Hydrogeochemical modelling of CO₂ equilibria and mass transfer induced by organic–inorganic interactions in siliciclastic petroleum reservoirs

Abstract

Different feldspar types control complex hydrogeochemical processes in hydrocarbon-bearing siliciclastic reservoirs, which have undergone different degrees of degradation. To test such processes generically, carbon dioxide equilibria and mass transfers induced by organic-inorganic interactions have been modelled for different hydrogeochemical scenarios. The approach is based on and compared with data from the Norwegian continental shelf (Smith & Ehrenberg 1989) and assumes local thermodynamic equilibrium among solids and fluids. Equilibrating mineral assemblages (different feldspar types, quartz, kaolinite, calcite) are based on the primary reservoir composition. Equilibration and coupled mass transfer were triggered by the addition and reaction of different amounts of CO 2 , CH 4 and H 2 (plus acetic acid) at temperatures between 50 and 95°C (323 and 368 K). These components occur in oil fields as products of anaerobic bacterial degradation, hydrolytic disproportionation of hydrocarbons and ⁄ or thermal maturation of kerogen. We apply two different computer codes and two different thermodynamic data bases to calculate the results. Reaction of 0.32-0.6 mol CO 2 , 0.16-0.3 mol CH 4 and 0.8-1.5 mol H 2 with K-feldspar, quartz, kaolinite and calcite in 1 l of pore water results in modelled values of 0.3-2.3 mol% CO 2 in a multicomponent gas phase that resembles measured data (0.2-1.5 mol%). Similar CO 2 contents result from acetic acid addition (CO 2 , CH 4 , H 2 + 0.016 mol CH 3 COOH). Equilibration with albite or anorthite reduces the release of CO 2 into the multicomponent gas phase dramatically, by 1 or 4 orders of magnitude compared with the equilibration with K-feldspar. Minor differences in the modelled CO 2 content (0.1-0.2 mol%) result from calculations with different computer codes if the same thermodynamic data base is applied. Relevant differences (up to 1.9 mol% CO 2 ) result from calculations using different thermodynamic data bases.

The biogenic methane potential of European gas shale analogues: Results from incubation experiments and thermodynamic modelling

“…In our modelling scenario we are considering Posidonia Shale at shallow depth ranging from 500 m depth to the surface. The approach relies on chemical considerations about aqueous oil degradation published by Seewald (2003), it is based on hydrogeochemical data published by Martini et al (1998), and refers to mass balance calculations by McIntosh et al (2002) and a modelling concept by van Berk et al (2009).…”

Creation of pre-oil-charging porosity by migration of source-rock-derived corrosive fluids through carbonate reservoirs: one-dimensional reactive mass transport modelling

“…in the Gullfaks oil field: Smith & Ehrenberg 1989;Ehrenberg & Jakobsen 2001). Hydrogeochemical modelling by van Berk et al (2009van Berk et al ( , 2013 quantitatively reproduced this proven alteration of mineral assemblages in the Gullfaks field, which was driven by the products of oil degradation (CO 2 , CH 3 COOH and CH 4 ).…”

“…Consequently, even higher concentrations could be expected in ACF-bearing brines that are generated by kerogen maturation and subsequent oil degradation already in the source rock. In summary, organic-inorganic interactions are driven by the products of kerogen maturation and subsequent oil degradation already in siliciclastic source and reservoir rocks (Smith & Ehrenberg 1989;Ehrenberg & Jakobsen 2001;van Berk et al 2009van Berk et al , 2013. Such organic-inorganic interactions represent the inevitable consequences of chemical thermodynamics of such systems under elevated temperature and pressure conditions; the involved hydrogeochemical reactions tend to reach (metastable) equilibrium conditions (Helgeson et al 1993).…”

“…Therefore, and for the sake of simplicity, kerogen maturation is simulated by adding its products CH 4 , CO 2 , H 2 and acetic acid into the batch modelling reactor. In this study, their initial relative production ratios are set to 1.9 (for CO 2 ), 0.9 (for CH 4 ), 5.0 (for H 2 ) and 0.1 (for acetic acid : Seewald 2003;Helgeson et al 2009;van Berk et al 2009); molecular hydrogen and carbon dioxide will subsequently react to form additional methane. The initial ratio of CO 2 to acetic acid follows the findings of Barth & Bjørlykke (1993).…”

Hydrogeochemical modelling of corrosion effects and barite scaling in deep geothermal wells of the North German Basin using PHREEQC and PHAST

“…Hydrogeochemical modelling is a helpful tool for reproducing and predicting natural hydrogeochemical and technically induced processes (e.g., corrosion, scale formation, outgassing) that occur in deep aquifers, oil fields, CO 2 sequestration systems, and geothermal energy production systems (e.g., Yuan and Todd, 1991;Yuan et al, 1994;Thomas, 1994;van Berk et al, 2009;Hellevang et al, 2011).…”