Francisca Ferreira Rosario

Laboratory-Based Prediction of Sulphate Scaling Damage

BaSO4 scaling can have a disastrous impact on production in waterflood projects with incompatible injected and formation waters. This is due to precipitation of barium sulphate from the mixture of both waters, the consequent permeability reduction resulting in loss of well productivity. The system where sulphate scaling damage occurs is determined by two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient reflecting permeability decrease due to salt precipitation. Previous work has derived an analytical model-based method for determination the kinetics coefficient from laboratory corefloods during quasi-steady state commingled flow of injected and formation waters. The current study extends the method and derives formulae for calculation of the formation damage coefficient from pressure drop measurements during the coreflood. The proposed method can be extended for axisymmetric flow around the well allowing calculation of both sulphate scaling damage coefficients from field data consisting of barium concentrations in the produced water and well productivity decline. We analyse several laboratory test data and field data, and obtain values of the two sulphate scaling damage parameters. The values of kinetics and formation damage coefficients as obtained from either laboratory or field data vary in the same range intervals. These results validate the proposed mathematical model for sulphate scaling damage and the analytical model-based method “from lab to wells”. Introduction It has been long recognised that formation and well damage may be caused by incompatibility of injected and formation waters. Precipitation of salts results in permeability decline. Among the most significant of all scaling species are the sulphates, particularly barium and strontium sulphates. Decision making on scale prevention and removal is based on prediction scale precipitation and damage is provided by mathematical modelling. The mathematical models for sulphate scaling during waterflooding consist of mass balance equations for all species with the reaction rate sink terms. Chemical reaction rate must obey law of acting masses or another more complex kinetics law. Several numerical and analytical models describing sulphate scaling under laboratory and field conditions are available in the literature. Nevertheless, the problem of determining model coefficients from either laboratory or field data to use in sulphate scaling simulation is far from resolved. This SPE 100611 Laboratoryand Field Prediction of Sulphate Scaling Damage P. G. Bedrikovetsky, SPE, North Fluminense State University (LENEP/UENF); E. J. Mackay, SPE, Heriot-Watt University; R. P. Monteiro, North Fluminense State University (LENEP/UENF); P. M. Gladstone, Cefet-Campos/UNED Macae; F. F. Rosario, SPE, Petrobras/CENPES

Injectivity Impairment due to Sulphate Scaling during PWRI: an Analytical Model

Previous work has derived an analytical model for simultaneous flow of incompatible waters in porous media with sulphate salt precipitation, determined typical values of the kinetics reaction coefficient from corefloods and what the impact would be on productivity impairment during sulphate scaling. This paper extends the previous work, by modelling the injectivity impairment during simultaneous injection of incompatible waters, i.e. cation-rich produced water (PWRI) and seawater with sulphate anions. An analytical model with explicit expressions for deposited concentration and injectivity decline was developed. The location of scale deposition and the resulting injectivity impairment are calculated for a range of sensitivities, including reaction kinetics (ranging from minimum to maximum values as obtained from coreflood and field data), fraction of produced water in the injected mixture and barium concentration in produced/re-injected water. The theoretical parameter of the size of formationdamaged zone was introduced. It was found that almost all deposition takes place in a neighbourhood occupying a distance 2-4 times the well radius. Calculations show that simultaneous injection of seawater with produced water containing even decimal fractions of ppm of barium would results in significant injectivity decline. Introduction Sulphate scaling with consequent deposit formation and wellbore damage is a well-known phenomenon that occurs during waterflooding, when mixing of incompatible injection and formation waters may result in sulphate salt precipitation and flow restriction. The most significant damage occurs in and near production wells, where dispersion and chemical kinetics are particularly high due to high fluid velocities, and where the mixing of the different brines is most pronounced. Sulphate scaling productivity impairment has been widely reported for North Sea, Gulf of Mexico and Persian Gulf fields. Produced water re-injection (PWRI) involves injection of some additional water in order to fulfil the injectionproduction volumetric balance. In offshore waterflood projects, PWRI is complemented by seawater injection. The produced water may contain barium, strontium, magnesium and other metal cations, as well as seawater that is sulphaterich. Simultaneous injection of incompatible waters results in sulphate salt deposition and consequent injectivity impairment. The injectivity decline depends on the metal cation concentration in the injected water, the formation damage coefficient, the kinetics of chemical reaction and of salt deposition, the rock permeability and the injection rate. The SPE 100512 Injectivity Impairment due to Sulphate Scaling during PWRI: Analytical Model P.G. Bedrikovetsky, SPE, North Fluminense State University (LENEP/UENF); E.J. Mackay, SPE, Heriot-Watt University; R.P. Monteiro and F. Patricio, North Fluminense State University (LENEP/UENF); F.F. Rosario, Petrobras/CENPES

PCA: uma ferramenta para identificação de traçadores químicos para água de formação e água de injeção associadas à produção de petróleo

This study describes the use of Principal Component Analysis to evaluate the chemical composition of water produced from eight oil wells in three different production areas. A total of 609 samples of produced water, and a reference sample of seawater, were characterized according to their levels of salinity, calcium, magnesium, strontium, barium and sulphate (mg L-1) contents, and analyzed by using PCA with autoscaled data. The method allowed the identification of variables salinity, calcium and strontium as tracers for formation water, and variables magnesium and sulphate as tracers for seawater.

Preferential incorporation of sulfate into calcite polymorphs during calcium carbonate precipitation: an experimental approach

Experimental validation was given to molecular dynamics calculations regarding the preferential retention of sulfate ions in the calcite polymorph of calcium carbonate. This retention results in calcite crystal habit imperfection and changes the polymorphs stabilization.

Mathematical modelling of scaling in a reservoir which contains impermeable layers

Several different scenario of injected and reservoir water mixing have been proposed: mixing at high velocity near to injectors, mixing at low velocity inside reservoirs, mixing by diffusion via boundaries of layers with different permeabilities, mixing of injected, connate and aquifer waters at high velocity near to producers. Just the latter mechanism results in the accumulation of formation damage, while other mechanisms cause precipitation near to moving concentration front. In the current paper a new mechanism of oilfield scaling by diffusion of Barium from impermeable layer into the reservoir is proposed. The mechanism results in accumulation of precipitant and of formation damage. Viscous dominant regime of waterflooding takes place in the majority of oil fields. The Welge´s method allows calculating the permeability distribution from water cut history. The proposed extension to Welge´s method determines the partition of permeable layers in a reservoir from tracer concentration in production wells. Knowledge of this partition is important for modelling of oilfield scaling accounting for Barium supply from impermeable layers.