In subsea environments, wax-phase separation, deposition, and gelling constitute an important concern in production operation/activities. Understanding the crude oil wax-phase behavior can help to avoid the high costs resulting from production reduction or stoppage in the field operations to mitigate these effects. Conversely, expenses arising from production system overdesign may also be prevented. In this context, two waxy crude oils from different Brazilian fields were selected to be characterized according to Petrobras technical specification for flow assurance requirements. These light crude oils A and B have similar chemical characteristics of saturates, aromatics, resins, and asphaltenes (SARA) analysis, but crude oil A has a wax appearance temperature 15 °C higher than crude oil B. Despite having a density around 29° American Petroleum Institute (API), for a rheological point of view, crude oil B has a viscosity about half that of crude oil A at 20 °C. In addition, crude oil B dehydrated exhibits Newtonian behavior, in the range evaluated for the shear rate and temperature, while crude oil A features a shear thinning behavior, which increases with the increase of the water content and temperature reduction.

In oilfield operations, the formation of crude oil emulsions is very common and can cause significant flow assurance problems during oil production. These emulsions can be very stable as a result of the presence of polar compounds, such as asphaltenes and resins, that play the role of natural surfactants and also because of the occurrence of many types of fine solids that can form resistant films at the crude oil/water interface. Gelled waxy crude oil flows have been largely studied, and the effect of dispersed water on crude oil rheology has been well-characterized; however, little attention has been given to the potential impact of waxy crude oil emulsion gel formation. In this study, it is shown that in some waxy crude oils the presence of water above a threshold value could promote gel formation, significantly changing the viscosity of the mixture. The rheological properties of waxy crude oils were determined at different water cuts, temperatures, and shear rates, and also a chemical characterization of these waxy crude oils was carried out. Highly stable and viscous emulsions with water cuts as high as 70% and wax-oil gel emulsions were observed. Rheological flow curves show viscosity values much higher than usually obtained for other waxy crude oils. Furthermore, strong shear-thinning behavior of the crude oils and emulsions at low-temperature conditions were seen as well.

The oil compatibility model is important for assessing the stability of crudes. The compatibility between maltenes and the corresponding asphaltenes, Asphs, can be assessed from the solubility parameters (Hildebrand and Hansen) of both components of the crude. Solvatochromism is the effect of the medium on the UV/vis spectra of substances (solvatochromic probes) that are sensitive to the properties of the medium, namely, its empirical (or overall) polarity, Lewis acidity and basicity, dipolarity, and polarizability. Therefore, the solubility and solvatochromic parameters of solvents should be related. We synthesized a novel solvatochromic probe (E-2,6-di-tert-butyl-4-(2-(1-hexylquinolin-1-ium-4-yl)­vinyl)­phenolate, HxQMBu 2 ) whose properties are convenient to study in nonpolar and polar solvents. The empirical solvent polarities measured with HxQMBu 2 in 38 solvents correlated linearly with the corresponding Hildebrand solubility parameters. Likewise, the solvent Lewis acidity/basicity, dipolarity, and polarizability correlated linearly with the corresponding Hansen solubility parameters. To test the equivalence of the two scales (solvatochromic and solubility parameters), we determined the solubility of Asphs in 28 solvents, pertaining to different chemical classes. The dependence of Asph solubility on three solvent descriptors (Lewis acidity/basicity, dipolarity, and polarizability) was tested. Our results indicated that alcohols and hydrocarbons are inefficient solvents; solvents of intermediate efficiency carry either a strongly dipolar group or polarized bonds. Aromatic and heterocyclic solvents are most efficient. The most relevant solvent descriptor (for the dissolution of Asphs) is its polarizability.

