Solid amine sorbents were prepared using mixtures of linear and branched primary, secondary, and tertiary amines. These amines were immobilized within polystyrene (PS)-, silicon dioxide (SiO 2 )-, or polymethylmethacrylate (PMMA)-based substrates at various weight ratios. Testing was conducted in various reactor systems, where the reactive water required for the capture of carbon dioxide (CO 2 ) was tracked during the adsorption/desorption cycles by mass spectrometer gas analysis. The water management for these sorbents was quantified and used to assess the technical feasibility of the operating conditions for the capture of CO 2 from simulated flue gas streams. In addition, the heats of reaction and performance capture loading capacities of these sorbents were also determined by differential scanning calorimetry (DSC) and thermogravimetric analyses (TGAs), respectively, in both dry and humidified CO 2 gas streams. The regenerable solid amine sorbents investigated in this study exhibit acceptable CO 2 -capture loading capacities of 2.5-3.5 mol of CO 2 /kg of sorbent by TGA and a laboratory-scale fixed-bed reactor. These sorbents were stable over the adsorption/desorption temperature range of 25-105 °C for 10 cyclic tests. According to the DSC analysis, the heat of reaction generated by these sorbents was in the range of 400-600 Btu/lb. CO 2 , which will require a reactor with heat management capabilities.

a b s t r a c tLong term containment of stored CO 2 in deep geological reservoirs will depend on the performance of the caprock to prevent the buoyant CO 2 from escaping to shallow drinking water aquifers or the ground surface. Here we report new laboratory experiments on CO 2 -brine-caprock interactions and a review of the relevant literature.The Eau Claire Formation is the caprock overlying the Mount Simon sandstone formation, one of the target geological CO 2 storage reservoirs in the Midwest USA region. Batch experiments of Eau Claire shale dissolution in brine were conducted at 200• C and 300 bars to test the extent of fluid-rock reactions. Scanning electron microscopy (SEM) and X-ray diffraction (XRD) analysis indicate minor dissolution of K-feldspar and anhydrite, and precipitation of pore-filling and pore-bridging illite and/or smectite, and siderite in the vicinity of pyrite.We also reviewed relevant reactivity experiments, modeling work, and field observations in the literature in an attempt to help define the framework for future studies on the geochemical systems of the caprock overlain on geological CO 2 storage formations. Reactivity of the caprock is generally shown to be low and limited to the vicinity of the CO 2 -caprock interface, and is related to the original caprock mineralogical and petrophysical properties. Stable isotope studies indicate that CO 2 exists in both free phase and dissolved phase within the caprock. Carbonate and feldspar dissolution is reported in most studies, along with clay and secondary carbonate precipitation. Currently, research is mainly focused on the micro-fracture scale geochemistry of the shaly caprock. More attention is required on the potential pore scale reactions that may become significant given the long time scale associated with geological carbon storage.

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CO2 solubility data in the natural formation brine, synthetic formation brine, and synthetic NaCl+CaCl2 brine were collected at the pressures from 100 to 200 bar, temperatures from 323 to 423 K. Experimental results demonstrate that the CO2 solubility in the synthetic formation brines can be reliably represented by that in the synthetic NaCl+CaCl2 brines. We extended our previously developed model (PSUCO2) to calculate CO2 solubility in aqueous mixed-salt solution by using the additivity rule of the Setschenow coefficients of the individual ions (Na(+), Ca(2+), Mg(2+), K(+), Cl(-), and SO4(2-)). Comparisons with previously published models against the experimental data reveal a clear improvement of the proposed PSUCO2 model. Additionally, the path of the maximum gradient of the CO2 solubility contours divides the P-T diagram into two distinct regions: in Region I, the CO2 solubility in the aqueous phase decreases monotonically in response to increased temperature; in region II, the behavior of the CO2 solubility is the opposite of that in Region I as the temperature increases.

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