It is generally assumed that scale inhibitor squeeze treatments in production wells are displaced radially into the formation, since it is normal to pump these treatments below the fracture pressure. However, it is known that thermal stresses as a result of injecting cold fluids can result in thermally induced fractures (TIF). The first question that this paper addresses is the evidence of thermal fracturing during low volume (<10,000 bbl) treatments, and then, secondly, what would be the impact on squeeze life of treating a well that was fractured during treatment vs a non-fractured well.

The process involves modelling of fractured and unfractured treatments to identify what are the advantages and disadvantages of temporarily fracturing a well during a squeeze treatment in terms of inhibitor placement. While inhibitor may be placed at a greater distance from the wellbore if the formation is fractured during the treatment, the surface area of rock contacted during the treatment may be less than is the case in radial displacements. Issues such as consolidated vs unconsolidated formations, initial reservoir temperature, fluid temperature at the sandface during injection, injection rate and fracture dimensions should be considered.

In general, this work demonstrates that there are clear advantages to temporarily fracturing a well during a squeeze treatment, depending on the inhibitor return concentrations required to prevent mineral scale formation.

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