Summary
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 geo-cellular 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.
