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Migration of exsolved CO2 following depressurization of saturated brines
Greenhouse Gases: Science and Technology
Abstract
Geologic disposal of supercritical CO2 in saline aquifers and depleted oil and gas fields will cause large volumes of brine to become saturated with dissolved CO2 at concentrations of 40 g/l or more. As CO2 dissolves in brine, the brine density increases slightly. This property favors the long-term storage security of the CO2 because the denser brine is less likely to move upwards toward shallower depths. However, there are plausible mechanisms by which the CO2-laden brine could be transported to a shallower depth, where the CO2 would come out of solution (exsolve), forming a mobile CO2 gas phase. Recent laboratory experiments of the exsolution process show that the CO2 phase relative permeability measured during exsolution is on the order of 1000 times lower than the relative permeability measured during a conventional CO2 core flood. Numerical simulations of upward brine migration through an open fault were performed using TOUGH2-ECO2N with the two types of relative permeability functions. When traditional core flood relative permeabilities are used, upward flow of a CO2 saturated brine leads to exsolution and the development of a highly mobile CO2 gas phase. When relative permeabilities measured during exsolution are used, the tendency for the exsolved CO2 to migrate as a separate phase is greatly reduced, and the exsolved CO2 can partially block brine flow through the open fault. For the conditions considered, use of the exsolution relative permeability functions reduced the upward CO2 flux by about a factor of four compared to the case with core flood relative permeability functions. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd
... It is clear from this discussion, and the discussion about velocity profiles in Section 3.3.1 above, that the relative permeabilities of the brine and CO 2 phase have a considerable effect on the hydrogeochemical evolution of the simulated CCUS reservoirs. We chose to utilize the relative permeability parameters presented by André et al. (2007), but a considerable body of literature has demonstrated the considerable range of relative permeability parameters associated with different rock types and CO 2 -brine flow regimes (e.g., Bennion et al., 2008;Müller, 2011;Krevor et al., 2012;Zuo et al., 2012;Falta et al., 2013;Tutolo et al., 2014b). In particular, a number of studies have shown that exsolved CO 2 can cause interesting and dramatic relative permeability effects (e.g., Luhmann et al., 2013;Falta et al., 2013;Tutolo et al., 2014b). ...
... We chose to utilize the relative permeability parameters presented by André et al. (2007), but a considerable body of literature has demonstrated the considerable range of relative permeability parameters associated with different rock types and CO 2 -brine flow regimes (e.g., Bennion et al., 2008;Müller, 2011;Krevor et al., 2012;Zuo et al., 2012;Falta et al., 2013;Tutolo et al., 2014b). In particular, a number of studies have shown that exsolved CO 2 can cause interesting and dramatic relative permeability effects (e.g., Luhmann et al., 2013;Falta et al., 2013;Tutolo et al., 2014b). However, variations in the CO 2 and brine relative permeability functions would generally only impact our conclusions if they allowed for high relative permeability of the brine phase even in regions with significant CO 2 saturation, which is generally not the case. ...
Carbonate minerals and CO2 are both considerably more soluble at low temperatures than they are at elevated temperatures. This inverse solubility has led a number of researchers to hypothesize that injecting low-temperature (i.e., less than the background reservoir temperature) CO2 into deep, saline reservoirs for CO2 Capture, Utilization, and Storage (CCUS) will dissolve CO2 and carbonate minerals near the injection well and subsequently exsolve and re-precipitate these phases as the fluids flow into the geothermally warm portion of the reservoir. In this study, we utilize high performance computing to examine the coupled effects of cool CO2 injection and background hydraulic head gradients on reservoir-scale mineral volume changes. We employ the fully coupled reactive transport simulator PFLOTRAN with calculations distributed over up to 800 processors to test 21 scenarios designed to represent a range of reservoir depths, hydraulic head gradients, and CO2 injection rates and temperatures. In the default simulations, 50 °C CO2 is injected at a rate of 50 kg/s into a 200 bar, 100 °C calcite or dolomite reservoir. By comparing these simulations with others run at varying conditions, we show that the effect of cool CO2 injection on reservoir-scale mineral volume changes tends to be relatively minor. We conclude that the low heat capacity of CO2 effectively prevents low-temperature CO2 injection from decreasing the temperature across large portions of the simulated carbonate reservoirs. This small thermal perturbation, combined with the low relative permeability of brine within the supercritical CO2 plume, yields limited dissolution and precipitation effects directly attributable to cool CO2 injection. Finally, we calculate that relatively high water-to-rock ratios, which may occur over much longer CCUS reservoir lifetimes or in materials with sufficiently high brine relative permeability within the supercritical CO2 plume, would be required to substantially affect injectivity through thermally-induced mineral dissolution and precipitation. Importantly, this study shows the utility of reservoir scale-reactive transport simulators for testing hypotheses and placing laboratory-scale observations into a CCUS reservoir-scale context.
... Du and Yortsos, 1999;Tsimpanogiannis and Yortsos, 2004;Zuo et al., 2013) or free phase migration in homogeneous sands and rocks (e.g. Fry et al., 1997;Enouy et al., 2011;Zuo et al., 2012;Krevor et al., 2012;Falta et al., 2013;Zuo and Benson, 2014). Recently, Sakaki et al. (2013) and Plampin et al. (2014a,b) conducted intermediate-scale CO 2 gas evolution experiments in homogeneous and heterogeneous sand configurations. ...
... In their model, they assumed rate-limited mass transfer of CO 2 from aqueous to gas phase and showed that advection of the gas phase is adequately modeled with the classical extension of Darcy's law for multi-phase flow and conventional constitutive relationships. However, recent experimental studies have suggested that non-conventional relative permeability relationships may be required to accurately represent CO 2 gas evolution in porous media Falta et al., 2013;Zuo and Benson, 2014). In fact, Zuo and Benson (2014) conducted microtomography experiments comparing CO 2 gas exsolution and immiscible displacement and concluded that the traditional model parameters and constitutive relationships are process-dependent. ...
The physicochemical processes associated with CO2 leakage into shallow aquifer systems are complex and span multiple spatial and time scales. Continuum-scale numerical models that faithfully represent the underlying pore-scale physics are required to predict the long-term behavior and aid in risk analysis regarding regulatory and management decisions. This study focuses on benchmarking the numerical simulator, FEHM, with intermediate-scale column experiments of CO2 gas evolution in homogeneous and heterogeneous sand configurations. Inverse modeling was conducted to calibrate model parameters and determine model sensitivity to the observed steady-state saturation profiles. It is shown that FEHM is a powerful tool that is capable of capturing the experimentally observed outflow rates and saturation profiles. Moreover, FEHM captures the transition from single- to multi-phase flow and CO2 gas accumulation at interfaces separating sands. We also derive a simple expression, based on Darcy's law, for the pressure at which CO2 free phase gas is observed and show that it reliably predicts the location at which single-phase flow transitions to multi-phase flow.
