Two-dimensional (2D) relaxation exchange nuclear magnetic resonance (NMR) is in many ways similar to 2D frequency exchange NMR, except that the encoding times are comparable to the exchange time. This fact prevents the straightforward analysis of the cross-peak intensities in terms of joint probability densities, and quantitative information and understanding can only be obtained by comparison with simulated spectra. Based on simulations, an explanation is proposed as to why interference between relaxation and exchange may lead to asymmetric 2D exchange maps when exchange occurs between more than two sites. Practically, retro-fitting a simulated data set to an experimental one is shown to allow for the determination of the experimental relaxation and exchange parameters. This point is illustrated by studying a two-site model system consisting of interstitial water exchanging within a pack of spherical silica particles.

Benchtop nuclear magnetic resonance (NMR) pulsed field gradient (PFG) and relaxation measurements were used to monitor the clathrate hydrate shell growth occurring in water droplets dispersed in a continuous cyclopentane phase. These techniques allowed the growth of hydrate inside the opaque exterior shell to be monitored and, hence, information about the evolution of the shell's morphology to be deduced. NMR relaxation measurements were primarily used to monitor the hydrate shell growth kinetics, while PFG NMR diffusion experiments were used to determine the nominal droplet size distribution (DSD) of the unconverted water inside the shell core. A comparison of mean droplet sizes obtained directly via PFG NMR and independently deduced from relaxation measurements showed that the assumption of the shell model-a perfect spherical core of unconverted water-for these hydrate droplet systems is correct, but only after approximately 24 h of shell growth. Initially, hydrate growth is faster and heat-transfer-limited, leading to porous shells with surface areas larger than that of spheres with equivalent volumes. Subsequently, the hydrate growth rate becomes mass-transfer-limited, and the shells become thicker, spherical, and less porous.

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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.