In the oilfield, coproduction of water with petroleum is unavoidable. Thus, operations engineers and field staff continually face scale and water compatibility problems. A thermodynamic geochemical model can be a valuable tool for prediction, identification and resolution of scale and water compatibility problems. This paper demonstrates the utility of such a model by investigating scale precipitation throughout a production system – –in the injection side, within the reservoir, in the wellbore and in treating facilities.


Scale problems occur when the concentrations of dissolved species in a water exceed saturation limits. The species then combine and precipitate as minerals. The resulting deposits present a variety of problems for the oilfield operator, such as plugged perfs, downhole equipment failure, loss of efficiency in surface equipment and reduced permeability in the reservoir. For injection and disposal wells, scale deposits within the reservoir can cause loss of injectivity, formation fracturing and water injection out of zone. On the production side, scale deposits within the reservoir can even lead to last reserves. These problems increase costs, due to more frequent workovers and increased use of chemicals, and reduce revenue, due to lost production.

The most common oilfield scales are calcium carbonate (e.g., calcite, CaCO3), calcium sulphate (e.g., gypsum, CaSO4), barium sulphate (barite, BaSO4) and complex iron oxides (e.g., ferrous hydroxide, Fe(OH)2 and magnetite, Fe3O4) and sulphides (e.g., troilite, FeS and marcasite, FeS2). While almost all iron containing scales are associated with corrosion, the other scales usually result from species originally dissolved in the water. Precipitation of these scales is due to change in the water chemistry. In the oilfield, changes in water chemistry can be induced by;

  • a change in temperature, such as from the reservoir to the surface, in lines and treating vessels or from the surface to the reservoir. The solubility of barite increases with increasing temperature, while the solubility of carbonate scales, such as calcite, decreases with increasing temperature.

  • a change in pressure, such as across the perfs, up the tubing, across valves, in treating vessels or from the surface to the reservoir. In general, the solubility of most scales increases with increasing pressure, but the dependence is usually weak.

  • exchange of gases. Exchange of gases is often associated with a change in pressure. Reservoir fluids (oil, gas, water and solvents) can also act as a source or sink for gas exchange. The solubility of carbonate scales decreases dramatically with increasing pH, which is frequently caused by loss of CO2 or H2S from the water. Boilers and gas wells commonly encounter scale problems due to concentration of dissolved species by water evaporation.

  • mixing of waters, such as waters from different reservoirs or zones, waters from several process streams or formation water and injected water.

  • the addition of chemicals, such as some oxygen scavengers.

Scaling tendency is often characterized by simple, empirical correlations. Perhaps the best known example is the Stiff-Davis1 stability index for calcite. If the calculated stability index is positive, then the mineral is supersaturated and expected to precipitate.

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