Yunjiao Fu

Controls on CO2 fate and behavior in the Gullfaks oil field (Norway): How hydrogeochemical modeling can help decipher organic-inorganic interactions

Oil degradation in the Gullfaks field led to hydrogeochemical processes that caused high CO2 partial pressure and a massive release of sodium into the formation water. Hydrogeochemical modeling of the inorganic equilibrium reactions of water-rock-gas interactions allows us to quantitatively analyze the pathways and consequences of these complex interconnected reactions. This approach considers interactions among mineral assemblages (anorthite, albite, K-feldspar, quartz, kaolinite, goethite, calcite, dolomite, siderite, dawsonite, and nahcolite), various aqueous solutions, and a multicomponent fixed-pressure gas phase (CO2, CH4, and H2) at 4496-psi (31-mPa) reservoir pressure. The modeling concept is based on the anoxic degradation of crude oil (irreversible conversion of n-alkanes to CO2, CH4, H2, and acetic acid) at oil-water contacts. These water-soluble degradation products are the driving forces for inorganic reactions among mineral assemblages, components dissolved in the formation water, and a coexisting gas at equilibrium conditions. The modeling results quantitatively reproduce the proven alteration of mineral assemblages in the reservoir triggered by oil degradation, showing (1) nearly complete dissolution of plagioclase; (2) stability of K-feldspar; (3) massive precipitation of kaolinite and, to a lesser degree, of Ca-Mg-Fe carbonate; and (4) observed uncommonly high CO2 partial pressure (61 psi [0.42 mPa] at maximum). The evolving composition of coexisting formation water is strongly influenced by the uptake of carbonate carbon from oil degradation and sodium released from dissolving albitic plagioclase. This causes supersaturation with regard to thermodynamically stable dawsonite. The modeling results also indicate that nahcolite may form as a CO2-sequestering sodium carbonate instead of dawsonite, likely controlling CO2 partial pressure.

Hydrogen sulfide formation, fate, and behavior in anhydrite-sealed carbonate gas reservoirs: A three-dimensional reactive mass transport modeling approach

A novel hydrogeochemical modeling approach is developed to unravel thermochemical sulfate reduction (TSR) in hydrocarbon reservoirs. Our numerical model couples a web of interconnected hydrogeochemical reactions to three-dimensional (3-D) and reservoir-wide diffusive mass transport. Our modeling approach simulates a semigeneric gas reservoir sealed by anhydrite. The calculated diagenetic processes fit the observations in reservoirs affected by TSR: formation of water, precipitation of calcite, metal (di-)sulfides, and elemental sulfur as replacements of dissolved anhydrite at the expense of CH4(g), as well as formation of hydrogen sulfide (H2S). By varying input parameters, the crucial factors controlling TSR have been identified. Our results highlight that reservoir-wide diffusive mass transport is one prerequisite for TSR. An increase in the rate constant of abiotic sulfate reduction (ASR) and in diffusive mass fluxes, as well as lack of precursor minerals for metal (di-)sulfide precipitation, can increase the souring intensity and accelerate H2S outgassing. In contrast, precipitation of elemental sulfur, which is stable according to the chemical thermodynamics, weakens H2S formation. Our modeling shows that TSR is complex and cannot be represented by the single reaction ASR and by simple correlations between the rate constant of ASR and the H2S gas content. The application of 3-D reactive transport modeling presented here, despite its semigeneric nature, provides a good example of how such an approach can be used ahead of drilling. Our modeling helps to investigate TSR in time and space to quantify the mass conversion of all reactants involved within this web and to predict the souring level.

Redox Roll-Front Mobilization of Geogenic Uranium by Nitrate Input into Aquifers: Risks for Groundwater Resources.

Redox conditions are seen as the key to controlling aqueous uranium concentrations (cU(aq)). Groundwater data collected by a state-wide groundwater quality monitoring study in Mecklenburg-Western Pomerania (Germany) reveal peak cU(aq) up to 75 μg L-1 but low background uranium concentrations (median cU(aq) < 0.5 μg L-1). To characterize the hydrogeochemical processes causing such groundwater contamination by peak cU(aq), we reanalyzed measured redox potentials and total concentrations of aqueous uranium, nitrate, and sulfate species in groundwater together with their distribution across the aquifer depth and performed semigeneric 2D reactive mass transport modeling which is based on chemical thermodynamics. The combined interpretation of modeling results and measured data reveals that high cU(aq) and its depth-specific distribution depending on redox conditions is a result of a nitrate-triggered roll-front mobilization of geogenic uranium in the studied aquifers which are unaffected by nuclear activities. The modeling results show that groundwater recharge containing (fertilizer-derived) nitrate drives the redox shift from originally reducing toward oxidizing environments, when nitrate input has consumed the reducing capacity of the aquifers, which is present as pyrite, degradable organic carbon, and geogenic U(IV) minerals. This redox shift controls the uranium roll-front mobilization and results in high cU(aq) within the redoxcline. Moreover, the modeling results indicate that peak cU(aq) occurring at this redox front increase along with the temporal progress of such redox conversion within the aquifer.

