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25 pages, 14215 KiB

Open AccessArticle

Innovative CO₂ Injection Strategies in Carbonates and Advanced Modeling for Numerical Investigation

by José Carlos de Dios, Yann Le Gallo and Juan Andrés Marín

Fluids 2019, 4(1), 52; https://doi.org/10.3390/fluids4010052 - 16 Mar 2019

Cited by 4 | Viewed by 3145

Carbon sequestration in deep saline aquifers was recently developed at the industrial scale. CO₂ injection experiences in carbonates are quite limited, most of them coming from projects carried out in porous mediums in the USA and Canada. Hontomín (Spain) is the actual [...] Read more.

Carbon sequestration in deep saline aquifers was recently developed at the industrial scale. CO₂ injection experiences in carbonates are quite limited, most of them coming from projects carried out in porous mediums in the USA and Canada. Hontomín (Spain) is the actual on-shore injection pilot in Europe, being a naturally fractured carbonate reservoir where innovative CO₂ injection strategies are being performed within the ENOS Project. CO₂ migration through the fracture network existing on site produces hydrodynamic, mechanical and geochemical effectsdifferent from those caused by the injection in mediums with a high matrix permeability. The interpretation of these effects is required to design safe and efficient injection strategies in these formations. For this, it is necessary to determine the evolution of pressure, temperature and flow rate during the injection, as well as the period of pressure recovery during the fall-off phase. The first results from the not-continuous injections (8–24 h) conducted at Hontomín reveal the injection of liquid CO₂ (density value of 0.828 t/m³) and the fluid transmissivity through the fractures. Taking into account the evolution of the pressure and flow rate showed variations of up to 23% and 30% respectively, which means that the relevant changes of injectivity took place. The results were modeled with a compositional dual media model which accounts for both temperature effects and multiphase flow hysteresis because alternative brine and CO₂ injections were conducted. Advanced modeling shows the lateral extension of CO₂ and the temperature disturbance away from the well. Full article

(This article belongs to the Special Issue Fundamentals of CO₂ Storage in Geological Formations)

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11 pages, 1268 KiB

Open AccessArticle

Instability of a Diffusive Boundary Layer beneath a Capillary Transition Zone

by Fengyuan Zhang and Hamid Emami-Meybodi

Fluids 2018, 3(4), 85; https://doi.org/10.3390/fluids3040085 - 31 Oct 2018

Cited by 2 | Viewed by 3144

Abstract

Natural convection induced by carbon dioxide (CO₂) dissolution from a gas cap into the resident formation brine of a deep saline aquifer in the presence of a capillary transition zone is an important phenomenon that can accelerate the dissolution process, reducing [...] Read more.

Natural convection induced by carbon dioxide (CO₂) dissolution from a gas cap into the resident formation brine of a deep saline aquifer in the presence of a capillary transition zone is an important phenomenon that can accelerate the dissolution process, reducing the risk of CO₂ leakage to the shallower formations. Majority of past investigations on the instability of the diffusive boundary layer assumed a sharp CO₂–brine interface with constant CO₂ concentration at the top of the aquifer, i.e., single-phase system. However, this assumption may lead to erroneous estimates of the onset of natural convection. The present study demonstrates the significant effect of the capillary transition zone on the onset of natural convection in a two-phase system in which a buoyant CO₂ plume overlaid a water-saturated porous layer. Using the quasi-steady-state approximation (QSSA), we performed a linear stability analysis to assess critical times, critical wavenumbers, and neutral stability curves as a function of Bond number. We show that the capillary transition zone could potentially accelerate the evolution of the natural convection by sixfold. Furthermore, we characterized the instability problem for capillary-dominant, in-transition, and buoyancy-dominant systems. In the capillary-dominant systems, capillary transition zone has a strong role in destabilizing the diffusive boundary layer. In contrast, in the buoyancy-dominant systems, the buoyancy force is the sole cause of the instability, and the effect of the capillary transition zone can be ignored. Our findings provide further insight into the understanding of the natural convection in the two-phase CO₂–brine system and the long-term fate of the injected CO₂ in deep saline aquifers. Full article

(This article belongs to the Special Issue Fundamentals of CO₂ Storage in Geological Formations)

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14 pages, 9168 KiB

Open AccessArticle

Differential Diffusivity Effects in Reactive Convective Dissolution

by V. Loodts, H. Saghou, B. Knaepen, L. Rongy and A. De Wit

Fluids 2018, 3(4), 83; https://doi.org/10.3390/fluids3040083 - 26 Oct 2018

Cited by 14 | Viewed by 3537

Abstract

When a solute A dissolves into a host fluid containing a reactant B, an A + B → C reaction can influence the convection developing because of unstable density gradients in the gravity field. When A increases density and all three chemical species [...] Read more.

