Emulsion Breakage Mechanism using Pressurised Carbon Dioxide

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Emulsion Breakage Mechanism using Pressurised Carbon Dioxide Azlinda Azizi, Zachary M. Aman, Eric F May, Agnes Haber, Nicholas N.A. Ling, Hazlina Husin, and Michael L. Johns Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b00606 • Publication Date (Web): 07 May 2019 Downloaded from http://pubs.acs.org on May 8, 2019

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1 Emulsion Breakage Mechanism using Pressurised Carbon Dioxide Azlinda Azizi1*, Zachary M. Aman1, Eric F. May1, Agnes Haber1, Nicholas N. A. Ling1, Hazlina Husin2, Michael L. Johns1 1Department

of Chemical Engineering, School of Engineering, University of Western Australia, 35 Stirling Highway, Crawley, Western Australia 6009, Australia 2Department

of Petroleum Engineering, Universiti Teknologi PETRONAS, 32610, Seri Iskandar, Perak DR, Malaysia

*Corresponding author: [email protected] ABSTRACT The production of water during crude oil extraction may result in the formation of stable water-in-oil emulsions. Such emulsions are problematic for a variety of reasons; for example they increase the fluid viscosity and hence pumping costs. Previously Ling, et al.1 have shown that treating these water-in-crude oil emulsions with sub-critical CO2 at 50 bar can lead to them breaking. These measurements utilised benchtop nuclear magnetic resonance (NMR) pulsed field gradient (PFG) techniques to monitor the evolution in the emulsion droplet size distribution (DSD), which is a precursor to emulsion breakage.

Experimental limitations meant

however that the measurements were performed only following depressurisation of the applied CO2; and as such were unable to directly distinguish between two potential mechanisms for emulsion breakage as proposed in the literature: (i) CO2 bubble formation within the water droplets upon depressurisation or (ii) the removal of surface adsorbed asphaltenes. Here we develop a new apparatus and perform the required emulsion droplet sizing measurements using NMR PFG techniques with the sample under pressure during CO2 treatment. A distinct growth in droplet size was observed during the treatment, which is consistent with mechanism (ii); however further growth was observed following depressurisation and shown to be consistent with mechanism (i) – both thus are relevant. The efficacy of the treatment was then further assessed for the case of NaCl addition to the aqueous phase. Keywords: Water-in-oil emulsions, magnetic resonance, depressurisation, carbon dioxide, emulsion breaking.

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2

1.0

INTRODUCTION The production of crude oil inevitably also results in the production of

substantial amounts of liquid water – this includes both typically highly saline formation water from the relevant hydrocarbon reservoir and condensed water from any gas phase present. Transportation of the resultant hydrocarbon and water mixture after extraction normally involves multiple exposures to high shear environments (e.g. via inflow control devices)2 which provide suitable conditions for the formation of emulsions. Dependent primarily upon overall composition, metastable water-in-oil emulsions can result, which may lead to a number of operational problems at several stages of oil production. These include both an increased viscosity and production volume leading to higher transport costs, enhanced corrosion and salt deposits in refining equipment and poisoning of refining catalysts.3 Prevention or breakage of such emulsions is complex, costly and generally considered to be poorly understood.e.g. 4, 5 These water-in-crude oil emulsions are stabilised against droplet coalescence, and hence emulsion breakage, by the adsorption of surfactants and/or the presence of organic macromolecules or fine particles at the water-oil interface. A variety of such surface-active agents occur naturally in crude oil, including asphaltenes, resins and oil-soluble organic acids. Asphaltenes and resins are frequently considered to be the most prominent materials active in such emulsion stabilisation6-9 via the formation of a rigid film at the oil-water interface.10,

11.

