Effect of Brine Salinity on the Stability of Hydrate-in-Oil Dispersions and Water-in-Oil Emulsions

Abstract

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.

Role of Aqueous Phase Chemistry, Interfacial Film Properties, and Surface Coverage in Stabilizing Water-in-Bitumen Emulsions

“…Figure 4.17b shows that similar results with CaCl2. Aman et al (2015) observed a similar reduction in droplet size (by up to 50%) after 24 hours of settling when the salt content increased from 0 to 4 wt% NaCl in model water-in-crude oil emulsions.…”

“…It has been documented by some authors that salts can reduce the drop size and created more stable emulsions (Aman et al, 2015;Marquez et al, 2010). However, other authors have reported the opposite effect, higher droplets and less stable emulsions, with an increase in salt content (Moradi et al, 2013).…”

“…One possible explanation is a decrease in the average drop size. Aman et al (2015) investigated the change in drop size after 24 hours of settling on emulsions prepare with 70vol% of crude oil (4.7 cP, density of 0.85g/mL at 20 o C) and 30vol% NaCl-brine, and found that the average droplet size decreased by 50% at salt contents higher than 0.1 wt% NaCl in the aqueous phase.…”

High pressure rheological measurements of gas hydrate-in-oil slurries

“…Water-in-oil emulsions were created with deionized water and an industrial crude oil previously described by Aman et al [27,28] with a respective density and viscosity of 0.85 g/ml and 4.7 cP at 20 °C and atmosphere pressure. Asphaltenes are contained in this crude oil, which contributes to the stabilization of the water-in-oil emulsion.…”

Effect of hydrate anti-agglomerants on water-in-crude oil emulsion stability

“…The aims of the work presented here are to apply these PFG NMR techniques to monitor the effect of three different industrially available hydrate AAs on W/O emulsion stability (assessed via monitoring the temporal evolution in droplet size distributions) as a complement to traditional bottle stability tests. Turner et al (2009) and (Aman et al 2014(Aman et al , 2015 1 3…”