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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.
... 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 .
... 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 .
... 2. CO 2 migration in the reservoir obeys appropriate laws of physics (Sigfusson et al., 2015). Relationship outside injection well Synthetic saturation models Figure 3: Workflow of the velocity-and saturation-simulation algorithms. ...
... According to that function, CO 2 moves parallel to the upper aquifer boundary with a speed that exponentially decreases with depth. Hence, CO 2 always moves faster in the shallow region, which is driven by CO 2 buoyancy (Sigfusson et al., 2015). ...
... An additional factor that scientists must consider is the released heat factor produced from these reactions [25]. An important risk factor concerns the possible lack of sufficient amounts of carbon to achieve CO2 storage [30][31][32], although the risk can be decreased through dissolving CO2 in water prior to or during injection into geological formations, since this form is generally denser than CO2 in gas or at supercritical form [33][34][35]. It should be noted that, in general, the in situ methods should be deployed in cases of high CO2 volumes [36]. ...
... CO2 injection within basalts provides many advantages over other methods since it can achieve fast mineralization with its large potential storage volume [67,[91][92][93]. Through this method, CO2 is dissolved within water before injection into highly porous basalts [35,79,91]. Basalts are enriched with CaO, MgO, and FeO. ...
Carbon dioxide (CO2) has reached a higher level of emissions in the last decades, and as it is widely known, CO2 is responsible for numerous environmental problems, such as climate change. Thus, there is a great need for the application of CO2 capture and storage, as well as of CO2 utilization technologies (CCUS). This review article focuses on summarizing the current CCUS state-of-the-art methods used in Europe. Special emphasis has been given to mineralization methods/technologies, especially in basalts and sandstones, which are considered to be suitable for CO2 mineralization. Furthermore, a questionnaire survey was also carried out in order to investigate how informed about CO2 issues European citizens are, as well as whether their background is relative to their positive or negative opinion about the establishment of CCUS technologies in their countries. In addition, social acceptance by the community requires contact with citizens and stakeholders, as well as ensuring mutual trust through open communication and the opportunity to participate as early as possible in the development of actions and projects related to CO2 capture and storage, at all appropriate levels of government internationally, as citizens need to understand the benefits from such new technologies, from the local to the international level.
... Mineralization of CO2 in basaltic reservoirs has been demonstrated to be both rapid and effective during two pilot-scale field injection experiments. The CarbFix project in Iceland tested a water-dissolved CO2 method, where CO2 was dissolved into fresh water prior to injection, thus inducing geochemical trapping immediately [9,10]. Over 95% of the injected CO2 was mineralized within 2 years [11,12]. ...
... This simulates a hybrid of the injection strategies used in the CarbFix and Wallula field experiments. Although CO2 solubility decreases with increasing temperature and salinity, it increases at higher pressures [35,36]; so, for this deep ocean site, the simulated seawater-dissolved-CO2 scenarios contain greater dissolved CO2 concentrations than the injected CarbFix waters (~6% and 4%, respectively) [9]. Whereas scCO2 will clearly dissolve more readily into CO2-free water [36,37], investigating WAG with CO2-saturated-seawater may be particularly useful for site-specific applications. ...
... Gas was released as fine bubbles into the water at depth, which completely dissolved into the water before it entered the porous aquifer rocks. In this case, water was pumped in the annulus space and gas was injected in the central tubing (Sigfusson et al., 2015). To reduce costs and to streamline the original CarbFix approach, CO2 and H2S dominated gas mixture was and continues to be directly captured from the power plant exhaust gas stream by its dissolution into pure water in a scrubbing tower (Aradotti et al., 2015). ...
... The two fluids are mixed at a certain depth and a part of the NCGs is then progressively dissolved into the water flow and the mixture is re-injected into the reservoir at the bottom hole. The prototype completion extends the original CarbFix solution (Sigfusson et al., 2015) to the case of high NCG content and is similar to the solution proposed by Shafaei et al. (2012) for CO2 storage in aquifers. Recompression of the gas occurs in the two-phase flow section of the well and allows reduction of NCG compression at the surface: this approach improves the overall efficiency and the cost of the system. ...
High enthalpy geothermal systems, including vapour-dominated reservoirs, may contain non-condensable gases (NCGs). Thus, the steam production is accompanied with emissions of geothermal gases (CO2, H2S, H2….) initially dissolved in the liquid phase or mixed in a vapour phase at depth in the reservoir. In order to reduce the environmental impact of geothermal exploitation resources and avoid emission of greenhouse or toxic gases in the atmosphere, NCGs have to be captured and re-injected. This approach leads to an environmentally friendly exploitation, pressure support and geothermal resource sustainability. For low NCG content, the gases can be fully dissolved at the surface in the condensed water and re-injected. However, for high concentration of NCG, the dissolution is only partial and a two-phase flow (gaseous NCGs and condensed water) needs to be re-injected. We focus here on presenting the fluid flow model of a completion configuration ensuring the simultaneous re-injection of NCGs and condensed water in the same well. A specific geothermal site was selected as base case, main characteristics of which are the high concentration of NCGs on the production geothermal fluid (mainly vapour) and the low injection reservoir pressure. The objective of the current work is to study the complete operation of reinjection under non-isothermal steady state conditions and to demonstrate its efficiency. The prototype well completion consists in an annulus completion with water circulating in one part and non-condensable gases in the other. The two fluids are mixed at a given depth and through several injection points. A part of the non-condensable gases is then progressively dissolved into the liquid phase within the flow and the mixture flow is re-injected into the reservoir at the bottom hole. The recompression occurring in the two-phase flow section of the well allows reduction of NCG compression at the surface improving the overall efficiency and the cost of the system. The model takes into account the single phase flows of water and NCGs, the hydrodynamics of the two-phase downward flow with two major components (H2O and CO2) in the injected fluid, constitutive laws for the mixtures, the dissolution of gas into water, and the evaporation of the aqueous phase into the gaseous phase. Finally, the heat exchange between the surrounding ground, the annulus and the central part of the well is modelled.
... Whether CO 2 is injected as a separate fluid (gaseous, liquid, or supercritical) or dissolved in water (details regarding the injection of CO 2 as a dissolved aqueous phase in Sigfússon et al. 2015) depends on capture strategy, formation characteristics, and in situ conditions. Various physical and geochemical trapping mechanisms (structural/stratigraphic, capillary/residual, solubility, and mineral trapping) may act within the formation, influencing the performance and the safety of carbon dioxide storage over different time scales (IPCC 2005;Ide et al. 2007;Kopp et al. 2010;Trevisan et al. 2014;Bachu 2015;Krevor et al. 2015;Trevisan et al. 2017;Snaebjörnsdóttir et al. 2020). ...
... However, these conditions are difficult to find in sedimentary basins due to their low reactivity with CO 2 . Conversely, mafic and ultramafic rocks are reactive enough to allow for a fast mineralization of carbon dioxide (especially when already dissolved in water before or during injection; Sigfússon et al. 2015;Matter et al. 2016;Gunnarsson et al. 2018;Snaebjörnsdóttir et al. 2020), thus making alternative GCS technologies like in situ mineral carbonation competitive and appealing over short time scales as well (Alfredsson et al. 2013;Snaebjörnsdóttir et al. 2017). ...
Particular attention is paid to the risk of carbon dioxide (CO2) leakage in geologic carbon sequestration (GCS) operations, as it might lead to the failure of sequestration efforts and to the contamination of underground sources of drinking water. As carbon dioxide would eventually reach shallower formations under its gaseous state, understanding its multiphase flow behavior is essential. To this aim, a hypothetical gaseous leak of carbon dioxide resulting from a well integrity failure of the GCS system in operation at Hellisheiði (CarbFix2) is here modeled. Simulations show that migration of gaseous carbon dioxide is largely affected by formation stratigraphy, intrinsic permeability, and retention properties, whereas the initial groundwater hydraulic gradient (0.0284) has practically no effect. In two different scenarios, about 18.3 and 30.6% of the CO2 that would have been injected by the GCS system for 3 days could be potentially released again into the atmosphere due to a sustained leakage of the same duration. As the gaseous leak occurs, the aquifer experiences high pressure buildups, and the presence of a less conductive layer further magnifies these. Strikingly, the dimensional analysis showed that buoyant and viscous forces can be comparable over time within the predicted gaseous plumes, even far from the leakage source. Local pressure gradients, buoyant, viscous, and capillary forces all play an important role during leakage. Therefore, neglecting one or more of these contributions might lead to a partial prediction of gaseous CO2 flow behavior in the subsurface, giving space to incorrect interpretations and wrong operational choices.
