No full-text available
To read the full-text of this research,
you can request a copy directly from the authors.
Carbonate Caprock-Brine-CO2 Interaction: Alteration of Hydromechanical Properties
Abstract
Caprocks play a crucial role in geological storage of CO2 by preventing the escape of CO2 and thus trapping CO2 into underlying porous reservoirs. An evaluation of interaction-induced alteration of hydromechanical properties of caprocks are essential to better assess the leaking risk and injection-induced rock instability, and thus ensuring a long-term viability of geological CO2 storage. We study the changes in nanopores, elastic velocities and mechanical responses of a carbonate caprock due to rock-water/brine-CO2 interaction (CO2 pressure ~ 12 MPa; 50 ℃). Before the interaction, the total and accessible porosities are 1.6% and 0.6%, respectively, as characterized by the Small Angle Neutron Scattering (SANS) technique. SANS results show that the total porosity of the carbonate caprock increases apparently due to rock-brine-CO2 interaction and the increasing rate rises as brine concentration increases (2.2% for 0M NaCl, 2.6% for 1M NaCl, and 2.7% for 4M NaCl). The increase total porosity is due to the dissolution of calcite which tends to enlarge accessible pores (by 0.8%-1.2%) while slightly decrease the inaccessible pores (by 0.1%-0.2%). Under CO2-acidified water environment, P- and S-wave velocities (5536.7 m/s and 2699.7 m/s) of a core sample containing natural fractures decreases by 8.5% and 8.1% respectively, while both P- and S-wave velocities (6074.1 m/s and 3858.8 m/s) for a intact sample show only ~0.5% decreases. The interaction also causes more than 50% degradation of the uniaxial compressive strength for the core sample with natural fractures.
We also conduct simulations of the single-phase creeping flow and two-phase water-CO2 flow in micron-scale natural fractures, as extracted from X-ray Micro-CT images of the core sample. The simulated absolute permeability (2.0×10-12 m2) is much higher than the matrix permeability (6.7×10-20 m2before the interaction; 1.3×10-19 m2after the interaction), as calculated based on the Kozeny–Carman Equation. This indicates that natural fractures provide preferential flow paths for CO2 while flow through caprock matrix can be reasonably neglected. Simulation results also indicate that CO2 preferentially migrates in the natural fractures where there are more inter-connected and permeable channels. The study recommends that more attention should be addressed on interaction-induced alteration of fracture/faults permeability/stability, and its effect on the sealing integrity of carbonate caprocks.
... Tarokh et al. (2020) noted that CO 2 injection increases permeability and porosity while reducing strength and elastic creep rate in low-carbonate reservoir rocks. Sang et al. (2020Sang et al. ( , 2021 highlighted reductions in compressional and shear-wave velocities and uniaxial compressive strength in carbonate caprock is due to CO 2 -brine interactions Liu 2021, 2020). ...
Carbon dioxide (CO2) interacts with rock minerals due to a series of geochemical reactions affecting rock geomechanical properties. These changes in mineralogy, mechanical, and elastic properties weaken the reservoir rock and caprocks. These effects, as consequences, affect the deep saline formation’s mechanical integrity, storage capacity, storage efficiency, and permanence or safety of Carbon Capture and Sequestration (CCS). Generally, CO2 is injected into the rock continuously in supercritical conditions. Different injection schemes and strategies have been proposed to manage these effects; however, the dynamics of CO2 interaction when subjected to these strategies are unknown. This paper provides a comprehensive analysis of the geochemical and geomechanical impacts of supercritical CO2 (scCO2) on rock formations, employing three distinct injection strategies: Continuous scCO2 Injection (CCI), Water- Alternating Gas (scCO2) Injection (WAG), and Simultaneous Water and scCO2 Aquifer Injection (SAI). Through experimental approaches, the study utilizes core samples from Gray Berea sandstone and Indiana limestone to examine short-term and long-term effects on rock elasticity, strength, and mineralogy. This research assesses the alterations in elastic and mechanical properties by employing a suite of coupled experimental approaches, including core flooding, uniaxial compression testing, and X-Ray Diffraction (XRD). Results demonstrate that different scCO2 injection strategies significantly affect the rock mechanical integrity and mineral stability due to acidification, geochemical reaction, sequences of the dissolution and precipitation processes, cyclic effect, and mineral hardness. CCI and WAG demonstrate a more favorable impact on the geomechanical properties of both rock types. Conversely, the SAI strategy proves less beneficial, adversely affecting both elastic and mechanical properties despite occurring geochemical reactions. The study highlights the interplay between mineral dissolution and precipitation processes under varying injection conditions, providing insights into optimizing injection schemes to maximize CO2 storage while maintaining the structural integrity of the geological formations.
