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Solving the carbon-dioxide buoyancy challenge: The design and field testing of a dissolved CO2 injection system
Abstract
Long-term security is critical to the success and public acceptance of geologic carbon storage. Much of the security risk associated with geologic carbon storage stems from CO2 buoyancy. Gaseous and supercritical CO2 are less dense than formation waters providing a driving force for it to escape back to the surface via fractures, or abandoned wells. This buoyancy can be eradicated by the dissolution of CO2 into water prior to, or during its injection into the subsurface. Here we demonstrate the dissolution of CO2 into water during its injection into basalts leading directly to its geologic solubility storage. This process was verified via the successful injection of over 175 t of CO2 dissolved in 5000 t of water into porous rocks located 400–800 m below the surface at the Hellisheidi, Iceland CarbFix injection site. Although larger volumes are required for CO2 storage via this method, because the dissolved CO2 is no longer buoyant, the storage formation does not have to be as deep as for supercritical CO2 and the cap rock integrity is less important. This increases the potential storage resource substantially compared to the current estimated storage potential of supercritical CO2.
... Additional innovation may focus on using seawater to dissolve CO2 to reduce water costs, which make up a significant portion of the OPEX for the aqueous dissolved method of CO2 injection. Designing injection systems for direct integration with the CO2 source (e.g., dissolving DAC-sourced CO2 in water within the wellbore at depth rather than the surface) could drive energy savings (129). We estimate innovations focused on optimizing conditioning and systems integration for in situ mineralization technologies have a low potential to reduce the total cost of CDR by <10%. ...
... Note that the injection rate used in this model presents a conservative estimate of per-well injectivity assuming 40-kg/s injection rates, whereas field injectivity tests at the Coda Terminal site indicated feasible injection rates of up to 70 kg/s. It is assumed that CO2 is delivered at >99% purity and atmospheric pressure before being compressed to 2.5 MPa for injection in a gaseous state, with a separate CO2 and water pipe that mix when sufficiently deep for complete dissolution (i.e., >2.50 MPa) (129,249). Energy requirements assume pumping for the water intensity of approximately 27 tH2O/tCO2 (249). ...
... The scope of this document covers two commercially and technically mature methods: CO2(aq) and scCO2 injection. The first method, CO2(aq), describes the method developed by Carbfix in Iceland, where gaseous CO2 is dissolved in the injection well via mixing at depth downhole, leveraging the hydrostatic pressure to maintain CO2 in solution and avoid degassing (129,249). The second method, scCO2, describes the method developed by Pacific Northwest National Laboratory in the Wallula Basalt Pilot Project, where CO2 is injected in a pure phase as a supercritical fluid (T > 31°C, P > 7.4 MPa). ...
https://www.energy.gov/sites/default/files/2024-11/Carbon%20Negative%20Shot_Technological%20Innovation%20Opportunities%20for%20CO2%20Removal_November2024.pdf
... 22 While this mineralization reaction occurs naturally through silicate weathering over geological time scales, artificial mineral storage can accelerate carbon fixation much faster. 53 By injecting CO 2 into the ground, solubility trapping occurs immediately, allowing for rapid carbon sequestration and bypassing the slow natural process of silicate weathering. 53 In a minimum of 2−10 years, a vast majority of the injected CO 2 is observed to be trapped as a carbonate mineral. ...
... 53 By injecting CO 2 into the ground, solubility trapping occurs immediately, allowing for rapid carbon sequestration and bypassing the slow natural process of silicate weathering. 53 In a minimum of 2−10 years, a vast majority of the injected CO 2 is observed to be trapped as a carbonate mineral. [33][34][35]54 Mineral carbonation can be enhanced by dissolving CO 2 in water prior to or during injection, enhancing solubility trapping, and achieving mineral trapping within 2 years at 20−50°C. ...
... 92 The target formation, at 400−800 m depth, exhibits vertical and lateral intrinsic permeabilities of 1700 and 300 mD, respectively. 53 The formation is composed of olivine tholeiite, a type of basaltic lava and hyaloclastite, with temperatures ranging from 20 to 50°C and pH between 8.4 and 9.4. 92,122 Only pure CO 2 and CO 2 +H 2 S mixtures dissolved in water were considered for injection into the basaltic rocks (see Figure 8a). ...
... Injection of carbonated water has been proposed as a solution to this issue [10][11][12][13][14] . This method introduces an already stable and non-buoyant phase into the reservoir, which allows the storage of CO 2 directly by solubility trapping [14][15][16][17][18] . ...
... Injection of carbonated water has been proposed as a solution to this issue [10][11][12][13][14] . This method introduces an already stable and non-buoyant phase into the reservoir, which allows the storage of CO 2 directly by solubility trapping [14][15][16][17][18] . Moreover, waterdissolved CO 2 can also promote the dissolution of divalent metal bearing silicate minerals leading to the formation of carbonatite minerals xing the injected dissolved gas in the solid-state 17,19,20 . ...
... In this case, the use of surface dissolution yielded substantial cost savings compared to alternative CO 2 capture approaches. Alternatively, wellbore dissolution of CO 2 into water has been proposed and implemented as part of the original CarbFix1 project 14,61 . This approach combines the engineering bene ts of surface dissolution while avoiding most extra costs for cases where a pure CO 2 stream is available 13 . ...
Carbon capture and storage projects need to be greatly accelerated to attenuate the rate and degree of global warming. Due to the large volume of carbon that will need to be stored to address this issue, it is likely that the bulk of this storage will be in the subsurface via geologic storage. To be effective, subsurface carbon storage needs to limit the potential for CO 2 leakage from the reservoir to a minimum. Water-dissolved CO 2 injection can aid in this goal. Water-dissolved CO 2 tends to be denser than CO 2 -free water, and its injection leads immediate solubility storage in the subsurface. To assess the feasibility and limits of water-dissolved CO 2 injection coupled to subsurface solubility, a suite of geochemical modeling calculations based on the TOUGHREACT computer code were performed. The modelled system used in the calculations assumed the injection of 100,000 metric tons of water-dissolved CO 2 annually for 100 years into a hydrostatically pressured unreactive porous rock, located at 800 to 2000 m below the surface without the presence of a caprock. This system is representative of an unconfined sedimentary aquifer. Most selected scenarios suggest that the injection of CO 2 charged water leads to the secure storage of injected CO 2 so long as the water to CO 2 ratio is no less than ~24 to 1. The identified exception is when the salinity of the original formation water substantially exceeds the salinity of the CO 2 -charged injection water. The results of this study indicate that unconfined aquifers, a generally overlooked potential carbon storage host, could provide for the subsurface storage of substantial quantities of CO 2 .
... There are different approaches to CO 2 storage in the subsurface in terms of the phase of the injected CO 2 , the subsurface trapping mechanisms, and the corresponding reservoir prerequisites (Snaebjörnsdóttir et al., 2020). In the most common approach, supercritical CO 2 is injected into saline aquifers or depleted oil and gas fields for storage through structural, stratigraphic, and residual trapping (Sigfusson et al., 2015). Examples include the experimental sites Ketzin in Germany (Juhlin et al. 2007;Schilling et al. 2009;Bergmann et al. 2016Bergmann et al. , 2017, Otway in Australia (Underschultz et al. 2011;Pevzner et al. 2017), Quest and Weybun in Canada (Verdon et al., 2010), as well as the commercial offshore sites Sleipner (Furre et al. ,2017;Yan et al., 2019) and Northern Lights (Meneguolo et al., 2024) in Norway and Greensand in Denmark. ...
... Aside from the higher costs of capturing and storing CO 2 , compared to its release into the atmosphere and the purchase of corresponding emission quotas, there are also significant technological hurdles slowing the implementation of large-scale CO 2 mineral storage projects (Snaebjörnsdóttir et al., 2020;Smith et al., 2023): Suitable storage formations need to be identified, ideally within the vicinity of large carbon emitters (Snaebjörnsdóttir et al., 2020). Additionally, the large amounts of freshwater required, approximately 26 t per 1 t of CO 2 injected, is challenging in most regions of the world (Sigfusson et al., 2015). Wolff Boenisch et al. (2011) proposed overcoming this limitation by using saline water instead of freshwater for the CO 2 dissolution, which would also unlock large offshore storage potential in basaltic mid-ocean ridges (Snaebjörnsdóttir et al. 2014;Kopf et al. 2024). ...
In-situ CO2 mineral storage is moving into focus as a technology for storing substantial amounts of CO2 that would otherwise be released into the atmosphere. However, one of the main drawbacks of this technology is that it requires large amounts of freshwater for injection. To overcome this obstacle, a pilot project in Helguvik, Iceland is testing the effectiveness of carbon mineralization using saline water, similar to seawater. Here, we describe the project and the geophysical characterization of the pilot site using crosshole seismic- and single-hole electrical resistivity measurements. The data show that the subsurface strata are dominated by decameter-thick horizontal layers of basaltic strata, with varying seismic velocities and electrical resistivities. Variations in both seismic velocity and electrical resistivity are in excellent agreement and delineate high and low porosity zones in the subsurface. The results are compared to well logging results and the mineralogical composition of drill cuttings to build a comprehensive subsurface model of the future CO2 mineral storage reservoir, highlighting potential pathways for the injected CO2-charged waters.
... These findings align with Chevalier et al. (2010) and Ladner et al. (2023), who noted that Alpine rocks are predominantly metamorphic, with low porosity and permeability. Hydraulic stimulation could potentially enhance porosity and permeability (Al Kalbani et al., 2023;Kelemen and Matter, 2008), but it incurs additional financial and energy costs, as well as risks (Sigfusson et al., 2015;Hofmann et al., 2018); the induced seismicity risk associated with hydraulic stimulation often faces political and social resistance (L'Orange Seigo et al., 2014), though managing injection rates can mitigate this risk (Hofmann et al., 2018). ...
... Environmental issues and risks include water resource use (Brunner et al., 2019;Snaebjörnsdottir et al., 2020), leakage risk from CO 2 -charged water migration through groundwater flow (IEA, 2022;IPCC, 2005) and potential contamination of nearby aquifers (IEA, 2022;Li et al., 2018;Trias et al., 2017), as well as induced seismicity (Sigfusson et al., 2015;Snaebjörnsdottir and Gislason, 2016;Zoback and Gorelick, 2012). Other impacts of CCS activities, including those associated with the utilization of geological rock units, encompass atmospheric emissions, solid waste production, noise, and biodiversity effects (Chiang and Pan, 2017). ...
Carbon Capture and Storage (CCS) technologies play a critical role in achieving global and Swiss climate goals, particularly with Switzerland aiming to domestically store some of its residual CO 2 emissions. In situ mineralization presents a promising avenue for stable and permanent CO 2 sequestration. This study aims to evaluate the potential of CO 2 storage via in situ mineralization in the Swiss underground. A set of technical/geological criteria was defined and used to identify, evaluate, and classify the various geological formations. The selected areas identified and evaluated include alpine tectonic units with large volumes of mafic and ultramafic rocks. Despite the presence of suitable rock types, these units are marked by alpine deformation with highly complex structures, rock mixtures, and complex bedrock hydrogeology. The old, altered, and metamorphic nature of the alpine mafic and ultramafic rock formations results in minimal permeability and porosity, consequently impeding CO 2 injectivity and mineralization kinetics, particularly given the low average geothermal gradient. Additionally, challenges related to water resource requirements, storage site location and accessibility, financial costs, regulation, social acceptance, and environmental impacts further impact feasibility negatively. This study concludes that CO 2 sequestration via in situ mineralization in the Swiss context is unfeasible in the near term and possibly unsuitable in the long one.
... This project improved the storage security of injected CO 2 by injecting CO 2 already dissolved in water into the formations (Sigfússon et al., 2015) and by injecting into fresh basalts. ...
... The result of the pilot run was that more than 95% of the injected CO 2 was mineralised within two years after the injection started (Matter et al., 2016). After this success, the project was expanded with another reinjection site at Hellisheiði in the CarbFix2 project where reinjection started in 2014 (Sigfússon et al., 2015). This second field has become the major reinjection site at Hellisheiði. ...
As part of the SUCCEED project, investigating CO reinjection with different seismic methods, both passive and active seismic surveys have been conducted at the geothermal power plant at Hellisheii, Iceland. During the 2021 survey, two geophone lines recorded noise for a week. We process the passive‐source data with seismic interferometry to image the subsurface structure around the CarbFix2 reinjection reservoir. To improve image quality, we perform an illumination analysis to select only noise panels dominated by body‐wave energy. The results show that most noise panels are dominated by air‐wave energy arriving from the direction of the power plant. We use panels with a near‐vertical incidence to create a zero‐offset image and a larger selection of body‐wave‐dominated panels to create virtual common‐shot gathers. We process the gathers with a simple reflection seismology processing workflow to obtain stacked images. The zero‐offset images show a relatively lower signal‐to‐noise ratio and only horizontal reflectors. The stacked images show slightly dipping reflectors and possibly lateral amplitude variations around the expected injection region. This could indicate a region of interest for future research into the reinjection reservoir.
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... The practice of in-line dissolution of geogenic CO2 into geothermal reinjection wells was pioneered during the Carbfix project in 2012 at the Hellisheidi geothermal power plant in Iceland (Sigfusson et al., 2015). The goal was to capture CO2 and H2S that would otherwise be vented to atmosphere from the plant's cooling system . ...
... Further, CO2 is more likely to stay dissolved if reservoir pressure is maintained (Kaya & Zarrouk, 2017), which is promoted under the standard reservoir management practice of reinjection of produced fluids. Finally, with favourable geology, subsurface chemical rock reactions can allow reinjected CO2 to mineralise, a nigh permanent form of storage (Marieni et al., 2018;Sigfusson et al., 2015). At Carbfix, chemical tracer testing showed that 98% of the reinjected geogenic CO2 mineralised within two years. ...
