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Research Papers: Underground Injection and Storage

Effect of Flue-Gas Impurities on the Process of Injection and Storage of CO2 in Depleted Gas Reservoirs

[+] Author and Article Information
Marjorie Nogueira

Department of Petroleum Engineering, Texas A&M University, 3116 TAMU-407 Richardson Building, College Station, TX 77843-3116marjorie.nogueira@bhpbilliton.com

Daulat D. Mamora

Department of Petroleum Engineering, Texas A&M University, 3116 TAMU-407 Richardson Building, College Station, TX 77843-3116marjorie.nogueira@bhpbilliton.com

Electronic communication with D. Chuck, EPRI-Continuous and Predictive Emissions Monitoring Group (22 July 2003).

www.kehlco.com

J. Energy Resour. Technol 130(1), 013301 (Feb 04, 2008) (5 pages) doi:10.1115/1.2825174 History: Received May 03, 2005; Revised October 31, 2006; Published February 04, 2008

Our previous coreflood experiments—injecting pure CO2 into carbonate cores—showed that the process is a win-win technology, sequestrating CO2 while recovering a significant amount of hitherto unrecoverable natural gas that could help defray the cost of CO2 sequestration. In this paper, we report our findings on the effect of “impurities” in flue gas—N2, O2, H2O, SO2, NO2, and CO—on the displacement of natural gas during CO2 sequestration. Results show that injection of CO2 with approximately less than 1mole% impurities would result in practically the same volume of CO2 being sequestered as injecting pure CO2. This gas would have the advantage of being a cheaper separation process compared to pure CO2 as not all the impurities are removed. Although separation of CO2 out of flue gas is a costly process, it appears that this is necessary to maximize CO2 sequestration volume, reduce compression costs of N2 (approximately 80% of the stream), and improve sweep efficiency and gas recovery in the reservoir.

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Copyright © 2008 by American Society of Mechanical Engineers
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References

Figures

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Figure 1

Phase envelopes of the two gases injected (Gas A and Gas B) in coreflood experiments compared to the vapor pressure line for pure CO2

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Figure 2

Photograph showing main components of the experimental apparatus

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Figure 3

Longitudinal section of coreflood cell with maximum operating conditions of 34.58MPa[5000psi(gauge)] and 366K. Scale approximately 1:3.

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Figure 4

Isosurface images of 3D porosity profiles using PETRO3D . These images are very helpful for understanding the porosity distribution in the core.

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Figure 5

Concentration of produced gas versus injected pore volume for runs at 10.44MPa[1500psi(gauge)] and 343K. Best-fit lines represent analytical solution for the best value of the coefficient of longitudinal dispersion. Earlier breakthrough time for Gas A when the initial water saturation is 20%.

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Figure 6

CO2 and Gas A density versus pressure at 343K as calculated using PVTSIM

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Figure 7

CO2 and Gas A viscosity versus pressure at 343K as calculated using PVTSIM . Viscosity of CO2 is higher than that of Gas A at pressures higher than 6.90MPa [1000psi (absolute)].

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