phase) in the presence of surface-active agents

1-3

. Emulsions may be categorized as oil-in-water (o/w), water-in-oil (w/o)

or a more complex dispersion, such as oil-in-water-in-oil (o/w/o) or water-in-oil-in-water (w/o/w) emulsions 4. o/w and w/o emulsions can be formed in situ under adequate conditions in porous media. A third component that is present in an emulsion is the surface active material, which can reduce interfacial tension between liquids and can stabilize the dispersed droplets 3. In oil reservoirs, some crude oil components such as asphaltenes, waxes, and naphthenic acids act as emulsifying agents, which can suppress the emulsion breakdown process 5-10. Besides the natural surfactants in the crude oil, fine solid particles such as sand, clay, drilling mud, drag reducing agents, and corrosion inhibitors could also adsorb at the oil-water interface and stabilize the emulsions 3, 11. In petroleum production, heavy crude oils are often produced with water in the form of water-inoil (w/o) or oil-in-water (o/w) emulsions 10-12. A variety of emulsions is also observed in enhanced oil recovery (EOR) methods 13. McAuliffe 14, 15 was one of the first researchers to report the use of o/w emulsions in improving oil recovery during waterflooding. He compared o/w emulsion flooding to waterflooding and proved that o/w emulsion injection can lead to an increase of the volumetric sweep efficiency and oil production. Similar improvement in volume of oil recovery and displacement efficiency were observed in other EOR processes, such as alkaline flooding 16, alkaline-surfactant flooding 16-18, and alkaline-surfactant-polymer flooding 19, in which emulsions naturally occurred as a consequence of decreased interfacial tension and they could decrease the mobility contrast between the displacing and displaced phases. Bera et al.

20-22

investigated the

solubilization and phase equilibria of oil-water micro emulsion systems to find out suitable anionic and cationic micro emulsions for the oil recovery using micro emulsion flooding. The effect of salinity, alkane carbon number (ACN) of hydrocarbon, surfactant, and cosurfactant concentration was also studied on the formation of micro emulsion. These important properties were found to be very helpful to prepare the micro emulsion for enhanced oil recovery process.


Page 3 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Emulsions have been also used as plugging agents to improve oil recovery performance. Many researchers carried out experimental investigation on injection of w/o or o/w emulsion as a selective plugging agent to improve oil recovery in waterflooding as well as chemical and steamflooding

14, 15, 23, 24

. Abdul and Farouq Ali

25

showed the efficiency of blocking potential and

mobility control of emulsion flooding followed by polymer flooding. Bai et al. introduced a new technique, in which a mixture of crude oil and emulsifier, denominated activated crude oil, was injected to form in situ emulsion and block water channels by significantly reducing water permeability, and consequently acting as a plugging agent, which could divert the flow to unswept area 26. Similar mechanism was found during alkaline flooding, in which in-situ formation of w/o emulsions could block the high permeable zones, which improved the oil recovery and sweep efficiency 4, 18. Despite the positive application of emulsions in EOR processes, the formation of w/o emulsion was found to be a major concern when water is injected in some reservoirs. Rezaei and Firoozabadi 27

reported formation of tight w/o emulsions in situ during waterflooding of some unusual crudes.

As a result, they observed very high pressure fluctuations, a pronounced pressure spike at the start of injection, and high pressure drops in porous media. All these unusual phenomena suggested severe challenges to oil recovery from water injection. Strange and Talash 28, Whiteley and Ware 29

, and Widmyer et al. 30 have also reported poor oil recovery due to problems associated with the

undesirable formation of stable macroemulsions in the oil fields. They observed formation of a high viscosity emulsions in the reservoir of homogeneous permeability, which required very high energy for flow in porous media. The physics of emulsion flow in porous media is so complex due to the complicated properties of emulsion system and porous media geometry. A number of flow models have been reported in the literature to describe the emulsion transport behavior in porous media including (1) the bulk viscosity model, (2) the droplet retardation model, and (3) the filtration model. The bulk viscosity model was proposed by Alvarado and Marsden

31

, in which an emulsion is

viewed as a continuous, single-phase fluid with no allowable interaction between drops and pore walls. Hence, no permeability reduction is introduced in the model and emulsion flow is different from that described by Darcy's law only when the bulk emulsion viscosity varies with shear rate.



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

McAuliffe

15

Page 4 of 35

introduced the droplet retardation model, which considers transient permeability

reduction. This model suggests that the emulsion droplets retard during their passage along the tortuous paths of the medium and the permeability of the porous medium decreases until steady state is reached. However, a problem associated with this model is that the permeability of the porous medium rises back to initial value when emulsion is followed by water. Soo and Radke 32 then presented another mechanism and developed a filtration model to describe the flow of dilute emulsions in porous media. Based on this model, some emulsion droplets with a size comparable to the pore throats may block the pore constrictions by straining mechanism; while the smaller ones may capture on the surface of sand grains, in the crevices and in recirculation eddies by means of interception mechanism. A schematic diagram of the straining and interception mechanisms is drawn in Figure 1. They showed that the permeability reduction caused by these trapping mechanisms is a function of drop size and pore size distribution. Interception Emulsion Flow Direction

S

Straining S

Figure 1. Mechanisms of emulsion flow in porous media: pore blockage by straining and interception process. S refers to solid

Furthermore, they evaluated the efficiency of deep bed filtration model by comparing simulation results with the experimental data 33. Later on, they studied the effect of velocity on emulsion flow performance and showed that at higher injection rates, droplets captured by straining mechanism can squeeze through the pore throats if the local pressure gradients overcome the capillary resistance force. Moreover, once the hydrodynamic force exceeds colloidal attractive forces between the drops and the sand grains, the captured droplets may entrain into the main flow stream 34

. Therefore, the droplet capturing and re-entrainment causes dynamic local pressure fluctuations

during emulsion flow in porous media. Moradi et al.

35

conducted core flooding experiments to investigate the capillary trapping of o/w

emulsion droplets in porous media as a function of drop to pore size ratio and capillary number.


Page 5 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Pressure drop oscillation were used to show the occurrence of blockage-release mechanism of o/w emulsion droplets during flow in porous media. The results showed that the blockage-release mechanism of the trapped droplets became less effective as the capillary number increased above a critical value. Moreover, a larger droplet-to-pore size ratio resulted in higher required capillary number; hence, larger viscous force to mobilize the droplets in the porous media. Guillen et al. 36 investigated the emulsion flow in transparent sand packs to visualize pore-level displacement. He demonstrated the flow diversion at the pore level, which was attributed to the pore throats blockage by the emulsion droplets. Romero

37

investigated the flow of emulsion in sandstone cores and

studied the effect of drop size to pore-throat size ratio and flow rate on injection pressure as well as the effectiveness of the emulsion to block the pores. A network model was also developed to simulate emulsion flow in porous media, which qualitatively matched experimental observations of emulsion flow. Mandal and Bera 4 investigated the rheological properties and flow behavior of o/w emulsions with different concentrations through sand packs of different sand sizes. The pressure drop behavior of emulsions were found to be influenced by the oil concentration of o/w emulsions and the average particle size of the medium. A mathematical model was also developed, which calculated the effective viscosity of o/w emulsions as a function of shear rate while flowing through different sand packs. The model was useful to describe the flow behavior of o/w emulsions through porous media. So far, most of the research works conducted on the behaviors of emulsion flow in porous media and permeability reduction have been carried out using core flooding tests or analytical and numerical simulations. Although micromodel techniques have become more accepted for visualizing the physical phenomena during fluid displacement

38-45

, a very limited micromodel

visualization study has been carried out to determine the pore level behaviors of emulsion flow in porous media. Soo and Radke 46 used a micromodel to study o/w emulsion flow performance. They described the emulsion flow profiles in micromodel; however, no photograph of the pore level events was reported in their work. Recently, Rezaei and Firoozabadi

