ALBERT

Description: CO2 geological storage is one of the most promising technologies for reducing atmospheric emissions of greenhouse gas. The results obtained by a new approach applied to a CO2 storage geochemical model at the Weyburn (Saskatchewan, Canada) test site, where since September 2000 5000 t/day of supercritical CO2 are injected, are presented and discussed. The Weyburn oil-pull is recovered from the Midale Beds (at the depth of 1300-1500 m), consisting of Mississippian shallow marine carbonate-evaporites, that is classically subdivided into two units: i) the dolomitic “Marly” and ii) the underlying calcitic “Vuggy”, sealed by an anhydrite cap-rock. Assumptions and gap-acceptance are commonly made to reconstruct the reservoir conditions (pressure, pH, chemistry, and mineral assemblage), although most geochemical parameters of deep fluids are to be computed by a posteriori procedure due to the sampling collection at the well-head, i.e. using depressurised aliquots. On the basis of the available data at Weyburn, such as: a) bulk mineralogy of the Marly and Vuggy reservoirs; b) mean gas-cap composition at the well-heads and c) selected pre- and post-CO2 injection water samples, we have rebuilt the in-situ reservoir chemical composition and the kinetic evolution after CO2 injection. The geochemical modelling has been performed by using the code PRHEEQC (V2.11) software package; the in-situ reservoir composition was calculated by the chemical equilibrium among the various phases at reservoir temperature (62 °C) and pressure (150 bars) via thermodynamic corrections to the code default database. Furthermore, the “primitive” chemical composition of the pre-injection Marly and Vuggy liquid phase was derived by assuming the equilibrium conditions for the mineral assemblage with respect to a Na-Cl (Cl/Na=1.2) water. A comparison between the chemical composition of the “primitive brine” and that measured before the CO2 injection shown an agreement within 10 % for most analytical species. The second step has been that to compute the geochemical impact of three years of CO2 injection (September 2000-2003) by kinetically controlled reactions. In order to statically validated our geochemical model we have compared the computed and measured data by using the Median Test. The results show that the proposed geochemical model is able to reliably describe (within 5% error) the behaviour of pH, HCO3, Cl, Li, Na, Sr, Si and HS+SO4, with the exception of K, Ca and Mg. Finally, the kinetic evolution of the CO2-rich Weyburn brines interacting with the host-rock minerals, performed over 100 years after injection, has also been modelled. The solubility trapping (short/medium-term sequestration) gives an amount of dissolved CO2 of 0.761moles/L and 0.752 moles/L for Marly and Vuggy units, respectively, whereas the mineral trapping, calculated as difference between dissolved (calcite and dolomite) and precipitated carbonate (dawsonite) minerals, is -0.019 and -5.69x10-5 moles/L for Marly and Vuggy units, respectively. The experimental data-set available and the geochemical modelling intrinsic limitation introduce a large uncertainty in the modelled results and in order to evaluate the dependence of the results from the modeling code, a different thermodynamic approach, such as the modelling software GEM (Gibbs Energy Minimization approach), is required.