... Simulations with varying parameters related to modified gas relative permeability during secondary drainage were carried out to find the best matching parameters. Results showed that the gas relative permeability is reduced significantly during secondary drainage which is in agreement with the available literature at both lab and field scales (Babadimas, 2017;Falta et al., 2013). The significant reduction to gas relative permeability during recovery stage was also in agreement to an earlier modeling study on Heletz CO 2 injection experiment where the near-field processes related to the borehole-reservoir interaction were modeled . ...
Residual trapping of CO2, typically quantified by residual gas saturation (Sgr), is one of the main trapping mechanisms in geological CO2 storage (GCS). An important additional characteristic parameter is critical gas saturation (Sgc). Sgc determines at what saturation the trapped gas remobilizes again if gas saturation increases due to exsolution from the aqueous phase, rather than from further gas injection. In the present study, a pilot-scale CO2 injection experiment carried out at Heletz, Israel, in 2017, is interpreted by taking critical saturation into account. With regards to this experiment, the delayed second arrival peak of the partitioning tracer could not be captured by means of physical models. In this work, the hysteretic relative permeability functions were modified to account for Sgc. The results showed that accounting for the effect of Sgc during the secondary drainage indeed captured the observed delayed peak. The difference between the values of Sgr and Sgc, influenced both the time and peak height of the tracer arrival. To our knowledge this is first time that critical gas saturation has been considered in field scale analyses related to GCS. Accounting for Sgc is relevant where gas saturation during secondary drainage increases due to gas phase expansion or exsolution from the aqueous phase. This will happen in situations where pressure depletion occurs, e.g. due to gas leakage from fracture zones or wells or possibly because of pressure management activities. The findings also have implications for other applications such as underground gas storage as well as for geothermal reservoir management.
... Deng et al. (2012) proposed that heterogeneity in porosity and permeability of geologic reservoirs has a strong influence on CO 2 injection rate, CO 2 plume migration, storage capacity, potential leakage, and risk assessment. Conventional simulation methods based on the assumption of homogeneous formations (Nordbotten et al., 2005;Ronald et al., 2012;Oruganti et al., 2013;Raza et al., 2015) may lead to misevaluation of the storage efficiency and safety. How to characterize the heterogeneity of sedimentary reservoirs is the key to study the law of CO 2 migration under the effect of heterogeneity. ...
Large volumes of carbon dioxide (CO2 ) captured from carbon emission source can be stored in deep saline aquifers as a mean of mitigating climate change. The deep saline aquifers are naturally heterogeneous at multiple scales. It is important to generate representative multiscale heterogeneous fields of various hydrogeologic properties and understand storage safety by studying CO2 migration and distribution in such fields. In this work, a new multiscale heterogeneous model with partly fine multi-facies heterogeneous domain is proposed. A method based on transition probability theory is referred to establish a multi-facies model. A new multiscale heterogeneous model with partly fine multi-facies heterogeneous domain is built up according to the categorized permeability data obtained from the Geological Carbon Storage Frio site in USA. TOUGH2/ECO2N is applied to simulate CO2 migration and distribution in such a multiscale heterogeneous model. The CO2 plume shows obvious viscous fingering and non-uniform migration both in layered and vertical directions, implying vertical and horizontal heterogeneity which cannot be represented by a single-scale model or simulated with the assumption of homogeneous formation. The profile of CO2 migration shown in the numerical simulation at a time of 10 days is in a good accordance with the seismic data of Frio situ in qualitative and quantitative aspects.
... This elevation, represented by the dashed horizontal white line in Figure 1, is referred to as the critical elevation, and its location can be pre- dicted based on previous findings (Plampin et al., 2014a;Porter et al., 2015). When CO 2 -saturated water reaches the critical elevation, gas phase CO 2 will form ( Falta et al., 2013;Sakaki et al., 2013). Gas bubbles may then migrate upward individually ( Corapcioglu et al., 2004), and/or coalesce to form continuous gas flow pathways through the middle of the aquifer (Oldenburg & Lewicki, 2006;Tsimpanogiannis & Yortsos, 2004). ...
To assess the risks of Geologic Carbon Sequestration (GCS), it is crucial to understand the fundamental physicochemical processes that may occur if and when stored CO2 leaks upward from a deep storage reservoir into the shallow subsurface. Intermediate-scale experiments allow for improved understanding of the multiphase evolution processes that control CO2 migration behavior in the subsurface, because the boundary conditions, initial conditions, and porous media parameters can be better controlled and monitored in the laboratory than in field settings. For this study, a large experimental test bed was designed to mimic a cross section of a shallow aquifer with layered geologic heterogeneity. As water with aqueous CO2 was injected into the system to mimic a CO2-charged water leakage scenario, the spatiotemporal evolution of the multiphase CO2 plume was monitored. Similar experiments were performed with two different sand combinations to assess the relative effects of different types of geologic facies transitions on the CO2 evolution processes. Significant CO2 attenuation was observed in both scenarios, but by fundamentally different mechanisms. When the porous media layers had very different permeabilities, attenuation was caused by local accumulation (structural trapping) and slow redissolution of gas phase CO2. When the permeability difference between the layers was relatively small, on the other hand, gas phase continually evolved over widespread areas near the leading edge of the aqueous plume, which also attenuated CO2 migration. This improved process understanding will aid in the development of models that could be used for effective risk assessment and monitoring programs for GCS projects.
... Exsolution occurs when pore pressures decline and CO 2 solubility in brine decreases, resulting in the formation of a separate CO 2 phase [3][4][5][6]. This scenario occurs in carbon sequestration reservoirs by upward migration of CO 2 saturated brine, through faults, leaking boreholes or even seals, driven by the upward pressure gradient from CO 2 injection or ground water extraction [7,8]. In this way, dissolved CO 2 could migrate out of storage reservoir and form a gas phase at shallower depths. ...
This paper summarizes the results of a 4-year study regarding the implications of CO2 exsolution on geological carbon storage security and subsurface flow management, including core-flood experiments, micro-model studies, pore-scale modeling, and relative permeability calculations. When separate phase CO2 exsolves from carbonated water in sandstones, water relative permeability drops significantly. The relative permeability of exsolved CO2 is disproportionately reduced compared to drainage due to the dispersed morphology of exsolved CO2 bubbles in the pore space. Our studies suggest that CO2 exsolution provides an opportunity for mobility control in subsurface processes. The low mobility of exsolved CO2 suggests that risks of groundwater contamination due to this phenomenon are small.
