Interfacial Shear Rheology of Calcium Naphthenate at the Oil/Water Interface and the Influence of pH, Calcium, and in Presence of a Model Monoacid

In this article, the interfacial shear rheological properties of calcium naphthenate with a model tetraacid at the chloroform/xylene-water interface has been investigated as a function of aqueous pH, calcium concentration and monoacid concentration. The experiments are carried out using an interfacial rheology system with an electro commutated motor, direct strain oscillation and a biconical bob geometry. The model tetraacid used, BP10, has previously been shown to have similar bulk and interfacial properties as a narrow group of tetraprotic, so-called Arn acids, and these acids are known to be responsible for formation of hard deposits during oil recovery. A great increase in the elastic modulus was observed around pH 6.2, which is in agreement with observations from oil fields with calcium naphthenate deposition problems. The gel strength and elastic nature is highest around the gelation onset, believed to be due to a bilayer-like conformation of the tetraacid generating a densely packed interface with high cross-linking density and possible film growth. As a function of calcium concentration, both a reduction of the gel strength and slower gel formation was observed when decreasing the calcium concentration from 10 to 4 mM. Myristic acid, a linear C14 fatty acid, was employed as a model for indigenous monoacids and the influence onto the viscoelastic properties of the Ca2+-TA film was studied as a function of myristic acid concentration at pH 8.0 and 6.5. A great reduction of both the gel strength and elasticity was obvious in the range of 100 to 1000 higher monoacid than tetraacid concentration. This is however typical indigenous acid concentrations for an acidic crude oil, and may indicate that indigenous monoacids have the ability to act as indigenous inhibitors towards formation of calcium naphthenate. This could explain why some Arn-containing acidic crude oils have deposition problems while others do not. Moreover, all parameters should be taken into account when predicting the deposition risk for a given crude oil, such as concentrations of Ca2+, Arn, monoacids and other indigenous acids.