Evaluation of the scaling risk at production wells is generally carried out using thermodynamic prediction models. These models are generally very accurate in terms of predicting the type of scale that may form, the degree of supersaturation, and the mass of scale that will deposit by the time the system reaches equilibrium -provided the brine composition or compositions involved are well known, and the pressure and temperatures conditions are accurately specified. However, in performing these calculations, engineers and chemists often fail to take account of reactions occurring in the reservoir, and assume that brines reaching the production wells have not reacted in any way prior to entering the wellbore. This often leads to a significant overestimate of the scaling risk.The work presented in this paper addresses this issue by studying data from various fields to identify what can be learnt from the produced brine compositions. A new technique to estimate the range of scaling tendencies that takes account of reservoir precipitation is developed, and the results are displayed in a 3D response surface. This is illustrated for barium sulphate scaling tendency, accounting for different levels of ion stripping.In order to calibrate some simulation parameters, and to identify the more important equations that should be inserted in the reservoir simulation, studies were performed based on the observed data. Different reservoir simulations were used and compared, with a focus on scale management to identify positive and negative aspects of each one.This work has identified that in fields with reservoir temperatures above 120°C and calcium concentrations above 7000 mg/l, significant sulphate stripping occurs due to anhydrite precipitation. This effect is increased where ion exchange leads to a reduction in magnesium and an increase in calcium concentration as the injected brine is displaced through the reservoir.

Solutions of the hydraulic diffusivity equation are of utmost importance for many reservoir engineering problems. Despite all the efforts, there is still a need for the development of rigorous and comprehensive solutions for transient flow problems in heterogeneous oil reservoirs. This study demonstrates the use of an integral transform approach to obtain such a rigorous and comprehensive solution for the hydraulic diffusivity equation in heterogeneous porous domain. The reservoir heterogeneities can be approximated by any continuous differentiable function. The presented general solution and its derivation are valid for multidimensional problems in any orthogonal coordinate system. It has the advantage of rigorously solving the hydraulic diffusivity equation for transient, late-transient and steady-state (or pseudo-steady-state) flow regimes in a single formulation that allows the consideration of variable flowrates. In this work, applications of the general solution for one-dimensional problems in the Cartesian and radial coordinate systems are presented, showing comparisons of the results obtained with a finite difference numerical scheme. The solution presented can be used to analyze buildup, drawdown and interference test data, making it a useful tool for pressure transient analysis applied to reservoir engineering problems.

In Campos Basin, deepwater offshore Brazil, permanent downhole gauges are used to record pressure and temperature. Pressure data are used extensively in well analysis, but temperature data have seen little use. Production data indicate that downhole temperature changes as a function of flowrate, pressure and fraction of fluids. A strong relationship was observed between flowing temperature and gas-oil ratio (GOR), caused by cooling upon expansion. It has also been observed that temperature data can be used to detect scale occurrence, aiding reservoir management. This paper proposes a methodology based on a semi-empirical equation that makes use of downhole temperature data to estimate GOR. The energy balance applied to the wellbore was simplified to generate an equation suitable to use with easily obtainable field data. The resulting equation has two unknown parameters, which are obtained by adjusting the model to field data. The inputs used to calibrate the model are GOR, oil flowrate, watercut and downhole temperature. The use of this methodology to three horizontal wells will be presented. For well C, the mean error obtained while estimating the GOR measured at the tests was 6.6%. In well B, the mean error was 11%. Well A has passed through a wide range of liquid flowrates, and over the 150 production tests that were performed before water breakthrough, the model was able to estimate the GOR with a mean error of 5.4%. However, after water breakthrough it could not reproduce the measured data accurately. In Campos Basin, accurate GOR measures are difficult to obtain, particularly after gas-lift start-up, because gas flowrate measurement is unreliable and test separators are often unavailable. Using this methodology, it is possible to obtain estimates of the GOR, which is desirable for an improved definition of the waterflood strategy and as a refined input for material balance in specific regions of the reservoir.

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Monitoring of downhole flowing temperatures in oil wells is gaining attention in the recent years due to the possibility of exploring these data for reservoir characterization and determination of inflow profiles along the well completions, leading to an increased interest in the development of solutions for the equations governing the thermal behavior of a reservoir. In this work, it is proposed to use the generalized integral transform technique (GITT) to provide solutions for the energy balance equation, considering the thermal effects related to fluid flow. A formal and general solution for the energy balance in the porous media is presented and validated. It is presented the application of the proposed solution to one-dimensional and two-dimensional problems in the Cartesian coordinate system. The two-dimensional problem, which considers heat transfer to the surrounding impermeable formations, is tackled by a single domain formulation. The mathematical approach taken in these solutions is rigorous, valid for all flow regimes (transient, late-transient and pseudo-steadystate/steady-state) and for any orthogonal coordinate system, presenting the possibility of achieving differentiable and stable solutions with controlled accuracy. The solution comprises an important contribution to support the application of temperature data to reservoir engineering problems.