Oilfield scale management based on produced water composition
Motta Gomes, Roberto
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Evaluation of the scaling risk at production wells is generally carried out using thermodynamic prediction models. These models are generally very accurate in terms of predicting the type of scale that may form, the degree of supersaturation, and the mass of scale that will deposit when the system reaches equilibrium – provided the brine composition or compositions involved are well known, and the pressure and temperatures conditions are accurately specified. However, in performing these calculations, engineers often fail to take account of reactions occurring in the reservoir, and assume that brines reaching the production wells have not reacted in any way prior to entering the wellbore. This often leads to a significant overestimate of the scaling risk. This work seeks to address this issue by studying field data from a variety of sources to identify what can be learnt from the produced brine compositions, and by simulating various possible scenarios using reservoir simulation calculations, and taking account of potential reservoir reactions, but also considering other factors, such as reservoir properties and architecture, fluid properties, etc., that may impact the composition of the brine by the time it reaches the production wells. This work also provides the basic information regarding commercial reservoir simulators with a focus on reservoir scale management. Black-oil, semi-compositional and fully compositional simulators will be analysed with this purpose. Finally, this work will present a scale management strategy based upon the use of an integrated approach, that considers both flow and thermodynamical properties of the reservoir, aided by numerical simulations. This approach can lead to a more realistic forecast of scaling potential, leading to the development of optimized scale management strategies.