Experimental and Numerical Modeling of Direct Injection of CO2 Into Carbonate Formations

Sequestration of carbon dioxide in geological formations is an alternative way to manage the carbon emitted by combustion of fossil fuels. Results of an experimental and numerical modeling study aiming to investigate the important aspects of injection of CO2 in carbonate formations are presented. Different from sandstones, in carbonates surface reaction rates are very high, so mass transfer often limits the overall reaction rate, leading to highly non-uniform dissolution patterns. Often, large flow channels called wormholes are created. A distinctive feature of carbonate reservoirs is the porosity/permeability mismatch. Experiments were conducted to investigate the effect of CO2 injection rate, formation temperature, and brine salinity on chemical kinetics and thus permeability and porosity alteration trends through injection of gaseous CO2 into carbonate formations. Experiments were designed to model fast near well bore flow (in horizontal direction) and slow reservoir flows (in vertical direction). It was observed that small changes in porosity may lead to dramatic changes in permeability (presence of preferential flow paths, worm holes). Results of CT-monitored experiments were then used to calibrate a geochemical numerical model where a multi-phase, non-isothermal commercial simulator in which dissolution and deposition of calcite were considered by means of chemical reactions was used. It was observed that solubility and hydrodynamic storage of CO2 was larger compared to mineral trapping. Chemical kinetics leads to dissolution of carbonate and later precipitation of bicarbonate particles. Numerical models together with experimental results proposed that time required for chemical reactions among formation fluid (brine), rock (carbonate) and CO2 was small, that change in effective permeability and absolute porosity were observed within small periods of time. The calibrated model was then used to analyze field scale injections and to model the CO2 sequestration capacity of a hypothetical carbonate aquifer formation. Copyright 2006, Society of Petroleum Engineers

Experimental and Numerical Investigation of Carbon Sequestration in Saline Aquifers

Because of the global warming threat posed by greenhouse gases, mainly by CO2, some strategies were proposed. Along those, disposal and long term storage, of greenhouse gases is important for reducing global warming. Aquifers represent the most widely available and the second largest, naturally occurring potential store for CO2. Although there are a number of mathematical modeling studies related to injection of CO2 in deep saline aquifers, experimental studies are limited and most studies focus to sandstone aquifers as opposed to carbonate ones. Potential CO2 sequestration capacity of a carbonate aquifer formation located in S. East Turkey was evaluated using computerized tomography (CT) monitored experiments. Porosity changes along the core plugs, drilled from Midyat aquifer formation located in south-east Turkey, and the corresponding permeability changes are reported for differing CO2 injection rates, pressures and temperatures with differing salt concentrations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. It was observed that permeability initially increased and decreased for slow injection cases. As the salt concentration decreased the porosity and thus the permeability decrease was less pronounced. Orientation of the core plugs was observed to be influential in rock-fluid-carbon dioxide interactions. For vertically aligned cores high injection rates resulted in an increase then decrease of permeability. On the other hand horizontally aligned cores represented a decrease in permeability due to CaCO3 precipitation. It was observed that CO2 sequestration by solubility trapping is larger compared to mineral trapping. The results are discussed using a finite difference, non-isothermal compositional numerical simulator where solution and dissolution of carbonates via chemical reactions are considered. The calibrated model was then used to analyze field scale injections and to model the CO 2 sequestration capacity of a potential carbonate aquifer formation located in S. East Turkey

CO2 injection in carbonates

Started as an EOR technique to produce oil, injection of carbon dioxide which is essentially a greenhouse gas is becoming more and more important. Although there are a number of mathematical modeling studies, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments to characterize relevant chemical reactions associated with injection and storage of CO 2 in carbonate formations. Porosity changes along the core plugs and the corresponding permeability changes are reported for differing CO2 injection rates and with differing salt concentrations. CT monitored experiments are designed to model fast near wellbore flow and slow reservoir flows. It was observed that permeability initially increased and decreased for slow injection cases. As the salt concentration decreased the porosity and thus the permeability decrease was less pronounced. The experiments were modeled using a commercial simulator where solution and deposition of calcite were considered by means of chemical reactions. The calibrated model was then used to analyze field scale injections. It was observed that solubility storage of CO2 is larger compared to mineral trapping

Modeling of underground gas storage in a depleted gas field

It is possible to predict the behavior of fluids in permeable and porous medium under different operating conditions by using reservoir models. Since geological data and reservoir properties can be defined most accurately by reservoir models, it has been accepted as a reliable prediction tool among reservoir engineers. In this study, a gas reservoir has been modeled with IMEX Module of CMG Reservoir Simulator. Rock properties, gas composition and certain production data were entered to the model as input data and the measured field data were matched with simulated ones. After the 5 year depletion of the reservoir by vertical wells, the average reservoir pressure dropped from an original reservoir pressure of 2150 psi to 1200 psi. This depleted reservoir was planned to be used for gas storage purposes. The remaining gas was used as cushion gas during the conversion of this reservoir to an underground gas storage field. Afterwards, horizontal wells were defined in the model and certain production/injection scenarios were simulated for the gas storage operation