Geothermal Energy & Geofluids
Institute of Geophysics
NO FO 47.2
CH-8092 Zurich Switzerland
|Phone||+41 44 632 6538|
|Dominique Ballarin Dolfin|
|Phone||+41 44 632 3465|
REFEREED PUBLICATIONS IN JOURNALS
Hefny, M., C.-Z. Qin, M.O. Saar, and A. Ebigbo Synchrotron-based pore-network modeling of two-phase flow in Nubian Sandstone and implications for capillary trapping of carbon dioxide International Journal of Greenhouse Gas Control, 103/1031642, 2020. [Download PDF] [View Abstract]Depleted oil fields in the Gulf of Suez (Egypt) can serve as geothermal reservoirs for power production using a CO2-Plume Geothermal (CPG) system, while geologically sequestering CO2. This entails the injection of a substantial amount of CO2 into the highly permeable brine-saturated Nubian Sandstone. Numerical models of two-phase flow processes are indispensable for predicting the CO2-plume migration at a representative geological scale. Such models require reliable constitutive relationships, including relative permeability and capillary pressure curves. In this study, quasi-static pore-network modeling has been used to simulate the equilibrium positions of fluid-fluid interfaces, and thus determine the capillary pressure and relative permeability curves. Three-dimensional images with a voxel size of 0.65 μm3 of a Nubian Sandstone rock sample have been obtained using Synchrotron Radiation X-ray Tomographic Microscopy. From the images, topological properties of pores/throats were constructed. Using a pore-network model, we performed a sequential primary drainage–main imbibition cycle of quasi-static invasion in order to quantify (1) the CO2 and brine relative permeability curves, (2) the effect of initial wetting-phase saturation (i.e. the saturation at the point of reversal from drainage to imbibition) on the residual–trapping potential, and (3) study the relative permeability–saturation hysteresis. The results illustrate the sensitivity of the pore-scale fluid-displacement and trapping processes on some key parameters (i.e. advancing contact angle, pore-body-to-throat aspect ratio, and initial wetting-phase saturation) and improve our understanding of the potential magnitude of capillary trapping in Nubian Sandstone.
Hefny, M., A. Zappone, Y. Makhloufi, A. de Haller, and A. Moscariello A laboratory approach for the calibration of seismic data in the western part of the Swiss Molasse Basin: the case history of well Humilly-2 (France) in the Geneva area Swiss Journal of Geosciences , 113/11, 2020. [Download PDF] [View Abstract]A collection of 81 plugs were obtained from the Humilly-2 borehole (France), that reached the Permo-Carboniferous sediments at a depth of 3051 m. Experimental measurements of physical parameters and mineralogical analysis were performed to explore the links between sedimentary facies and seismic characteristics and provide a key tool in the interpretation of seismic field data in terms of geological formations. The plugs, cylinders of 22.5 mm in diameter and ~30 mm in length were collected parallel and perpendicular to the bedding in order to explore their anisotropy. Ultrasound wave propagation was measured at increasing confining pressure conditions up to 260 MPa, a pressure where all micro-fractures are considered closed. The derivatives of velocities with pressure were established, allowing the simulation of lithological transitions at in-situ conditions. At room conditions, measured grain densities [kg/m3] range from 2630 to 2948 and velocities vary from 4339 to 6771 m/s and 2460 to 3975m/s for P- and S-waves propagation modes, respectively. The largest seismic-reflections coefficients were calculated for the interface between the evaporitic facies of the Keuper (Lettenkohle) and the underlying Muschelkalk carbonates (Rc= 0.3). The effective porosity has a range of 0.23% to 16.65%, while the maximum fluid permeability [m2] is 9.1e-16. A positive correlation between porosity and ultrasound velocity has been observed for P- and S-waves. The link between velocities and modal content of quartz, dolomite, calcite, and micas has been explored. This paper presents a unique set of seismic parameters potentially useful for the calibration of seismic data in the Geneva Molasse Basin.
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Hefny, M., C.-Z. Qin, A. Ebigbo, J. Gostick, M.O. Saar, and M. Hammed CO2-Brine flow in Nubian Sandstone (Egypt): Pore-Network Modeling using Computerized Tomography Imaging , European Geothermal Congress (EGC), 2019. [Download PDF] [View Abstract]The injection of CO2 into the highly permeable Nubian Sandstone of a depleted oil field in the central Gulf of Suez Basin (Egypt) is an effective way to extract enthalpy from deep sedimentary basins while sequestering CO2, forming a so-called CO2-Plume Geothermal (CPG) system. Subsurface flow models require constitutive relationships, including relative permeability and capillary pressure curves, to determine the CO2-plume migration at a representative geological scale. Based on the fluid-displacement mechanisms, quasi-static pore-network modeling has been used to simulate the equilibrium positions of fluid-fluid interfaces, and thus determine the capillary pressure and relative permeability curves. 3D images with a voxel size of 650 nm3 of a Nubian Sandstone rock sample have been obtained using Synchrotron Radiation X-ray Tomographic Microscopy. From the images, topological properties of pores/throats were constructed. Using a pore-network model, we performed a cycle of primary drainage of quasi-static invasion to quantify the saturation of scCO2 at the point of a breakthrough with emphasis on the relative permeability–saturation relationship. We compare the quasi-static flow simulation results from the pore-network model with experimental observations. It shows that the Pc-Sw curve is very similar to those observed experimentally.