... (2) In fact, some scholars have carried out experiments on combined samples before this. Guijie Sang [10] prepared the samples into three forms: powder samples for XRD analysis (300 mesh), four flakes for SANS experiments (thickness: 1 mm), and two cores for ultrasonic testing (diameter: 1 inch); Bing Wei [11] used an average core diameter of 25 mm, a length of 8 mm, and granular samples with a grain size of 0.85 mm to 1.18 mm in the sequestration physical simulation experiment. These simulations can compare the analysis before and after the experiment, but these results lack the analysis of the experimental process. ...
Carbon neutrality has become a global common goal. CCUS, as one of the technologies to achieve carbon neutrality, has received widespread attention from academia and industry. After CO2 enters the formation, under the conditions of formation temperature and pressure, supercritical CO2, formation water, and rock components interact, which directly affects the oil and gas recovery and carbon sequestration efficiency. In this paper, the recent progress on CO2 water–rock interaction was reviewed from three aspects, including (i) the investigation methods of CO2 water–rock interaction; (ii) the variable changes of key minerals, pore structure, and physical properties; and (iii) the nomination of suitable reservoirs for CO2 geological sequestration. The review obtains the following three understandings: (1) Physical simulation and cross-time scale numerical simulation based on formation temperature and pressure conditions are important research methods for CO2 water–rock interaction. High-precision mineral-pore in situ comparison and physical property evolution evaluation are important development directions. (2) Sensitive minerals in CO2 water–rock interaction mainly include dolomite, calcite, anhydrite, feldspar, kaolinite, and chlorite. Due to the differences in simulated formation conditions or geological backgrounds, these minerals generally show the pattern of dissolution or precipitation or dissolution before precipitation. This differential evolution leads to complex changes in pore structure and physical properties. (3) To select the suitable reservoir for sequestration, it is necessary to confirm the sequestration potential of the reservoir and the later sequestration capacity, and then select the appropriate layer and well location to start CO2 injection. At the same time, these processes can be optimized by CO2 water–rock interaction research. This review aims to provide scientific guidance and technical support for shale oil recovery and carbon sequestration by introducing the mechanism of CO2 water–rock interaction, expounding the changes of key minerals, pore structure, and physical properties, and summarizing the sequestration scheme.
A quantitative in situ characterization of the impact of surface
roughness on wettability in porous media is currently lacking.
We use reservoir condition micrometer-resolution X-ray tomography
combined with automated methods for the measurement
of contact angle, interfacial curvature, and surface roughness
to examine fluid/fluid and fluid/solid interfaces inside a porous
material. We study oil and water in the pore space of limestone
from a giant producing oilfield, acquiring millions of measurements
of curvature and contact angle on three millimeter-sized
samples. We identify a distinct wetting state with a broad distribution
of contact angle at the submillimeter scale with a mix
of water-wet and water-repellent regions. Importantly, this state
allows both fluid phases to flow simultaneously over a wide
range of saturation. We establish that, in media that are largely
water wet, the interfacial curvature does not depend on solid surface
roughness, quantified as the local deviation from a plane.
However, where there has been a significant wettability alteration,
rougher surfaces are associated with lower contact angles
and higher interfacial curvature. The variation of both contact
angle and interfacial curvature increases with the local degree of
roughness. We hypothesize that this mixed wettability may also
be seen in biological systems to facilitate the simultaneous flow of
water and gases; furthermore, wettability-altering agents could
be used in both geological systems and material science to design
a mixed-wetting state with optimal process performance.
The effects of CO2-water-rock interactions on the mechanical properties of shale are essential for estimating the possibility of sequestrating CO2 in shale reservoirs. In this study, uniaxial compressive strength (UCS) tests together with an acoustic emission (AE) system and SEM and EDS analysis were performed to investigate the mechanical properties and microstructural changes of black shales with different saturation times (10 days, 20 days and 30 days) in water dissoluted with gaseous/super-critical CO2. According to the experimental results, the values of UCS, Young’s modulus and brittleness index decrease gradually with increasing saturation time in water with gaseous/super-critical CO2. Compared to samples without saturation, 30-day saturation causes reductions of 56.43% in UCS and 54.21% in Young’s modulus for gaseous saturated samples, and 66.05% in UCS and 56.32% in Young’s modulus for super-critical saturated samples, respectively. The brittleness index also decreases drastically from 84.3% for samples without saturation to 50.9% for samples saturated in water with gaseous CO2, to 47.9% for samples saturated in water with super-critical carbon dioxide (SC-CO2). SC-CO2 causes a greater reduction of shale’s mechanical properties. The crack propagation results obtained from the AE system show that longer saturation time produces higher peak cumulative AE energy. SEM images show that many pores occur when shale samples are saturated in water with gaseous/super-critical CO2. The EDS results show that CO2-water-rock interactions increase the percentages of C and Fe and decrease the percentages of Al and K on the surface of saturated samples when compared to samples without saturation.
