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Collaborating Authors
Abstract In a fractured reservoir, three dimensional (3-D) preferential flow paths are likely to be formed (i.e. 3-D channeling flow) due to the heterogeneous aperture distributions of individual fractures. However, to date there is no practical modeling method that precisely maps the 3-D channeling flow. In this study, we developed a novel method to analyze and predict channeling flow in an actual fractured reservoir, where a novel discrete fracture network (DFN) model simulator, GeoFlow, is used. In GeoFlow, heterogeneous aperture distributions are given for individual rock fractures depending on their scale and shear displacement under confining stress. By using GeoFlow, fluid flow is simulated for a fractured reservoir of the Yufutsu oil/gas fields, where we can observe an interesting phenomenon that the difference in productivity between two neighboring wells is three-orders-of-magnitude. This phenomenon can be reproduced only with the GeoFlow model, which strongly supports the idea that the three-orders-of-magnitude difference in productivity is mainly caused by the occurrence of 3-D channeling flow within the reservoir. Specifically, the impact of 3-D channeling flow on well production is expected to be significant in the domain where the degree of fracture connectivity is relatively limited. The contacting asperities within such a domain play a significant role as a resistance for 3-D preferential flow paths and, as a result, it is difficult of the flow paths to be maintained consistently.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (0.94)
Abstract The discrete fracture network (DFN) model simulation, in which the fracture network can have a natural heterogeneity, is one of the most effective approaches in fluid flow analyses for a fractured reservoir. In the DFN model simulation, the fracture is modeled by a pair of parallel smooth plates although real fractures have rough surfaces. However, numerous field and laboratory observations have suggested that fluid flow through a fracture occurred in specific preferential flow paths (channeling flow) due to a heterogeneous aperture distribution formed by the rough surfaces. The conventional DFN model simulation therefore gives us a serious concern about the reality. To address this concern, we have developed a new concept DFN model simulator, GeoFlow, in which the fracture can have the heterogeneous aperture distribution. Three dimensional fluid flow simulation was performed for a simple fracture network by both the conventional and the new concept DFN models. In the conventional DFN model simulation, the fracture had no aperture distribution, and fluid flow in the fracture plane was quite uniform. On the other hand, the GeoFlow simulation showed formation of three dimensional preferential flow paths in the fracture network. In addition, another GeoFlow simulation showed that productivities of the wells highly depended on their locations even when the wells intersected the same fracture. The productivities were considerably smaller when the wells intersected the regions with smaller aperture conductivities, where the preferential flow paths were difficult to form at the natural condition (no well condition). The results demonstrated occurrence of three dimensional channeling flow in fractured reservoirs, which should be addressed for effective developments of the reservoirs. Introduction Fluid flows through rock fractures in the Earth's crust have been a subject of interest for some time because rock fractures usually have much greater permeability than the rock matrix. Rock fractures are therefore recognized as the predominant pathways of resources and hazardous materials such as groundwater, oil/gas, geothermal fluids, and the high-level nuclear wastes. The fluid flow properties of rock fractures have been investigated with respect to the geological disposal of the high-level nuclear wastes. As a result, our understanding of the subsurface flow system has been greatly improved and has been applied to the development of geothermal and oil/gas fractured reservoirs. Recently, the prediction of flow and transport phenomena through rock fractures based on a precise modeling of the flow system in a fractured rock mass with natural heterogeneities has become increasingly important because recent environmental and energy problems require urgent solutions using underground space based on the safe and effective development of reservoirs. A modeling with a natural heterogeneity of a fracture network has been established by the Discrete Fracture Network (DFN) modeling technique [1–5]. In the DFN modeling, rock fractures have been described by parallel smooth plates. However, field and laboratory studies have suggested that fluid flow through a rock fracture is far from the fluid flow through parallel smooth plates, due to channeling flow in a heterogeneous aperture distribution by rough surfaces [6–14]. When channeling flow occurs in a single fracture of granite, the area where flowing fluid exists is expected only 5–20% at confining pressures of up to 100 MPa, with various features in the preferential flow paths [14].