27

studied the micro- and

macroscale waterflooding performances of unusual crudes which naturally form tight w/o emulsions upon mixing with brines. The waterflooding tests were conducted in both Berea cores and a glass-etched micromodel. The pore scale observations of waterflooding in glass etched micromodel revealed that in situ formation of w/o emulsion could block a significant portion of a



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

pore and resulted in high pressure drops and pressure fluctuations during waterflooding, which imposed significant production challenges. According to the aforementioned study, undesirable formation of w/o emulsion can occur in-situ in waterflooding, which is of the most utilized oil recover techniques. It is notable that the composition and salinity of the injected water can critically affect the emulsification ability of an oil-water system, emulsion drop size distribution, emulsion viscosity, and interfacial tension, all of which control the flow of emulsions in porous media. A review of the literature indicated that there is lack of systematic investigation on the effect of aqueous phase salinity on water-in-oil emulsion flow behavior in micromodel porous media. Here, we conduct a series of emulsion flow visualization tests at different brine concentrations to investigate the effect of brine salinity on w/o emulsion flow behavior during waterflooding. Due to the lack of water resources, the use of sea water or formation brine as the injection fluid is one of the first priorities of reservoir engineers. Therefore, we synthesize brines to resemble the Persian Gulf sea water and an Iranian offshore oil reservoir formation brine in studying the effect of brine salinity on w/o emulsion flow performance in glass-etched micromodel. Prior to visualization experiments, a series of emulsion stability, rheological and interfacial tension tests are performed at different brine salinities to find out the most effective parameter on w/o emulsion flow performance. Waterflooding tests are then performed in the micromodel to examine the displacement pore-scale mechanism, injection rate effect, and the pressure drop behavior of w/o emulsions for various brine salinities.

2. Experimental Section 2.1. Test Fluids A crude oil from one of Iranian oil fields, located in the south of Iran was used. Ubbelohde viscometer and a pycnometer were used to measure the viscosity and density of crude oil in ambient condition, respectively. The measured values for viscosity and density are 44 cP and 900.2 kg/m3, respectively. The crude oil used has an oil API gravity of 25.7 ̊API; the SARA analysis for the crude is summarized in Table 1.


Page 6 of 35

Page 7 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Table 1. Crude oil properties based on SARA analysis Saturates (wt.%)

Aromatics (wt.%)

Resins (wt.%)

Asphaltenes (wt. %)

42

43

8

7

It is widely accepted that the formation and stability of w/o emulsions depends on a rigid interfacial film around water droplets which reduces oil and aqueous phases interfacial tension and prevents the droplet from coalescence 47-50. This interfacial film is mainly composed of natural surfactants in crude oil such as asphaltenes, resins and fatty acids 51, 52. Among these components, asphaltenes are believed to be the main contributor to emulsion stability 53, 54. McLean and Kilpatrick 8, 49 have shown that the formation of a physically cross-linked network of asphaltene aggregates at the oilwater interface can stabilize the crude oil emulsions. Lashkarblooki et al. has also observed a large IFT reduction in acidic crude oil/water system due to the asphaltene and resin contents of the crude oil, which acted as natural surface active agents 55. Based on the aforementioned literature on the effect of asphaltene content of the crude oil on producing an interfacial film around water droplets and also based on the SARA analysis of the crude oil, it is found that the relatively high asphaltene content of 7% is responsible for the formation and stabilization of the w/o emulsions 5-10, 55, 56. The brines used for the emulsion stability analysis and waterflooding tests were synthesized according to an Iranian offshore oil reservoir formation brine and Persian Gulf sea water TDS data. We also used a brine with intermediate salt concentration to investigate the effect of injection rate on the emulsion flow behavior in the micromodel. To stabilize the emulsions, 10 g/L of Na2SO4 was added to the brine samples, since the divalent molecules of SO42- tend to produce a very compact film around the droplets due to electrostatic forces. After numerous trials of emulsion preparation with a wide range of Na2SO4 concentrations, the above mentioned concentration was found suitable to stabilize the emulsions. The brine compositions are shown in Table 2.



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 8 of 35

Table 2. Brines composition and concentration Salt Concentration (g/L) Brine

Salinity level

Identification NaCl

Na2SO4

A

Low

synthesized Persian Gulf seawater

40

10

B

Intermediate

n/a

100

10

C

High

synthesized Iranian offshore formation brine

140

10

2.2.Micromodel Fabrication and Characterization High quality float glass plates were used for the micromodel fabrication. The fabrication process mainly comprises of: patterning, etching and fusing

57

. The flow pattern was designed using

CorelDraw Graphics Suite X7. The pattern was then etched on the float glass through dry etching (laser beam) and wet chemical etching (HF acid solution) processes to attain controlled pore throat size. During the dry etching process, the glass surface was first coated with acid resist adhesive layer; the micromodel pattern was exposed to a laser engraving machine to selectively remove the acid resist layer. In wet etching process, the glass plate was etched by successive steps of HF solution (39%, Merck) etching and distilled water cleaning. Two cycles of 1-minute HF etching and 5-minute water cleaning were used to achieve the desired depth of etch. The number and duration of each cycle can differ depending on the desired depth of etch, and glass composition. Finally, the inlet and outlet ports of the micromodel were drilled. The etched plate was fused to the drilled plate in a controlled temperature furnace by gradually increasing the temperature from ambient temperature to 670 ̊C. After 48 hours staying in the oven, the micromodel was allowed to gradually cool overnight. The homogeneous micromodel five spot pattern is shown in Figure 2. In this figure, black areas resemble the pores and white areas are the matrix. This synthetic pattern is comprised of uniform pores of square shapes, being connected by rectangular throats, which resembles bundles of capillary tube for fluid flow in porous media. The network channels are etched to a uniform depth through the pattern and the average aspect ratio (Dp/Dth) of the pattern is about 5. This pattern had also used to study w/o emulsion flow performance 27.


Page 9 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Figure 2. Micromodel five spot pattern used in the experiments

To calculate the micromodel pore volume and average pore depth, water was injected into dry micromodel at constant injection rate and two consecutive pictures were taken at different times. The water surface (and surface porosity) at each time was calculated through image processing technique. Having water surfaces and the volume of water injected during this time interval, the pore volume and average depth of etch was calculated. The micromodel properties used in the experiments are summarized in Table 3. Table 3. Physical and hydraulic properties of micromodel Length

Width

PV

Avg. Pore

Avg. Pore

Avg. Throat

(cm)

(cm)

(cc)

Depth (cm)

diameter (cm)

diameter (cm)

6

6

0.31

0.008

0.070

0.013

Porosity 0.305

Absolute Permeability (D) 1.5

2.3.Emulsion Preparation w/o emulsion was prepared through mixing of crude oil with brine A, B and C using magnetic stirrer. A 20 cc container was first filled with the crude sample, and 2 cc brine was continuously added in a span of 30 min, while being mixed at 1000 RPM using the magnetic stirrer. The w/o emulsion was then placed in test tubes for the emulsion stability analysis and the viscosity measurement tests. 2.4.Emulsion Stability Analysis The measurements of emulsion stability are important tests that should be performed prior to the waterflooding experiments. In this study, the emulsion stability was investigated through



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 10 of 35

microscopic photography and droplet size distribution analysis. An emulsion sample was taken from each test tubes 2 and 4 hours after emulsion preparation. The samples were randomly taken from different locations along the height of the test tube. Each sample was then photographed under a Dino AM-351 digital microscope with adjustable magnification up to 600X. Image J processing software was used to measure the droplet size distribution. Table 4 shows the emulsion properties and sampling times used in the experiments. Table 4. W/O emulsion properties Salt Concentration (g/L) Emulsion

NaCl

Na2SO4

Brine content vol. (%)

Brine

Sampling time (hr.)

