Summary
In this study, the available methods and software to predict the well
productivity and total skin factor in fully perforated vertical wells have been
reviewed. The methods have been compared against the experimental data obtained
on an electrolytic apparatus, and their accuracy has been investigated. It has
been observed that the 3D semianalytical model, SPAN 6.0 software, and the
simple hybrid model described in this paper replicate the experimental results
very well. On the other hand, the results estimated from the McLeod method and
the Karakas-Tariq method substantially deviate from the experimental data;
hence, these models/methods should be used with caution.
The literature hosts many equations to predict the total skin factor in
partially perforated vertical wells. Some of the available models have been
tested against the results from the 3D semianalytical model. It has been shown
that total skin-factor equations based on the summation of individual
components do not work.
The 3D semianalytical model has been modified to build an approximate model
for fully and partially perforated inclined wells in isotropic formations.
Additionally, a simple hybrid model to compute total skin factor in perforated
inclined wells has been presented. The hybrid model for perforated inclined
wells agrees well with the approximate 3D model. Some of the available models
to calculate total skin factor in perforated inclined wells have been compared
to the approximate 3D model, and their accuracy has been discussed.
Finally, a simple model to predict total skin factors in perforated
horizontal wells has been developed. The application using the simple model has
demonstrated that a combination of long wellbore length and perforations
bypassing the damaged zone could overcome the destructive effect of severe
formation damage around the wellbore.
Introduction
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. 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 open hole. In the base case, the ideal
vertical open hole produces single-phase fluid, the fluid flow obeys Darcy’s
law, and the 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 caused
by invasion 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 caused by drilling,
production, and acidizing operations is quantified in terms of mechanical skin
factor.
The fluid flow in the near-wellbore region is also influenced by
well-completion type. Openhole completion yields a local flow pattern that is
radial around the wellbore and normal to the well trajectory. However, in some
cases, openhole completion may not be desirable. Different types of well
completion may be needed to control/isolate fluid entry into the wellbore, to
avoid gas/water coning, and to minimize sand production. Besides the openhole
completion, wells may be partially or selectively completed with perforations,
slotted liners, gravel packs, screens, and zonal-isolation devices. Also, wells
with low productivity may need to be hydraulically fractured. In completed
wells, the flow pattern around the wellbore is distorted. Completions result in
additional fluid convergence and divergence in the near-wellbore region. For
example, partial penetration creates a 2D flow field in the formation. On the
other hand, a perforated well experiences 3D flow converging around perforation
tunnels. Compared to an ideal open hole, the wells with completions are subject
to additional pressure gain/loss in the near-wellbore region. The additional
pressure change caused by well completion is quantified in terms of completion
pseudoskin factor.
Well performance is naturally influenced by the geometry of the well itself.
Based on their geometrical shape, wells may be classified as vertical,
inclined, horizontal, undulating, and multibranched. In the literature, the
reference well geometry has been that of a fully penetrating vertical open
hole. Historically, the differences in the productivity of vertical openhole
and other well geometries have also been formulated in terms of pseudoskin
factor. However, when it comes to the assessment of completion effects on well
productivity, rather than comparing the given completed nonvertical well to an
ideal vertical open hole, 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.
Multiphase flow in the formation may evolve because of gas/water coning
around the wellbore, gas evaporation from the liquid-hydrocarbon phase, and
liquid dropout from gas condensate. Compared to single-phase fluid flow,
multiphase flow in the formation creates an additional pressure drop because of
the relative permeability effect. If multiphase flow is intensified in the
near-wellbore region, only then may the impact of multiphase flow be formulated
in terms of multiphase pseudoskin factor.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
1 June 2004
- Meeting paper published:
13 May 2003
- Revised manuscript received:
21 November 2005
- Manuscript approved:
2 December 2005
- Version of record:
20 February 2006
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