- Information Technology > Communications > Networks (0.50)
- Information Technology > Modeling & Simulation (0.50)
Precise 3D Numerical Modeling of Fracture Flow Coupled With X-Ray Computed Tomography for Reservoir Core Samples
Watanabe, N.. (Tohoku University) | Ishibashi, T.. (Tohoku University) | Hirano, N.. (Tohoku University) | Tsuchiya, N.. (Tohoku University) | Ohsaki, Y.. (Japan Petroleum Exploration Company Limited) | Tamagawa, T.. (Japan Petroleum Exploration Company Limited) | Tsuchiya, Y.. (Japan Oil, Gas and Metals National Corporation) | Okabe, H.. (Japan Oil, Gas and Metals National Corporation)
Summary The present study focuses on the feasibility of a precise 3D numerical modeling coupled with X-ray computed tomography (CT), which enables simple analysis of heterogeneous fracture flows within reservoir core samples, as well as the measurement of porosity and permeability. A numerical modeling was developed and applied to two fractured granite core samples. One of the samples had an artificial single fracture (sample dimensions: 100 mm in diameter, 150 mm in length), and the other had natural multiple fractures (sample dimensions: 100 mm in diameter, 120 mm in length). A linear relationship between the CT value and the fracture aperture (fracture-aperture calibration curve) was obtained by X-ray CT scanning for a fracture-aperture calibration standard while varying the aperture from 0.1 to 0.5 mm. With the fracture-aperture calibration curve, 3D distributions of the CT value for the samples (voxel dimensions: 0.35×0.35×0.50 mm) were converted into fracture-aperture distributions in order to obtain fracture models for these samples. The numerical porosities reproduced the experimental porosities within factors of approximately 1.3 and 1.1 for the single fracture and the multiple fractures, respectively. Using the fracture models, a single-phase flow simulation was also performed with a local cubic law-based fracture-flow model for steady-state laminar flow of a viscous and incompressible fluid. The numerically obtained permeabilities were larger than the experimentally obtained permeabilities by factors of approximately 2.2 and 2.7 for the single fracture and the multiple fractures, respectively. However, these discrepancies can be reduced to approximately 1.3—2.1 and 1.6-2.6, respectively, by simply using the correction factor for the cubic-law equation proposed by Witherspoon et al. (1980). Consequently, a precise numerical modeling coupled with X-ray CT is essentially feasible. Furthermore, the development of preferential flow paths (i.e., channeling flow) was clearly demonstrated for multiple fractures, which is much more challenging to achieve by most other methods. Further progress in modeling should enable the in-situ evaluation of heterogeneous fracture flow within reservoir core samples, as well as the clarification of the impacts of the heterogeneity on the productivity of wells and, for example, the efficiency of recovery by water-/gasflooding.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract Whole core analysis, which provides characteristics on a larger scale closer to that of the reservoir, is particularly important for heterogeneous formations such as vuggy carbonate or fractured rocks. Consequently, the authors previously developed an X-ray CT based method to numerically analyze fluid flows through fractured rock cores. This method provides a 3D fracture aperture distribution of a fractured rock, which can be utilized to analyze fluid flow within the rock, with a local cubic law-based fracture flow model simulation. The numerical models of fractured rock and fluid flow, respectively, can reproduce experimentally determined porosity and permeability, and therefore can provide realistic fracture flow characteristics. In the present study, a new X-ray CT based method to numerically analyze fluid flows through vuggy carbonate rock cores has been developed, and has been applied to different types of vuggy carbonate rock core samples. 3D distributions of CT number of the samples, which consists of 0.4-mm cubic voxels, are converted into 3D porosity distributions, using the partial volume effect (i.e., a linear relationship between CT number and porosity). The porosity distributions can reproduce experimentally determined porosities within factors of approximately 1.1–1.4. To simulate Darcy flow in the samples, 3D permeability distributions are obtained by assuming that the permeability-porosity relation of non-vuggy carbonate rocks is valid locally within a vuggy carbonate rock. As a result of a fluid flow simulation, experimentally determined permeabilities, which show large differences among the samples, are reproduced within factors of 1.6–3.6, and heterogeneous fluid flows (i.e, channeling flows) within the samples.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Appropriate relative permeability curves for two-phase flows through heterogeneous vuggy carbonates remain unclear. We have therefore conducted numerical oil-water two-phase flow simulations using X-ray CT data, to obtain relative permeability curves for different types of vuggy carbonate samples. 3D distributions of CT number of the samples, which consist of 400-μm cubic voxels, are converted into 3D porosity distributions, and corresponding 3D distributions of absolute permeability are obtained by assuming porosity-permeability relations of non-vuggy carbonates at the voxel scale. 3D distributions of water saturation at different global water saturation levels for different capillary pressure conditions are obtained for the porosity distributions, by assuming porosity-dependent capillary pressure curves of non-vuggy carbonates at the voxel scale, providing corresponding 3D distributions of oil and water relative permeabilities with an assumption of Corey-type relative permeability curves at the voxel scale. Darcy flow simulations for resultant distributions of oil and water effective permeabilities provide global oil and water relative permeabilities at various global water saturation levels (i.e., relative permeability curves), which are validated by two-phase flow experiments. As a result, relative permeability curves of the samples containing vug pores distributed over the entire body exhibit Corey-type behaviors. On the other hand, relative permeability curves of the samples containing vug pores having fracture-like 2D distributions exhibit ν-type behaviors, which has been observed for two-phase flows through rock fractures. In case of vuggy carbonates, there is a possibility to have the non-Corey-type relative permeability curves, which are characterized by quite different behaviors of non-wetting phase from those of Corey type, depending on the distribution of vug pores because vug pores of weaker capillarity strongly affect behaviors of non-wetting phase.