... 60 In order to maintain CO 2 in dissolved state, the ratio of CO 2 to H 2 O should be kept less than the solubility of CO 2 at reservoir condition. 61 Solubility of CO 2 in brine (UW-8B) is simulated using PHREEQC at various pressure values and the assigned temperature of 200°C (473.15 K). ...
... 68 However, this timespan depends on the host rock identity and the availability of metallic ions required for precipitation of carbonate minerals, and can be shortened if CO 2 is injected in soluble form rather than gaseous. 61 In this study, complete transition from solubility to mineral trapping occur in the period from 4 days to 1 year after injection. Equilibrium between CO 2 -brine reservoir rock is achieved 10 years after injection (see Fig. 7). ...
Carbon capture and storage (CCS) is considered to be an effective method to mitigate anthropogenic carbon emissions that have been the major cause of global warming. One of the possible sites to store CO 2 is in geothermal reservoirs. In this study, an attempt to simulate CO 2-brine reservoir rock interaction inside a geothermal reservoir is carried out using the PHREEQC program. The study utilizes published rock mineralogy of the assumed reservoir lithology and chemistry of the hot water in the Ungaran geothermal field, Java, Indonesia. The simulation is based on equilibrium and kinetic modeling and assumes a single stage CO 2 injection kept at a constant temperature and pressure. The amount of injected CO 2 is determined by solubility modeling of CO 2 in hot water under estimated reservoir conditions. The modeling predicted (i) the effect of solubility trapping at early stages of CO 2-brine rock interaction, (ii) dissolution of Ca-bearing silicates (plagioclases) coupled with calcite precipitation as a potential chemical processes relevant to a possible CO 2 mineralization, (iii) progressive transition from solubility to mineral trapping becoming significant after 30 days following injection, (iv) minor porosity increase (∼0.5%), and (v) achievement of equilibrium between CO 2-brine-rock in 10 years after injection. Sensitivity analysis associated with the uncertainties for altering mineral proportion and rock porosity reveal no significant change in the ability of the modeled reservoir to trap injected CO 2 into mineral phases. Concerning the CCS studies so far carried out in geothermal fields in volcanic reservoirs, this modeling comprises one of the first performed for fields with intermediate volcanics. The result from this study can be utilized as foreknowledge for possible future CCS operations in Indonesian geothermal fields.
... With this approach, the captured carbon is stored through its injection into reactive rocks, such as mafic or ultramafic lithologies, which contain high concentrations of divalent cations, such as Ca 2+ , Mg 2+ and Fe 2+ , for rapid mineralization to calcite (CaCO 3 ), dolomite (CaMg(CO 3 ) 2 ) or magnesite (MgCO 3 ). Mineral carbonation can be further promoted by the dissolution of CO 2 into water before or during its injection, achieving solubility trapping immediately 11 and mineral trapping within 2 years ( fig. 1b) at 20-50 °C (ref. ...
... The method requires large amounts of water: ~25 tonnes of water for each tonne of gas injected to fully dissolve the CO 2 at depth. However, as the gascharged water is denser than fresh water, solubility trapping occurs immediately 11 . Injection of the acidic gascharged water accelerates metal release from the bedrock and, hence, the formation of carbonate minerals 12,77 . ...
Carbon capture and storage (CCS) has a fundamental role in achieving the goals of the Paris Agreement to limit anthropogenic warming to 1.5–2 °C. Most ongoing CCS projects inject CO2 into sedimentary basins and require an impermeable cap rock to prevent the CO2 from migrating to the surface. Alternatively, captured carbon can be stored through injection into reactive rocks (such as mafic or ultramafic lithologies), provoking CO2 mineralization and, thereby, permanently fixing carbon with negligible risk of return to the atmosphere. Although in situ mineralization offers a large potential volume for carbon storage in formations such as basalts and peridotites (both onshore and offshore), its large-scale implementation remains little explored beyond laboratory-based and field-based experiments. In this Review, we discuss the potential of mineral carbonation to address the global CCS challenge and contribute to long-term reductions in atmospheric CO2. Emphasis is placed on the advances in making this technology more cost-effective and in exploring the limits and global applicability of CO2 mineralization.
... 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.
... 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.
... Initial reports from the project confirmed their injection method was successful in preventing the buoyancy of CO2 usually associated with injecting it into the subsurface. By dissolving the CO2 in water for injection, solubility trapping was demonstrated in less than 5 minutes Sigfússon et al., 2015). This helps minimise some the of risk associated with supercritical or gaseous state CO2, which would likely be prone to leakage without an impermeable caprock layer. ...
This thesis aims to examine whether andesitic rock samples are likely to be good targets for permanent carbon sequestration via mineral trapping, as an alternative to basaltic-type reservoirs which have been proven to be successful. The CarbFix project in Iceland and the Wallula Basalt Pilot Scale project both reported results from field scale studies that suggested carbonation reactions had occurred within just two years in basaltic-type reservoirs, which is a significant improvement on the thousands of years needed for other geological carbon storage methods to be considered permanent. Carbon dioxide was successfully sequestered in these systems, after mineral dissolution reactions with the injected acidic fluids, which released divalent cations able to combine with the dissolved CO2 and precipitate carbonate minerals. However, there is a significant lack of research examining whether alternative volcanic rocks such as andesite may also be suitable. If alternative volcanic rocks can also be utilised as targets for permanent carbon sequestration in short timescales, this would expand the accessibility of the CarbFix project to more global locations and help mitigate the impacts of rising CO2 concentrations in the atmosphere. Rock samples from the region of Rantau Dedap on the Island of Sumatra, Indonesia, were first characterised in detail to examine their mineralogical and chemical compositions, with results indicating they were of andesitic composition. Batch reactor experiments were conducted under elevated temperatures of 100oC and pH values close to 3 using crushed andesite type rock samples, to simulate carbon sequestration conditions close to the site of injection. The release of silicon into the experimental fluids was used to calculate a bulk rock dissolution rate of the order 10-11 mol/m2/s for the andesite type rocks, which is roughly 1-2 orders of magnitude slower than reported basaltic dissolution rates. Mineral dissolution in basaltic systems is considered to be the rate limiting step in the permanent carbon sequestration via mineral trapping process, and so these results indicate that permanent sequestration of CO2 in andesitic systems may take slightly longer than the basaltic systems which saw sequestration in just two years. However, significant divalent cation release was observed as a result of mineral dissolution, which suggests andesitic samples may still have a good carbon sequestration potential. To expand on these findings, batch experiments were conducted using resin embedded andesite rocks, at temperatures of 100oC and increased concentrations of CO2 and calcium, to simulate conditions further from the site of injection. Some mineral dissolution was observed as well as divalent cation release. Evidence from electron microscope and energy dispersive x-ray techniques indicated two of the samples which had a feldspar composition with a higher anorthite content had an increased amount of calcite minerals present at the end of the 3-day experiments. These results give a positive indication that andesite samples are likely to support relatively rapid carbon sequestration via mineral trapping under conditions relevant to CO2 injection. The two samples also had a higher content of alteration minerals present compared to the third sample which indicates that the presence of calcic-plagioclase and/or alteration minerals increase the potential for permanent carbon sequestration in andesitic-type reservoir systems. Batch experiments were conducted to examine the impact of using fluids with increase NaCl concentrations up to 2.1 M, instead of freshwater, on the dissolution of feldspar minerals. If saline type fluids can be used as well as freshwater to dissolve CO2 for subsurface injection in volcanic rock systems, the feasibility of using this technique for carbon sequestration will be made more accessible in new locations worldwide. Silicon and aluminium release into the fluids in all experiments of a similar magnitude with varying NaCl concentrations indicates that using saline fluids is unlikely to have a negative impact on the carbon sequestration potential of a volcanic rock reservoir. Comparison between two feldspar mineral compositions indicates that a sample with a higher anorthite content may be more effective at buffering the acidity of acidic saline fluids, which is essential for initiating carbonation reactions, and so targeting such mineralogy’s is likely to be most effective. The water adsorption isotherms of samples before and after use in rock-fluid experiments were collected for andesitic rock samples, to determine whether a change in mineralogy as a result of acidic fluid dissolution has an impact on the water adsorption capacity of the rocks. The results indicate the andesitic samples have a water adsorption capacity of roughly 5.0 – 9.2 mg/g, which is comparable to previous studies using rock samples from other geothermal reservoir systems. The collected isotherms indicate that the water adsorption capacity of the samples increases after reaction with representative geothermal fluids, particularly if acidic fluids are used. The authors interpret this is a result of increased reactive surface areas after reaction and gives some indication that the water adsorption capacity of a reservoir is unlikely to be negatively impacted as a result of changing mineralogy during injection of acidic fluids. Overall, the results from this whole project indicate that andesitic rock samples should be further examined as potential targets for permanent carbon sequestration and that utilising seawater instead of freshwater for CO2 injection is likely to be a viable alternative and make the technique more globally accessible. However, significant research is still needed in these areas, to examine more long-term impacts of such suggestions and in particular, the impact of inducing such precipitation reaction will have on the overall permeability of a volcanic rock reservoir system. The impact of alterations minerals on the carbon sequestration potential in terms of possible cation release on dissolution, and permeability reducing properties on precipitation should be examined particularly closely.
