Fluid/Rock Interactions During CO2 Sequestration in Deep Saline Carbonate Aquifers: Laboratory and Modeling Studies
- Ibrahim Mohamed (Texas A&M University) | Hisham A. Nasr-El-Din (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- April 2013
- Document Type
- Journal Paper
- 468 - 485
- 2013. Society of Petroleum Engineers
- 1.8 Formation Damage, 5.10.1 CO2 Capture and Sequestration, 1.6.9 Coring, Fishing, 5.4 Enhanced Recovery
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Carbon dioxide (CO2) injection in carbonate formations causes a reduction in the well injectivity caused by precipitation of the reaction products between CO2, rock, and brine. The precipitated material includes sulfate and carbonate scales. The homogeneity of the carbonate rock, in terms of mineralogy and rock structure, is an important factor that affects the behavior of permeability changes during CO2 injection.
Limestone rocks that were tested in this study included homogeneous Pink Desert limestone and Austin chalk, which were mainly calcite; heterogeneous Silurian dolomite (composed of 98 wt% carbonate minerals and 2 wt% silicate minerals); and heterogeneous Indiana limestone, which was mainly calcite and had vugs.
Experiments were conducted to compare the permeability loss between these rocks during corefloods. CO2 was injected with the water-alternating-gas (WAG) technique. Different brines were examined, including sulfate-bearing seawater and no-sulfate seawater. The experiments were run at a backpressure of 1,300 psi, a temperature of 200°F, and an injection rate of 5 cm3/min. A compositional-simulator tool (CMG-GEM) was used to predict the Carman-Kozeny and power-law exponents on the basis of the experimental results.
More damage was observed for heterogeneous rocks compared with the homogeneous cores--the source of damage to permeability for high-permeability cores is the precipitation of reaction products--but for low-permeability cores, capillary forces between CO2 and brine increase the severity of formation damage. The form of the precipitated material changes depending on the core mineralogy and permeability. The simulation study showed that for the cores tested in this study, power-law exponent and Carman-Kozeny exponent between 5 and 6 can be used for the homogeneous carbonate rock to estimate the change in permeability depending on change in porosity, whereas a larger exponent is needed for heterogeneous cores.
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