Base Number and Wetting Properties of Crude Oils
- S.T. Dubey (Shell Development Co.) | P.H. Doe (Shell Development Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- August 1993
- Document Type
- Journal Paper
- 195 - 200
- 1993. Society of Petroleum Engineers
- 5.6.2 Core Analysis, 4.1.5 Processing Equipment, 5.1.1 Exploration, Development, Structural Geology, 4.2.3 Materials and Corrosion, 5.5.2 Core Analysis, 2.4.3 Sand/Solids Control, 4.1.2 Separation and Treating, 3.2.4 Acidising, 4.3.4 Scale
- 2 in the last 30 days
- 854 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
Oil acid and base numbers influence wetting through their effect on electrostatic interactions with the mineral surface. An improved nonaqueous potentiometric titration has been developed that correctly quantifies weak bases in crude oils. In crude-oil/silica systems, wetting behavior correlates with base/acid ratio and is consistent with wetting theories based on disjoining pressure.
Reservoir oil recovery and the time scale over which recovery may be achieved are affected significantly by the extent to which the oil wets the reservoir minerals. Morrow's1 recent review summarizes some important effects of wetting on oil recovery and emphasizes that most systems depart from what he calls very strongly water-wet conditions. If the departure from water-wet conditions is significant, special care is required in core analysis to duplicate reservoir wettability conditions as closely as possible.
The theoretical understanding of wettability has not advanced to the stage where these departures from water-wetness can be predicted reliably from first principles. Oil accumulation in a reservoir represents a process of partial displacement of reservoir brine with crude oil. During this process, oil approaches the mineral surfaces but remains separated from them by very thin (typically < 50-nm thick) water mms. Hirasaki2-4 argued that wetting in these oil/brine/mineral systems will be determined by the water-film thickness, which in turn is determined by the balance of forces within the film. These forces give rise to an excess pressure, the disjoining pressure, that acts to resist further thinning of the film. The film will drain (become thinner) until its disjoining pressure is equal to the applied capillary pressure.2,3
Various component forces make up the total disjoining pressure. For relatively thick films, only van der Waals and electrostatic forces are of long enough range to be significant. In oil/brine/mineral systems of interest for reservoirs, van der Waals forces would be expected to be attractive (Le., they act to thin the water film).2,3
The electrostatic interaction varies greatly depending on reservoir mineralogy, reservoir brine pH and composition, and oil chemistry. If the electrostatic interaction is repulsive, it may be sufficiently strong to counterbalance the van der Waals attraction, thereby stabilizing a relatively thick film. This would be expected to produce a water-wet regime.2,5,6
If the electrostatic force is attractive or not sufficiently repulsive, the water film will continue to thin until further thinning is limited by short-range, repulsive, structural forces. "Structural" is a catchall term for the effects that arise because the thin mm is not a continuum but consists of discrete, space-filling molecules. The practical effect of the structural force is a lower limit on the water-film thickness. At this lower film-thickness limit, the surface will not be water-wet. The contact angle (the most fundamental measure of wettability) can be calculated from the disjoining-pressure-vs.-thickness relationship.4
The theoretical argument that a relationship should exist between disjoining pressure and wettability provides the rationale for systematic investigation of variables that influence wetting and offers a long-term prospect for prediction of wetting from first principles. This paper begins such an investigation.
Electrostatics in Crude-Oil/Brine/Silica Systems
As oil is forced into close contact with an initially water-wet mineral surface, the water film on the surface becomes bounded by an oil/brine interface on one side and by a mineral/brine interface on the other. If these two interfaces have like charges, an electrostatic force of repulsion will occur that increases the disjoining pressure and tends to maintain a thick water film. This situation is likely to produce water-wetness.
Conversely, if the oil/brine and mineral/brine interfaces have opposite charges, the electrostatic interaction is attractive, which acts to thin the film and pull the system into a non-water-wet regime. We then expect increased oil-wetting of the surface.
The sign of the charge at the oil/brine or mineral/brine interface can be determined from zeta-potential measurements. Zeta potential is the potential at the shear plane, which lies some small (unknown) distance from the surface. The usefulness of zeta potential is that it is an experimentally accessible quantity obtained from electrokinetic experiments, such as eletrophoresis.7 In the absence of strong specific counter-ion adsorption, the zeta-potential sign indicates the surface-charge sign. Zeta potential may be used to calculate the electrostatic-interaction force.
Reservoir mineral zeta potentials can vary widely. Quartz surfaces, which represent the dominant mineral in most sandstones, are negatively charged.7 Aluminosilicate minerals (feldspars and clays) may show diverse behavior (including different charges on different crystal faces), although available evidence8 suggests a net negative charge for minerals of interest in reservoirs. In these systems, the zeta-potential sign and magnitude are determined primarily by the brine pH.
Zeta-potential determination for carbonate minerals is less straightforward. The brine divalent- and carbonate-ion contents are the most important controllers of surface charge. Calcite, for instance, will be positively charged in the presence of sufficient calcium ion;9 conversely, addition of bicarbonate may produce a negative surface charge. We do not consider carbonates further. Throughout the work described, the "mineral" is acid-washed silica, which is negatively charged under all our experimental conditions (0.02 M NaCl brines, pH>2, and 25°C).
The pH also determines the charge on the oil/brine interface. At low pH, oils are positively charged; at higher pH, the zeta potential decays to zero at the isoelectric point and then becomes strongly negative. This positive-to-negative trend is seen with all oils, including pure hydrocarbons10-13 and crude oils.5,14,15 If the mineral surface is negatively charged, this change from positive to negative potential at the oil/brine interface leads to a change from attractive to repulsive electrostatics and to a change in wetting tendency from oil- to water-wet. Several studies5,16-18, have documented aspects of this pH dependence of wetting in crude-oil systems. Aronson et al.19 showed similar effects for hexadecane systems containing a long-chain amine, and other investigators20-22 showed that a pH dependence of contact angles exists even for a silica/air/water system. The pH dependence of wetting on silicate surfaces is thus a very pervasive phenomenon.
The interpretation of wetting presented here and elsewhere2-6,17 clearly shows that electrostatic repulsion is necessary for water-wetness. For perfect water-wetness, the repulsive force must be large enough to overcome the van der Waals attraction. This requirement for repulsive electrostatics means that the silica surface should be water-wet only above the. oil isoelectric point in silica/oil/brine systems. Therefore, oil-wet behavior is more likely at a given pH where the oil has a high isoelectric point.
Fig. 1 illustrates this situation for a California crude oil and for acid-washed silica (25°C and 0.02 M NaCl). This particular crude oil has a relatively high isoelectric point, between pH 6 and 7. Thus, as Fig. 1 shows, electrostatic attraction should lead to oil-wetting up to at least pH 7. Actual wetting results that confirm this prediction for this crude oil are presented later.
|File Size||3 MB||Number of Pages||6|