Quantifying the Effect of Salinity on Oilfield Water ... - ACS Publications

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Quantifying the Effect of Salinity on Oilfield Water-in-Oil Emulsion Stability Nicholas N.A. Ling, Agnes Haber, Brendan Francis Graham, Zachary M. Aman, Eric F May, Einar Orn Fridjonsson, and Michael L. Johns Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b02143 • Publication Date (Web): 31 Jul 2018 Downloaded from http://pubs.acs.org on August 1, 2018

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Quantifying the Effect of Salinity on Oilfield Water-in-Oil Emulsion Stability N.N.A. Ling, A. Haber, B.F. Graham, Z.M. Aman, E.F. May, E.O. Fridjonsson, M.L. Johns* School of Mechanical and Chemical Engineering, The University of Western Australia, 35 Stirling Highway, CRAWLEY WA 6009, Australia

Abstract The effect of salinity on water-in-oil emulsions was systematically studied using a combination of Nuclear Magnetic Resonance (NMR) pulsed field gradient (PFG) measurements of emulsion droplet size distribution complemented by interfacial tension measurements using the pendant drop method. Long-term emulsion stability over periods of up to five days was found to increase with salinity; this was shown to be independent of whether a monovalent (NaCl) or a divalent (CaCl2) salt was used. The methodology was applied to water-in-oil emulsions formulated with crude oil, paraffin oil, xylene, crude oil with reduced asphaltene content and crude oil with reduced organic acid content as the continuous phase, respectively. In all cases, emulsion stability increased consistently with aqueous phase salinity, with no discernible difference between the continuous oil phases with respect to the extent of this stabilisation. The enhanced stability could thus not be attributed to differences in density, interfacial tension or dielectric permittivity. This leaves a potential increased surface accumulation of stabilising surface active species driven by increasing salinity as the most plausible explanation for the observations reported here. Keywords: oilfield emulsions, PFG NMR, droplet size distribution, salinity

Destination: Energy & Fuels * Corresponding author: [email protected]

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1.

Introduction and Background

In 2016, worldwide consumption of crude oil reached ~97 million barrels per day.1 Most of the required crude oil is produced in the form of an emulsion (approximately 80-95% of all crude oils existing at some stage in an emulsified state)2 which in order to be refined needs to go through multiple separation and purification stages. Such water-in-oil (w/o) emulsions are frequently formed and stabilised during oil production (e.g. due to high pressure drops through choke valves and pumps) and are usually already present when the produced fluids reach the primary gas-water-oil separation vessel. The resulting operational problems are numerous and include:3-5 enhanced corrosion from dissolved salts in the water phase, flow assurance concerns and/or hydrate formation, and difficulty meeting crude oil product specifications. The emulsions typically consist of micron-scale water droplets stabilised in a continuous oil phase. Problematic w/o emulsions are particularly acute for older, more marginal oilfields, which are typically characterised by higher water cuts, silt and asphaltene content.6 Surface active species in crude oil such as asphaltenes, resins, wax, naphthenic acids and fine particles are known to contribute to the stability of oilfield emulsions.e.g. 3, 4, 7 Particularly for the case of formation water, these emulsions are in practice characterised by a range of droplet (water) phase salinities. Whilst a significant amount of literature focusses on the effect of various potential surface agents on oilfield emulsion stability, the focus of the work presented here will be on the effects of salinity on this emulsion stability. It is generally accepted that natural surfactants within the asphaltene/resin content of crude oil are responsible for stabilising water-in-crude oil (w/o) emulsions7 by adsorbing at the water-oil interface forming a rigid film that resists droplet coalescence. Such emulsion stability is also thought to be strongly influenced by naphthenic acids in the crude oil3. Increasing salinity of the water phase is also very widely reported in the literature to reduce the interfacial tension (IFT) between the aqueous phase and crude oil,e.g. 8 plausibly as a consequence of increasing the ‘ionic surfactant’ character of the absorbed asphaltene film. This reduced interfacial tension as salinity increases should render more stable water-in-crude oil (w/o) emulsions as it reduces the driving force for droplet coalescence. Stabilisation of w/o emulsions by increasing salinity is often reported in the literature: for example, Rocha, et al. 9 observed an increase in water-incrude oil emulsion stability (defined as % water recovered after 10 hours of sequential heat treatment and centrifugation) with salinity up to a concentration of 0.1 wt% NaCl. Beyond the oil industry, Márquez, et al. 10 observed that an increase in salinity (primarily via CaCl2 addition) resulted in more stable water-in-sunflower oil emulsions (as observed using optical backscattering measurements). There is however considerable scepticism e.g. 8, 11 that the observed reduction in interfacial tension as a function of increased salinity of the aqueous phase is primarily responsible for this observed increase in emulsion stability. In terms of the mechanism whereby salinity affects emulsion stability, there is no persuasive consensus in the literature. Rocha, Baydak, Yarranton, Sztukowski, Ali-Marcano,


