Pressure Buildup During CO<Subscript>2</Subscript> Injection into a Closed Brine Aquifer

CO₂ injected into porous formations is accommodated by reduction in the volume of the formation fluid and enlargement of the pore space, through compression of the formation fluids and rock material, respectively. A critical issue is how the resulting pressure buildup will affect the mechanical integrity of the host formation and caprock. Building on an existing approximate solution for formations of infinite radial extent, this article presents an explicit approximate solution for estimating pressure buildup due to injection of CO₂ into closed brine aquifers of finite radial extent. The analysis is also applicable for injection into a formation containing multiple wells, in which each well acts as if it were in a quasi-circular closed region. The approximate solution is validated by comparison with vertically averaged results obtained using TOUGH2 with ECO2N (where many of the simplifying assumptions are relaxed), and is shown to be very accurate over wide ranges of the relevant parameter space. The resulting equations for the pressure distribution are explicit, and can be easily implemented within spreadsheet software for estimating CO₂ injection capacity.     

Injection and Storage of CO<Subscript>2</Subscript> in Deep Saline Aquifers: Analytical Solution for CO<Subscript>2</Subscript> Plume Evolution During Injection

Injection of fluids into deep saline aquifers is practiced in several industrial activities, and is being considered as part of a possible mitigation strategy to reduce anthropogenic emissions of carbon dioxide into the atmosphere. Injection of CO₂ into deep saline aquifers involves CO₂ as a supercritical fluid that is less dense and less viscous than the resident formation water. These fluid properties lead to gravity override and possible viscous fingering. With relatively mild assumptions regarding fluid properties and displacement patterns, an analytical solution may be derived to describe the space–time evolution of the CO₂ plume. The solution uses arguments of energy minimization, and reduces to a simple radial form of the Buckley–Leverett solution for conditions of viscous domination. In order to test the applicability of the analytical solution to the CO₂ injection problem, we consider a wide range of subsurface conditions, characteristic of sedimentary basins around the world, that are expected to apply to possible CO₂ injection scenarios. For comparison, we run numerical simulations with an industry standard simulator, and show that the new analytical solution matches a full numerical solution for the entire range of CO₂ injection scenarios considered. The analytical solution provides a tool to estimate practical quantities associated with CO₂ injection, including maximum spatial extent of a plume and the shape of the overriding less-dense CO₂ front.     

Numerical Simulations of the Thermal Impact of Supercritical CO<Subscript>2</Subscript> Injection on Chemical Reactivity in a Carbonate Saline Reservoir

Geological sequestration of CO₂ offers a promising solution for reducing net emissions of greenhouse gases into the atmosphere. This emerging technology must make it possible to inject CO₂ into deep saline aquifers or oil- and gas-depleted reservoirs in the supercritical state (P > 7.4MPa and T > 31.1°C) to achieve a higher density and therefore occupy less volume underground. Previous experimental and numerical simulations have demonstrated that massive CO₂ injection in saline reservoirs causes a major disequilibrium of the physical and geochemical characteristics of the host aquifer. The near-well injection zone seems to constitute an underground hydrogeological system particularly impacted by supercritical CO₂ injection and the most sensitive area, where chemical phenomena (e.g. mineral dissolution/precipitation) can have a major impact on the porosity and permeability. Furthermore, these phenomena are highly sensitive to temperature. This study, based on numerical multi-phase simulations, investigates thermal effects during CO₂ injection into a deep carbonate formation. Different thermal processes and their influence on the chemical and mineral reactivity of the saline reservoir are discussed. This study underlines both the minor effects of intrinsic thermal and thermodynamic processes on mineral reactivity in carbonate aquifers, and the influence of anthropic thermal processes (e.g. injection temperature) on the carbonates’ behaviour.     

Numerical Simulation Studies of the Long-term Evolution of a CO<Subscript>2</Subscript> Plume in a Saline Aquifer with a Sloping Caprock

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 400 years, with migration distances of more than 80 km. 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.     