When a solute A dissolves into a host fluid containing a reactant B, an A + B → C reaction can influence the convection developing because of unstable density gradients in the gravity field. When A increases density and all three chemical species A, B and C diffuse at the same rate, the reactive case can lead to two different types of density profiles, i.e., a monotonically decreasing one from the interface to the bulk and a non-monotonic profile with a minimum. We study numerically here the nonlinear reactive convective dissolution dynamics in the more general case where the three solutes can diffuse at different rates. We show that differential diffusion can add new dynamic effects like the simultaneous presence of two different convection zones in the host phase when a non-monotonic profile with both a minimum and a maximum develops. Double diffusive instabilities can moreover affect the morphology of the convective fingers. Analysis of the mixing zone, the reaction rate, the total amount of stored A and the dissolution flux further shows that varying the diffusion coefficients of the various species has a quantitative effect on convection. Full article

(This article belongs to the Special Issue Fundamentals of CO₂ Storage in Geological Formations)

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31 pages, 12217 KiB

Open AccessArticle

Modeling of Carbon Dioxide Leakage from Storage Aquifers

by Parvaneh Heidari and Hassan Hassanzadeh

Fluids 2018, 3(4), 80; https://doi.org/10.3390/fluids3040080 - 23 Oct 2018

Cited by 7 | Viewed by 4879

Abstract

Long-term geological storage of CO₂ in deep saline aquifers offers the possibility of sustaining access to fossil fuels while reducing emissions. However, prior to implementation, associated risks of CO₂ leakage need to be carefully addressed to ensure safety of storage. CO [...] Read more.

Long-term geological storage of CO₂ in deep saline aquifers offers the possibility of sustaining access to fossil fuels while reducing emissions. However, prior to implementation, associated risks of CO₂ leakage need to be carefully addressed to ensure safety of storage. CO₂ storage takes place by several trapping mechanisms that are active on different time scales. The injected CO₂ may be trapped under an impermeable rock due to structural trapping. Over time, the contribution of capillary, solubility, and mineral trapping mechanisms come into play. Leaky faults and fractures provide pathways for CO₂ to migrate upward toward shallower depths and reduce the effectiveness of storage. Therefore, understanding the transport processes and the impact of various forces such as viscous, capillary and gravity is necessary. In this study, a mechanistic model is developed to investigate the influence of the driving forces on CO₂ migration through a water saturated leakage pathway. The developed numerical model is used to determine leakage characteristics for different rock formations from a potential CO₂ storage site in central Alberta, Canada. The model allows for preliminary analysis of CO₂ leakage and finds applications in screening and site selection for geological storage of CO₂ in deep saline aquifers. Full article

(This article belongs to the Special Issue Fundamentals of CO₂ Storage in Geological Formations)

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16 pages, 5076 KiB

Open AccessArticle

Investigating the Impact of Reservoir Properties and Injection Parameters on Carbon Dioxide Dissolution in Saline Aquifers

by Mohsen Abbaszadeh and Seyed M. Shariatipour

Fluids 2018, 3(4), 76; https://doi.org/10.3390/fluids3040076 - 20 Oct 2018

Cited by 16 | Viewed by 3507

Abstract

CO₂ injection into geological formations is considered one way of mitigating the increasing levels of carbon dioxide concentrations in the atmosphere and its effect on and global warming. In regard to sequestering carbon underground, different countries have conducted projects at commercial scale [...] Read more.