... Gas flow is less likely to occur in reservoirs with high critical gas saturations (determined by the pervasion of snap-off events), low vertical pressure gradients and low permeability. This also suggests that the formation of exsolved CO 2 in leakage pathways would retard flow and develop gas barriers which may suppress upward flows [30]. ...
Erosion may modify the architecture of subsurface flow systems by removing confining units and changing topography to influence patterns of fluid circulation or by inducing gas exsolution from subsurface fluids, influencing compositional and buoyancy patterns in flow systems. Here, we examine the geologic record of subsurface flow in the sedimentary rocks of the Paradox Basin in the Colorado Plateau (southwestern USA), including the distribution and ages of Fe- and Mn-oxide deposits and bleached, former red-bed sandstones. We compare our results to those of previous geo- and thermochronology studies that documented as much as 2 km of erosional exhumation at ca. 3–4 Ma and Fe-and Mn-oxide precipitation at 3.6 Ma along fault zones in the region.
We used (U-Th)/He and K-Ar dating to document two new records of subsurface flow of reduced fluids between 3 and 4 Ma. The first is precipitation of Mn-oxides along the Moab fault (Utah, USA) at 3.9 ± 0.2 Ma. The second is clay mineralization associated with laterally extensive bleaching in the Curtis Formation, which we dated using K-Arillite age analysis to 3.60 ± 0.03 Ma. The coincidence of the timing of bleaching, Fe- and Mn-oxide formation in multiple locations, and erosional exhumation at 3–4 Ma raises the question of how surface erosion may have induced a phase of fluid flow in the subsurface. We suggest that recent erosion of the Colorado Plateau created steep topographic gradients that enhanced regional groundwater flow, whereby meteoric water circulation flushed reduced fluids toward discharge zones. Dissolved gases, transported from hydrocarbon reservoirs, also may have been exsolved by rapid depressurization.
This study utilizes synchrotron X-ray micro-tomography and pore scale modeling to investigate the process of gas exsolution and how it affects non-wetting phase relative permeability. Exsolved gas distributions are measured on Domengine and Boise sandstone samples using synchrotron X-ray micro-tomography. Observed gas phase distributions are compared to a new model that simulates the growth and distribution of exsolved gas phase at the pore-scale. Water relative permeability curves are calculated using a Stokes flow simulator with modeled and observed gas distributions, under various conditions, such as rock geometry, and pressure depletion rates. By comparing the actual bubble distributions with modeled distributions, we conclude that exsolved gas is more likely to form and accumulate at locations with higher water velocities. This suggests that convective delivery of CO2 to the gas bubble is a primary mechanism for bubble growth, as compared to diffusive transport through the aqueous phase. For carbonated brine flowing up a fault at half a meter per day, with 5% exsolved gas, the water relative permeability is estimated to be 0.6∼0.8 for various sandstones. The reduction of water mobility reduces upward brine migration when even a small amount of exsolution occurs.
This paper demonstrates that the nature and extent of residual CO2 trapping depends on the process by which the CO2 phase is introduced into the rock. We compare residual trapping of CO2 in Berea Sandstone by imbibing water into a core containing either exsolved CO2 or CO2 introduced by drainage. X-ray CT measurements are used to map the spatial distribution of CO2 pre- and post imbibition. Unlike during drainage where the CO2 distribution is strongly influenced by the heterogeneity of the rock, the distribution of exsolved CO2 is comparatively uniform. Post-imbibition, the CO2 distribution retained the essential features for both the exsolved and drainage cases but twice as much residual trapping is observed for exsolved CO2 even with similar pre-imbibition gas saturations. Residually trapped exsolved gas also disproportionately reduced water relative permeability. Development of process dependent parameterization will help better manage subsurface flow processes and unlock benefits from gas exsolution.
Dissolution of CO2 into brine is an important and favorable trapping mechanism for geologic storage of CO2. There are scenarios, however, where dissolved CO2 may migrate out of the storage reservoir. Under these conditions, CO2 will exsolve from solution during depressurization of the brine, leading to the formation of separate phase CO2. For example, a CO2 sequestration system with a brine-permeable caprock may be favored to allow for pressure relief in the sequestration reservoir. In this case, CO2-rich brine may be transported upwards along a pressure gradient caused by CO2 injection. Here we conduct an experimental study of CO2 exsolution to observe the behavior of exsolved gas under a wide range of depressurization. Exsolution experiments in highly permeable Berea sandstones and low permeability Mount Simon sandstones are presented. Using X-ray CT scanning, the evolution of gas phase CO2 and its spatial distribution is observed. In addition, we measure relative permeability for exsolved CO2 and water in sandstone rocks based on mass balances and continuous observation of the pressure drop across the core from 12.41 to 2.76 MPa. The results show that the minimum CO2 saturation at which the exsolved CO2 phase mobilization occurs is from 11.7 to 15.5%. Exsolved CO2 is distributed uniformly in homogeneous rock samples with no statistical correlation between porosity and CO2 saturation observed. No gravitational redistribution of exsolved CO2 was observed after depressurization, even in the high permeability core. Significant differences exist between the exsolved CO2 and water relative permeabilities, compared to relative permeabilities derived from steady-state drainage relative permeability measurements in the same cores. Specifically, very low CO2 and water relative permeabilities are measured in the exsolution experiments, even when the CO2 saturation is as high as 40%. The large relative permeability reduction in both the water and CO2 phases is hypothesized to result from the presence of disconnected gas bubbles in this two-phase flow system. This feature is also thought to be favorable for storage security after CO2 injection.
Geological carbon dioxide (CO2) storage is a means of reducing anthropogenic emissions. Dissolution of CO2 into the brine, resulting in stable stratification, increases storage security. The dissolution rate is determined by convection in the brine driven by the increase of brine density with CO2 saturation. We present a new analogue fluid system that reproduces the convective behaviour of CO2-enriched brine. Laboratory experiments and high-resolution numerical simulations show that the convective flux scales with the Rayleigh number to the 4/5 power, in contrast with a classical linear relationship. A scaling argument for the convective flux incorporating lateral diffusion from downwelling plumes explains this nonlinear relationship for the convective flux, provides a physical picture of high Rayleigh number convection in a porous medium, and predicts the CO2 dissolution rates in CO2 accumulations. These estimates of the dissolution rate show that convective dissolution can play an important role in enhancing storage security.
A new and relatively simple equation for the soil-water content-pressure head curve is described. The particular form of the equation enables one to derive closed-form analytical expressions for the relative hydraulic conductivity, when substituted in the predictive conductivity models of N. T. Burdine or Y. Mualem. The resulting expressions contain three independent parameters which may be obtained by fitting the proposed soil-water retention model to experimental data. Results obtained with the closed-form analytical expressions based on the Mualem theory are compared with observed hydraulic conductivity data for five soils with a wide range of hydraulic properties.