... differential pressure with dead brine injection was used to calculate the initial sample permeability. Ten pore volumes of live brine (with a pH 3-4 (Schaef and McGrail, 2005;Sigfusson et al., 2015;He et al., 2020)), which was prepared by mixing dead brine with CO 2 in a stirred reactor (El-Maghraby et al., 2012) at 6.9 MPa and 323 K, was injected. This is because the CO 2 will be dissolved in the aquifer's water beyond the wellbore area after injection. ...
Deep saline aquifers and depleted carbonate reservoirs are generally considered promising locations for subsurface CO2 storage. However, carbonate minerals particularly calcite can react with CO2-saturated brine, resulting in dissolution of carbonate and potentially mechanical compaction. Thus, it is crucial to understand the extent of this reaction in both water-wet and oil-wet scenarios, and subsequently its consequences on CO2 storage in depleted carbonate reservoirs. In this study, medical X-ray computed tomography (CT) was used to image water-wet and oil-wet Indiana limestone core samples before and after CO2 flooding. Changes in the rock matrix and pore structure were further assessed from the porosity and permeability data computed from the CT images. In both cases, imaging shows a significant amount of dissolution resulting in an increase in pore volume after core flooding with live brine and subsequently CO2. This increase in porosity is 46.7% and 19% for the water-wet and oil-wet core, respectively. Likewise, the brine permeability for the water-wet core increased from 9.2 mD (before CO2 flooding) to 108 mD (after CO2 flooding), whereas the permeability for the oil-wet core increased modestly from 9.0 mD to 20.1 mD. These results suggests that the reactivity is less pronounced in the oil-wet rock compared to the water-wet rock. Therefore, the wettability state of a target carbonate reservoir and the subsequent potential for the wettability state to be modified should be considered when assessing the CO2 storage capacity and integrity.
... The injected CO 2 could dissolve in formation brine at the CO 2 -brine interface, altering the concentration of aquifer fluid, thus leading to precipitation. Regardless of rock composition, the progressive dissolution of CO 2 in the brine (formation water) forms carbonic acid that leads to a reduction in pH to about 3-5 [66,67]. The following reactions occur at the interface between both media ...
Climate change is now considered the greatest threat to global health and security. Greenhouse effect, which results in global warming, is considered the main driver of climate change. Carbon dioxide (CO2) emission has been identified as the largest contributor to global warming. The Paris Agreement, which is the biggest international treaty on Climate Change, has an ambitious goal to reach Net Zero CO2 emission by 2050. Carbon Capture, Utilization and Storage (CCUS) is the most promising approach in the portfolio of options to reduce CO2 emission. A good geological CCUS facility must have a high storage potential and robust containment efficiency. Storage potential depends on the storage capacity and well injectivity. The major target geological facilities for CO2 storage include deep saline reservoirs, depleted oil and gas reservoirs, Enhanced Oil Recovery (EOR) wells, and unmineable coal seams. Deep saline formations have the highest storage potential but challenging well injectivity. Mineral dissolution, salt precipitation, and fines mobilization are the main mechanisms responsible for CO2 injectivity impairment in saline reservoirs. This chapter reviews literature spanning several decades of work on CO2 injectivity impairment mechanisms especially in deep saline formations and their technical and economic impact on CCUS projects.
... Standard ScCO 2 injection generally requires deeper reservoir conditions to maintain the supercritical fluid (>800 m, 31°C) and a secure seal to contain the buoyant plume. New and emerging proposed techniques such as injection of CO 2 dissolved in production water or wastewater or CO 2 injected as a nano-emulsion may accelerate trapping mechanisms, avoid ScCO 2 dry out, and avoid the need for deep reservoirs or secure seals (Khan et al. 2021;Pearce et al. 2021a;Sigfusson et al. 2015;Snaebjörnsdóttir et al. 2018;Pearce et al. 2022). In Australia, several deep, high-salinity, or low-salinity aquifers are being considered for CO 2 storage reservoirs (Garnett et al. 2019;Pearce et al. 2021b;Saeedi et al. 2016). ...
Carbon dioxide (CO2) capture from industrial sources including coal combustion, gas processing, cement or steel production, blue hydrogen, or direct air capture, and subsequent geological storage is part of the transition to reduce greenhouse gas emissions. Unconventional and conventional reservoirs provide opportunities for beneficial use such as enhanced recovery, supercritical CO2 (ScCO2) fracturing, and storage of gases such as CO2 and ancillary gases, or potentially hydrogen. The purpose of this study is to use Australian unconventional rock packages to understand the controls on CO2 reactivity and mineral trapping (the most secure form of storage) and compare the potential for CO2 storage. Characterization of core from the Surat, Eromanga, and Cooper basins, Australia, is used to populate CO2 and production water-rock reactivity models. Sensitivity to production water composition and temperature was also tested. Coal seam gas (CSG) reservoir interburden ranged from clay-rich mudstones to interlaminated sandstone and mudstone, and calcite cemented sandstones. The coal seam interburden samples contained high plagioclase and chlorite content. They were predicted to alter to carbonates calcite, ankerite, siderite, and dawsonite mineral trapping CO2. After 30 years, net mineral trapping varied from −0.1 to +0.3 kg CO2/m3, and pH was 4.6–4.9. Net mineral trapping after 1,000 years varied from 5.7 to 16.3 kg CO2/m3 and was 17.1 kg CO2/m3 with higher salinity water. The mineral content had the main control with different lithologies decreasing mineral trapping by 41 or 35% compared with a base case. Overlying plagioclase-rich sandstone trapped 17.1 kg CO2/m3 as calcite, ankerite, dawsonite, and siderite after 1,000 years with the pH increasing to 6. For the quartz-rich oil reservoir sandstone, however, only 0.3 kg CO2/m3 was trapped after 1,000 years. Gas shale and marine black oil shales contained high mica, chlorite, and feldspar content that could be converted to carbonate minerals, mineral trapping CO2. A marine black oil shale mineral trapped 8.3 and 13.9 kg CO2/m3 after 30 and 1,000 years, respectively, as siderite and ankerite. Unconventional reservoirs have a strong potential for mineral trapping during CO2 storage.
... The vaporization of water from the brine into the gas phase could lead to salt precipitation due to drying (Miri & Hellevang, 2016;Peysson, Bazin, Magnier, Kohler, & Youssef, 2011). The dissolved CO 2 in formation brine will produce carbonic acid that lowers the pH to about 3-5 which has a significant impact on rock properties such as permeability and porosity Schaef & McGrail, 2005;Sigfusson et al., 2015;Zou et al., 2018). This reaction leads to ion-dissolution-precipitation and generates fines particles, considered as secondary minerals into the pore fluid, that could be mobilized, reducing the rock permeability when entrapped at the pore throats. ...