Gas diffusion in coal is controlled by nano-structure of the pores. The interconnectivity of pores not only determines the dynamics of gas transport in the coal matrix but also influences the mechanical strength. In this study, small angle neutron scattering (SANS) was employed to quantify pore accessibility for two coal samples, one of sub-bituminous rank and the other of anthracite rank. A theoretical pore accessibility model was proposed based on scattering intensities under both vacuum and zero average contrast (ZAC) conditions. The results show that scattering intensity decreases with increasing gas pressure using deuterated methane (CD 4) at low Q values for both coals. Pores smaller than 40 nm in radius are less accessible for anthracite than sub-bituminous coal. On the contrary, when the pore radius is larger than 40 nm, the pore accessibility of anthracite becomes larger than that of sub-bituminous coal. Only 20% of pores are accessible to CD 4 for anthracite and 37% for sub-bituminous coal, where the pore radius is 16 nm. For these two coals, pore accessibility and pore radius follows a power-law relationship.
Significance
In Salah is one of the largest carbon capture and storage projects to date and has played a central role in demonstrating the feasibility of onshore sequestration of CO 2 in deep saline aquifers. The unique field experience at In Salah provides a valuable case study in managing commercial-scale CO 2 injections. In particular, the current work highlights the importance of geomechanics and integrated monitoring in understanding field behavior and managing storage risk.
We apply an accurate numerical scheme to solve for Stokes flow directly on binarized three-dimensional rock images, such as those obtained by micro-CT imaging. The method imposes no-flow conditions exactly at the solid boundaries and employs an algebraic multigrid method to solve for the resultant set of linear equations. We compute the permeability of a range of consolidated and unconsolidated porous rocks; the results are comparable with those obtained using the lattice Boltzmann method and agree with experimental measurements on larger core samples. We show that the Kozeny–Carman equation can over-estimate permeability by a factor of 10 or more, particularly for the more heterogeneous systems studied. We study the existence and size of the representative elementary volume (REV) at lamina scale. We demonstrate that the REV for permeability is larger than for static properties—porosity and specific surface area—since it needs to account for the tortuosity and connectedness of the flow paths. For the carbonate samples, the REV appeared to be larger than the image size. We also study the anisotropy of permeability at the pore scale. We show that the permeability of sandpacks varies by less than 10 % in different directions. For sandstones, permeability changes by 25 % on average. However, the anisotropy of permeability in carbonates can be up to 50 %, indicating the existence of connected pores in one direction which are not connected in another.
Leakage of CO2 into the atmosphere is the most crucial concern for geological storage of anthropogenic CO2. Leakage routes could develop through existing wells and pipelines, but also by natural migration of CO2 rich pore-fluid through the caprock and in fault zones. Therefore, a thorough geological characterization of the prospective formation identifying seal capacity, integrity and possible migration pathways must be performed prior to injection of CO2. A caprock is a low permeable confining layer trapping CO2 stored in a reservoir rock. Although the caprock acts as a seal, its lower boundary will be in contact with CO2 saturated pore water or even pure CO2. Chemical interaction between the pore fluid and the caprock may change its material properties.The aim of this study is to increase our understanding of the interaction between CO2 and caprock, focusing on the microstructural properties of the rock. A flow through cell is used to flood a shale core (40 mm long and 38 mm diameter) with supercritical CO2 at a temperature of 35 ∘C and at pressures above 7.5 MPa. A pressure gradient is applied across the sample to obtain a breakthrough of CO2 in the core. During flooding both axial and radial strain of the core are measured together with the acoustic velocities in the axial direction. The measurements are performed both for the brine saturated core and at various stages during flooding with CO2. The experimental results suggest flow of CO2 along defined pathways within the shale. These pathways are likely to be controlled by the increasing pore pressure at the bottom of the sample which allows reopening of the cracks in the lower part of the sample, allowing CO2 to enter the shale. Flow of CO2 into the cracks in the lower part of the sample is followed by percolation of CO2 in the upper part of the sample where the effective pressure is higher and crack reopening is less likely to occur.