We present the results of compositional reservoir simulation of a prototypical CO2 sequestration project in a deep saline aquifer. The objective was to better understand and quantify estimates of the most important CO2 storage mechanisms under realistic physical conditions. Simulations of a few decades of CO2 injection followed by 103 to 105 years of natural gradient flow were performed. The impact of several parameters was studied, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, and permeability heterogeneity. The storage of CO2 in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals. Most importantly, we find that permanent storage is feasible. That is, the storage process can be designed to place large volumes of CO2 in forms that will not escape the aquifer any faster than fluids originally present in the aquifer.
The numerous CO2 reservoirs in the Colorado Plateau region of the United States are natural analogues for potential geologic CO2 sequestration repositories. To better understand the risk of leakage from reservoirs used for long-term underground CO2 storage, we examine evidence for CO2 migration along two normal faults from a reservoir in east-central Utah. CO2 -charged springs, geysers, and a hydrocarbon seep are localised along these faults. These include natural springs that have been active for long periods of time, and springs that were induced by recent drilling. The CO2 -charged spring waters have deposited travertine mounds and carbonate veins. The faults cut siltstones, shales, and sandstones and the fault rocks are fine-grained, clay-rich gouge, generally thought to be barriers to fluid flow. The geologic and geochemical data are consistent with these faults being conduits for CO2 to the surface. Consequently, the injection of CO2 into faulted geologic reservoirs, including faults with clay gouge, must be carefully designed and monitored to avoid slow seepage or fast rupture to the biosphere.
Upward displacement of brine from deep reservoirs driven by pressure increases
resulting fromCO2 injection for geologic carbon sequestrationmay occur through improperly
sealed abandoned wells, through permeable faults, or through permeable channels between
pinch-outs of shale formations. The concern about upward brine flow is that, upon intrusion
into aquifers containing groundwater resources, the brinemay degrade groundwater. Because
both salinity and temperature increase with depth in sedimentary basins, upward displacement
of brine involves lifting fluid that is saline but also warm into shallower regions that contain
fresher, cooler water. We have carried out dynamic simulations using TOUGH2/EOS7 of
upward displacement of warm, salty water into cooler, fresher aquifers in a highly idealized
two-dimensional model consisting of a vertical conduit (representing a well or permeable
fault) connecting a deep and a shallow reservoir. Our simulations show that for small pressure
increases and/or high-salinity-gradient cases, brine is pushed up the conduit to a new
static steady-state equilibrium. On the other hand, if the pressure rise is large enough that
brine is pushed up the conduit and into the overlying upper aquifer, flow may be sustained
if the dense brine is allowed to spread laterally. In this scenario, dense brine only contacts
the lower-most region of the upper aquifer. In a hypothetical case in which strong cooling
of the dense brine occurs in the upper reservoir, the brine becomes sufficiently dense that it
flows back down into the deeper reservoir from where it came. The brine then heats again
in the lower aquifer and moves back up the conduit to repeat the cycle. Parameter studies
delineate steady-state (static) and oscillatory solutions and reveal the character and period of
oscillatory solutions. Such oscillatory solutions aremostly a curiosity rather than an expected
natural phenomenon because in nature the geothermal gradient prevents the cooling in the
upper aquifer that occurs in the model. The expected effect of upward brine displacement
is either establishment of a new hydrostatic equilibrium or sustained upward flux into
the bottom-most region of the upper aquifer.
Injection of carbon dioxide (CO2) into geological formations is widely regarded as a promising tool for reducing global atmospheric CO2 emissions. To evaluate injection scenarios, estimate reservoir capacity and assess leakage risks, an accurate understanding of the subsurface spreading and migration of the plume of mobile CO2 is essential. Here, we present a complete solution to a theoretical model for the subsurface migration of a plume of CO2 due to natural groundwater flow and aquifer slope, and subject to residual trapping. The results show that the interplay of these effects leads to non-trivial behaviour in terms of trapping efficiency. The analytical nature of the solution offers insight into the physics of CO2 migration, and allows for rapid, basin-specific capacity estimation. We use the solution to explore the parameter space via the storage efficiency, a macroscopic measure of plume migration. In a future study, we shall incorporate CO2 dissolution into the migration model and study the importance of dissolution relative to capillary trapping and the impact of dissolution on the storage efficiency.
This paper summarises the results of a benchmark study that compares a number of mathematical and numerical models applied
to specific problems in the context of carbon dioxide (CO2) storage in geologic formations. The processes modelled comprise advective multi-phase flow, compositional effects due to
dissolution of CO2 into the ambient brine and non-isothermal effects due to temperature gradients and the Joule–Thompson effect. The problems
deal with leakage through a leaky well, methane recovery enhanced by CO2 injection and a reservoir-scale injection scenario into a heterogeneous formation. We give a description of the benchmark
problems then briefly introduce the participating codes and finally present and discuss the results of the benchmark study.
In this paper we investigate the mass transfer of CO2 injected into a homogenous (sub)-surface porous formation saturated with a liquid. In almost all cases of practical interest CO2 is present on top of the liquid. Therefore, we perform our analysis to a porous medium that is impermeable from sides and that is exposed to CO2 at the top. For this configuration density-driven natural convection enhances the mass transfer rate of CO2 into the initially stagnant liquid. The analysis is done numerically using mass and momentum conservation laws and diffusion of CO2 into the liquid. The effects of aspect ratio and the Rayleigh number, which is dependent on the characteristics of the porous medium and fluid properties, are studied. This configuration leads to an unstable flow process. Numerical computations do not show natural convection effects for homogeneous initial conditions. Therefore a sinusoidal perturbation is added for the initial top boundary condition. It is found that the mass transfer increases and concentration front moves faster with increasing Rayleigh number. The results of this paper have implications in enhanced oil recovery and CO2 sequestration in aquifers.