Initiation of Combustion in a Supersonic Hydrogen-Air Mixture Flow by CO<Subscript>2</Subscript>-Laser Radiation

Features of the ignition kinetics of an H₂/air mixture in the supersonic flow behind an inclined shock front are analyzed when asymmetric vibrations of a small amount (<1%) of O₃ molecules specially introduced into the initial mixture are excited by 9.7 μm wavelength radiation. It is shown that this radiation leads to intensification of the chain reactions and makes it possible to organize combustion at small distances from the front (of the order of 1 m) of even relatively weak shocks at small values of the laser radiation energies absorbed by the gas. This method of initiating combustion in a supersonic flow is 10–100 times more efficient than the thermal method.__________Translated from Izvestiya Rossiiskoi Academii Nauk, Mekhanika Zhidkosti i Gaza, No. 2, 2005, pp. 157–167.Original Russian Text Copyright © 2005 by Lukhovitskii, Starik, and Titova.     

Impact of CO<Subscript>2</Subscript> Injection on Flow Behavior of Coalbed Methane Reservoirs

On the basis of observations at four enhanced coalbed methane (ECBM)/CO₂ sequestration pilots, a laboratory-scale study was conducted to understand the flow behavior of coal in a methane/CO₂ environment. Sorption-induced volumetric strain was first measured by flooding fresh coal samples with adsorptive gases (methane and CO₂). In order to replicate the CO₂–ECBM process, CO₂ was then injected into a methane-saturated core to measure the incremental “swelling.” As a separate effort, the permeability of a coal core, held under triaxial stress, was measured using methane. This was followed by CO₂ flooding to replace the methane. In order to best replicate the conditions in situ, the core was held under uniaxial strain, that is, no horizontal strain was permitted during CO₂ flooding. Instead, the horizontal stress was adjusted to ensure zero strain. The results showed that the relative strain ratio for CO₂/methane was between 2 and 3.5. The measured volumetric strains were also fitted using a Langmuir-type model, thus enabling calculation of the strain at any gas pressure and using the analytical permeability models. For permeability work, effort was made to increase the horizontal stress to achieve the desired zero horizontal strain condition expected under in situ condition, but this became impossible because the “excess” stress required to maintain this condition was very large, resulting in sample failure. Finally, when CO₂ was introduced and horizontal strain was permitted, permeability reduction was an order of magnitude greater, suggesting that the “excess” stress would have reduced it significantly further. The positive finding of the work was that the “excess” stresses associated with injection of CO₂ are large. The excess stresses generated might be sufficient to cause microfracturing and increased permeability, and improved injectivity. Also, there might be a weakening effect resulting from repeated CO₂ injection, as has been found to be the case with thermal cycling of rocks.     

Nonequilibrium molecular radiation behind the front of a strong shock wave in the CO<Subscript>2</Subscript>-N<Subscript>2</Subscript>-O<Subscript>2</Subscript> mixture

Models of population of some radiating electron-vibrational states of CO, CN, and C₂ molecules are developed. The characteristics of radiation in a chemically nonequilibrium flow behind the front of a strong shock wave in a mixture of gases constituting the Martian atmosphere are calculated. The numerical data are compared with experimental results.Translated from Prikladnaya Mekhanika i Tekhnicheskaya Fizika, Vol. 46, No. 2, pp. 13–22, March–April, 2005     

Modeling of Rocks and Cement Alteration due to CO<Subscript>2</Subscript> Injection in an Exploited Gas Reservoir

