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 5
days was found to increase with salinity; this was shown to be independent
of whether a monovalent (NaCl) or 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 stabilization.
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 stabilizing surface-active
species driven by increasing salinity as the most plausible explanation
for the observations reported here.
Formation of water-in-crude oil emulsions is a pervasive problem for crude oil production and transportation.Here we investigate the effectiveness of a comparatively low pressure CO 2 treatment in terms of breaking these water-in-crude oil emulsions. To this end, we used unique benchtop nuclear magnetic resonance (NMR) technology to measure the droplet size distribution (DSD) of the emulsions. Treatment with 50 bar CO 2 for 2 h resulted in significant emulsion destabilization; this was replicated when CO 2 was replaced by N 2 O, which has a solubility in both the aqueous and oil phases similar to that of CO 2 . Low solubility gases, N 2 and CH 4 , by contrast had no effect on emulsion stability. Treatment with CO 2 was also found to have no effect on a model water-in-paraffin oil emulsion stabilized by a synthetic surfactant (Span 80). Collectively, this supported the hypothesis that emulsion destabilization results from CO 2 precipitation of asphaltenes as opposed to emulsion droplet film disruption during depressurization, which are the two competing theories reported in the literature to explain the observed supercritical CO 2 destabilization of emulsions. Treatment of a water-in-crude oil emulsion featuring partial removal of asphaltenes from the oil phase was consistent with this hypothesis, as the effect of the CO 2 treatment on emulsion destabilization was significantly more pronounced.
The stability of hydrate-in-oil dispersions is a critical parameter in assessing the risk of flowline blockage due to particle aggregation or wall deposition. Many studies of hydrate particle transportability have used deionized water to form the dispersion; however, the resulting lack of ions means that the crude oil's natural surfactants will be less active, which does not represent production conditions. This study presents a new investigation of both hydrate-in-oil dispersion stability and water-in-oil emulsion stability, measured with a differential scanning calorimeter (DSC) and low-field nuclear magnetic resonance (NMR) apparatus, respectively. The results show that hydrate-in-oil dispersion stability increases directly with sodium chloride (NaCl) mass fraction in the aqueous phase; above 5 wt% NaCl, the dispersion was observed to be stable over ten hydrate formation-dissociation trials. This was comparable with the dispersion stability observed previously when an ionic surfactant was dosed at 2 wt% into the same crude oil. In contrast, only 0.1 wt% NaCl was required to stabilize water-in-oil emulsions over a four day observation period. This comparison suggests that, for crude oils containing natural surfactants, the risk of hydrate blockage may decrease as brine salinity increases from 1 to 10 wt%, without affecting the stability of the water-in-oil emulsion. The results demonstrate that experimental studies on hydrate-or water-in-crude oil systems should be performed with realistic values of brine salinity, to accurately capture dispersion stability.
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