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

Locally increased porosity of carbonate reservoir rocks may result from acidic fluids that migrated as a pre-oil phase through the reservoir. Here, hydrogeochemical modelling, which is based on the principles of chemical equilibrium thermodynamics, is performed to test such a hypothetical concept. Despite the generic nature of the model, the modelling results give basic and quantitative insights into the mechanisms of calcite dissolution in carbonate reservoirs induced by migrating acidic and corrosive aqueous fluids. The hydrogeochemical batch modelling considers pre-oil-phase aqueous fluids that form by kerogen maturation in siliciclastic source rocks underlying the carbonate reservoir rocks. Although saturated with respect to calcite, migration of such fluids through the carbonate reservoir triggers continuous calcite dissolution along their migration path following a decreasing pressure and temperature regime. One-dimensional reactive transport modelling reveals that thermodynamically controlled chemical re-equilibration among pre-oil-phase fluids, calcite and CO2(g) is the driving force for continuous calcite dissolution along this migration path. This reflects the increasing solubility of calcite in the system ‘pre-oil-phase fluids/calcite/CO2(g)’ with decreasing pressure and temperature. In consequence, such fluids can preserve their calcite-corrosive character, if they are exposed to continuously decreasing pressure and temperature along their migration path through the reservoir. Supplementary material: The modelling input files to ensure retraceability of our modelling approach and its results are available at http://www.geolsoc.org.uk/SUP18802.

H2S Risk Assessment: Hydrogeochemical 3D Reactive Mass Transport Modeling and Mass Balancing of Acid Gas Generation and Distribution in Anhydrite-Sealed Oil and Gas Reservoirs

Acid gas generation by thermochemical sulfate reduction (TSR) evolves within a complex web of petroleum-water-rock-gas interactions in reservoirs under high temperature conditions of more than ca. 100°C. The interactions lead to the formation of toxic and corrosive hydrogen sulfide (free H2S gas and dissolved H2S). Such interactions are caused by the instability of hydrocarbons in the presence of water and a reactive reservoir rock matrix containing water-soluble anhydrite. The mass conversions of the inorganic water-rock-gas interactions which are triggered by the redox degradation of hydrocarbons establish a certain, thermodynamically defined state of chemical equilibrium. Any approach to geochemically model “acid gas generation” and “H2S-risk distribution” in petroleum systems should be based on a conceptual model that adequately reproduces the intimately interconnected and interdependent nature of all isochronous hydrogeochemical reactions, whether they are kinetically controlled or establish equilibrium species distributions. Such approaches rely (1) on the thermodynamical calculation of chemical equilibrium species distribution, (2) on the coupling of kinetically controlled oil degradation and sulfate reduction by oil-derived reductants to the equilibrium calculations, and (3) on the calculation of diffusive mass transport through the free pore water network and the irreducible water film. The key to model TSR, “acid gas generation, and “H2S-risk distribution” is not to consider and model any single, isolated reaction like the kinetically controlled sulfate reduction which depends on the thermal history. The actual key to model TSR, the fate and behavior of sulfidic sulfur, and a realistic “H2S-risk distribution” in petroleum reservoirs is an overall reproduction of the hydrogeochemical reactive transport processes which temporally and spatially evolve in a complex network of oil/petroleum-water-rock-gas interactions under reservoir conditions. Consequently, we perform 3D hydrogeochemical, multi-component and multi-species reactive mass transport modeling for a semi-generic case study by using the PHAST computer code (provided by the U.S. Geological Survey) and take the following boundary conditions into account: gas reservoir; carbonate (dolomite plus calcite) reservoir rocks; anhydrite seal; 140°C; 600 bar total pressure; kinetic rate constant for sulfate reduction by CH4 = 1.08 x 10-16 mol s-1 l-1; mass transport is restricted to diffusion; modeled time span is 10 Ma