Numerical Simulation of Thick, Tight Fluvial Sands
- Fabian O. Iwere (Schlumberger) | Jaime E. Moreno (Schlumberger) | Osman G. Apaydin (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- August 2006
- Document Type
- Journal Paper
- 374 - 381
- 2006. Society of Petroleum Engineers
- 3 Production and Well Operations, 5.2 Reservoir Fluid Dynamics, 5.5 Reservoir Simulation, 5.2.1 Phase Behavior and PVT Measurements, 5.8.3 Coal Seam Gas, 4.3.4 Scale, 5.8.1 Tight Gas, 1.2.3 Rock properties, 2.4.3 Sand/Solids Control, 5.3.4 Integration of geomechanics in models, 4.1.2 Separation and Treating, 2 Well Completion, 5.5.3 Scaling Methods, 4.6 Natural Gas, 5.7.2 Recovery Factors, 5.5.7 Streamline Simulation, 5.8.8 Gas-condensate reservoirs, 5.2 Fluid Characterization, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.8.7 Carbonate Reservoir, 1.6 Drilling Operations, 5.6.5 Tracers, 5.1 Reservoir Characterisation, 5.8.6 Naturally Fractured Reservoir, 5.5.8 History Matching, 5.3.2 Multiphase Flow, 5.2.2 Fluid Modeling, Equations of State
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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.
The subject field is located in the northwestern Green River basin in Wyoming. It produces gas from the fluvial channel sandstones of the Upper Cretaceous Lance formation at drilling depths ranging from 11,000 to 12,500 ft. The Lance formation consists of several hundred feet of stacked lenticular sands and siltstones, floodplain shales, and minor coals that were deposited in a broad alluvial plain. The reservoirs consist of several sand units over a gross thickness of 4,000 ft in a fluvial depositional environment. The thickness of individual sand units ranges from 5 to 50 ft. These geological heterogeneous reservoirs are poorly correlatable over a large area.
The sandstones are fine- to medium-grained, with porosity ranging from 5 to 14% and permeabilities in the range of 0.001 to 0.03 md. Water saturation varies from approximately 30% updip to approximately 60% downdip. The study area situated updip has better reservoir quality and produces a very small amount of water, which is probably water from condensation and rock compaction. The reservoirs are overpressured with a pressure gradient of approximately 0.7 psi/ft. To honor the pressure gradient, the models were initialized by enumeration of reservoir pressure and fluid saturation, and infinitesimal vertical permeabilities were entered into the models to prevent gravity equilibrium.
Wells are stimulated with multiple limited-entry hydraulic fracturing to attain economical gas-production rates. Operators of the field use different completion strategies, which have evolved over the years. Three to six individual sands were completed per stage, with four to six stages per well. The number of stages has increased over the years, and a range of 6 to 10 stages is now common.
The complex architecture of this thick reservoir and massive hydraulic fracturing posed two major modeling challenges: reservoir upscaling and appropriate representation of the hydraulic fractures.
|File Size||3 MB||Number of Pages||8|
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