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Gong, Shi and Zeng 9 proposed that the increased w/o emulsion stability with salinity observed in their measurements was a consequence of an increase in the concentration of asphaltenes adsorbed at the interface, whilst Márquez, Medrano, Panizzolo and Wagner 10 attributed similar behaviour to a combination of smaller initial water droplets for saline systems, an increased surface adsorption of the surfactant deployed (poly glycerol polyricinoleate) and a reduction in attractive forces between droplets as a consequence of a reduction in the dielectric permittivity difference between the aqueous and oil phases. Interestingly both Rocha, Baydak, Yarranton, Sztukowski, Ali-Marcano, Gong, Shi and Zeng 9 and Márquez, Medrano, Panizzolo and Wagner 10 observe an increase in surface film compressibility as salt concentration increases, which is not consistent with a more rigid surface film forming as salt concentration increases. In summary, potential (not necessarily independent) reasons for increased emulsion stability with salinity are: • Reduction in interfacial tension between the oil and aqueous phases • Concentration increase in adsorbed surface active species • Smaller initial droplets upon emulsion formation • Reduction in droplet-droplet attraction due to a reduction in dielectric permittivity differences between the aqueous and oil phases • Increase in density difference between the oil and aqueous phases For completeness we note that the relevant literature is also not unanimous regards this salinityemulsion stability relationship and includes a few examples where increasing salinity was reported as resulting in less stable emulsions: Moradi, Alvarado and Huzurbazar 5 and Wang and Alvarado 12 both consider water-in-crude oil emulsions and report that increased salinity promotes droplet coalescence and hence decreases emulsion stability. Moradi, Alvarado and Huzurbazar 5 used optical microscopy to observe droplet size, whilst Wang and Alvarado 12 used centrifuged bottle tests, and hence water recovery, to assess emulsion stability. Nuclear Magnetic Resonance (NMR), a completely non-invasive technique, via the application of pulsed field gradients (PFG) is able to measure the restricted self-diffusion of molecules, which for droplet phase molecules in emulsions can be exploited to determine droplet size distributions.e.g.13-16 This methodology has found wide application, including for the characterisation of oilfield emulsions.e.g. 17-19 It is readily applied to emulsions that are opaque and concentrated, and requires no sample manipulation prior to measurement. Previously, we have applied this measurement technique to consider the effect of NaCl concentration on emulsion stability as a complement to a study concerning hydrate particle stability.20 There 0.1 wt% NaCl was shown to stabilise a 30 wt% water–in-crude oil emulsion against droplet coalescence over a five-day period. Here we significantly extend this initial measurement to consider the effect of salinity, over the range 0 – 1 wt% NaCl, on long term emulsion stability over several days. We then proceed to replace NaCl with (divalent) CaCl2 and repeat the stability measurements. We also consider the effect of salinity on water-in-xylene and water-inparaffin oil emulsions stabilised by non-ionic surfactants. Finally, in order to consider the effect of salinity on the surface-active components of crude oil, we repeat the measurements with crude oils whose asphaltene or naphthenic (organic) acid content had been substantially reduced.


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2.

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Methodology

2.1.

Emulsion Preparation All emulsions were prepared by first dissolving the required amount of salt in deionised (DI) water and then adding it to the relevant oil at the required water cut. This was then mixed vigorously for 10 minutes using a high speed Miccra D-9 homogenizer manufactured by ART Prozess & Laborthechnick GmbH at a shear rate of 17,800 rpm. During the mixing process the sample temperature was consistently below 35 °C, all emulsion samples were then stored at 22°C prior to measurement with NMR. Table 1 below summarises the pertinent properties of the emulsions prepared, each repeated with the addition of 0, 0.01, 0.1 and 1 wt% NaCl or CaCl2 to the aqueous phase respectively. These salinities are reported in Table 2 along with the standard solution ionic strengths calculated according to the corresponding ionic strength equation21 and the solution density.22 Table 1: Emulsion test samples. Emulsion