A comprehensive experimental approach has been used to assess the interrelation of CO(2)-mediated chemical reactions and transport properties in pelitic rocks. Sorption values on shale samples (P<20 MPa, 50 degrees C) were high with maximum amounts of similar to 44 kg/t. These capacities did not correlate with the organic carbon content, indicating sorption on and/or reaction with mineral components. Further, crushed shale samples were exposed to CO(2) in the presence of water at 15 MPa and 50 degrees C for different time periods, showing significant changes in mineral composition. Reaction equilibrium was reached within periods of less than a month. Some of the caprock lithotypes could represent a significant sink for CO(2) deposited in the subsurface and could reduce the risk of leakage to the surface.
Gas transport in the shale matrix is controlled by pore structure, which can ultimately influence natural gas production potential and carbon sequestration in shale gas reservoirs. In this study, in situ small-angle neutron scattering (SANS) measurements under methane and CO2 injections were employed to investigate two Marcellus Shale thin section samples cut parallel and perpendicular to the bedding. Marcellus Shale nanopores show intrinsic anisotropy over the detected length scale of 5–2000 Å. Microscopic gas transport could be inhibited due to the decrease of accessible porosity with increasing gas pressure. The degree of inhibition may be higher for CO2 than for methane, and for the direction normal to the bedding than in the bedding direction. In addition, under the condition of liquid CO2, higher porosity reduction for the direction normal to the bedding may insight into nanoscale anisotropic wettability in the shale matrix.
The permeability of a reservoir is a key parameter to determine the pressure response due to production and injection and its concomitant geomechanical response. A fractured reservoir affects the fluid flow by increased permeability, which can be further enhanced by elevated pore pressure. The CO2 storage project at Krechba, In Salah, Algeria, was concluded in 2011, but it provided unique and valuable geomechanical data and still remains an important site to study geomechanical processes. It has previously been shown that fracture injection, i.e. injection of CO2 above fracture pressure, is an important transport mechanism. Here we analyze the pressure response from the many temporary shut-ins during injection to justify a proposed correlation between pressure and permeability (power-law expressions) in the reservoir. The correlation is validated using field-data: pressure response in the reservoir and surface heave from InSAR data. Although the shut-in curves from pressure data at In Salah cannot provide the permeability directly, due to its complex injection history (rate and duration), they can show how the permeability varies with pore pressure and provide evidence of the fracture pressure. A recently developed efficient up-scaled numerical model of fully coupled poroelasticity and two-phase flow that effectively captures the main processes in the high-aspect ratio reservoir of In Salah, allows for the current analysis. This model illustrates that a static geomodel cannot explain the observed pressure response and surface heave, and is subsequently used to fit the parameters in the proposed correlation for the pressure-dependent reservoir permeability. Although there are three injection wells at In Salah, KB501, KB502 and KB503, this study is supported primarily by the data from KB501 and KB503. The correlation for the reservoir permeability provides a good match with both the pressure response in the reservoir and the surface heave above the injection wells, thus illustrating that irreversible and non-elastic processes can be approximated with non-linear material properties. For KB502 the geological setting is much more complicated and the response and behavior around the injection well is strongly depending on the behavior of a large and intersecting fracture zone and it still remains crucial to characterize properties of fault/fracture zones, such as thickness, transmissivity, stiffness and porosity.
Moisture-induced reduction in the strength of shales is one of the primary mechanisms of roof degradation affecting the stability and safety of underground coal mines. The underlying mechanisms of nanoscale matrix-water interactions remains unclear. Thus, an improved understanding of the nanopore structure, and dependent water adsorption and retention behavior of shale is key in defining strength degradation due to seasonal variations in humidity and temperature in underground coal mines. We use small-angle neutron scattering (SANS), low-pressure N2 adsorption (LPNA), and high-pressure mercury intrusion porosimetry (MIP) to characterize the nanopore structure of a fireclay (7F) and four coal mine roof shales (6R, 5A, 6F, H6) from the Illinois basin. The results show that overall distributions of pore volume obtained from SANS, LPNA and MIP techniques agree well between methods and over a wide range of pore size from ~1 nm to ~100 nm. Mercury porosities for the five ordered (7F, 6R, 5A, 6F, H6) samples (7.3%, 7.8%, 8.3%, 12.3%, 4.6%) are higher than the respective N2 porosities (5.0%, 6.3%, 3.8%, 8.2%, 2.5%), as attributed to the dilation of mesopores and compression of the grain skeleton induced by high pressure intrusion of mercury. The SANS porosities for samples 7F, 6R, 5A, 6F (4.0%, 6.2%, 4.1%, 8.8%) are in good agreement with their N2 porosities. Among all tested samples, H6 shale exhibits a relatively high SANS porosity (8.0%) but the lowest N2 (2.5%) and mercury porosities (4.6%). This is attributed to the interlayer micro-pore spaces within montmorillonite, which is detected by SANS but not by the two fluid penetration methods due to the inaccessibility of N2 molecules and mercury. Based on LPNA, larger micropores (1.5–2 nm) and mesopores (2–50 nm) predominantly contribute to the total porosity (~77.8%–87.6%) for the five tested samples.