The injection of CO₂ in exploited natural gas reservoirs as a means to reduce greenhouse gas (GHG) emissions is highly attractive as it takes place in well-known geological structures of proven integrity with respect to gas leakage. The injection of a reactive gas such as CO₂ puts emphasis on the possible alteration of reservoir and caprock formations and especially of the wells’ cement sheaths induced by the modification of chemical equilibria. Such studies are important for injectivity assurance, wellbore integrity, and risk assessment required for CO₂ sequestration site qualification. Within a R&D project funded by Eni, we set up a numerical model to investigate the rock–cement alterations driven by the injection of CO₂ into a depleted sweet natural gas pool. The simulations are performed with the TOUGHREACT simulator (Xu et al. in Comput Geosci 32:145–165, 2006) coupled to the TMGAS EOS module (Battistelli and Marcolini in Int J Greenh Gas Control 3:481–493, 2009) developed for the TOUGH2 family of reservoir simulators (Pruess et al. in TOUGH2 User’s Guide, Version 2.0, 1999). On the basis of field data, the system is considered in isothermal (50°C) and isobaric (128.5 bar) conditions. The effects of the evolving reservoir gas composition are taken into account before, during, and after CO₂ injection. Fully water-saturated conditions were assumed for the cement sheath and caprock domains. The gas phase does not flow by advection from the reservoir into the interacting domains so that molecular diffusion in the aqueous phase is the most important process controlling the mass transport occurring in the system under study.     

Thermodynamic Conditions of Formation of CO<Subscript>2</Subscript> Hydrate in Carbon Dioxide Injection into a Methane Hydrate Reservoir

The mechanism of replacement of methane by carbon dioxide in the hydrate in the process of CO₂ injection into a reservoir with formation of fronts of methane hydrate dissociation and carbon dioxide hydrate generation is investigated. It is found that such a replacement regime can be implemented in both low- and high-permeability reservoirs. It is shown that in the highintensity injection regime the heat flux from the well does not affect propagation of the fronts of methane hydrate dissociation and carbon dioxide hydrate generation. In this case the replacement regime is maintained by only the heat released at formation of carbon dioxide hydrate. An increase in the injection pressure may lead to suppression of methane hydrate dissociation and termination of the replacement reaction. The critical diagrams of existence of the regime of conversion of methane hydrate to carbon dioxide hydrate are constructed.     

Injection,Flow, and Mixing of CO<Subscript>2</Subscript> in Porous Media with Residual Gas

Geologic structures associated with depleted natural gas reservoirs are desirable targets for geologic carbon sequestration (GCS) as evidenced by numerous pilot and industrial-scale GCS projects in these environments world-wide. One feature of these GCS targets that may affect injection is the presence of residual CH₄. It is well known that CH₄ drastically alters supercritical CO₂ density and viscosity. Furthermore, residual gas of any kind affects the relative permeability of the liquid and gas phases, with relative permeability of the gas phase strongly dependent on the time-history of imbibition or drainage, i.e., dependent on hysteretic relative permeability. In this study, the effects of residual CH₄ on supercritical CO₂ injection were investigated by numerical simulation in an idealized one-dimensional system under three scenarios: (1) with no residual gas; (2) with residual supercritical CO₂; and (3) with residual CH₄. We further compare results of simulations that use non-hysteretic and hysteretic relative permeability functions. The primary effect of residual gas is to decrease injectivity by decreasing liquid-phase relative permeability. Secondary effects arise from injected gas effectively incorporating residual gas and thereby extending the mobile-gas plume relative to cases with no residual gas. Third-order effects arise from gas mixing and associated compositional effects on density that effectively create a larger plume per unit mass. Non-hysteretic models of relative permeability can be used to approximate some parts of the behavior of the system, but fully hysteretic formulations are needed to accurately model the entire system.     

Analytical Solution Incorporating History-Dependent Processes for Quick Assessment of Capillary Trapping During CO<Subscript>2</Subscript> Geological Storage

Carbon storage in saline formations is considered as a promising option to ensure the necessary decrease of CO₂ anthropogenic emissions. Its industrial development in those formations is above all conditioned by its safety demonstration. Assessing the evolution of trapped and mobile CO₂ across time is essential in the perspective of reducing leakage risks. In this work, we focus on residual trapping phenomenon occurring during the wetting of the injected CO₂ plume. History dependent effects are of first importance when dealing with capillary trapping. We then apply the classical fractional flow theory (Buckley–Leverett type model) and include trapping and hysteresis models; we derive an analytical solution for the temporal evolution of saturation profile and of CO₂ trapped quantity when injecting water after the gas injection (“artificial imbibition”). The comparison to numerical simulations for different configurations shows satisfactory match and justifies, in the case of industrial CO₂ storage, the assumptions of incompressible flow with no consideration of capillary pressure. The obtained analytical solution allows the quick assessment of both the quantity and the location of mobile gas left during imbibition.     

