Modeling flow in naturally fractured reservoirs: effect of fracture aperture distribution on dominant sub-network for flow

Gong, Jiakun; Rossen, W.R.

doi:10.1007/s12182-016-0132-3

Cited by 51 publications

(29 citation statements)

References 54 publications

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“…3 shows the results for R d = 2.5 and R n = 1/3. This value of R d and R n approximates the results of our DFN study [15], i.e. that just 1/3 of the fractures account for 90% of the permeability of the fracture network.…”

Section: Primary Recoverysupporting

confidence: 87%

“…Then, the total flow capacity of two (half-) primary fractures on opposite sides of the matrix is equal to that of one primary fracture. R n = 1/3 approximately corresponds to our previous DFN study [15]. For a more complex reservoir, it might be better to correlate results to the cumulative lengths of primary and secondary fractures, as we did in our previous studies [15,16], rather than number of fractures.…”

Section: Methodssupporting

confidence: 72%

“…R n = 1/3 approximately corresponds to our previous DFN study [15]. For a more complex reservoir, it might be better to correlate results to the cumulative lengths of primary and secondary fractures, as we did in our previous studies [15,16], rather than number of fractures. In this simplified representation, the fractures all have the same length, and R n is also the ratio of cumulative fracture lengths.…”

Section: Methodssupporting

confidence: 72%

“…As we presented in a previous study [15], even in a well-connected fracture network, there is a dominant sub-network which carries almost all the flow, but it is much sparser than the original network. In this study we refer to the fractures in the dominant sub-network as "primary" fractures, and the remaining fractures as "secondary" fractures.…”

Section: Introductionmentioning

confidence: 75%

“…In this study we refer to the fractures in the dominant sub-network as "primary" fractures, and the remaining fractures as "secondary" fractures. The primary fractures tend to be wider, but they are not necessarily the widest, longest or most highly connected fractures in the network [15]. The flow-path length of the dominant sub-network can be as little as 30% of that of the corresponding original fracture network.…”

Section: Introductionmentioning

confidence: 99%

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Characteristic Fracture Spacing in Primary and Secondary Recovery for Naturally Fractured Reservoirs

Gong

Rossen

2017

Proceedings

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. Characteristic fracture spacing in primary and secondary recovery for naturally fractured reservoirs. Fuel: the science and technology of fuel and energy, 223, 470-485. https://doi.org/10.1016/j.fuel.2018.02.046 Important noteTo cite this publication, please use the final published version (if applicable). Please check the document version above. CopyrightOther than for strictly personal use, it is not permitted to download, forward or distribute the text or part of it, without the consent of the author(s) and/or copyright holder(s), unless the work is under an open content license such as Creative Commons. Takedown policyPlease contact us and provide details if you believe this document breaches copyrights. We will remove access to the work immediately and investigate your claim. A B S T R A C TIf the aperture distribution is broad enough in a naturally fractured reservoir, even one where the fracture network is highly inter-connected, most fractures can be eliminated without significantly affecting the flow through the fracture network. During a waterflood or enhanced-oil-recovery (EOR) process, the production of oil depends on the supply of injected water or EOR agent. This suggests that the characteristic fracture spacing (or shape factor) for the dual-porosity/dual-permeability simulation of waterflood or EOR in a naturally fractured reservoir should account not for all fractures but only the relatively small number of fractures carrying almost all the injected water or EOR agent ("primary," as opposed to "secondary," fractures). In contrast, in primary production even a relatively small fracture represents an effective path for oil to flow to a production well. This distinction suggests that the "shape factor" in dual-permeability reservoir simulations and the repeating unit in homogenization should depend on the process involved: specifically, it should be different for primary and secondary or tertiary recovery. We test this hypothesis in a simple representation of a fractured region with a non-uniform distribution of fracture flow conductivities. We compare oil production, flow patterns in the matrix, and the pattern of oil recovery with and without the "secondary" fractures that carry only a small portion of injected fluid. The role of secondary fractures depends on a dimensionless ratio of characteristic times for matrix and fracture flow (Peclet number), and the ratio of flow carried by the different fractures. In primary production, for a large Peclet number, treating all the fractures equally is a better approximation of the original model, than excluding the secondary fractures; the shape factor should reflect both the primary and the secondary fractures. For a sufficiently small Peclet number, it is more accurate to exclude the secondary fractures in calculation of the shape factor in the dual-porosity/dual-permeability models than to include them and, in effect, assume they play an equally important role in transport to and from the matrix. For waterflood or EOR, in most cases examined, the a...

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Section: Primary Recoverysupporting

confidence: 87%