Limiting global temperature rise to between 1.5 and 2°C will likely require widespread deployment of carbon dioxide removal (CDR) technologies for sectors with hard-to-abate emissions. As financial resources for decarbonization are finite, strategic deployment of CDR technologies is essential for maximizing atmospheric CO2 reductions. Carbon capture and sequestration (CCS), using either direct air capture (DACCS) or bioenergy (BECCS) technologies has a particular synergy with geothermal energy generation. This is because it can leverage expensive geothermal infrastructure for dissolved CO2 storage in subsurface reservoirs.Here, we argue that the use of existing well apparatuses and a lack of offsite CO2 transportation costs substantially improves the economic feasibility of geothermal-based CDR schemes over traditional approaches. We further argue that revenues from net-negative CO2 emissions and increased power production should be used to lower the net costs of decarbonization activities.To test these ideas, we compared the techno-economic performance of geothermal-BECCS and geothermal-DACCS plant designs against conventional geothermal operations. We did this using a systems model that quantifies energy, carbon and financial flows through those designs. At a CO2 market price of 69/MWh) than geothermal-DACCS (81/MWh). New geothermal-BECCS plants also achieved the lowest costs of emissions abatement, 41/tCO2, for BECCS retrofit of existing geothermal plants due to pre-existing infrastructure (wells, steam field, plant).Although geothermal-DACCS removes CO2 at high rates, its high parasitic load increases the overall decarbonization cost ($197/tCO2). In contrast, when biomass hybridization is considered, geothermal-BECCS produced 20% more electricity than the benchmark geothermal plant. We conclude that this increase in electricity production makes geothermal-BECCS the more cost-effective geothermal-based CDR configuration.
... The co-injection of CO 2 (or NCGs) and water (or brine) is a technique that has been promoted to avoid these issues and enhance mineralization (under suitable conditions) [7]. The co-injection may take place under either single-or two-phase flow conditions and the two phases (gas and water) can be mixed either on the surface before the injection well [8][9][10][11][12][13][14][15][16] or directly in the injection well at a certain depth [17][18][19][20][21]. The single-phase co-injection requires that the gas is completely dissolved in the liquid stream. ...
... These relied on the co-injection of water and CO 2 as a single-phase (liquid with pre-dissolved gas at high pressure). The original Carbfix [17] approach aimed to co-inject water and soluble gases into the subsurface in two separate streams at the surface level. Gas was released as fine bubbles into the water at depth and was completely dissolved into the geothermal brine stream before it entered the porous aquifer rocks. ...
... Injection of carbonated water has been proposed as a solution to this issue 10-14 . This method introduces an already stable and non-buoyant phase into the reservoir, which allows the storage of CO 2 directly by solubility trapping [14][15][16][17][18] . Moreover, water-dissolved CO 2 can also promote the dissolution of divalent metal-bearing silicate minerals leading to the formation of carbonate minerals fixing the injected dissolved gas in the solid-state 17,19-22 . ...
... In this case, the use of surface dissolution yielded substantial cost savings compared to alternative CO 2 capture approaches. Alternatively, wellbore dissolution of CO 2 into water has been proposed and implemented as part of the original CarbFix1 project 14,65 . This approach combines the engineering benefits of surface dissolution while avoiding most extra costs for cases where a pure CO 2 stream is available 13 . ...
Carbon capture and storage projects need to be greatly accelerated to attenuate the rate and degree of global warming. Due to the large volume of carbon that will need to be stored, it is likely that the bulk of this storage will be in the subsurface via geologic storage. To be effective, subsurface carbon storage needs to limit the potential for CO 2 leakage from the reservoir to a minimum. Water-dissolved CO 2 injection can aid in this goal. Water-dissolved CO 2 tends to be denser than CO 2 -free water, and its injection leads immediate solubility storage in the subsurface. To assess the feasibility and limits of water-dissolved CO 2 injection coupled to subsurface solubility storage, a suite of geochemical modeling calculations based on the TOUGHREACT computer code were performed. The modelled system used in the calculations assumed the injection of 100,000 metric tons of water-dissolved CO 2 annually for 100 years into a hydrostatically pressured unreactive porous rock, located at 800 to 2000 m below the surface without the presence of a caprock. This system is representative of an unconfined sedimentary aquifer. Most calculated scenarios suggest that the injection of CO 2 charged water leads to the secure storage of injected CO 2 so long as the water to CO 2 ratio is no less than ~ 24 to 1. The identified exception is when the salinity of the original formation water substantially exceeds the salinity of the CO 2 -charged injection water. The results of this study indicate that unconfined aquifers, a generally overlooked potential carbon storage host, could provide for the subsurface storage of substantial quantities of CO 2 .
... Each mechanism has a discrete capacity, storing time, and storage security [8,[11][12][13]. Their efficiencies also depend on the types of geological units and environmental conditions [14][15][16][17][18]. The mineral trap is currently considered to be the most stable permanent CO 2 storage as the CO 2 is turned into solid carbonate phases through a process called CO 2 mineralization [9,10,12,14,[19][20][21][22][23][24][25][26]. ...
Mafic and ultramafic rocks have become a promising approach for atmospheric carbon dioxide (CO2) reduction, as they are major sources of CO2-reactive minerals, i.e., olivine, pyroxene, plagioclase, and serpentine. The minerals potentially sequester CO2 by turning it into a stable solid phase through carbon mineralization in the rock weathering process. However, detailed descriptions and evaluations of the target formations are lacking. This study investigates the mineralogical composition and microtextural characteristics of representative mafic and ultramafic rocks observed in northern Thailand, using a petrographic analysis. The results show that variations in CO2-reactive mineral assemblages of rocks certainly affect their theoretical CO2 uptake potential. Ultramafic rocks tend to sequester larger amounts of CO2 than mafic rocks. The microtextural observation reveals the mineral size ranges of 0.05–5 mm for ultramafic and mafic intrusive rocks and 0.01–2 mm for mafic extrusive and metamorphosed rocks. Reducing the rock size to be equal to the average size of the reactive minerals could be considered one of the practical designs in enhanced rock weathering activities. Understanding the mineralogical and textural characteristics of target rocks thus plays a crucial role in further georesource exploration and engineering designs, supporting climate action strategies on various scales.
... Therefore, the design of dissolving CO 2 in water before underground injection is considered (see Fig. 5a). In phase 1 (CarbFix1), a total of 230 tons of CO 2 were injected, comprising two separate injections of 175 tons of pure CO 2 > 1000 t/a n/a and 73 tons of mixed gas (75 mol% CO 2 , 24 mol% H 2 S, and 1 mol% H 2 ) (Sigfusson et al. 2015;Gislason et al. 2010;Galeczka et al. 2022). ...
The substantial emissions of greenhouse gases, particularly CO 2 , constitute a primary driver of global warming. CCUS is proposed as an effective mitigation strategy which is often estimated to account for about 15% of cumulative carbon emission reduction. In-situ CO 2 mineralization sequestration, compared to conventional geological storage methods such as depleted oil and gas reservoirs, unmineable coal seams, and deep saline aquifers, offers the advantage of permanent immobilization of injected carbon. However, uncertainties persist regarding the characteristics of geochemical interactions under reservoir pore conditions, as well as the kinetic mechanisms of mineralization reactions. Additionally, geochemical reactions may lead to solid particle transport and deposition, potentially causing pore throat occlusion. Pilot projects in Iceland and the United States have demonstrated the feasibility of this technology, but the field remains in the early deployment stage. In this review, the mechanisms of in-situ mineralization have been elucidated, the primary factors influencing the reaction kinetics have been discussed, and the current research status in this field has been summarized. It is emphasized that establishing a reliable system for evaluating storage capacity and understanding the kinetic mechanisms governing CO 2 conversion into minerals at multi-phase interfaces are key priorities for future work.
... 46,47 A sparger was used to disperse CO 2 in water. 48,49 By adopting this method, challenges such as corrosion are prohibited, and recommendations on minimum water content in the CO 2 stream during transportation can be appropriately regarded. ...
CO2 storage in geological formations, particularly deep saline aquifers, is a critical component of carbon capture and storage technology, offering significant potential for mitigating greenhouse gas emissions. However, high salinity of these aquifers poses the risk of salt precipitation, leading to pressurization and injectivity reduction. Developing a method to prevent salt precipitation remains a challenge, and this is an area that this study is focused on. Dissolved-water CO2 injection (dwCO2 injection) is proposed here as a novel method to prevent salt precipitation where water is dissolved in CO2 before injection into an aquifer. Presence of water in the CO2 stream prevents more dissolution of water into CO2 (evaporation) and, hence, prevents salt precipitation. Before presenting this method and in order to provide a good mechanistic understanding of the interactions involved in a CO2 storage process, six different scenarios are examined using the CMG-GEM simulator within a carbonate aquifer. The results showed that saturating CO2 with water reduced the precipitation nearly to zero, and dissolving 2000 ppmv water decreased the salt precipitation to one-third. It should be noted that injection of humid CO2 requires special methods to tackle the potential challenges, including corrosion and hydrate formation risks, and the paper also discusses them.
... It can also provide improved safety for such operations as it reduces the mobility of carbon dioxide, preventing it from escaping through a fracture network. However, this approach presents a plethora of challenges and drawbacks, with pressure build-ups and increased costs, to name a few [14]. Therefore, in this project, the injection of supercritical carbon dioxide is taken into consideration. ...
This study presents an in-depth analysis of the variability in numerical simulations of supercritical carbon dioxide injection and storage. The project focuses on the impact of the grid size and different calculation methods on the outcomes of the simulation. navigator software has been utilized as the simulator of choice, whereas the three simulation models in question were based on the CO2STORE, CO2SOL, and GASSOL (with Henry solubility enabled) keywords. The simulation runs were conducted on a homogeneous, rectangular prism that represented an aquifer. The model underwent a three-year injection process followed by a 100-year-shut-in period that allowed for observations regarding CO2 plume development and migration. The initial conditions were aligned with the Illinois Basin - Decatur Project. The study compares the efficiency of carbon dioxide dissolution mechanisms across all models as well as highlights the impact of the grid size on the plume area estimations and computational demand.
... First, for carbon mineralization in serpentinite, the CO 2 gets dissolved in water forming HCO 3 -(e.g. Sigfusson et al., 2015;Doucet et al., 2023), through reaction: ...
... However, the Natih saline aquifers and the stratigraphic units below the Natih reservoirs remain potential targets, particularly south and west of the Fahud area (Fig. 4). In South and Central Oman, the Natih Formation is generally shallower than 800 m and, therefore, cannot be used to store CO 2 in its supercritical state (Sigfusson et al. 2015). Natih's top seal is also absent or very thin in South Oman. ...
This work presents an overview of the surface and subsurface carbon capture and storage (CCS) opportunities, and their associated risks, in Oman. Oman's stratigraphy encompasses various rock sequences that can be harnessed for CCS purposes. The ultramafic rocks of the Samail Ophiolite have long been researched for their ability to permanently sequestrate CO 2 near the surface, whilst the well-studied subsurface sequences also offer storage opportunities for CO 2 , particularly in deeply buried clastic and carbonate saline aquifers. Structural and stratigraphic traps could hold potential for carbon disposal. Producing hydrocarbon fields can also be considered for CCS, either to enhance hydrocarbon production from existing reservoirs or by utilising deep traps for disposal. Oman's Late Proterozoic to Cambrian evaporites could be utilised to create large underground salt caverns for storing hydrogen and less-attractively CO 2 . The identified CCS opportunities are ranked based on different criteria. Using injected CO 2 to enhanced hydrocarbon recovery by providing additional reservoir pressure support, using depleted hydrocarbon fields for CO 2 storage, and the injection of CO 2 in deep clastic saline aquifers rank among the main opportunities for CCS in Oman.
... CO 2 is injected in the subsurface after being dissolved in water, at low over-pressures and shallow depth (a few hundreds of metres) in highly permeable locations. Injection of dissolved CO 2 enhances trapping safety as solubility has already taken place, while risk of leakage to the surface is limited since the injected fluid is not buoyant (Sigfusson et al., 2015). Finally, CO 2 injection at shallow depths results in reduced drilling and monitoring cost. ...
... In contrast, brine vapourization also increases the salt concentration due to the salting effect, which causes injectivity decline (Pruess & Müller, 2009). The dissolved CO 2 in formation brine will produce carbonic acid that lowers the pH to about 3-4, which has a significant impact on the rock properties such as permeability and porosity (Schaef & McGrail, 2005; OTC-34792-MS Sigfusson et al., 2015;Zou et al., 2018). This reaction leads to ion-dissolution precipitation and generates fine particles, considered secondary minerals, into the pore fluid and reduces the permeability. ...
A "business-as-usual" approach to the increasing anthropogenic CO2 emissions would exacerbate the issues of climate change and global warming, which have devastating impacts. Given this, measures are currently rolled out to mitigate these global challenges. CO2 capture and storage (CCS) has proven to support the realization of a carbon-neutral society by 2050. Saline aquifers, with their porous and permeable properties, have gained prominence as potential storage reservoirs for CO2 sequestration. However, the CO2 injectivity in saline aquifers could be curtailed by challenges such as permeability impairment, which is triggered by the CO2-brine-rock interactions. Permeability impairment (or simply injectivity loss) could be influenced by the thermophysical conditions and injected CO2 characteristics. Moreover, these factors dictate the effectiveness of CO2 storage via the solubility trapping mechanism. The study therefore explored the impact of pressure and temperature variations, and the injected CO2 phase on the CO2 injectivity alteration during CO2 injection in saline aquifers. Coreflooding experiments were conducted on high-quartz Berea sandstone samples using a 30000 ppm (3wt%) NaCl brine. The thermophysical conditions were varied from 900 to 2000 psi for pressure and 27 and 60°C for temperature to evaluate the impact of different CO2 phases (gas, liquid, and supercritical) on injectivity impairment. Additionally, pressure and temperature ranges of 1400 to 4000 psi and 40 to 100°C were selected to investigate their influence on injectivity impairment during CO2 injection into saline aquifers. These thermophysical conditions represent those of warm-shallow, warm-deep, cold-shallow, and cold-deep storage basins. The injection rate was kept constant at 2 mL/min in all experiments to capture near-wellbore fluid flow conditions. The relative injectivity change (RIC) was computed post-CO2 injection to comprehend the extent of injectivity alteration and identify the optimum conditions for CO2 injection in saline aquifers. Subsequently, petrographic, and effluent analyses were employed to corroborate permeability measurements before and after CO2 injection. Experimental findings revealed that the severity of formation damage is temperature-dependent, decreasing up to 80°C, beyond which an increase in potential damage is observed. The key findings from the study underscore the temperature-dependent nature of CO2 solubility saturation, the influence of pressure up to saturation points, and the plateauing effect at higher temperatures. This study contributes essential knowledge to the field, emphasizing the intricate relationship between pressure, temperature, and CO2 injectivity alteration. The findings also provide a robust foundation for the development of a comprehensive predictive model to enhance our ability to optimize CO2 storage and achieve global net-zero targets.
