The formation damage in scaled-up production wells caused by incompatibility of injected and formation waters have long been known. Precipitation of salts results in permeability decline. Among the most onerous of all scaling species is that of sulphates, particularly barium and strontium sulphates. We study effects of porous media on the BaSO4 scaling kinetics. A new methodology for determination of reaction rate coefficient from coreflood tests consists of the sequence of diffusivity reaction free tests, of transient tests with chemical reaction, and of simultaneous injections of both injected and formation waters with quasi steady state concentration profiles for barium and sulphate ions. The diffusivity tests serve for dispersivity coefficient determination. Quasi steady state tests allow determination of the reaction rate coefficient versus velocity. The transient test data as compared with the mathematical modelling data validate the model and the data of steady state test data treatment. An analytical model developed is used for treatment of quasi steady state test data. The transient tests are treated by a numerical model. The main result of the work is proportionality between the reaction rate coefficient and flow velocity for the parameter range studied. Introduction The BaSO4 scaling is a chronicle disaster in waterflood projects with incompatible injected and formation waters. This is usually due to precipitation of barium sulphate from the mixture of both waters and consequent permeability reduction1–3. The rate coefficient for the reaction between incompatible chemical species in injected and formation waters is the main parameter that determines the oilfield scaling intensity in cases where the aqueous solution is far from equilibrium. This rate is highly affected by flow velocity, diffusion/dispersion in porous media, pore space geometry and, therefore, the reaction rate coefficients inside and outside porous media should be different. Nevertheless, presently the reaction rate coefficients used in mathematical modelling are obtained in laboratory reactors without porous media4–8. Usually the solid grains are used during water mixing in reactors in order to induce the precipitation centres, but the pore space structure and the relative fluid-rock flows are not represented. The mathematical models for reactive flow in porous media consist on mass balance equations with the reaction rate sink terms8–10. The rate terms should depend on porous media properties. In order to reliably predict well behaviour during the oilfield scaling, the effect of porous media flow on chemical reaction rate should be studied systematically. The design and results of barium sulphate steady state scaling tests allowing for such study have been presented in the literature11–13. Nevertheless, there were no attempts to determine the reaction rate coefficients from laboratory coreflood tests. The laboratory and mathematical study of scaling formation in porous media has been performed13,14. The sequence of coreflood tests allowing for determination of the reaction rate coefficient for various flow conditions has been proposed:displacement of water by traced water at the absence of reaction in order to determine diffusion coefficient;displacement of Ba-rich formation water by SO4-rich injection water (transient tests);simultaneous injection of Ba-rich formation water and SO4-rich injection water (steady state tests). The diffusive tests allow determining the diffusion coefficient dependency of flow velocity for a given core15. The quasi steady state tests being performed at different velocities determine the reaction rate coefficient versus flow velocity. The transient tests allow comparing experimental results with the data of numerical modelling based on the steady state test data.

In a joint R&D project under the full sponsorship of PETROBRAS, the Brazilian National Oil Company, the first CO 2 monitoring field lab was started-up in Brazil in 2011.The site chosen, the Ressacada Farm, in the Southern region of the country, offered an excellent opportunity to run controlled CO 2 release experiments in soil and shallow subsurface (< 3 m depth). This paper focuses on the presentation and comparison of the results obtained using electrical imaging, CO 2 flux measurements and geochemical analysis of the groundwater to monitor CO 2 migration in both saturated and unsaturated sand-rich sediments and soil. In 2013 a controlled release campaign was run, covering an area of approximately 6,300 m 2 . Commercial food-grade gaseous carbon dioxide was continuously injected at 3 m depth for 12 days. The average injection rate was 90 g/day, totaling ca. 32kg of gas being released. The low injection rate avoided fracturing of the unconsolidated sediments composing the bulk of the local soil matrix. Monitoring techniques deployed during 30 consecutive days, including background characterization, injection Andresa Oliva et al. / Energy Procedia 63 ( 2014 ) 3992 -4002 3993and post-injection periods, were: (1) 3D electrical imaging using a Wenner array, (2) soil CO 2 flux measurements using accumulation chambers, (3) water sampling and analysis, (4)3D (tridimensional) and 4D (time-lapsed) electrical imaging covering depth levels to approximately 10 m below the surface. Water geochemical monitoring consisted of the analyses of several chemical parameters, as well as acidity and electrical conductivity in five multi-level wells (2m; 4m and 6 m depth) installed in the vicinity of the CO 2 injection well. Comparison of pre-and post-injection electrical imaging shows changes in resistivity values consistent with CO 2 migration pathways. A pronounced increase in resistivity values occurred, from 1,500 ohm.m to 2,000 ohm.m, in the vicinity of the injection well. The accumulation chamber assessment show significant changes in the CO 2 flux during the release experiment: maximum values detected were ca. 270 mmol/m 2 /s(during injection) as compared to background values of c.a. 34mmol/m 2 /s. The pH showed variations after CO 2 injection in two monitoring wells at 2m, 4m and 6m depth. After the CO 2 injection ceased, the lowest pH measured was 4.1, which represents a decrease of 0.5 relative to the background values. Slight variations in the oxidation-reduction potential (Eh) were observed near the CO 2 injection well. There was a decreasing trend of this potential, especially in a monitoring well at 6m depth, ranging from 308mV to 229mV, between the background and the injection scenarios. Ppb level increments were detected in the measurements carried out for the major cations (Ca, Mg, Na, and P) and trace elements (Ag, Al, As, B, Ba, Cd, Pb, Cu, Cr, Ni, Mn, S, V, and Zn). Electrical conductivity and alkalinity, however, remained constant throughout the experiment, with values around 40 μS.cm -1 and 2.5 mgCaCO 3 .L -1 , r...

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Over the last 15 years, much research and many field application studies have led to considerable improvement in our understanding of the formation and mitigation of calcium naphthenate deposits.In this field example, calcium naphthenates and stable emulsions are formed following mixing of fluids from different reservoir formations on a single FPSO. High TAN crudes containing low levels of ARN produce with low calcium formation waters whereas low TAN crudes are associated with high calcium formation waters. Mixing of these two systems has led to calcium naphthenate deposition and associated problems with its removal.This paper outlines the challenges in this complex deepwater subsea production system and the interpretation of the cause of the deposit. A series of laboratory tests using a specialised flow rig were conducted to illustrate the effects of mixing different fluids and identify those mixtures with the largest naphthenate potential.The work further illustrates the effect of bicarbonate ions on the system. Laboratory tests at low levels of bicarbonate (to prevent carbonate scaling at separator conditions) do not result in calcium naphthenate formation when mixing the high TAN crude with the current produced brine (moderate calcium). Naphthenates only formed when mixing with the high calcium brine. When bicarbonate is included at full field levels (in the presence of a scale inhibitor) significant calcium naphthenate formation is recorded with the lower calcium brines. The effect of CO 2 within the produced fluids has also been evaluated.The paper describes how several variables contribute to the likelihood of calcium naphthenate deposition and presents results from several naphthenate formation and inhibition tests covering a range of fluid compositions and mixtures. Chemical qualification in the lab using the worst case fluid mixtures has been conducted to select a calcium naphthenate inhibitor for field deployment. Field trials demonstrate both the effectiveness of the treatments and also the qualification exercise conducted for this field.The results further indicate the complexity of accurately predicting a calcium naphthenate risk while illustrating that, even under challenging conditions, chemical inhibitors are effective in this system.