Modeling of CO2storage in aquifers (original) (raw)
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A numerical procedure to model and monitor CO2sequestration in aquifers
Journal of Physics: Conference Series, 2013
Carbon Dioxide (CO2) sequestration into geologic formations is a means of mitigating greenhouse effect. In this work we present a new numerical simulation technique to model and monitor CO2 sequestration in aquifers. For that purpose we integrate numerical simulators of CO2-brine flow and seismic wave propagation (time-lapse seismics). The simultaneous flow of brine and CO2 is modeled applying the Black-Oil formulation for two phase flow in porous media, which uses the Pressure-Volume-Temperature (PVT) behavior as a simplified thermodynamic model. Seismic wave propagation uses a simulator based on a space-frequency domain formulation of the viscoelastic wave equation. In this formulation, the complex and frequency dependent coefficients represent the attenuation and dispersion effect suffered by seismic waves travelling in fluid-saturated heterogeneous porous formations. The spatial discretization is achieved employing a nonconforming finite element space to represent the displacement vector. Numerical examples of CO2 injection and time-lapse seismics in the Utsira formation at the Sleipner field are analyzed. The Utsira formation is represented using a new petrophysical model that allows a realistic inclusion of shale seals and fractures. The results of the simulations show the capability of the proposed methodology to monitor the spatial distribution of CO2 after injection.
2000
In the ongoing aquifer CO 2 disposal project in the Sleipner license (North Sea), underground CO 2 is being monitored by time-lapse seismic. The CO 2 is being injected close to the base of a high permeable, highly porous sand unit, the Utsira Sand. In an iterative process between seismic surveys and reservoir simulations, a reservoir model featuring the major controlling heterogeneities has been developed. Well-data and seismic data prior to injection shows that the sand is divided by nearly horizontal, discontinuous shales. From the 3-D seismic image after three years of injection, strong reflectors can be interpreted as CO 2 accumulations identifying the major shale layers that control the vertical migration of CO 2 from the injection point to the top of the formation. By modelling this flow in reservoir simulations, it can be inferred that the CO 2 is transported in distinct columns between the shales rather than as dispersed bubbles over a large area. Improvement of the geological model increases the confidence of predictions based on simulation of the long-time fate of CO 2 . A possible natural aquifer flow can have a pronounced effect on the location of CO 2 accumulations due to the relatively flat topography of the trapping shales. This effect has been quantified by simulation and this phenomenon was used to adjust the localisation of the CO 2 bubbles to better fir the seismic images.
In the ongoing aquifer CO 2 disposal project in the Sleipner license (North Sea), underground CO 2 is being monitored by time-lapse seismic. The CO 2 is being injected close to the base of a high permeable, highly porous sand unit, the Utsira Sand. In an iterative process between seismic surveys and reservoir simulations, a reservoir model featuring the major controlling heterogeneities has been developed. Well-data and seismic data prior to injection shows that the sand is divided by nearly horizontal, discontinuous shales. From the 3-D seismic image after three years of injection, strong reflectors can be interpreted as CO 2 accumulations identifying the major shale layers that control the vertical migration of CO 2 from the injection point to the top of the formation. By modelling this flow in reservoir simulations, it can be inferred that the CO 2 is transported in distinct columns between the shales rather than as dispersed bubbles over a large area. Improvement of the geologic...
In the ongoing aquifer CO2 disposal project in the Sleipner license (North Sea), underground CO2 is being monitored by time-lapse seismic. The CO2 is being injected close to the base of a high permeable, highly porous sand unit, the Utsira Sand. In an iterative process between seismic surveys and reservoir simulations, a reservoir model featuring the major controlling heterogeneities has been developed. Well-data and seismic data prior to injection shows that the sand is divided by nearly horizontal, discontinuous shales. From the 3-D seismic image after three years of injection, strong reflectors can be interpreted as CO2 accumulations identifying the major shale layers that control the vertical migration of CO2 from the injection point to the top of the formation. By modelling this flow in reservoir simulations, it can be inferred that the CO2 is transported in distinct columns between the shales rather than as dispersed bubbles over a large area. Improvement of the geological mod...
Transport in Porous Media, 2008
Sequestration of carbon dioxide in geological formations is an alternative way of managing extra carbon. Although there are a number of mathematical modeling studies related to this subject, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study describes a fully coupled geochemical compositional equation-of-state compositional simulator (STARS) for the simulation of CO2 storage in saline aquifers. STARS models physical phenomena including (1) thermodynamics of sub- and supercritical CO2, and PVT properties of mixtures of CO2 with other fluids, including (saline) water; (2) fluid mechanics of single and multiphase flow when CO2 is injected into aquifers; (3) coupled hydrochemical effects due to interactions between CO2, reservoir fluids, and primary mineral assemblages; and (4) coupled hydromechanical effects, such as porosity and permeability change due to the aforementioned blocking of pores by carbonate particles and increased fluid pressures from CO2 injection. Matching computerized tomography monitored laboratory experiments showed the uses of the simulation model. In the simulations dissolution and deposition of calcite as well as adsorption of CO2 that showed the migration of CO2 and the dissociation of CO2 into HCO3 and its subsequent conversion into carbonate minerals were considered. It was observed that solubility and hydrodynamic storage of CO2 is larger compared to mineral trapping.