Droplet Phase Continuous Phase Continuous Continuous (wt%) Phase Density Phase Viscosity Water Crude Oil 0.81g/mL 10 mPa·s A (30 wt%) (25°C) 0.80 g/mL 10 mPa·s Water Crude Oil (Reduced B (30 wt%) Asphaltenes) (25°C) Water Crude Oil (Reduced 0.80 g/mL 10 mPa·s C (30 wt%) Organic Acids) (25°C) Water Paraffin Oil 0.83 g/mL 110 mPa·s D (20 wt%) (Span80 – 0.5 wt%) (20°C) Water Xylene 0.86 g/mL 0.62 mPa·s E (20 wt%) (Span80 – 1 wt%) (20°C) Note: The densities and viscosities of crude oils were measured, whilst the densities and viscosities of paraffin oil and xylene were obtained from the relevant product data sheets. The oil treatment procedures for Emulsions B and C are outlined below.

Table 2: Ionic strength and densities of different brine samples Brine Sample (wt%) 0% 0.01% NaCl 0.10% NaCl 1.00% NaCl 0.01% CaCl2 0.10% CaCl2

Ionic Strength (M) 0 0.0017 0.0171 0.1711 0.0027 0.0273

Solution Density (g/mL) 0.997 0.997 0.998 1.00 0.997 0.998


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The crude oil was sourced from a local West Australian producer. All other chemicals were purchased from Sigma Aldrich at purities in excess of 99%. Given that organic acids and asphaltenes are often considered as natural surfactants23-26 that stabilise water-in-crude oil emulsions, Emulsion B and C which feature significantly less of these two components, respectively, were prepared to explore such interactions. The continuous crude oil phases of Emulsions B and C were prepared as follows (mimicking their preparation in our recent publication,27 which explored the effect of CO2 on emulsion stability): Asphaltene reduction:28 the crude oil was initially diluted with hexane using a volume ratio of 1:30. Subsequently, the diluted crude oil was mixed vigorously and allowed to rest for 24 hours to allow for the formation of laboratory-precipitated asphaltenes which are (by definition) insoluble in hexane. The sample was then coarsely filtrated using 40 µm and 10 µm filter membranes, following by fine filtration using a 0.41 µm filter membrane. The amount of precipitated asphaltenes was gravimetrically determined to be ~0.31 wt%. The filtrate (asphaltene reduced crude oil and hexane) was heated to ~ 70°C and the hexane was evaporated using a rotary evaporator. The crude oil was thus recovered and used to produce Emulsion B. Organic Acid reduction:29 A filtration process was applied. This requires the activation of a sorbent (BIOTAGER ISOLUTE SAX) with 500 mL of 0.1 M NaHCO3/0.1 M Na2CO3 solution; the sorbent was then washed with 600 mL de-ionised water, 300 mL methanol and 1000 mL CH2Cl2, respectively. Then 50 g of crude oil was diluted with 500 mL of CH2Cl2. The mixture was then filtrated through the sorbent to allow for acid adsorption. After the completion of this process, the treated crude oil was stirred in an open beaker under a fume hood for 48 hours allowing the CH2Cl2 (boiling point of 39.6°C) to vaporise. The total acid number (TAN) of the crude oil was measured using test method ASTM D664.30 It was determined that this acid removal process had reduced the TAN from 0.22 to 0.11 ± 0.01 mg KOH/g. 2.2.

Nuclear Magnetic Resonance Measurements A bench-top 1 Tesla permanent magnet featuring a Halbach array and a 5 mm inner diameter r.f. coil tuned to the 1H resonance of 40 MHz was used as the main measurement tool in this study (hereafter referred to as the 1T system). With a homogeneous magnetic field (Water LW50: ~4 Hz), this magnet provides unambiguous 1H chemical shift resolution of water and oil NMR signals. This NMR hardware also features a custom-built gradient coil with a maximum gradient strength of 1 T/m. The stimulated echo pulsed field gradient (STE PFG)15 pulse sequence, as shown in Figure 1, and the 1T system were used to perform diffusion measurements, as has been done previously to obtain droplet size distributions (DSD) of various water-in-oil emulsions. e.g. 17, 27, 31-33 The NMR signal, S, acquired with the STE PFG pulse sequence shown in Figure 1, can be related to molecular diffusion, D, using the Stejskal Tanner equation:34

δ S = exp[−D(γ gδ )2 (∆ − )] , S0 3


(1)

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where S is the signal intensity measured for the water peak; g is the intensity of the magnetic field gradient (T/m) applied; S0 is the signal measured when g = 0 ; δ is the magnetic field gradient pulse duration (s); γ is the 1H nuclei gyromagnetic ratio (2.68 × 108 T-1s-1 for 1H); ∆ is the diffusion observation time (s) and D is the diffusion coefficient (m2/s).