... For an offshore reservoir, a sedimentary seal overlying the volcanic packages may be the best alternative (Planke et al. 2021). However, the CarbFix method of injecting CO 2 dissolved in water removes the need for a caprock as the fluid is no longer buoyant and represents an alternative storage method used at the CarbFix injection sites Sigfusson et al. 2015;Gunnarsson et al. 2018). ...
Offshore CO2 sequestration in basaltic formations of the North Atlantic Igneous Province (NAIP) may allow permanent storage of large volumes of CO2 through rapid carbonate mineralization. Characterizing the internal architecture of such reservoirs is key to assessing the storage potential. In this study, six photogrammetry models and three boreholes on the Faroe Islands have been used to characterize the internal lava sequence architectures as a direct analogue to potential offshore NAIP storage sites. The studied formations are dominated by ca. 5 m to 50 m thick simple and compound lava flows, with drill core observations documenting a transition from pāhoehoe moving towards ‘a’ā lava flow types interbedded with thin (<5 m thick) volcaniclastic rock units. The identification of flow margin breccias is potentially important as these units form excellent reservoirs in several other localities globally. Stacked, thick simple flows may present sealing units associated with dense flow interiors. Connected porous and permeable lava flow crusts present potential reservoirs, however, the degree of secondary mineralization and alteration can alter initially good reservoir units to impermeable barriers for fluid flow. Large-scale reservoir volumes may be present mainly within both vesicular, fractured pāhoehoe and brecciated flow margins of transitional simple lava flows.
... The target injection formation is at a depth of 400e800 m, with a porosity of 8.5% and horizontal and vertical permeabilities of 300 and 1700 mD, respectively. The temperature ranges from 20 to 50 C, and the pH is between 8.4 and 9.4 (Sigfusson et al., 2015). The chemical composition is olivine tholeiite, consisting of basaltic lava and hyaloclastite (Alfredsson et al., 2008). ...
Global warming has greatly threatened the human living environment and carbon capture and storage (CCS) technology is recognized as a promising way to reduce carbon emissions. Mineral storage is considered a reliable option for long-term carbon storage. Basalt rich in alkaline earth elements facilitates rapid and permanent CO2 fixation as carbonates. However, the complex CO2-fluid-basalt interaction poses challenges for assessing carbon storage potential. Under different reaction conditions, the carbonation products and carbonation rates vary. Carbon mineralization reactions also induce petrophysical and mechanical responses, which have potential risks for the long-term injectivity and the carbon storage safety in basalt reservoirs. In this paper, recent advances in carbon mineralization storage in basalt based on laboratory research are comprehensively reviewed. The assessment methods for carbon storage potential are introduced and the carbon trapping mechanisms are investigated with the identification of the controlling factors. Changes in pore structure, permeability and mechanical properties in both static reaction and reactive percolation experiments are also discussed. This study provides insight into challenges as well as perspectives for future research.
... Assessing the long-term stability of CO 2 storage and the potential for leakage pathways in basalt formations is a critical challenge [226]. Monitoring techniques must be developed to accurately detect and quantify the migration and fate of CO 2 within the reservoir over extended periods. ...
The underground storage of CO2 (carbon dioxide) in basalt presents an exceptionally promising solution for the effective and permanent sequestration of CO2. This is primarily attributed to its geochemistry and the remarkable presence of reactive basaltic minerals, which play a pivotal role in facilitating the process. However, a significant knowledge gap persists in the current literature regarding comprehensive investigations on the reactivity of basaltic minerals in the context of CO2 sequestration, particularly with respect to different basalt types. To address this gap, a comprehensive investigation was conducted that considered seven distinct types of basalts identified through the use of a TAS (total alkali–silica) diagram. Through a thorough review of the existing literature, seven key factors affecting the reactivity of basaltic minerals were selected, and their impact on mineral reactivity for each basalt type was examined in detail. Based on this analysis, an M.H. reactivity scale was introduced, which establishes a relationship between the reactivity of dominant and reactive minerals in basalt and their potential for carbonation, ranging from low (1) to high (5). The study will help in choosing the most suitable type of basalt for the most promising CO2 sequestration based on the percentage of reactive minerals. Additionally, this study identified gaps in the literature pertaining to enhancing the reactivity of basalt for maximizing its CO2 sequestration potential. As a result, this study serves as an important benchmark for policymakers and researchers seeking to further explore and improve CO2 sequestration in basaltic formations.
... More recently, the study of mineral precipitation in porous media has received increased attention in the context of geological carbon storage (Jiang and Tsuji 2014;Sigfusson et al. 2015;Matter et al. 2016;Snaebjornsdottir et al. 2017). To this end, many studies have shown that mineralization and precipitation of salts in porous media can decrease the effective permeability and porosity of the rock formation, leading to a significant increase in the pressure drop and a decrease in injectivity and storage capacity (Singurindy and Berkowitz 2023;Peysson et al. 2014;Andre et al. 2014;Ott et al. 2015;Miri and Hellevang 2016). ...
In this study, we experimentally investigate fluid–fluid displacement in a Hele–Shaw cell where the two fluids react, upon mixing, to form solid precipitates. Under the conditions of our experiments, we observe that precipitation reaction along the moving fluid–fluid interface generates solids in the form of mineral particle suspensions. We find that both electrostatic and hydrodynamic forces control the extent of particle–particle agglomeration during the suspension flow. Such particle suspension decreases the overall mobility of the multiphase mixture, thus altering the overall displacement. Although the injected fluids are viscously stable, the precipitation band that forms between the fluids becomes unstable to form finger-like flow channels compartmentalized by solid-deposited walls and clusters. We show that the emergence, growth and decay of the fingering pattern are strongly influenced by the injection rate and the initial fluid chemical concentrations. In addition, we show that precipitation-induced fingering has a strong feedback on fluid–fluid mixing and the subsequent precipitation rate. Lastly, we find that, counter to intuition, a higher injection rate results in a larger amount of precipitates that are securely deposited in the Hele–Shaw cell.
... Large-scale CO 2 sequestration projects carry significant pressure management requirements due to the volumes in question, especially in the option of CO 2 solution injection (Bryant, 2013;Pool et al., 2013). These can be ameliorated to some degree by choosing to inject into depleted hydrocarbon fields (Jenkins et al., 2012), areas of natural underpressure such as actively deglaciating regions (Bekele and Rostron, 2003), or unconfined aquifers (Sigfusson et al., 2015). The storage volume potential of a prospective CO 2 sequestration site is difficult to estimate due to the absence of storage efficiency information in large-scale projects, and various estimating methodologies are available (De Silva and Ranjith, 2012). ...
Geologic carbon storage (GCS) is a fundamental pillar of carbon management that helps mitigate greenhouse gas emissions and addresses the negative effects of climate change. Viable CO 2 storage sites share some of the same elements required for successful petroleum systems. For example, while reservoir, seal, and trap are required, migration pathway and timing are not important for CO 2 storage, because rather than withdrawing fluid from a trap, CO 2 storage involves injection into a geologic trap. Conceptually, this represents a form of reverse production. Numerous petroleum traps around the world, as well as naturally occurring CO 2 -producing fields and natural gas storage sites attest that safe, long-term storage is possible. Research over the past two decades identified five methods of Geologic Carbon Storage which have been validated through several demonstration and pilot projects around the world: (1) storage in depleted oil and gas fields, (2) use of CO 2 in enhanced hydrocarbons recovery (3) storage in saline formations/aquifers, (4) injection into deep unmineable coal seams, and (5) in-situ / ex-situ carbon mineralization. The greatest volumetric potential for GCS is found in saline aquifers which are present throughout the world’s sedimentary basins.
... In fact, this reaction also exists in nature, namely silicate weathering, which occurs on geological time scales. However, artificial mineral storage can significantly shorten the time required for carbon fixation and consume atmospheric carbon dioxide since the solubility trapping occurs immediately after the injection [39]. Within two years of injection at 20-50 C, the vast majority of the carbon is trapped as carbonate minerals [40,41]. ...
... monitoring in 2012, and industrial-scale operation began in 2014 (Gíslason et al., 2018). In all Carbfix injections, CO 2 is dissolved in water before or during injection (Gunnarsson et al., 2018;Sigfusson et al., 2015). Dissolving the CO 2 in water removes the need for a caprock as the gas is no longer buoyant, as well as dramatically reducing the time needed to achieve CO 2 mineral trapping. ...
Offshore injection of CO2 into volcanic sequences of the North Atlantic Igneous Province may present a large- scale, permanent storage option through carbonate mineralization. To investigate this potential, onshore studies of reservoir properties and reactivity of the subaerially erupted Faroe Islands Basalt Group have been conducted. Outcrop and borehole samples reveal that the lava flow crusts commonly contain vesicles that have been filled with secondary minerals due to hydrothermal fluid circulation, however, unmineralized and highly porous layers do occur. Bulk density measurements, micro-computed tomography (μ-CT) image analysis, and microscope studies of samples from onshore boreholes give present-day porosities ranging from 0.5% to 36.2% in the volcanic sequences. The unmineralized brecciated lava flow crusts contain the largest estimated porosity and simulated absolute permeability (reaching up to 10− 12 m2). μ-CT studies of the mineralized, brecciated flow crusts indicate initial porosities reaching up to 45%, before clogging. Kinetic experiments of rock dissolution show that the reactivity of the basalt and volcaniclastic sediments depends on the alteration state with more altered basalt being less reactive. However, the presence of reactive, high porosity, and high permeability flow crusts prior to clogging indicate the existence of promising and very large CO2 reservoirs in less altered offshore sequences.
... Being injected as a dissolved phase instead of a free phase reduces issues related to poor sweep efficiency, gas fingering, and gravity segregation (Riazi et al. 2011;Mosavat and Torabi 2014;Bisweswar et al. 2020;Esene et al. 2019). Because CO 2 is no longer buoyant, it eliminates the necessity of choosing deep [≥800 m (2,600 ft)] formations for injection, and the caprock integrity is less relevant (Sigfusson et al. 2015). Also, CWI has a higher density and viscosity than the formation water due to CO 2 dissolution (Ohsumi et al. 1992;Garcia 2001), causing the carbonated water (CW) to sink and thus eliminating the risk of buoyancy-driven leakage (Burton and Bryant 2009;Mosavat and Torabi 2014). ...
This paper describes the study of dissolution and mineralogical alteration caused by saline carbonated water injection (CWI) and its effects on the petrophysical properties (porosity and permeability) of limestone samples from the Mupe Member, composed of lacustrine microbialites from the Upper Jurassic, part of the Purbeck Group lower portion. These limestones are a partial analog of the Brazilian presalt Aptian carbonates, the most important oil reservoir in Brazil. These reservoirs present large amounts of CO2 that are reinjected into the formation, which given the high reactivity of carbonate rocks in the presence of carbonic acid generated by the reaction between CO2 and water, can cause damage to the rock’s pore space. To achieve the proposed objectives, four laminated/massive samples with very low permeability (<5 md) and two vuggy/microbial samples with very high permeability (>1,700 md) underwent laboratory tests carried out before, during, and after CWI, including gas porosity and permeability measurement, nuclear magnetic resonance (NMR), microcomputed tomography (micro-CT), and ion chromatography. X-ray diffraction (XRD) analysis and petrographic thin-section observations were also performed. The experimental results showed that samples with high permeability showed a small decrease in permeability, possibly indicating formation damage, while low-permeability samples presented a significant increase in permeability with little change in porosity, indicating feasibility for carbon capture and storage (CCS) in similar samples in likewise experimental conditions (20°C and 500 psi). For samples with more pore volumes injected, the pressure stabilization seems to have favored dissolution in the later injection stages, indicated by the highest output of calcium ions. In all samples occurred salt precipitation during injection, especially in the more heterogeneous rocks, presenting a possible issue.
... Since the dissolved CO 2 is not buoyant, the fluid injected into the reservoir is in fact denser than the surrounding reservoir fluid due to the presence of CO 2 , so it will not rise. As a result, solubility trapping takes place rapidly and no cap rock is needed to seal the CO 2 in Sigfusson et al. (2015). The gas-charged water aids metals release from the basalts, like iron, magnesium and calcium, which react with the injected CO 2 to form carbonates, like siderite, magnesite, and calcite, respectively, which results in permanent geological storage of the CO 2 (Snaebjörnsdóttir et al., 2017). ...
As the concentration of carbon dioxide (CO2) in the atmosphere continues to rise, and the reality of global warming challenges hits the world, global research societies are developing innovative technologies to address climate change challenges brought about by high atmospheric concentration of CO2. One of such challenges is the direct removal of CO2 from the atmosphere. Among all the currently available CO2 removal technologies, direct air capture (DAC) is positioned to deliver the needed CO2 removal from the atmosphere because it is independent of CO2 emission origin, and the capture machine can be stationed anywhere. Research efforts in the last two decades, however, have identified the system overall energy requirements as the bottleneck to the realization of DAC’s commercialization. As a result, global research community continues to seek better ways to minimize the required energy per ton of CO2 removed via DAC. In this work, the literature was comprehensively reviewed to assess the progress made in DAC, its associated technologies, and the advances made in the state-of-the-art. Thus, it is proposed to use traditional heating, ventilation, and air conditioning (HVAC) system (mainly the air conditioning system), as a preexisting technology, to capture CO2 directly from the atmosphere, such that the energy needed to capture is provided by the HVAC system of choice.
