Reservoir management strategies to balance risk and cost of subsurface CO2 storage

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Title Reservoir management strategies to balance risk and cost of subsurface CO2 storage
Publication Type thesis
School or College College of Engineering
Department Civil & Environmental Engineering
Author McIntire, Blayde Alias
Date 2013-12
Description The long-term success of Carbon Capture and Storage (CCS) as an industry depends on effective risk management and cost efficiency. Reservoir pressure-buildup associated with injection induces minor seismic events in all subsurface reservoirs, and thus such will necessarily be an outcome of CCS operations, too. Perhaps the simplest approach is to modulate injection rates to maintain bottom hole pressure (BHP) below the theoretical fracture pressure of the reservoir that is assumed to be 80% of the lithostatic pressure. A reservoir model was created in TOUGH-MP for simulating numerous injection well configurations. Due to time constraints, 10 m injection cells were chosen to balance error and computational efficiency. Results of this study include plots of injection volume versus number of injection wells, or "injection curves," for a broad range of reservoir parameters evaluated in a comprehensive sensitivity analysis. One injection well proved to inject the least amount of fluid of the tested well configurations. In all cases, the largest injection coincided with the most wells. Injectivity was most sensitive to permeability; injection volume changed by nearly an order of magnitude for an order of magnitude change in permeability. Effects of less sensitive parameters were summarized by their effects to the permeability injection curves. A cost function was developed and applied to all results from the sensitivity analysis to determine cost efficiency. The full set of results may be interpolated to forecast an optimal number of wells for most scenarios. Generally, the optimal number of wells that facilitates the lowest cost of CO2 per tonne is between four and eight wells. Injection scenarios with a single injection well proved to be the least efficient. Finally, the developed methodology is illustrated via application in a case study of the Rocky Mountain Carbon Capture and Storage (RMCCS) project, a CCS candidate site near Craig, Colorado, USA. The forecasting method provided decent estimates of cost and injection volume when compared to simulated results. All results suggest CCS success may be increased by careful BHP management through optimized well placement strategies.
Type Text
Publisher University of Utah
Subject Carbon capture and storage; CO2 Sequestration; Induced seismicity; Injection; Optimization; Pressure
Dissertation Institution University of Utah
Dissertation Name Master of Science
Language eng
Rights Management Copyright © Blayde Alias McIntire 2013
Format application/pdf
Format Medium application/pdf
Format Extent 2,033,438 bytes
Identifier etd3/id/2663
ARK ark:/87278/s6q277f3
Setname ir_etd
ID 196238
Reference URL https://collections.lib.utah.edu/ark:/87278/s6q277f3
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