Abstract
Carbon dioxide sequestration in deep saline aquifers is being considered as one of the more important geological sequestration types due to the potentially large storage capacity when compared to some other geological sequestration reservoirs. CO2 will react with formation rock when injected in dolomite formations, due to the rock dissolution and precipitation of reaction products permeability may be changed. Several parameters affect these interactions including pressure, temperature, brine composition, CO2 injection rate, and overall injection scheme.
This paper addresses the effect of the temperature, injection rate, brine composition, and injection scheme on the damage generated in the formation due to CO2 injection. A core flood study was conducted using dolomite cores. CO2 was injected under supercritical conditions at a pressure of 1,300 psi, and at temperatures ranging from 70 to 200°F, and injection rates of 2.0, 3.5 and 5.0 cm3/min. Core effluent samples were collected and the concentrations of calcium and magnesium ions were measured. Core permeabilities were measured before and after the experiment to evaluate the damage generated.
The results show that temperature, injection flow rate, and injection scheme don't have a clear impact on the core permeability, the main factor that affect the change in core permeability is the initial core permeability. The damage is mainly due to calcium carbonate precipitation, and the precipitation of the reaction products between silicate minerals that present naturally with dolomite and CO2.
Introduction
Dolomite rock is carbonate rock that contains more than 50 wt% dolomite mineral (CaMg (CO3)2), calcite mineral (CaCO3) and anhydrite from the remaining percent, non-carbonate phases may also present (Warren 2000). Dolomite formations are usually heterogeneous, different kind of permeability and porosity can be identified in the dolomite includes: (1) intercrystal, (2) vug, (3) moldic, (4) intracrystal, (5) fracture, and (6) intraparticle porosity (Mathis and Sears 1984). Reduction of well injectivity ranged between 40% and 50% is usually noted during WAG CO2 injection in dolomite formations (Grigg and Svec 2003).
