How CO2-Storage Mechanisms Are Different in Organic Shale: Characterization and Simulation Studies
- Hui Pu (InPetro Technologies) | Yuhe Wang (Texas A&M University at Qatar) | Yinghui Li (InPetro Technologies)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- June 2018
- Document Type
- Journal Paper
- 661 - 671
- 2018.Society of Petroleum Engineers
- 3D Compositional Simulator, Pore size distribution, CO2 Storage, Capillarity, Shale oil reservoirs
- 8 in the last 30 days
- 256 since 2007
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Widely distributed organic-rich shales are being considered as one of the important carbon-storage targets, owing to three differentiators compared with conventional reservoirs and saline aquifers: (1) trapping of a significant amount of carbon dioxide (CO2) permanently; (2) kerogen-rich shale’s higher affinity of CO2; and (3) existing well and pipeline infrastructure, especially that in the vicinity of existing power or chemical plants. The incapability to model capillarity with the consideration of imperative pore-size-distribution (PSD) characteristics by use of commercial software may lead to inaccurate modeling of CO2 injection in organic shale. We develop a novel approach to examine how PSD would alter phase and flow behavior under nanopore confinements. We incorporate adsorption behavior with a local density-optimization algorithm designed for multicomponent interactions to adsorption sites for a full spectrum of reservoir pressures of interests. This feature elevates the limitation of the Langmuir isotherm model, allowing us to understand the storage and sieving capabilities for a CO2/N2 flue-gas system with remaining reservoir fluids. Taking PSD data of Bakken shale, we perform a core-scale simulation study of CO2/N2 flue-gas injection and reveal the differences between CO2 injection/storage in organic shales and conventional rocks on the basis of numerical modeling.
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