Magnesite is the most desirable phase within the magnesium carbonate family for carbon storage for a number of reasons: magnesium efficiency, omission of additional crystal waters and thermodynamic stability. For large-scale carbonation to be a viable industrial process, magnesite precipitation must be made to occur rapidly and reliably. Unfortunately, the formation of metastable hydrated magnesium carbonate phases (e.g. MgCO3·3H2O and Mg5(CO3)4(OH)2·4H2O) interferes with the production of anhydrous magnesite under a variety of reaction conditions because magnesite crystals are slower to both nucleate and grow compared to the hydrated carbonate phases. Furthermore, the reaction conditions required for the formation of each magnesium carbonate phases have not been well understood with conflicting literature data. In this study, the effects of both magnesite (MgCO3) and inert (Al2O3) seed particles on the precipitation of magnesium carbonates from a Mg(OH)2 slurry were explored. It was interesting that MgCO3 seeding was shown to accelerate anhydrous magnesite growth at temperatures (80-150 °C), where it would normally not form in short time scale. Since the specific surface areas of MgCO3 and Al2O3 seeding particles were similar, this phenomenon was due to the difference in the surface chemistry of two seeding particles. By providing a template with similar chemistry for the growth of magnesite, the precipitation of anhydrous magnesite was demonstrated. The effect of temperature on seeded carbonation was also investigated. A comparison with published MgCO3 precipitation rate laws indicated that the precipitation of magnesite was limited by either CO2 adsorption from the gas phase or the dissolution rate of Mg(OH)2.

This reference is for an abstract only. A full paper was not submitted for this conference. Abstract The B-field, located on Central Java, Indonesia, is a steep flanked carbonate structure of Oligo-Miocene age with approximately 1,000 m of relief relative to the surrounding platform. The extensive formation evaluation program for large carbonate oil fields shows that geologic features such as karst and fractures can be very effective to enhance productivity and thus production but they can also provide detrimental connection between the producing oil zone and the overlying gas and underlying water zones. Characterizing this type of system is a huge challenge for reservoir simulators. This paper will discuss the results of a modeling study in characterizing the excess permeability, quantifying its impact on production, and representing its effect in simulation models. In this study, the karst features was modeled with an analogue-based dendritic pattern and the size and permeability of karst region was calibrated with production data. To model fracture excess permeability, a DFN (discrete fracture network) geologic model was built, upon which a DP (dual-porosity) simulation model was constructed. A series of DP sensitivity cases was designed and simulated to evaluate the range of production impact from fractures. Although DP model is considered the most rigorous modeling technique available for fractures, the challenges are that it normally requires long simulation time and more importantly it needs significant amount of data for model verification and calibration. From the results of reservoir characterization and production comparison, it was demonstrated that a conventional single porosity model with modifications that mimic fracture connections is appropriate for the B-field. Two modifications adopted in this study were pseudo wells and permeability enhancement in the fracture-prone area. Pseudo wells, shutting in at surface but permitting cross-flow in designated reservoir intervals, were implemented to capture premature gas / water breakthrough phenomena that often observed in naturally fractured reservoirs. The permeability enhancement was intended to represent the positive impact of fractures on production by accelerating fluid movement through tighter reservoir. The results of DP model were used as a bench mark to determine the extent of permeability enhancement.

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