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Research Papers: Hydrates/Coal Bed Methane/Heavy Oil/Oil Sands/Tight Gas

Modeling of CO2-Hydrate Formation in Geological Reservoirs by Injection of CO2 Gas

[+] Author and Article Information
M. Uddin

 Alberta Research Council Inc., 250 Karl Clark Road, Edmonton, AB, T6N 1E4, Canadauddin@arc.ab.ca

D. Coombe

 Computer Modeling Group Ltd., 3512-33 Street, NW, Calgary, AB, T2L 2A6, Canadadennis.coombe@cmgl.ca

F. Wright

 Geological Survey of Canada, Terrain Sciences Division, Box 6000, 9860 West Saanich Road, Sidney, BC, V8L 4B2, Canadafwright@nrcan.gc.ca

J. Energy Resour. Technol 130(3), 032502 (Aug 08, 2008) (11 pages) doi:10.1115/1.2956979 History: Received August 27, 2007; Revised March 28, 2008; Published August 08, 2008

Continuing concern about the impacts of atmospheric carbon dioxide (CO2) on the global climate system provides an impetus for the development of methods for long-term disposal of CO2 produced by industrial and other activities. Investigations of the CO2-hydrate properties indicate the feasibility of geologic sequestration CO2 as gas hydrate and the possibility of coincident CO2 sequestration/CH4 production from natural gas hydrate reservoirs. Numerical studies can provide an integrated understanding of the process mechanisms in predicting the potential and economic viability of CO2 gas sequestration, especially when utilizing realistic geological reservoir characteristics in the models. This study numerically investigates possible sequestration of CO2 as a stable gas hydrate in various reservoir geological formations. As such, this paper extends the applicability of a previously developed model to more realistic and relevant reservoir scenarios. A unified gas hydrate model coupled with a thermal reservoir simulator (CMG STARS) was applied to simulate CO2-hydrate formation in four reservoir geological formations. These reservoirs can be described as follows. The first reservoir (Reservoir I) is similar to tight gas reservoir with mean porosity 0.25 and mean absolute permeability 10mD. The second reservoir (Reservoir II) is similar to a conventional sandstone reservoir with mean porosity 0.25 and mean permeability 20mD. The third reservoir (Reservoir III) is similar to hydrate-free Mallik silt with mean porosity 0.30 and mean permeability 100mD. The fourth reservoir (Reservoir IV) is similar to hydrate-free Mallik sand with mean porosity 0.35 and mean permeability 1000mD. The Mallik gas hydrate bearing formation itself can be described as several layers of variable thickness with permeability variations from 1mDto1000mD, and is addressed as a separate part of this study. This paper describes numerical methodology, model input data selection, and reservoir simulation results, including an enhancement to model the effects of ice formation and decay. The numerical investigation shows that the gas hydrate model effectively captures the spatial and temporal dynamics of CO2-hydrate formation in geological reservoirs by injection of CO2 gas. Practical limitations to CO2-hydrate formation by gas injection are identified and potential improvements to the process are suggested.

Copyright © 2008 by American Society of Mechanical Engineers
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References

Figures

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Figure 19

Distributions of CH4-hydrate (CH4⋅nH2O) concentrations at the end of 2days and 10days (hydrate saturation, Sh=concentration(ch)/volumetric mole density (ρ))

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Figure 20

Distributions of pressures (P) at the end of 2days and 10days

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Figure 21

Distributions of temperatures (T) at the end of 2days and 10days

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Figure 1

CH4- and CO2-hydrate stability curves for the above freezing point (water-hydrate-gas system) and below freezing point (ice-hydrate-gas system) (data sources: Adisasmito (7), North (23), and Moridis )

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Figure 2

Effects of pore-water salinity on CH4- and CO2-hydrate stability curves for the above freezing point (water-hydrate-gas system) (stability curves were shifted 1°C20ppt salinity)

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Figure 3

Effects of pore-water salinity on CH4- and CO2-hydrate stability curves for temperatures below the freezing point (ice-hydrate-gas system)

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Figure 4

Half pattern (200×20×4m3) numerical flow system for the four generic reservoirs

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Figure 5

Tight gas reservoir I: Effects of CO2 vapor injection rates on the average field pressure (P), temperature (T), and CO2-hydrate concentration (CO2⋅nH2O) (hydrate saturation, Sh=concentration(ch)/Volumetric mol density (ρ))

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Figure 6

Sandstone reservoir II: Effects of CO2 vapor injection rates on the average field pressure (P), temperature (T), and CO2-hydrate concentration (CO2⋅nH2O)

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Figure 7

Mallik silt reservoir III: Effects of CO2 vapor injection rates on the average field pressure (P), temperature (T), and CO2-hydrate concentration (CO2⋅nH2O)

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Figure 8

Mallik sand reservoir IV: Effects of CO2 vapor injection rates on the average field pressure (P), temperature (T), and CO2-hydrate concentration (CO2⋅nH2O)

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Figure 9

Reservoirs I–IV: Variations of the average field pressure (P), temperature (T), and CO2-hydrate concentration (CO2⋅nH2O) at a CO2 vapor injection rate of 400m3∕day (STD)

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Figure 10

Reservoirs I–IV: Variations of the average field pressure (P), temperature (T), and CO2-hydrate concentration (CO2⋅nH2O) at a CO2 vapor injection rate of 200m3∕day (STD)

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Figure 11

Reservoir I: Distributions of CO2-hydrate concentration, pressure, and temperature at the end of 360days at a CO2 vapor injection rate of 200m3∕day (STD)

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Figure 12

Reservoir IV: Distributions of CO2-hydrate concentration, pressure, and temperature at the end of 360days at a CO2 vapor injection rate of 200m3∕day (STD)

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Figure 13

Effects of the rock thermal conductivity and pore-water salinity on CO2-hydrate formations (hydrate saturation, Sh=concentration(ch)/volumetric mole density (ρ))

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Figure 14

Half pattern (200×60×4m3) numerical flow system with 48,000 active grid cells

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Figure 15

Permeability distribution in the numerical grid cells for the Mallik (5L-38) lower hydrate bearing formation

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Figure 16

Mallik (5L-38) lower hydrate formation showing variation of porosity, permeability, and gas hydrate saturation (JAPEX/JNOC/GSC Mallik gas hydrate production research well, Dallimore (4,6))

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Figure 17

Variations of the simulated production data (gas and water) and well bottom hole pressure

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Figure 18

Variations of the average field pressure (P), temperature (T), and CH4-hydrate concentration (CH4⋅nH2O) (hydrate saturation, Sh=concentration(ch)/volumetric mole density (ρ))

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