E1

A

40

10

10

2-4

E2

B

100

10

10

2-4

E3

C

140

10

10

2-4

2.4.1. Droplet Size Distribution Three samples were taken from each test tube, and observed under the microscope; for each sample, several images were taken for the analysis. Therefore, for each hour of sampling, we had a minimum of 2000 droplets from each emulsion solution to be analyzed. Image J processing software was employed to provide the emulsion drop size distribution, which was later used to calculate the emulsion droplet mean size and range. Finally, the results were presented in the form of droplet size distributions; the mean size and the range of the droplets were obtained from the size distributions. 2.5. Emulsion Rheology Tests Anton-Paar MCR 301 rheometer was used to study the effect of brine salinity on w/o emulsion rheological behavior. The experiments were conducted 2 hours after preparing the emulsion at ambient conditions. The viscosity was obtained through changing the shear rate applied to the emulsion. 2.6. Visual Flooding Tests


Page 11 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


The micromodel flow visualization setup is shown in Figure 3, consisting of: horizontally-held glass micromodel, micromodel holder, fluid injection system, pressure transmitter, data logger, back light system and digital camera, which is integrated to image processing software. To inject the fluids, a TS2-60 syringe pump was used. A ball valve was installed at the inlet to control the fluid flow and to stop the inlet flow when the tests were completed. A Rosemount differential pressure (DP) transmitter was used to measure the injection pressure with a resolution of 0.0125 psi. Note that the outlet pressure is atmospheric pressure, and the inlet pressure is equivalent to the total pressure drop in the model. The DP was calibrated in the range 0 and 50 pisg. We used a Nikon digital camera to capture the distribution of fluids at different times. A Dino AM-351 digital microscope with LED back light illumination was also used for the pore-scale observations. Image Analyzer

Data Logger

Digital Camera

Pressure Transmitter

Syringe Pump

Back Light

Effluent Collector

Figure 3. Schematic of flow visualization experimental setup

Visual flooding experiments were designed to study the pore-scale displacement mechanism, injection rate effect, and the pressure drop behavior of w/o emulsions with different brine salinities. The principal hypothesis considered in flow visualization tests includes: horizontal flow, laminar flow, homogeneity of porous medium and no gravity effects. The detailed procedure of visual flooding experiments is described as follow.



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Prior to any flooding test, all the elements of experimental set up including the micromodel and connections were cleaned and dried overnight to remove any undesirable contaminations. The brines were dyed red for better visibility, and contrast between the phases. The micromodel was then vacuumed, and fully saturated with the dyed brine. Then, several pore volumes of w/o emulsion were injected to the model at constant injection rate of 0.12 cc/h (which guarantied laminar flow in our micromodel) to saturate the model with emulsions, having initial water saturation. Waterflooding tests were then conducted at constant injection rate of 0.12 cc/h. The same brine was used for waterflooding tests and emulsion preparation. The pressure drop data were recorded continuously by data logger system until steady state condition was reached; that is, the processes of obtaining residual emulsion saturation were completed and there was no change in the pressure drop of the system. The flooding tests were observed and recorded using digital camera, which was integrated with image processing software. The saturation of each phase was then determined using the image processing software. The emulsion flow in the micromodel and its important pore scale events were studied and captured under a Dino AM-351 digital microscope. Visual observations were used to explain the pressure drop behavior during waterflooding experiments. The effect of injection rate was also investigated by generating capillary desaturation curve (CDC) using emulsion No. 2 (E2). Therefore, both experiments of brine displacement by emulsion flooding and w/o emulsion displacement by waterflooding were performed in this section at different injection rates. To clean the micromodel saturated with w/o emulsion and brine, alternate cycles of alcohol, acetone and toluene were injected. After the last cycle of acetone injection, we applied vacuum for 1 h, and dried overnight at 80 °C to remove the alcohols and toluene adsorbed onto the pore surfaces, and to attain the micromodel initial wettability.

3. Results and Discussions This section starts with emulsion stability analysis results at different brine salinities and continues with the results of emulsion rheological behavior at different brine salinities. Then, the results obtained during waterflooding tests for crude oil emulsions with seawater and formation brines will be shown. Finally, the effect of injection rate on w/o emulsion flow will be discussed.


Page 12 of 35

Page 13 of 35

3.1. Emulsion Stability Analysis Figure 4 shows microscopic views for the emulsions E1, E2 and E3 (see Table 4), 4 hours after preparation for which the size distributions are shown in Figure 5.

100 µm

100 µm

100 µm

(a)

(b)

(c)

Water droplet

Oil Phase

Figure 4. Microscopic views of emulsion samples, 4 hrs. after preparation. (a) E1, (b) E2 and (c) E3. The brown color resembles the oil and the creamy color resembles the brine phase

600 E1, me an=5.5 micron E2, me an=6.6 micron E3, me an=8.1 micron

500

Droplet Frequency

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


400 300 200 100 0

0

5

10

15

20

25

d (micron)

Figure 5. Emulsion droplet size distribution for different emulsion salinities, 4 hrs. after preparation

As seen in Figure 4 and Figure 5, both the droplet number mean size and range increase with the dispersed brine salinity. The emulsion droplet size distribution is also monitored for E1 and E3



over time, as shown in Figure 6. This figure illustrates that the emulsion size distribution for E3 is shifted to larger sizes with time while E1 remains stable within the period 2-4 hours after preparation. This figure suggests that when the NaCl concentration increases from 40 to 140 g/L, the emulsion stability decreases for the 2-hour period studied. Figure 5 and Figure 6 also reveal that as the size of dispersed phase droplets decreases, the emulsion stability increases. This point was expected since the interfacial area-per-volume increases as the droplets become smaller and this makes the emulsion more stable. The droplet number mean size and droplet range for three emulsions within the period of 2-4 hours after preparation are summarized quantitatively in Table 5. It should be noted that emulsion stability analysis for E1, E2 and E3 was repeated at least three times at the same sampling period and the same trend was observed in all tests. The reproducibility of emulsion stability analysis is shown by error bars on Figure 5 and Figure 6.

600

800

t=2 hr, mean=5.3 micron t=4hr, mean=5.5 micron

t=2hr, mean=7.1 micron t=4hr, mean=8.1 micron

500

Droplet Frequency

600

Droplet Frequency

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 14 of 35

400

200

400 300 200 100

0

0

0

2

4

6

8

10

12

14

16

18

0

5

10

15

20

25

d (micron)

d (micron)

(a)

(b)

Figure 6. Emulsion droplet size distribution, 2 and 4 hrs. after preparation for (a) E1 and (b) E3

From a macro-scale view, the emulsions were initially of Winsor type IV (emulsion phase with no excess of either oil or water). Over time, E3 became unstable by aggregation, coalescence and sedimentation mechanisms, and the excess water accumulated at the bottom of test tube which then transformed to Winsor type II (emulsion phase with excess water/brine). E1 remained the same as Winsor type IV over time 58. For E3, the amount of water accumulated at the bottom of test tubes was less than 2 cc, which was accumulated in a period of 4 hours after the emulsion preparation.


Page 15 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Table 5. Droplet mean size and range at different times for different emulsions at room conditions Mean Droplet Size (µm)

Droplet Range (µm)

Emulsion 2 hr.

4 hr.

2 hr.

4 hr.

E1

5.3

5.5

0.7 - 12.6

0.7 - 13.5

E2

6.2

6.6

0.7 - 18.5

0.7 – 20.0

E3

7.1

8.1

0.7 - 19.4

0.7 – 22.0

In general, an increase in the droplet number mean size and range after certain periods of time for E3 (higher salinity) compared to E1 (lower salinity) indicates the higher rate of aggregation and coalescence for the emulsion with higher salinity, which means that E3 is relatively less stable. These results are consistent with previous work conducted by Moradi et al.