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Hefny, M. Rock Physics and Heterogeneities Characterization Controlling Fluid flow in Reservoir Rocks, Dissertation, 2020. [Download PDF] [View Abstract]Integrating geothermal energy production with CO2 capture and sequestration (CCS) in deep saline aquifers or oil/gas reservoirs is a promising approach in order to stabilize atmospheric CO2 concentrations while producing a reliable net-zero energy supply. The underlying base energy system is a so-called CO2-Plume Geothermal (CPG) power plant, where the captured CO2 is circulated in geological reservoirs. Within these reservoirs, the CO2 is naturally geothermally heated, produced to the surface, where it is expanded in a turbine for generating electricity. It is then cooled and finally combined with any CO2 additional stream, from any CO2 emitter, before being re-injected into the subsurface reservoir. The CO2 re-injection along with the continued supply of captured CO2 results in the continued growth of the subsurface CO2 plume. To ensure that 100% of the subsurface-injected CO2 is eventually permanently stored underground, it is essential to predict the migration and distribution of the CO2 in the subsurface reservoir. In this way, injection and flow can be maximized through the reservoir while keeping the risk of leakage through the sealing caprock at a minimum. In this study, we combine laboratory experiments and numerical techniques to understand characteristic features of subsurface fluid migration/entrapment of CO2 occurring within deep geological formations. The results cover three main topics at different scales: Calibration of seismic data Seismic reflection imaging within the earth's upper crust may be greatly distorted due to the attenuation in seismic waves, particularly the high-frequency waves, passing through fluid-bearing rocks. Our approach is to understand the origin of seismic reflectors at the microscopic scale. Experimental measurements at ultrasonic frequencies and under high confining pressures were performed to explore the link between the intrinsic rock properties (i.e. mineralogy, porosity, grain density, permeability) and the characteristics seismic response. We provide a unique set of seismic parameters necessary to calibrate seismic surveys in the Swiss Molasse Basin. This calibration of the seismic data provides a starting point for generating a synthetic seismic trace, based on the calculated reflection coefficients. The synthetic trace then correlates with both the seismic field data and the well logs in order to dynamically simulate wave propagation in the porous (and saturated) media. Our results improve the seismic interpretations of the geological reservoir and caprock geometries. CPG reservoir flow impedance Petrophysical properties of subsurface reservoirs are generally poorly understood, which increases the uncertainty related to the CO2 potential and storage security as well as the potential to use the CO2, stored in the reservoir, to produce geothermal energy. To this end, we investigate whether the Nubian Sandstone (a common reservoir rock found in the Gulf of Suez at depths of 2.5 to 4.4 km, with a geothermal gradient of 35.7 oC/km, confined by multiple aquitards) can serve as a CCS/CPG subsurface target. We combine field permeability estimates with laboratory measurements to provide constraints for reservoir modelling to estimate the power generation potential of the Nubian Sandstone reservoir. The reservoir geometry is constrained by seismic surveys, which show that the region of interest has several extensional faults with an accumulative dip-slip displacement of 810 m. We estimate the reservoir flow impedance [kPa.s/kg] for each compartmentalized block using a 1D analytical Darcy solution, developed for a single-phase fluid in an inverted 5-spot well-pattern configuration. With this flow impedance, we determine a potential net electric power of 1137 kWe for the deepest fault block (depth: 4.0 km, surface area: 1.0 km2, pressure: 40 MPa, well diameter: 0.41 m). This potential net power decreases by 47% for a smaller well diameter of 0.17 m, and 88% for over-pressurized zones (pressure: 62 MPa). Overall, we estimate a potential net electric power generation capacity for the entire field (with a reservoir footprint of 15 km2) of 12 MWe and a Levelized Cost Of Electricity (LCOE) of less than 150 $/MWh (0.15 $/kWh), depending on the availability of infrastructure and other resources (i.e. CO2 sources, geophysical exploration, and the existence of a well network). These results substantially reduce uncertainties in assessing the geothermal prospect in the Hammam Faraun hot spring region, Sinai Peninsula, Egypt. Capillary trapping: Implication for CCS This study describes how digital rock physics investigations compare with laboratory experiments to quantify two-phase fluid flow properties. Three-dimensional images, with a voxel size of 0.65 m3 of a Nubian Sandstone sample, have been obtained using Synchrotron Radiation X-ray Tomographic Microscopy. From the images, topological properties of pores/throats were constructed. Using a pore-network model, we perform sequential primary drainage--main imbibition cycle of quasi-static invasion to quantify: (1) the CO2 and brine relative permeability curves, (2) the effect of initial wetting-phase saturation (i.e. the saturation at the point of reversal from drainage to imbibition) on the residual–trapping potential, and (3) study the relative permeability–saturation hysteresis. The results illustrate the sensitivity of the pore-scale fluid-displacement and trapping processes on some key parameters (i.e. advancing contact angle, pore-body-to-throat aspect ratio, and initial wetting-phase saturation) and improve our understanding of the potential magnitude of capillary trapping in Nubian Sandstone. Finally, we are developing a numerical model in MOOSE (Multiphysics Object Oriented Simulation Environment) to (1) quantify the CO2 saturation profiles at the reservoir-scale and (2) simulate the reservoir behaviour under different physical processes and different well pattern configurations. We base our reservoir simulations on a well-established static geological model from an offshore oilfield in the Gulf of Suez (the model that has been developed under CPG reservoir flow impedance part; Chapter 3), utilizing the physical properties and two-phase fluid flow behavior properties that we have obtained from the Capillary trapping part (Chapter 4). The first results of the reservoir simulations show how the CO2-plume evolves over time and predict a heat extraction potential for the heterogeneous reservoirs.