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.
Oilfield scale is a concern associated with water production in many fields. The severity of the problem and the most cost-effective solution depend on the field operating conditions. A number of remedial and proactive scale-management options are available, including chemical and non-chemical based alternatives. It is commonplace to prevent scale formation by injecting a chemical inhibitor continuously and/or by periodic squeeze treatments in the production wells, depending on the location and severity of the scale deposition.
The majority of scale inhibitor squeeze studies have considered treatment of unfractured wells, where injection and production is assumed to occur under radial flow conditions, giving a uniformly radial distribution of inhibitor around the well since it is normal to pump these treatments below the fracture pressure. However, it is known that injecting cold fluids into hot reservoirs may result in thermally induced fractures (TIF) as a consequence of stresses changes within the overburden rock, even if injection takes place at below the hydraulic fracture pressure. This paper presents a theoretical study of the impact of fracturing production wells during squeeze treatments.
The first step was to analyse recorded flow rates and bottom hole pressures (BHPs) from a number of treatments or water injection wells reported in the literature to see if there were any indication of fracture propagation during the cold water injection stages. The second step was to model fractured and unfractured treatments using a conventional reservoir simulation package to identify if there would be any advantages or disadvantages to temporarily fracturing a well during a squeeze treatment in terms of inhibitor placement. Three scenarios were compared: non-fractured wells, permanently fractured wells where the fractures are induced during the squeeze treatment and remain open throughout production, and finally temporarily fractured wells where it is assumed that once the thermal stresses have been removed (when hot reservoir fluids flow back into the well) the fractures would heal and the return flow would be radial.