Dependent upon the conditions of pH and water content, an acidic crude oil may form different type of emulsions with different stability. These oils generally contain large amounts of naphthenic acids, RCOOH, which result from crude oil biodegradation. They also contain heavier compounds such as asphaltenes and resins. All of these amphiphiles may contribute to the formation and stability of emulsions. In this work, an acidic crude oil (total acid number ) 1.25) was distilled in three fractions to separate naphthenic acids from resins and asphaltenes. The influence of pH and water content on the type and stability of emulsions prepared with the crude oil and its fractions was investigated. The role of the light, intermediate, and heavy amphiphiles present in the crude oil on its emulsifying properties has been discussed by comparing the emulsion type and stability diagrams obtained for the different oil phases. It has been found that the type of emulsion is governed by the acidic amphiphiles contained in the intermediate fraction. The stability of oil-in-water emulsions is ensured by electrostatic repulsion between the naphthenates, RCOO -, present at the interface, whereas that of water-in-oil emulsions is due to the amphiphiles contained in the heavy fraction, i.e., asphaltenes and resins.

Many of the fields that have been or will be discovered in the near future show signs of biodegradation of the crude oil. The result of such biodegradation is a decrease in the amount of the paraffins associated with the formation of naphthenic acids. Some of these crude oils may have a Total Acid Number (TAN) close to 5mg/g. When the reservoir fluid contains a significant amount of CO2, one can expect to find mixed scale of calcium carbonate and naphthenate. The aim of the work conducted was to assess the various factors which affect the formation of mixed scale. We studied, in particular, the consequences arising from the formation of highly surface-active naphthenates which, depending on the nature of the cations in the formation water, can form stable emulsions, calcium naphthenate deposits or mixed scale of calcium carbonate and calcium naphthenate. This paper presents the ways to prevent emulsions or deposits resulting from the formation of naphthenates. Chemical prevention is the most commonly used method but problems can sometimes be solved by modifying the way crude is processed. We will also describe an example of a modified process that we plan to use. Introduction The fields recently discovered in deep offshore in Angola, in the Congo or in Nigeria produce an oil with a high acid content. This observation is not limited to West Africa, as some fields from the North Sea and from Venezuela have the same characteristics (shown in Table 1). The naphthenic acids in petroleum are considered to be a class of biological markers1,2,3, closely linked to the maturity and the biodegradation level of the fields. The naphthenic acids are found predominantly in immature biodegraded, heavy crudes4. The alteration of petroleum by living micro-organisms, which may occur for example when meteoric water is introduced into an accumulation5, significantly increases the density of the crude and, at the same time, decreases the paraffinic components content. On the basis of this, we can presume that acidic crudes most likely contain low levels of paraffins and have higher densities than non acidic crudes. The correlation is quite good for all the wells from the same field or all the fields located in the same block. Table 2 gives some of the characteristics of crudes from Angola block 17: their TAN value, level of paraffin and API degree. The table clearly shows that the increase in the level of paraffin and in the API degree are associated with a decrease in acidity. The results are illustrated in figure 1 which shows the relation of TAN versus the level of paraffin, and in figure 2 which illustrates the relation of TAN versus API degree. In addition to corrosion during the refining of acidic crudes, the naphthenic acids are also responsible for two other problems observed in crude processing, resulting from an increase in the pH of the reservoir water:The formation of mixed carbonate and soap deposits inside tubing or surface installations.The build-up of stable emulsions associated with the strong surface-active power of the naphthenate group RCOO-. These problems can be avoided through measures which prevent the pH value of the reservoir water from rising.

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