• Energy Research

In order to assess the thermo-hydraulic modelling capabilities of various geothermal simulators, a comparative test suite was created, consisting of a set of cases designed with conditions relevant to the low-enthalpy range of geothermal operations within the European HEATSTORE research project. In an effort to increase confidence in the usage of each simulator, the suite was used as a benchmark by a set of 10 simulators of diverse origin, formulation, and licensing characteristics: COMSOL, MARTHE, ComPASS, Nexus-CSMP++, MOOSE, SEAWATv4, CODE_BRIGHT, Tough3, PFLOTRAN, and Eclipse 100. The synthetic test cases (TCs) consist of a transient pressure test verification (TC1), a well-test comparison (TC2), a thermal transport experiment validation (TC3), and a convection onset comparison (TC4), chosen to represent well-defined subsets of the coupled physical processes acting in subsurface geothermal operations. The results from the four test cases were compared among the participants, to known analytical solutions, and to experimental measurements where applicable, to establish them as reference expectations for future studies. A basic description, problem specification, and corresponding results are presented and discussed. Most participating simulators were able to perform most tests reliably at a level of accuracy that is considered sufficient for application to modelling tasks in real geothermal projects. Significant relative deviations from the reference solutions occurred where strong, sudden (e.g. initial) gradients affected the accuracy of the numerical discretization, but also due to sub-optimal model setup caused by simulator limitations (e.g. providing an equation of state for water properties). Geothermics, 96 ISSN:0375-6505

Póster presentado en la 7th Trondheim Conference on CO2 Capture, Transport and Storage, celebrada en Trondheim (Noruega) del 4 al 6 de junio de 2013. It is usually assumed that CO2 for geological storage should be injected in supercritical (SC) state (i.e. p>7.382 MPa and T>31.04 ºC) to avoid thermal stresses or phase changes in the injection tubing or in the formation. Injecting CO2 in liquid phase would be desirable because its density is much larger than that of either gaseous or supercritical CO2. Since most of the wellhead pressure is required for overcoming buoyancy forces in the wellbore, increasing density in the wellbore translates into a parallel reduction of the required wellhead pressure. Yet, most projects contemplate injection in either SC or gaseous phase because of concerns about (1) phase changes in the wellbore, or (2) thermal stresses in the reservoir caused by the injection of CO2 much colder than the reservoir. We perform numerical simulations to analyze the thermodynamic evolution of CO2 and the thermo-hydro-mechanical response of the formation and the caprock to liquid CO2 injection. We find that injecting CO2 in liquid state is energetically more efficient than in SC state because liquid CO2 is denser than SC CO2, leading to a lower overpressure not only at the wellhead, but also in the reservoir because a smaller fluid volume is displaced. Cold CO2 injection cools down the formation around the injection well. Further away, CO2 equilibrates thermally with the medium in an abrupt front. A slight temperature increase occurs in the SC CO2 region that is due to the exothermal dissolution of CO2 into the brine. The liquid CO2 region close to the injection well advances far behind the SC CO2 interface. While the SC CO2 region is dominated by gravity override, the liquid CO2 region displays a steeper front because viscous forces dominate (liquid CO2 is not only denser, but also more viscous than SC CO2). The temperature decrease close to the injection well induces a stress reduction due to thermal contraction of the media. This can lead to shear slip of pre-existing fractures in the aquifer for large temperature contrasts in stiff rocks, which could enhance injectivity. In contrast, the mobilized friction angle in the seals is not increased when injecting liquid CO2 and it is even reduced in stress regimes where the maximum principal stress is the vertical. We conclude that injecting CO2 in liquid state rather than SC is favourable for several reasons: (1) this injection strategy is energetically advantageous, (2) no transformation operation or only low energy consumption conditioning operations are necessary, (3) a smaller compression work at the wellhead is necessary because of the smaller compressibility of liquid CO2, (4) since liquid CO2 is denser than SC CO2, liquid CO2 injection induces a lower overpressure also at within the aquifer because a smaller amount of fluid is displaced and (5) the caprock mechanical stability is improved. Peer reviewed

Carbon dioxide (CO2) will reach the storage formation at a temperature lower than that of the reservoir, especially for high flow rates. Thus, thermo-mechanical effects might jeopardize the caprock mechanical stability and cause induced seismicity. We perform thermo-hydro-mechanical simulations of cold (liquid) CO2 injection and analyze the impacts on the rock mechanical stability during a 30 year injection period. Injection of cold CO2 develops a cold region around the injection well that induces a thermal stress reduction in the reservoir due to its contraction. Stress redistribution, which occurs to satisfy stress equilibrium and displacement compatibility, causes the horizontal total stress to increase in the lower portion of the caprock. The thermal stress reduction in the reservoir decreases its stability when injecting a constant mass flow rate through a vertical well in normal faulting stress regimes. Such decrease in stability, if sufficiently large, might cause induced seismicity as well as enhancing reservoir permeability and injectivity. However, the caprock tightens due to the increase in horizontal total stress, improving its stability. After a significant improvement in caprock stability during the first years of injection, stability decreases gradually for longer injection times, but the stress state remains more stable than prior to injection, even for stiff caprocks. By contrast, in a reverse faulting stress regime, both the reservoir and the caprock are less stable during the first years of injection, but stability improves subsequently. On the other hand, injecting cold CO2 at a constant mass flow rate through a horizontal well does not significantly affect the caprock stability for the scenarios considered in this study (in both normal and reverse faulting stress regimes). We show that accounting for the thermal expansion of the grains is very important in low porosity formations to avoid simulating artificial porosity and total stress reductions in the cooled region of the caprock that yield unreal high mobilized friction angles in the lower part of the caprock in normal faulting stress regimes. Overall, injecting cold CO2 should not be feared because of the thermal stresses reduction, though care should be taken to avoid excessive induced seismicity.