Figure 1. Stimulated echo pulsed field gradient (STE PFG) pulse sequence used in this work to obtain the droplet size distribution (DSD) of water-in-crude oil emulsions. Equation (1) is only strictly true for bulk fluids where the diffusion of the fluid molecules is unrestricted. For water-in-oil emulsions, the diffusion of the water molecules is however restricted by the water/oil interface. This restricted diffusion is the physical phenomenon that can be exploited to determine the emulsion droplet size distribution. Murday and Cotts 35 formulated a model, that assumes a Gaussian phase distribution (GPD) for the acquired NMR signal, to relate the spherical droplet radius, a, to this restricted diffusion: S = R ( a, g ) = S0 2 2 2 2 ∞   2δ 1 2 + e −α m D ( ∆ −δ ) − 2e −α m D∆ − 2e α m Dδ + e −α m D ( ∆ +δ )  2 2 exp − 2γ g ∑ 2 2 2  2 −  (α m2 D) 2  m =1 α m (α m a − 2)   α m D

(2a)

where αm are the positive roots of the following equation and J n is the nth order Bessel function:

J 3/ 2 (α a ) = α aJ 5/ 2 (α a )

(2b) A simplified short gradient pulse (SGP) model proposed by Linse and Soderman 36 neglects the diffusion that occurs during the application of gradient pulse based on the assumption that the gradient pulse duration is infinitely short, δ = 0 . The drawbacks of the GPD and SGP method 37-39 have led to the implementation of the block gradient pulse (BGP) method by Lingwood, Chandrasekera, Kolz, Fridjonsson and Johns 14 based on general gradient waveforms40-42 to quantify the signal attenuation. The BGP method uses eigenfunction expansions38 to solve the relevant Block Torrey equation.43 By dividing the pulse sequence into Ne intervals of constant gradient, the NMR signal can be written as:


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where t% = D0t / a 2

 Ne  S = v †  ∏G ( t%k − t%k −1 ; γ%k )  v (3)  k =1  is the dimensionless time, γ% = −cγ ga 3 / D0 is the dimensionless magnetic

field gradient and G (~ t ; ~γ ) = exp[(− Λ + i(~γ ⋅ zˆ )Z )~ t]

(4)

where the matrix ‫ ܈‬correlates the equilibrium mode to the higher eigenmodes for a sphere. 39, 44, 45 The elements of matrix Ʌ are calculated as follows: 2 δ jk Λ = α nm

where δ jk is the Kronecker delta and α nm is the m

(5) th

root of the following Bessel function:

J ' n (α ) = 0

(6) The elements of v describe the reflecting boundary surface with no NMR signal relaxation:

1 j = 1 v j = δ j1 =  0 j > 1 The signal attenuation function for the BGP method is consequently:

(7)

v†G ( t%δ ; γ% ) exp[−Λ(∆ − δ )]G* ( t%δ ; γ% ) v S = S ( a, g ) = (8) S0 v† exp[−Λ(∆ + δ )]v Droplet radius (a) can be calculated by regression of equation (8) to the relevant NMR signal attenuation. We have previously shown that the BGP method is more accurate for sizing emulsion droplets14 than the GPD or SGP methods and consequently employed it in several previous studies 17, 31-33; it is thus the method deployed in this work1. The water-in-crude-oil emulsions synthesized in this study consisted of a range of droplet sizes. Packer and Ress 46 employed equation (9) to compute the droplet size distribution, P(a):

∫ b( g ) =

∞ 0

a 3 P ( a ) S ( a , g ) da

∫

∞ 0

,

a 3 P ( a ) da

(9)

where b(g) is the normalised NMR signal as a function of g. This inversion problem is however ill-conditioned; Tikonov regularisation is the technique demonstrated to be able to solve this problem with the appropriate smoothing parameter determined using the generalized cross validation (GCV) method.47 Extensive validation of this regularisation technique can also be found in our previous studies.17, 31-33 1

The relevant software (REGEDS) is available for download from: http://www.fsr.ecm.uwa.edu.au/capabilities/software/regeds/


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2.3.