However a detailed, fundamental understanding of the stabilisation of such waterin-oil emulsions is currently lacking.12 Several methods for breaking such water-in-crude oil emulsions are currently applied in industry. These include the addition of demulsifier chemicals, heating,

distillation,

filtering,

electrostatic

coalescing,

centrifugation

and

gravitational settling.13-17 The addition of chemical demulsifiers is widely practiced18 but requires frequent revision to be suitable for particular reservoir crude oil and water chemistries19 and can often result in significant aqueous phase contamination. The alternatives listed above are generally expensive and/or require a comparatively large amount of energy.20 An alternative to break such emulsions,


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3 which is potentially cheap and which results in minimal effluent contamination, is the use of CO2 at sub-critical conditions. Ling, et al.1 used Nuclear Magnetic Resonance (NMR) Pulsed Field Gradient (PFG) to monitor the temporal evolution in droplet size distribution for water-in crude oil emulsions subject to exposure (treatment) with sub-critical CO2. At pressures of the order of 50 bar, a substantial increase in water droplet size was observed (relative to an untreated sample) for multiple crude oil types. Such droplet coalescence and hence growth is a natural precursor to the breaking of such an emulsion.

The mechanism whereby CO2 break these emulsions is however the

subject of some conjecture. In literature two mechanisms are detailed (albeit for supercritical CO2): Mechanism 1, as proposed by Sjoblom et al.12 focuses on the formation of CO2 bubbles in the aqueous droplet phase following depressurisation of the CO2 treated emulsion, due to reduced solubility. These bubbles serve to rupture the water-oil interface, in the process promoting droplet coalescence. Mechanism 2, as proposed by Zaki, et al. 21 is that asphaltenes precipitate upon CO2 saturation of the oil phase under pressure, resulting in asphaltene removal from the oil-water interface and hence emulsion destabilisation. Ling, et al.1 concluded that Mechanism 2 was more likely given that emulsion destabilisation upon CO2 treatment was not observed for model water-in-oil emulsions featuring no asphaltenes. This was concluded on the basis of nuclear magnetic resonance (NMR) pulsed field gradient (PFG) measurements of the evolving droplet size distributions. NMR PFG measurements of emulsion droplet size are well established22-28 and have been widely applied to water-in-crude oil emulsions; they are readily applied to opaque, concentrated and complex emulsion structures. As a consequence of equipment constraints however Ling, et al.1 only performed these measurements of water-in-oil emulsion droplet size distributions after depressurisation following CO2 treatment. In the current work we have developed and adapted the equipment such that the measurements can be performed under pressure during CO2 treatment, thus allowing a much more direct investigation of the relative contribution of Mechanism 1 and Mechanism 2 to the observed emulsion destabilisation.

Specifically, any observation of emulsion


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4 destabilisation during CO2 treatment could only be attributed to Mechanism 2 as Mechanism

1

operates

only

post-treatment

following

depressurisation.

Furthermore we progress to observe the extent of this emulsion destabilisation via CO2 treatment for brine solution-in-crude oil emulsions, which are directly relevant to oil fields featuring significant formation water content. 2.0

METHODOLOGY

2.1

Emulsion Preparation In the work conducted here, water-in-oil emulsions were formed using two

different local West Australian crude oils. These are hereafter referred to as Crude Oil A and Crude Oil B (and their emulsions as Emulsion A and Emulsion B); basic properties of these oils are listed in Table 1. Both are able to readily form water-in crude oil emulsions that are stable over 7 days. Table 1: Crude oil characteristics Crude Oil

Density (g/mL)1

Viscosity (mPa.s)2 at 20 °C

1

A

0.83

13

B

0.75

150

determined gravimetrically

2 determined

using a TA Instruments DHR-3 controlled stress Rheometer

Water-in-oil emulsions were formed using either 30 wt % deionised (DI) water or 30 wt % brine solution (1 wt% NaCl in DI water); in the case of crude oil A the viscosity (20 °C) increased from 13 to 30 mPa.s and in the case of crude oil B the viscosity (20 °C) increased from 150 to 300 mPa.s. They were prepared by adding the aqueous phase drop-wise to the crude oil whilst mixing, followed by shearing at 17,500 rpm for 10 minutes using a high-speed Miccra D-9 homogeniser manufactured by ART Prozess & Labortechnik GmbH & Co. All emulsions were prepared and stored at room temperature (~22 °C). 2.2