38 páginas, 11 figuras. Sequestration of carbon dioxide (CO2) in deep saline aquifers has emerged as an option for reducing greenhouse gas emissions to the atmosphere. The large amounts of supercritical CO2 that need to be injected into deep saline aquifers may cause large fluid pressure increases. The resulting overpressure may promote reactivation of sealed fractures or the creation of new ones in the caprock seal. This could lead to escape routes for CO2. In order to assess the probability of such an event, we model an axisymmetric horizontal aquifer-caprock system, including hydromechanical coupling. We study the failure mechanisms, using a viscoplastic approach. Simulations illustrate that, depending on boundary conditions, the least favorable moment takes place at the beginning of injection. Initially, fluid pressure rises sharply because of a reduction in permeability due to desaturation. Once CO2 fills the pores in the vicinity of the injection well and a capillary fringe is fully developed, the less viscous CO2 displaces the brine and the capillary fringe laterally. The overpressure caused by the permeability reduction within the capillary fringe due to desaturation decreases with distance from the injection well. This results in a drop in fluid pressure buildup with time, which leads to a safer situation. Nevertheless, in the presence of low-permeability boundaries, fluid pressure continues to rise in the whole aquifer. This occurs when the radius of influence of the injection reaches the outer boundary. Thus, caprock integrity might be compromised in the long term. V.V. and D.B. would like to acknowledge the Spanish Ministry of Science and Innovation (MIC) for financial support through the “Formación de Profesorado Universitario” and “Juan de la Cierva” programs. V.V. also wishes to acknowledge the “Colegio de Ingenieros de Caminos, Canales y Puertos – Catalunya” for their financial support. This project has been funded by the Spanish Ministry of Science and Innovation through the CIUDEN project (Ref.: 030102080014), and through the MUSTANG project, from the European Community’s Seventh Framework Programme FP7/2007-2013 under grant agreement nº 227286. Peer reviewed

Sequestration of carbon dioxide (CO2) in deep saline aquifers has emerged as a mitigation strategy for reducing greenhouse gas emissions to the atmosphere. The large amounts of supercritical CO2 that need to be injected into deep saline aquifers may cause large fluid pressure buildup. The resulting overpressure will produce changes in the effective stress field. This will deform the rock and may promote reactivation of sealed fractures or the creation of new ones in the caprock seal, which could lead to escape paths for CO2. To understand these coupled hydromechanical phenomena, we model an axisymmetric horizontal aquifer-caprock system. We study plastic strain propagation patterns using a viscoplastic approach. Simulations illustrate that plastic strain may propagate through the whole thickness of the caprock if horizontal stress is lower than vertical stress. In contrast, plastic strain concentrates in the contact between the aquifer and the caprock if horizontal stress is larger than vertical stress. Aquifers that present a low-permeability boundary experience an additional fluid pressure increase once the pressure buildup cone reaches the outer boundary. However, fluid pressure does not evolve uniformly in the aquifer. While it increases in the low-permeability boundary, it drops in the vicinity of the injection well because of the lower viscosity of CO2. Thus, caprock stability does not get worse in semi-closed aquifers compared to open aquifers. Overall, the caprock acts as a plate that bends because of pressure buildup, producing a horizontal extension of the upper part of the caprock. This implies a vertical compression of this zone, which may produce settlements instead of uplift in low-permeability (k≤10-18 m2) caprocks at early times of injection. Peer Reviewed

AbstractHigh-temperature aquifer thermal energy storage (HT-ATES) systems can help in balancing energy demand and supply for better use of infrastructures and resources. The aim of these systems is to store high amounts of heat to be reused later. HT-ATES requires addressing problems such as variations of the properties of the aquifer, thermal losses and the uplift of the surface. Coupled thermo-hydro-mechanical (THM) modelling is a good tool to analyse the viability and cost effectiveness of HT-ATES systems and to understand the interaction of processes, such as heat flux, groundwater flow and ground deformation. The main problem of this modelling is its high computational cost. We propose a dimensional and numerical analysis of the thermo-hydro-mechanical behaviour of a pilot HT-ATES. The results of this study have provided information about the dominant thermo-hydraulic fluxes, evolution of the energy efficiency of the system and the role of the hydraulic and thermal loads generated by the injection and extraction of hot water.