Water-in-oil (W/O) emulsions are very common in oil field operations and are formed as a result of energy input from turbulence caused by the flow in the production pipelines, pumps, and valves. Understanding emulsion rheological behavior is crucial to deal with flow assurance issues. This paper presents and discusses a series of rheological experiments carried out with synthetic emulsions formulated with 126 Brazilian crude oils with American Petroleum Institute (API) gravity ranging from 13° to 35°. This rheological study includes viscosity dependence upon the shear rate, temperature, and water volume fraction. The results show that crude oils with similar API gravity and viscosity can generate emulsions with very different viscosities (8–50 mPa s at 50 °C around 25° API gravity, for example) and different maximum water content limits. Besides, W/O emulsions that are prepared with either light (API gravity of >35°) or heavy (API gravity of <13°) crude oils are the emulsions observed to be the more difficult to stabilize, particularly the high-water-cut emulsions. Also, a large amount of data show that intermediate API gravity crude oils can incorporate up to 70% water volume fraction and show the highest relative viscosity. As a general trend, W/O emulsions show a typical Newtonian behavior at temperatures above the wax appearance temperature and at low water cuts. The rheological study shows that the temperature, shear rate, water volume fraction, and API gravity have important impacts on the viscosity of W/O emulsions.

To assess the relationship of wax chemical structure and viscoelastic properties of waxy gels, model oils composed of single and blended waxes were prepared at a fixed concentration of 7.5 wt % and then gelled. The investigation encompassed four different well-characterized commercial paraffin waxes, solubilized in a mineral oil matrix. Previous rheological measurements pointed out that these systems reproduce essential features of crude oil gels (e.g., gel-like mechanical response) when gelled. Among the employed waxes, two are predominantly linear, whereas the others are nonlinear branched molecules. The waxes were molecularly characterized to aid in the investigation by means of GC-FID, 13 C NMR, DSC, FT-IR, and XRD. Rheological properties were measured via a controlled-stress rheometer by oscillatory shear experiments. Polarized light microscopy was adopted for morphological characterization of precipitated crystals. It was found that yield stress and elastic modulus at linear viscoelastic region are highly correlated (R 2 = 0.94). For single wax systems, the increase in chain length resulted in a yield stress increase, although there is a competitive effect among chain length (positive effect) and branching content (negative effect). The results indicated that for blended systems the small-chain linear wax was able to interact favorably with the long-chain nonlinear wax, possibly due to its ability to accommodate within the later molecule, ensuring the highest yield stress value (630.2 Pa). The wax structural arrangement of 37 carbon atoms on average, including approximately three tertiary carbons, was effective for lowering the yield stress of particular blended systems. The lowest viscoelastic properties were measured for a blended system composed of nonlinear waxes, which was also characterized by the smallest and rounded crystals visible by optical microscopy.

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Flow assurance is a multidiscipline process involving sampling, laboratory analysis, and production and facilities engineering to ensure uninterrupted optimum well productivity. Laboratory testing provides necessary data to assess the flow assurance risk because it defines phase behavior and the properties of the waxes, asphaltenes, emulsions and hydrates known to be principal causes of flow problems. In deep- and ultra-deepwaters scenarios the precipitation, deposition, and gelling of organic solids in hydrocarbon fluids constitute critical production concerns. Understanding the crude oil behavior can help to avoid high costs resulting from production reductions or stoppages or, conversely, from system overdesign. This paper shows an effort to establish correlations between Brazilian crude oils properties and flow assurance related issues.

An asphaltene sample from a light Arabian crude oil was characterized using several analytical techniques, such as thermogravimetric analysis, nuclear magnetic resonance, Fourier transform infrared spectroscopy, and elemental analysis. The results showed that the sample has a high sulfur content and highly condensed aromatic compounds and the average molecular structure is predominantly of continental/island type; however, the presence of a significant amount of methylene carbons in long alkyl chains is clear. A diffusion-ordered spectroscopy nuclear magnetic resonance experiment (DOSY-NMR) was carried out to detect the presence of asphaltene aggregates, evaluate their size, and shed light on the presence of maltenic occluded species and entrained residual solvent. In the DOSY spectrum, some sample signals were attributed to non-asphaltenic molecules, showing that it is possible to achieve key features of the sample complexity in “one shot”.