The water adsorption isotherms are measured by dynamic vapor sorption (DVS) and water retention curves are calculated based on the characterized pore size distribution (PSD) by LPNA and MIP techniques. Pore structures of the five studied samples evidently exert a strong influence on their water adsorption and retention behaviors. Water adsorption capacity correlates positively with total porosity/specific surface area (SSA), with a large proportion of micro/meso-pores resulting in the strong water retention capacity with matric suction reaching ~100–150 MPa for liquid saturation < 3%. Among the studied fireclay/shales, samples with higher retention capacity tend to adsorb more water. Thus, nanopore structure and its impact on water adsorption and retention behavior exert the key controls on shale-water interaction and its implication on strength reduction of roof shales in underground coal mines.
The Bunter Sandstone formation in the UK's southern North Sea has been identified as having the potential to store large volumes of CO 2. Prior to injection, CO 2 is captured with certain amounts of impurities, usually less than 5% vol. The dissolution of these impurities in formation water can cause chemical reactions between CO2 , brine, and rock, which can affect the reservoir quality by altering properties such as permeability. In this study, we explored the effect of CO 2 and impurities (NO 2 , SO 2 , H 2 S) on reservoir permeability by measuring changes in grain size distributions after a prolonged period of 9 months, simulating in situ experimental conditions. It was found that the effects of pure CO 2 and CO 2-H 2 S are relatively small, i.e., CO 2 increased permeability by 5.5% and CO 2-H 2 S decreased it by 5.5%. Also, CO 2-SO 2 slightly decreased permeability by 6.25%, while CO 2-NO 2 showed the most pronounced effect, reducing permeability by 41.6%. The decrease in permeability showed a correlation with decreasing pH of the formation water and this equally correlates with a decrease in geometric mean of the grain diameter. The findings from this study are aimed to be used in future modelling studies on reservoir performance during injection and storage, which also should account for the shifts in boundaries in the CO phase diagram, altering the reservoir properties and affecting the cost of storage.
The safe storage of CO2 in deep reservoir units requires an efficient sealing of the overlaying caprock. The acidic environment caused by the dissolution of CO2 into the pore fluid can induce changes in the microstructure of the material over the long term and might consequently impact its retention capabilities through changes in the pore size and pore connectivity. In the first part of this paper, the impact of a low pH environment on some of the physical properties, such as grain density, void ratio and dominant entrance pore size, and on the retention capacity of a shaly caprock representative material, i.e., Opalinus Clay shale, is investigated by using an HCl solution inducing a pH = 3. The results show that grain density, dominant entrance pore size and void ratio are not significantly affected by the contact with a low pH environment in the considered period. Similar conclusions can be drawn for the retention capacity because the air entry value appears to be the same for treated and non-treated material.
Subsidence and mechanical failure of the caprock are among the issues related to CO2 storage technology. The second part of the paper is dedicated to the analysis of the impact of CO2 injection on the mechanical behaviour of the Opalinus Clay shale. CO2 injection under constant stress conditions with consideration of different overconsolidation ratios is conducted to take into account different loading paths that could be experienced in situ by the caprock. The results show that the injection of CO2 induces the development of volumetric strains of less than 0.1%. Lower strains are measured when the material is overconsolidated; this result can be related to the fact that the material structure is more prone to collapse when it is found in normally consolidated conditions. The observed vertical displacements can be partially caused by desaturation effects induced by the differential pressure between CO2 and pore water, together with double layer effects induced by the CO2 diffusing along the height of the specimen. The impact of CO2 injection on the hydro-mechanical properties of the material is also analysed. The findings suggest that the diffusion of CO2 into the shale does not impact the hydro-mechanical properties of the material because no significant change in oedometric modulus, coefficient of consolidation, secondary compression coefficient, poromechanical parameters and hydraulic conductivity are highlighted after the injection of CO2.