59

, who investigated

the effect of salinity on water-in-oil emulsion stability and showed the decrease in emulsion stability by increasing the brine salinity. The interfacial tension between brine A, B, and C and crude oil were also measured by pendant drop tensiometer at room condition, and shown in Table 6. The increase of IFT values with increasing the brine salinity are also supporting the stability results for E1, E2 and E3 cases. Table 6. The brine-crude oil interfacial tension at room temperature Brine

A

B

C

IFT (mN/m)

19.4

20.1

20.6

3.2.Emulsion Rheological Behavior The variation of emulsion viscosity with shear rate for E1, E2 and E3 are shown in Figure 7, and compared to that of the crude oil. This figure shows that for these crude oil and brines, the w/o emulsion formation results in higher fluid viscosity by a factor of about 2 compared to the crude oil. This increase is related to the increased emulsion droplet interactions with the continuous phase, which increases the flow resistance for emulsions. This figure also shows that the emulsion viscosity values for E1, E2 and E3 are close to each other. Moreover, the emulsion viscosities start to slightly decrease as the shear rate increases, especially at low shear rates (less than 10). However, the emulsion viscosities do not change considerably with shear rate at higher shear rate



values. Therefore, only a mild shear thinning behavior is observed for the crude oil-brine emulsions E1, E2, and E3 as the concentration of NaCl in the brine increases from 40 to 140 g/L. This issue is related to the dispersed phase concentration of emulsion samples. As shown in Table 4, the brine phase concentration in all emulsion samples are 10 % (by Vol.) and they are not expected to show a strong non- Newtonian behavior with relatively small volume fraction of the dispersed phase droplets. This is consistent with previous study conducted by Pal

60

, who

investigated the rheological behavior of several oil/water emulsions and found that at low-tomoderate values of water cut (less than 60%), the emulsions exhibited Newtonian behavior. However, at higher values of water cuts, emulsions exhibited shear-thinning behavior. Blinks et al. also studied water-in-IPM emulsion rheology. A light shear thinning rheological behavior was obtained at low loading of hydrophobic clay (used as emulsion stabilizer), although they were using emulsion concentration of 50% 61. In a recent work by Ariffin et al., concentrated emulsions (40%) was characterized and even in a wider shear range of 0-1000 1/s, the extend of shear thinning behavior was limited 62.

90

80

Viscosity (cp)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 16 of 35

70

60

Crude oil E1 E2 E3

50

40 1

10

100

Shear rate (1/s)

Figure 7. The variation of emulsion viscosity with shear rate for different emulsions

The effect of brine salinity on the water-in-oil emulsion viscosity is complex. With the increase in salt concentration, the viscosity of dispersed phase (brine) slightly increases (according to Table 7), which is expected to increase the emulsion viscosity. However, with the increase in the salt concentration, the droplet size increases (at the same water cut). The increase in the droplet size of


Page 17 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


a stable emulsion is expected to decrease the mixture viscosity. We also observe a slight increase in the range of emulsion size which is again expected to decrease the viscosity

63

. The repeated

measurements of viscosity in this work showed higher viscosity for E3 compared to E1 and E2. This increase in the emulsion viscosity from E1 to E3 is about 12%. It is worth mentioning that there is only 14 % increase in the dispersed phase viscosity from brine A (used in E1) to brine C (used in E3), which is comparable to the extent of increase in the emulsion viscosity. It seems that the effect of salt concentration on the emulsion viscosity overcomes the effects of droplet sizes on viscosity for the crude oil-brine system. There is another point which adds to the complexity of problem related to the unstable emulsion nature for E3 (at higher salt concentration) compared to E1. As it was already stated, with an increase in the brine salinity, the rate of aggregation increases. This instability will be more pronounced in E3 compared to E1 and E2, however this dynamic droplet aggregation is not expected to be significant within the time frame of viscosity measurements. Table 7. Physical properties of brines at room temperature Brine Properties

A

B

C

Density @ 20 0C (g/cc)

1.033

1.071

1.092

Viscosity @ 20 0C (cP)

1.049±0.006

1.124±0.005

1.196±0.005

The rheological behavior of E1, E2 and E3 are described by log–log plots of shear stress versus shear rate, shown in Figure 8. The flow behavior index (n) and consistency constant (K) for E1, E2 and E3 are calculated from Figure 8 using the power law model and summarized in Table 8. It should be mentioned that the flow behavior index (n) is measure of the degree of departure from Newtonian behavior and the consistency constant (K) indicates how viscous the fluid is.



10 E1 E2 E3

Shear stress (Pa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 18 of 35

1

0.1 1

10

100

Shear rate (1/s)

Figure 8. Emulsion rheological behavior for different emulsions Table 8. Emulsion rheological properties (flow index, n and consistency constant k) for different emulsions Emulsion rheological properties n

E1

E2

E3

0.9947

0.9943

0.9932

k

0.0681

0.0717

0.0792

Table 8 shows that as the emulsion brine salinity increases, the value of n decreases and in all emulsion samples, the value is very close to unity. This indicates that the emulsion samples depart mildly from Newtonian behavior, which is consistent with the results in Figure 7. As stated previously, this is related to the low concentration of dispersed phase in the emulsion samples. The dispersed phase concentration of water is only 10 percent in all emulsion samples; hence, they represent a very mild non-Newtonian behavior. The results also show that as the brine salinity increases in the emulsion samples, the value of k increases slightly. Therefore, E3 with higher value of k has higher viscosity compared to E2 and E1. However, due to the small increase in k value, there is no significant difference in emulsion viscosities of E1, E2 and E3 as the brine salinity increases. 3.3.Micromodel Flooding Experiments


Page 19 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


The emulsion viscosity, density and brine-emulsion interfacial tension were measured by Ubblehode viscometer, pycnometer and pendant drop tensiometer, respectively, and shown in Table 9. All physical property measurement tests were conducted at room conditions. Table 9. Physical properties of w/o emulsions at room temperature Properties

E1

E2

E3

Density @ 20 0C (g/cc)

0.945

0.949

0.950

Viscosity @ 20 0C (cP)

67.3±1.0

70.5±1.4

75.4±2.3

IFT (mN/m)

12.3

14.4

15.8

As it is shown in Table 9, the emulsion viscosity and interfacial tension increase slightly as the emulsion brine salinity increases in the range of salinity tested; therefore, these physical parameters are not expected to considerably affect the flow behavior in porous media. We think that the emulsion droplet size distribution in conjunction with the emulsion capture and reentrainment, and also the water-oil interfacial elasticity govern the displacement mechanism. 3.3.1. Waterflooding Experiment Water-in-oil emulsions with sea water and formation brine were prepared fresh before each flooding test and placed in the syringe to be injected into the model using a syringe pump. Initially, the micromodel was vacuumed and fully saturated with brine. W/O emulsion was then injected at constant flow rate of 0.12 cc/h to displace the brine and to establish the irreducible water saturation condition. Then, brine was injected into the model at constant injection rate of 0.12 cc/h until it reached the steady state pressure and saturation. The pressure drop (or, injection pressure) behavior during the waterflooding experiments is shown in Figure 9. It should be noted that pressure signals were recorded after water invaded the inlet dead volume of the micromodel pattern (the leftbottom, in Figure 2). That is why the pressure drop is not initially zero.



