Formation Damage Evaluation in Naturally Fractured Reservoirs Using a Laboratory-Calibrated Multi-Phase Flow Numerical Simulator

2020 ◽  
Author(s):  
Kelly Díez ◽  
Nicolás Bueno ◽  
Juan Mejía ◽  
Alejandro Restrepo ◽  
Juan Vallejo
Keyword(s):  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Formation Damage ◽  
Phase Flow ◽  
Damage Evaluation ◽  
Naturally Fractured ◽  
Multi Phase Flow ◽  
Multi Phase ◽  
Numerical Simulator

A Similarity Solution for Imbibition Process and its Adaptation in Finite Difference Simulation of Fractured Reservoirs

2021 ◽  
Author(s):  
Song Du ◽  
Seong Lee ◽  
Xian-Huan Wen ◽  
Yalchin Efendiev
Keyword(s):  
Numerical Simulation ◽  
Finite Difference ◽  
Similarity Solution ◽  
Capillary Force ◽  
Fractured Reservoirs ◽  
Phase Flow ◽  
Scale Modeling ◽  
Fracture Models ◽  
Multi Phase Flow ◽  
Multi Phase

Abstract The imbibition process due to capillary force is an important mechanism that controls fluid flow between the two domains, matrix and fracture, in naturally or hydraulically fractured reservoirs. Many simulation studies have been done in the past decades to understand the multi-phase flow in the tight and shale formation. Although significant advances have been made in large-scale modeling for both unconventional and conventional fields, the imbibition processes in the fractured reservoirs remains underestimated in numerical simulation, that limits confidence in long-term field production predictions. In the meanwhile, to simulate the near-fracture imbibition process, traditionally very-fine simulation grids have to be applied so that the physical phenomena of small-length scale could be captured. However, this leads to expensive computation cost to simulate full-field models with a large number of fractures. To improve numerical efficiency in field-scale modeling, we propose a similarity solution for the imbibition process that can be incorporated into the traditional finite difference formulation with coarse grid cells. The semi-analytical similarity solutions are validated by comparing with numerical simulation results with fine-scale grids. The comparison clearly indicates that the proposed algorithm accurately represents the flow behaviors in complex fracture models. Furthermore, we adopt the semi-analytical study to hydraulic fracture models using Embedded Discrete Fracture Model (Lee et al., 2001) in our numerical studies at different scales to represent hydraulic fractures that are interconnected. We demonstrate: 1) the imbibition is critical in determining flow behavior in a capillary force dominant model, 2) conventional EDFM has its limitation in capturing sub-cell flow behaviors near fractures, 3) combining the proposed similarity solution and EDFM, we can accurately represent the multi-phase flow near fractures with coarser grids, and 4) it is straightforward to adapt the similarity solution concept in finite-difference simulations for fractured reservoirs

Upscaling two-phase flow in naturally fractured reservoirs

AAPG Bulletin ◽  
2009 ◽  
Vol 93 (11) ◽  
pp. 1621-1632 ◽  
Author(s):  
Stephan K. Matthäi ◽  
Hamidreza M. Nick
Keyword(s):  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Phase Flow ◽  
Two Phase ◽  
Naturally Fractured

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.

Numerical Simulation of Water-Oil Flow in Naturally Fractured Reservoirs

1976 ◽  
Vol 16 (06) ◽  
pp. 317-326 ◽  
Author(s):  
H. Kazemi ◽  
L.S. Merrill ◽  
K.L. Porterfield ◽  
P.R. Zeman
Keyword(s):  
Finite Difference ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Phase Flow ◽  
Two Phase ◽  
Flow Equations ◽  
Difference Grid ◽  
Naturally Fractured ◽  
Matrix Blocks ◽  
The Matrix

Abstract A three-dimensional, multiple-well, numerical simulator for simulating single- or two-phase flow of water and oil is developed for fractured reservoirs. The simulator equations are two-phase flow extensions of the single-phase flow equations derived by Warren and Root. The simulator accounts for relative fluid mobilities, gravity force, imbibition, and variation in reservoir properties. The simulator handles uniformly and nonuniformly properties. The simulator handles uniformly and nonuniformly distributed fractures and for no fractures at all. The simulator can be used to simulate the water-oil displacement process and in the transient testing of fractured reservoirs. The simulator was used on the conceptual models of two naturally fractured reservoirs: a quadrant of a five-spot reservoir and a live-well dipping reservoir with water drive. These results show the significance of imbibition in recovering oil from the reservoir rock in reservoirs with an interconnected fracture network. Introduction Numerical reservoir simulators are being used extensively to simulate multiphase, multicomponent flow in "single-porosity" petroleum reservoirs. Such simulators generally cannot be used to petroleum reservoirs. Such simulators generally cannot be used to study flow behavior in the naturally fractured reservoirs that are usually classified as double-porosity systems. In the latter, one porosity is associated with the matrix blocks and the other porosity is associated with the matrix blocks and the other represents that of the fractures and vugs. If fractures provide the main path for fluid flow from the reservoir, then usually the oil from the matrix blocks flows into the fracture space, and the fractures carry the oil to the wellbore. When water comes in contact with the oil zone, water may imbibe into the matrix blocks to displace oil. Combinations of large flow rates, low matrix permeability, and weak imbibition may result in water fingering permeability, and weak imbibition may result in water fingering through the fractures into the wellbore. Once fingering of water occurs, the water-oil ratio may increase to a large value. None of the published theoretical work on multiphase flow in naturally fractured systems has been applied directly to the simulation of a reservoir as a whole. Usually, only a segment of the reservoir was simulated, and the results were extrapolated to the entire reservoir. To simulate a reservoir as a whole, we have developed a mathematical formulation of the flow problem that has been programmed as a three-dimensional, compressible, water-oil reservoir simulator. The simulator equations are two-phase flow extensions of the single-phase flow equations derived by Warren and Root. The theory is based on the assumption of double porosity at each point in a manner that the fractures form a continuum filled by the noncontinuous matrix blocks. In other words, the fractures are the boundaries of the matrix blocks. The flow equations are solved by a finite difference method. A typical finite-difference grid cell usually contains one or several matrix blocks. In this case, all the matrix blocks within the finite-difference grid cell have the same pressure and saturation. Gravity segregation within individual matrix blocks is not calculated, but the over-all gravity segregation from one grid cell to another is accounted for. In many practical problems, this approximation is acceptable. In some situations, a matrix block encloses several finite-difference grid cells. In this case, the gravity segregation within the matrix block is calculated. To include heterogeneity, a redefinition of local porosities and permeabilities provides a method for simulating situations where part of the reservoir is fractured and where part is not fractured. The above description points to the complexity of the situations that one encounters. Therefore, the judicious choice of the number of finite difference grid cells with respect to the number of matrix blocks becomes a critical engineering decision. Later sections will provide insight to alleviate such decisions. SPEJ P. 317

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