ALBERT

Description: CO2 Capture & Storage (CCS) is presently one of the most promising technologies for reducing anthropogenic emissions of CO2 . Among the several potential geologi- cal CO2 storage sites, e.g. depleted oil and gas field, unexploitable coal beds, saline aquifers, the latter are estimated to have the highest potential capacity (350-1000 Gt CO2 ) and, being relatively common worldwide, a higher probability to be located close to major CO2 anthropogenic sources. In these sites CO2 can safely be retained at depth for long times, as follows: a) physical trapping into geologic structures; b) hy- drodynamic trapping where CO2(aq) slowly migrates in an aquifer, c) solubility trap- ping after the dissolution of CO2(aq) and d) mineral trapping as secondary carbon- ates precipitate. Despite the potential advantages of CO2 geo-sequestration, risks of CO2 leakage from the reservoir have to be carefully evaluated by both monitoring techniques and numerical modeling used in “CO2 analogues”, although seepage from saline aquifers is unlikely to be occurring. The fate of CO2 once injected into a saline aquifer can be predicted by means of numerical modelling procedures of geochemical processes, these theoretical calculations being one of the few approaches for inves- tigating the short-long-term consequences of CO2 storage. This study is focused on some Italian deep-seated (〉800 m) saline aquifers by assessing solubility and min- eral trapping potentiality as strategic need for some feasibility studies that are about to be started in Italy. Preliminary results obtained by numerical simulations of a geo- chemical modeling applied to an off-shore Italian carbonatic saline aquifer potential suitable to geological CO2 storage are here presented and discussed. Deep well data, still covered by industrial confidentiality, show that the saline aquifer, includes six Late Triassic-Early Jurassic carbonatic formations at the depth of 2500-3700 m b.s.l. These formations, belonging to Tuscan Nappe, consist of porous limestones (mainly calcite) and marly limestones sealed, on the top, by an effective and thick cap-rock (around 2500 m) of clay flysch belonging to the Liguride Units. The evaluation of the potential geochemical impact of CO2 storage and the quantification of water-gas-rock reactions (solubility and mineral trapping) of injection reservoir have been performed by the PRHEEQC (V2.11) Software Package via corrections to the code default ther- modynamic database to obtain a more realistic modelling. The main modifications to the Software Package are, as follows: i) addition of new solid phases, ii) variation of the CO2 supercritical fugacity and solubility under reservoir conditions, iii) addi- tion of kinetic rate equations of several minerals and iv) calculation of reaction sur- face area. Available site-specific data include only basic physical parameters such as temperature, pressure, and salinity of the formation waters. Rocks sampling of each considered formation in the contiguous in-shore zones was carried out. Mineralogy was determined by X-Ray diffraction analysis and Scanning Electronic Microscopy on thin sections. As chemical composition of the aquifer pore water is unknown, this has been inferred by batch modeling assuming thermodynamic equilibrium between minerals and a NaCl equivalent brine at reservoir conditions (up to 135 ̊C and 251 atm). Kinetic modelling was carried out for isothermal conditions (135 ̊C), under a CO2 injection constant pressure of 251 atm, between: a) bulk mineralogy of the six formations constituting the aquifer, and b) pre-CO2 injection water. The kinetic evolu- tion of the CO2 -rich brines interacting with the host-rock minerals performed over 100 years after injection suggests that solubility trapping is prevailing in this early stage of CO2 injection. Further and detailed multidisciplinary studies on rock properties, geochemical and micro seismic monitoring and 3D reservoir simulation are necessary to better characterize the potential storage site and asses the CO2 storage capacity.

Description: Published

Description: Vienna (Austria)

Description: 2.4. TTC - Laboratori di geochimica dei fluidi

Description: open

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: Geological storage is presently one of the most promising options for reducing anthropogenic emissions of CO2. Among the several projects investigating the fate of CO2 stored at depth, the EnCana's CO2 injection EOR (Enhancing Oil Recovery) project at Weyburn (Saskatchewan, Canada) is the most important oil production development that hosts an international monitoring project. In the Weyburn EOR Project CO2 is used to increase recovery of heavy oil from the Midale Beds, a Mississippian reservoir consisting of shallow marine carbonate, where about 3 billions standard m3 of supercritical CO2 have been injected since 2000 with an injection rate of 5000 ton/day. In this work the available dataset (bulk mineralogy of the reservoir, gas-cap composition and selected preand post-CO2 injection water samples) provided by the International Energy Agency Weyburn CO2 Monitoring & Storage Project has been used in order to: i) reconstruct the pre-injection reservoir chemical composition (including pH and the boundary conditions at 62 °C and 15 MPa); ii) assess the evolution of the reservoir subjected to CO2 injection and predict dissolution/precipitation processes of the Weyburn brines over 100 years after injection; iii) validate the short-term (September 2000–2003) evolution of the in situ reservoir fluids due to the CO2 injection, by comparing the surface analytical data with the composition of the computed depressurized brines. To achieve these goals the PRHEEQC (V2.14) Software Package was used with both modified thermodynamic database and correction for supercritical CO2 fugacity. The oil–gas–water interaction and the non-ideality of the gas phase (with exception of CO2) were not considered in the numerical simulations. Despite intrinsic limitations and uncertainties of geochemical modeling, the main results can be summarized, as follows: 1) the calculated pre-injection chemical composition of the Midale Beds brine is consistent with the analytical data of the waters collected in 2000 (baseline survey), 2) the main reservoir reactions (CO2 and carbonate dissolution) take place within the first year of simulation, 3) the temporal evolution of the chemical features of the fluids in the Weyburn reservoir suggests that CO2 can safely be stored by solubility (as CO2(aq)) and mineral trapping (via dawsonite precipitation). The short-term validation performed by calculating chemical composition of the reservoir fluids (corrected for surface conditions) after the simulation of 3 years of CO2 injection is consistent (error ≤5%) with the analytical data of the wellhead water samples collected in 2003, with the exception of Ca and Mg (error N90%), likely due to complexation effect of carboxilic acid.

Description: Published

Description: 181-197

Description: 2.4. TTC - Laboratori di geochimica dei fluidi

Description: JCR Journal

Description: partially_open