Improving understanding of CO2 migration, phase change, and trapping processes motivates the development of large-scale laboratory experiments to bridge the gap between bench-scale experiments and field-scale studies. Critical to the design of such experiments are defensible configurations that mimic relevant subsurface flow scenarios. We use numerical simulation with TOUGH2/ECO2M and ECO2N to design flow and transport experiments aimed at understanding upward flows including the transition of CO2 from supercritical to liquid and gaseous forms. These experiments are designed for a large-scale facility such as the proposed laboratory for underground CO2 investigations (LUCI). LUCI would consist of one or more long-column pressure vessels (LCPVs) several hundred meters in length filled with porous materials. An LCPV with an insulated outer wall corresponds to the column being at the center of a large upwelling plume. If the outer wall of the LCPV is assigned fixed temperature boundary conditions corresponding to the geothermal gradient, the LCPV represents a narrow upwelling through a fault or well. Numerical simulations of upward flow in the columns reveal complex temporal variations of temperature and saturation, including the appearance of liquid CO2 due to expansion cooling. The results are sensitive to outer thermal boundary conditions. Understanding of the simulations is aided by time-series animations of saturation-depth profiles and trajectories through P-T (pressure-temperature) space with superimposed phase saturations. The strong dependence of flow on hydrologic properties and the lack of knowledge of three-phase relative permeability and hysteresis underlines the need for large-scale flow experiments to understand multiphase leakage behavior. © 2012 Society of Chemical Industry and John Wiley & Sons, Ltd
Geologic carbon capture and storage (CCS) is an option for reducing CO2 emissions, but leakage to the surface is a risk factor. Natural CO2 reservoirs that erupt from abandoned oil and gas holes leak to the surface as spectacular cold geysers in the Colorado Plateau, United States. A better understanding of the mechanisms of CO2‐driven cold‐water geysers will provide valuable insight about the potential modes of leakage from engineered CCS sites. A notable example of a CO2‐driven cold‐water geyser is Crystal Geyser in central Utah. We investigated the fluid mechanics of this regularly erupting geyser by instrumenting its conduit with sensors and measuring pressure and temperature every 20 sec over a period of 17 days. Analyses of these measurements suggest that the timescale of a single‐eruption cycle is composed of four successive eruption types with two recharge periods ranging from 30 to 40 h. Current eruption patterns exhibit a bimodal distribution, but these patterns evolved during past 80 years. The field observation suggests that the geyser's eruptions are regular and predictable and reflect pressure and temperature changes resulting from Joule–Thomson cooling and endothermic CO2 exsolution. The eruption interval between multiple small‐scale eruptions is a direct indicator of the subsequent large‐scale eruption.
It is challenging to predict the degree to which shallow groundwater might be affected by leaks from a CO2 sequestration reservoir, particularly over long time scales and large spatial scales. In this study observations at a CO2 enriched shallow aquifer natural analog were used to develop a predictive model which is then used to simulate leakage scenarios. This natural analog provides the opportunity to make direct field observations of groundwater chemistry in the presence of elevated CO2, to collect aquifer samples and expose them to CO2 under controlled conditions in the laboratory, and to test the ability of multi-phase reactive transport models to reproduce measured geochemical trends at the field-scale. The field observations suggest that brackish water entrained with the upwelling CO2 are a more significant source of trace metals than in situ mobilization of metals due to exposure to CO2. The study focuses on a single trace metal of concern at this site: U. Experimental results indicate that cation exchange/adsorption and dissolution/precipitation of calcite containing trace amounts of U are important reactions controlling U in groundwater at this site, and that the amount of U associated with calcite is fairly well constrained. Simulations incorporating these results into a 3-D multi-phase reactive transport model are able to reproduce the measured ranges and trends between pH, pCO2, Ca, total C, U and Cl− at the field site. Although the true fluxes at the natural analog site are unknown, the cumulative CO2 flux inferred from these simulations are approximately equivalent to 37.8E−3 MT, approximately corresponding to a .001% leak rate for injection at a large (750 MW) power plant. The leakage scenario simulations suggest that if the leak only persists for a short time the volume of aquifer contaminated by CO2-induced mobilization of U will be relatively small, yet persistent over 100 a.
We investigate the physical processes that occur during the sequestration of carbon dioxide (CO2) in liquid-saturated, brine-bearing geologic formations using the numerical simulator TOUGH2. CO2 is injected in a supercritical state that has a much lower density and viscosity than the liquid brine it displaces. In situ, the supercritical CO2 forms a gas-like phase, and also partially dissolves in the aqueous phase, creating a multi-phase, multi-component environment that shares many important features with the vadose zone. The flow and transport simulations employ an equation of state package that treats a two-phase (liquid, gas), three-component (water, salt, CO2) system. Chemical reactions between CO2 and rock minerals that could potentially contribute to mineral trapping of CO2 are not included. The geological setting considered is a fluvial/deltaic formation that is strongly heterogeneous, making preferential flow a significant effect, especially when coupled with the strong buoyancy forces acting on the gas-like CO2 plume. Key model development issues include vertical and lateral grid resolution, grid orientation effects, and the choice of characteristic curves.
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.
Leakage of CO2 from a hypothetical geologic storage reservoir along an idealized fault zone has been simulated, including transitions between supercritical, liquid, and gaseous CO2. We find strong non-isothermal effects due to boiling and Joule-Thomson cooling of expanding CO2. Leakage fluxes are limited by limitations in conductive heat transfer to the fault zone. The interplay between multiphase flow and heat transfer effects produces non-monotonic leakage behavior.
Storage of carbon dioxide in deep formations is being actively considered for the reduction of greenhouse gas emissions. Relevant experience in the petroleum industry comes from natural gas storage and enhanced recovery using carbon dioxide, but this experience is over a time scale less than the hundreds or thousands of years required for carbon dioxide storage. On these long time scales, different mechanisms need to be considered.
In the long term, the dominant mechanism for dissolution of carbon dioxide in formation water is convective mixing rather than pure diffusion. This arises because the density of formation water increases upon dissolution of carbon dioxide, creating a density instability. Linear stability analysis has been used to estimate the time required for this instability to occur in anisotropic systems. For sufficiently thick formations with moderate vertical permeability, this time ranges from less than a year up to a few hundred years. Further approximate analysis shows that the time needed for the injected gas to dissolve completely is typically much longer, on the order of hundreds of years to tens of thousands of years, depending on the vertical permeability. This theoretical analysis is compared with the results of numerical simulations.
ECO2M is a fluid property module for the TOUGH2 simulator (Version 2.0) that was designed for applications to geologic storage of CO in saline aquifers. It includes a comprehensive description of the thermodynamics and thermophysical properties of HO - NaCl - CO mixtures, that reproduces fluid properties largely within experimental error for temperature, pressure and salinity conditions in the range of 10 C T 110 C, P 600 bar, and salinity from zero up to full halite saturation. The fluid property correlations used in ECO2M are identical to the earlier ECO2N fluid property package, but whereas ECO2N could represent only a single CO-rich phase, ECO2M can describe all possible phase conditions for brine-CO mixtures, including transitions between super- and sub-critical conditions, and phase change between liquid and gaseous CO. This allows for seamless modeling of CO storage and leakage. Flow processes can be modeled isothermally or non-isothermally, and phase conditions represented may include a single (aqueous or CO-rich) phase, as well as two-and three-phase mixtures of aqueous, liquid CO and gaseous CO phases. Fluid phases may appear or disappear in the course of a simulation, and solid salt may precipitate or dissolve. TOUGH2/ECO2M is upwardly compatible with ECO2N and accepts ECO2N-style inputs. This report gives technical specifications of ECO2M and includes instructions for preparing input data. Code applications are illustrated by means of several sample problems, including problems that had been previously solved with TOUGH2/ECO2N.