The interaction between carbon dioxide (CO2) and shale during the process of CO2 sequestration and shale gas recovery could significantly affect mechanical properties of the shale. In the current study, we performed experiments on shale samples at 38 °C from the Sichuan Basin aiming at investigating the effects of sub-critical CO2 (SubCO2) and super-critical CO2 (ScCO2) saturation on shale mechanics. Uniaxial compressive strength (UCS) test, X-ray diffraction (XRD) analysis, energy dispersive X-ray spectroscopy (EDX) analysis and acoustic emission (AE) analysis were conducted on the raw and CO2-saturated (4, 6, 8, 12 and 16 MPa) shale samples. Results indicate that SubCO2 saturation (4 and 6 MPa) causes reduction in UCS and elastic modulus (E) of the shale up to 22.9% and 23.1%, respectively. More significantly, ScCO2 saturation (8, 12 and 16 MPa) causes up to 33.9% reductions of UCS and 34.0% reduction of E. This phenomenon can be attributed to a higher adsorptive potential and dissolution capacity of the ScCO2 fluid. In addition, these two parameters gradually vary with increasing saturation pressure: They slowly decrease and reach minimum values at 12 MPa, and then slightly increase as the saturation pressure increases from 12 to 16 MPa because of the compression effect resulted from higher fluid pressure. Results of AE analysis show that, compared with the raw shale samples, cracks of the CO2-saturated samples have a longer closure stage while a shorter stable and unstable crack propagation stage. It reveals that mechanical weakening of the shale is controlled by microscopic damages that resulted from CO2 saturation. Overall, our study confirms that the influence of CO2 saturation on the mechanical characteristics of organic-rich shale samples is closely related to gas pressure and phase state of CO2.
Shale is an increasingly viable source of natural gas and a potential candidate for geologic CO2 sequestration. Understanding the gas adsorption behavior on shale is necessary for the design of optimal gas recovery and sequestration projects. In the present study neutron diffraction and small-angle neutron scattering measurements of adsorbed CO2 in Marcellus Shale samples were conducted on the Near and InterMediate Range Order Diffractometer (NIMROD) at the ISIS Pulsed Neutron and Muon Source, STFC Rutherford Appleton Laboratory along an adsorption isotherm of 22°C and pressures of 25 and 40 bar. Additional measurements were conducted at approximately 22°C and 60°C at the same pressures on the General-Purpose Small-Angle Neutron Scattering (SANS) instrument at Oak Ridge National Laboratory. The structures investigated (pores) for CO2 adsorption range in size from the Å level to ~50 nm. The results indicate that, using the conditions investigated densification or condensation effects occurred in all accessible pores. The data suggest that at 22oC the CO2 has liquid-like properties when confined in pores of around 1 nm radius at pressures as low as 25 bar. Many of the 2.5 nm pores, 70% of 2 nm pores, most of the <1 nm pores, and all pores <0.25 nm, are inaccessible or closed to CO2, suggesting that despite the vast numbers of micropores in shale, the micropores will be unavailable for storage for geologic CO2 sequestration.
Fluid injection–induced seismicity has become increasingly widespread in oil- and gas-producing areas of the United States ( 1 – 3 ) and western Canada. It has shelved deep geothermal energy projects in Switzerland and the United States ( 4 ), and its effects are especially acute in Oklahoma, where seismic hazard is now approaching the tectonic levels of parts of California. Unclear in the highly charged debate over expansion of shale gas recovery has been the role of hydraulic fracturing (fracking) in causing increased levels of induced seismicity. Opponents to shale gas development have vilified fracking as directly responsible for this increase in seismicity. However, this purported causal link is not substantiated; the predominant view is that triggering in the midwestern United States is principally a result of massive reinjection of energy-coproduced wastewaters. On page 1406 of this issue, Bao and Eaton ( 5 ) identify at least one example of seismicity developed from hydraulic fracturing for shale gas in the Alberta Basin.
Carbon capture and storage (CCS), where CO2 is injected into geological formations, has been identified as an important way to reduce CO2 emissions to the atmosphere. While there are several aquifers worldwide into which CO2 has been injected, there is still uncertainty in terms of the long-term fate of CO2. Simulation studies have proposed capillary trapping - where the CO2 is stranded as pore-space droplets surrounded by water - as a rapid way to secure safe storage. However, there has been no direct evidence of pore-scale trapping. We imaged trapped super-critical CO2 clusters in a sandstone at elevated temperatures and pressures, representative of storage conditions using computed micro-tomography (μ-CT) and measured the distribution of trapped cluster size. The clusters occupy 25% of the pore space. This work suggests that locally capillary trapping is an effective, safe storage mechanism in quartz-rich sandstones.
