Assessment of Total Skin Factor in Perforated Wells
- Turhan Yildiz (Colorado School of Mines)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- February 2006
- Document Type
- Journal Paper
- 61 - 76
- 2006. Society of Petroleum Engineers
- 1.8 Formation Damage, 2.4.5 Gravel pack design & evaluation, 5.3.4 Integration of geomechanics in models, 1.6 Drilling Operations, 3.2.5 Produced Sand / Solids Management and Control, 1.11 Drilling Fluids and Materials, 2 Well Completion, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.1.5 Processing Equipment, 5.3.2 Multiphase Flow, 5.8.7 Carbonate Reservoir, 5.1 Reservoir Characterisation, 2.2.2 Perforating, 5.6.4 Drillstem/Well Testing, 3.2.4 Acidising, 3.2.8 Well Performance Modeling and Tubular Optimization, 2.4.3 Sand/Solids Control, 1.14 Casing and Cementing, 2.7.1 Completion Fluids, 4.3.4 Scale, 5.2.1 Phase Behavior and PVT Measurements
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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.
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.
|File Size||2 MB||Number of Pages||15|
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