Interfacial Tension Measurement Water/oil interfacial tension measurements were conducted for all samples to complement the NMR studies of emulsion stability. The interfacial tension measurements were carried out using the pendant drop method,48 where the oil phase was pushed out from the tip of the needle forming a pendant-shaped droplet in a continuous aqueous phase. This process was monitored using an optical tensiometer, Theta Lite, as shown in Figure 2(a). Once the droplet shape had stabilised (usually within 0.5 to 1 hour for the systems listed in Table 1), the interfacial tension (σ) was computed by fitting equations (11) (derived from the Young-Laplace equation (10)) to the profile of the droplet as schematically shown in Figure 2(b).

a)

b)

Figure 2. a) Optical tensiometer Theta Lite, b) Young-Laplace fit to a pendant drop The classical Young-Laplace equation is: 1 1 + ) (10) R1 R2 For a pendant drop, the principal radii of curvature at the vertex (highest point of the drop) are: R1 = R2 = R . With the introduction of the parameter, arc length (S) of the drop shape, and other ∆P = ( Pint − Pext ) = σ (

geometric parameters as defined in Figure 2(b), equation (10) can be rewritten into the following set of three first-order differential equations which are readily numerically integrated and fit to the experimental droplet shape: dφ sin φ 2 ∆ρ gz , =− + ± dS x R σ dx = cos φ , dS dz = sin φ , dS


(11)

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0 = x (S = 0) = z (S = 0) = φ (S = 0)

3.

Results and Discussions

3.1.

Effect of Mono-valent and Divalent Salts on Crude Oil Emulsion Stability Figure 3(a) shows sample emulsion droplet size distributions for Emulsion A, for various NaCl concentrations, acquired 30 minutes after emulsion formation. There is little variation between the distributions with respect to the dominant droplet size peak between ~1 and 10 microns. The smaller random peaks at larger sizes can be attributed to measurement noise and possible imperfect sample homogenisation. In Figure 3(b) the equivalent emulsion droplet size distributions are shown after four days (during which the samples were stored stagnant at room temperature). Cleary, relative to Figure 3(a) - the samples 30 minutes after preparation - there is a general increase in the emulsion droplet size. This effect is also clearly more pronounced for low salinity samples: the mean droplet size of the emulsion with no NaCl has grown from 2.5 µm to 8 µm, whereas there was no discernible difference for the emulsion formulated with 1% NaCl. Thus, consistent with the bulk of literature, we clearly observe an increase in long-term emulsion stability (against droplet coalescence) as salinity increases. For further analysis of the results, we will hereafter present the evolution in the mean emulsion droplet size, as determined from distribution data such as those in Figure 3.

a)

b)

Figure 3. Water-in-crude oil emulsion droplet size distributions measured a) 30 minutes and b) 96 hours after sample preparation Figure 4(a) shows the evolution in the mean droplet size for Emulsion A, sampled daily post emulsion formulation, for all considered salinities for both the monovalent (NaCl) and divalent (CaCl2) salts. A significant linear growth rate in mean emulsion droplet size is evident for the emulsion formulated with no salt. The addition of 0.01 wt% sodium chloride (NaCl) or Calcium Chloride (CaCl2) significantly stabilises the emulsion, whilst 0.1 wt% sodium chloride (NaCl) or Calcium Chloride (CaCl2) (or higher salt concentration) rendered an emulsion that was


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stable over the 4-day period showing no discernible increase in mean emulsion droplet size. With reference to Table 2, the ionic strengths for these two salts at the same wt% are comparable. Thus, there is no evidence of divalent CaCl2 rendering a significantly more or less stable emulsion compared to an equivalent amount of NaCl. The observation that a stable emulsion is produced for a salt concentration of 0.1 wt% is directly consistent with the results of Rocca et al.9 Another observation of the results in Figure 4(b) is that the initial emulsion for all samples features a very similar mean droplet size of around 2 microns. Thus the suggestion, as discussed above, that an increase in salinity produces smaller initial droplets which are responsible for the enhanced emulsion stability is not relevant here. Figure 4(b) shows the corresponding change in interfacial tension as a function of salt concentration for both salts. Whilst there is clearly a decrease in interfacial tension, it is relatively modest. It seems implausible that a reduction in interfacial tension from ~18 to ~17 mM/m (for 0.1 wt% NaCl or CaCl2) would result in the emulsion stabilisation observed in Figure 4(a) – this is explored further below.

a)

b)

Figure 4. a) Mean droplet size of water-in-crude oil emulsions with different salt concentrations, monitored with NMR over 4 days, b) interfacial tension of water and crude oil with different salt concentrations. The dashed line refers to the zero-salinity measurement. 3.2.