Numerical simulation of CO 2 geological storage in saline aquifers – case study of Utsira formation
2013
CO2 geological storage (CGS) is one of the most promising technologies to address the issue of excessive anthropogenic CO2 emissions in the atmosphere due to fossil fuel combustion for electricity generation. In order to fully exploit the storage potential, numerical simulations can help in determining injection strategies before the deployment of full scale sequestration in saline aquifers. This paper presents the numerical simulations of CO2 geological storage in Utsira saline formation where the sequestration is currently underway. The effects of various hydrogeological and numerical factors on the CO2 distribution in the topmost hydrogeological layer of Utsira are discussed. The existence of multiple pathways for upward mobility of CO2 into the topmost layer of Utsira as well as the performance of the top seal are also investigated. Copyright © 2014 International Energy and Environment Foundation All rights reserved.
Temperature is one of the main parameters influencing CO2 properties during storage in saline aquifers, since it controls along with pressure the phase behavior of the CO2/brine mixture. When CO2 replaces brine as a free gas it is known to affect the elastic properties of porous media considerably. In order to track the migration of geologically stored CO2 in a saline aquifer at the Ketzin pilot site (Germany), 3D time-lapse seismic data were acquired by means of a baseline (pre-injection) survey in 2005 and monitor surveys in 2009 and 2012. At Ketzin, CO2 was injected from 2008 to 2013 in a sandstone reservoir at a depth of about 630 -650 m. In total about 67 kilotons of CO2 were injected. The present study is devoted to the 4D seismic dataset of 2005 -2009. The temperature in the storage reservoir near the injection well was observed to have increased from 34 °C in 2005 to 38 °C in 2009. This temperature increase led us to investigate the impact of temperature on the seismic response to CO2 injection and on our estimations of spatial CO2 mass distribution in the reservoir based on the Ketzin 4D seismic data. Both temperature scenarios in the reservoir of 2005 and 2009 were studied using multiphase fluid flow modeling. The isothermal simulations carried out for both 34°C and 38°C
Simulation of Carbon Dioxide Storage Applying Accurate Petrophysics, Fluid-Flowand Seismics Models
2012
Capture and storage of Carbon dioxide in aquifers and reservoirs is one of the solutions to mitigate the greenhouse effect. Geophysical methods can be used to monitor the location and migration of the gas in the underground. To perform this task properly, a suitable geological model is important, which simulates the geometry and petro-elastical properties of the different formations. In this work we integrate numerical simulators of CO2-brine flow and seismic wave propagation to model and monitor CO2 storage in saline aquifers. We also build a petrophysical model of a shaly sandstone based on porosity and clay content and considering the variation of properties with pore pressure and fluid saturation. The pressure map before the injection of CO2 is assumed to be hydrostatic for which a reference porosity map is defined. The permeability is assumed to be anisotropic and is obtained from first principles as a function of porosity and grain sizes. The density is the usual arithmetic av...
Flow Simulation of CO2 Storage in Saline Aquifers Using Black Oil Simulator
2012
Sequestration of carbon dioxide in geological formations has drawn increasing consideration as a potential method to reduce the level of CO 2 in the atmosphere, and therefore mitigate climate change. In particular, saline aquifers can potentially provide a large storage volume world-wide. It is essential to assess the risk involved in storing CO 2 in the subsurface, and simulations of CO 2 injection play an important role. Detailed simulations using a compositional simulator, which solves the equation of state for the fluids and calculates the partitioning of fluids between phases, is time consuming. It is therefore advantageous to use a simpler method for simulation, such as a modification of a black-oil simulator (designed for use in the oil industry), where fluid properties are input using look-up tables.
Carbon dioxide (CO 2 ) sequestration in saline aquifers is considered as one of the most viable and promising ways to reduce CO 2 concentration in the atmosphere. CO 2 is injected into deep saline formations at supercritical state where its density is smaller than the hosting brine. This motivates an upward motion and eventually CO 2 is trapped beneath the cap rock. The trapped CO 2 slowly dissolves into the brine causing the density of the mixture to become larger than the host brine. This causes gravitational instabilities that is propagated and magnified with time. In this kind of density-driven flows, the CO 2 -rich brines migrate downward while the brines with low CO 2 concentration move upward. With respect to the properties of the subsurface aquifers, there are instances where saline formations can possess anisotropy with respect to their hydraulic properties. Such anisotropy can have significant effect on the onset and propagation of flow instabilities. Anisotropy is predicted to be more influential in dictating the direction of the convective flow. To account for permeability anisotropy, the method of multipoint flux approximation (MPFA) in the framework of finite differences schemes is used. The MPFA method requires more point stencil than the traditional two-point flux approximation (TPFA). For example, calculation of one flux component requires 6-point stencil and 18-point stencil in 2-D and 3-D cases, respectively. As consequence, the matrix of coefficient for obtaining the pressure fields will be quite complex. Therefore, we combine the MPFA method with the experimenting pressure field technique in which the problem is reduced to solving multitude of local problems and the global matrix of coefficients is constructed automatically, which significantly reduces the complexity. We present several numerical scenarios of density-driven flow simulation in homogeneous, layered, and heterogeneous anisotropic porous media. The numerical results emphasize the significant effects of anisotropy in driving the migration of dissolved CO 2 along the principal direction of anisotropy even if the porous medium is highly heterogeneous. Furthermore, the impacts of the increase of density difference between the brine and the CO 2 -saturated brine with respect to the onset time of convection, the CO 2 flux, and the CO 2 total dissolved mass are also discussed in this paper.