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 20 of 35

Figure 9. Pressure drop behavior during waterflooding for crude oil emulsions with sea water and formation brines

This figure illustrates that for both emulsions (E1 and E3), the pressure drop increases until breakthrough time and then decreases while fluctuating and there is no fluctuating before the breakthrough. Before the breakthrough time, only w/o emulsion phase is being producing at the outlet which controls the overall pressure drop of the system and demands high pressure drop to be mobilized. As the brine saturation increases, the w/o emulsion relative permeability decreases; for our system of crude oil and brine, the decreased emulsion relative permeability overcomes the increased brine saturation which has much lower viscosity, demanding a higher displacing pressure drop. The maximum pressure drop is observed at breakthrough time after which the brine phase develops a percolating pathway, and the pressure drop start to decrease with considerable fluctuations. After about 2 to 3 pore volumes of injection, the pressure drop fluctuates around a stabilized pressure. The first pressure fluctuation for E3 at low pore volumes of brine injection may be due to the flow initiation; that is, w/o emulsion has been mobilized in porous media after attaining certain pressure. It is also observed that as the emulsion brine salinity increases (e.g., in E3 as compared to E1), the extent of pressure overshoot increases accordingly. The emulsion viscosity and interfacial tension are not expected to considerably affect the flow behavior, since they increase only slightly with the brine salinity (in the range of salinity tested here). So, the effect of emulsion droplet size distribution (more precisely, the ratio of emulsion size to pore size) is expected to dominate the oil recovery flow mechanism when emulsions present


Page 21 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


in the porous media. So, for the case of E3 with larger droplet size, the emulsion droplets will be captured easier in pore throats and pore bodies by both straining and interception mechanisms, causing higher pressure drop and lower final emulsion recovery. As a matter of fact, for the case of E3 (with larger droplet and lower stability), a number of droplets tend to aggregate or coalescence, forming larger droplets, which could restrict more pore throats in the micromodel in comparison to the case of E1. This would cause the injecting brine phase to reroute its path in porous medium, resulting in higher pressure drop and pressure fluctuations for E3 compared to E1. The interface elasticity is another important parameter affecting the pressure drop trend and the emulsion recovery performance during the waterflooding of emulsions at different brine salinity. As reported by Alvarado et. al, the water-oil interface elasticity increases as the brine salinity decreases during low salinity waterflooding 64. On the other hand, the interface elasticity reduces the chance of snap-off of the oil phase, which leads to reduced pressure fluctuations and also leads to a more continuous interface which can be swept more easily

64, 65

. Therefore, in the

waterflooding of E1 by sea water (with lower salinity), the interface elasticity between brine and crude oil is higher compared to waterflooding of E3 by the formation brine (with higher salinity). This would lead a more stable displacement of E1 compared to E3, resulting in higher emulsion recovery and lower pressure drop compared to waterflooding of E3. The emulsion saturation distribution is presented in Figure 10. A comparison of Figure 9 and Figure 10 shows that although there is no emulsion production after about 1.3 of pore volume injection (PVI) for E1, and 0.6 PVI for E3, there are significant pressure changes for both cases. This is due to continuous emulsion saturation redistribution along the flow path. This behavior is also confirmed by the emulsion saturation, and the pressure drop results at different pore volumes of injection presented in Table 10. These results are in agreement with the observations made by Rezaei and Firoozabadi during coreflooding tests 27.



0.9

E1 E3

0.8

Emulsion Saturation

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 22 of 35

0.7

0.6

0.5

0.4

0.3 0

1

2

3

PVI

Figure 10. Emulsion saturation distribution during waterflooding Table 10. Emulsion saturation and pressure drop vs. pore volumes of water injected E1 PVI

E3

∆p (psi)

So

∆p (psi)

So

0

0.4146

0.84

0.5140

0.85

0.2

0.6464

0.58

0.7694

0.64

0.6

0.5348

0.44

0.6192

0.51

1.0

0.4364

0.41

0.6468

0.51

1.2

0.4357

0.40

0.6430

0.51

1.6

0.4341

0.40

0.6297

0.51

2.0

0.4169

0.40

0.6688

0.51

2.2

0.4528

0.40

0.6659

0.51

2.4

0.4553

0.40

0.6620

0.51

Table 11 presents important recovery results for the waterflooding experiments. It can be concluded that waterflooding of E3 results in lower final emulsion recovery than E1 due to more w/o emulsion entrapment and unfavorable displacement resulted from higher viscosity and IFT. It should be mentioned that at the end of waterflooding, some pore throats filled by w/o emulsions are bypassed by the brine phase and there is residual emulsion left in the pore throats. Therefore, Sor (in Table 11) is referred to for the residual emulsion saturation.


Page 23 of 35

Table 11. A summary of important recovery results for the waterflooding experiment Waterflooding

E1

E3

Sw at B.T time

0.49

0.43

Sor

0.40

0.51

Pressure drop at B.T time (psi)

0.6584

0.8537

Stabilized pressure drop (psi)

0.4361

0.6645

RF (%)

52.4

39.9

3.3.2. Single Phase Flow Experiment The single-phase water flow experiment was carried out in the homogeneous micromodel to better understand the effect of w/o emulsion flow on pressure drop responses. Figure 11 shows pressure drop as a function of injected pore volume at different flow rates of 10, 7 and 5 cc/h. The flow rate is decreased in each step after the system reached the steady state condition at each specific flow rate. This explains step function decrease observed in this figure.

0.6

0.5 Q = 10 cc/h

P (psi)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


0.4

0.3 Q = 7 cc/h 0.2 Q = 5 cc/h 0.1 0.0

0.5

1.0

1.5

2.0

2.5

PVI

Figure 11. Pressure drop behavior during single-phase water flow at different flow rates

As can be seen from Figure 11, as flow rate decreases form 10 cc/h to 7 cc/h and then 5 cc/h, the pressure drop decreases accordingly which is expected from Darcy’s equation of flow in porous media with constant permeability. This figure also shows that there is no significant pressure fluctuations during the single phase flow of water at different injection rates, and the pressure drop responses in this experiment are qualitatively different to the pressure drop responses during w/o



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 24 of 35

emulsion flow provided in Figure 9. This issue reveals that possible syringe pump injection pulse or the accuracy of pressure transmitter in recording the pressure drop data do not have considerable effect on the pressure drop behavior or it's fluctuations. Therefore, pressure fluctuations in Figure 9 during waterflooding of emulsions with different brine salinities are not affected by accuracy of the syringe pump or pressure transmitter (DP) and they are related to droplet capturing of w/o emulsions during their flow in the micromodel porous media. 3.4. Microscopic Examination In this section, qualitative investigation of the effect of brine salinity on w/o emulsion flow performance is made through microscopic images taken during waterflooding of E1 and E3. This would help us to make a deeper mechanistic understanding of the pressure drop behavior and emulsion recovery performance during the waterflooding of emulsions at different brine salinities. Figure 12. Microscopic view of micromodel pore and throats during waterflooding of E3. (a) Droplet aggregation, (b) Pore blockage, (c) Interception of water droplets, and (d) Droplet coalescence. S refers to solid or non-etched part of the micromodel.

shows a pore throat being captured by E3 droplets. The white and brown areas resemble water droplets and the oil continuum, respectively. This figure shows that a large number of emulsion droplets can aggregate and block some portion of the micromodel throats either partially (Figure 12. Microscopic view of micromodel pore and throats during waterflooding of E3. (a) Droplet aggregation, (b) Pore blockage, (c) Interception of water droplets, and (d) Droplet coalescence. S refers to solid or nonetched part of the micromodel.

(a)) or completely (Figure 12. Microscopic view of micromodel pore and throats during waterflooding of E3. (a) Droplet aggregation, (b) Pore blockage, (c) Interception of water droplets, and (d) Droplet coalescence. S refers to solid or non-etched part of the micromodel.

(b)). Some other droplets can also adsorb at the pore body and throats surfaces and restrict the area available to emulsion flow (Figure 12. Microscopic view of micromodel pore and throats during waterflooding of E3. (a) Droplet aggregation, (b) Pore blockage, (c) Interception of water droplets, and (d) Droplet coalescence. S refers to solid or non-etched part of the micromodel.

(a), (b) and (c)) via interception mechanism. The interfacial films in some aggregated droplets can also rupture, forming a larger droplet by coalescence (Figure 12. Microscopic view of micromodel


Page 25 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


pore and throats during waterflooding of E3. (a) Droplet aggregation, (b) Pore blockage, (c) Interception of water droplets, and (d) Droplet coalescence. S refers to solid or non-etched part of the micromodel.

(d)). The larger droplet can block a significant portion of a throat or pore body. All of the mentioned processes restrict the accessibility to pore bodies and throats in the glass micromodel and re-route the advancing flow interface, causing pressure fluctuations at the pore-scale. The coalescence evidence for E3 in micromodel is in agreement with the findings in Figure 6.