Stabilisation of modified Crude Oils Asphaltenes and organic acids are generally recognised as significant contributors to emulsion stability. Emulsions were formulated from crude oils in which the asphaltene content was reduced by 0.31 wt% to below the detection limit of 0.01 wt% using the methodology detailed above (Emulsion B). The resultant evolution in mean droplet size is shown in Figure 5(a) with corresponding interfacial tension data shown in Figure 5(b), both as a function of NaCl content. In the absence of salt, the emulsion is slightly more unstable than that formulated with the original crude oil (relative to Figure 4, over an equivalent period the droplets grow to 10 microns in diameter as opposed to 8 microns) – this is in agreement with our previous work.27 However consistent with the original crude oil emulsion, 0.1 wt% NaCl was adequate to stabilise


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the emulsion over the four day period. The interfacial tension data were broadly consistent between Figure 4 and Figure 5.

a)

b)

Figure 5. a) Mean droplet size of asphaltene-reduced crude oil emulsions (Emulsion B) with different NaCl concentrations in the aqueous phase monitored via NMR over 4 days, b) interfacial tension of water and asphaltene-reduced crude oil water systems at different NaCl concentrations. The equivalent data to Figure 4 and Figure 5, for the crude oil with its total acid number reduced (Emulsion C) as detailed above (0.2 to 0.1 mg KOH/g), are shown in Figure 6. The initial emulsion formulated from the modified crude oil was slightly less stable than that from the original crude oil (the mean droplet size increased by 1- 1.5 microns). However again 0.1 wt% NaCl in the aqueous phase was adequate to stabilise the emulsion over a 4-day period. A similar trend in interfacial tension was evident in Figure 6(b) with respect to salinity albeit with significantly elevated values – this increase in interfacial tension highlights the importance of these naphthenic acids in reducing the interfacial tension of these water-crude oil systems. However, the collective data in Figures 4-6 do suggest that relatively small changes in interfacial tension are not responsible for the observed changes in emulsion stability with system salinity – the reduction in interfacial tension upon addition of 0.1 wt% NaCl is consistently of the order of 1 mN/m and hence significantly less than the 4 mN/m variation between the different crude oils considered in Figures 4,5 and 6. Furthermore, the results in Figures 5 and 6 provide an example of where an emulsion with a larger IFT (20 mN/m, 1 wt % NaCl) is significantly more stable than one with a lower IFT (18 mN/m, DI water).


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a)

b)

Figure 6. a) Mean droplet size of acid-reduced crude oil emulsions (Emulsion C) with different NaCl concentrations in the aqueous phase monitored via NMR over 4 days, b) interfacial tension of water and acid-reduced crude oil at different NaCl concentrations. 3.3.

Model Oil Emulsion We continued to explore the effect of salinity on emulsion stability as a function of oil type – specifically an aliphatic (paraffin oil) and an aromatic oil (xylene) (Emulsions D and E respectively). In both cases water-in-oil emulsions were formulated using non-ionic Span 80 as a surfactant. The concentration of Span 80 was tuned to deliver an initial water–in-oil emulsion (with zero salinity) that was similarly unstable over an equivalent 4-day period to that of the crude oils. Figure 7(a) shows the evolution in the mean droplet size for water-in-paraffin oil emulsions as a function of time and salinity; the equivalent interfacial tension data are shown in Figure 7(b). For this system, a 0.1 wt NaCl solution again renders the emulsion stable over the 4-day period; this is accompanied by a relatively minor reduction in interfacial tension (~0.5 mN/m) with salt concentration increase and consistently much lower interfacial tension values relative to that for the crude oils (Emulsions A-C).

a)

b)

Figure 7. a) Mean droplet size of water-in-paraffin oil emulsions (Emulsion D) with different NaCl concentrations in the aqueous phase monitored via NMR over 4 days, b) interfacial tension of water and paraffin oil at different NaCl concentrations.


