Experimental and Numerical Simulation of CO2 Injection Into Upper-Triassic Sandstones in Svalbard, Norway
- Raheleh Farokhpoor (Norwegian U. of Science & Tech) | Ole Torsater (Norwegian U. of Science & Tech) | Tooraj Baghbanbashi (NTNU) | Atle Mork (SINTEF) | Erik G.B. Lindeberg (SINTEF Petroleum 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
- 4.6 Natural Gas, 5.5 Reservoir Simulation, 5.1 Reservoir Characterisation, 5.10.1 CO2 Capture and Sequestration, 5.2.2 Fluid Modeling, Equations of State, 2.2.2 Perforating, 4.3.4 Scale, 5.4 Enhanced Recovery, 5.1.1 Exploration, Development, Structural Geology, 1.2.3 Rock properties, 2.4.3 Sand/Solids Control, 5.2 Reservoir Fluid Dynamics, 6.5.7 Climate Change, 6.5.3 Waste Management, 5.4.2 Gas Injection Methods, 1.6.9 Coring, Fishing
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Sequestration of carbon dioxide in a saline aquifer is currently being evaluated as a possible way to handle carbon dioxide emitted from a coal-fuelled power plant in Svalbard. The chosen reservoir is a 300 m thick, laterally extensive, shallow marine formation of late Triassic-mid Jurassic age, located below Longyearbyen in Svalbard. The reservoir consists of 300 m of alternating sandstone and shale and is capped by 400 meter shale.
Experimental and numerical studies have been performed to evaluate CO2 storage capacity and long term behaviour of the injected CO2 in rock pore space. Laboratory core flooding experiments were conducted during which air was injected into brine saturated cores at standard conditions. Analysis of the results shows that the permeability is generally less than 2 millidarcies and the capillary entry pressure is high. For most samples, no gas flow was detected in the presence of brine, when employing a reasonable pressure gradient. This poses a serious challenge with respect to achieving viable levels of injectivity and injection pressure.
A conceptual numerical simulation of CO2 injection into a segment of the planned reservoir was performed using commercial reservoir simulation software and available petrophysical data. The results show that injection using vertical wells yields the same injectivity but more increases in field pressure compare to injection through horizontal wells. In order to keep induced pressure below top-seal fracturation pressure and preventing the fast propagation and migration of CO2 plume, slow injection through several horizontal wells into the lower part of the "high?? permeability beds appears to offer the best solution.
The high capillary pressure causes slow migration of the CO2 plume, and regional groundwater flow provides fresh brine for CO2 dissolution. In our simulations, half of the CO2 was dissolved in brine and the other half dispersed within a radius of 1000 meter from the wells after 4000 years. Dissolution of CO2 in brine and lateral convective mixing from CO2 saturated brine to surrounding fresh brine are the dominant mechanisms for CO2 storage in this specific site and this guarantees that the CO2 plume will be stationary for thousands of years.
One of the strategies to mitigate climate change is to reduce atmospheric greenhouse gases by capturing and sequestering CO2 in sub-surface reservoirs for extended periods of time. Saline aquifers are considered to be one of the best options for CO2 sequestration due to their large storage capacity, injectivity potential and proximity to CO2 sources at some places. Uncertainties due to limitation of geological data and reservoir data will, however, limit the accuracy of predictions from modeling. (Bachu, et al., 2009). CO2 sequestration in saline aquifers is being actively pursued particularly in United States, Norway, Germany, Canada, Algeria, Australia and Japan (Australian Cooperative Research Centres).
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