Enhanced oil recovery (EOR) process selection is an important part of field development strategy. One of the most important categories of EOR methods utilize certain chemical components that enhance the fluid properties. Polymer-enhanced waterfloods are one of the examples. During conventional waterfloods, the flow characteristics and displacement efficiency usually depends on a certain rock type in study. In a chemical EOR flood, there are a large number of parameters needed to be defined and optimized that impact process efficiency. The attempt to execute corefloods for various combinations of these parameters for each rock type would lead to a large number of tests not executable in a time frame compatible with timely decision making. And the destructive nature of the experimental chemical EOR floods prohibits repeated testing on the same core sample. The natural difference between the samples selected for the study can prevail over the process efficiency difference related to the certain design parameter in the study.
Digital core analysis can help to optimize design of EOR floods and reduce the associated uncertainty. In this work we apply digital core analysis to investigate the dynamics of oil displacement, using water and water-based polymer solutions in porous media. The described technology application includes scanning of core samples using X-ray microtomography, creating digital models for the samples in study, and running pore-scale hydrodynamic modeling using the density functional hydrodynamics (DFH) method, which combines density functional theory with compositional multiphase hydrodynamics. The results include visual snapshots of phase distributions at pore scale for various times during the waterflooding and polymer solution flooding at various concentrations.
Polymer-enhanced waterflooding increased the displacement coefficient by almost 2% and 20% for low- and high-concentrated polymer solutions, respectively. This effect was further explained by analyzing the dynamics of oil displacement on a pore scale. The results show an exemplary sensitivity study that investigates the dependency of the displacement coefficient on the polymer solution type and concentration. Additional sensitity studies with varying design parameters (slug size, injection sequence, polymer type, etc.) can be also performed.
The dynamics of oil displacement using water and gas mixtures in porous media is studied using digital rock analysis. The technology includes scanning of core samples using X-Ray micro tomography, creating of digital models for the samples, and running hydrodynamic modeling on pore scale using the density functional approach. The results include visual snapshots of phase distributions on pore scale for various time instants of oil displacement by water and water-gas mixtures. Due to WAG the displacement coefficient was increased by 5% to 10.5% for water-wet samples and by 20-21% for oil-wet samples. This effect was explained by analyzing the dynamics of oil displacement on a pore scale. The simulations also allow studying the dependency of the displacement coefficient on WAG regimes for water-wet and oil-wet media.
Coalbed methane (CBM) is clean unconventional energy that can be exploited with stimulation treatment to realize commercial value, and hydraulic fracturing is the key technology for increasing CBM production. The simulation of hydraulic fractures is an important research content that can guide the engineering practice to achieve the purpose of increasing production. Based on the distribution characteristic of cleats in coal, the research on the propagation of hydraulic fractures is carried out via Discrete element method (DEM). The simulated results show that: hydraulic fractures mainly propagate along the cleats towards the maximum principal stress. The fracture network can be formed due to the intersection of face cleats and butt cleats that can propagate at certain pressure. During the injection process of fracturing fluid, the pressure at injection point decreases with the fracture propagation until the pressure tends to be stable. With the increase of injection rate and fracturing fluid viscosity at the same condition, the maximum aperture of hydraulic fracture increases, while the length of principal hydraulic fracture shortens. Therefore, to achieve the purpose of forming hydraulic fracture network in coal seams with cleats, low viscosity fracturing fluid and low injection rate need be applied to the fracturing technology. As the cleat density increases, the number of branch fractures increases, but the length of principal hydraulic fracture becomes short. Long and narrow hydraulic fractures are easily formed in coal seams with lower cleat density.
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