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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe formation of calcium naphthenate precipitates and emulsions during oil production is becoming an increasing problem to the oil industry. Naphthenic acids, R-CO 2 H, are present in many crude oils and the hydrophilic nature of the carboxylic acid group means that they congregate at the oilwater interface. As the pressure drops during production and carbon dioxide is lost from solution, the pH of the brine increases, which in turn leads to dissociation of the naphthenic acid (RCO 2 H -> RCO 2 -). The naphthenates can then act as natural surfactants leading either to stabilised emulsions or solid deposits following complexation with calcium cations present in the aqueous phase. The naphthenate deposits collect predominantly in oil / water separators and de-salters but can also deposit in the tubing and pipelines.This study has looked at a variety of conditions to determine when certain carboxylic acids will form naphthenate deposits under idealised laboratory conditions. A range of naphthenic acids of different molecular structure were dissolved in an organic phase (toluene) and mixed with synthetic brines containing a range of calcium concentrations typical of oilfield production waters. These tests have determined that as the size of straight chain carboxylic acids increases so does the amount of naphthenate deposit. Increases in brine pH also increased the amount of deposit. However, the effects of changes in calcium concentration and molecular structure on the formation of naphthenate deposits were more difficult to quantify. The work assists in increasing our understanding of the factors controlling the precipitation of naphthenate solids under controlled conditions and forms the basis for future studies in real oilfield fluids.

With the development of a number of new HT/HP fields in the North Sea, for example the ETAP fields (Eastern Trough Area Project), a number of important "scale" control issues have arisen. In addition to harsh downhole conditions (T - 180 C; P - 13,000 psi), high salinity formation water chemistries indicate that the control of inorganic precipitates in these systems will be very important. The form of the inorganic precipitates are predicted to include the more Cornnjton oilfield scales (BaSO4 and CaCO3). In addition the very high salinity of several of the formation brines (TDS - 350,000 ppm) can result in halite precipitation (NaCl(s)). This occurs either as a result of water flash-off into the gas phase as pressure decreases during production or simply due to reduced halite solubility as temperature and pressure decline during production. This paper discusses the potential scaling problem associated with these harsh reservoir conditions and outlines various solutions for treating such reservoirs using conventional scale inhibitor technology. A series of different generic scale inhibitor chemistries have been assessed for their potential application in such reservoirs. The assessment has involved a range of laboratory procedures including thermal stability, brine compatibility, carbonate and sulphate inhibition efficiency testing. These tests were conducted at temperatures up to 180C. The laboratory screening procedures led to the selection of the most appropriate generic chemical types which are applicable for scale inhibitor treatment under HP/HT reservoir conditions. Further studies then examined the most appropriate species for application downhole as squeeze treatment chemicals under HP/HT conditions. This included static adsorption tests conducted at temperatures and pressures ranging from 950C at saturated vapour pressure (SVP) to 180C and 7,500 psi. Reservoir conditioned core flooding studies were conducted on the two most appropriate species in order to assess formation damage issues and to derive their respective adsorption isotherms in order to model potential squeeze lifetimes. P. 645

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