In this study, we present methods to predict the total skin factor for perforated and damaged wells correctly. The non-linear interaction between individual skin components is accurately represented in the methods. We show that the total skin factor models based on the simple addition of individual skin factors due to formation damage, perforation, inclination, partial penetration etc... do not work.


The long-term productivity of oil and gas wells is influenced by many factors. Among these factors are petrophysical properties, fluid properties, degree of formation damage and/or stimulation, well geometry, well completions, number of fluid phases, and flow-velocity type (Darcy, non-Darcy). To isolate and identify the effect of any single parameter on the well performance, a sensitivity study on the parameter of interest is conducted and the results are compared to a reference base case of an ideal vertical openhole. In the base case, the ideal vertical openhole produces single-phase fluid, the fluid flow obeys Darcy's law, and formation is neither stimulated nor damaged. The influence of the individual parameters not considered in the base case is quantified in terms of skin factor.

Oil and gas wells may have permeability reduction around the wellbore due to invasion of the formation by drilling mud, cement solids, and completion fluids. This is generally referred to as formation damage. Formation damage around the wellbore causes additional pressure drop. On the other hand, stimulation operations such as acidizing may decrease the pressure drop in the near wellbore region by improving the formation permeability around the wellbore. The impact of permeability impairment/improvement around the wellbore owing to the drilling, production, and acidizing operations is quantified in terms of mechanical skin factor due to damage/stimulation.

The fluid flow in the near wellbore region is also influenced by the well completion type. Barefoot openhole completion is usually the most cost-effective method. Openhole completion yields a local flow pattern that is nearly radial around the wellbore and normal to the well trajectory. However, in some cases, the openhole completion may not be desirable. Different types of well completion may be needed to control/isolate the fluid entry into the wellbore, to avoid gas/water coning, and to minimize sand production. Besides the openhole completion, the wells may be partially or selectively completed with perforations, slotted liners, gravel packs, screens, and zonal isolation devices. Also, the wells with low productivity may need to be hydraulically fractured to accelerate the hydrocarbon recovery. In the completed wells, the flow pattern around the wellbore is distorted. The completions result in additional fluid convergence and divergence in the near wellbore region. For example, partial penetration creates a two-dimensional flow field in the formation. On the other hand, a perforated well experiences three-dimensional flow converging around perforation tunnels. Compared to an ideal openhole, the wells with completions are subject to additional pressure loss/gain in the near wellbore region. The additional pressure change due to well completion is quantified in terms of completion pseudoskin factor.

The well performance is naturally influenced by the geometry of the well itself. Based on their geometrical shape, the wells can be classified as vertical, inclined, horizontal, undulating, and multibranched. In the literature, the reference well geometry has been that of a fully penetrating vertical openhole. Historically, the differences in the productivity of vertical openhole and other well geometries have been formulated in terms of pseudoskin factor as well. However, when it comes to the assessment of completion effects on well productivity, rather than comparing the given completed non-vertical well to an ideal vertical openhole, it may be more appropriate to work with the considered well geometry only and compare the completed and openhole cases of the same well geometry. For this reason, the term geometrical pseudoskin factor is proposed to quantify the differences between the productivities of vertical wells and other well geometries.

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