A theoretical investigation of factors affecting the gas phase transport
of evaporating organic liquids in the unsaturated zone is presented.
Estimates of density-driven advective gas flow using a simple analytic
expression indicate that significant advective gas flow will result from
the evaporation of volatile liquids in soils having a high permeability.
Numerical simulations using a two-dimensional cylindrical geometry and
including the effects of phase partitioning between the solid, gas,
water, and organic liquid phases show that mass transfer due to
density-driven flow may dominate the gas phase transport of some organic
chemical vapors in the unsaturated zone.
ECO2N is a fluid property module for the TOUGH2 simulator (Version 2.0) that was designed for applications to geologic sequestration of COâ in saline aquifers. It includes a comprehensive description of the thermodynamics and thermophysical properties of HâO-NaCl-COâ mixtures, that reproduces fluid properties largely within experimental error for the temperature, pressure and salinity conditions of interest (10 C ⤠T ⤠110 C; P ⤠476 bar; salinity up to full halite saturation). Flow processes can be modeled isothermally or non-isothermally, and phase conditions represented may include a single (aqueous or COâ-rich) phase, as well as two-phase mixtures. Fluid phases may appear or disappear in the course of a simulation, and solid salt may precipitate or dissolve. This report gives technical specifications of ECO2N and includes instructions for preparing input data. Code applications are illustrated by means of several sample problems, including problems that had been previously investigated in a code intercomparison study.
Any substantive campaign to mitigate greenhouse gas emissions must involve sequestration of CO2 in geologic formations. For stakeholders to accept this technology, the risk of leakage from the storage formation must be balanced against the economics of capture and injection. The standard approach to geologic sequestration assumes that CO2 will be injected as a bulk phase into a saline aquifer. The primary driver for leakage in this approach is the buoyancy of CO2 relative to native brine under typical deep reservoir conditions. If no leakage occurs, the primary impact of storage will be the displacement of large volumes of groundwater, equal to the volume of CO2 injected at reservoir conditions. Here we investigate an alternative storage approach that alleviates these concerns. The incremental cost of this approach over the standard approach therefore sets an upper bound on reasonable costs for monitoring and verification of the standard storage scheme and for avoiding groundwater contamination.
Many studies on geological carbon dioxide (CO2) storage capacity neglect the influence of complex coupled processes which occur during and after the injection of CO2. Storage capacity is often overestimated since parts of the reservoirs cannot be reached by the CO2 plume due to gravity segregation and are thus not accessible for storage. This work investigates the effect of reservoir parameters like depth, temperature, absolute and relative permeability, and capillary pressure on the processes during CO2 injection and thus on estimates of effective storage capacity. The applied statistical characteristics of parameters are based on a large reservoir parameter database. Different measured relative permeability relations are considered. The methodology of estimating storage capacity is discussed. Using numerical 1D and 3D experiments, detailed time-dependent storage capacity estimates are derived. With respect to the concept developed in this work, it is possible to estimate effective CO2 storage capacity in saline aquifers. It is shown that effective CO2 mass stored in the reservoir varies by a factor of 20 for the reservoir setups considered. A high influence of the relative permeability relation on storage capacity is shown.
The dependent-domain theory of hysteresis developed here accounts for the effect of the pore-water blockage against air entry, while using the similarity hypothesis of the universal model (Mualem 1977). The resulting model is simpler and requires fewer data for calibration than previous dependent-domain models. Marked improvement is attained compared with the performance of the universal model.
Three porous media-glass beads, sand, and sandy loam for which detailed data are available-were used to test the model. Computed primary and secondary scanning curves derived by the new model are compared with corresponding experimental curves, as well as computed curves based on Model II of Mualem (1974) or Model III of Mualem and Dagan (1975). The new model seems to agree with observations much better that Model II, which uses the same amount of data for calibration. The accuracy of the computed results is comparable to that found for the dependent-domain model of Mualem and Dagan (1975), which requires more experimental data.
(C) Williams & Wilkins 1984. All Rights Reserved.
Storage of CO 2 in saline aquifers is intended to be at supercritical pressure and temperature conditions, but CO 2 leaking from a geologic storage reservoir and migrating toward the land surface (through faults, fractures, or improperly abandoned wells) would reach subcritical conditions at depths shallower than 500–750 m. At these and shallower depths, subcritical CO 2 can form two‐phase mixtures of liquid and gaseous CO 2 , with significant latent heat effects during boiling and condensation. Additional strongly non‐isothermal effects can arise from decompression of gas‐like subcritical CO 2 , the so‐called Joule–Thomson effect. Integrated modeling of CO 2 storage and leakage requires the ability to model non‐isothermal flows of brine and CO 2 at conditions that range from supercritical to subcritical, including three‐phase flow of aqueous phase, and both liquid and gaseous CO 2 . In this paper, we describe and demonstrate comprehensive simulation capabilities that can cope with all possible phase conditions in brine‐CO 2 systems. Our model formulation includes: an accurate description of thermophysical properties of aqueous and CO 2 ‐rich phases as functions of temperature, pressure, salinity and CO 2 content, including the mutual dissolution of CO 2 and H 2 O;
transitions between super‐ and subcritical conditions, including phase change between liquid and gaseous CO 2 ;
one‐, two‐, and three‐phase flow of brine‐CO 2 mixtures, including heat flow;
non‐isothermal effects associated with phase change, mutual dissolution of CO 2 and water, and (de‐) compression effects; and
the effects of dissolved NaCl, and the possibility of precipitating solid halite, with associated porosity and permeability change.
Applications to specific leakage scenarios demonstrate that the peculiar thermophysical properties of CO 2 provide a potential for positive as well as negative feedbacks on leakage rates, with a combination of self‐enhancing and self‐limiting effects. Lower viscosity and density of CO 2 as compared to aqueous fluids provides a potential for self‐enhancing effects during leakage, while strong cooling effects from liquid CO 2 boiling into gas, and from expansion of gas rising towards the land surface, act to self‐limit discharges. Strong interference between fluid phases under three‐phase conditions (aqueous – liquid CO 2 – gaseous CO 2 ) also tends to reduce CO 2 fluxes. Feedback on different space and time scales can induce non‐monotonic behavior of CO 2 flow rates. © 2011 Society of Chemical Industry and John Wiley & Sons, Ltd
Deep saline aquifers are one of the most suitable geologic formations for carbon sequestration. The linear and global stability analysis of the time-dependent density-driven convection in deep saline aquifers is presented for long-term storage of carbon dioxide (CO 2). The convective mixing that can greatly accelerate the CO 2 dissolution into saline aquifers arises because the density of brine increases upon the dissolution of CO 2 and such a density difference may induce instability. The effects of anisotropic permeability on the stability criteria, such as the critical time for the appearance of convective phenomena and the critical wavelength of the most unstable perturbation, are investigated with linear and global stability analysis. The linear stability analysis provides a sufficient con-dition for instability while the global stability analysis yields a sufficient condition for stability. The results obtained from these two approaches are not exactly the same but show a consistent trend, both indicating that the anisotropic system becomes more unstable when either the vertical or horizontal permeability increases.