S

S

50 µm

50 µm

(a)

(b)

S 50 µm

50 µm

(c)

(d)

Figure 12. Microscopic view of micromodel pore and throats during waterflooding of E3. (a) Droplet aggregation, (b) Pore blockage, (c) Interception of water droplets, and (d) Droplet coalescence. S refers to solid or non-etched part of the micromodel.

Besides the microscopic pore throat blockage by w/o emulsion droplets, some macro emulsions can also form at the brine-emulsion interface. Figure 13 shows formation of w/o macro emulsions during waterflooding of E3. The w/o macro emulsions are formed due to IFT reduction as the presence of asphaltenes in the oil continues phase. Figure 13(a) indicates a group of large water droplets, which aggregated and blocked a pore body. Some water droplets are formed at the brineemulsion interface, shown in Figure 13(b) and (c) and some of them are attached to pore surfaces by interception mechanisms as shown in Figure 13(c). Figure 14 also indicates that w/o macro emulsions are formed during waterflooding of E1. As it is shown in Figure 14(a), formation of w/o macro emulsion has blocked a pore throat by straining mechanism. Figure 14(b) and (c) also show



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 35

pore and throat blockage by a group of aggregated w/o macro emulsions. The microscopic images taken during waterflooding of E1 and E3 provide additional support for pressure fluctuations during waterflooding of emulsions at different brine salinity, which is caused by pore throat blockage by w/o macro emulsion and re-distribution of the injected brine interface.

(a)

(b)

(c)

Figure 13. Formation of w/o macro emulsions during waterflooding of E3 with formation brine. (a) Pore blockage by aggregation of water droplets, (b) Formation of water droplets at the brine-emulsion interface, and (c) Interception of water droplets

(a)

(b)

(c)

Figure 14. Formation of w/o macro emulsions during waterflooding of E1 with sea water. (a) Pore throat blockage by straining mechanism, (b) Accumulation of water droplets in pore body, and (c) Pore and throat blockage by aggregation of water droplets

The emulsion recovery performance during the waterflooding of emulsions at different brine salinity is also investigated through comparison of the microscopic displacement process of E1 and E3 at different pore volumes of water injection. Figure 15 and Figure 16 show the brine and emulsion distribution profiles during waterflooding of E1 and E3; respectively. The black and pink areas resemble the emulsion and water phases, respectively. To better compare the emulsion recovery performance during waterflooding of E1 and E3, fluid distribution profiles are chosen at same pore volume of water injection (PVI). A comparison of Figure 15 and Figure 16 shows that during the waterflooding of E3 with higher salinity level, water splits into two main branches and


Page 27 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


fingers through the medium; however, it displaces E1 more uniformly, resulting in higher emulsion recovery. Therefore, as the emulsion salinity (hence, emulsion droplet size) increases, the emulsion final recovery decreases due to more emulsion entrapment. It means that emulsions with larger droplets prevent the invasion of injected brine interface into the emulsion-filled pores. Moreover, the higher interface elasticity during the waterflooding of E1 with seawater leads to a more stable displacement of E1 compared to E3 at the same pore volumes of water injected, resulting in higher emulsion recovery for the case of E1. It should be noted that the emulsion saturation distribution during waterflooding of E1 and E3 has already provided quantitatively in Figure 10.

(a)

(b)

(c)

(d)

Figure 15. Snapshots of fluid distributions during waterflooding of E1 at four different pore volumes of water injected. The black and pink areas represent the emulsion and water phases, respectively. (a) PVI = 0.1, (b) PVI = 0.2, (c) PVI = 0.3, and (d) PVI = 1



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

(a)

(b)

(c)

(d)

Page 28 of 35

Figure 16. Snapshots of fluid distributions during waterflooding of E3 at four different pore volumes of water injected. The black and pink areas represent the emulsion and water phases, respectively. (a) PVI = 0.1, (b) PVI = 0.2, (c) PVI = 0.3, and (d) PVI = 1

3.5. Effect of Injection Rate on Emulsion and Brine Displacement Emulsion droplet entrapment in porous media is a function of droplet to pore size ratio and the capillary number, which is defined as Eq (1). 𝑁𝑐𝑎 =

∆𝑝𝑣𝑖𝑠 𝜇𝑣 = ∆𝑝𝑐𝑎 𝜎

(1)

In this equation, μ denotes displacing phase viscosity (Pa.s); 𝑣 is displacing phase velocity (m/s); and 𝜎 is interfacial tension (N/m). In order to mobilize the captured droplets, a certain local critical capillary number should be attained. At the critical capillary number, viscous forces become large enough to overcome the capillary force, resulting in mobilization of the trapped droplets 35.


Page 29 of 35

In this section, the effect of viscous force on both water and w/o emulsion displacement is investigated by generating capillary desaturation curve (CDC) for the emulsion-brine system. The water injection rate is increased from 0.12 to 20 cc/h in waterflooding of E2 emulsion saturated model. The emulsion injection rate is also increased from 0.003 to 7 cc/h during the flood for Brine B. Figure 17 presents the CDC for E2 with brine B system. As shown in the figure, the emulsion saturation has not changed at low capillary numbers, which implies that the brine phase viscous gradient was insufficient to overcome the high capillary pressure at the droplet, and consequently emulsion droplets remained trapped in pore throats. By increasing the flow rate, viscous force increased to eventually overcome the capillary pressure at a critical capillary number of 1.7×10-5. Above this critical value, the emulsion blockage mechanism no longer occurred, which resulted in a reduction in emulsion saturation. Therefore, the trapping and re-entrainment mechanisms of the w/o emulsion droplets become less effective as the brine flow rate or equivalently, the capillary number, increases above a critical value. The critical capillary number value for viscous force dominant region for the wetting phase (brine B) is around 8.2×10-4, which shows that larger pressure drop is needed to reduce the wetting phase saturation.

0.55

Residual phase saturation

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Brine B E2

0.50 0.45 0.40 0.35 0.30 0.25 0.20 0.15 1e-7

1e-6

1e-5

1e-4

1e-3

1e-2

1e-1

Nca

Figure 17. Capillary desaturation curve (CDC) for E2

Further increase in the capillary number to more than ten times for the emulsion displacement reduces the emulsion recovery by 18%. Figure 18 suggests that to increase the emulsion recovery



by 18 %, the pressure drop required to overcome the capillary forces increases by a factor of 6. This significant pressure drop is related to high viscosity of emulsion droplets; the interfacial rheology effect is also more pronounced at higher emulsion saturation.

60

Ultimate Emulsion Recovery (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 30 of 35

55

50

45

40

35 0.0

0.5

1.0

1.5

2.0

2.5

3.0

Stabilized Differential Pressure (psi)

Figure 18. Pressure drop required for E2 recovery with increasing injection rate

Figure 19 shows successive magnified images of brine-emulsion advancing interfaces in the micromodel during the waterflooding experiments. It is obvious that some trapped emulsions are mobilized at higher injection rates, resulting in higher emulsion recovery.

S

S

E

W

S

S

S S

W

S

S

S

S

S

S

(a)

(b)

(c)

Figure 19. Sequence of emulsion/brine interface advancement in waterflooding at different injection rates of (a) 0.12 cc/h, (b) 3 cc/h and (c) 7 cc/h. S, E and W on figure refer to solid, emulsion and water, respectively.

4. Conclusions


Page 31 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


The effect of brine salinity on w/o emulsion stability, w/o emulsion rheology and w/o emulsion flow behavior was investigated through emulsion stability analysis, emulsion rheological tests and waterflooding tests. Different brine concentrations were prepared based on three different aqueous phases, Persian Gulf brine, an Iranian offshore oil reservoir formation water and a brine with intermediate concentration. Waterflooding experiments were performed in micromodel (as dynamic tests) to examine the displacement mechanism, the effect of injection rate, and the pressure drop behavior of w/o emulsions for various cases. Based on the results for the effect of salinity on w/o emulsion systems, the following conclusions were made in the range of experimental variables tested: 

Emulsion stability analysis revealed that as the brine concentration increased, w/o emulsion droplets became larger due to the higher IFT, rate of aggregation and coalescence and the emulsion stability decreased.



