Multi-Scale Analysis of CO2 Injection as Improved Shale Gas Recovery Method
- Brice Y. Kim (Texas A&M University) | Olufemi Olorode (Louisiana State University) | I. Yucel Akkutlu (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Europec featured at 81st EAGE Conference and Exhibition, 3-6 June, London, England, UK
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 5.1.1 Exploration, Development, Structural Geology, 4.6 Natural Gas, 5 Reservoir Desciption & Dynamics, 2.4 Hydraulic Fracturing, 2.4 Hydraulic Fracturing, 4.3.4 Scale, 5.8 Unconventional and Complex Reservoirs, 4 Facilities Design, Construction and Operation, 3 Production and Well Operations, 5.8.2 Shale Gas, 3 Production and Well Operations, 5.5 Reservoir Simulation, 4.1.2 Separation and Treating, 1.6 Drilling Operations, 2 Well completion, 4.1 Processing Systems and Design, 5.1 Reservoir Characterisation
- CO2, kerogen, shale, carbon dioxide, enhanced recovery
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This study is based on the premise that most of the trapped hydrocarbons can be produced, if we substitute them with another ‘acrificial’ fluid that has amplified interactions with organic pore walls, such as CO2. For the presented study, a downhole shale sample is analyzed in the laboratory to predict gas storage properties such as pore-volume, pore compressibility, and gas adsorption capacity. Then a series of pressure pulse decay measurements are performed to delineate transport mechanisms and predict stress-sensitive permeability. These coefficients are obtained as the calibration parameters of a simulation-based optimization for injection and production. Simulation model considers compositional gas flow in a deformable porous media and includes a multi-continuum porosity, with organic and inorganic pores, and micro-fractures. The experimental and simulation results show that most of the injected CO2 is adsorbed in the organic matrix and are not produced back. This is because CO2 molecules have significantly larger adsorption capacity when compared to methane. The strong adsorption of CO2 improves the release of natural gas from kerogen pores. This indicates that the separation of produced CO2 will be a minimal cost. Transport in kerogen has significant pore wall effects, and includes large mass fluxes of the adsorbed molecules by the walls due to surface diffusion. In essence, the adsorbed CO2 molecules significantly influence transport of methane. The results also show core-plug permeability is stress-sensitive due to presence of micro-fractures. Forward simulation results using optimum parameters indicate that closure stress developing near the fractures could significantly control the volume of CO2 injected. This raises operational issues on when to start injecting, and how to inject CO2. Using a simulation study of a production well with single-fracture, we show that fracture closure stress develops rapidly and production rate becomes a slave of the fracture geo-mechanics, e.g., strength of the proppants and the level of proppant embedment.
|File Size||1 MB||Number of Pages||22|
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