CO2 storage in deep saline aquifers is considered a possible option for mitigation of greenhouse gas emissions from anthropogenic sources. Understanding of the underlying mechanisms, such as convective mixing, that affect the long-term fate of the injected CO2 in deep saline aquifers, is of prime importance. We present scaling analysis of the convective mixing of CO2 in saline aquifers based on direct numerical simulations. The convective mixing of CO2 in aquifers is studied, and three mixing periods are identified. It is found that, for Rayleigh numbers less than 600, mixing can be approximated by a scaling relationship for the Sherwood number, which is proportional to Ra1/2. Furthermore, it is shown that the onset of natural convection follows tDc∼Ra−2 and the wavelengths of the initial convective instabilities are proportional to Ra. Such findings give insight into understanding the mixing mechanisms and long term fate of the injected CO2 for large scale geological sequestration in deep saline aquifers. In addition, a criterion is developed that provides the appropriate numerical mesh resolution required for accurate modeling of convective mixing of CO2 in deep saline aquifers. © 2007 American Institute of Chemical Engineers AIChE J, 2007
We have used the TOUGH2-MP/ECO2N code to perform numerical simulation studies of the long-term behavior of CO2 stored in an aquifer with a sloping caprock. This problem is of great practical interest, and is very challenging due to
the importance of multi-scale processes. We find that the mechanism of plume advance is different from what is seen in a forced
immiscible displacement, such as gas injection into a water-saturated medium. Instead of pushing the water forward, the plume
advances because the vertical pressure gradients within the plume are smaller than hydrostatic, causing the groundwater column
to collapse ahead of the plume tip. Increased resistance to vertical flow of aqueous phase in anisotropic media leads to reduced
speed of up-dip plume advancement. Vertical equilibrium models that ignore effects of vertical flow will overpredict the speed
of plume advancement. The CO2 plume becomes thinner as it advances, but the speed of advancement remains constant over the entire simulation period of
up to 400years, with migration distances of more than 80km. Our simulations include dissolution of CO2 into the aqueous phase and associated density increase, and molecular diffusion. However, no convection develops in the aqueous
phase because it is suppressed by the relatively coarse (sub-) horizontal gridding required in a regional-scale model. A first
crude sub-grid-scale model was developed to represent convective enhancement of CO2 dissolution. This process is found to greatly reduce the thickness of the CO2 plume, but, for the parameters used in our simulations, does not affect the speed of plume advancement.
KeywordsCO2 plume–Long-term fate–Sloping aquifer–Numerical simulation–Enhanced dissolution–Capillary effects
Injection of CO2 into saline aquifers is described by mass conservation equations for the three components water, salt (NaCl), and CO2. The equations are discretized using an integral finite difference method, and are solved using methods developed in geothermal and petroleum reservoir engineering. Phase change processes are treated through switching of primary thermodynamic variables. A realistic treatment of PVT (fluid) properties is given which includes salinity and fugacity effects for partitioning of CO2 between gaseous and aqueous phases. Chemical reactions and mechanical stress effects are neglected. Numerical simulations are presented for injection of CO2 into a brine aquifer, and for loss of CO2 from storage through discharge along a fault zone. It is found that simulated pressures are much more sensitive to space discretization effects than are phase saturations. CO2 discharge along a fault is a self-enhancing process whose flow rates can increase over time by more than an order of magnitude, suggesting that reliable containment of CO2 will require multiple barriers.
Simulations are routinely used to study the process of carbon dioxide (CO2) sequestration in saline aquifers. In this paper, we describe the modeling and simulation of the dissolution–diffusion–convection process based on a total velocity splitting formulation for a variable-density incompressible single-phase model. A second-order accurate sequential algorithm, implemented within a block-structured adaptive mesh refinement (AMR) framework, is used to perform high-resolution studies of the process. We study both the short-term and long-term behaviors of the process. It is found that the onset time of convection follows closely the prediction of linear stability analysis. In addition, the CO2 flux at the top boundary, which gives the rate at which CO2 gas dissolves into a negatively buoyant aqueous phase, will reach a stabilized state at the space and time scales we are interested in. This flux is found to be proportional to permeability, and independent of porosity and effective diffusivity, indicative of a convection-dominated flow. A 3D simulation further shows that the added degrees of freedom shorten the onset time and increase the magnitude of the stabilized CO2 flux by about 25%. Finally, our results are found to be comparable to results obtained from TOUGH2-MP.
ECO2N is a fluid property module for the TOUGH2 simulator (Version 2.0) that was designed for applications involving geologic storage of CO2 in saline aquifers. It includes a comprehensive description of the thermodynamics and thermophysical properties of H2O–NaCl–CO2 mixtures, that reproduces fluid properties largely within experimental error for the temperature, pressure and salinity conditions of interest (10 °C ⩽ T ⩽ 110 °C; P ⩽ 600 bar; salinity up to full halite saturation). Flow processes can be modeled isothermally or non-isothermally, and phase conditions represented may include a single (aqueous or CO2-rich) phase, as well as two-phase mixtures. Fluid phases may appear or disappear in the course of a simulation, and solid salt may precipitate or dissolve. ECO2N can model super- as well as sub-critical conditions, but it does not make a distinction between liquid and gaseous CO2 and hence is not applicable for processes that involve two CO2-rich phases. This paper highlights significant features of ECO2N, and presents illustrative applications.
The basic equation for volume, heat and CO2 flux in a porous medium which is subject to both a temperature field and molecular diffusion have been analysed with respect to the stability criteria for convectional vertical flow in a porous medium. This analysis reveals under what condition vertical convection may occur, which is important for the total storage capacity of CO2 in aquifers.
