Modelling scale inhibitor treatments in horizontal wells is emerging as an important field of research due to the need to reduce the cost of treating wells that may be thousands of feet long. Simulation studies performed using recently developed modelling tools have led to recommendations that have reduced the risk of chemical upsets at the wellhead and extended squeeze lifetimes downhole.

However, as an increasing number of "problem wells," such as high crossflow wells, need be treated to prevent scale formation, these models have to be adapted to enable them to capture the complex range of properties that make these systems so problematic. Diverter technology is being developed to enable optimal placement of chemical inhibitor, but to study the impact of the diverter on the squeeze performance, the fluid flow properties in the near-wellbore region must be modelled accurately. This is done by using a full-field reservoir simulation model that includes sufficient detail in the near-well formation not only to capture the fluid flows, but also to model accurately the chemical placement and recovery. The model can assess the impact of various placement strategies, as well as assist in determining the optimal fluid and chemical volumes.

A case study from the North Sea where a gel diverter was selected to assist inhibitor placement is presented. The study demonstrates the types of calculation that can be made, and what information can be usefully supplied to the field engineer designing squeeze treatments.

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