CO₂ injection into geological formations is considered one way of mitigating the increasing levels of carbon dioxide concentrations in the atmosphere and its effect on and global warming. In regard to sequestering carbon underground, different countries have conducted projects at commercial scale or pilot scale and some have plans to develop potential storage geological formations for carbon dioxide storage. In this study, pure CO₂ injection is examined on a model with the properties of bunter sandstone and then sensitivity analyses were conducted for some of the fluid, rock and injection parameters. The results of this study show that the extent to which CO₂ has been convected in the porous media in the reservoir plays a vital role in improving the CO₂ dissolution in brine and safety of its long term storage. We conclude that heterogeneous permeability plays a crucial role on the saturation distribution and can increase or decrease the amount of dissolved CO₂ in water around ± 7% after the injection stops and up to 13% after 120 years. Furthermore, the value of absolute permeability controls the effect of the K_v/K_h ratio on the CO₂ dissolution in brine. In other words, as the value of vertical and horizontal permeability decreases (i.e., tight reservoirs) the impact of K_v/K_h ratio on the dissolved CO₂ in brine becomes more prominent. Additionally, reservoir engineering parameters, such as well location, injection rate and scenarios, also have a high impact on the amount of dissolved CO₂ and can change the dissolution up to 26%, 100% and 5.5%, respectively. Full article

(This article belongs to the Special Issue Fundamentals of CO₂ Storage in Geological Formations)

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17 pages, 6504 KiB

Open AccessArticle

Geomechanical Response of Fractured Reservoirs

by Ahmad Zareidarmiyan, Hossein Salarirad, Victor Vilarrasa, Silvia De Simone and Sebastia Olivella

Fluids 2018, 3(4), 70; https://doi.org/10.3390/fluids3040070 - 29 Sep 2018

Cited by 19 | Viewed by 3624

Abstract

Geologic carbon storage will most likely be feasible only if carbon dioxide (CO₂) is utilized for improved oil recovery (IOR). The majority of carbonate reservoirs that bear hydrocarbons are fractured. Thus, the geomechanical response of the reservoir and caprock to IOR [...] Read more.

Geologic carbon storage will most likely be feasible only if carbon dioxide (CO₂) is utilized for improved oil recovery (IOR). The majority of carbonate reservoirs that bear hydrocarbons are fractured. Thus, the geomechanical response of the reservoir and caprock to IOR operations is controlled by pre-existing fractures. However, given the complexity of including fractures in numerical models, they are usually neglected and incorporated into an equivalent porous media. In this paper, we perform fully coupled thermo-hydro-mechanical numerical simulations of fluid injection and production into a naturally fractured carbonate reservoir. Simulation results show that fluid pressure propagates through the fractures much faster than the reservoir matrix as a result of their permeability contrast. Nevertheless, pressure diffusion propagates through the matrix blocks within days, reaching equilibrium with the fluid pressure in the fractures. In contrast, the cooling front remains within the fractures because it advances much faster by advection through the fractures than by conduction towards the matrix blocks. Moreover, the total stresses change proportionally to pressure changes and inversely proportional to temperature changes, with the maximum change occurring in the longitudinal direction of the fracture and the minimum in the direction normal to it. We find that shear failure is more likely to occur in the fractures and reservoir matrix that undergo cooling than in the region that is only affected by pressure changes. We also find that stability changes in the caprock are small and its integrity is maintained. We conclude that explicitly including fractures into numerical models permits identifying fracture instability that may be otherwise neglected. Full article

(This article belongs to the Special Issue Fundamentals of CO₂ Storage in Geological Formations)

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17 pages, 3365 KiB

Open AccessArticle

CO₂ Injection Effect on Geomechanical and Flow Properties of Calcite-Rich Reservoirs

by Kiseok Kim, Victor Vilarrasa and Roman Y. Makhnenko

Fluids 2018, 3(3), 66; https://doi.org/10.3390/fluids3030066 - 14 Sep 2018

Cited by 44 | Viewed by 6352

Abstract

Geologic carbon storage is considered as a requisite to effectively mitigate climate change, so large amounts of carbon dioxide (CO₂) are expected to be injected in sedimentary saline formations. CO₂ injection leads to the creation of acidic solution when it [...] Read more.