Southeast Asia is increasingly gaining attention as a promising geological site for permanent CO2 sequestration in deep saline aquifers. During CO2 injection into saline reservoirs, the reaction between injected CO2, the resident formation brine, and the reservoir rock could cause injectivity change due to salt precipitation, mineral dissolution, and fine particles migration. The underlying mechanisms have been extensively studied, both experimentally and numerically and the governing parameters have been identified and studied. However, the current models that have been widely adopted to investigate reactive transport and its impact on CO2 injectivity have fundamental limitations when applied to solve small, high dimensional, and non-linear data. The objective of this study is to develop efficient and robust predictive models using support vector regression (SVR) integrated with hyperparameter tuning optimization algorithms, including genetic algorithm (GA). To develop the model, 44 datasets are used to predict the CO2 injectivity change with its influencing variables such as brine salinity, injection flow rate, particle size, and particle concentration. The performance for each model is analyzed and compared with previous models by determination of coefficient (R2), adjusted determination of coefficient (R¯2), average absolute percentage error (AAPE), root mean square error (RMSE) and mean absolute error (MAE). The model with the highest R2 is selected as the predictive model for CO2 injectivity impairment during CO2 sequestration in a saline aquifer. The results revealed that both SVR and GA-SVR are able to capture the precise correlation between measured and predicted data. However, the GA-SVR model slightly outperformed the SVR model by a higher R2 value of 0.9923 compared to SVR with R2 value of 0.9918. Based on SHAP value analysis, brine salinity had the highest impact on CO2 injectivity change, followed by injection flow rate, particle concentration, and jamming ratio. It was also found that hybridization of genetic algorithm with support vector regression does improve the model performance contrary to single algorithm and contributes to the determination of the most impactful factors that induce CO2 injectivity change. The proposed model can be upscaled and integrated into field-scale models to improve the optimization of CO2 injectivity in deep saline reservoirs.
... We also see similarly short simulation times in numerical modelling studies with a focus on the many chemical reactions taking place (Kang et al. 2006(Kang et al. , 2010Jiang and Tsuji 2014) at the expense of a detailed representation of the pore geometry and flow conditions. Sigfusson et al. (2015) and Snaebjörnsdóttir et al. (2020) comment that MT becomes a more prominent carbon sequestering process with time, showing significantly more mineralisation from around 100 years after injection. This highlights the importance of geologically significant simulation durations. ...
Mineral trapping (MT)is the most secure method of sequestering carbon for geologically significant periods of time. The processes behind MT fundamentally occur at the pore scale, therefore understanding which factors control MT at this scale is crucial. We present a finite elements advection–diffusion–reaction numerical model which uses true pore geometry model domains generated from $$\upmu$$ μ CT imaging. Using this model, we investigate the impact of pore geometry features such as branching, tortuosity and throat radii on the distribution and occurrence of carbonate precipitation in different pore networks over 2000 year simulated periods. We find evidence that a greater tortuosity, greater degree of branching of a pore network and narrower pore throats are detrimental to MT and contribute to the risk of clogging and reduction of connected porosity. We suggest that a tortuosity of less than 2 is critical in promoting greater precipitation per unit volume and should be considered alongside porosity and permeability when assessing reservoirs for geological carbon storage (GCS). We also show that the dominant influence on precipitated mass is the Damköhler number, or reaction rate, rather than the availability of reactive minerals, suggesting that this should be the focus when engineering effective subsurface carbon storage reservoirs for long term security.
Article Highlights
The rate of reaction has a stronger influence on mineral precipitation than the amount of available reactant.
In a fully connected pore network preferential flow pathways still form which results in uneven precipitate distribution.
A pore network tortuosity of <2 is recommended to facilitate greater carbon mineralisation.
... Since CO 2 dissolved in water is denser than an injected buoyant gas or supercritical CO 2 plume, storage of dissolved CO 2 has been applied in Iceland for the purposes of reducing the risk of leakage in basalt formations at depths ~800m. CO 2 and H 2 S dissolved during injection into wastewater from the Hellisheidi geothermal power plant has been successfully stored subsurface in basalt in the CarbFix pilot project since 2012 at Reykjavik, Iceland (Gislason et al., 2010;Matter et al., 2016;Sigfusson et al., 2015). The CarbFix project has also famously shown that mineral trapping of CO 2 as carbonate minerals, and H 2 S as precipitated pyrite, was possible within just 2 years in a basalt formation. ...
During geological CO2 storage traditionally CO2 is injected subsurface into a high permeability reservoir capped by a low permeability seal to trap the buoyant supercritical plume. Wastewater from oil and gas production is also currently disposed of by subsurface injection into suitable reservoirs, most notably in the USA and Canada. Injection of CO2 dissolved in water may both increase storage security by reducing vertical migration and enhancing dissolution and mineral trapping. There is potential for surface dissolution of CO2 into wastewater that is already being stored subsurface. CO2-water-rock reactions in different sandstone or limestone reservoir rocks with either saline coal production water or low salinity water were geochemically modelled. The geochemical potential for mineral trapping of CO2, and associated changes to pH for potential reservoirs is compared. For a mineralogically clean quartz-rich saline sandstone reservoir only 0.18 and 0.20 kg/m³ CO2 was mineral trapped as ankerite and calcite over 30 or 1000 years. Feldspars, clays and carbonate minerals were converted to kaolinite, calcite, ankerite and smectites, as pH increased to 5.65. The specific silicate minerals present controlled mineral trapping potential e.g. with an Fe-rich chlorite present rather than a clinochlore chlorite 6.3 and 6.8 kg/m³ CO2 was trapped at 30 and 1000 years respectively as siderite and ankerite. Dissolution trapping dominated in the low salinity or limestone reservoirs with minor mineral trapping. The presence of small amounts of SO2 or H2S in the CO2 stream resulted in dissolved S sequestered as elemental S, pyrite, barite, and anhydrite. The effects of low CO2 content or potential reservoir cooling induced by injection fluids were also investigated. The low pH of the injection fluid could potentially corrode legacy wellbores, one solution is a form of amendment such as liming to neutralise pH.
... The simulations in this subsection consider CO 2 injection using the CarbFix method (Sigfússon et al., 2015), that is, the injection of formation water with pre-dissolved CO 2 . During the primary injection period, we inject formation water that has been brought up to the solubility limit a,sat c . ...
Unlike sedimentary formations, flood basalts have the potential for relatively rapid mineral trapping when used as an injection target for CO2 storage. However, there are still open questions surrounding the implementation of CO2 storage in basalt at a large scale. These include how the porosity of the target formation will be altered by the geochemical activity, as well as whether a large‐scale CO2 storage project can expect the same fast mineralization rates observed during small‐scale pilot injections. Field‐scale numerical modeling studies can play a role in answering these questions, by improving our understanding of the way in which details such as mineralogy, temperature or injection strategy affect the timing and spatial location of geochemical processes. Simulations of reactive transport processes in the subsurface often rely on computationally demanding methods. Although these methods provide comprehensive simulation capabilities, they may not provide the efficiency needed for wide exploration of parameter spaces or for simulations over long time scales. The present work combines a vertically integrated model of two‐phase flow in porous media with a fully customizable geochemical model to create an efficient vertically integrated method for field‐scale simulation of CO2 mineral trapping in basalt. The proposed method provides a platform for extensive field‐scale modeling studies that can help address some of the remaining barriers to large‐scale implementation of CO2 storage in basalt formations.
... These minerals react differently to the changing environment when CO 2 is injected, e.g., calcite cement is highly reactive in an acidic environment [35,39,40]. In fact, pH decreases to 3-4 when CO 2 mixes with brine at reservoir conditions [41,42], and such an acidic condition can considerably affect the permeability and pore morphology [43]. Alternatively, CO 2 can be stuck in the target reservoir's pore space for hundreds or thousands of years because of the slow dissolution kinetics caused by the partial mixing of CO 2 and brine [44]. ...
Wettability is one of the main parameters controlling CO2 injectivity and the movement of CO2 plume during geological CO2 sequestration. Despite significant research efforts, there is still a high uncertainty associated with the wettability of CO2/brine/rock systems and how they evolve with CO2 exposure. This study, therefore, aims to measure the contact angle of sandstone samples with varying clay content before and after laboratory core flooding at different reservoir pressures, of 10 MPa and 15 MPa, and a temperature of 323 K. The samples’ microstructural changes are also assessed to investigate any potential alteration in the samples’ structure due to carbonated water exposure. The results show that the advancing and receding contact angles increased with the increasing pressure for both the Berea and Bandera Gray samples. Moreover, the results indicate that Bandera Gray sandstone has a higher contact angle. The sandstones also turn slightly more hydrophobic after core flooding, indicating that the sandstones become more CO2-wet after CO2 injection. These results suggest that CO2 flooding leads to an increase in the CO2-wettability of sandstone, and thus an increase in vertical CO2 plume migration and solubility trapping, and a reduction in the residual trapping capacity, especially when extrapolated to more prolonged field-scale injection and exposure times. View Full-Text
Keywords: CO2 injectivity; wettability; contact angle; sandstone; CO2 sequestration
... Quartz dissolution [39] is given by: However, at low pH, the effect of pH dissolution is negligible and has not been observed in short-term laboratory tests. Moreover, the acidic environment of CO 2 -brine dissolution only reduced the pH value to about 4 in this experiment and would not lower the pH below 3 [43,44]. Fig. 4 FESEM images of quartz-rich sandstone B core samples saturated with 30,000 ppm of NaCl show the pore space enlargement due to dissolution causing an increase in pore connectivity. ...
