Downhole scaling has long been recognized as causing significant damage to the near wellbore area of production wells. Furthermore complex heterogeneous wells, represent a significant challenge to ensuring effective placement and thereby protection along the entire length of the wells, as the injected chemicals (inhibitor or dissolver) naturally enter the higher permeability / lower pressure zones which may leave other zones untreated. Recent publications and field trials have demonstrated the benefits of using modified, lightly viscosified shear-thinning fluids to give more even placement of chemicals in such wells via bullheading. However, when large volumes of polymer gel are used the in situ fluid properties (viscosity) become critical as the fluid penetrates further into the formation. The in situ viscosity affects both the ability to place treatment chemicals into low permeability / high pressure zones and the post-job well clean up. Accurate prediction of the flow behaviour of these gels in porous media depends on the characterization of the physical properties of the reservoir zones, in particular the permeability, effective porosity and most importantly with shear thinning fluids – the formation shape factor. In this paper we present work investigating the suitability of such shear thinning fluids for non-damaging chemical interventions for an HPHT field. The paper will describe thermal stability tests and novel techniques developed to characterize non-Newtonian fluid behaviour under flow conditions between 120°C and 170°C. Results from bulk, coil and core tests will be included. The paper will also describe test protocols developed to investigate the parameters which could influence the formation shape factor. The work clearly demonstrates the significant impact that the shape factor has on diverting fluid into the low injectivity zones. The results will help achieve more even chemical placement and therefore improved scale protection/removal in the wellbore following treatments in complex wells.

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