Geologic carbon storage is considered as a requisite to effectively mitigate climate change, so large amounts of carbon dioxide (CO₂) are expected to be injected in sedimentary saline formations. CO₂ injection leads to the creation of acidic solution when it dissolves into the resident brine, which can react with reservoir rock, especially carbonates. We numerically investigated the behavior of reservoir-caprock system where CO₂ injection-induced changes in the hydraulic and geomechanical properties of Apulian limestone were measured in the laboratory. We found that porosity of the limestone slightly decreases after CO₂ treatment, which lead to a permeability reduction by a factor of two. In the treated specimens, calcite dissolution was observed at the inlet, but carbonate precipitation occurred at the outlet, which was closed during the reaction time of three days. Additionally, the relative permeability curves were modified after CO₂–rock interaction, especially the one for water, which evolved from a quadratic to a quasi-linear function of the water saturation degree. Geomechanically, the limestone became softer and it was weakened after being altered by CO₂. Simulation results showed that the property changes occurring within the CO₂ plume caused a stress redistribution because CO₂ treated limestone became softer and tended to deform more in response to pressure buildup than the pristine rock. The reduction in strength induced by geochemical reactions may eventually cause shear failure within the CO₂ plume affected rock. This combination of laboratory experiments with numerical simulations leads to a better understanding of the implications of coupled chemo-mechanical interactions in geologic carbon storage. Full article

(This article belongs to the Special Issue Fundamentals of CO₂ Storage in Geological Formations)

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11 pages, 2199 KiB

Open AccessArticle

A Simple Analytical Model for Estimating the Dissolution-Driven Instability in a Porous Medium

by Layachi Hadji

Fluids 2018, 3(3), 60; https://doi.org/10.3390/fluids3030060 - 25 Aug 2018

Viewed by 2586

Abstract

This article deals with the stability problem that arises in the modeling of the geological sequestration of carbon dioxide. It provides a more detailed description of the alternative approach to tackling the stability problem put forth by Vo and Hadji (Physics of Fluids, [...] Read more.

This article deals with the stability problem that arises in the modeling of the geological sequestration of carbon dioxide. It provides a more detailed description of the alternative approach to tackling the stability problem put forth by Vo and Hadji (Physics of Fluids, 2017, 29, 127101) and Wanstall and Hadji (Journal of Engineering Mathematics, 2018, 108, 53–71), and it extends two-dimensional analysis to the three-dimensional case. This new approach, which is based on a step-function base profile, is contrasted with the usual time-evolving base state. While both provide only estimates for the instability threshold values, the step-function base profile approach has one great advantage in the sense that the problem at hand can be viewed as a stationary Rayleigh–Bénard problem, the model of which is physically sound and the stability of which is not only well-defined but can be analyzed by a variety of existing analytical methods using only paper and pencil. Full article

(This article belongs to the Special Issue Fundamentals of CO₂ Storage in Geological Formations)

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Graphical abstract

21 pages, 9497 KiB

Open AccessArticle

Steady Flux Regime During Convective Mixing in Three-Dimensional Heterogeneous Porous Media

by Christopher P. Green and Jonathan Ennis-King

Fluids 2018, 3(3), 58; https://doi.org/10.3390/fluids3030058 - 14 Aug 2018

Cited by 23 | Viewed by 3842

Abstract

Density-driven convective mixing in porous media can be influenced by the spatial heterogeneity of the medium. Previous studies using two-dimensional models have shown that while the initial flow regimes are sensitive to local permeability variation, the later steady flux regime (where the dissolution [...] Read more.

Density-driven convective mixing in porous media can be influenced by the spatial heterogeneity of the medium. Previous studies using two-dimensional models have shown that while the initial flow regimes are sensitive to local permeability variation, the later steady flux regime (where the dissolution flux is relatively constant) can be approximated with an equivalent anisotropic porous media, suggesting that it is the average properties of the porous media that affect this regime. This work extends the previous results for two-dimensional porous media to consider convection in three-dimensional porous media. Through the use of massively parallel numerical simulations, we verify that the steady dissolution rate in the models of heterogeneity considered also scales as

\sqrt{k_{v} k_{h}}

in three dimensions, where

k_{v}

and

k_{h}

are the vertical and horizontal permeabilities, respectively, providing further evidence that convective mixing in heterogeneous models can be approximated with equivalent anisotropic models. Full article

(This article belongs to the Special Issue Fundamentals of CO₂ Storage in Geological Formations)

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