Chemical Placement for scale inhibitor squeeze and other near wellbore chemical treatments is recognized as a significant challenge in today's ever more complex operating environments. For heterogeneous wells and long reach horizontal wells, various factors (including heterogeneity, crossflow and pressure gradients between non-communicating zones within the well) all contribute to uneven placement in the reservoir. Current methods to circumvent these problems often rely on extremely expensive coiled tubing operations, staged diversion (temporary shut-off) treatments or overdosing some zones to gain placement in other (e.g. low permeability) zones. For other very near wellbore treatments e.g. acid stimulation, a number of self-diverting strategies have been applied in field treatments with some success. Unfortunately, the properties which make such treatments applicable for acid stimulation may also make them inappropriate for scale squeeze treatments. Other modified lightly viscosified fluids have however been demonstrated to be of significant importance for improving chemical placement thereby reducing the potential for low permeability/high pressure zones being rapidly denuded of chemical during flowback.
Critical to our understanding of such a process is the ability to accurately simulate the effectiveness of such treatments in the laboratory and to use the data to build and validate more effective modelling tools to allow field treatments to be designed. The paper examines the potential benefits of using modified injection fluids, including lightly viscosified and shear thinning fluids to aid uniform scale inhibitor placement in complex wells. Laboratory data using dual linear core flood experiments coupled with mathematical modelling are used to describe cases where such fluids are shown to offer benefit for field application and also those where more minimal benefit would be anticipated, such that the risks associated with the use of modified fluids (e.g. potential formation damage and fines mobilization) would outlay the benefits. The paper therefore describes the effective use and interpretation of detailed laboratory core flood data, mathematical modelling and field evidence to describe the benefits associated with the application of modified lightly viscosified shear thinning fluids in scale inhibitor squeeze treatments.
Chemical placement for scale inhibitor squeeze and other near wellbore chemical treatments is recognized as a significant challenge in today's ever more complex operating environments, especially if effective chemical placement cannot be achieved through conventional bullhead squeeze treatments.[1–8] For heterogeneous wells and long reach horizontal wells, a combination of factors (such as heterogeneity, crossflow and pressure gradients between non-communicating zones within the well) can contribute to uneven placement of a squeeze treatment in the reservoir. This may result in the majority of the squeeze treatment volume being placed in an inappropriate zone in the near-wellbore, which can result in reduced squeeze lifetimes and inadequate scale protection of vulnerable near-wellbore mixing zones. Heterogeneity in the near-wellbore region will obviously affect the placement of a squeeze treatment under permeability control, with most of the volume of a conventional bullhead squeeze being placed in the higher permeability formation. Pressure gradients or crossflow will also influence the placement of an inhibitor slug, with injection being favoured in the lower pressure zones. The presence of crossflow during shut-in can cause a redistribution of the injected slug, resulting in more placement in a lower pressure zone. Other factors such as wellbore friction, layer pressures, the properties of the fluid in place and differences in mobility ratios between different zones also have an impact on chemical placement but will not be considered in this manuscript.