Emulsion Treatment Cell


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5 An emulsion CO2 treatment cell was constructed out of PEEK (polyether ether ketone), which was able to operate safely at pressures up to 100 bar. This is schematically shown in Figure 1(a). The emulsion is accommodated at the bottom of the 6 mm outer diameter cell to a height of 19 mm, which is fully contained within the detection region of the NMR r.f. coil deployed. 50 bar CO2 is supplied by a 1 mm inner diameter high pressure PEEK tube with its exit submerged in the emulsion sample. CO2 is thus allowed to bubble through the emulsion sample at a flowrate of 0.5 ml/s (STP) before being removed from the cell at the top using 1 mm inner diameter high pressure PEEK tubing. During all required NMR measurements under pressure (i.e. at 50 bar), the exit valve (Valve 2) is closed and the flow of CO2 hence stopped. Figure 1(b) shows a photo of the cell and its positioning within the NMR magnet used.

(a)

(b) Figure 1: (a) Schematic Diagram of PEEK emulsion CO2 treatment cell with CO2 gas supply at 50 bar. (b) Photo of the cell and its accommodation within the Bruker Minispec spectrometer magnet.


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6

2.3

Nuclear Magnetic Resonance (NMR) Measurements The NMR hardware used for this study was a commercially available

benchtop NMR Minispec mq Bruker spectrometer, with a 1H resonance frequency of 20 MHz. The Bruker Minispec features a 4 T/m gradient for pulsed field gradient (PFG) measurements of self-diffusion and is designed to accommodate 10 mm (outer diameter) NMR sample tubes. As detailed above, the PEEK emulsion CO2 treatment cell fits into this tube space in the permanent magnet. The magnet and sample were all maintained at a temperature of 39 °C during both CO2 treatment and NMR measurements. All PFG measurements for emulsion droplet sizing were performed using a modified stimulated echo pulsed field gradient (SSE-PFG) pulse sequence as shown in Figure 2. It should be noted that the Bruker Minispec has no chemical shift resolution (its magnetic field is not sufficiently homogeneous) to directly distinguish the oil and water 1H NMR spectral peaks; this distinction is achieved here by exploiting differences in the T1 relaxation time of oil and water respectively (T1,water > T1,oil; it should be noted that the T1,oil for crude oil is not a single value but a distribution of values). This is achieved via a 180° radio frequency (r.f.) pulse which is introduced at the pulse sequence initiation, followed by a time delay (Tinv) equal to the NMR signal null point of the oil (0.693 T1,oil). Implementing this for a distribution of T1,oil, so as to eliminate the oil signal, thus allowing only the aqueous phase signal to be detected, requires a suitable combination of the following timing parameters in Figure 2: , Tinv and TR. Further details of this NMR signal selection process are provided in Fridjonsson, et al. 29 The observation time (Δ) used for all measurements was 300 ms, the gradient pulse length (δ) was 4 ms, and the gradient strength (g) was increased from 0.05 to 2.0 T/m in 16 increments. Independent measurements of the T1 distribution for the emulsion were also performed using a standard inversion recovery pulse sequence. This is necessary in order to determine the dominant T1 peak for the oil signal contribution in order to effect complete oil signal suppression allowing the water NMR 1H signal to be used exclusively for emulsion droplet sizing.


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7

TR 90°

180° Tinv

rf

τE

tdelay

δ

τE

Homospoil gradient

g g g g

g

Stimulated 180° Echo

90°

90°

g

Δ

Figure 2: Modified SSE PFG pulse sequence with initial 180° radio frequency (r.f.) pulse to eliminate the dominant oil signal to allow for emulsion DSD measurements. (adapted from Fridjonsson, et al. 29)

NMR PFG techniques are routinely used for the determination of the free diffusion coefficient, D, of a fluid via application of the Stejskal Tanner equation;22 𝑆 𝑆𝑜

[

]

𝛿

.