Matched Boundary Extrapolation Solutions for CO<Subscript>2</Subscript> Well-Injection into a Saline Aquifer

The injection of supercritical CO₂ through wells into deep brine reservoirs is a topic of interest for geologic carbon sequestration. The injected CO₂ is predominantly immiscible with the brine and its low density relative to brine leads to strong buoyancy effects. The displacement of brine by CO₂ in general is a multidimensional, complex nonlinear problem that requires numerical methods to solve. The approximations of vertical equilibrium and complete gravity segregation (sharp interface) have been introduced to reduce the complexity and dimensionality of the problem. Furthermore, for the radial displacement process considered here, the problem can be formulated in terms of a similarity variable that reduces spatial and temporal dependencies to a single variable. However, the resulting ordinary differential equation is still nonlinear and exact solutions are not available. The existing analytical solutions are approximations limited to certain parameter ranges that become inaccurate over a large portion of the parameter space. Here, I use a matched boundary extrapolation method to provide much greater accuracy for analytical/semi-analytical approximations over the full parameter range.     

An Experimental Study on the Influence of Sub-Core Scale Heterogeneities on CO<Subscript>2</Subscript> Distribution in Reservoir Rocks

This article presents the results of CO₂/brine two-phase flow experiments in rocks at reservoir conditions. X-ray CT scanning is used to determine CO₂ saturation at a fine scale with a resolution of a few pore volumes and provide 3D porosity and saturation maps that can be use to correlate CO₂ saturations and rock properties. The study highlights the strong influence of sub-core scale heterogeneities on the spatial distribution of CO₂ at steady state and provides useful relative permeability data on a sample originated from an actual storage site (CO2CRC-Otway project, Victoria, South-West Australia). Two different samples tested, although different in nature, present strong heterogeneities, but differ in the detail of the connectivity of high porosity layers. In both samples, the results of the investigations show that sub-core scale heterogeneities control the sweep efficiency and may cause channeling through the porous medium. In one of the samples, CO₂ saturation appears uncorrelated to porosity close to the outlet end of the core. This observation is understood as a result of the position and the orientation of high porosity layers with respect to the inlet face of the core. Finally, in the operating conditions of the two experiments, the saturation maps demonstrate that gravity does not play a major role since no detectable buoyancy driven flow is observed.     

Production of nanomaterials by vaporizing ceramic targets irradiated by a moderate-power continuous-wave CO<Subscript>2</Subscript> laser

The efficiency of utilization of CO ₂ laser energy for vaporization of Al ₂ O ₃ ceramics is evaluated using a mathematical model for the interaction of laser radiation with materials. It is shown that the calculated efficiency of radiation-energy utilization is not higher than 15% at a radiation power density of 10⁵ W/cm ² on the target. On the experimental facility designed for the synthesis of nanopowders, a vaporization rate of 1 g/h was achieved for Al ₂ O ₃, which corresponds to a 3% efficiency of radiation-energy utilization. The dependence of the characteristic particle size of a zirconium oxide nanopowder on helium pressure in the range of 0.01–1.00 atm was studied. Results of experiments on vaporization of multicomponent materials (LaNiO ₃ and the Tsarev meteorite) are given. __________ Translated from Prikladnaya Mekhanika i Tekhnicheskaya Fizika, Vol. 48, No. 2, pp. 172–184, March–April, 2007.     

