Fast and Efficient Modeling and Conditioning of Naturally Fractured Reservoir Models Using Static and Dynamic Data

García, Michel; Gouth, Francois Michel; Gosselin, Olivier

doi:10.2118/107525-ms

Cited by 23 publications

(6 citation statements)

References 30 publications

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“…The classical way to model production from NFRs is the dual-porosity model (Warren and Root 1963) with its extension to multiphase flow (Kazemi et al 1976;Kazemi 1983, 1988;Quandalle and Sabathier 1989), which separates the reservoir into a flowing domain (the network of connected and permeable fractures) and a stagnant domain (the low-permeability rock matrix), with the latter providing the storage. The equivalent fracture permeability is usually computed from stochastically generated discrete fracture networks (DFNs), whereas the permeability of the rock matrix comes from plug measurements (Dershowitz et al 2000;Bourbiaux et al 2002;Garcia et al 2007). The exchange of oil, gas, and water between the two domains is modeled by transfer func-tions (describing the physics of fluid exchange between fracture and matrix) and a shape factor (describing the geometry of the rock matrix).…”

Section: Introductionmentioning

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: Introductionmentioning

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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“…An alternative method to DFN modeling is proposed by Garcia et al (2007), who consider 3D DFNs as a heavy solution. DFNs require a detailed understanding of fracture network characteristics, which may not always be available in the subsurface.…”

Section: Rationalementioning

confidence: 99%

“…DFNs require a detailed understanding of fracture network characteristics, which may not always be available in the subsurface. Instead, these authors propose a method based on conceptual fracture models and a notion of scale-dependent effective properties (Garcia et al, 2007). However, the issue of fracture-network characterization also remains in this case.…”

Section: Rationalementioning

confidence: 99%

Calibrating discrete fracture-network models with a carbonate three-dimensional outcrop fracture network: Implications for naturally fractured reservoir modeling

Bisdom¹,

Gauthier²,

Bertotti³

et al. 2014

Bulletin

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A B S T R A C TModeling naturally fractured reservoirs requires a detailed understanding of the three-dimensional (3D) fracture-network characteristics, whereas generally only one-dimensional (1D) data, often suffering from sampling artifacts, are available as inputs for modeling. Additional fracture properties can be derived from outcrop analogs with the scanline method, but it does not capture their full two-dimensional (2D) characteristics. We propose an improved workflow based on a 2D field-digitizing tool for mapping and analyzing fracture parameters as well as relations to bedding. From fracture data collected along 11 vertical surface outcrops in a quarry in southeast France, we quantify uncertainties in modeling fracture networks. The fracture-frequency distribution fits a Gaussian distribution that we use to evaluate the intrinsic fracture density variability within the quarry at different observation scales along well-analog scanlines. Excluding well length as a parameter, we find that 30 wells should be needed to fully (i.e., steady variance) capture the natural variability in fracture spacing. This illustrates the challenge in trying to predict fracture spacing in the subsurface from limited well data. Furthermore, for models with varying scanline orientations we find that Terzaghi-based spacing corrections fail when the required correction angle is more than 60°. We apply the 1D well Kevin Bisdom holds a M.Sc. degree in petroleum engineering and geosciences from the Delft University of Technology, Netherlands. He is currently a Ph.D. candidate in the section of applied geology at the Delft University of Technology working on geomechanical and fluid flow modeling of fracture networks in folded subsurface structures using outcrop analogs in central Tunisia. is a senior geologist and geophysicist at Total. He is currently head of the naturally fractured reservoir (NFR) study team and scientific adviser for NFR operational and research and development projects. Bertrand holds a Ph.D. in structural geology from the Pierre and Marie Curie University of Paris and has 25 years of experience in the oil and gas industry with Shell and Total. received his master's degree at the University of Pisa (Italy) and the Ph.D. at the ETH-Zurich with a thesis on the tectonosedimentary evolution of the South-Alpine rifted margin. He was then at the VU Amsterdam studying passive margins and foredeep basins. Since 2010, he has been a professor for applied geology at the Delft University of Technology working mainly on fractured reservoirs.

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“…Instead, the conventional methodology to model these natural fracture networks in a reservoir scale has been to upscale to dual porosity dual permeability (DPDK) frameworks [17][18][19][20][21] through the Oda or tensor method. Although the Oda method is efficient in terms of processing speed, it lacks precision as it assumes long and highly connected fractures [21][22][23][24][25][26]. Likewise, the tensor method is too slow to be applicable to full-field scale characterization [21].…”

Section: Introductionmentioning

confidence: 99%

Water Intrusion Characterization in Naturally Fractured Gas Reservoir Based on Spatial DFN Connectivity Analysis

Chen

Torres

Xing

et al. 2020

Preprint

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In this study, the non-intrusive embedded discrete fracture model (EDFM) in combination with the Oda method are employed to characterize natural fracture networks fast and accurately, by identifying the dominant water flow paths through spatial connectivity analysis. The purpose of this study is to present a successful field case application in which a novel workflow integrates field data, discrete fracture network (DFN), and production analysis with spatial fracture connectivity analysis to characterize dominant flow paths for water intrusion in a field-scale numerical simulation. Initially, the water intrusion of single-well sector models was history matched. Then, resulting parameters of the single-well models were incorporated into the full field model, and the pressure and water breakthrough of all the producing wells were matched. Finally, forecast results were evaluated. Consequently, one of the findings is that wellbore connectivity to the fracture network has a considerable effect on characterizing the water intrusion in fractured gas reservoirs. Additionally, dominant water flow paths within the fracture network, easily modeled by EDFM as effective fracture zones, aid in understanding and predicting the water intrusion phenomena. Therefore, fracture clustering as shortest paths from the water contacts to the wellbore endorses the results of the numerical simulation. Finally, matching the breakthrough time depends on merging responses from multiple dominant water flow paths within the distributions of the fracture network. The conclusions of this investigation are crucial to field modeling and the decision-making process of well operation by anticipating water intrusion behavior through probable flow paths within the fracture networks.

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Fast and Efficient Modeling and Conditioning of Naturally Fractured Reservoir Models Using Static and Dynamic Data

Cited by 23 publications

References 30 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

Calibrating discrete fracture-network models with a carbonate three-dimensional outcrop fracture network: Implications for naturally fractured reservoir modeling

Water Intrusion Characterization in Naturally Fractured Gas Reservoir Based on Spatial DFN Connectivity Analysis

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