Streamline Simulation of Countercurrent Water-Oil and Gas-Oil Flow in Naturally Fractured Dual-Porosity Reservoirs

Moreno, Jaime Eduardo; Kazemi, Hossein; Gilman, James R.

doi:10.2118/89880-ms

Cited by 21 publications

(16 citation statements)

References 32 publications

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“…19 shows the comparison of the oil recovery between the transfer functions and the fine-grid model. It is immediately obvious from the recovery plot that without the modification to the old transfer function (Moreno et al 2004) a match with the fine-grid model cannot be obtained.…”

Section: Case 4-effect Of Partially Water-filled Fractures Onmentioning

confidence: 99%

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Verification and Proper Use of Water-Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs

Balogun

Kazemi

Özkan

et al. 2009

SPE Reservoir Evaluation &Amp; Engineering

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Accurate calculation of multiphase fluid transfer between the fracture and matrix in naturally fractured reservoirs is a very crucial issue. In this paper, we will present the viability of the use of a simple transfer function to accurately account for fluid exchange resulting from capillary and gravity forces between fracture and matrix in dual-porosity and dual-permeability numerical models. With this approach, fracture-and matrix-flow calculations can be decoupled and solved sequentially, improving the speed and ease of computation. In fact, the transfer-function equations can be used easily to calculate the expected oil recovery from a matrix block of any dimension without the use of a simulator or oil-recovery correlations.The study was accomplished by conducting a 3-D fine-grid simulation of a typical matrix block and comparing the results with those obtained through the use of a single-node simple transfer function for a water-oil system. This study was similar to a previous study (Alkandari 2002) we had conducted for a 1D gas-oil system.The transfer functions of this paper are specifically for the sugar-cube idealization of a matrix block, which can be extended to simulation of a match-stick idealization in reservoir modeling. The basic data required are: matrix capillary-pressure curves, densities of the flowing fluids, and matrix block dimensions.

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Section: Case 4-effect Of Partially Water-filled Fractures Onmentioning

confidence: 99%

“…The pressure and water saturation equations used in modeling water-oil flow in naturally fractured reservoirs are given below (Kazemi 2004):…”

mentioning

confidence: 99%

Verification and Proper Use of Water-Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs

Balogun

Kazemi

Özkan

et al. 2009

SPE Reservoir Evaluation &Amp; Engineering

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“…35 can be obtained from Eq. 7 by assuming τ w + τ o = 0 as was similarly done in a previous paper (Moreno, et al, 2004), which excluded the term σ z /σ. …”

Section: Dual-porosity Formulationmentioning

confidence: 99%

“…23 shows the comparison of the oil recovery between the transfer functions and the finegrid model. It is immediately obvious from the recovery plot that without the modification to the old transfer function (Moreno, et al, 2004) a match with the fine-grid model cannot be obtained. …”

Section: Case 5 -Old and New Transfer Function Comparisonmentioning

confidence: 99%

Verification and Proper Use of Water/Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs

Balogun

Kazemi

Özkan

et al. 2007

SPE Middle East Oil and Gas Show and Conference

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAccurate calculation of multi-phase fluid transfer between the fracture and matrix in naturally fractured reservoirs is a very crucial issue. In this paper, we will present the viability of the use of a simple transfer function to accurately account for fluid exchange resulting from capillary and gravity forces between fracture and matrix in dual-porosity and dualpermeability numerical models. With this approach, fracture and matrix flow calculations can be decoupled and solved sequentially, improving the speed and ease of computation. In fact, the transfer function equations can be easily used to calculate the expected oil recovery from a matrix block of any dimension without the use of a simulator or oil recovery correlations.The study was accomplished by conducting fine-grid simulation of a typical matrix block and comparing the results with those obtained with the use of a simple transfer function for a water-oil system. This study was similar to a previous study (Alkandari, 2002) we had conducted for a gas-oil system.The transfer functions of this paper are specifically for the sugar-cube idealization of a matrix block, which can be extended to simulation of a match-stick idealization in reservoir modeling. The basic data required are: matrix capillary pressure curves, densities of the flowing fluids, and matrix block dimensions.

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“…The flow-based upscaling technique was therefore used to determine the degree of vertical upscaling. Although streamline simulation is designed for convection-dominated problems (fluid displacement) (Moreno et al 2004;Sovold et al 1990), it is adaptable for simulation of tight gas sand reservoirs.…”

Section: Geocellular Model Upscalingmentioning

confidence: 99%

Numerical Simulation of Thick, Tight Fluvial Sands

Iwere

Moreno

Apaydin

2006

SPE Reservoir Evaluation &Amp; Engineering

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This paper presents several workflows for constructing adequate flow models of a tight gas field located in Wyoming. The numerical flow models were built by integrating seismic, petrophysical, geological, and engineering data, including hydraulic fracture data. The reservoirs consist of several sand units over a gross thickness of 4,000 ft in a fluvial depositional environment. Reservoir rock permeabilities are in the microdarcy range. The overpressured reservoirs become economically viable only by hydraulic fracturing. Two major challenges of modeling the field are reservoir upscaling and appropriate representation of the hydraulic fractures.A streamline-based flow model was used to upscale geological features. Some practical assumptions were made to apply this technology in our study. Multiple models were generated using different upscaling scenarios and techniques. The models were set up with the same boundary conditions (injector/producer pairs, injection/production rates, etc.), and their results were compared with the fine-grid geocellular-model results. Pseudofluid properties (low viscosity) and a very long time scale had to be used because of the low permeability of the sands. The fluid recovery and injected fluid breakthrough times for the flow models and the geocellular model were then compared. The flow model with the most reasonable volumetrics and flow characteristics was chosen for the numerical simulation study.The producing wells are hydraulically fractured with multiple stages. Single-well and sector models were used to determine the ultimate fracture properties that were used in the final simulation model. First, local grid refinement was used to represent the fracture properties. Then, a parametric study was conducted to establish the effective global cell properties that are required to simulate the flow of hydrocarbons along the hydraulic fracture without using the local grid refinements. Production and pressure performance over a long period of time were compared. Effective permeability and pore-volume calculation yielded the best results, and they were used during the history matching of the wells' performances.

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Streamline Simulation of Countercurrent Water-Oil and Gas-Oil Flow in Naturally Fractured Dual-Porosity Reservoirs

Cited by 21 publications

References 32 publications

Verification and Proper Use of Water-Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs

Verification and Proper Use of Water-Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs

Verification and Proper Use of Water/Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs

Numerical Simulation of Thick, Tight Fluvial Sands

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