Mineral carbon storage in mafic and ultramafic rock masses has the potential to be an effective and permanent mechanism to reduce anthropogenic CO2. Several successful pilot‐scale projects have been carried out in basaltic rock (e.g., CarbFix, Wallula), demonstrating the potential for rapid CO2 sequestration. However, these tests have been limited to the injection of small quantities of CO2. Thus, the longevity and feasibility of long‐term, large‐scale mineralization operations to store the levels of CO2 needed to address the present climate crisis is unknown. Moreover, CO2 mineralization in ultramafic rocks, which tend to be more reactive but less permeable, has not yet been quantified. In these systems, fractures are expected to play a crucial role in the flow and reaction of CO2 within the rock mass and will influence the CO2 storage potential of the system. Therefore, consideration of fractures is imperative to the prediction of CO2 mineralization at a specific storage site. In this review, we highlight key takeaways, successes, and shortcomings of CO2 mineralization pilot tests that have been completed and are currently underway. Laboratory experiments, directed toward understanding the complex geochemical and geomechanical reactions that occur during CO2 mineralization in fractures, are also discussed. Experimental studies and their applicability to field sites are limited in time and scale. Many modeling techniques can be applied to bridge these limitations. We highlight current modeling advances and their potential applications for predicting CO2 mineralization in mafic and ultramafic rocks.
The objective of this paper is to explore a novel environment for carbon sequestration. Mid ocean ridge hydrothermal systems flow enormous volumes of water through vesicular porosity and natural fracture systems in basalt. Since the basic premise of carbon mineralization projects is to dissolve carbon dioxide in water and react the resulting carbonate ions with minerals in mafic or ultramafic igneous rock, the presence of so much natural flow through such rocks presents an opportunity. The proposed concept is to inject carbon dioxide in or near natural seawater intakes associated with these hydrothermal systems. Snæbjörnsdóttir and Gislason (2016) assessed the carbon dioxide sequestration potential in basalt offshore Iceland and concluded that up to 7000 GtCO2 could be stored offshore Iceland within its exclusive economic zone, so volumes of basalt are not a limiting factor.
The increasing level of anthropogenic CO2 in the atmosphere has made it imperative to investigate an efficient method for carbon sequestration. Geological carbon sequestration presents a viable path to mitigate greenhouse gas emissions by sequestering the captured CO2 deep underground in rock formations to store it permanently. Geochemistry, as the cornerstone of geological CO2 sequestration (GCS), plays an indispensable role. Therefore, it is not just timely but also urgent to undertake a comprehensive review of studies conducted in this area, articulate gaps and findings, and give directions for future research areas. This paper reviews geochemistry in terms of the sequestration of CO2 in geological formations, addressing mechanisms of trapping, challenges, and ways of mitigating challenges in trapping mechanisms; mineralization and methods of accelerating mineralization; and the interaction between rock, brine, and CO2 for the long-term containment and storage of CO2. Mixing CO2 with brine before or during injection, using microbes, selecting sedimentary reservoirs with reactive minerals, co-injection of carbonate anhydrase, and enhancing the surface area of reactive minerals are some of the mechanisms used to enhance mineral trapping in GCS applications. This review also addresses the potential challenges and opportunities associated with geological CO2 storage. Challenges include caprock integrity, understanding the lasting effects of storing CO2 on geological formations, developing reliable models for monitoring CO2–brine–rock interactions, CO2 impurities, and addressing public concerns about safety and environmental impacts. Conversely, opportunities in the sequestration of CO2 lie in the vast potential for storing CO2 in geological formations like depleted oil and gas reservoirs, saline aquifers, coal seams, and enhanced oil recovery (EOR) sites. Opportunities include improved geochemical trapping of CO2, optimized storage capacity, improved sealing integrity, managed wellbore leakage risk, and use of sealant materials to reduce leakage risk. Furthermore, the potential impact of advancements in geochemical research, understanding geochemical reactions, addressing the challenges, and leveraging the opportunities in GCS are crucial for achieving sustainable carbon mitigation and combating global warming effectively.
Silicate weathering is a natural regulator of atmospheric carbon dioxide (CO 2 ), where the majority of carbonate is stored in the oceans. In some instances, carbonates may form via bedrock weathering in terrestrial landscapes, but this is commonly noted in ultramafic rock due to its desirable mineralogy. In Northwest Scotland, carbonate minerals surround felsic, intermediate, and mafic igneous bedrock. Their abundance suggests that these rocks could potentially be targeted for carbonation, given the absence of other known cation sources nearby. We present geochemical and mineralogical data for bedrock samples and mineralogy and stable carbon and oxygen isotope data for the carbonate samples. Whole rock geochemistry demonstrates that major abundancies of CaO and MgO are present in the bedrock samples and would be sourced from plagioclase and pyroxene minerals which are target minerals for CO 2 mineralisation. The stable carbon and oxygen isotope data demonstrate that there are likely mixed carbon sources (atmospheric and organic), while other environmental factors including temperature, CO 2 degassing/ evaporation, and nearby waters influence the isotopic composition. Results suggest that rocks traditionally overlooked in CO 2 mineralisation studies have the potential to serve as a feedstock for carbonation, given the abundance of secondary carbonates found in NW Scotland.
Basaltic rocks, owing to their vast geological presence, have been identified as potential reservoirs for carbon dioxide (CO2) sequestration. Their inherent attributes, namely, a pronounced mineral trapping capability, distinct structural intricacies, and a potential storage capacity surpassing 100Gt, earmark them as prime candidates for CO2 storage. However, knowledge gaps exist in understanding the modifications in the petrophysical and mechanical characteristics of these rocks post-CO2 sequestration. Comprehending these CO2-induced petrophysico-mechanical alterations is crucial for assessing their potential for long-term carbon mineralization-based storage. Thus, this study provides a critical review of key parameters that can induce post-CO2 injection changes in the mechanical and petrophysical properties of basaltic rocks. Also, the implications of these changes for long-term CO2 storage efficiency in Basaltic rocks are succinctly presented. Findings from this review work show that the mineralogical composition of basaltic rocks can alter the petrophysical and mechanical behaviors during CO2 injection. The reaction processes tend to enhance CO2 storage and mineralization via an increase in the porosity of the basaltic tuff, which was caused mainly by their dissolution. Laboratory simulations of CO2 storage in basaltic rocks had revealed that when the experiment was run for a longer length of time, the distribution/concentration of reaction minerals, reaction rates of the minerals, and/or permeability development of the rock matrix either decreased, increased, or remained the same. Furthermore, the strength indices for all types of basalts demonstrate that as exposure duration increases, the material strength steadily decreases. Core experiments and laboratory simulations have revealed that permeability increased at a higher flow rate and decreased at a lower flow rate. This is because a higher flow rate (increased injection pressure) will yield more pore spaces. Also, precipitation of carbonate minerals is favored under alkaline conditions since this condition necessitates increased production of divalent cations. Understanding these changes is essential since they can be detrimental to the immediate environment of the storage site, especially when there is CO2 leakage and consequent contact with freshwater resources. Similarly, we highlighted how several reports have correlated the occurrence of low-scale seismic events bounding the storage sites, to CO2 storage. Lastly, based on the reviews synthesized, we recommend promising directions to provide more profound insights into CO2 storage in basaltic rocks.
The CO2 trap mechanisms during carbon capture and storage (CCS) are classified into structural, residual, solution, and mineral traps. The latter is considered as the most permanent and stable storage mechanism as the injected CO2 is stored in solid form by the carbon mineralization. In this study, the carbon mineralization process in geological CO2 storage in basalt, sandstone, carbonate, and shale are reviewed. In addition, relevant studies related to the carbon mineralization mechanisms, and suggestions for future research directions are proposed. The carbon mineralization is defined as the conversion of CO2 into stable carbon minerals by reacting with divalent cations such as Ca²⁺, Mg²⁺, or Fe²⁺. The process is mainly affected by rock types, temperature, fluid composition, injected CO2 phase, competing reaction, and nucleation. Rock properties such as permeability, porosity, and rock strength can be altered by the carbon mineralization. Since changes of the properties are directly related to injectivity, storage capacity, and stability during the geological CO2 storage, the carbon mineralization mechanism should be considered for an optimal CCS design.
Carbon capture and storage (CCS) technologies can play an essential role in the decarbonization of the energy sector, especially coal-fired power plants, considering their high-emissions character. This study assesses the theoretical potential of using CCS coupled to the Jorge Lacerda Thermoelectric Complex, which has the largest installed capacity for coal-fired power generation in Brazil. The primary focus is the geological investigation of carbon storage in units of the Paraná Sedimentary Basin. Regulatory, environmental, financial and social aspects are also considered. We conclude that implementing CCS could be a sustainable and feasible alternative for the power complex studied. We alert for the need to develop regulatory, financial, public acceptance and infrastructure aspects to support and scale CCS growth in Brazil. From the potential geological reservoirs analyzed for carbon storage, coal layers of the Rio Bonito Formation are the most interesting option, with a theoretical storage capacity of up to 38 GtCO2. Other geological formations assessed were disregarded considering the required criteria at the regional scale. Their potential at the local scale is not assessed. This case study could be replicated in other power plants aiming to achieve low-carbon standards.
Carbon capture and storage (CCS) is a climate change mitigation method in which anthropogenic carbon dioxide (CO2) is captured from large point sources and stored in geological formations, in the ocean, or through mineral carbonation. CO2 can be injected and stored for a variety of reasons, including permanent disposal or enhanced oil recovery in certain oil fields. The main objective of this paper is to assess the advances made in CO2 storage projects globally. This study reviews the major companies/businesses that are involved in CCS deployment. The study also presents the alternative for the sequestration of CO2 into the geological formations through existing major projects. It explains their progress, structural and faulting configuration, CO2 transportation and injection, potential CO2 source(s), estimation of the storage capacity, etc. This study also highlights the monitoring programs that are used in different operating projects and the status of active projects. The study suggests that CCS faces further deployment challenges due to the heterogeneity and complexity of rock formations, high cost of deployment, possibility of formation damage during injection and potential for migration and leakage of CO2. Additionally, inappropriate strategy for CO2 injection may lead to wellbore integrity problems, formation of hydrates, and inadequate pressure control. More research─particularly, geological evaluation before injection and storage─is apparently needed.
Geothermal systems are an attractive option for baseload electricity generation with low emissions intensity (average 122 gCO2/kWh). However, about 70% of geothermal systems are low or medium enthalpy (<160°C), which often renders them uneconomic to develop for electricity production. A solution to increase both power production and utilization efficiency of these systems is hybridization with a biomass fuel source. In this work, we introduce and verify the concept of biomass hybridization combined with in-line dissolution and reinjection of biomass flue CO2. This subclass of bioenergy and carbon capture and storage (BECCS), termed geothermal-BECCS, has improved power production and negative CO2 emissions. This dual approach of using geothermal systems for power production and as carbon sinks can be a potential decarbonisation tool in areas with suitable geothermal and bioenergy resources.
Here, we quantify the thermodynamic and sequestration performance of four geothermal-BECCS configurations. Up to 100% of flue gas is dissolved and reinjected with the spent geofluid. Scaled to a 1 kg/s geofluid production rate, flash and binary benchmark plants generated 32 and 43 kWe at efficiencies of 6 and 8%, respectively. In comparison, four geothermal-BECCS designs yielded 64 kWe at 9% efficiency (flash plant), 76 kWe at 9% efficiency (ORC binary plant), 62 kWe at 7% efficiency (compound flash-binary plant), and 589 kWe at 20% efficiency (bioenergy based geothermal-preheat plant). Annual biogenic CO2 sequestration rates ranged from 217 to 675 tonnes per kg/s with emissions intensities from -131 to -922 gCO2/kWh. By simultaneously boosting low-emissions energy and sequestering biogenic CO2, geothermal-BECCS promises to be an essential technology for meeting climate targets.
Massive quantities of carbon dioxide (CO2) need to be captured and stored to achieve net zero CO2 emissons by mid-century and avoid the worst consequences of unchecked global warming. Geologic storage of CO2 may be the only realistic option available to store the bulk of this CO2 due to the required storage volumes. Geologic storage involves the injection of CO2 into the subsurface. This injection will lead to the acidification of the formation fluids and provoke a large number of fluid-mineral reactions in the subsurface. Of these reactions, those among CO2-rich fluids and carbonate minerals may be the most significant as these reactions are relatively rapid and have the potential to alter the integrity of caprocks and well bore cement. This review provides a detailed summary of the field, laboratory, and modeling results illuminating the potential impacts of the injection of large quantities of CO2 into the subsurface of carbonate formations as part of geologic storage efforts.
Flood basalts have the potential for relatively rapid mineral trapping when used as an injection target for CO2 storage. Although CO2 mineral trapping in basalt has been studied in various ways, including two successful small-scale pilot projects, questions remain about how the system will behave during a full-scale CO2 storage project. These questions include whether a full-scale CO2 injection can expect complete mineralization on time scales similar to those observed during small-scale injections, as well as how the properties of the target formation will be altered by decades of geochemical reactions. Recently, we developed VIRTra, a vertically integrated reactive transport model specifically designed for efficient field-scale simulation of CO2 storage in reactive rocks. The present work uses this new method to explore the behavior of the water-CO2-basalt system during large-scale injection of separate-phase CO2 in a deep saline aquifer. Trends in the assembled data indicate that a high rate of CO2 dissolution into the aqueous phase results in faster mineralization. However, the time scales on which full mineralization of the injected CO2 is achieved are on the order of centuries, orders of magnitude larger than those observed in small-scale field tests. This appears to be a direct result of the increase in scale of the injection. During the injection period, changes in porosity are observed to be highly dependent on mineral reaction kinetics. Important areas of further research include the impact of mineralogy and formation water composition on the mineralization process, and the relationship between porosity and permeability in vesicular rock types.
