Black-Oil Simulations for Three-Component, Three-Phase Flow in Fractured Porous Media

Geiger, Sebastian; Matthäi, Stephan; Niessner, Jennifer; Helmig, Rainer

doi:10.2118/107485-pa

Cited by 128 publications

(18 citation statements)

References 55 publications

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“…5 in which the fractures are treated as d -1 elements (i.e., 1D line elements in 2D geometries and 2D surface elements in 3D geometries) (Geiger et al 2004(Geiger et al , 2009. For simplicity, we assume that the capillary entry pressure in fracture and matrix is identical in the direct numerical simulations, which allows us to overcome timestepping limitations for the case of discontinuous capillary pressures between the mobile and immobile domains (Reichenberger et al 2006;Hoteit and Firoozabadi 2008) and thus to deal with more-complex and more geologically realistic fracture geometries.…”

Section: Mathematical Model and Numerical Solutionmentioning

confidence: 99%

A Novel Multirate Dual-Porosity Model for Improved Simulation of Fractured and Multiporosity Reservoirs

Geiger¹,

Dentz

Neuweiler

2013

SPE Journal

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A major part of the world's remaining oil reserves is in fractured carbonate reservoirs, which are dual-porosity (fracture-matrix) or multiporosity (fracture/vug/matrix) in nature. Fractured reservoirs suffer from poor recovery, high water cut, and generally low performance. They are modeled commonly by use of a dual-porosity approach, which assumes that the high-permeability fractures are mobile and low-permeability matrix is immobile. A single transfer function models the rate at which hydrocarbons migrate from the matrix into the fractures. As shown in many numerical, laboratory, and field experiments, a wide range of transfer rates occurs between the immobile matrix and mobile fractures. These arise, for example, from the different sizes of matrix blocks (yielding a distribution of shape factors), different porosity types, or the inhomogeneous distribution of saturations in the matrix blocks. Thus, accurate models are needed that capture all the transfer rates between immobile matrix and mobile fracture domains, particularly to predict late-time recovery more reliably when the water cut is already high. In this work, we propose a novel multi-rate mass-transfer (MRMT) model for two-phase flow, which accounts for viscous-dominated flow in the fracture domain and capillary flow in the matrix domain. It extends the classical (i.e., singlerate) dual-porosity model to allow us to simulate the wide range of transfer rates occurring in naturally fractured multiporosity rocks. We demonstrate, by use of numerical simulations of waterflooding in naturally fractured rock masses at the gridblock scale, that our MRMT model matches the observed recovery curves more accurately compared with the classical dual-porosity model. We further discuss how our multi-rate dual-porosity model can be parameterized in a predictive manner and how the model could be used to complement traditional commercial reservoir-simulation workflows.

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Section: Mathematical Model and Numerical Solutionmentioning

confidence: 99%

A Novel Multirate Dual-Porosity Model for Improved Simulation of Fractured and Multiporosity Reservoirs

Geiger¹,

Dentz

Neuweiler

2013

SPE Journal

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“…Simulations with explicitly discretized fractures with very-fine gridblocks as fracture width with a single-porosity approach can give us a very-accurate flow modeling into and from fractures, especially for two-phase flow problems. Advanced numerical methods are also studied in the literature to improve discrete fracture modeling for multiphase/ multicomponent flows (e.g., Geiger et al 2009;Schmid et al 2013;Zidane and Firoozabadi 2014). However, an explicitly discrete fracture model (DFM) involves a large number of cells which are not suitable for reservoir-scale simulations because of the computational intensity.…”

Section: Hybrid Approach Based On the Minc Conceptmentioning

confidence: 99%

“…Fracturing-fluid-induced formation damage has been studied in the literature for a long time (e.g., Holditch 1979;Friedel 2004;Gdanski et al 2006;Wang et al 2009;Ding et al 2013). Recently, the fracturing-fluid-induced formation damage is particularly discussed for extremely low-permeability shale gas reservoirs.…”

Section: Introductionmentioning

confidence: 99%

Simulation of the Impact of Fracturing Fluid Induced Formation Damage in Shale Gas Reservoirs

Farah

Ding

2015

SPE Reservoir Simulation Symposium

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The unconventional gas resources from tight and shale gas reservoirs have received great attention in the past decade and have become the focus of petroleum industry. Shale gas reservoirs have specific characteristics, such as tight reservoir rock with nanodarcy permeability. Multistage hydraulic fracturing is required for such low-permeability reservoirs to create very complex fracture networks and therefore to connect effectively a huge reservoir volume to the wellbore. During hydraulic fracturing, an enormous amount of water is injected into the formation, where only 25-60% is reproduced during flowback and a long production period. A major concern with hydraulic fracturing is the waterblocking effect in tight formations caused by the high capillary pressure and the presence of water-sensitive clays. High water saturation in the invaded zone near the fracture face may reduce gas relative permeability greatly and may impede gas production. In this paper, we consider the numerical techniques to simulate during hydraulic fracturing the water invasion or formation damage and its impact on the gas production in shale gas reservoirs. Two-phase-flow simulations are considered in a large stimulated reservoir volume (SRV) containing extremely low-permeability tight matrix and multiscale fracture networks including primary hydraulic fractures, induced secondary fractures, and natural fractures. To simulate the water-blocking phenomenon, it is usually required to explicitly discretize the fracture network and use very fine meshes around the fractures. On the one hand, the commonly used single-porosity model is not suitable for this kind of problem, because a large number of gridblocks is required to simulate the fracture network and fracture-matrix interaction. On the other hand, a dual-porosity (DP) model may also be not applicable, because of the long transient duration with large block sizes of ultralow-permeability matrix. In this paper, we study the applicability of the MINC (multiple interacting continuum) method, and use a hybrid approach between matrix and fractures to correctly simulate the fracturing-fluid invasion and its backflow during hydraulic fracturing. This approach allows us to quantify the fracturing water invasion and its formation-damage effect in the whole SRV.

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“…ADM extends the applicability of the multiscale methods to fully-implicit (stable) simulations, allows for crossing the scales for all unknowns with a multilevel dynamic mesh, does not require reconstruction of conservative flux field, employs the basis functions which are computed only at the beginning of the simulation, and does not rely on any smoothing iterative procedure. The development of such a dynamic multilevel scheme for fractured media has not yet been addressed, despite their high importance in the geo-scientific community and extensive literature for fine-scale consistent discrete representations [22][23][24][25][26][27][28][29][30][31][32]. Such a dynamic multilevel approach allows for capturing explicit fractures at their relevant resolution while maintaining the scalability of the simulation for real-field applications.…”

Section: Introductionmentioning

confidence: 99%

Algebraic dynamic multilevel method for embedded discrete fracture model (F-ADM)

HosseiniMehr

Cusini

Vuik

et al. 2018

Journal of Computational Physics

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Black-Oil Simulations for Three-Component, Three-Phase Flow in Fractured Porous Media

Cited by 128 publications

References 55 publications

A Novel Multirate Dual-Porosity Model for Improved Simulation of Fractured and Multiporosity Reservoirs

A Novel Multirate Dual-Porosity Model for Improved Simulation of Fractured and Multiporosity Reservoirs

Simulation of the Impact of Fracturing Fluid Induced Formation Damage in Shale Gas Reservoirs

Algebraic dynamic multilevel method for embedded discrete fracture model (F-ADM)

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