= exp ―𝐷(𝛾𝑔𝛿)2( △ – 3)

(1)

Here S is the measured NMR signal, S0 is the signal measured when g = 0, g is the magnetic field gradient applied, δ is the duration of the magnetic field gradient applied, γ is the gyromagnetic ratio of the nucleus (1H = 2.68 × 108 T−1 s−1, which was exclusively detected in the work presented here), and Δ is the time interval between two gradient pulses. For the case of the water-in-oil emulsions, the diffusion of the water molecules is restricted by the spherical boundary of the droplet. This restricted diffusion results in a decreased reduction in S as a function of g. In this case, the NMR signal attenuation (I = S(g)/S(g=0)) can be approximated as:30 1

∞

[

ln 𝐼(𝐷, 𝑎, 𝑔,𝛿) = ―2𝛾2𝑔2∑𝑚 = 1𝛼2 (𝛼2 𝑎2 ― 2) 𝑚

2

2

𝑚

2𝛿 𝛼2𝑚𝐷

―

2

𝛹

]

(2a)

2 (𝛼2𝑚𝐷)

2

𝛹 = 2 + 𝑒𝑥𝑝 ― 𝛼𝑚𝐷(𝛥 ― 𝛿) ―2𝑒𝑥𝑝 ― 𝛼𝑚𝐷𝛥 ―2𝑒𝑥𝑝 ― 𝛼𝑚𝐷𝛿 + 𝑒𝑥𝑝 ― 𝛼𝑚𝐷(𝛥 + 𝛿) , (2b) where a is the droplet radius, and αm is the mth positive root of the following equation:


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8 1

𝐽5(𝑎α) ― 𝑎𝛼𝐽3(𝑎𝛼) = 0 2

2

,

(2c)

where Jk is a Bussel function of the first kind of order k. Hence by measuring I as a function of g, it is possible to extract the droplet radius, a, using Equation 2. Equation 2 assumes a Gaussian shape for the NMR signal phase distribution (and is hence known as the Gaussian phase distribution (gpd) model). It is also possible to arrive at a variant of Equation 2 by assuming that there is no diffusion during  (the short gradient pulse (sgp) method).23, 30 Lingwood, et al. 31 however showed that it is possible to effectively eliminate the assumptions of both

the gpd and sgp model via use of the block gradient pulse (bgp) method when using NMR PFG to size emulsion droplets. This is based on the general gradient waveform set of methods, it has been employed widely in our previous publicationse.g. 1, 29, 32-34 and is used for the required NMR PFG data analysis in this work. Equation 2 and the bgp method are valid only for an emulsion with a single droplet size. For a distribution of droplet radii, P(a), as is the case for the work presented here, the measured NMR signal (I(D, g, δ)) is given by:30 ∞

𝐼(𝐷,𝑎, 𝑔, 𝛿) =

∫0 𝑎3𝑃(𝑎)𝐼(𝐷,𝑎, 𝑔, 𝛿) 𝑑𝑎 ∞

∫0 𝑎3𝑃(𝑎) 𝑑𝑎

(3)

The extraction of P(a) from Equation 3, is an ill-conditioned and unstable matrix inversion problem. However it may be rendered numerically stable using Tikhonov regularisation to invert Equation 335. The Tikhonov regularisation method has been widely demonstrated and validated in our previous work e.g. 1, 29, 32, 33 to accurately determine P(a) based on appropriate measurements of I(D, g, δ).


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9 3.

RESULTS AND DISCUSSIONS

NMR Relaxation Measurements Figure 3(a) shows NMR T1 relaxation time distributions for the water-incrude oil and brine-in-crude oil emulsions (both for Emulsion A and B respectively). These were acquired prior to pressurisation (treatment) with CO2. Consistent with previous literature featuring similar water-oil emulsions e.g. 29, 36, Figure 3(a) shows a broad T1 distribution for the crude oil phase (partially reflecting its complex heterogeneous chemical composition); however it is quite distinct from the narrower single water T1 peak. Consequently we are able to use T1 signal relaxation to eliminate the signal from the oil phase allowing only the water signal to be detected and thereby enable emulsion droplet sizing for the water-in-oil emulsions. Emulsions B feature slightly shorter oil T1 values, which is consistent with its more viscous character (Table 1). During treatment with 50 bar CO2 for a period of 12 hours it was observed that the T1 relaxation distribution for the oil phase shifted slightly to larger values; this occurred as CO2 dissolved into the oil phase rendering it less viscous. The final T1 distributions for both Emulsion A and Emulsion B are shown in Figure 3(b). The crude oil peaks and the water peak are slightly closer together but still sufficiently distinct to allow for adequate oil signal suppression. Upon depressurisation the T1 distribution for the oil phase returned to its original value before CO2 treatment. A practical consequence of this is that it was necessary to measure the T1 distribution prior to every self-diffusion measurement such that effective signal suppression of the oil signal could be achieved – this was hence done for all diffusion and hence emulsion droplet sizing measurements performed in this work.