Numerical models of geologic storage of carbon dioxide (CO2) in brine-bearing formations use characteristic curves to represent the interactions of non-wetting-phase CO2 and wetting-phase brine. When a problem includes both injection of CO2 (a drainage process) and its subsequent post-injection evolution (a combination of drainage and wetting), hysteretic characteristic curves are required to correctly capture the behavior of the CO2 plume. In the hysteretic formulation, capillary pressure and relative permeability depend not only on the current grid-block saturation, but also on the history of the saturation in the grid block. For a problem that involves only drainage or only wetting, a non-hysteretic formulation, in which capillary pressure and relative permeability depend only on the current value of the grid-block saturation, is adequate. For the hysteretic formulation to be robust computationally, care must be taken to ensure the differentiability of the characteristic curves both within and beyond the turning-point saturations where transitions between branches of the curves occur. Two example problems involving geologic CO2 storage are simulated with TOUGH2, a multiphase, multicomponent code for flow and transport through geological media. Both non-hysteretic and hysteretic formulations are used, to illustrate the applicability and limitations of non-hysteretic methods. The first application considers leakage of CO2 from the storage formation to the ground surface, while the second examines the role of heterogeneity within the storage formation.
A general approach to evaluating sedimentary basins for CO2 disposal is presented in this paper. The approach is exemplified for the case of the Alberta Basin in western Canada where a wealth of geological and hydrogeological data from more than 150,000 wells drilled by the oil industry allows for a proper estimate of the basin potential for long-term storage of CO2 captured from fossil-fuelled power plants. Geochemical and hydrogeological analyses of CO2 interaction with the aquifer water and rocks, and of CO2 transport in miscible and immiscible phase by the natural flow of aquifer water indicate that, besides stratigraphic trapping, two additional mechanisms are available for the capture and long-term retention of CO2 in the subsurface. One mechanism is mineral trapping through precipitation of carbonate minerals when CO2 is injected into basic siliciclastic aquifers. The other mechanism is hydrodynamic trapping when the residence or travel time of CO2 in low permeability regional aquifers is of the order of thousands to a million years.
Sulfur dioxide is a possible co-injectant with carbon dioxide in the context of geologic sequestration. Because of the potential of SO2 to acidify formation brines, the extent of SO2 dissolution from the CO2 phase will determine the viability of co-injection. Pressure-, temperature-, and salinity-adjusted values of the SO2 Henry's Law constant and fugacity coefficient were determined. They are predicted to decrease with depth, such that the solubility of SO2 is a factor of 0.04 smaller than would be predicted without these adjustments. To explore the potential effects of transport limitations, a nonsteady-state model of SO2 diffusion through a stationary cone-shaped plume of supercritical CO2 was developed. This model represents an end-member scenario of diffusion-controlled dissolution of SO2, to contrast with models of complete phase equilibrium. Simulations for conditions corresponding to storage depths of 0.8-2.4 km revealed that after 1000 years, 65-75% of the SO2 remains in the CO2 phase. This slow release of SO2 would largely mitigate its impact on brine pH. Furthermore, small amounts of SO2 are predicted to have a negligible effect on the critical point of CO2 but will increase phase density by as much as 12% for mixtures containing 5% SO2.
Geological storage of carbon dioxide (CO2) is likely to be an integral component of any realistic plan to reduce anthropogenic greenhouse gas emissions. In conjunction with large-scale deployment of carbon storage as a technology, there is an urgent need for tools which provide reliable and quick assessments of aquifer storage performance. Previously, abandoned wells from over a century of oil and gas exploration and production have been identified as critical potential leakage paths. The practical importance of abandoned wells is emphasized by the correlation of heavy CO2 emitters (typically associated with industrialized areas) to oil and gas producing regions in North America. Herein, we describe a novel framework for predicting the leakage from large numbers of abandoned wells, forming leakage paths connecting multiple subsurface permeable formations. The framework is designed to exploit analytical solutions to various components of the problem and, ultimately, leads to a grid-free approximation to CO2 and brine leakage rates, as well as fluid distributions. We apply our model in a comparison to an established numerical solverforthe underlying governing equations. Thereafter, we demonstrate the capabilities of the model on typical field data taken from the vicinity of Edmonton, Alberta. This data set consists of over 500 wells and 7 permeable formations. Results show the flexibility and utility of the solution methods, and highlight the role that analytical and semianalytical solutions can play in this important problem.
It is possible to accelerate the dissolution of CO2 injected into deep aquifers by pumping brine from regions where it is undersaturated into regions occupied by CO2. For a horizontally confined reservoir geometry, we find that it is possible to dissolve most of the injected CO2 within a few hundred years at an energy cost that is less than 20% of the cost of compressing the CO2 to reservoir conditions. We anticipate that use of reservoir engineering to accelerate dissolution can reduce the risks of CO2 storage by reducing the duration over which buoyant free-phase CO2 is present underground. Such techniques could simplify risk assessment by reducing uncertainty about the long-term fate of injected CO2, and could expand the range of reservoirs which are acceptable for storage.
LNAPL Distribution and Recovery Model (LDRM) Volume 1: Distribuion and Recovery of Petroleum Hydrocarbon Liquids in Porous Media
- R Charbeneau
Charbeneau, R., 2007, LNAPL Distribution and
Recovery Model (LDRM) Volume 1:
Distribuion and Recovery of Petroleum
Hydrocarbon Liquids in Porous Media,
American Petroleum Institute API
Publication 4760.
Development and Application of a Ground-Water Flow and Management Model of the Chesterfield County Region in South Carolina
- B Campbell
Campbell, B., 2008, Development and
Application of a Ground-Water Flow and
Management Model of the Chesterfield
County Region in South Carolina. Clemson
Hydrogeology Symposium, Clemson
University.
Coordinating Lead AuthorsUnderground Geological Storage
- S M Benson
- P Cook
Benson, S.M. and P. Cook, Coordinating Lead
Authors., 2005, "Underground Geological
Storage," IPCC Special Report on Carbon
Dioxide Capture and Storage, Chapter 5.
Intergovernmental Panel on Climate
Change, Cambridge University Press,
Cambridge, U.K
- R Charbeneau
Charbeneau, R., 2007, LNAPL Distribution and
Recovery Model (LDRM) Volume 1:
Distribuion and Recovery of Petroleum
Hydrocarbon Liquids in Porous Media,
American Petroleum Institute API
Publication 4760.
A semi-analytical model estimating leakage associated with CO2 storage in large-scale multi-layered geological systems with multiple leaky wells
- J M Nordbotten
- D Kavetski
- M A Celia
- S Bachu
Nordbotten J.M., D. Kavetski, M.A. Celia, and
S. Bachu, 2008, A semi-analytical model
estimating leakage associated with CO2
storage in large-scale multi-layered
geological systems with multiple leaky
wells, Environmental Science &
Technology, doi:10.1021/es801135v.
A semi-analytical model estimating leakage associated with CO2 storage in large-scale multi-layered geological systems with multiple leaky wells
- Nordbotten
Numerical simulation of density driven natural convection in porous media with applications for CO2 injection projects
- Farajzadeh
Convective dissolution of carbon dioxide in saline aquifers
- Neufled JA