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The equivalent data for water-in-xylene emulsions (Emulsion E) are shown in Figure 8. Again, salt is observed to increase the stability of the emulsions (with 0.1 wt% NaCl reducing the growth in droplet size to effectively zero) whereas in this case these is virtually no change in interfacial tension with salinity. The initial emulsion features a considerably larger initial mean droplet size that Emulsions A-D, potentially because of the reduced density contrast between the two phases. However no significant differences are observed between the emulsions formulated with different salinities.

a)

b)

Figure 8. a) Mean droplet size of water-in-xylene emulsions (Emulsion E) with different NaCl concentrations in the aqueous phase monitored via NMR over 4 days, b) interfacial tension of water and xylene at different NaCl concentrations. Thus, in summary the persistent but modest reduction in interfacial tension with salt concentration does not correlate across the range of emulsion samples considered with emulsion stability as salinity increases – there is clearly no threshold interfacial tension value below which the emulsions are stable over the time frame considered. Equally there is no discernable correlation between salt concentration and the mean droplet size of the initially formulated emulsions. Naphthenic acids clearly serve to reduce the interfacial tension of the oil-water interface, however any influence on emulsion stability as a function of salinity is not evident. The persistent observation that 0.1 wt % of salt (in water) is adequate for all oil types to render a stable emulsion over four days is intriguing. This is plausibly consistent with the suggestion, detailed above, that emulsion stability is caused by a reduction in attractive forces between droplets due to a reduction in dielectric permittivity (ε/ε0) difference between the oil and water phases. However this reduction (∆(ε/ε0)), estimated based on the work of Gavish and Promislow,49 is only ~2 (80.16 to 77.98)49 for a salt concentration of 1 wt%. The emulsion stabilisation is however consistently observed for a salt concentration of 0.1 wt% when this difference is negligible (~0.2); this is smaller than the 0.7 variation in ε/ε0 for the oils used (ranging from 2.3 for xylene to 1.6 for the paraffin oil). In addition, we attempted to measure ε/ε0 for Emulsion A as a function of salinity, however there was no discernible change. These minimal variations in dielectric constant are thus not consistent with the observed emulsion


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stabilisation. A similar argument pertains to density differences – with reference to Table 1 and 2 above, the variation in density of the aqueous phase as salinity increases, over the range considered, is significantly smaller than the variation in density for the oil samples considered. We cannot rule out the accumulation of surface active species (e.g. asphaltenes/acids or Span 80) at the interface in response to salt increases. Finally, we note that typical mineral oil-water interfacial tensions are of the order of 40-55 mN/m. Thus, our measured values of 18 and 22 mN/m for asphaltene- and napthenic acid-reduced oils indicate that in these samples other surface-active species are also still present. The nature of these and their role in stabilising emulsions more readily for saline solutions will be the subject of future work. 4.

Conclusions

The long-term stability of various water-in-oil emulsions against droplet coalescence as a function of salinity, was monitored over a four-day period using NMR PFG droplet sizing techniques. This was done for a range of oils (crude oil, crude with reduced asphaltene and naphthenic acids respectively, paraffin oil and xylene). A consistent stabilisation of the emulsion across different valency salts and the range of different oils considered for the continuous phase was observed at 0.1 wt% salt addition to the aqueous phase. This did not correlate with system interfacial tension or any obvious reduction in initial droplet size with salinity. It equally does not result in an appreciable difference in either aqueous phase density or differences in dielectric permittivity. The quite different ‘surfactants’ employed suggest that greater surface concentration of these species in response to salinity changes (whilst improbable) cannot be eliminated based on the data acquired. Acknowledgements Support of the Australian Research Council via grant DP130101461 is gratefully acknowledged. Special thanks go to Douglas Velho for his assistance in conducting NMR measurements. References 1. Parry, M.; Mackey, P.; Bosoni, T.; Aktkinson, N.; Wilson, A. Oil Market Report; International Energy Agency: 2016. 2. Xia, L.; Lu, S.; Cao, G., Stability and Demulsification of Emulsions Stabilized by Asphaltenes or Resins. Journal of Colloid and Interface Science 2004, 271, (2), 504-506. 3. Abdel-Aal, H. K.; Aggour, M.; Fahim, M. A., Petroleum and Gas Field Processing. Marcel Dekker, Inc.: The United States of America, 2003. 4. Kokal, S. L., Crude Oil Emulsions. In Petroleum Engineering Handbook, Fanchi, J. R., Ed. Society of Petroleum Engineers: Texas, 2006; Vol. 1, pp 533 - 570. 5. 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, (1), 260268.


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