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10

(a)

(b)

Figure 3: T1 relaxation time for water- and brine-in-oil emulsions for Emulsion A and Emulsion B (a) before CO2 pressurisation and (b) after CO2 pressurisation for 12 hours. The broader, multi-modal distribution of T1 values for the crude oil phases reflects the range of components within the oils. The oil T1 peaks generally shifted to slightly higher values following pressurisation due to the viscosity reduction associated with increased solubility of the CO2 in the emulsions.

NMR Droplet Sizing of Water-in-Crude Oil Emulsions Sample water-in-crude oil emulsion droplet size distributions are shown in Figure 4 for (a) Emulsion A and (b) Emulsion B respectively. These correspond to both during pressurisation (4 and 12 hours after commencement of CO2 injection) and after depressurisation at 13 hours (16 and 24 hours after commencement of CO2 injection). The initial pressurisation of the emulsion is referenced as time zero. In both cases, a substantial increase in emulsion droplet size is observed following the application of CO2 with further increases observed following depressurisation. During treatment, the increase in mean droplet size is approximately linear suggesting that the system is adequately saturated with CO2. The data acquired post depressurisation is broadly consistent with the post CO2 treatment measurements of emulsion droplet size by Ling, et al.1 Using the measured emulsion size distributions, as shown in Figure 4, it is readily possible to extract the mean emulsion droplet size; this resultant data for all measurements performed is shown in Figure 5(a).

Note that measurement of emulsion droplet size was not possible for

approximately 3 hours following depressurisation due to excessive sample foaming. To act as a reference, droplet sizing measurements were also performed on the initial untreated emulsions prior to the commencement of CO2 treatment and after a ACS Paragon Plus Environment

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11 period of 35 hours with no CO2 treatment applied (hereafter referred to as the control emulsions).

(a)

(b)

Figure 4: Droplet Size Distributions for water-in-oil emulsions for (a) Emulsion A and (b) Emulsion B, both before and after CO2 pressurisation. An increase in the droplet size is observed both during pressurisation and following depressurisation.

(a)

(b)

Figure 5: Mean droplet sizes for all emulsions, (a) both those treated with CO2 (with measurements performed during CO2 pressurisation and following depressurisation) and the control emulsions. All treated emulsions undergo a substantial and permanent increase in mean droplet size. This was not observed for the control emulsions over a period of 35 hours. (b) For Emulsion A (Exp. 2), the pressurisation time was reduced from 12 hours to 6 hours.


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12 The substantial increase in mean droplet size is immediately obvious for all treated emulsions and is more than an order of magnitude larger than the mean droplet size variations of 1-2 microns observed for the control emulsions over a 35 hour period. All treated emulsions also showed a substantial increase in mean emulsion droplet size during CO2 pressurisation (treatment).

This can only be

consistent with Mechanism 2, as proposed by Zaki, et al.21 as outlined above, whereby CO2 oil saturation precipitates out asphaltenes from the oil phase, consequently stripping them off the surface of the emulsion droplets to re-establish chemical equilibrium and hence rendering the emulsion less stable. proposed by Sjoblom, et al.