Supercritical CO2 (SC-CO2) fluid is capable of extracting organic matter in shale and dissolving the primary pores and fractures. To determine how well SC-CO2 can influence the microstructure at different traditions, shale samples were treated at different times, pressures and temperatures with SC-CO2. The results showed that crystal water was released from clay mineral in the shale after treatment. The specific surface area and porosity of the shale increased with time and pressure; pressure was significant at transforming shale's microstructure. Under low pressure, SC-CO2 treatment of shale at different temperatures does not have a clear influence on the microstructure of the shale. The porosity had a linear relationship with the specific surface area. The mechanism of changing the microstructure of the shale by SC-CO2 is as follows: as treatment time, pressure and temperature increase, the SC-CO2 fluid increases its density and dissolving capability and can extract more organic matter from the pores and fractures in shale. Concurrently, it increases the number of shale gas seepage channels and widens them. This research lays a foundation for efficient shale gas exploitation with SC-CO2 fluid.
Shale caprock integrity is critical in ensuring that subsurface injection and storage of anthropogenic carbon dioxide (CO2) is permanent. The interaction of clay-rich rock with aqueous CO2 under dynamic conditions requires characterization at the nanoscale level due to the low-reactivity of clay minerals. Geochemical mineral-fluid interaction can impact properties of shale rocks primarily through changes in pore geometry/connectivity. The experimental work reported in this paper applied specific analytical techniques in investigating changes in surface/near-surface properties of crushed shale rocks after exposure (by flooding) to CO 2-brine for a time frame ranging between 30 days and 92 days at elevated pressure and fractional flow rate. The intrinsically low permeability in shale may be altered by changes in surface properties as the effective permeability of any porous medium is largely a function of its global pore geometry. Diffusive transport of CO2 as well as carbon accounting could be significantly affected over the long term. The estimation of permeability ratio indicated that petrophysical properties of shale caprock can be doubled.
Carbon sequestration technology requires injection and storage of large volumes of carbon dioxide (CO2) in subsurface geological formations. Shale caprock which constitutes more than 60% of effective seals for geologic hydrocarbon bearing formations are therefore of considerable interest in underground CO2 storage into depleted oil and gas formations. This study investigated experimentally shale caprock's geophysical and geochemical behavior when in contact with aqueous CO2 over a long period of time. The primary concern is a potential increase in hydraulic conductivity of clay-rich rocks as a result of acidic brine- rock minerals geochemical interactions. Both, mineral reactivity and microstructural characteristics, such as presence and development of fracture networks, may lead to potential leakage of CO2 to the surface or underground water sources. Bulk XRD analysis and Transmitted Light Microscopic imaging results acquired on six shale samples showed some heterogeneity in the shale caprock but the mineralogy and particle orientation are similar reflecting the same depositional environment. The XRD analyses indicated the presence of quartz, feldspar, albite, and bulk clays (muscovite, chlorite, and kaolinite). Some microheterogeneity in the depositional distribution of the shale minerals was observed. Capillary entry pressure using CO2-brine fluid revealed high seal strength. Nano-pores constituted the controlling pore size but the presence of blind and unconnected micropores might degrade or improve seal capacity in the long term. The geochemical buffer strength of shale appears to be durable. Inductively Coupled Plasma Spectroscopy showed positive mineralogical alterations with slow reactive transport of dissolved CO2 as seal enhancing mechanism supporting predicted simulation studies. Useful geochemical and geophysical data on the regional shale caprock were obtained for coupled predictive modeling of seal integrity in CO2 sequestration.