Evaluation of Potential Changes in Groundwater Quality in Response to CO<Subscript>2</Subscript> Leakage from Deep Geologic Storage

Concern has been expressed that carbon dioxide (CO₂) leaking from deep geological storage could adversely impact water quality in overlying potable aquifers by mobilizing hazardous trace elements. In this article, we present a systematic evaluation of the possible water quality changes in response to CO₂ intrusion into aquifers currently used as sources of potable water in the United States. The evaluation was done in three parts. First, we developed a comprehensive geochemical model of aquifers throughout the United States, evaluating the initial aqueous abundances, distributions, and modes of occurrence of selected hazardous trace elements in a large number of potable groundwater quality analyses from the National Water Information System (NWIS) database. For each analysis, we calculated the saturation indices (SIs) of several minerals containing these trace elements. The minerals were initially selected through literature surveys to establish whether field evidence supported their postulated presence in potable water aquifers. Mineral assemblages meeting the criterion of thermodynamic saturation were assumed to control the aqueous concentrations of the hazardous elements at initial system state as well as at elevated CO₂ concentrations caused by the ingress of leaking CO₂. In the second step, to determine those hazardous trace elements of greatest concern in the case of CO₂ leakage, we conducted thermodynamic calculations to predict the impact of increasing CO₂ partial pressures on the solubilities of the identified trace element mineral hosts. Under reducing conditions characteristic of many groundwaters, the trace elements of greatest concern are arsenic (As) and lead (Pb). In the final step, a series of reactive-transport simulations was performed to investigate the chemical evolution of aqueous As and Pb after the intrusion of CO₂ from a storage reservoir into a shallow confined groundwater resource. Results from the reactive-transport model suggest that a significant increase of aqueous As and Pb concentrations may occur in response to CO₂ intrusion, but that the maximum concentration values remain below or close to specified maximum contaminant levels (MCLs). Adsorption/desorption from mineral surfaces may strongly impact the mobilization of As and Pb.     

Modeling of CO<Subscript>2</Subscript> Leakage up Through an Abandoned Well from Deep Saline Aquifer to Shallow Fresh Groundwaters

This article presents a numerical modeling application using the code TOUGHREACT of a leakage scenario occurring during a CO₂ geological storage performed in the Jurassic Dogger formation in the Paris Basin. This geological formation has been intensively used for geothermal purposes and is now under consideration as a site for the French national program of reducing greenhouse gas emissions and CO₂ geological storage. Albian sandstone, situated above the Dogger limestone is a major strategic potable water aquifer; the impacts of leaking CO₂ due to potential integrity failure have, therefore, to be investigated. The present case–study illustrates both the capacity and the limitations of numerical tools to address such a critical issue. The physical and chemical processes simulated in this study have been restricted to: (i) supercritical CO₂ injection and storage within the Dogger reservoir aquifer, (ii) CO₂ upwards migration through the leakage zone represented as a 1D vertical porous medium to simulate the cement–rock formation interface in the abandoned well, and (iii) impacts on the Albian aquifer water quality in terms of chemical composition and the mineral phases representative of the porous rock by estimating fluid–rock interactions in both aquifers. Because of CPU time and memory constraints, approximation and simplification regarding the geometry of the geological structure, the mineralogical assemblages and the injection period (up to 5 years) have been applied to the system, resulting in limited analysis of the estimated impacts. The CO₂ migration rate and the quantity of CO₂ arriving as free gas and dissolving, firstly in the storage water and secondly in the water of the overlying aquifer, are calculated. CO₂ dissolution into the Dogger aquifer induces a pH drop from about 7.3 to 4.9 limited by calcite dissolution buffering. Glauconite present in the Albian aquifer also dissolves, causing an increase of the silicon and aluminum in solution and triggering the precipitation of kaolinite and quartz around the intrusion point. A sensitivity analysis of the leakage rate according to the location of the leaky well and the variability of the petro-physical properties of the reservoir, the leaky well zone and the Albian aquifers is also provided.     

