Effects of Oil Compressibility on Production Performance of Fractured Reservoirs Evaluated by Streamline Dual-Porosity Simulation
- Shusei Tanaka (Waseda University) | Norio Arihara (Waseda University) | Muhammad Ali Al-Marhoun (King Fahd University of Petroleum and Minerals)
- Document ID
- Society of Petroleum Engineers
- SPE EUROPEC/EAGE Annual Conference and Exhibition, 14-17 June, Barcelona, Spain
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 5.5 Reservoir Simulation, 5.5.7 Streamline Simulation, 5.2 Reservoir Fluid Dynamics, 5.3.1 Flow in Porous Media, 5.3.2 Multiphase Flow, 4.6 Natural Gas, 4.1.4 Gas Processing, 5.6.4 Drillstem/Well Testing, 5.6.5 Tracers, 6.5.2 Water use, produced water discharge and disposal, 4.3.4 Scale, 5.8.6 Naturally Fractured Reservoir, 5.2.1 Phase Behavior and PVT Measurements
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As naturally fractured reservoirs (NFR) present wide ranges of geological characteristics and complex flow mechanisms between matrix and fracture, reservoir simulation is highly necessary to properly evaluate production performance. The production performance depends on fracture distributions and matrix/fracture properties as well as on fluid properties. We studied by simulation particularly about effects of oil compressibility below bubble-point pressure on production performance. Also evaluated was how the compressibility effects vary with different fracture spacing that is generally uncertain even in a production stage and should be characterized by simulation.
We first developed and validated a 3-phase 3-dimensional dual-porosity model with the streamline method. The fluid compressibility is a primary parameter that directly affects the reservoir performance. We accounted for compressibility effects with the total compressibility in the 3-D pressure equations, and with the effective density in the 1-D flow equations along streamlines. A flash-calculation algorithm was incorporated to treat the gas and oil phases correctly. We also considered dissolved gas, capillary pressure and gravity
The oil and gas compressibility definitions presented by Perrine, that have been being used conventionally, show a physical inconsistency such that oil compressibility below the bubble-point pressure increases with the increase of density, and that the mass of gas phase remains constant with changing pressures below the bubble-point pressure. To correct those, new derivation based on the basic compressibility definition was introduced.
With constant water-injection and liquid production rates in a 5-spot well pattern, simulation results using the new and conventional compressibility formulation were compared for different fracture and fluid properties such as shape factor and solution gas-oil ratio. With the new compressibility, we obtained slower declines of the reservoir pressure, higher oilproduction rates, lower water-production rates, and slower increases of production GOR. Differences between the results with
the new and conventional compressibility are augmented as the fracture spacing decreases.
Flow simulation of fractured reservoirs is usually performed using a dual-porosity model.1,2 The dual-porosity system is described by using two coupled continua, fracture and matrix. Fluids in the dual-porosity medium flow through a network of high-permeability and low-porosity fractures developed in low-permeability and high-porosity matrix blocks. The matrix blocks contain the majority of the reservoir pore volume and act as sources/sinks of fluids to/from the fractures. The gridbased finite-difference method is conventionally used to solve the coupled flow equations for pressure and saturation in fracture and matrix.
The streamline approach, of which applicability to field-scale simulation was first demonstrated in the mid-90s, was thought not to be suited for the fractured-reservoir simulation because of difficulties to describe the matrix-fracture transfer mechanisms. However, several authors have overcome those issues with the dual-media approach. In 2003, Di Donato et al.3 presented a dual-porosity simulator for incompressible water-oil flow in which the fracture-matrix transfer is accommodated as a source/sink term in one-dimensional conservation equation along streamlines. In 2004, Al-Huthali and Datta-Gupta4 developed a general dual-porosity dual-permeability model for incompressible water-oil flow. They solved the saturation equations using an operator splitting approach in which matrix-fracture transfer calculations are performed on the grid. In these years, formulation of three-phase compressible flow was another challenge for the streamline-based simulation.
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