A Critical Assessment of CO2 Injection Strategies in Saline Aquifers
- Mojdeh Delshad (U. of Texas at Austin) | Mary Fanett Wheeler (U. of Texas at Austin) | Xianhui Kong (University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Western Regional Meeting, 27-29 May, Anaheim, California, USA
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 2 Well Completion, 5.4 Enhanced Recovery, 6.5.3 Waste Management, 5.4.2 Gas Injection Methods, 5.5 Reservoir Simulation, 5.10.1 CO2 Capture and Sequestration, 5.1.2 Faults and Fracture Characterisation, 6.5.2 Water use, produced water discharge and disposal, 5.1.1 Exploration, Development, Structural Geology, 5.2.1 Phase Behavior and PVT Measurements, 1.2.2 Geomechanics, 4.3.4 Scale
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There is an overwhelming evidence of increased levels of green house gases such as CO2 in the atmosphere with an urgent need to stabilize the CO2 atmospheric content by storage in geological formations. The main concern in geological storage of CO2 is its long term subsurface retention. Primary containment mechanisms are dissolution in water, reaction with rock, and capillary trapping. Development decisions such as number of injection wells, injection rates, well placement, and the need for water production/reinjection may pose a profound effect on long term storage. A reservoir simulation study was conducted to study several injection schemes to assess the impact on the amount sequestered and the extent of vertical migration. Simulations were performed using the compositional reservoir simulator CMG-GEM (2009). Thermal and geomechanical effects were not considered. Several prototype reservoir geomodels were studied to determine the impact of injection strategy on injectivity, CO2 retention, plume extension, and upward movement to formation top seal. It is demonstrated that the well placement, well completion and injection schemes have strong impact on the amount of residual and dissolved CO2. The CO2 injectivity was severely impaired when water and gas are injected simultaneously.
Geologic sequestration by injection of CO2 into deep brine aquifers and oil and gas reservoirs represents one of the most promising approaches to lower the rate that CO2 increases in the atmosphere. The basis for this potential is the huge global storage capacity existing in geologic formations and the availability and close proximity of potential injection sites to power generation plants. Injections of large volumes of CO2 into these formations pose significant technical issues to ensure safety, to minimize leakage probability on a time scale of hundreds or even thousands of years, and to gain public acceptance.
While geologic sequestration is a proven means of permanent CO2 storage, it is difficult to design and manage such efforts. Numerical simulations may be the only mean to account for the lack of complete characterization of the subsurface environment, the multiple scales of the various interacting processes, the large areal extent of saline aquifers, and the need for long time predictions. Key issues for modeling CO2 injection in saline formations are large uncertainty in predicting CO2 flow rates. This is due to insufficient and inaccurate data in characterizing formation permeability, porosity, and multiphase fluid behavior as a function of pressure, salinity, and temperature. There are several ongoing and proposed injection programs such as Sleipner (Torp and Gale, 2004), Weyburn (Malik and Islam, 2000), In Salah (Davies et al., 2001; Wright, 2007), Gorgon (Flett et al., 2008), Frio (Hovorka et al., 2005; Benson, 2006; Ghomian et al., 2008), and Cranfield (Meckel and Hovorka, 2009) designed to enhance our understanding of CO2 storage.
Injection of CO2 in aquifers includes a series of coupled multiphase physical and chemical processes such as phase behavior, fluid viscosity, relative permeability and capillary pressure, wettability, geochemical/mineralization reactions etc. There are also geological processes such as leakage through faults and fractures, abandoned wells and open boundaries. For many deep saline aquifers, the supercritical carbon dioxide has a density less than that of the aquifer brine; hence, it has the tendency to migrate upward due to gravity driven flow. If the formation has a dip angle, the free carbon dioxide phase will likely travel along the cap rock and leakage may occur if there is fault or open boundary in the formation. The four primary mechanisms for CO2 trapping in brine formations are: (1) residual trapping, in which CO2 becomes disconnected and becomes trapped in individual pores of the rock; (2) structural trapping due to low-permeability cap rocks; (3) dissolution, CO2 gas phase is dissolved in brine; and (4) mineral trapping, in which dissolved CO2 in brine reacts with rock to form minerals. Residual trapping and dissolution of CO2 are the fastest and most significant means of sequestering CO2 for long durations. Mineral trapping is a much slower mechanism compared to capillary trapping and dissolution trapping.
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