Abstract

This paper presents a coupled chemical-hydro-mechanical model for the evaluation of the fluid behavior around an injector well taking into account insoluble salt precipitation (barium and strontium sulfate). A salt precipitation model is developed and coupled with the ion transport equation describing the ion movements and reactions through porous media. The finite element method has been used to obtain the solution for the coupling amongst the ion transport, the fluid flow and the mechanical response of the rock. A computer program has been developed to solve this highly nonlinear problem. Results of an experimental test1 carried out in a sand pack with the analysis of the barium sulfate crystal growth was selected as benchmark to test the computer program developed using the methodology described above, showing an excellent agreement between the numerical and the experimental results.

Introduction

The water produced during oil recovery, demands expensive treatment before being discarded due to environmental issues. One economical alternative to handle this formation water is its re-injection into the producing reservoir, or alternatively into another permeable formation. However, water injection program may have low efficiency due to formation damage around the injected wellbore. This formation damage is the result of interaction between the injected fluid (chemical composition, solid particles and percentage of oil emulsion) and the rock formation. In this work, we focus our attention to the damage caused by the differences between the chemical composition (Table 1) of the injected fluid and the formation fluid. This fluid mixing process may generate the precipitation (scale) of some salts in the rock pores, and consequently, causes a permeability reduction. The most commonly found scales are the carbonate and sulfate salts of calcium, barium and strontium. Carbonate scale are softer and tend to be acid soluble, i.e., can be removed from the wellbore through an acidification operation. The concern with sulfate scale is justified due to their relative hardness and low solubility, that is, cannot be dissolved easily in the field.

Another important issue is that the fluid is subjected to a high temperature variation during injection process. Initially, the water is injected at high temperature (40°C). During the water depth the fluid is cooled, for ultra-deep wells, it could arrive to a temperature in order of 3°C. After that, due to the geothermal gradient, the fluid is heated again, arriving to temperature around 115°C for deep reservoirs. This high temperature variation increases the amount of salt precipitation.

Formation damage models that include chemical effects have already been developed2–7. Malate3 presents a mathematical model of silica deposition during the reinjection of seawater using the method of characteristics. Walsh et al.4 developed a geochemical model to simulate the reactive fluid flow in porous media. Wu and Sharma5 extended Walsh's model to include the migration of precipitate solids. Chang and Civan6 developed a mathematical model to simulate the permeability alteration mechanisms caused by various physical and chemical interactions between fluids and reservoir rocks. Araque-Martinez and Lake7 developed a model to characterize the geochemical changes that occur in a permeable medium with flow and reaction under a consistent kinetic formulation.

In the current work, a salt precipitation model is developed and coupled with an ion transport equation describing the ion movements and reactions through porous media. The finite element method has been used to obtain the solution for the coupling amongst the ion transport and reaction, the fluid flow and the mechanical response of the rock. It is followed a different approach from the papers mentioned above. The developed model simulates injection under conditions, of high temperature and pressure variations and high salinity.

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