One of the most common production problems in geothermal fields is calcite (calcium carbonate) scale deposition. Calcite formed in the wellbore and in near wellbore region significantly decreases the output of a production well. Calcite scaling is experienced in almost all the geothermal fields around the world. Calcite may form from hydrolysis, boiling and heating of cooler peripheral fluids.

Although there are plenty of mathematical modeling studies that try to explain the rock-fluid-carbon dioxide reaction kinetics, experimental studies are limited in number. This study presents results of computerized tomography (CT) monitored laboratory experiments where CO2 was injected in carbonate cores at three different temperatures. Porosity changes along the core plugs and the corresponding permeability changes were reported for differing temperatures. CT monitored experiments were designed to model fast near well bore flow and slow reservoir flows. It was observed that permeability initially increased and then decreased for slow injection cases. As the salt concentration decreased, the porosity and thus the permeability decrease was less pronounced.

Furthermore, rock-fluid-carbon dioxide interactions were seen to be affected by the orientation of the core plugs used in experiments. In vertical experiments, it is observed that permeability increased at the beginning, and then decreased for later times. On the other hand, for horizontal core plugs, permeability change was observed to be completely in reverse order. Because of the preferential paths, sometimes permeability alteration trend did not match with the porosity alteration trend. Experiments showed that solubility of CO2 is larger compared to mineral trapping and temperature have great influence on chemical kinetics, thus on permeability change.

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