Injection of carbon dioxide (CO2) into saline aquifer for sequestration is a promising approach to mitigate the climate issue. However, reactive interactions between various CO2–brine–rock parameters have significantly affected the CO2 sequestration. Factors such as brine type, brine salinity, reactive pore surface area and contact time were found to significantly alter the physical rock properties. Until now, a systematic study on the dominance and degree of influence of each factor has yet to be carried out. To further understand environmental factors that impact dissolution and precipitation mechanisms, we combined the four influencing factors in static batch experiments and observed the physical changes on formation rock and ranked them according to the level of dominance by using Taguchi method. Static batch CO2–brine–rock experiments were carried out by injecting supercritical CO2 in an aging cell filled with brines and cubes of rock samples. The results showed that brine salinity is the most notable factor, followed by reactive pore surface area and duration of exposure. Comparison of field emission scanning electron microscope images taken before and after experiments indicated changes among potassium chloride (KCl), sodium chloride (NaCl) and calcium chloride (CaCl2) brines resulting in dramatic changes of pore spaces because of mineral dissolution, deposited salts, and fines migration.
... Dans une première phase, 175 tonnes de CO2 commercial pur ont été injectées de janvier à mars 2012 afin de tester la faisabilité du stockage de gaz sous forme minérale . Puis dans un second temps, 73 tonnes d'un mélange purifié de gaz dérivé de la centrale géothermique d'Hellisheiði ont été injectées de juin à août 2012 pour tester cette fois la faisabilité du stockage minéral d'un mélange de gaz plus proche des rejets industriels (Sigfusson et al. 2015 ;Matter et al. 2016). ...
La subsurface est considérée comme le plus vaste habitat sur Terre, abritant la majorité de la biomasse et des espèces microbiennes. La croûte océanique constitue le plus grand aquifère de notre planète où les réactions eau-roche pourraient fournir des sources de carbone abiotique et d’énergie à la base de la structuration des écosystèmes profonds. Cette thèse s’intéresse à deux réactions majeures associées à l’hydrothermalisme en subsurface, que sont la serpentinisation des péridotites mantelliques et l’altération des basaltes cristallins, pour comprendre comment l’altération des roches peut soutenir les écosystèmes microbiens profonds. Dans cet objectif, la diversité des communautés microbiennes et leur potentiel métabolique ont été caractérisés (i) sur un site hydrothermal serpentinisé, à savoir le site hydrothermal de Old City (OCHF), récemment découvert dans la région orientale de la dorsale ultralente sud-ouest indienne (SWIR), (ii) ainsi que dans un aquifère basaltique influencé par des injections de gaz acides, situé à Hellisheiði (Islande). Les approches métagénomiques ont révélé que la diversité microbienne et les métabolismes à OCHF dépendent de l’influence relative des fluides dérivés de la serpentinisation et de l'eau de mer. De plus, nos résultats suggèrent une forte hétérogénéité au sein et entre les évents hydrothermaux, probablement due aux fluides hydrothermaux très diffus dans ces évents. Les niches microbiennes sont potentiellement discriminées à la micro-échelle selon l’interaction entre les fluides hydrothermaux et l'eau de mer, fournissant ainsi différents nutriments. Un résultat majeur de cette thèse est la mise en évidence de phylotypes microbiens, potentiellement influencés par la serpentinisation, à OCHF proches de microorganismes d’écosystèmes serpentinisés terrestres plutôt qu'à son unique analogue océanique, à savoir le site hydrothermal de Lost City (LCHF). Or, OCHF est situé dans la région la plus amagmatique de la SWIR, alors que les gabbros sont répandus sous LCHF. Nous avons donc postulé que les intrusions magmatiques, impactant à la fois la minéralogie et la température et composition des fluides hydrothermaux, pourraient être le principal facteur expliquant les différences entre les communautés microbiennes d’OCHF et LCHF. Les comparaisons génomiques des populations microbiennes vivant dans des systèmes serpentinisés distincts ont mis en évidence plusieurs stratégies d'adaptation pour faire face aux conditions extrêmes liées à la serpentinisation. En outre, cette thèse présente les fonctions métaboliques des groupes taxonomiques dans l'aquifère basaltique de Hellisheiði, où l'altération des roches et les précipitations de minéraux suite aux injections de gaz soutiennent fortement les communautés microbiennes. Cette thèse vient étayer les preuves antérieures selon lesquelles l'écologie des écosystèmes microbiens profonds est fortement liée aux processus abiotiques de subsurface qui dépendent des régimes hydrogéologiques.
... It requires knowledge and skills from geology, fluid mechanics, chemistry, geochemistry, hydrogeology, and environmental science. Current research questions in CO2 geological sequestration focus on the improvement of the injection techniques (Hoteit et al., 2019;Sigfusson et al., 2015), ensuring safe and successful implementation (Romasheva and Ilinova, 2019;Singh and Islam, 2018;Soltanian et al., 2019), enhancement of reservoirs capacity (Kim et al., 2017;Raziperchikola et al., 2013), and assessment and prediction of the geological and environmental impacts (Chen et al., 2018). A key point in addressing these research questions relies on a good understanding of the fate of CO2 in geological formations. ...
Carbon dioxide (CO2) storage in geologic formations is an attractive means of reducing greenhouse gas emissions. The main processes controlling the migration of CO2 in geological formations are related to convective mixing and geochemical reactions. The effects of heterogeneity on these coupled processes have been widely discussed in the literature. Recently, special attention has been devoted to fractured geological formations that can be found in several storage reservoirs. However, existing studies on the effect of fractures on the fate of CO2 neglect the key processes of geochemical reactions. This work aims at addressing this gap. Based on numerical simulations of a hypothetical reservoir, we explore the effect of fracture properties and topology on the domain’s storage capacity at different rates of CO2 mineral dissolution. It is found that the fractures not only can help the mixing convection and reaction process in the domain but also may play a restrictive role in entering dissolved CO2 and hinder the plume fingers from growing. The hypothetical case is relevant in providing preliminary understanding but can show varying degrees of geological realism. For more representative geology, we investigate the migration-dissolution of buoyant CO2 on a large-scale outcrop of a volcanic basalt rock formation. The results show that neglecting thin fractures can significantly affect the predicted amount of trapped CO2. The storage capacity is more sensitive to heterogeneity at low dissolution rates. The findings are useful for the management of CO2 sequestration in fractured domains.
... 230 tons of CO 2 and purified geothermal gases composed of 75% CO 2 + 24.2% H 2 S + 0.8% H 2 mixed with water into the subsurface. It was followed by a rapid removal of carbon from the fluid, including mineralization within 2 months after the injection stopped (Gíslason et al., 2014;Sigfusson et al., 2015;Snaebjörnsdóttir et al., 2018). Approximately 165 tons of CO 2 were stored in biomass or precipitated into calcite, indicative of a sequestration efficiency of 72 AE 5% (Pogge von Strandmann et al., 2019). ...
Carbon capture and storage technologies are crucial for reducing carbon emission from power plants as a response to global climate change. The CarbFix project (Iceland) aims at examining the geo-chemical response of injected CO2 into subsurface reservoirs. The potential role of the subsurface bio-sphere has been little investigated up to now. Here, we used Thiobacillus thioparus that became abundant at the CarbFix1 pilot site after injection of CO2 and purified geothermal gases in basaltic aquifer at 400-800 m depth (4-8 MPa). The capacity of T. thioparus to produce sulfate, through oxidation of thiosulfate, was measured by Raman spectroscopy as a function of pressure up to 10 MPa. The results show that the growth and metabolic activity of T. thioparus are influenced by the initial concentration of the electron donor thiosulfate. It grows best at low initial concentration of thiosulfate (here 5 g. l −1 or 31.6 mM) and best oxidizes thiosulfate into sulfate at 0..1 MPa with a yield of 14.7 ± 0.5%. Sulfur oxidation stops at 4.3 ± 0.1 MPa (43 bar). This autotrophic specie can thereby react to CO2 and H2S injection down to 430 m depth and may contribute to induced biogeochemical cycles during subsurface energy operations.
