REFEREED PUBLICATIONS IN JOURNALS
Lima, M.M., D. Vogler, L. Querci, C. Madonna, B. Hattendorf, M.O. Saar, and X.-Z. Kong Thermally driven fracture aperture variation in naturally fractured granites Geothermal Energy Journal, 7/1, pp. 1-23, 2019. [Download PDF] [View Abstract]Temperature variations often trigger coupled thermal, hydrological, mechanical, and chemical (THMC) processes that can significantly alter the permeability/impedance of fracture-dominated deep geological reservoirs. It is thus necessary to quantitatively explore the associated phenomena during fracture opening and closure as a result of temperature change. In this work, we report near-field experimental results of the effect of temperature on the hydraulic properties of natural fractures under stressed conditions (effective normal stresses of 5-25 MPa). Two specimens of naturally fractured granodiorite cores from the Grimsel Test Site in Switzerland were subjected to flow-through experiments with a temperature variation of 25-140 °C to characterize the evolution of fracture aperture/permeability. The fracture surfaces of the studied specimens were morphologically characterized using photogrammetry scanning. Periodic measurements of the efflux of dissolved minerals yield the net removal mass, which is correlated to the observed rates of fracture closure. Changes measured in hydraulic aperture are significant, exhibiting reductions of 20-75 % over the heating/cooling cycles. Under higher confining stresses, the effects in fracture permeability are irreversible and notably time-dependent. Thermally driven fracture aperture variation was more pronounced in the specimen with the largest mean aperture width and spatial correlation length. Gradual fracture compaction is likely controlled by thermal dilation, mechanical grinding, and pressure dissolution due to increased thermal stresses exerted over the contacting asperities, as confirmed by the analyses of hydraulic properties and efflux mass.
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Lima, M., P. Schädle, D. Vogler, M. Saar, and X.-Z. Kong A Numerical Model for Formation Dry-out During CO2 Injection in Fractured Reservoirs Using the MOOSE Framework: Implications for CO2-based Geothermal Energy Extraction , Proceedings of the World Geothermal Congress 2020, Reykjavík, Iceland, (in press). [View Abstract]Injection of supercritical carbon dioxide (scCO2) into geological reservoirs is involved in Carbon Capture, Utilization, and Storage (CCUS), such as geological CO2 storage, and Enhanced Geothermal Systems (EGS). The potential physico-chemical interactions between the dry scCO2, the reservoir fluid, and rocks may cause formation dry-out, where mineral precipitates due to continuous evaporation of water into the scCO2 stream. This salt precipitation may impair the rock bulk permeability and cause a significant decrease in the well injectivity. Formation dry-out and the associated salt precipitation during scCO2 injection into porous media have been investigated in previous studies by means of numerical simulations and laboratory experiments. However, few studies have focused on the dry-out effects in fractured rocks in particular, where the mass transport is strongly influenced by the fracture aperture distribution. In this study, we numerically model the dry-out processes occurring during scCO2 injection into brine-saturated single fractures and evaluate the potential of salt precipitation. Fracture aperture fields are photogrammetrically determined with fracture geometries of naturally fractured granite cores from the Deep Underground Geothermal (DUG) Lab at the Grimsel Test Site (GTS), in Switzerland. We use an open-source, parallel finite element framework to numerically model two-phase flow through a 2D fracture plane. Under in-situ reservoir conditions, the brine is displaced by dry scCO2 and also evaporates into the CO2 stream. The fracture permeability is calculated with the local cubic law. Additionally, we extend the numerical model by the Young-Laplace equation to determine the aperture-based capillary pressure. Finally, as future work, the precipitation of salt will be modelled by employing a uniform mineral growth approach, where the local aperture uniformly decreases with the increase in precipitated mineral volume. The numerical simulations assist in understanding the long-term behaviour of reservoir injectivity during subsurface applications that involve scCO2 injection, including CO2-based geothermal energy extraction.