The emulsion viscosity and interfacial tension slightly increased with the brine salinity. Therefore, the emulsion flow performance at different brine salinities was found to be more influenced by the emulsion droplet size distribution, emulsion capturing and re-entrainment mechanisms, and the water-oil interfacial elasticity.



The visualization study revealed that E3 (formation brine-in-crude oil emulsions) with higher salt concentration and larger water droplets blocked more of the pore spaces by means of both straining and interception mechanisms, and caused lower final emulsion recovery.



Higher pressure drop and pressure fluctuations were observed during the waterflooding tests in the micromodel initially saturated with E3 compared to E1 (Persian Gulf seawater-in-crude emulsions). This was due to more emulsion entrapment for the E3 as a results of larger emulsion droplets and their aggregation which caused the invading brine to re-route its path.



A more stable brine-emulsion displacement was observed for E1 because of higher interface elasticity compared to E3. This caused less snap-off happening for E1, resulting in higher final recovery of emulsion for E1 compared to E3.



More re-entrainment of captured water droplets to the main flow stream was observed at higher capillary numbers (higher injection rates), resulting in higher final emulsion recovery during the waterflooding of micromodel saturated with emulsion E2 using bring B.



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60



Page 32 of 35

The emulsion rheological results revealed a small effect of emulsion dispersed brine salinity on the emulsion viscosity; only a mild shear thinning behavior was observed when the concentration of NaCl in the brine increased from 40 to 140 g/L.

Acknowledgments The support by the members of Prof. Shahab Ayatollahi's EOR Research Center at Sharif University of Technology is greatly acknowledged.

References (1) Gewers, C., Colloid and surface chemical problems in non-conventional heavy oil recovery. J. Can. Pet. Technol. 1968, 7, 85-89. (2) Bande, R. M.; Prasad, B.; Mishra, I.; Wasewar, K. L., Oil field effluent water treatment for safe disposal by electroflotation. Chem. Eng. J. 2008, 137, 503-509. (3) Pietrangeli, G. A.; Quintero, L.; Jones, T. A.; Darugar, Q. In Treatment of Water in Heavy Crude Oil Emulsions with Innovative Microemulsion Fluids, SPE Heavy and Extra Heavy Oil Conference: Latin America, 2014; Society of Petroleum Engineers: 2014. (4) Mandal, A.; Bera, A., Modeling of flow of oil-in-water emulsions through porous media. Pet. Sci. 2015, 12, 273-281. (5) Fingas, M.; Fieldhouse, B., Formation of water-in-oil emulsions and application to oil spill modelling. J. Hazard. Mater. 2004, 107, 37-50. (6) Murray, B. S.; Dickinson, E.; Wang, Y., Bubble stability in the presence of oil-in-water emulsion droplets: influence of surface shear versus dilatational rheology. Food Hydrocolloids 2009, 23, 1198-1208. (7) Mohammed, R.; Bailey, A.; Luckham, P.; Taylor, S., Dewatering of crude oil emulsions 2. Interfacial properties of the asphaltic constituents of crude oil. Colloids Surf., A 1993, 80, 237-242. (8) McLean, J. D.; Kilpatrick, P. K., Effects of asphaltene solvency on stability of water-in-crude-oil emulsions. J. Colloid Interface Sci. 1997, 189, 242-253. (9) Wang, X.; Alvarado, V., Direct Current Electrorheological Stability Determination of Water-in-Crude Oil Emulsions†. J. Phys. Chem. B 2009, 113, 13811-13816. (10) Abdel-Raouf, M., Factors affecting the stability of crude oil emulsions. Crude oil emulsions– composition, stability and characterization. Croatia: Intech 2012, 183-204. (11) Kokal, S. L., Crude oil emulsions: A state-of-the-art review. SPE Production & facilities 2005, 20, 513. (12) Schramm, L. L., Fundamentals and applications in the petroleum Industry. Adv. Chem 1992, 231, 324. (13) Mandal, A.; Samanta, A.; Bera, A.; Ojha, K., Characterization of Oil− Water Emulsion and Its Use in Enhanced Oil Recovery. Ind. Eng. Chem. Res. 2010, 49, 12756-12761. (14) McAuliffe, C. D., Crude-oil-water emulsions to improve fluid flow in an oil reservoir. J. Pet. Technol. 1973, 25, 721-726. (15) McAuliffe, C. D., Oil-in-water emulsions and their flow properties in porous media. J. Pet. Technol. 1973, 25, 727-733.


Page 33 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


(16) Wang, J.; Dong, M.; Arhuoma, M., Experimental and numerical study of improving heavy oil recovery by alkaline flooding in sandpacks. J. Can. Pet. Technol. 2010, 49, 51-57. (17) Arhuoma, M.; Dong, M.; Yang, D.; Idem, R., Determination of water-in-oil emulsion viscosity in porous media. Ind. Eng. Chem. Res. 2009, 48, 7092-7102. (18) Arhuoma, M.; Daoyong, Y.; Mingzhe, D.; HENG, L.; Idem, R., Numerical simulation of displacement mechanisms for enhancing heavy oil recovery during alkaline flooding. Energy Fuels 2009, 23, 5995-6002. (19) Shen, P.; Wang, J.; Yuan, S.; Zhong, T.; Jia, X., Study of enhanced-oil-recovery mechanism of alkali/surfactant/polymer flooding in porous media from experiments. Spe Journal 2009, 14, 237-244. (20) Bera, A.; Ojha, K.; Kumar, T.; Mandal, A., Water solubilization capacity, interfacial compositions and thermodynamic parameters of anionic and cationic microemulsions. Colloids Surf., A 2012, 404, 70-77. (21) Bera, A.; Mandal, A.; Ojha, K.; Kumar, T., Water solubilization capacity and conductance behaviors of anionic and cationic microemulsion systems. J. Chem. Eng. Data 2011, 56, 4422-4429. (22) Bera, A.; Mandal, A.; Kumar, T., Physicochemical characterization of anionic and cationic microemulsions: Water solubilization, particle size distribution, surface tension, and structural parameters. J. Chem. Eng. Data 2014, 59, 2490-2498. (23) Islam, M.; Ali, S., Numerical simulation of emulsion flow through porous media. J. Can. Pet. Technol. 1994, 33. (24) Thomas, S.; Ali, S. F., Flow of emulsions in porous media, and potential for enhanced oil recovery. J. Pet. Sci. Eng. 1989, 3, 121-136. (25) Abdul, H.; Ali, S., Combined polymer and emulsion flooding methods for oil reservoirs with a water leg. J. Can. Pet. Technol. 2003, 42. (26) Bai, B.; Han, M.; Li, Y.; Wei, M.; Gao, Y.; Coste, J. In Selective water shutoff technology study and application of W/O emulsions, SPE/DOE Improved Oil Recovery Symposium, 2000; Society of Petroleum Engineers: 2000. (27) Rezaei, N.; Firoozabadi, A., Macro-and Microscale Waterflooding Performances of Crudes which form w/o Emulsions upon Mixing with Brines. Energy Fuels 2014, 28, 2092-2103. (28) Strange, L.; Talash, A., Analysis of Salem Low-Tension Waterflood Test. J. Pet. Technol. 1977, 29, 1,380-1,384. (29) Whiteley, R.; Ware, J., Low-tension waterflood pilot at the Salem unit, Marion County, Illinois Part 1: field implementation and results. J. Pet. Technol. 1977, 29, 925-932. (30) Widmyer, R.; Satter, A.; Frazier, G.; Graves, R., Low-Tension Waterflood Pilot at the Salem Unit, Marion County, Illinois Part 2: Performance Evaluation. J. Pet. Technol. 1977, 29, 933-938. (31) Alvarado, D. A.; Marsden Jr, S., Flow of oil-in-water emulsions through tubes and porous media. Soc. Pet. Eng. J. 1979, 19, 369-377. (32) Soo, H.; Radke, C., A filtration model for the flow of dilute, stable emulsions in porous media—I. Theory. Chem. Eng. Sci. 1986, 41, 263-272. (33) Soo, H.; Williams, M.; Radke, C., A filtration model for the flow of dilute, stable emulsions in porous media—II. Parameter evaluation and estimation. Chem. Eng. Sci. 1986, 41, 273-281. (34) Soo, H.; Radke, C., Velocity effects in emulsion flow through porous media. J. Colloid Interface Sci. 1984, 102, 462-476. (35) Moradi, M.; Kazempour, M.; French, J. T.; Alvarado, V., Dynamic flow response of crude oil-in-water emulsion during flow through porous media. Fuel 2014, 135, 38-45. (36) Guillen, V.; Carvalho, M.; Alvarado, V., Pore scale and macroscopic displacement mechanisms in emulsion flooding. Transp. Porous Media 2012, 94, 197-206.



