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Abstract In-situ barium sulphate precipitation was observed during coreflooding experiments conducted at frontal velocities of 0.31 m/day in fired Berea sandstone cores. The precipitate was observed during a laboratory study on the transport of sulphate ions contained within the injection water that displaced a synthetic formation water containing barium ions. Two separate cores were 100% saturated with formation water similar to that of a West African offshore reservoir (240 ppm barium and 230 ppm strontium) and were respectively flooded with synthetic seawater containing 2860 ppm sulphate and synthetic low-sulphate (desulphated) seawater containing 36 ppm sulphate. Careful measurement and comparison of flood effluent profiles of precipitating and non-precipitating ionic species such as sulphate, barium, strontium, etc. indicates that barium sulphate precipitated in situ during the flooding experiments. In the case of the seawater flood, approximately 27% of the barium that was contained in the formation water resident in the core was precipitated. In the case of the low sulphate seawater flood where the propensity for barium sulphate precipitation was low, results were less dramatic and determination of the exact amount of precipitated barium sulphate was less certain, e.g., approximately 10% of the barium was precipitated. Temperature and pressure conditions for these coreflooding experiments were ambient temperature (~70°F) and atmospheric pressure. The Berea cores utilized were 5.08 cm in diameter, 15.2 cm long, and averaged 112 md permeability and 17.5% porosity.
Results of this coreflooding study indicate that in-situ precipitation of barium sulphate occurs while even low-sulphate seawater is flooded through core material that is saturated with a formation water containing barium. During reservoir-scale flooding with low sulphate seawater, a favorable consequence of the barium sulphate precipitation is that the sulphate scaling potential is substantially reduced at the producing wells. This work represents a first step in generating experimental data that can be input into a mathematical simulator for predicting the propagation rate and the breakthrough time, under reservoir conditions, of the sulphate ions of the injection water — both for low and high sulphate content injection waters.
Introduction The production problems caused by mineral scale in oil production operations have long been known. Among the most onerous of all scaling problems is that of sulphate scales, particularly barium sulphate scale. This is a difficult scaling problem because of the low solubility of barium sulphate in most fluids and the commensurate low reactivity of most acids with barium sulphate scale. Deposition of barium sulphate into a continuous scale surface on production tubulars exposes very little surface area for treatment by chemicals, and therefore this scale is almost impossible to remove once it is deposited. The most popular approach to addressing the barium sulphate scale problem has been to retard or prevent the formation of this scale in the first place. Scale inhibitors that are periodically pumped down production wells and into the producing formation for short distances around the wellbore have been developed and are widely utilized. The inhibitor contacts the formation and is adsorbed onto the reservoir petrofabric. It is later slowly released into the produced fluids, thereby inhibiting the formation of sulphate scales for some period of time, usually several months. When the inhibitor concentration levels fall too low to be effective, the well is again squeezed with chemical and the cycle is repeated. This technique is widely known as ‘squeeze inhibition.’
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