Lima, M.M., P. Schädle, D. Vogler, M.O. Saar, and X.-Z. Kong Impact of Effective Normal Stress on Capillary Pressure in a Single Natural Fracture , European Geothermal Congress 2019, pp. 1-9, 2019. [View Abstract]Multiphase fluid flow through rock fractures occurs in many reservoir applications such as geological CO2 storage, Enhanced Geothermal Systems (EGS), nuclear waste disposal, and oil and gas production. However, constitutional relations of capillary pressure versus fluid saturation, particularly considering the change of fracture aperture distributions under various stress conditions, are poorly understood. In this study, we use fracture geometries of naturally-fractured granodiorite cores as input for numerical simulations of two-phase brine displacement by super critical CO 2 under various effective normal stress conditions. The aperture fields are first mapped via photogrammetry, and the effective normal stresses are applied by means of a Fast Fourier Transform (FFT)-based convolution numerical method. Throughout the simulations, the capillary pressure is evaluated from the local aperture. Two approaches to obtain the capillary pressure are used for comparison: either directly using the Young-Laplace equation, or the van Genuchten equation fitted from capillary pressure-saturation relations generated using the pore-occupancy model. Analyses of the resulting CO2 injection patterns and the breakthrough times enable investigation of the relationships between the effective normal stress, flow channelling and aperture-based capillary pressures. The obtained results assist the evaluation of two-phase flow through fractures in the context of various subsurface applications.
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Lima, M.M. The effect of sulfate ions on the performance of smartwater flooding applied to carbonate reservoirs, MSc Thesis, University of Campinas, 197 pp., 2016. [View Abstract]The "low salinity water" technology is an enhanced oil recovery method that is gaining attention from researchers and the oil industry. For carbonate reservoirs, which are normally oil wet or mixed wet, this technique is even more attractive. Studies have shown that the sulfate ion plays a unique role on the technique, acting as a catalyzer for the multiple ion exchanges that promote the wettability alteration. The concentration of the ions Na+ and Cl-, as well as the temperature, are considered important parameters. In many cases, seawater is already an optimized water for the process. Traditionally, however, in the Brazilian pre-salt oil fields, the desulfated seawater is used as the injecting water ¿ as a precaution to avoid reservoir incrustation or souring. To justify the replacement of the injection water by seawater, substantial laboratory data using reservoir carbonate rocks are still required. The present work aims to evaluate the effect of the sulfate ion in the injection water using carbonate plugs, as well as to analyze the influence of the Na+ and Cl- ions and the temperature. At the laboratory, nine water-flooding tests, at 65°C and 100°C, and six spontaneous imbibition tests, at 65°C and 90°C, were performed with different water compositions. The water-flooding tests were divided in three groups. The first group contained four tests that were selected in order to investigate the effects of the initially chosen parameters (SO42-, Na+, Cl- and temperature). The second and third groups were elaborated because the injection rates and the rock samples¿ lithology could influence the oil recovery. Therefore, other five water-flooding tests were performed to study these new perceived variables. The results have shown that an increase in the sulfate concentration of the injection water, up to the amount present in seawater, can recover up to an additional 8% OOIP, after the injection of desulfated seawater. The effect of the non-active Na+ and Cl- ions was also observed. The influence of relatively small variations (less than an order of magnitude) of the flow capillary number on the remaining oil saturation in carbonate rocks was clearly observed, indicating a very small or even inexistent critical capillary number. It was noticed that the minimum temperature for the effect of the potential ions depends on the type of test performed. In spontaneous imbibition tests, it was not possible to distinguish the effect of increasing sulfate concentrations in water at 65°C ¿ which is in agreement with literature results. However, in the water-flooding tests, at 65°C it was already possible to notice the effect of the sulfate ion on the oil recovery. Finally, the overall results open up the suggestion to analyze the viability of changing the composition of the injection water currently being used in many Brazilian pre-salt oil fields, given the seawater’s potential of saving money by simplifying the operating plant and promoting oil production