Enhanced Gas Recovery and CO2 Storage in Coalbed-Methane Reservoirs: Optimized Injected-Gas Composition for Mature Basins of Various Coal Rank
- Karine Chrystel Schepers (Advanced Resources International, Inc.) | Anne Yvonne Oudinot (Advanced Resources International, Inc.) | Nino Ripepi (Virginia Center for Coal and Energy Research)
- Document ID
- Society of Petroleum Engineers
- SPE International Conference on CO2 Capture, Storage, and Utilization, 10-12 November, New Orleans, Louisiana, USA
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.5 Reservoir Simulation, 3 Production and Well Operations, 5.6.4 Drillstem/Well Testing, 5.10.1 CO2 Capture and Sequestration, 5.4.2 Gas Injection Methods, 5.8.3 Coal Seam Gas, 6.5.3 Waste Management, 5.1.5 Geologic Modeling, 5.8.6 Naturally Fractured Reservoir, 5.4 Enhanced Recovery, 4.3.4 Scale
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Nitrogen (N2) and carbon dioxide (CO2) injection has been a subject of enhanced coal bed methane (ECBM) and carbon capture and storage (CCS) research during the past decade. N2 and CO2 injection produce substantially different recovery processes. Coal has a higher affinity for CO2 as compared to methane (CH4). Preferential adsorption of CO2, a larger molecule than methane, onto the coal surface results in a dramatic decrease in cleat permeability due to coal swelling. This ultimately induces a loss of injectivity creating a significant technical hurdle for CCS operations in coal. In contrast, N2 increases cleat permeability because of its lower coal storage capacity relative to methane. As a result, injectivity increases during N2-ECBM. Theoretically, the injection of a mixture of CO2 and N2 will result in ECBM and CCS without a loss of injectivity. This study presents an investigation of that concept.
To identify key geological and reservoir parameters driving ECBM and sequestration processes in deep unminable coal seams, a Monte Carlo probabilistic approach was implemented. Results from tornado plots confirmed the major role that coal rank (Langmuir isotherms) and pressure-dependent permeability data play in ECBM processes. As coal rank determines the maximum gas-in-place that could be stored per volume of coal, average fracture permeability, matrix and pore compressibility, and differential swelling factors are predominant in coal capacity to flow water and gas phases, impacting both incremental methane production as well as injectivity.
Additionally, cleat permeability will vary greatly in response to injected gas composition during ECBM process. To better understand the consequences of these permeability changes by coal rank, a parametric study was designed. First results show that, for a specific coal rank, ECBM can drastically improve by increase N2 content in the injected gas stream. However, methane incremental recovery due to high N2 content will increase up to a maximum N2 concentration, or threshold: besides this threshold, breakthrough occurs too rapidly to generate additional methane recovery. This N2 threshold varies between coal ranks, as pressure dependant parameters also vary relative to the rank.
Finally, 100%N2 injection scenarios per coal rank highlight permeability behaviors easily explained in theory but which would probably need additional laboratory measurements to better understand their physical meaning while encountered during "real world?? problems.
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