... Peridotite is rare at shallow depths, and its total capacity for CO 2 storage is in the order of Gt, provided that the rock is massively hydraulically fractured to reach all the available mineral. Regarding dissolved CO 2 storage, the leakage risk is mitigated because brine is heavier when it is CO 2 saturated (Burton & Bryant, 2009;Sigfusson et al., 2015). CO 2 dissolution can be performed either on surface (Burton & Bryant, 2009) or at the reservoir depth (Pool et al., 2013). ...
... Peridotite is rare at shallow depths, and its total capacity for CO 2 storage is in the order of Gt, provided that the rock is massively hydraulically fractured to reach all the available mineral. Regarding dissolved CO 2 storage, the leakage risk is mitigated because brine is heavier when it is CO 2 saturated (Burton & Bryant, 2009;Sigfusson et al., 2015). CO 2 dissolution can be performed either on surface (Burton & Bryant, 2009) or at the reservoir depth (Pool et al., 2013). ...
Plain Language Summary
Geologic carbon storage, which consists in returning carbon deep underground, should be part of the solution to effectively reach carbon neutrality by the middle of the century to mitigate climate change. CO2 has been traditionally proposed to be stored in sedimentary rock at depths below 800 m, where CO2 becomes a dense fluid, minimizing the required storage volume. Nevertheless, CO2 is lighter than brine in the traditional concept, so a rock with sufficient sealing capacity should be present above the storage formation to prevent leakage. Indeed, one of the main hurdles to deploy geologic carbon storage is the risk of CO2 leakage. To reduce this risk, we propose a novel storage concept that consists in injecting CO2 in reservoirs where the pore water stays in supercritical conditions (pressure and temperature higher than 21.8 MPa and 374°C, respectively) because at these conditions, CO2 becomes denser than water. Consequently, CO2 sinks, leading to a safe long‐term storage. This concept, which could store a significant portion of the total requirements to decarbonize the economy, should start being implemented in deep volcanic areas, given that supercritical reservoirs are found at relatively shallow depths between 3 and 5 km.
... The simultaneously co-injection of NCGs and water/brine into saline aquifers is also a technique used for gas storage and has been promoted in order to avoid the aforementioned issues. These include either the total dissolution of the gases into water in the surface and the injection into a reservoir (Burton and Bryan, 2009;Eke et al, 2011) or the simultaneous but separate injection of CO 2 and brine, ensuring the mixing at a certain depth and the downwards flow of the mixture as single-phase (Sigfusson et al., 2015) or two-phase (Shafaei et al., 2012). However, these solutions have not been designed for relative high mass ratio of NCGs and/or low reservoir pressures. ...
A steady-state compositional flow model has been developed for simulating the injection of condensed steam together with non-condensable gases (NCGs). All fluids are originated from a high enthalpy subsurface source, and after the recuperation of their energy in a geothermal power plant they must be reinjected back into the earth for controlling the emissions of greenhouse and toxic gases. For high content of NCGs in the initial geothermal fluid and reinjection of the totality of the fluids, the dissolution of the gas into the liquid phase is partial and a two-phase mixture must be injected. Targeting a low pressure (depleted) reservoir for the injection can result in a liquid column inside the well which is far for the surface in a depth of several hundreds of meters. The model considers a prototype well completion which overcomes these restrictions by injecting separately the
water and the NCGs, and by mixing the two phases in a certain depth while ensuring the downward
flow of the mixture.
... The main role of reinjection is to ensure the long-term energy extraction and longevity of a geothermal resource by providing pressure support, improving heat recovery from the subsurface rock and reducing the risk of subsidence (Axelsson, 2008;Kaya et al., 2011;Stefansson, 1997). Also, the injection is frequently used to dispose of wastewater from power plants and return water from direct applications, and to enhance or revitalize surface features such as hot springs and fumaroles (Axelsson, 2012), and recently the reinjection is being used for injection of CO2 and H2S emissions as the case of CarbFix-Sulfix project in Hellisheiði Geothermal Power Plant, SW-Iceland (Sigfusson et al., 2015(Sigfusson et al., , 2018Ratouis, et al., 2019). Nevertheless, reinjection can cause problems such as thermal and chemical breakthrough into production wells and can other undesirable effects such as ground subsidence (due to rock cooling and contraction) and induced seismicity (Diaz et al., 2016). ...
The Nesjavellir geothermal power plant is the second largest in Iceland, with a district heating capacity of 300 MW and electrical generation of 120 MW. Reinjection of the excess water from the Nesjavellir geothermal plant, derived from separated water from
high enthalpy wells and condensed steam, has affected the temperature of the shallow groundwater in the area. These discharges of warm water present a risk to cold water production for the power plant as well as the ecosystem in Lake Thingvellir, which is a
UNESCO World Heritage Site. This study investigates the flow path of reinjected liquid and temperature of impacted groundwater for a better management of the discharge and injection in the area. A numerical model of the Nesjavellir warm wastewater reinjection zone was developed using the TOUGH2 non-isothermal flow simulator program and incorporates a 3D geological model developed with Leapfrog Geothermal modeling software. The model was calibrated against underground water temperature data measured between 1998 - 2018 from several monitoring stations located to the north of the power plant. Hydrological parameters such as porosity and permeability were further calibrated against data from a tracer test carried out in the area between 2018-2019. Both models use the Multiple Interactive Continuum (MINC) method, which is a generalization of the dual-porosity method. Compared to the single-porosity model, the MINC method better replicates the fast and strong recovery of tracers found in the monitoring stations. The temperature model showed acceptable results that match the temperature field. While the tracer model closely matches the overall tracer return in some wells, the model underestimates tracer returns in others. However, the model reproduces the overall trend, with similar tracer arrival and concentration peaks for monitoring stations located over main structures acting as permeable channels. Two future scenarios were simulated for a period of 20 years, one in which injection continues and another in which the injection is completely stopped. The numerical model in this study improves understanding of the connections between injection wells and monitoring stations, along with better characterization of the fracture matrix interface and the porosity of postglacial lava flows. Therefore, it can be useful in providing a basis for sustainable management of the geothermal resource and the surrounding environment.
... This has been shown in the Hellisheidi pilot project (Iceland) that targeted a MORB aquifer. The CO2 injection rate in this pilot project is particularly low because CO2-enriched water was injected instead of the usual supercritical CO2 (Sigfusson et al. 2015;Matter et al. 2016;Gunnarsson et al. 2018). ...
The research on the Columbia River Basalt is a unique combination of projects that minimise CO2 emissions to the atmosphere. Both are underground waste disposal projects: CO2 waste versus nuclear waste. The recent Wallula CO2 project and the previous nuclear-waste project in the Columbia River Basalt (CRB), USA, provide the database for a high-capacity CO2 sequestration model. Due to geomechanical constraints, the injection rate of CO2 sequestration must be limited in order not to jeopardise the integrity of the reservoir and cap rock. The interbed in the continental flood basalt tested in the Wallula project only allows injection at a rate in the range of 9-19 kg CO2/s, depending on permeability (4×10⁻¹⁴-10⁻¹³ m²) and porosity (0.1-0.15). At the end of a 50-year injection period, the fraction of CO2 converted to carbonate minerals is 37.1-67.1%. Underground space for waste disposal is a rare asset. The Columbia River Basalt occupies an area of 200,000 km². Fifty years of CO2 sequestration from a single well would require about the same fraction of the area as that of a nuclear waste repository (0.025%). The repository design is for a capacity of 70,000 MTHM (metric tons heavy metal). If all the waste is spent nuclear fuel, it originates from 1.2×10⁴-8.4×10⁴ TWh electric power production, depending on reactor type. The CO2 injection well operating at maximum capacity (19 kg CO2/s) represents 50 TWh generated in a gas power station minus the energy consumed for CO2 separation, i.e., less than 0.4% of the nuclear option.
... Peridotite is rare at shallow depths, and its total capacity for CO 2 storage is in the order of Gt, provided that the rock is massively hydraulically fractured to reach all the available mineral. Regarding dissolved CO 2 storage, the leakage risk is mitigated because brine is heavier when it is CO 2 saturated (Burton & Bryant, 2009;Sigfusson et al., 2015). CO 2 dissolution can be performed either on surface (Burton & Bryant, 2009) or at the reservoir depth (Pool et al., 2013). ...
... The CarbFix method first captures CO 2 and H 2 S in water either during its injection (Gislason and Oelkers, 2014;Sigfusson et al., 2015) or in a scrubbing tower adjacent to the gas source . The resulting gas-charged injection water is acidic. ...