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 34 of 35

(37) Romero, M. I.; Carvalho, M. S.; Alvarado, V., Experiments and network model of flow of oil-water emulsion in porous media. Phys. Rev. E 2011, 84, 046305. (38) Blunt, M. J., Flow in porous media—pore-network models and multiphase flow. Curr. Opin. Colloid Interface Sci. 2001, 6, 197-207. (39) Blunt, M. J.; Jackson, M. D.; Piri, M.; Valvatne, P. H., Detailed physics, predictive capabilities and macroscopic consequences for pore-network models of multiphase flow. Adv. Water Resour. 2002, 25, 1069-1089. (40) Buchgraber, M.; Al-Dossary, M.; Ross, C.; Kovscek, A., Creation of a dual-porosity micromodel for pore-level visualization of multiphase flow. J. Pet. Sci. Eng. 2012, 86, 27-38. (41) Pak, T.; Butler, I. B.; Geiger, S.; van Dijke, M. I.; Sorbie, K. S., Droplet fragmentation: 3D imaging of a previously unidentified pore-scale process during multiphase flow in porous media. Proc. Natl. Acad. Sci. U. S. A. 2015, 112, 1947-1952. (42) Lenormand, R.; Touboul, E.; Zarcone, C., Numerical models and experiments on immiscible displacements in porous media. J. Fluid Mech. 1988, 189, 165-187. (43) Chang, L.-C.; Tsai, J.-P.; Shan, H.-Y.; Chen, H.-H., Experimental study on imbibition displacement mechanisms of two-phase fluid using micro model. Environ. Earth Sci. 2009, 59, 901. (44) Zhang, C.; Oostrom, M.; Wietsma, T. W.; Grate, J. W.; Warner, M. G., Influence of viscous and capillary forces on immiscible fluid displacement: Pore-scale experimental study in a water-wet micromodel demonstrating viscous and capillary fingering. Energy Fuels 2011, 25, 3493-3505. (45) Maaref, S.; Rokhforouz, M. R.; Ayatollahi, S., Numerical investigation of two phase flow in micromodel porous media: Effects of wettability, heterogeneity, and viscosity. Can. J. Chem. Eng. 2016. (46) Soo, H.; Radke, C. J., Flow mechanism of dilute, stable emulsions in porous media. Ind. Eng. Chem. Fundam. 1984, 23, 342-347. (47) Kang, W.; Xu, B.; Wang, Y.; Li, Y.; Shan, X.; An, F.; Liu, J., Stability mechanism of W/O crude oil emulsion stabilized by polymer and surfactant. Colloids Surf., A 2011, 384, 555-560. (48) Daaou, M.; Bendedouch, D., Water pH and surfactant addition effects on the stability of an Algerian crude oil emulsion. J. Saudi Chem. Soc. 2012, 16, 333-337. (49) McLean, J. D.; Kilpatrick, P. K., Effects of asphaltene aggregation in model heptane–toluene mixtures on stability of water-in-oil emulsions. J. Colloid Interface Sci. 1997, 196, 23-34. (50) Yarranton, H. W.; Hussein, H.; Masliyah, J. H., Water-in-hydrocarbon emulsions stabilized by asphaltenes at low concentrations. J. Colloid Interface Sci. 2000, 228, 52-63. (51) Sjöblom, J.; Urdahl, O.; Børve, K. C. N.; Mingyuan, L.; Saeten, J. O.; Christy, A. A.; Gu, T., Stabilization and destabilization of water-in-crude oil emulsions from the Norwegian continental shelf. Correlation with model systems. Adv. Colloid Interface Sci. 1992, 41, 241-271. (52) Spiecker, P. M.; Kilpatrick, P. K., Interfacial rheology of petroleum asphaltenes at the oil− water interface. Langmuir 2004, 20, 4022-4032. (53) Sztukowski, D. M.; Jafari, M.; Alboudwarej, H.; Yarranton, H. W., Asphaltene self-association and water-in-hydrocarbon emulsions. J. Colloid Interface Sci. 2003, 265, 179-186. (54) Sjoblom, J., Encyclopedic handbook of emulsion technology. CRC Press: 2001. (55) Lashkarbolooki, M.; Ayatollahi, S.; Riazi, M., Effect of salinity, resin, and asphaltene on the surface properties of acidic crude oil/smart water/rock system. Energy Fuels 2014, 28, 6820-6829.


Page 35 of 35

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


(56) Moeini, F.; Hemmati-Sarapardeh, A.; Ghazanfari, M.-H.; Masihi, M.; Ayatollahi, S., Toward mechanistic understanding of heavy crude oil/brine interfacial tension: The roles of salinity, temperature and pressure. Fluid Phase Equilib. 2014, 375, 191-200. (57) Geschke, O.; Klank, H.; Telleman, P., Microsystem Engineering of Lab-on-a-chip Devices. Wiley Online Library: 2004; Vol. 258. (58) Winsor, P., Hydrotropy, solubilisation and related emulsification processes. Trans. Faraday Soc. 1948, 44, 376-398. (59) Moradi, M.; Alvarado, V.; Huzurbazar, S., Effect of salinity on water-in-crude oil emulsion: evaluation through drop-size distribution proxy. Energy Fuels 2010, 25, 260-268. (60) Pal, R., Shear viscosity behavior of emulsions of two immiscible liquids. J. Colloid Interface Sci. 2000, 225, 359-366. (61) Binks, B. P.; Clint, J. H.; Whitby, C. P., Rheological behavior of water-in-oil emulsions stabilized by hydrophobic bentonite particles. Langmuir 2005, 21, 5307-5316. (62) Ariffin, T. S. T.; Yahya, E.; Husin, H., The Rheology of Light Crude Oil and Water-In-Oil-Emulsion. Procedia Eng. 2016, 148, 1149-1155. (63) Pal, R., Effect of droplet size on the rheology of emulsions. AlChE J. 1996, 42, 3181-3190. (64) Alvarado, V.; Moradi Bidhendi, M.; Garcia-Olvera, G.; Morin, B.; Oakey, J. S. In Interfacial viscoelasticity of crude oil-brine: An alternative EOR mechanism in smart waterflooding, SPE Improved Oil Recovery Symposium, 2014; Society of Petroleum Engineers: 2014. (65) Chávez-Miyauchi, T. s. E.; Firoozabadi, A.; Fuller, G. G., Nonmonotonic Elasticity of the Crude Oil– Brine Interface in Relation to Improved Oil Recovery. Langmuir 2016, 32, 2192-2198.

For Table of Contents only (TOC)


The Effect of Dispersed Phase Salinity on Water-in-Oil Emulsion Flow

Recommend Documents