Improve Well Performance by Reducing Formation Damage

2015 ◽  
Author(s):  
Brian Goldstein ◽  
Kanth Josyula ◽  
Alan VanZeeland ◽  
Moustafa Aboushabana ◽  
Tuan Tran ◽  
...  
Keyword(s):  
Formation Damage ◽  
Well Performance

Improve Well Performance by Reducing Formation Damage

2015 ◽  
Author(s):  
Brian Goldstein ◽  
Kanth Josyula ◽  
Alan VanZeeland ◽  
Moustafa Aboushabana ◽  
Tuan Tran ◽  
...  
Keyword(s):  
Formation Damage ◽  
Well Performance

scholarly journals FORMATION DAMAGE MECHANISMS AND NUMERICAL SIMULATION OF PERMEABILITY IMPAIRMENT IN HORIZONTAL WELLS

2021 ◽  
Vol 15 (2) ◽  
pp. 184-204
Author(s):  
Tunde Adeosun ◽  
Moruffdeen Adabanija ◽  
Folake Akinpelu
Keyword(s):  
Numerical Simulation ◽  
Linear Partial Differential Equation ◽  
Horizontal Wells ◽  
Numerical Approach ◽  
Formation Damage ◽  
Well Performance ◽  
Damage Mechanisms ◽  
Pressure Losses ◽  
Permeability Impairment ◽  
The Impact

Puzzling circumstance associated with formation damage near wellbore occur frequently, resulting in permeability impairments and increased pressure losses. Potential damage phenomenon usually starts from drilling to completion via production and such mechanisms have been fully considered. Most of the existing tasks to mitigate the near oil wellbore damages involve use of empirical models, conducting experiments, frequent shut down of wells for proper well tests and pressure maintenance are highly expensive and time consuming. Permeability impairments have been simulated by modifying Darcy’s equation to optimize reservoir pressure for improved near wellbore in horizontal wells. The model, transient linear partial differential equation (TLPDE) for impaired permeability is developed and numerically resolved using finite difference method. The model was implemented by writing codes in MATLAB language and the solution obtained was validated using synthetic/ field data. The results obtained for TLPDE model indicated pressure depletion over time. This was also shown for every values of coefficient of anisotropy until 400 days when the anisotropy became insignificant approaching isotropy condition, suggesting permeability impairment. Numerical simulation proved to be effective in simulating near oil wellbore damages. This paper describes the detailed mechanisms of formation damage and provided a numerical approach to model impaired permeability in horizontal wells. This approach allowed us to study the impact of various damage mechanisms related to drilling, completion conditions and significant improvement of near oil wellbore for well performance.

Evaluation of Horizontal Well Performance After Drilling-Induced Formation Damage

2005 ◽  
Vol 127 (3) ◽  
pp. 257-263 ◽  
Author(s):  
Y. Ding ◽  
G. Renard
Keyword(s):  
Horizontal Well ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Integrated Approach ◽  
Formation Damage ◽  
Well Performance ◽  
Wellbore Modeling ◽  
Open Hole ◽  
Testing Techniques ◽  
Study Laboratory

It is well recognized that near-wellbore formation damage can dramatically reduce well productivities, especially for open hole completed horizontal wells. The economic impact of poor productivity of these wells has pushed toward significant efforts in recent years to study laboratory testing techniques and numerical modeling methods for predicting and controlling drilling-induced formation damage. This paper presents an integrated approach, combining a near-wellbore modeling with laboratory experiments for data acquisition as input for the model, to evaluate the performance of oil and gas wells after drilling-induced formation damage.

Combined Effect of Non-Darcy Flow and Formation Damage on Gas Well Performance of Dual-Porosity and Dual-Permeability Reservoirs

2006 ◽  
Vol 9 (05) ◽  
pp. 543-552 ◽  
Author(s):  
Carlos A. Pereira ◽  
Hossein Kazemi ◽  
Erdal Ozkan
Keyword(s):  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Combined Effect ◽  
Flow Coefficient ◽  
Darcy Flow ◽  
Dual Porosity ◽  
Formation Damage ◽  
Well Performance ◽  
Skin Damage ◽  
Naturally Fractured

Summary This paper addresses the combined effect of formation damage and non-Darcy flow in naturally fractured reservoirs using simplified analytical solutions and a 2D numerical simulator. Pressure drawdown, buildup, and isochronal tests simulated in this work indicate that, despite high fracture permeability, skin damage may accentuate the non-Darcy flow effect and drastically influence pressure-transient characteristics of low-pressure, naturally fractured reservoirs. In high-pressure reservoirs, this effect is significant only at high rates. Non-Darcy flow does not usually mask the typical pressure-transient characteristics of dual-porosity and dual-permeability reservoirs, but the conventional interpretation of the early-time data may lead to erroneous results. If the exponent, n, of the isochronal tests approaches 0.5 while the matrix permeability is low and flow rate is rather high, this would indicate the predominance of fracture flow. Under these conditions, small contributions from skin damage may greatly reduce gas-well performance in naturally fractured reservoirs. Introduction High velocity flow through porous media and fractures causes a higher pressure drop than predicted by the Darcy equation. This phenomenon, generally referred to as non-Darcy flow, was first described by Forchheimer (1901). Since then, it has been well established that the main variables that affect non-Darcy flow are the velocity, density, and saturation of the fluid and the permeability and porosity of the reservoir. Reservoir properties may be correlated to a single parameter, known as the non-Darcy flow coefficient, beta. Very little is known about the effect of other parameters, such as physical skin damage, on non-Darcy flow and their consequences in well performance. In fact, a recent literature review on non-Darcy flow by Li and Engler (2001a) indicates that most of the work has been focused on finding an accurate correlation for the non-Darcy flow coefficient, beta. There is also the issue of non-Darcy flow in dual-porosity and dual-permeability reservoirs, where high local velocities are prominent in the fractures. This paper pertains specifically to this issue. In general, the lower the formation permeability, the greater the non-Darcy pressure gradient. Formation damage in the near-wellbore region causes a drastic reduction in formation permeability, which potentially could be even more prominent in naturally fractured reservoirs. Thus, a greater non-Darcy flow effect could result in the wellbore region of a dual-porosity reservoir. The literature explaining the combined effect of physical damage and non-Darcy flow in single-porosity reservoirs is abundant (Berumen-C. et al. 1989; Camacho-V. et al. 1993; Fligelman et al. 1981); however, there is little information about such effects in dual-porosity and dual-permeability reservoirs. A finite-difference, 2D simulator in cylindrical coordinates was constructed to simulate pressure-drawdown and -buildup tests. By analyzing the simulated pressure drawdown and buildup tests, it was possible to decipher the combined effect of the skin damage and non-Darcy flow in fractured reservoirs. Both dual-porosity and dual-permeability idealizations of fractured reservoirs were considered.

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