In carbon capture and sequestration, developing rapid and effective imaging techniques is crucial for real-time monitoring of the spatial and temporal dynamics of CO 2 propagation during/after injection. With continuing improvements in computational power and data storage, data-driven techniques based on machine learning (ML) have been effectively applied to seismic inverse problems. In particular, ML helps alleviate the ill-posedness and high computational cost of full-waveform inversion (FWI). However, such data-driven inversion techniques require massive high-quality training data sets to ensure prediction accuracy, which hinders their application to time-lapse monitoring of CO 2 sequestration. We propose an efficient “hybrid” time-lapse workflow that combines physics-based FWI and data-driven ML inversion. The scarcity of the available training data is addressed by developing a new data-generation technique with physics constraints. The method is validated on a synthetic CO 2 -sequestration model based on the Kimberlina storage reservoir in California. The proposed approach is shown to synthesize a large volume of high-quality, physically realistic training data, which is critically important in accurately characterizing the CO 2 movement in the reservoir. The developed hybrid methodology can also simultaneously predict the variations in velocity and saturation and achieve high spatial resolution in the presence of realistic noise in the data.
Among the many scenarios that have been proposed to reduce the amount of carbon dioxide (CO2) emissions to the atmosphere, carbon-capture and storage (CCS) in geological reservoirs represents the method most technologically feasible and capable of accommodating the large amounts of CO2 that are generated on an annual basis by combustion of fossil fuels (IPCC, 2005). Geological environments and processes that have been proposed for CCS include deep, unmineable coal seams, depleted oil and gas reservoirs, organic-rich shale basins, deep saline formations, and mineral carbonation of basalts. Of these various options, the one that is most attractive owing to its widespread distribution and capacity to store large amounts of CO2 is deep saline formations, with the U.S. Department of Energy reporting that saline formations in the United States could potentially store more than 2,100–20,000 billion metric tons of CO2 (DOE, 2012). A recently released assessment of geologic carbon dioxide storage potential (USGS, 2013) estimates a capacity ranging from 2,400 to 3,700 billion metric tonnes (Gt) of CO2, which corresponds to the low end of the DOE estimate.
When supercritical CO2 (scCO2) is injected into a saline formation, it may be stored in various ways. Initially, the CO2 will be stored by structural and stratigraphic trapping, whereby scCO2 is trapped beneath an impermeable confining layer that prohibits the upward migration of the more buoyant scCO2. Some scCO2 may also be stored by residual trapping in pores via capillary forces. In the discussion to follow, we include residual trapping with structural/stratigraphic trapping as all of these processes involve the storage of a scCO2 phase and, as such, the volume requirements are assumed to be identical for these storage mechanisms for a given mass of CO2. Over time, …
The global CO2-carbonic acid-carbonate system of seawater, although certainly a well-researched topic of interest in the past, has risen to the fore in recent years because of the environmental issue of ocean acidification (often simply termed OA). Despite much previous research, there remain pressing questions about how this most important chemical system of seawater operated at the various time scales of the deep time of the Phanerozoic Eon (the past 545 Ma of Earth's history), interglacial-glacial time, and the Anthropocene (the time of strong human influence on the behaviour of the system) into the future of the planet. One difficulty in any analysis is that the behaviour of the marine carbon system is not only controlled by internal processes in the ocean, but it is intimately linked to the domains of the atmosphere, continental landscape, and marine carbonate sediments. For the deep-time behaviour of the system, there exists a strong coupling between the states of various material reservoirs resulting in an homeostatic and self-regulating system. As a working hypothesis, the coupling produces two dominant chemostatic modes: (Mode I), a state of elevated atmospheric CO2, warm climate, and depressed seawater Mg/Ca and SO4/Ca mol ratios, pH (extended geologic periods of ocean acidification), and carbonate saturation states (Omega), and elevated Sr concentrations, with calcite and dolomite as dominant minerals found in marine carbonate sediments (Hothouses, the calcite-dolomite seas), and (Mode II), a state of depressed atmospheric CO2, cool climate, and elevated seawater Mg/Ca and SO4/Ca ratios, pH, and carbonate saturation states, and low Sr concentrations, with aragonite and high magnesian calcites as dominant minerals found in marine carbonate sediments (Icehouses, the aragonite seas). Investigation of the impacts of deglaciation and anthropogenic inputs on the CO2-H2O-CaCO3 system in global coastal ocean waters from the Last Glacial Maximum (LGM: the last great continental glaciation of the Pleistocene Epoch, 18,000 year BP) to the year 2100 shows that with rising sea level, atmospheric CO2, and temperature, the carbonate system of coastal ocean water changed and will continue to change significantly. We find that 6,000 Gt of C were emitted as CO2 to the atmosphere from the growing coastal ocean from the Last Glacial Maximum to late preindustrial time because of net heterotrophy (state of gross respiration exceeding gross photosynthesis) and net calcification processes. Shallow-water carbonate accumulation alone from the Last Glacial Maximum to late preindustrial time could account for similar to 24 ppmv of the similar to 100 ppmv rise in atmospheric CO2, lending some support to the "coral reef hypothesis''. In addition, the global coastal ocean is now, or soon will be, a sink of atmospheric CO2, rather than a source. The pH(T) (pH values on the total proton scale) of global coastal seawater has decreased from similar to 8.35 to similar to 8.18 and the CO32- ion concentration declined by similar to 19% from the Last Glacial Maximum to late preindustrial time. In comparison, the decrease in coastal water pH(T) from the year 1900 to 2000 was similar to 8.18 to similar to 8.08 and is projected to decrease further from about similar to 8.08 to similar to 7.85 between 2000 and 2100. During these 200 years, the CO32- ion concentration will fall by similar to 45%. This decadal rate of decline of the CO32- ion concentration in the Anthropocene is 214 times the average rate of decline for the entire Holocene! In terms of the modern problem of ocean acidification and its effects, the "other CO2 problem", we emphasise that most experimental work on a variety of calcifying organisms has shown that under increased atmospheric CO2 levels (which attempt to mimic those of the future), and hence decreased seawater CO32- ion concentration and carbonate saturation state, most calcifying organisms will not calcify as rapidly as they do under present-day CO2 levels. In addition, we conclude that dissolution of the highly reactive carbonate phases, particularly the biogenic and cementing magnesian calcite phases, on reefs will not be sufficient to alter significantly future changes in seawater pH and lead to a buffering of the CO2-carbonic acid system in waters bathing reefs and other carbonate ecosystems on timescales of decades to centuries. Because of decreased calcification rates and increased dissolution rates in a future higher CO2, warmer world with seas of lower pH and carbonate saturation state, the rate of accretion of carbonate structures is likely to slow and dissolution may even exceed calcification. The potential of increasing nutrient and organic carbon inputs from land, occurrences of mass bleaching events, and increasing intensity (and perhaps frequency of hurricanes and cyclones as a result of sea surface warming) will only complicate matters more. This composite of stresses will have severe consequences for the ecosystem services that reefs perform, including acting as a fishery, a barrier to storm surges, a source of carbonate sediment to maintain beaches, and an environment of aesthetic appeal to tourist and local populations. It seems obvious that increasing rates of dissolution and bioerosion owing to ocean acidification will result in a progressively increasing calcium carbonate (CaCO3) deficit in the CaCO3 budget for many coral reef environments. The major questions that require answers are: will this deficit occur and when and to what extent will the destructive processes exceed the constructive processes?
Field projects are beginning to demonstrate the potential for carbon storage in basaltic rocks.
Caprocks are impermeable sedimentary formations that overlie prospective geologic CO2 storage reservoirs. As such, caprocks will be relied upon to trap CO2 and prevent vertical fluid migration and leakage. Natural and industrial analogues provide evidence of long-term performance of caprocks in holding buoyant fluids. However, the large volumes of CO2 that must be injected and stored to meaningfully reduce anthropogenic greenhouse gas emissions will exert unprecedented geomechanical and geochemical burdens on caprock formations due to elevated formation pressures and brine acidification.
Caprocks have inherent vulnerabilities in that wellbores, faults and fractures that transect caprock formations may provide conduits for CO2 and/or brine to leak out of the intended storage formation. As a result, a critical criterion for CO2 storage reservoir siting assessments will be to predict and reliably quantify the risk of leakage through caprock formations. We use “flow paths” as a catchall term for any fluid conduit through caprocks including pore networks, fractures and faults along with any combination of the three elements. It is useful to assess leakage rates through flow paths in terms of their individual transmissivity, T [m4], which is the product of the permeability and the cross-sectional area of the flow path. Darcy’s law can be used to relate these intrinsic flow path characteristics and the hydraulic potential (pressure) gradient to determine a volumetric flow rate, Q , or a leakage rate for the individual flow path:
![Formula][1] (1)
Where P is the hydraulic potential [Pa], z is the depth [m], μ is the fluid viscosity [Pa s] and A [m2] is the cross-sectional area of the flow path perpendicular to flow, and A equals the product of average fracture aperture and fracture length normal to the flow direction. Predicting leakage potential, however, is extremely complex because assessments …
[1]: /embed/mml-math-1.gif
PHREEQC version 2 is a computer program written in the C programming language that is designed to perform a wide variety of low-temperature aqueous geochemical calculations.
The success of human and industrial development over the past hundred years has lead to a huge increase in fossil fuel consumption and CO2 emission to the atmosphere leading to an unprecedented increase in atmospheric CO2 concentration. This increased CO2 content is believed to be responsible for a significant increase in global temperature over the past several decades. Global-scale climate modeling suggests that this temperature increase will continue at least over the next few hundred years leading to glacial melting, and raising seawater levels. In an attempt to attenuate this possibility, many have proposed the large scale sequestration of CO2 from our atmosphere. This introduction presents a summary of some of the evidence linking increasing atmosphere CO2 concentration to global warming and our efforts to stem this rise though CO2 sequestration.
Seismicity induced by fluid injection and extraction is a widely observed phenomenon. These earthquakes can exceed magnitudes of M 6 and have the potential to impact on the containment, infrastructure and public perceptions o f safety at CO2 storage sites. We examine induced seismicity globally using published data from 75 sites dominated by water injection and hydrocarbon extraction to estimate the timing (relative to injection/extraction), locations, size range and numbers of induced earthquakes. Most induced earthquakes occur during injection/extraction (∼70%) and are clustered at shallow depths in the region of the reservoir. The rates and maximum magnitudes of induced earthquakes generally increase with rising reservoir pressures, total fluid volumes and injection/extraction rates. The likelihood of an earthquake greater than or equal to a given magnitude being induced during injection is approximately proportional to the total volume of fluid injected/extracted, which appears to provide a proxy fo r changes in rock dynamics. If this observation holds for CO2 storage sites, then we can expect the rates and maximum magnitudes of induced earthquakes to be significantly higher fo r commercial-scale operations (e.g., 50 Mt) than for pilot projects (e.g., 50 kt). In accord with these results the risks associated with induced seismicity may also rise with project size. Mitigation and monitoring measures at commercial-size sequestration sites, including installation of microseismic networks, public education on the expected seismicity and pressure relief wells, will be key for risk reduction.
In situ mineral carbonation is facilitated by aqueous-phase chemical reactions with dissolved CO2. Evidence from the laboratory and the field shows that the limiting factors for in situ mineral carbonation are the dissolution rate of CO2 into the aqueous phase and the release rate of divalent cations from basic silicate minerals. Up to now, pilot CO2 storage projects and commercial operations have focused on the injection and storage of anthropogenic CO2 as a supercritical phase in depleted oil and gas reservoirs or deep saline aquifers with limited potential for CO2 mineralization. The CarbFix Pilot Project will test the feasibility of in situ mineral carbonation in basaltic rocks as a way to permanently and safely store CO2. The test includes the capture of CO2 flue gas from the Hellisheidi geothermal power plant and the injection of 2200 tons of CO2 per year, fully dissolved in water, at the CarbFix pilot injection site in SW Iceland. This paper describes the design of the CO2 injection test and the novel approach for monitoring and verification of CO2 mineralization in the subsurface by tagging the injected CO2 with radiocarbon (14C), and using SF5CF3 and amidorhodamine G as conservative tracers to monitor the transport of the injected CO2 charged water.
The reduction of atmospheric CO2 is one of the challenges that scientists face today. University of Iceland, Reykjavik Energy, CNRS in Toulouse and Columbia University have started a cooperative project called CarbFix (www.carbfix.com) aiming at CO2 mineral sequestration into basalts at Hellisheidi, SW Iceland. Gaseous CO2 will be injected into a borehole where it will be carbonated with Icelandic groundwater. The CO2 charged injection fluid will be released into the target aquifer at ca. 500 m depth at about 35 °C and 40 bar. The aim is to permanently bind CO2 into carbonates upon water-rock interaction. In order to evaluate the hydro-geochemical patterns and proportions of CO2 mineralization in the aquifer, full scale monitoring is needed. This will involve monitoring of conservative and gas tracers injected with the carbonated fluid, isotope ratios and major and trace elemental chemistry. A crucial issue of the monitoring is the quality of the sampling at depth and under pressure. Commonly, gas bubbles are observed when using commercial downhole samplers (bailers) and in order to avoid this problem, a piston-type downhole bailer was designed, constructed and tested as part of the project.
With developing countries strongly relying on fossil fuels for energy generation, geological carbon sequestration
(GCS) is seen as a candidate for large reductions in CO2 emissions during the next several decades.
