Pål V. Hemmingsen

Emulsions of Heavy Crude Oils. I: Influence of Viscosity, Temperature, and Dilution

Twenty‐seven crude oils of different origin have been systematically analyzed with regard to viscosity, density, molecular weight, and SARA (saturates, aromatics, resins, asphaltenes) fractionation. Emulsion stability of water‐in‐oil emulsions of the different crude oil samples have been measured by the critical electric field technique (E‐critical). In addition, droplet size distributions for some of the water‐in‐oil emulsions have been determined by NMR self‐diffusion. Rheology measurements show that some of the crude oils have Bingham plastic type flow behavior at temperatures below 20°C, indicating content of waxes. Analysis of the critical electric field measurements shows that the E‐critical value depends on the applied electric field gradient. At low applied electric field gradients, the droplets are given more time to organize into water‐continuous bridges, resulting in a lower E‐critical value than when the applied electric field gradient is higher. The value of E‐critical also increases as the volume of the water phase decreases, due to the increased distances the droplets must move to form linear chains between the two electrodes. E‐critical measurements of emulsions of diluted crude oils show that, in general, the emulsion stability decreases with increased dilution of the oil phase. However, some systems show regions where the emulsion stability is independent of the dilution ratio or viscosity of the crude oil. Here the coalescence rate controls the level of emulsion stability. Viscosity and emulsion stability for water‐in‐oil emulsions were measured for the complete crude oil matrix (27 crude oils), and in general there is an increase of the emulsion stability as the viscosity increases. However, viscosity also correlates well with the SARA data of the crude oils. E‐critical shows a temperature dependence according to the Arrhenius law.

Isolation and Characterization of Naphthenic Acids from a Metal Naphthenate Deposit: Molecular Properties at Oil‐Water and Air‐Water Interfaces

Naphthenic acids from a West African metal naphthenate deposit have been isolated and characterized by infrared (IR), nuclear magnetic resonance (NMR), and Fourier transform ion cyclotron resonance mass spectrometry (FT‐ICR MS). The sample has been shown to comprise a narrow group of 4‐protic naphthenic acids of molecular weight ∼1230 Da. The determined mass of 1230.0627 Da suggests a compound with the elemental composition C80H142O8. The NMR data show no sign of carbon‐carbon multiple bonds. Hence, the elemental composition indicates the presence of six saturated hydrocarbon rings. The naphthenic acids have proved to be highly oil‐water (o/w) interfacially active. On elevation of the pH from 5.6 to 9.0, interfacial activity increases gradually due to a higher degree of dissociation of the carboxylic groups. At pH 9.0, the interfacial tension (IFT) between water and toluene‐hexadecane (1–9 vol.) is lowered by ∼40 mN/m at concentrations of only 0.0050–0.010 mM naphthenic acid. The time rate of decrease of the IFT (dγ/dt) is also concentration‐dependent, and a well‐defined IFT is attained at long observation periods. The C80 naphthenic acids form relatively unstable Langmuir monolayers. The stability decreases further with increasing pH as more monomers become dissociated and dissolve into the aqueous phase. The stability is altered upon addition of calcium ions into the subphase due to formation of calcium naphthenate at the surface. In the undissociated state, the acids have a molecular area of ∼160 Å2/molecule in the noninteracting region. The high area reflects an extended molecular structure comprising four carboxylic head groups, which are likely to be separated by hydrocarbon chains.

The Role of Asphaltenes in Stabilizing Water-in-Crude Oil Emulsions

Stable water-in-oil emulsions may form during the production of crude oil, as coproduced water is mixed with the oil from reservoir to separation facilities. Such emulsions introduce technical challenges, as they must be resolved to provide the specified product quality. Asphaltenes and resins indigenous to the oil are acknowledged as the most important components in respect to stabilization of the interface against coalescence. Fine solids may also contribute to the stabilization, as may the presence of naphthenic acids. The combination of these components creates a complex picture of several contributing mechanisms to the stability of water-in-oil emulsions. It is also established that the pressure conditions will influence the behavior of active components and the properties of the interface. In order to successfully mitigate the problems of stable emulsions, a thorough knowledge of component properties, behavior, interactions, and effect on water/oil interfacial properties must be developed for pressures ranging from ambient to high. This chapter seeks to bring to light recent findings related to these topics. The theoretical and experimental impacts to create a better understanding of association phenomena and molecular interaction in oil-based systems are of recent date. One can say that these needs significantly emerge from the crude oil industry where a lot of problems of practical nature are closely related to colloid chemistry. In this chapter, we will concentrate on a description of water-in-crude oil (or model oil) emulsions and topics related to these. The coproduction of water and crude oil in the form of an emulsion is highly undesirable from a process and product quality point of view. When the crude oil is processed from the well head to the manifold, there is usually a substantial pressure reduction with a pressure gradient over chokes and valves where the