The CarbFix method was upscaled at the Hellisheiði geothermal power plant to inject and mineralize the plant’s CO2 and H2S emissions in June 2014. This approach first captures the gases by their dissolution in water, and the resulting gas-charged water is injected into subsurface basalts. The dissolved CO2 and H2S then react with the basaltic rocks liberating divalent cations, Ca²⁺, Mg²⁺, and Fe²⁺, increasing the fluid pH, and precipitating stable carbonate and sulfide minerals. By the end of 2017, 23,200 metric tons of CO2 and 11,800 metric tons of H2S had been injected to a depth of 750 m into fractured, hydrothermally altered basalts at >250 °C. The in situ fluid composition, as well as saturation indices and predominance diagrams of relevant secondary minerals at the injection and monitoring wells, indicate that sulfide precipitation is not limited by the availability of Fe or by the consumption of Fe by other secondary minerals; Ca release from the reservoir rocks to the fluid phase, however, is potentially the limiting factor for calcite precipitation, although dolomite and thus aqueous Mg may also play a role in the mineralization of the injected carbon.
During the first phase of the CarbFix2 injection (June 2014 to July 2016) over 50% of injected carbon and 76% of sulfur mineralized within four to nine months, but these percentages increased four months after the amount of injected gas was doubled during the second phase of CarbFix2 (July 2016–December 2017) at over 60% of carbon and over 85% of sulfur. The doubling of the gas injection rate decreased the pH of the injection water liberating more cations for gas mineralization. Notably, the injectivity of the injection well has remained stable throughout the study period confirming that the host rock permeability has been essentially unaffected by 3.5 years of mineralization reactions. Lastly, although the mineralization reactions are accelerated by the high temperatures (> 250 °C), this is the upper temperature limit for carbon storage via the mineral carbonation of basalts as higher temperatures leads to potential decarbonation reactions.
... There are two ways to implement mineral carbonation: in situ mineral sequestration and ex situ mineral sequestration [15]. In situ mineral carbonation is to inject CO2 dissolved in water into unconventional reservoirs such as mafic and ultramafic rocks, which can react with CO2 to form carbonate mineral such as calcite, magnesite, dolomite and siderite [16][17][18][19][20]. Although in situ mineral carbonation is stable, the requirements of reactivity, porosity and permeability hinder its development. ...
For relieving CO 2 emissions and climate change, carbon sequestration and storage has been paid more attention. Mineral carbonation technology is a process that the calcium and/or magnesium-containing minerals react with CO 2 to form stable carbonate precipitation, which in turn fixes CO 2 . It originates from natural rock weathering process that calcium and magnesium-containing rocks react with CO 2 dissolved in rain water to form carbonate minerals. The source of mineral carbonation is the solid containing calcium and magnesium compound. The classification of mineral carbonation including direct and indirect mineral carbonation is indicated, and the descriptions of extraction by different extract agent have been given. The pretreatments, operation conditions and reaction kinetics are also discussed. Furthermore, the different processes by carbonizing from industrial waste are reviewed and the energy loss and cost are also described.
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.
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.
Mineral carbonation is a Carbon Capture Utilization and Storage (CCUS) technique that can be used to remove or divert carbon dioxide (CO2) from the atmosphere and store it in carbonate minerals. Hydraulic fracturing flowback and produced water (FPW) is Ca- and Mg-rich wastewater generated by the petroleum industry that can be used to sequester CO2 in benign minerals. Here, we describe the rate and efficiency of mineral carbonation achieved by sparging 10% CO2/90% N2 gas into pH-adjusted FPW, collected from the Duvernay Formation in the Western Canadian Sedimentary Basin. Our results indicate that calcite (CaCO3) precipitated at the expense of brucite [Mg(OH)2] dissolution following CO2 injection; as such, no Mg-carbonate precipitates were formed. The carbonation reaction reached steady state within 1 h and 14.2% of the aqueous Ca in the FPW was precipitated as calcite, sequestering 1.56 ± 0.33 g CO2 L⁻¹ of FPW. Our dissolved inorganic carbon measurements, geochemical models, and stable carbon isotope results indicate that CO2 mineralization can be maximized by maintaining solution at pH ≥ 10 during CO2 sparging. If all of the Ca and Mg in the FPW could be carbonated, it would offer a greater CO2 sequestration potential of 12.5 ± 0.3 g CO2 L⁻¹.
This report presents the current status and evaluation of the CO2 storage potential in Denmark. The report discusses the storage potential of selected subsurface structures onshore Denmark and in near coast areas, as well as the potential in depleted North Sea oil-gas fields, beds of basalts, salt caverns and in dipping offshore saline aquifers. The main emphasis has focused on investigation of known structures in the Danish on- and nearshore area.
Deep saline aquifers and depleted carbonate reservoirs are generally considered promising locations for subsurface CO2 storage. However, carbonate minerals particularly calcite can react with CO2-saturated brine, resulting in dissolution of carbonate and potentially mechanical compaction. Thus, it is crucial to understand the extent of this reaction in both water-wet and oil-wet scenarios, and subsequently its consequences on CO2 storage in depleted carbonate reservoirs. In this study, medical X-ray computed tomography (CT) was used to image water-wet and oil-wet Indiana limestone core samples before and after CO2 flooding. Changes in the rock matrix and pore structure were further assessed from the porosity and permeability data computed from the CT images. In both cases, imaging shows a significant amount of dissolution resulting in an increase in pore volume after core flooding with live brine and subsequently CO2. This increase in porosity is 46.7% and 19% for the water-wet and oil-wet core, respectively. Likewise, the brine permeability for the water-wet core increased from 9.2 mD (before CO2 flooding) to 108 mD (after CO2 flooding), whereas the permeability for the oil-wet core increased modestly from 9.0 mD to 20.1 mD. These results suggests that the reactivity is less pronounced in the oil-wet rock compared to the water-wet rock. Therefore, the wettability state of a target carbonate reservoir and the subsequent potential for the wettability state to be modified should be considered when assessing the CO2 storage capacity and integrity.
The performance of basalt and sandstone for CO2 storage mainly depends on the CO2 migration and solidification in the pore network of rock. This study provides points of view for the simulation of the three-dimensional pore space and the numerical prediction of gas transfer in the microstructure of the studied rocks. The biphasic change on Gaussian random field forms a randomly shaped pore network and the combination of biphasic fields creates a porous model that satisfies the real rock porosity and pore size distribution. Based on the generated model, several calculation scenarios using the mathematical morphology are proposed and numerically implemented to investigate the pore space characteristics, to extract the potential CO2 transfer paths, to analyze the geometric features and thus to evaluate the CO2 storage performance.
Large volume of CO2 injection into the saline aquifer is considered to be the high potential CO2 storage method. Until now, the field of CO2 injectivity has been completely dominated by salt precipitation – and by far the most studied mechanism for the loss of injectivity. In this paper, our aim is to focus on recent findings on CO2 injectivity impairment by fines migration that should not be overlooked. This paper summarizes the state-of-the-art knowledge obtained from theoretical, field studies, and experimental observations on CO2 injectivity impairment by fines migration in saline aquifers in the sense of CO2 storage. By gathering various data from books, DOE papers, field reports and SPE publications, a detailed and high quality data set for fines migration during CO2 injection into saline aquifer is created. Key reservoir/fluid/rock information, operational parameters and petrophysical evaluations are assessments are provided, providing the basis for comprehensive data analysis. The results are presented in terms of boxplot and histogram, where histogram displays the distribution of each parameter and identifies the best suitable ranges for best practices; boxplots are used to detect the special cases and summarize the ranges of each parameter. Previous coreflooding experiments concluded that salt precipitation, mineral precipitation, dissolution and mobilization are the main mechanisms that caused CO2 injectivity impairments. Dissolution of carbonate minerals is dominant and it increases the poro spaces and connectivity of sandstone core samples. Conversely, detachment, precipitation of salt and clay minerals and deposition of fines particles decreases the flow are and even clog the flow paths despite net dissolution. However, the results are case dependent and lack generality in terms of quantifying the petrophysical damage. It has been highlighted that injection scheme (flow rate, time frame), mineral composition (clay content, sensitive minerals), particulate process in porous media (pore geometry, particle and carrier fluid properties), and thermodynamic conditions (pressure, temperature, salinity, CO2 and brine composition) give substantial effect on the fines migration during CO2 injection. Additionally, the current experimental work is limited to rendering time and difficult to identify the dynamic process of fines migration during CO2 injection. A list of potential additional work has therefore been presented in this paper including the establishment of microscopic visualization of CO2-brine-rock interactions with representative pore-network under reservoir pressure and temperature. This is the first paper to summarize the contribution of fines migration on CO2 injectivity impairment in saline aquifer.