GCS does, however, raise some safety concerns. Specifically, it has been associated with induced seismicity,
as a result of pressure buildup arising from prolonged CO2 injection in GCS projects. This seismicity
is a delicate issue for two main reasons. First, over a short time scale, deformation of rock could release
seismic energy, potentially affecting surface structures or simply alarming the population, with negative
consequences for the social acceptance of this kind of projects. Second, over a longer time scale, activated
faults may provide preferential paths for CO2 leakage out of reservoirs. While known major faults intersecting
target aquifers can be identified and avoided during site screening, the same might not be true for
faults that are not resolvable by geophysical surveys. In this study, we use geological observations and
seismological theories to estimate the maximum magnitude of a seismic event that could be generated by
a fault of limited dimensions. We then compare our estimate with results of geomechanical simulations
that consider faults with different hydrodynamic and geomechanical characteristics. The coupled simulations
confirm the notion that the tendency of faults to be reactivated by the pressure buildup is linked
with the in situ stress field and its orientation relative to the fault. Small, active (critically stressed) faults
are capable of generating sufficiently large events that could be felt on the surface, although they may not
be the source of large earthquakes. Active, relatively permeable faults may be detrimental concerning
the effectiveness of a storage project, meaning that they could be preferential pathway for upward CO2
leakage, although minor faults may not intersect both CO2 reservoirs and shallower potable aquifers.
Between November 2009 and September 2011, temporary seismographs deployed under the EarthScope USArray program were situated on a 70-km grid covering the Barnett Shale in Texas, recording data that allowed sensing and locating regional earthquakes with magnitudes 1.5 and larger. I analyzed these data and located 67 earthquakes, more than eight times as many as reported by the National Earthquake Information Center. All 24 of the most reliably located epicenters occurred in eight groups within 3.2 km of one or more injection wells. These included wells near Dallas-Fort Worth and Cleburne, Texas, where earthquakes near injection wells were reported by the media in 2008 and 2009, as well as wells in six other locations, including several where no earthquakes have been reported previously. This suggests injection-triggered earthquakes are more common than is generally recognized. All the wells nearest to the earthquake groups reported maximum monthly injection rates exceeding 150,000 barrels of water per month (24,000 m(3)/mo) since October 2006. However, while 9 of 27 such wells in Johnson County were near earthquakes, elsewhere no earthquakes occurred near wells with similar injection rates. A plausible hypothesis to explain these observations is that injection only triggers earthquakes if injected fluids reach and relieve friction on a suitably oriented, nearby fault that is experiencing regional tectonic stress. Testing this hypothesis would require identifying geographic regions where there is interpreted subsurface structure information available to determine whether there are faults near seismically active and seismically quiescent injection wells.
The storage of large volumes of industrial CO2 emissions in deep geological formations is one of the most promising climate mitigation options. The long-term retention time and environmental safety of the CO2 storage are defined by the interaction of the injected CO2 with the reservoir fluids and rocks. Finding a storage solution that is long lasting, thermodynamically stable and environmentally benign would be ideal. Storage of CO2 as solid magnesium or calcium carbonates in basaltic rocks may provide such a long-term and thermodynamically stable solution. Basaltic rocks, which primarily consist of magnesium and calcium silicate minerals, provide alkaline earth metals necessary to form solid carbonates. In nature, the carbonization of basaltic rocks occurs in several well-documented settings, such as in the deep ocean crust, through hydrothermal alteration and through surface weathering. The goal of the CarbFix pilot project is to optimize industrial methods for permanent storage of CO2 in basaltic rocks. The objective is to study the in-situ mineralization of CO2 and its long term fate. The project involves the capture and separation of flue gases at the Hellisheidi Geothermal Power Plant, the transportation and injection of the CO2 gas fully dissolved in water at elevated pressures at a depth between 400 and 800 m, as well as the monitoring and verification of the storage. A comprehensive reservoir characterization study is on-going prior to the CO2 injection, including soil CO2 flux measurements, geophysical survey and tracer injection tests. Results from the tracer tests show significant tracer dispersion within the target formation, suggesting large surface area for chemical reactions. The large available reservoir volume and surface area in combination with relatively rapid CO2-water-rock reactions in basaltic rocks may allow safe and permanent geologic storage of CO2 on a large scale.
1] Flood basalts are a potentially important host medium for geologic sequestration of anthropogenic CO 2 . Most lava flows have flow tops that are porous and permeable and have enormous capacity for storage of CO 2 . Interbedded sediment layers and dense low-permeability basalt rock overlying sequential flows may act as effective seals allowing time for mineralization reactions to occur. Laboratory experiments confirm relatively rapid chemical reaction of CO 2 -saturated pore water with basalts to form stable carbonate minerals. Calculations suggest a sufficiently short time frame for onset of carbonate precipitation after CO 2 injection that verification of in situ mineralization rates appears feasible in field pilot studies. If proven viable, major flood basalts in the United States and India would provide significant additional CO 2 storage capacity and additional geologic sequestration options in certain regions where more conventional storage options are limited.
Despite its enormous cost, large-scale carbon capture and storage (CCS) is considered a viable strategy for significantly reducing CO(2) emissions associated with coal-based electrical power generation and other industrial sources of CO(2) [Intergovernmental Panel on Climate Change (2005) IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by Working Group III of the Intergovernmental Panel on Climate Change, eds Metz B, et al. (Cambridge Univ Press, Cambridge, UK); Szulczewski ML, et al. (2012) Proc Natl Acad Sci USA 109:5185-5189]. We argue here that there is a high probability that earthquakes will be triggered by injection of large volumes of CO(2) into the brittle rocks commonly found in continental interiors. Because even small- to moderate-sized earthquakes threaten the seal integrity of CO(2) repositories, in this context, large-scale CCS is a risky, and likely unsuccessful, strategy for significantly reducing greenhouse gas emissions.
Fluids play a critical role in the geochemical and geodynamical evolution of the crust, and fluid flow is the dominant process associated with mass and energy transport in the crust. In this Perspectives, we summarise the occurrence, properties and role that fluids play in crustal processes, as well as how geoscientists' understanding of these various aspects of fluids have evolved during the past century and how this evolution in thinking has influenced our own research careers. Despite the wide range of possible fluid sources in the crust, fluids in sedimentary, magmatic and metamorphic environments are all approximated by the system H2O - "gas" - "salt" and normally reflect equilibrium with rocks and melts at the relevant PT conditions. The "gas" component in many environments is dominated by CO2, but CH4, as well as various sulphur and nitrogen-rich gases, may also be important. The major "salt" components are usually NaCl and/or CaCl2, but salts of K, Mg and Fe can be major components in specific circumstances. While the activities of many fluid components can often be calculated assuming equilibrium with coexisting minerals, salinity is normally unbuffered and must be determined independently from observations of fluid inclusions. Solubilities of "gas" and "salt" in H2O generally rise with increasing temperature and/or pressure, but in many environments compositions are such that phase separation (immiscibility or boiling) leads to the development of salt-rich aqueous fluids coexisting with a volatile-rich phase. Chloride content, buffering assemblages, temperature and, to a lesser extent pressure, all play a role in determining the dissolved load of crustal fluids. In addition to equilibrium considerations, kinetic factors can play an important role in relatively shallow, low temperature environments. The most important distinction between relatively shallow basinal or geothermal fluids and deeper metamorphic or magmatic ones is the physical behaviour of the fluid(s). In regions where fluid pressure corresponds to hydrostatic pressure, extensive circulation of fluid is possible, driven by thermal or compositional gradients or gravity. In contrast, at greater depths where fluids are overpressured and may approach lithostatic pressure, fluid can only escape irreversibly and so fluxes are generally much more limited. Much of our understanding of crustal fluids has come from studies of ore-forming systems that are present in different crustal environments. Thus, studies of Mississippi Valley-Type deposits that form in sedimentary basins have shown that the fluids are dominantly high salinity (Na, Ca) brines that have significant metal-carrying capacity. Studies of active continental geothermal systems and their fossil equivalents, the epithermal precious metal deposits, document the importance of boiling or immiscibility as a depositional mechanism in this environment. Ore-forming fluids associated with orogenic gold deposits show many similarities to low salinity metamorphic fluids, consistent with their formation during metamorphism, but similar fluids are also found in some magmatic pegmatites, demonstrating the difficulty in distinguishing characteristics derived from the fluid source from those that simply reflect phase relationships in the H2O - "gas"- "salt" system. Magmatic fluids associated with silicic epizonal plutons are consistent with experimental and theoretical studies related to volatile solubilities in magmas, as well as the partitioning of volatiles and metals between the melt and exsolving magmatic fluid. Ore fluids are generally representative of crustal fluids in comparable settings, rather than unusual, metal-rich solutions. During progressive burial and heating of sediments and metamorphic rocks, there is continuous fluid release and loss and the rocks remain wet and weak. Fluid composition evolves continuously as a result of changing conditions. Once rocks begin to cool, fluid is consumed by retrograde reactions and in much of the crust the rocks are effectively dry with a notional water fugacity buffered by the coexisting high-T and retrograde phases. In this case rocks are strong and unreactive. Our understanding of crustal fluids has advanced by leaps and bounds during the past few decades, and we expect new and exciting results to continue to emerge as new analytical methods are developed that allow us to analyse smaller fluid inclusions in particular, and as theoretical models and experiments advance our understanding of how fluids interact with rocks and minerals in the crust, changing both chemical and physical characteristics.
In little more than a decade, carbon dioxide (CO2) capture from point source emissions and sequestration in deep geological formations has emerged as one of the most important options for reducing CO2 emissions. Two major challenges stand in the way of realizing this potential: the high cost of capturing CO2 and gaining confidence in the capacity, safety, and permanence of sequestration in deep geological formations. Building on examples from laboratory and field based studies of multiphase flow of CO2 in porous rocks; this talk addresses the current prospects for carbon dioxide sequestration. Which formations can provide safe and secure sequestration? At what scale will this be practical and is this scale sufficient to significantly reduce emissions? What monitoring methods can be used to provide assurance that CO2 remains trapped underground? What can be done if a leak develops? What are the potential impacts to groundwater resources and how can these be avoided? The status of each these questions will be discussed, along with emerging research questions.
Humans are faced with a potentially disastrous global problem owing to the current emission of 32 gigatonnes of carbon dioxide (CO2) annually into the atmosphere. A possible way to mitigate the effects is to store CO2 in large porous reservoirs within the Earth. Fluid mechanics plays a key role in determining both the feasibility and risks involved in this geological sequestration. We review current research efforts looking at the propagation of CO2 within the subsurface, the possible rates of leakage, the mechanisms that act to stably trap CO2, and the geomechanical response of the crust to large-scale CO2 injection. We conclude with an outline for future research.
[1] Analysis of numerous case histories of earthquake sequences induced by fluid injection at depth reveals that the maximum magnitude appears to be limited according to the total volume of fluid injected. Similarly, the maximum seismic moment seems to have an upper bound proportional to the total volume of injected fluid. Activities involving fluid injection include (1) hydraulic fracturing of shale formations or coal seams to extract gas and oil, (2) disposal of wastewater from these gas and oil activities by injection into deep aquifers, and (3) the development of Enhanced Geothermal Systems by injecting water into hot, low-permeability rock. Of these three operations, wastewater disposal is observed to be associated with the largest earthquakes, with maximum magnitudes sometimes exceeding 5. To estimate the maximum earthquake that could be induced by a given fluid injection project, the rock mass is assumed to be fully saturated, brittle, to respond to injection with a sequence of earthquakes localized to the region weakened by the pore pressure increase of the injection operation, and to have a Gutenberg-Richter magnitude distribution with a b-value of 1. If these assumptions correctly describe the circumstances of the largest earthquake, then the maximum seismic moment is limited to the volume of injected liquid times the modulus of rigidity. Observations from the available case histories of earthquakes induced by fluid injection are consistent with this bound on seismic moment. In view of the uncertainties in this analysis, however, this should not be regarded as an absolute physical limit.
109 small earthquakes (Mw 0.4-3.9) were detected during
January 2011 to February 2012 in the Youngstown, Ohio area, where there
were no known earthquakes in the past. These shocks were close to a deep
fluid injection well. The 14 month seismicity included six felt
earthquakes and culminated with a Mw 3.9 shock on 31 December
2011. Among the 109 shocks, 12 events greater than Mw 1.8
were detected by regional network and accurately relocated, whereas 97
small earthquakes (0.4 < Mw < 1.8) were detected by the
waveform correlation detector. Accurately located earthquakes were along
a subsurface fault trending ENE-WSW—consistent with the focal
mechanism of the main shock and occurred at depths 3.5-4.0 km in the
Precambrian basement. We conclude that the recent earthquakes in
Youngstown, Ohio were induced by the fluid injection at a deep injection
well due to increased pore pressure along the preexisting subsurface
faults located close to the wellbore. We found that the seismicity
initiated at the eastern end of the subsurface fault—close to the
injection point, and migrated toward the west—away from the
wellbore, indicating that the expanding high fluid pressure front
increased the pore pressure along its path and progressively triggered
the earthquakes. We observe that several periods of quiescence of
seismicity follow the minima in injection volumes and pressure, which
may indicate that the earthquakes were directly caused by the pressure
buildup and stopped when pressure dropped.
Significance
Between 2006 and 2011 a series of earthquakes occurred in the Cogdell oil field near Snyder, TX. A previous series of earthquakes occurring 1975–1982 was attributed to the injection of water into wells to enhance oil production. We evaluated injection and extraction of oil, water, and gas in the Cogdell field. Water injection cannot explain the 2006–2011 earthquakes. However, since 2004 significant volumes of gas including CO 2 have been injected into Cogdell wells. If this triggered the 2006–2011 seismicity, this represents an instance where gas injection has triggered earthquakes having magnitudes 3 and larger. Understanding when gas injection triggers earthquakes will help evaluate risks associated with large-scale carbon capture and storage as a strategy for managing climate change.
The subsurface rocks at the Hellisheidi carbon injection site are primarily olivine tholeiite basalts consisting of lava flows and hyaloclastite formations. The hyaloclastites are low permeability glassy rocks formed under ice and melt water during glaciations that serve as the cap rock at the injection site; the boundaries between hyaloclastites and lava flows and those between individual lava flows boundaries are preferential fluid flow pathways. Some alteration is observed in the hyaloclastite cap rock situated at 100–300 m depth consisting primarily of smectite, calcite, Ca-rich zeolites, and poorly crystalline iron-hydroxides. Alteration increases with depth. These alteration phases lower the porosity and permeability of these rocks. Carbon dioxide injection will be targeted at a lava flow sequence at 400–800 m depth with the main aquifer located at 530 m depth. Loss on ignition suggests that over 80% of the primary rocks in the target zone are currently unaltered. The target zone rocks are rich in the divalent cations capable of forming carbonates; on average 6 moles of divalent cations are present per 1 kg of rock.