Description: Published

Description: Vienna, Austria

Description: 2.4. TTC - Laboratori di geochimica dei fluidi

Description: open

Description: In this work we present a new approach to model the effects of CO2 sequestration that has been tested in the Weyburn test site. The Weyburn oil-pull is recovered from Midale Beds (at 1300-1500 m depth). This formation consists of Mississippian shallow marine evaporitic carbonates that can be divided into two units: i) the dolomitic “Marly” and ii) the underlying calcitic “Vuggy”, sealed by an anhydrite cap-rock. Presently, about 3 billions mc of supercritical CO2 have been injected into the “Phase A1” injection area. The aim of our model is to reconstruct i) the chemical composition of the reservoir; ii) the geochemical evolution of the reservoir with time as CO2 is injected and ii) the boundary conditions. The geochemical modeling has been performed by using the code PRHEEQC (V2.11) software package. The “primitive brine” composition was calculated on the basis of the chemical equilibrium among the various phases, assuming reservoir equilibrium conditions for the mineral assemblage with respect to a Na-Cl (Cl/Na=1.2) water, at T of 62 °C and P of 150 bars via thermodynamic corrections to the code database. A comparison between the chemical composition of the “primitive brine” and that analytically determined on water samples collected before the CO2 injection shows an agreement within 10 %. Furthermore, we computed the kinetic evolution of the reservoir by considering the local equilibrium and the kinetically controlled reactions taking into account the CO2 injected during four years of monitoring. The calculated chemical composition after the CO2 injection is consistent with the analytical data of samples collected in 2004, with the exception of calcium and magnesium contents. The results of the Inverse Modeling Simulation (IMS) suggest that the measured Ca and Mg contents are higher than those calculated from the solubility of calcite and dolomite, likely due to the complexation effect of carboxilic acid. The results of the application of the kinetic model lasting 100 years indicate that dissolution of K-feldspar and kaolinite and precipitation of chalcedony affect the Marly and Vuggy units. Furthermore, calcite tends to be dissolved as CO2 solubilises in the reservoir, whereas dolomite dissolution can be considered negligible. Dawsonite precipitates as secondary mineral. The CO2 content from solubility trapping (short/medium-term sequestration) calculation is ~0.8 mol/L.

Description: Published

Description: Pechino, Cina

Description: 2.4. TTC - Laboratori di geochimica dei fluidi

Description: open

Description: CO2 Capture & Storage (CCS) is presently one of the most promising technologies for reducing anthropogenic emissions of CO2. The numerical modeling procedures of geochemical processes are one of the few approaches for investigating the short-long-term consequences of CO2 storage into a deep reservoir. We present the results of a new approach for the reconstruction of thermo-physical properties of an off-shore deep well (situated in the medium Tyrrhenian Sea, only 5 miles from the coast, in the frame of a distensive and relatively high heat flux regime as a whole,with good outcrops, on-shore, of its stratigraphy includes six Late Triassic-Early Jurassic carbonatic formations at the depth of 2500-3700 m b.s.l). We used the well-log coupled with temperature profile and new mineralogical analyses of the outcrops geological formations, being the original core data lacking. This kind of procedure is new as a whole, and it is useful to create background petro-physical data, for reservoir engineering numerical simulations both of mass-transport and geochemical as well as geo-mechanical, in order to asses its general properties, without re-opening the well itself for industrial use, such as CO2 geological storage. The profile of thermal capacity and conductivity, as well as porosity and permeability resulted very well constrained and detailed for further numerical simulation uses. Porosity is a very important parameter for reservoir engineering, mainly for numerical simulations including geochemical modelling, being strongly necessary for CO2 geological storage feasibility studies, because it allows to compute: i) the reservoir storage capacity for each trapping mechanisms (some algorithms are discussed in the presentation) and ii) the water/rock ratio (one of the input parameter requested by the geochemical software codes). A common problem, working with closed wells with, available the well-log report only, is to obtain data on the thermo-physical properties of the rock. Usually the available well-log report the temperature profile measured during drilling, the mud-loss and some other information on water and gas phase presence. In this work we present a procedure that allow to estimate porosity and permeability of the rock formation from the well-log data joint with a rough mineralogical analyses of the corresponding geological formations outcrop with the use of a boundary condition such as shallow heat flow measurements; a similar approach were presented from some authors that dealt with similar problems e.g. Singh V.K., (2007). The analyses of the rock samples proceed by using i) petro-graphical analyses; ii) calcimetry with Dietrich-Fruhling apparatus in order to analyse the carbonate content of each sample; iii) XRD Rietveld analyses in order to quantify the major mineralogy of each sample and to apply the dolomite correction to the results of calcimetry determination. Rietveld quantification procedure were performed by using Maud v 2.2.; iv) SEM analyses have been accomplished later in details. Successively, hints about the subsequent geochemical modelling approach are presented. Chemical composition of the aquifer pore water has been has been inferred by batch modeling assuming thermodynamic equilibrium between minerals and a NaCl equivalent brine at reservoir conditions (up to 70 °C and 200 bar). Numerical simulations has been carried out by the PRHEEQC (V2.11) Software Package via corrections to the code default thermodynamic to obtain a more realistic modeling.

Description: Published

Description: La Habana, Cuba

Description: 2.4. TTC - Laboratori di geochimica dei fluidi

Description: open