Dissolving CO 2 into water or brine produces a denser fluid than the CO 2 -free equivalent at all salinity, temperature and pressure conditions relevant to sedimentary basins. Negative buoyancy of CO 2 solutions opens the possibility of utilizing negative relief trapping configurations for CO 2 sequestration, as opposed to structural highs conventionally sought for positively buoyant fluids such as hydrocarbons or pure CO 2 . Exploring sedimentary basins for negative buoyancy traps can readily utilize hydrocarbon exploration datasets and techniques. Some major systemic differences when exploring for negative as opposed to positive buoyancy traps are examined here. Trap spatial scale is a consideration due to the inherent long-wavelength synformal geometry of basins. Antiforms are areally restricted relative to synforms, which may be embedded within larger-scale synformal closure at length scales right up to that of the basin itself. Multiscale synformal structure varies with basin type and may not be fully identified due to truncation effects arising from data coverage limitations. Similar to hydrocarbon exploration, CO 2 trap exploration must consider potential sequestration volumes in an uncertainty and risk framework. Charge risk is unnecessary in sequestration projects, however, the multiscale nature of synformal traps should be considered when estimating range of storage volumes.
This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series
Актуальность. В угледобывающей промышленности Донбасса существует потребность в использовании большого количества индивидуального аварийно-спасательного оборудования, содержащего регенерирующие продукты. В настоящее время необходимая процедура утилизации этих отходов в регионе не предусмотрена. Таким образом, закономерно, происходит неорганизованное скопление опасного для человека и окружающей среды продукта, содержащего надпероксид калия, к тому же являющегося ценным и дорогостоящим продуктом. Вторая острая экологическая проблема региона – образование большого количества шахтных вод на угледобывающих предприятиях и последующий их сброс в поверхностные водоемы. Одним из этапов очистки шахтной воды для последующего ее применения в хозяйственных циклах является умягчение (удаление соединений жесткости). Для этих целей обычно используются вещества, аналогичные отходам регенеративных продуктов самоспасателей, например, известь и карбонат натрия в отстойниках и осветлителях. Такая схема повторного использования будет выгодным и современным подходом к экологической безопасности региона. Цель: исследование возможности повторного использования отходов регенеративного продукта непригодных к эксплуатации самоспасателей для дальнейшего их применения в хозяйственно-бытовых нуждах предприятий. Объект: отходы самоспасателей на кислородсодержащем продукте на основе надпероксида калия, шахтные воды Донбасского региона. Методы: экспериментальные исследования по очистке шахтной воды отходами регенеративного продукта шахтных самоспасателей на химически связанном кислороде методом реагентного умягчения. Результаты. Экспериментально установлено, что очистка шахтных вод отходами регенеративного продукта шахтных самоспасателей обеспечивает высокую степень умягчения шахтных вод. Шахтные воды Донбасского региона, обработанные регенерирующим средством, соответствуют требованиям к использованию в хозяйственных целях и при дозе реагента 4 мг-экв/дм3 имеют следующие показатели качества: электропроводность – 2891 мкСм/см; водородный показатель (рН)=8,66; Ж=6,3 мг-экв/дм3; CO3–2 =0; HCO3=6,5 мг-экв/дм3.
This work discloses new insights into the formation and evolution of Mg -carbonates as well as carbonation processes of Mg-rich oxides and silicates with the aim of providing a safe and permanent anthropogenic CO2 storage, helping to tackle the worst effects of climate change. Carbonation reactions were carried in a purpose -built steam-mediated carbonation system at temperature and pressure ranges between 50-205ºC and 1 to 10 bar, respectively. A hydrated amorphous Mg-carbonate was identified upon carbonation of Mg-rich silicates and oxides at 50ºC. Such material might have similar composition and thermal dehydration behavior as nesquehonite. Results from this thesis provided new insights into the enigmatic and yet unconstrained transition of such phase to less hydrated phases. The evolution of Mg - carbonate phases is mainly controlled by the slow dehydration kinetics of Mg2+ rather than evolving to a thermodynamically more stable or structurally similar phase. Despite it has been predicted that such material could straightforward transform into magnesite, it is strongly argued that such transition is greatly inhibited due to preferential nucleation pathways to le ss hydrated Mg-carbonate phases. Phases within the group Mg5(CO3)4(OH)2·XH2O (11=X=4) allows a progressive dehydration whereas the MgCO3·nH2O (n=0) seemingly not. It is proposed that the transition between hydrated amorphous Mg-carbonate to highly disordered dypingite-like phases could occur progressively as it dehydrates and crystallizes, forming dypingite-like phases. The progressive evolution of dypingite-like phases is controlled by the removal of molecular water, inducing cell -shrinkage as well as ordering the internal structure heterogeneity, resulting in a crystalline hydrated structure with the name of hydromagnesite. This might explain the inconsistencies in the solubility and decomposition behavior data reported in the literature for such carbonate phases. No further dehydration is allowed within this group, entailing a significant kinetic barrier in order to allow the transition from hydromagnesite to magnesite. Results from this work shed light into the yet enigmatic evolution of Mg -carbonate phases. The understating of such processes is of paramount importance to accelerate the transition and/or dehydration kinetics among such phases and possibly unlocking preferential nucleation pathways. Brucite carbonation was observed to occur at feasible conversion rates even under simulated flue gas conditions, highlighting the potential of mineral carbonation processes for direct combined CO2 capture and storage/utilization. Carbonation of Mg-rich silicates remained a challenging field under the studied conditions, even for activated serpentine, despite its partial high-reactivity attributed to the presence of a highly-reactive amorphous Mg-rich phase. It was also found the presence of a poorly-reactive Mg-rich amorphous phase (formed upon activation of lizardite) which remained seemingly unreacted upon carbonation. Such observation might provide new insights into the yet unanswered low carbonation efficiencies for direct-carbonation of activated serpentine. Similar carbonation yields were observed for brucite-bearing serpentinized dunite when compared to activated lizardite. Strategically sourcing serpentinized rocks with higher brucite contents will potentially increase the carbonation potential of such materials. Coexisting lizardite and/or forsterite were also observed to be partially carbonated. Carbonation of enstatite and forsterite were also individually studied under conditions relevant to localized early Martian conditions. Enstatite dissolution was observed by the formation of a Si -rich passivating layer, where Si and Mg are heterogeneously distributed. Such observation is consistent with morphological changes within this layer, strongly suggesting an intergrowth of nucleating and growing Mg-carbonates with Si-rich phases.
Carbon Dioxide removal from air (CDR) combined with permanent solid storage can be accomplished via carbon mineralization in ultramafic rocks in at least four ways:
1. Surficial CDR: CO2-bearing air and surface waters are reacted with crushed and or ground mine tailings, alkaline industrial wastes, or sedimentary formations rich in reactive rock fragments, all with a high proportion of reactive surface area. This can be implemented at a low cost, but most proposed methods have a very large area footprint at the gigatonne scale. The area requirement can be greatly reduced by calcining (heating to produce pure CO2 for permanent storage or use) followed by recycling of MgO, CaO, Na2O, … Such looping methods have predicted costs that are as low or lower than for direct air capture with synthetic sorbents or solvents (DACSS), and a similar area footprint.
2. In situ CDR: CO2-bearing surface waters are circulated through rock formations at depth. These methods potentially have a cost similar to that of surficial carbon mineralization, and a giant storage capacity with reduced surface area requirements, but they involve uncertain feedbacks between permeability, reactive surface area, and reaction rate, providing a fascinating topic for fundamental research. Furthermore, the size, injectivity, permeability, geomechanics, and microstructure of key subsurface reservoirs for in situ CDR remain almost entirely unexplored.
3&4. Combined partial enrichment of CO2 using direct air capture with synthetic sorbents (DACSS) plus surficial carbon mineralization (3) or in situ carbon mineralization (4). Energy requirements and total costs for partial enrichment of CO2 are substantially lower than for enrichment to high purity. CO2 enriched air can be sparged through mine tailings at the surface, and/or through water to increase dissolved carbon concentrations prior to circulation through rock reactants. Such combined or hybrid approaches have not been investigated thoroughly, and offer many avenues for optimization.
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.
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.
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.
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 reli