Steady-state silica release rates (rSi) from basaltic glass and crystalline basalt of similar chemical composition as well as dunitic peridotite have been determined in far-from-equilibrium dissolution experiments at 25 °C and pH 3.6 in (a) artificial seawater solutions under 4 bar pCO2, (b) varying ionic strength solutions, including acidified natural seawater, (c) acidified natural seawater of varying fluoride concentrations, and (d) acidified natural seawater of varying dissolved organic carbon concentrations. Glassy and crystalline basalts exhibit similar rSi in solutions of varying ionic strength and cation concentrations. Rates of all solids are found to increase by 0.3–0.5 log units in the presence of a pCO2 of 4 bar compared to CO2 pressure of the atmosphere. At atmospheric CO2 pressure, basaltic glass dissolution rates were most increased by the addition of fluoride to solution whereas crystalline basalt rates were most enhanced by the addition of organic ligands. In contrast, peridotite does not display any significant ligand-promoting effect, either in the presence of fluoride or organic acids. Most significantly, Si release rates from the basalts are found to be not more than 0.6 log units slower than corresponding rates of the peridotite at all conditions considered in this study. This difference becomes negligible in seawater suggesting that for the purposes of in-situ mineral sequestration, CO2-charged seawater injected into basalt might be nearly as efficient as injection into peridotite.
Carbon dioxide capture and sequestration (CCS) in deep geological formations has quickly emerged as an important option for reducing greenhouse emissions. If CCS is implemented on the scale needed for large reductions in CO2 emissions, a billion of tonnes or more of CO2 will be sequestered annually a 250 fold increase over the amount sequestered annually today. Sequestering these large volumes will require a strong scientific foundation of the coupled hydrological-geochemical-geomechanical processes that govern the long term fate of CO2 in the subsurface. Methods to characterize and select sequestration sites, subsurface engineering to optimize performance and cost, safe operations, monitoring technology, remediation methods, regulatory oversight, and an institutional approach for managing long term liability are also needed.
Sequestration of CO2 in geologic formations will be part of any substantive campaign to mitigate greenhouse gas emissions. The risk of leakage from the target formation must be weighed against economic feasibilities for this technology to gain stakeholder acceptance. The standard approach to large-scale geologic sequestration assumes that CO2 will be injected as a bulk phase into a saline aquifer. In this case, the primary driver for leakage is the buoyancy of CO2 under typical deep reservoir conditions (depths > 2600 ft or 800 m). Investigating alternative approaches that utilize inherently safe trapping mechanisms can help to characterize the price of reducing the risk of leakage.
In this paper, we investigate a process in which CO2 is dissolved in brine prior to injection into deep subsurface formations. The CO2-laden brine is slightly denser than brine containing no CO2, so ensuring the complete dissolution of all CO2 into brine at the surface prior to injection will eliminate the risk of buoyancy-driven leakage. We examine the feasibility of dissolving CO2 at surface facilities and injection of the saturated brine. To estimate the costs of this process, we determine the capital costs for the additional facilities and compare them the capital costs for injecting bulk phase CO2. We also estimate the power requirements to determine the additional operating costs. The additional capital and operating costs can be regarded as the price of this form of risk reduction.
Comparing this alternative to the standard, we find that an additional power consumption of 3% to 8% of the power plant capacity will be required and the capital costs will increase by 34% to 44%. Brine is required at rates of millions of barrels per day, and in most applications this would be lifted from the target aquifer. The bulk volume of the aquifer is on the order of a hundred million acre-ft for reasonable power plant sizes (250MW to 1000MW) and for reasonable injection periods (30–50 years). Although this alternative results in higher costs, surface dissolution may be attractive where the costs of monitoring or insuring against buoyancy-driven CO2 leakage exceed these additional costs.
Introduction
The prototypical implementation of carbon capture and sequestration on existing power generation plants involves separation of CO2 from the flue gas followed by compression for injection into a brine-filled formation for geologic storage (see Fig.1). Future power generation may rely on advanced combustion schemes that eliminate the flue gas separation step, but compression and injection of the CO2 stream will still be required for greenhouse gas mitigation. In either case, the CO2 phase will be less dense than brine at conditions in the geologic formation. Many studies suggest buoyant bulk phase CO2 can be stored in the subsurface formations by a combination of dissolution into the brine, capillary trapping, and structural trapping.1–2 Similarly, some studies suggest co-injection of brine and CO2 could improve the pore scale mixing and dissolution near the injection site.3 Geologic uncertainties, such as the extent and conductivity of faults and seals, as well as human-introduced uncertainty, such as location and conductivity of well penetrations, pose important risk to structurally trapped CO2.4
This study estimates the operating and capital costs of preparing CO2-dense brine in surface facilities and compares them to the costs of the standard approach of injection. The comparison considers only the case of retrofitting capture technology on an existing coal-fired power plant. The approach can be readily extended to anticipated power generation plants which do not require separation. Our original motivation was to determine whether the major contributions to power consumption for a surface dissolution scheme would be prohibitively large. Thus the present analysis neglects several issues, such as the consequences of geochemical reactions or energy required for efficient mixing and dissolution.
We apply these results in a simple case study of a well documented brine aquifer, the Mt. Simon formation in central Illinois. The case study illustrates how the information presented in this paper can be used. We also discuss the technical challenges and future research needs.
A survey of the global carbon reservoirs suggests that the most stable, long-term storage mechanism for atmospheric CO2 is the formation of carbonate minerals such as calcite, dolomite and magnesite. The feasibility is demonstrated by the proportion
of terrestrial carbon bound in these minerals: at least 40,000 times more carbon is present in carbonate rocks than in the
atmosphere. Atmospheric carbon can be transformed into carbonate minerals either ex situ, as part of an industrial process,
or in situ, by injection into geological formations where the elements required for carbonate-mineral formation are present.
Many challenges in mineral carbonation remain to be resolved. They include overcoming the slow kinetics of mineral-fluid reactions,
dealing with the large volume of source material required and reducing the energy needed to hasten the carbonation process.
To address these challenges, several pilot studies have been launched, including the CarbFix program in Iceland. The aim of
CarbFix is to inject CO2 into permeable basaltic rocks in an attempt to form carbonate minerals directly through a coupled dissolution-precipitation
process.
One proposal for the mitigation of ongoing global warming is the sequestration of carbon dioxide extracted at combustion sites or directly from the air. Such sequestration could help avoid a large rise in atmospheric CO2 concentration from unchecked use of fossil fuels, and hence extreme warming in the near future. However, it is not clear how effective different types of sequestration and associated leakage are in the long term, and what their consequences might be. Here I present projections over 100,000 years for five scenarios of carbon sequestration and leakage with an Earth system model. Most of the investigated scenarios result in a large, delayed warming in the atmosphere as well as oxygen depletion, acidification and elevated CO2 concentrations in the ocean. Specifically, deep-ocean carbon storage leads to extreme acidification and CO2 concentrations in the deep ocean, together with a return to the adverse conditions of a business-as-usual projection with no sequestration over several thousand years. Geological storage may be more effective in delaying the return to the conditions of a business-as-usual projection, especially for storage in offshore sediments. However, leakage of 1% or less per thousand years from an underground stored reservoir, or continuous resequestration far into the future, would be required to maintain conditions close to those of a low-emission projection with no sequestration.
One of the outstanding challenges for large-scale CCS operations is to develop reliable quantitative risk assessments with a focus on leakage of both injected CO2 and displaced brine. A critical leakage pathway is associated with the century-long legacy of oil and gas exploration and production, which has led to many millions of wells being drilled. Many of those wells are in locations that would otherwise be excellent candidates for CCS operations, especially across many parts of North America. Quantitative analysis of the problem requires special computational techniques because of the unique challenges associated with simulation of injection and leakage in systems that include hundreds or thousands of existing wells over domains characterized by layered structures in the vertical direction and very large horizontal extent. An important feature of these kinds of systems is the depth of each well, and the fact that the number of wells penetrating different formations decreases as a function of depth. As such, one might reasonably expect the risk of leakage to decrease with depth of injection. With the special computational models developed to simulate injection and leakage along multiple wells, in layered systems with multiple formations, quantitative assessment of risk reduction as a function of injection depth can be made. An example of such a system corresponds to the Wabamun Lake area southwest of Edmonton, Alberta, Canada, where several large coal-fired power plants are located. Use of information about both the existing wells and the local stratigraphy allows a realistic model to be constructed. Leakage along existing wells is assumed to follow Darcy’s Law, and is characterized by a set of effective permeability values. These values are assigned stochastically, using several different methods, within a Monte Carlo simulation framework. Computational results show the clear trade-off between depth of injection and risk of leakage. The results also show how properties within the different formations affect the risk profiles. In the Wabamun Lake area, one of the formations has the highest injectivity, by far, while having a moderate number of existing wells. Its moderate risk of leakage, as compared to injections in formations above and below, shows some of the key factors that are likely to influence injection design for large-scale CCS operations.
Before implementing CO2 storage on a large scale its viability regarding injectivity, containment and long-term safety for both humans and environment is crucial. Assessing CO2–rock interactions is an important part of that as these potentially affect physical properties through highly coupled processes. Increased understanding of the physical impact of injected CO2 during recent years including buoyancy driven two-phase flow and convective mixing elucidated potential CO2 pathways and indicated where and when CO2–rock interactions are potentially occurring. Several areas of interactions can be defined: (1) interactions during the injection phase and in the near well environment, (2) long-term reservoir and cap rock interactions, (3) CO2–rock interactions along leakage pathways (well, cap rock and fault), (4) CO2–rock interactions causing potable aquifer contamination as a consequence of leakage, (5) water–rock interactions caused by aquifer contamination through the CO2 induced displacement of brines and finally engineered CO2–rock interactions (6). The driving processes of CO2–rock interactions are discussed as well as their potential impact in terms of changing physical parameters. This includes dissolution of CO2 in brines, acid induced reactions, reactions due to brine concentration, clay desiccation, pure CO2–rock interactions and reactions induced by other gases than CO2. Based on each interaction environment the main aspects that are possibly affecting the safety and/or feasibility of the CO2 storage scheme are reviewed and identified. Then the methodologies for assessing CO2–rock interactions are discussed. High priority research topics include the impact of other gaseous compounds in the CO2 stream on rock and cement materials, the reactivity of dry CO2 in the absence of water, how CO2 induced precipitation reactions affect the pore space evolution and thus the physical properties and the need for the development of coupled flow, geochemical and geomechanical models.
An experimental investigation is reported on the solubility of CO2(l) in water at temperatures from 278 K to 293 K and pressures from 6.44 MPa to 29.49 MPa and on the corresponding densities of the CO2aqueous solutions. Based on the experimental data, an expression for the Henry's law constant as a function of temperature and pressure was obtained. Good agreement was observed between the experimental data and the prediction made using the modified Henry's law and the resultant Henry's law constant, with a maximum difference of
Any substantive campaign to mitigate greenhouse gas emissions must involve sequestration of CO2 in geologic formations. For stakeholders to accept this technology, the risk of leakage from the storage formation must be balanced against the economics of capture and injection. The standard approach to geologic sequestration assumes that CO2 will be injected as a bulk phase into a saline aquifer. The primary driver for leakage in this approach is the buoyancy of CO2 relative to native brine under typical deep reservoir conditions. If no leakage occurs, the primary impact of storage will be the displacement of large volumes of groundwater, equal to the volume of CO2 injected at reservoir conditions. Here we investigate an alternative storage approach that alleviates these concerns. The incremental cost of this approach over the standard approach therefore sets an upper bound on reasonable costs for monitoring and verification of the standard storage scheme and for avoiding groundwater contamination.
Two and three-dimensional field scale reservoir models of CO2 mineral sequestration in basalts were developed and calibrated against a large set of field data. Resulting principal hydrological properties are lateral and vertical intrinsic permeabilities of 300 and 1700 × 10−15 m2 , respectively, effective matrix porosity of 8.5% and a 25 m/year estimate for regional groundwater flow velocity.
Reactive chemistry was coupled to calibrated models and predictive mass transport and reactive trans- port simulations carried out for both a 1200-tonnes pilot CO2 injection and a full-scale 400,000-tonnes CO2 injection scenario. Reactive transport simulations of the pilot injection predict 100% CO2 mineral capture within 10 years and cumulative fixation per unit surface area of 5000 tonnes/km2 . Correspond- ing values for the full-scale scenario are 80% CO2 mineral capture after 100 years and cumulative fixation of 35,000 tonnes/km2 . CO2 sequestration rate is predicted to range between 1200 and 22,000 tonnes/year in both scenarios.
The predictive value of mass transport simulations was found to be considerably lower than that of reactive transport simulations. Results from three-dimensional simulations were also in significantly better agreement with field observations than equivalent two-dimensional results.
Despite only being indicative, it is concluded from this study that fresh basalts may comprise ideal geological CO2 storage formations.
Sedimentary basins in general, and deep saline aquifers in particular, are being investigated as possible repositories for large volumes of anthropogenic CO2 that must be sequestered to mitigate global warming and related climate changes. To investigate the potential for the long-term storage of CO2 in such aquifers, 1600 t of CO2 were injected at 1500 m depth into a 24-m-thick “C” sandstone unit of the Frio Formation, a regional aquifer in the US Gulf Coast. Fluid samples obtained before CO2 injection from the injection well and an observation well 30 m updip showed a Na–Ca–Cl type brine with ∼93,000 mg/L TDS at saturation with CH4 at reservoir conditions; gas analyses showed that CH4 comprised ∼95% of dissolved gas, but CO2 was low at 0.3%. Following CO2 breakthrough, 51 h after injection, samples showed sharp drops in pH (6.5–5.7), pronounced increases in alkalinity (100–3000 mg/L as HCO3) and in Fe (30–1100 mg/L), a slug of very high DOC values, and significant shifts in the isotopic compositions of H2O, DIC, and CH4. These data, coupled with geochemical modeling, indicate corrosion of pipe and well casing as well as rapid dissolution of minerals, especially calcite and iron oxyhydroxides, both caused by lowered pH (initially ∼3.0 at subsurface conditions) of the brine in contact with supercritical CO2.
