Flow modelling of unconventional shale reservoirs using a DFM-MINC proximity function

Farah, N.; Delorme, Matthieu; Ding, Didier Yu; Wu, Yu‐Shu; Codreanu, D. Bossie

doi:10.1016/j.petrol.2018.10.014

Cited by 21 publications

(14 citation statements)

References 30 publications

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“…This can imply some numerical errors in the EDFM method because of the singular behavior in √ t of pressure close to a fracture is badly captured. In these cases, the MINC (Multiple Interacting Continua) methods for capturing short time behavior can be applied [43,44].…”

Section: Edfm Methodsmentioning

confidence: 99%

Fracture Detection and Numerical Modeling for Fractured Reservoirs

Zuo

Tan

et al. 2019

Energies

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The subsurface fractures could impact the fluid mechanisms dramatically, which makes the modeling of the hydraulic and natural fractures an essential step for fractured reservoirs simulations. However, because of the complexities of fracture patterns and distributions, it is difficult to detect and quantify the fracture networks. In this study, line detection techniques are designed and applied to quantify the fracture segments from fracture figures. Using this fracture detection algorithm, the fracture segments could be located by detecting the endpoints and the intersections of fractures, thus that the fracture patterns could be accurately captured and characterized. The proposed method is applied to two previous well-known field cases and the pressure distribution results are consistent with the micro-seismic data profiles. These two field cases are simulated and computed by using a semianalytical model and Embedded Discrete Fracture Model (EDFM) respectively. The third case is constructed by the fracture outcrop figure and simulated by a numerical simulator with EDFM implemented. The simulation results are accurate and clearly illustrate the important role fractures play in unconventional reservoirs. The technology proposed in this study could be used to quantify the fracture input data for reservoir simulations and be easily expanded for fracture detection and characterization problems in other fields.

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Section: Edfm Methodsmentioning

confidence: 99%

Fracture Detection and Numerical Modeling for Fractured Reservoirs

Zuo

Tan

et al. 2019

Energies

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“…Due to the large grid blocks used by dual-continuum models, such phenomena cannot be simulated. However, this problem could be accurately solved using the MINC method (see Delorme et al, 2016;Farah et al, 2018;Ricois et al, 2016). Recently, Farah and Delorme (2020) proposed a Unified Fracture Network Model (UFNM) for unconventional reservoirs modeling.…”

Section: Introductionmentioning

confidence: 99%

“…In such cases, the MINC-PF miscalculates the flow. Farah et al (2018) proposed a DFM based on a MINC Proximity Function for unconventional reservoirs to simulate fluid flow in irregular fracture network. However, the presence of different sub-volumes/blocks was not considered.…”

Section: Introductionmentioning

confidence: 99%

The MINC proximity function for fractured reservoirs flow modeling with non-uniform block distribution

Farah

Ghadboun

2021

Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles

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Reservoir simulation is a powerful technique to predict the amount of produced hydrocarbon. After a solid representation of the natural fracture geometry, an accurate simulation model and a physical reservoir model that account for different flow regimes should be developed. Many models based on dual-continuum approaches presented in the literature rely on the Pseudo-Steady-State (PSS) assumption to model the inter-porosity flow. Due to the low permeability in such reservoirs, the transient period could reach several years. Thus, the PSS assumption becomes unjustified. The numerical solution adopted by the Multiple INteracting Continua (MINC) method was able to simulate the transient effects previously overlooked by dual-continuum approaches. However, its accuracy drops with increasing fracture network complexity. A special treatment of the MINC method, i.e., the MINC Proximity Function (MINC–PF) was introduced to address the latter problem. And yet, the MINC–PF suffers a limitation that arises from the existence of several grid-blocks within a studied cell. In this work, this limitation is discussed and two possible solutions (transmissibility recalculation/adjusting the Proximity Function by accounting for nearby fractures) are put forward. Both proposed methods have demonstrated their applicability and effectiveness once compared to a reference solution.

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“…In addition, a number of methods are introduced to improve transmissibility calculations among several media of an EDFM by taking into account the pressure distribution using an integral method. In Farah et al (2019) paper, a novel doable hybrid method based upon a MINC proximity function is put forth to predict flow behavior in fractured reservoirs of low permeability type. The proposed method has the advantages of both discrete fracture model and multi-continuum for the purpose of simulating unconventional fractured reservoirs.…”

Section: Introductionmentioning

confidence: 99%

Modeling of transient shape factor in fractured reservoirs considering the effect of heterogeneity, pressure-dependent properties and quadratic pressure gradient

Abbasi¹,

Kazemi²,

Sharifi³

2019

Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles

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Fractured reservoirs contain most of the oil in the world’s reserves. The existence of two systems of matrix and fracture with completely different characteristics has caused the modeling of the mechanisms of fractured reservoirs to be more complex than conventional ones. Modeling of this type of reservoirs is possible using two methods of single and dual porosity model. Modeling via single porosity scheme is very time-consuming as it takes into account huge matrix blocks (low permeability and high porosity) and small fractures (high permeability and low porosity) alongside each other explicitly. The dual porosity model, however, attempts to solve this problem using the concept of shape factor, which is defined as the amount of fluid transferred from the matrix to the fracture. The shape factor coefficients expressed so far have been derived via simplifying assumptions which keep them away from real conditions prevailing in fractured reservoirs. In this paper, shape factor is calculated more realistically with consideration of the quadratic pressure gradient in the diffusivity equation, the heterogeneity of the matrix block and the change of the rock properties by pressure change. For these three cases, the analytical modeling of the flow of fluid from the matrix to the fracture system has been discussed and its results with previous models have been compared. In addition, the dependence of shape factor on the stated parameters was evaluated and in order to validate the results of the proposed analytical model, its results were compared with the results of a commercial simulator. Investigating the shape factor with the assumptions about the physics of the fractured reservoirs will improve our understanding of the fluid transfer between the matrix and the fracture, and this capability will allow numerical and commercial simulators to predict the behavior of fractured reservoirs more accurately.

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Flow modelling of unconventional shale reservoirs using a DFM-MINC proximity function

Cited by 21 publications

References 30 publications

Fracture Detection and Numerical Modeling for Fractured Reservoirs

Fracture Detection and Numerical Modeling for Fractured Reservoirs

The MINC proximity function for fractured reservoirs flow modeling with non-uniform block distribution

Modeling of transient shape factor in fractured reservoirs considering the effect of heterogeneity, pressure-dependent properties and quadratic pressure gradient

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