The extraction of crude oils rich in tetraprotic naphthenic acids along with formation water under pH conditions above 6.5 favors the formation of naphthenic acid salts that can generate deposits with high consistency and very low solubility in the oil and water phases. There is still much uncertainty regarding the behavior of naphthenates, and only a small number of tests exist to evaluate it. The aim of this study was to obtain the parameters necessary to assess the formation of calcium naphthenate film through shear rheology (Du Noüy ring method) and to assess the rheological behavior of this film at the water/oil interface as a function of the ARN acid concentration, calcium concentration, presence of magnesium ions, and addition of commercial chemical inhibitors. We observed an increase in the elastic modulus (G′) and a reduction of the viscous modulus (G″) with the formation of the calcium naphthenate film and that the viscous deformation is restricted, which is coincident with the formation of a cross-linked network between the calcium ions and ARN acids. We also found that G′ increases with an increasing calcium ion concentration and salinity. The addition of the commercial inhibitors tested caused a reduction of G′ in relation to the control formulation (no inhibitor), with it being possible to distinguish their different performances in film formation prevention. However, we did not observe a correlation between the results of the biphasic mixture test and rheological assay throughout the concentration range tested.

Recent years have seen a wide-world increase in the production of acidic crudes rich in naphtenic acids (NAs). The presence of these compounds in crude may lead to two different problems: i)-the so-called naphthenic acid corrosion (NAC), and: ii)-formation of naphthenates (naphthenic acid salts) which can either precipitate or form interfacial active salts (soaps) that are prone to stabilize emulsions. The formation of naphthenates (NAPHs) during the W/O separation process is promoted by the pH increase of the produced water phase brought about by CO 2 degassing.NAC problems are well-understood and advantages in technologies to mitigate them are abundant. In contrast to this, NAPHs problems which are germane to the topside O/W separation settings are themselves a dimly understood problem. However, the combination of tailored chemicals and changes in the processing parameters is the best solution to keep NAPHs problems at bay.Taking these points as the main rationale this paper presents:-a description of NAPHs problems in the upstream crude oil sector; -a comprehensive description of the NAPHs problems Petrobras has been facing; -the analytical tools suitable to characterize and quantify the presence of NAPHs in the produced fluids; the suite of lab tests to screen chemical additives for field application; the difficulties in sparking actions to modify oil-processing parameters and to injecting chemical on an outsourced FPSO top-side facilities, and; the concert of solutions that have provided the best field results. This paper concludes with a suggestion that a comprehensive water and crude oil characterization program (including geochemistry studies) is totally necessary to cope with the macroscopic behavior of NAs in actual field conditions. IntroductionAs far back as the year 1980 our R&D flow assurance team has been aware of the NAPHs growing problems in different oilprovinces around the world. A literature review enables one to correlate these problems with a growing world-wide tendency to produce heavy-, bio-degraded-, NAPHs-rich-, high total acid number (TAN)-crudes 1 . Figure 1 depicts the variation of TAN (mg KOH/g of crude) as a function of 0 API for different crudes produced in Campos Basin, Brazil. Although there is not a strong correlation between these two variables, it is possible to identify an upward trend of TAN as crude oil density increases.

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