Hydrate Plugging Potential of Original and Modified Crude Oils

The hydrate plugging potential of four crude oils have been studied. The crude oils were modified in two ways, either by de‐asphalting (by adding n‐pentane) or by a pH 14 liquid‐liquid extraction. The pH 14 extraction removes acidic compounds from the oil phase into the aqueous phase at pH 14, typically phenols and naphthenic acids. All of the crude oils, both original and modified, were characterized together with their water‐in‐oil emulsions. The main results showed that removing the acidic compounds at pH 14 destabilized the asphaltenes, leading to increased water‐in‐oil emulsion stability. De‐asphalting the crude oils decreased the water‐in‐oil emulsion stability, except for one of the crude oils. Three of the original crude oils were tested in a flow loop pilot rig. The results showed that the loop tests favor the inhibiting capacity of crude oils with high water‐in‐oil emulsion stability, possible due to emulsion formation by inline pump in the loop. In a flow simulator (wheel) the original crude oils, the pH 14 washed crude oils and two of the de‐asphalted crude oils were tested. The results showed that the wheel tests favor the inhibiting capacity of crude oils with high content of acidic surfactants (naphthenic acids, phenols). In the wheel, the flow conditions are milder than in the loop, with less mixing, and the propensity of the oils to form stable water‐in‐oil emulsions is much lower.

Solubility Parameters Based on IR and NIR Spectra: I. Correlation to Polar Solutes and Binary Systems

IR and NIR spectra were correlated to Hildebrand and Hansen solubility parameters through use of multivariate data analysis. PLS‐1 models were developed and used to predict solubility parameters for solvents, crude oils, and SARA fractions. PLS regression showed potential for good correlation of the solubility parameters with IR and NIR spectra. Principal component analysis of IR spectra showed that crude oils are grouped according to their relative contents of heavy components such as asphaltenes. PCA of IR spectra for SARA fractions resulted in obvious groupings of the respective fractions. Prediction of solubility parameters from IR spectra of polymers, crude oils, and SARA fractions gave values that are comparable to literature values. This study indicates that correlation of solubility parameters with IR and NIR spectra is possible. In turn, it may be possible to develop models that can predict the polarities of crude oils and crude oil fractions such as resins and asphaltenes.

Stability of Water/Crude Oil Systems Correlated to the Physicochemical Properties of the Oil Phase

A characterization of 30 crude oils has been performed to determine the relative level of influence that individual parameters have over the overall stability of w/o emulsions. The crude oils have been analyzed with respect to bulk and interfacial properties and the characteristics of their w/o emulsions. The parameters include compositional properties, acidity, spectroscopic signatures in the infrared and near‐infrared region, density, viscosity, molecular weight, interfacial tension, dilational relaxation, droplet size distribution, and stability to gravitationally and electrically induced separation. As expected, a strong covariance between several physicochemical properties was found. Near‐infrared spectroscopy proved to be an effective tool for crude oil analysis. In particular, we have showed the importance of the hydrodynamic resistance to electrically‐induced separation (static) in heavy crude oil‐water emulsions. A rough estimate of the drag forces and dielectrophoretic forces seemed to capture the difference between the 30 crude oils. Given enough time, water‐in‐heavy oil emulsions could be destabilized even at very low electric field magnitude (d.c.). When droplets approach each other in an inhomogeneous electric field, strong dielectrophoretic forces disintegrate the films and result in coalescence. The relative contribution from film stability to the overall emulsion stability may therefore be very different in a gravitational field compared to that in an electrical field.

Emulsions of Heavy Crude Oils. II. Viscous Responses and Their Influence on Emulsion Stability Measurements

The stability of 30 heavy crude oil emulsions was studied in a parallel-plate laboratory coalescer (DC field). Particularly, viscous responses and their influence on the emulsion stability measurements were investigated. In addition to highlighting previous results from the same experimental setup and discussing these based on recent experience, new results at different temperatures and volume fractions of water were presented. A new semi-empirical model for the characteristic time of the destabilization process was presented. The electrical forces were modelled with a point-dipole approximation and the hydrodynamic resistance to droplet transport was modelled with an empirical term including the logarithmic viscosity of the oil phase. The new model clearly performed much better than the previous model, particularly for very viscous crude oils. Studies of the performance of industrial electrocoalescers have showed that simple electrostatic theory can potentially explain complex separation phenomena when the resistance to the coalescence step is reduced by an efficient demulsifier. The ultimate goal is to build a model for both the laboratory setup and the industrial coalescer so that laboratory experiments can be used to predict the behavior of the industrial process.

A Laboratory-Scale Vertical Gravity Separator for Emulsion Characterization

A laboratory-scale vertical gravity separator has been built in order to perform characterization on oil and water based emulsions. The separation rig consists of two positive displacement pumps, a feed separator, and a test separator. Probes for sampling are placed at various heights of the test separator and at different points at the pipes. To induce mixing of the oil and water phases, a needle valve is placed downstream of the pumps. The valve, when choked, increases the pressure drop and thus increases the shear of the oil and water mixture pumped through the system. A differential pressure cell is used to monitor the pressure drop over the needle valve when choked. The differential pressure is used as a reference for the energy put into the mixing process. Calculation of the maximum surviving drop size for relevant pressure drops gave sizes in the range of 93 µm for a pressure drop of 0.25 bars and 29 µm for a pressure drop of 4.5 bars. Droplet sizes were determined with a digital video microscope. The results from the microscope analysis gave droplets with sizes beween 2 and 90 µm with mean diameters in the order of 4–12 µm.