The search for the appropriate demulsifier for a water-in-crude oil emulsion is generally carried out through the well-known “bottle test” technique. A comprehensive approach is proposed here, which is based on earlier work on the rate of separation of surfactant−water−hydrocarbon mixtures, where it was found that “optimal” type III systems, in Winsor's nomenclature, exhibits the fastest separation rate. It is shown that the rules developed for microemulsion optimization apply to the selection of the demulsifier. They allow one to take into account the variation of salinity, temperature, crude-oil type, and so forth and provide an explanation for the demulsifier concentration effect. Interfacial tension measurements have been carried out. They show that the kinetics of demulsifier adsorption at the water−crude oil interface (or alternatively the Gibbs elasticity modulus) is correlated to the phase separation rate, as already described in the literature: the higher the kinetics, the faster the separation rate.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMany of the fields that have been discovered recently in the West African deep-offshore will produce acidic crudes associated with gas containing a high concentration of CO 2 .During the oil production process, a pH increase due to decompression and carbon dioxide degassing may generate surface-active naphthenates that can drastically stabilize emulsified water in crude oil. These may also combine with metal cations present in the reservoir water and form deposits. In all cases, production operations may be seriously disturbed.The aim of the work conducted was to assess naphthenate and scale inhibition and the various factors that can affect its efficiency. In particular, we studied scale inhibitor interactions on naphthenate prevention. This paper presents the results of studies on emulsion stability and naphthenate deposit formation, evaluated for various acidic crudes. As the pH increased, various behaviors were observed: progressive emulsion stabilization or abrupt transitions from unstable to stable emulsions. Naphthenate deposits formed in some cases even at low pH. Such a diversity of behaviors was explained in terms of differences in acid natures.To prevent emulsion stability and naphthenate deposits, selected demulsifier and scale inhibitor additives were then tested. Several types of demulsifiers were found to be efficient at both emulsion-breaking and naphthenate deposit inhibition. In some cases, mixtures of demulsifiers and scale inhibitors produced very good results, highlighting a synergetic effect between the two additives. Unfortunately, the use of scale inhibitors generally increased the calcium content of the oil phase. Basically, the use of scale inhibitor with acidic crudes degrades the oil quality in terms of water cut and metal content.

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