CarbFix, a combined industrial-academic pilot program, was developed in order to assess the feasibility of in situ CO2 mineral sequestration in basaltic rocks. Unique to CarbFix is its connection to the Hellisheidi geothermal power plant, allowing for capture of otherwise emitted CO2 in addition to CO2 transport and mineral sequestration.
Extensive research has been conducted in order to characterize physical properties of the pilot injection site in Hellisheidi. Tracer tests have been carried out and continuous well-logging confirmed separation of the target formation from shallower groundwater systems. Alteration mineralogy in natural analogs has been mapped out in order to predict which minerals are likely to precipitate upon CO2 injection. In addition to carbonates, these include clays, zeolites, and poorly crystalline hydroxides. Some of the secondary minerals will compete with carbonates for cations dissolved from the rock matrix.
Numerical modeling plays an important role in the CarbFix project as it provides tools to predict and optimize long-term management of the injection site as well as to quantify the amount of CO2 that can be mineralized. A reactive transport model has been developed and numerical simulations of the pilot CO2 injection are ongoing. Extensive monitoring provides the basis for testing, validating, and calibrating reactive transport models.
It is anticipated that the results of CarbFix will be used to optimize the in situ carbon mineralization process, enabling it in basalt and ultramafic rock formations throughout the world. © 2011 Society of Chemical Industry and John Wiley & Sons, Ltd
In this paper we describe the thermodynamic and kinetic basis for mineral storage of carbon dioxide in basaltic rock, and how this storage can be optimized. Mineral storage is facilitated by the dissolution of CO2 into the aqueous phase. The amount of water required for this dissolution decreases with decreased temperature, decreased salinity, and increased pressure. Experimental and field evidence suggest that the factor limiting the rate of mineral fixation of carbon in silicate rocks is the release rate of divalent cations from silicate minerals and glasses. Ultramafic rocks and basalts, in glassy state, are the most promising rock types for the mineral sequestration of CO2 because of their relatively fast dissolution rate, high concentration of divalent cations, and abundance at the Earth's surface. Admixture of flue gases, such as SO2 and HF, will enhance the dissolution rates of silicate minerals and glasses. Elevated temperature increases dissolution rates but porosity of reactive rock formations decreases rapidly with increasing temperature. Reduced conditions enhance mineral carbonation as reduced iron can precipitate in carbonate minerals. Elevated CO2 partial pressure increases the relative amount of carbonate minerals over other secondary minerals formed. The feasibility to fix CO2 by carbonation in basaltic rocks will be tested in the CarbFix project by: (1) injection of CO2 charged waters into basaltic rocks in SW Iceland, (2) laboratory experiments, (3) studies of natural analogues, and (4) geochemical modelling.
Abstract Underground storage in porous and permeable reservoir rocks is a technically feasible way to dispose of industrial quantities of carbon dioxide such as are produced by a fossil fuel-fired power plant. All the necessary steps are commercially proven and in use today. Extensive, naturally occurring CO2 accumulations indicate that under favorable conditions CO2 can be retained in underground reservoirs for millions of years. Large-scale commercial underground CO2 sequestration has begun at the Sleipner West gas field in the North Sea. Some of the major issues to be addressed if this technology is to make an impact on CO2 emissions to the atmosphere are cost of CO2 capture, safety and security of storage, and public acceptability.
In assessing the feasibility of widespread deployment of CO2 geological storage, it is prudent to first assess potential consequences of an error or accident that could lead to CO2 leakage into groundwater resources above a sequestration interval. Information about the sensitivity of the groundwater system
to introduction of CO2 is needed in order to design groundwater monitoring program. A laboratory-batch experiment was conducted to explore the range
of CO2 impact on groundwater quality of a spectrum of representative aquifers, in the Gulf Coast region, USA. Results show that
CO2 elevated concentrations of many cations within hours or days. Two types of cations were recognized according to their concentration
trends. Type I cations—Ca, Mg, Si, K, Sr, Mn, Ba, Co, B, Zn—rapidly increased following initial CO2 flux and reached stable concentrations before the end of the experiment. Type II cations—Fe, Al, Mo, U, V, As, Cr, Cs, Rb,
Ni and Cu—increased at the start of CO2 flux, but declined, in most cases, to levels lower than pre-CO2 concentrations. Dissolution of dolomite and calcite caused the largest increase in concentrations for Ca, Mg, Mn, Ba and
Sr. Cation release rates decreased linearly as pH increased during mineral buffering. Experiment results suggest that carbonate
minerals are the dominant contributor of changes in groundwater quality. Risk assessments of potential degradation of groundwater
and monitoring strategies should focus on these fast-reacting minerals. Mobilization risk of Type II cations, however, may
be self-mitigated because adsorption occurs when pH rebounds.
KeywordsCarbon sequestration-CO2–rock–water reactions-Carbonate dissolution-Water contamination-Groundwater monitoring
This work was motivated by considerations of potential leakage pathways for CO2 injected into deep geological formations for the purpose of carbon sequestration. Because existing wells represent a potentially important leakage pathway, a spatial analysis of wells that penetrate a deep aquifer in the Alberta Basin was performed and various statistical measures to quantify the spatial distribution of these wells were presented. The data indicate spatial clustering of wells, due to oil and gas production activities. The data also indicate that the number of wells that could be impacted by CO2 injection, as defined by the spread of an injected CO2 plume, varies from several hundred in high well-density areas to about 20 in low-density areas. These results may be applied to other mature continental sedimentary basins in North America and elsewhere, where detailed information on well location and status may not be available.
A study on the sequestration of CO2 in aquifers in response to climate change was presented. The ultimate Co2 sequestration capacity in solution (UCSCS) in an aquifer was calculated by considering the effect of dissolved CO2 on the formation water density, the aquifer thickness and porosity. Results showed that the use of geochemical models to bring the analysis of formation waters to in-situ conditions was not warranted when the current inorganic carbon (TIC) in the aquifer was very small as compared to the CO2 solubility at saturation.
Comparison of measured far-from-equilibrium dissolution rates of natural glasses and silicate minerals at 25 °C and pH 4 reveals the systematic effects of crystallinity and elemental composition on these rates. Rates for both minerals and glasses decrease with increasing Si:O ratio, but glass dissolution rates are faster than corresponding mineral rates. The difference between glass and mineral dissolution rates increases with increasing Si:O ratio; ultra-mafic glasses (Si:O ⩽ 0.28) dissolve at similar rates as correspondingly compositioned minerals, but Si-rich glasses such as rhyolite (Si:O ∼ 0.40) dissolve ⩾1.6 orders of magnitude faster than corresponding minerals. This behaviour is interpreted to stem from the effect of Si–O polymerisation on silicate dissolution rates. The rate controlling step of dissolution for silicate minerals and glasses for which Si:O > 0.28 is the breaking of Si–O bonds. Owing to rapid quenching, natural glasses will exhibit less polymerisation and less ordering of Si–O bonds than minerals, making them less resistant to dissolution. Dissolution rates summarized in this study are used to determine the Ca release rates of natural rocks at far-from-equilibrium conditions, which in turn are used to estimate their CO2 consumption capacity. Results indicate that Ca release rates for glasses are faster than those of corresponding rocks. This difference is, however, significantly less than the corresponding difference between glass and mineral bulk dissolution rates. This is due to the presence of Ca in relatively reactive minerals. In both cases, Ca release rates increase by ∼two orders of magnitude from high to low Si:O ratios (e.g., from granite to gabbro or from rhyolitic to basaltic glass), illustrating the important role of Si-poor silicates in the long-term global CO2 cycle.
Carbon dioxide disposal into deep aquifers is a potential means whereby atmospheric emissions of greenhouse gases may be reduced. However, our knowledge of the geohydrology, geochemistry, geophysics, and geomechanics of CO2 disposal must be refined if this technology is to be implemented safely, efficiently, and predictably. As a prelude to a fully coupled treatment of physical and chemical effects of CO2 injection, the authors have analyzed the impact of CO2 immobilization through carbonate mineral precipitation. Batch reaction modeling of the geochemical evolution of 3 different aquifer mineral compositions in the presence of CO2 at high pressure were performed. The modeling considered the following important factors affecting CO2 sequestration: (1) the kinetics of chemical interactions between the host rock minerals and the aqueous phase, (2) CO2 solubility dependence on pressure, temperature and salinity of the system, and (3) redox processes that could be important in deep subsurface environments. The geochemical evolution under CO2 injection conditions was evaluated. In addition, changes in porosity were monitored during the simulations. Results indicate that CO2 sequestration by matrix minerals varies considerably with rock type. Under favorable conditions the amount of CO2 that may be sequestered by precipitation of secondary carbonates is comparable with and can be larger than the effect of CO2 dissolution in pore waters. The precipitation of ankerite and siderite is sensitive to the rate of reduction of Fe(III) mineral precursors such as goethite or glauconite. The accumulation of carbonates in the rock matrix leads to a considerable decrease in porosity. This in turn adversely affects permeability and fluid flow in the aquifer. The numerical experiments described here provide useful insight into sequestration mechanisms, and their controlling geochemical conditions and parameters.
Carbon dioxide capture and geological storage is an enabling technology that will allow the continued use well into this century of fossil fuels, mainly coal, for power generation and combustion in industrial processes because they are relatively abundant, cheap, available and globally distributed, thus enhancing the security and stability of energy systems. Geological media suitable for CO2 storage through various physical and chemical trapping mechanisms must have the necessary capacity and injectivity, and must confine the CO2 and impede its lateral migration and/or vertical leakage to other strata, shallow potable groundwater, soils and/or atmosphere. Such geological media are mainly oil and gas reservoirs and deep saline aquifers that are found in sedimentary basins. Storage of gases, including CO2, in these media has been demonstrated on a commercial scale by enhanced oil recovery operations, natural gas storage and acid gas disposal. Some of the risks associated with CO2 capture and geological storage are similar to, and comparable with, any other industrial activity for which extensive safety and regulatory frameworks are in place. Specific risks associated with CO2 storage relate to the operational (injection) phase and to the post-operational phase, of which the risks of most concern are those posed by the potential for acute or chronic CO2 leakage from the storage site. Notwithstanding the global climate effect of CO2 returning to the atmosphere, the local risks to health and safety, environment and equity need to be properly assessed and managed. Currently there are very few operations in the world where CO2 is injected and stored in the ground, mostly if not exclusively as a by-product of an operation driven by other considerations than climate change, such as oil production or regulatory requirements regarding H2S. These operations show that there are no major technological barriers to CO2 geological storage, and that challenges and barriers lie elsewhere. A major challenge in the implementation of CO2 geological storage is the high cost of CO2 capture, particularly for dilute streams like those from power plants and industrial combustion processes. There are concerns that public opinion and public's acceptance or rejection of this technology will likely affect the large-scale implementation of CO2 geological storage. The current paucity of policy, legislation and a proper regulatory framework in most jurisdictions is presently the most significant barrier. The resolution of these challenges will affect the economics and financial risk of CO2 geological storage and will accelerate or delay the deployment of this technology for reducing anthropogenic CO2 emissions into the atmosphere.
Carbon Capture and Storage may use deep saline aquifers for CO(2) sequestration, but small CO(2) leakage could pose a risk to overlying fresh groundwater. We performed laboratory incubations of CO(2) infiltration under oxidizing conditions for >300 days on samples from four freshwater aquifers to 1) understand how CO(2) leakage affects freshwater quality; 2) develop selection criteria for deep sequestration sites based on inorganic metal contamination caused by CO(2) leaks to shallow aquifers; and 3) identify geochemical signatures for early detection criteria. After exposure to CO(2), water pH declines of 1-2 units were apparent in all aquifer samples. CO(2) caused concentrations of the alkali and alkaline earths and manganese, cobalt, nickel, and iron to increase by more than 2 orders of magnitude. Potentially dangerous uranium and barium increased throughout the entire experiment in some samples. Solid-phase metal mobility, carbonate buffering capacity, and redox state in the shallow overlying aquifers influence the impact of CO(2) leakage and should be considered when selecting deep geosequestration sites. Manganese, iron, calcium, and pH could be used as geochemical markers of a CO(2) leak, as their concentrations increase within 2 weeks of exposure to CO(2).
Anthropogenic greenhouse-gas emissions continue to increase rapidly despite efforts aimed at curbing the release of such gases. One potentially long-term solution for offsetting these emissions is the capture and storage of carbon dioxide. In principle, fluid or gaseous carbon dioxide can be injected into the Earth's crust and locked up as carbonate minerals through chemical reactions with calcium and magnesium ions supplied by silicate minerals. This process can lead to near-permanent and secure sequestration, but its feasibility depends on the ease and vigour of the reactions. Laboratory studies as well as natural analogues indicate that the rate of carbonate mineral formation is much higher in host rocks that are rich in magnesium- and calcium-bearing minerals. Such rocks include, for example, basalts and magnesium-rich mantle rocks that have been emplaced on the continents. Carbonate mineral precipitation could quickly clog up existing voids, presenting a challenge to this approach. However, field and laboratory observations suggest that the stress induced by rapid precipitation may lead to fracturing and subsequent increase in pore space. Future work should rigorously test the feasibility of this approach by addressing reaction kinetics, the evolution of permeability and field-scale injection methods.
The possibility that substantial quantities of CO2 can be injected into subsurface porous rock formations has been investigated sufficiently to show that pore space available
to contain the CO2 is abundant. Multiple rock types and physical mechanisms can be used to trap the CO2 indefinitely. With careful site selection and operations, leakage to the near-surface region can be avoided. The next step
is to test these injection processes at the scale of a large power plant.