Laboratory-Based Prediction of Sulphate Scaling Damage
- Pavel Bedrikovetsky (UENF-LENEP) | Eric James Mackay (Heriot-Watt University) | Gladstone Peixoto Moraes | Francisca Ferreira Rosario (Petrobras) | Raphael P. Monteiro
- Document ID
- Society of Petroleum Engineers
- SPE International Oilfield Scale Symposium, 31 May-1 June, Aberdeen, UK
- Publication Date
- Document Type
- Conference Paper
- 2006. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 1.2.3 Rock properties, 4.1.2 Separation and Treating, 5.6.5 Tracers, 2.4.5 Gravel pack design & evaluation, 5.5 Reservoir Simulation, 5.6.4 Drillstem/Well Testing, 4.3.4 Scale, 5.2 Reservoir Fluid Dynamics, 1.8 Formation Damage, 5.4.1 Waterflooding
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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 reduction resulting in well productivity decrease.
The sulphate scaling damage system contains 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 analytical-model-based method for determination of kinetics coefficient from laboratory coreflood on quasi steady state commingled flow of injected and formation waters. The current study extends the method and derives formulae for calculation of formation damage coefficient from pressure drop measurements during coreflood.
The proposed method can be extended for axi-symmetric flow around the well allowing calculation of both sulphate scaling damage coefficients from field data on barium concentration in produced water and well productivity decline.
We treat several laboratory test data and field data, and obtain values of 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. It validates the proposed mathematical model for sulphate scaling damage and the analytical-model-based method "from lab to wells??.
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[1-3].
Decision making on scale prevention and removal is based on prediction of scaling formation damage provided by mathematical modelling.
The mathematical models for sulphate scaling during waterflood consist of mass balance equations for all species with the reaction rate sink terms[8-10,15]. Chemical reaction rate must obey law of acting masses[9,17,19] or another more complex kinetics law[18-20,23-25].
Several numerical[4,5] and analytical[6-8,14] models describing sulphate scaling in laboratory and field conditions are available in the literature.
Nevertheless, the problem of model coefficients determination from either laboratory or field data in order to use in sulphate scaling simulation is far from the final solution. It introduces significant uncertainty in scaling damage prediction.
The design and results of barium sulphate quasi steady state scaling tests have been presented in the literature[11-13]. The analytical model for quasi-steady state commingled flow of injected and formation waters in core allows solving the inverse problems of scaling model parameters determination from the laboratory test data.
The chemical reaction rate depends on reaction rate coefficient. The reaction rate coefficient can be determined from effluent barium concentration using the analytical solution. Treatment of laboratory data shows that the reaction rate is proportional to flow velocity, as it should be for reactive flows in porous media. The proportionality coefficient is called the kinetics coefficient.
The kinetics coefficient depends on rock and fluid properties. It cannot be predicted theoretically for real reservoirs and fluids. Therefore, it must be determined from either laboratory of field data by solution of inverse problems.
The second important parameter determining permeability impairment during sulphate scaling is the formation damage coefficient showing how permeability decreases with solid deposition.
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