12

Mechanism 1, as

in which CO2 bubbles form in the aqueous phase

following depressurisation, is obviously not operational during this treatment time period. However following depressurisation (which took 1 minute to complete), for Emulsion A and B and which had been pressurised/treated for 12 hours, the mean emulsion droplet size is seen to continue increasing – this could either be the consequence of inevitable emulsion droplet growth in an already significantly destabilised emulsion (i.e. a critical emulsion droplet size has been exceeded beyond which the emulsion rapidly destabilizes) or it could be that Mechanism 1 has contributed to emulsion destabilisation during depressurisation. Consequently a second experiment using Emulsion A was conducted (Emulsion A (Expt 2) in Figure 5(b)) in which the emulsion was subject to only 6 hours of CO2 treatment. In this case a substantial increase in droplet size is again observed during CO2 treatment; albeit it at a lower rate compared to Expt 1 (presumably due to subtle variations in crude oil composition; the measurements were performed six months apart). A further increase in mean droplet size is observed following depressurisation, however the resultant emulsion remains remarkably stable thereafter over a 5 hour period. This is only consistent with both Mechanism 2 and Mechanism 1 contributing to emulsion destabilisation and consequential growth in mean emulsion droplet size. NMR Droplet Sizing of Brine-in-Crude Oil Emulsions Figure 6(a) and (b) show sample emulsion droplet size distributions for Emulsion A and B respectively using a 1 wt% NaCl brine solution as the aqueous droplet phase. The CO2 treatment process is identical to that applied to the waterin-crude oil emulsions. What is immediately obvious, in contrast to the results in Figure 4, is that the addition of the NaCl has clearly resulted in considerably more ACS Paragon Plus Environment

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13 stable emulsions; this is consistent with previous observations we have made on similar water-in-crude oil emulsions observed over a time frame of weeks.37-38 This is more succinctly evident in Figure 7, which shows the mean emulsion droplet size for all emulsion droplet sizing data acquired using brine-in-crude oil emulsions subject to CO2 treatment. We note that this observation is not broadly consistent with the frequent observation that asphaltene deposition increase in the presence of brine39; this will be the subject of future work. With reference to Figure 7, a small increase in mean droplet size during CO2 treatment is evident; this amounts to a doubling of the mean emulsion droplet size whereas the control emulsion subject to no CO2 treatment shows no significant change (as is evident in Figure 7). The increase in mean droplet size is collectively summarised in Table 2, which tabulates the initial and maximum mean emulsion droplet size for the water-in-oil and brinein-oil emulsions subject to 12 hours of CO2 treatment.

(a)

(b)

Figure 6: Droplet Size Distributions for brine-in-crude oil emulsions formed using (a) Emulsion A and (b) Emulsion B, both during and after CO2 pressurisation. A slight increase in droplet size is observed as a consequence of the CO2 treatment.


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14

Figure 7: Mean droplet sizes for brine-in-crude oil emulsions for both Emulsion A and Emulsion B as a function of time during and after 12 hours of CO2 treatment. A small increase in mean droplet size is evident relative to the control emulsion. Table 2: Means Emulsion Droplet Size Type of Emulsions

Emulsion A

Emulsion B

(μm)

(μm)

Water-in-Oil

Initial

3.3

2.7

Emulsion

Max.

27

26

Brine-in-Oil

Initial

3.0

2.7

Emulsion

Max.

5.9

4.9

Following depressurisation, no increase in emulsion droplet size is discernible in Figure 7 (as was the case for the water-in-crude oil emulsions). In fact a slight decrease in droplet size is observed (however it still significantly exceeds the mean droplet size measured for the control emulsion); this effect was observed to be reproducible. Emulsions formed with the brine solution produced significantly more foam compared to those prepared with water; it is possible that this is the cause of this slight reduction in mean droplet size following depressurisation, however further investigation is required. Nevertheless for these brine-stabilised emulsions, Mechanism 2 is definitely operating (i.e. droplet size increase during CO2 pressurisation) whereas there is no evidence of Mechanism 1 occurring (i.e. no significant change in emulsion droplet size following depressurisation).


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15

4.0

CONCLUSIONS NMR PFG techniques were successfully used to monitor the in-situ temporal

evolution in emulsion droplet size for two different water-in-crude oil emulsions during treatment with 50 bar CO2 gas (which was bubbled through the emulsion systems). A significant increase in mean emulsion droplet size was observed during treatment, which is consistent with Mechanism 2 (as proposed in the literature) whereby asphaltenes are removed from the interface between the oil and water following CO2 dissolution into the oil phase. Further growth in mean droplet size was observed following depressurisation, which is consistent with Mechanism 1 (as proposed in the literature) in which CO2 bubbles form on depressurisation and rupture the emulsion droplet interface, destabilising the emulsion in the process. However when the CO2 treatment was applied to brine-in-crude oil emulsions (which form inherently more stable emulsions) only Mechanism 2 was observed to occur, albeit to a much reduced extent.


