Matrix treatments of openhole horizontal wells are extremely difficult. Placement of the treatment fluids at the very places where necessary, i.e. where damage exists, calls for diversion techniques of superior performance, due to the length of the section to be treated. Failure in achieving high diverting efficiency results in either incomplete damage removal and/or requirements for uneconomical volumes of treatment fluids.

Suspensions of particulate diverting agents build up very efficient cakes, however are costly due to the huge depositing surface. Therefore, the preferred diverting technique consists in pumping viscous banks into sections of high fluid intake. These banks are made of either non-Newtonian gels or foams having downhole qualities in the 60 to 85% range.

The aim of the present paper is to provide modeling equations for the radial placement of viscous pills around openhole horizontal wells. Primary porosity reservoir rocks are considered (usually 50- to 5,000-mD permeability sandstones) as well as naturally fractured ones (mostly carbonates). The pills are made of gels of Power-law fluid mechanics behavior. The increasing apparent viscosity of the gel with increasing distance to the well (due to decreasing shear rate) is taken into account.

Fluid bank pseudoskin equations are derived and used to optimize the diverting process. Optimization is either achieved by the selection of the proper characteristics of the viscous pill (e.g. n' and K' coefficients of a Power-law fluid) or by the pill volume and injection rate at which the latter is squeezed into the reservoir rock. Quantitative guidelines are provided with the aim of minimizing the cost of the diverting process as well as the duration of the matrix treatment.


Vertical wells intercept relatively thin producing layers and are therefore economically cased, cemented and perforated. When diversion of matrix acidizing treatments is required in such completions, particulate diverting agents can be used. They deposit efficient cakes onto perforations walls. Although the usual recommendation is to design at least one diverter stage for every twenty feet of perforated interval, diversion using this type of additive remains economical. Each diverter stage usually requires half a barrel of a 3-% dispersion of the particulate material into a convenient carrier fluid (in the case of a conventional 4-SPF completion type).

Vertical openholes are already much more expensive to treat: an 8.5-inch diameter hole calls for diverter stages seven times larger than a perforated well. Horizontal wells, which are so long that cementing and perforating options are discarded due to their cost, need so many diverter stages that the treatment would be prohibitive when using a particulate material. As a rough estimate, the diverting agent on its own would cost about 5,000 $ for every 100 ft of openhole section.

To alleviate this economical problem, various solutions have been proposed. In a first step, wells where cementing is mandatory (e.g. for further zone isolation) are perforated over a small fraction of their total horizontal section.1 Indeed, in primary porosity, thin isotropic layers, it has been shown that partial perforation, when properly designed, does not significantly impair the productivity of a horizontal well.2,3 In secondary porosity rocks, where most of the production comes from natural fissures, perforation is even limited to very short clusters across the zones of mud losses.4 In some instances the total number of perforations is small enough for ball sealers to be used as the diverting technique.5

This content is only available via PDF.
You can access this article if you purchase or spend a download.