Investigation of CO<Subscript>2</Subscript> Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon Storage in a Saline Formation

The hydrodynamic behavior of carbon dioxide (CO₂) injected into a deep saline formation is investigated, focusing on trapping mechanisms that lead to CO₂ plume stabilization. A numerical model of the subsurface at a proposed power plant with CO₂ capture is developed to simulate a planned pilot test, in which 1,000,000 metric tons of CO₂ is injected over a 4-year period, and the subsequent evolution of the CO₂ plume for hundreds of years. Key measures are plume migration distance and the time evolution of the partitioning of CO₂ between dissolved, immobile free-phase, and mobile free-phase forms. Model results indicate that the injected CO₂ plume is effectively immobilized at 25 years. At that time, 38% of the CO₂ is in dissolved form, 59% is immobile free phase, and 3% is mobile free phase. The plume footprint is roughly elliptical, and extends much farther up-dip of the injection well than down-dip. The pressure increase extends far beyond the plume footprint, but the pressure response decreases rapidly with distance from the injection well, and decays rapidly in time once injection ceases. Sensitivity studies that were carried out to investigate the effect of poorly constrained model parameters permeability, permeability anisotropy, and residual CO₂ saturation indicate that small changes in properties can have a large impact on plume evolution, causing significant trade-offs between different trapping mechanisms.     

Linear Stability Analysis of Double-Diffusive Convection in Porous Media,with Application to Geological Storage of CO<Subscript>2</Subscript>

Onset of double-diffusive buoyancy-driven flow resulted from vertical temperature and concentration gradients in a horizontal layer of a saturated and homogenous porous medium is investigated using amplification factor theory. After injection of CO₂ into a deep saline aquifer, the density of the brine saturated with CO₂ increases slightly. This increase in density induces natural convection. The effect of geothermal gradient is also considered in this work as a second incentive for convection and the double-diffusion convection was studied. Linear stability analysis is used to predict the inception of instabilities and initial wavelength of the convective instabilities. The analysis presented is applied to acid gas injection (as an analogue for CO₂ storage) into saline aquifers in the Alberta basin. It is found that the geothermal gradient does not have significant effect on the onset of convection for these aquifers. It is shown that the geothermal effects on the onset of natural convection are negligible as compared to the solutal effects induced by dissolution and diffusion of CO₂ in deep saline aquifers. Therefore, the linear stability analysis and the long-term numerical simulation of CO₂ sequestration into such saline aquifers may be assumed to be isothermal in terms of natural convection occurrence.     

Coreflooding Studies to Investigate the Potential of Carbonated Water Injection as an Injection Strategy for Improved Oil Recovery and CO<Subscript>2</Subscript> Storage

Carbonated water injection (CWI) is a CO₂-augmented water injection strategy that leads to increased oil recovery with added advantage of safe storage of CO₂ in oil reservoirs. In CWI, CO₂ is used efficiently (compared to conventional CO₂ injection) and hence it is particularly attractive for reservoirs with limited access to large quantities of CO₂, e.g. offshore reservoirs or reservoirs far from large sources of CO₂. We present the results of a series of CWI coreflood experiments using water-wet and mixed-wet Clashach sandstone cores and a reservoir core with light oil (n-decane), refined viscous oil and a stock-tank crude oil. The experiments were carried out to assess the performance of CWI and to quantify the level of additional oil recovery and CO₂ storage under various experimental conditions. We show that the ultimate oil recovery by CWI is higher than the conventional water flooding in both secondary and tertiary recovery methods. Oil swelling as a result of CO₂ diffusion into the oil and the subsequent oil viscosity reduction and coalescence of the isolated oil ganglia are amongst the main mechanisms of oil recovery by CWI that were observed through the visualisation experiments in high-pressure glass micromodels. There was also evidence of a change in the rock wettability that could also influence the oil recovery. The coreflood test results also reveal that the CWI performance is influenced by oil viscosity, core wettability and the brine salinity. Higher oil recovery was obtained with the mixed-wet core than the water-wet core, with light oil than with the viscous oil and low salinity carbonated brine than high-salinity carbonated brine. At the end of the flooding period, an encouraging amount of the injected CO₂ was stored in the brine and the remaining oil in the form of stable dissolved CO₂. The experimental results clearly demonstrate the potential of CWI for improving oil recovery as compared with the conventional water flooding (secondary recovery) or as a water-based EOR (enhanced oil recovery) method for watered out reservoirs.