Energy & Fuels 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 5.0 REFERENCES

1. Ling, N. N. A.; Haber, A.; Hughes, T. J.; Graham, B. F.; May, E. F.; Fridjonsson, E. O.; Johns, M. L., NMR Studies of the Effect of CO2 on Oilfield Emulsion Stability. Energy & Fuels 2016, 30, (7), 5555-5562. 2. Arnold, R.; Burnett, D. B.; Feeley, T. J.; Galbrun, M.; Hightower, M.; Jiang, Z.; Khan, M.; Lavery, M.; Luffey, F.; Verbeek, P., Managing Water-From Waste to Resource. Oilfield Review 2004. 3. Hernández, E. I.; Castro-Sotelo, L. V.; Avendaño-Gómez, J. R.; Flores, C. A.; Alvarez-Ramírez, F.; Vázquez, F., Synthesis, Characterization, and Evaluation of Petroleum Demulsifiers of Multibranched Block Copolymers. Energy Fuels 2016, 30, (7), 5363-5378. 4. Hussein, A.; Moin, M.; Ardi, S.; Dubey, S.; Vreenegoor, L.; Saleh, J., Rheology of Heavy Oil Emulsions. SPE Production and Operations August 2007, 22 (3), 285−293. 5. Been, J.; Crozier, B.; Mosher, M.; Mosher, W.; Tsaprailis, H., Internal Corrosion of Crude Oil Pipelines Research. Alberta Innovates Technology Futures 2012. 6. Yan, Z.; Janet, A. W. E.; Jacob, H. M., Roles of Various Bitumen Components in the Stability of Water-in-Diluted-Bitumen Emulsions. J. Colloid Interface Sci. 1999, 220, 329–337. 7. 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. 8. Gafonova, O. V.; Yarranton, H. W., The Stabilization of Water-in-Hydrocarbon Emulsions by Asphaltenes and Resins. J. Colloid Interface Sci. 2001, 241, 469-478. 9. Spiecker, P. M.; Gawrys, K. L.; Kilpatrick, P. K., Aggregation and solubility behavior of asphaltenes and their subfractions. J. Colloid Interface Sci. 2003, 178193, 178–193. 10. Abdel-Aal, H. K.; Aggour, M. A.; Fahim, M. A., Crude Oil Stabilization and Sweetening. In book: Petroleum and Gas Field Processing. Marcel Dekker, Inc. 2003, Chapter 7, 188-200. 11. Kokal, S. L., Crude Oil Emulsions. In: L. W. Lake ed. Petroleum Engineering Handbook; Fanchi, J. R., Ed., Texas. Society of Petroleum Engineers 2006, 1, 533–570. 12. Sjoblom, J.; Kallevik, H.; Westvik, A.; and Auflem, I., H, Process for separation of oil, water and gas in a separator by breaking of water-in-oil emulsions. P 4202-1 2002, PCT-Application. 13. Angle, C. W., Chemical Demulsification of Stable Crude Oil and Bitumen Emulsions in Petroleum Recovery—A Review. In book: Encyclopedic Handbook of Emulsion Technology; Sjoblom, J., Ed.; Marcel Dekker: New York 2001, Chapter 24, 541-594. 14. Eow, J. S.; Ghadiri, M., Electrostatic Enhancement of Coalescence of Water Droplets in Oil: A Review of the Technology. J. Chem. Eng. 2002, 85, 357-368. 15. Warren, K. W., Emulsion Treating. in Petroleum Engineering Handbook: Facilities and Construction Engineering; Arnold, K. E., Ed.; Society of Petroleum Engineers 2006, 3, 63-122. 16. Balsamo, M.; Erto, A.; Lancia, A., Chemical Demulsification of Model Water-inOil Emulsions with Low Water Content by Means of Ionic Liquids. Brazilian J. Chem. Eng. 2017, 34, (1), 273-282. ACS Paragon Plus Environment

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Emulsion Breakage Mechanism using Pressurised Carbon Dioxide

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