The frictional behavior of anhydrite-bearing faults is of interest to a) the safety and effectiveness of CO2 storage in anhydrite-capped reservoirs, b) seismicity induced by hydrocarbon production, and c) natural seismicity nucleated in evaporite formations. We performed direct shear experiments on simulated anhydrite fault gouges, at a range of temperatures (80-150 °C) and sliding velocities (0.2-10μms−1), under a fixed effective normal stress of 25 MPa. Four types of experiments were conducted: 1) dry experiments, 2) experiments pressurized with water, 3) dry experiments pressurized with CO2, and 4) wet experiments pressurized with CO2. Fluid pressures of 15 MPa were used when applied. Over the temperature range investigated water-saturated samples were found to be up to 15% frictionally weaker than dry equivalents. Wet samples containing CO2 were also up to 15% weaker than CO2-free equivalents. Dry sample strength without CO2 was independent of temperature, whereas wet samples without CO2 strengthened 10% from 80 to 150 °C. Samples containing CO2 weakened by 4% (dry) and 10% (wet) from 80 to 150 °C. Under the P-T conditions investigated, only dry anhydrite fault gouge showed velocity-weakening behavior above 120 °C, required for faults to potentially generate earthquakes. Assuming natural fault gouges are wet in-situ, seismicity is unlikely to nucleate in anhydrite-rich faults, though the presence of dolomite or reaction-produced calcite may change seismic potential. CO2 penetration into wet anhydrite-rich faults may trigger slip on critically stressed faults due to the observed short-term CO2 weakening effects (excluding possible formation of secondary minerals), but is not expected to influence slip stability.
Shale reservoirs are becoming an increasingly important source of oil and natural gas supply and a potential candidate for CO 2 sequestration. Understanding the pore morphology in shale may provide clues to making gas extraction more efficient and cost-effective. The porosity of Cretaceous shale samples from Alberta, Canada, collected from different depths with varying mineralogical compositions, has been investigated by small-and ultrasmall-angle neutron scattering. The samples come from the Second White Specks and Belle Fourche formations, and their organic matter content ranges between 2 and 3%. The scattering length density of the shale specimens has been estimated using the chemical composition of the different mineral components. Scattering experiments reveal the presence of fractal and non-fractal pores. It has been shown that the porosity and specific surface area are dominated by the contribution from meso-and micropores. The fraction of closed porosity has been calculated by comparing the porosities estimated by He pycnometry and scattering techniques. Although there is no correlation between total porosity and mineral components, a strong correlation has been observed between closed porosity and major mineral components in the studied specimens.
The importance of geomechanics—including the potential for faults to reactivate during large-scale geologic carbon sequestration operations—has recently become more widely recognized. However, notwithstanding the potential for triggering notable (felt) seismic events, the potential for buoyancy-driven CO2 to reach potable groundwater and the ground surface is actually more important from public safety and storage-efficiency perspectives. In this context, this work extends the previous studies on the geomechanical modeling of fault responses during underground carbon dioxide injection, focusing on the short-term integrity of the sealing caprock, and hence on the potential for leakage of either brine or CO2 to reach the shallow groundwater aquifers during active injection. We consider stress/strain-dependent permeability and study the leakage through the fault zone as its permeability changes during a reactivation, also causing seismicity. We analyze several scenarios related to the volume of CO2 injected (and hence as a function of the overpressure), involving both minor and major faults, and analyze the profile risks of leakage for different stress/strain-permeability coupling functions. We conclude that whereas it is very difficult to predict how much fault permeability could change upon reactivation, this process can have a significant impact on the leakage rate. Moreover, our analysis shows that induced seismicity associated with fault reactivation may not necessarily open up a new flow path for leakage. Results show a poor correlation between magnitude and amount of fluid leakage, meaning that a single event is generally not enough to substantially change the permeability along the entire fault length. Consequently, even if some changes in permeability occur, this does not mean that the CO2 will migrate up along the entire fault, breaking through the caprock to enter the overlying aquifer.
The present study reports a numerical investigation of water and CO2 (carbon dioxide) flooding at the pore scale of a porous medium. We use high resolution micro-computed tomography (micro-CT) images of Berea sandstone core to obtain the pore geometry. The numerical solution used for the simulation was carried out by a finite element based software package. Level Set method is used to determine the position of the interface between two immiscible fluids when oil is displaced by water and CO2, respectively. The present formulation is validated against single-phase flow through the porous structure. It is found that, fluid flow inside the pore space takes place through preferential inlet and outlet pores. For two-phase flow, it is observed that continuous displacement of oil occurs during water flooding but CO2 is able to displace oil at certain locations in the pores. Also, the separation of flow front is observed in the case of CO2 flooding. A quantitative comparison of the results obtained in two types of flooding simulations suggests that water displaces a higher volume of oil than CO2 in the time period for which the simulations are performed.
A study was initiated to investigate the effects of gaseous and super-critical carbon dioxide (CO2) adsorption on bituminous coal strength. Uniaxial compressive strength (UCS) experiments were conducted on bituminous coal samples from the southern Sydney Basin saturated with gaseous CO2, super-critical CO2 and N2 at various pressures, and a temperature 33 °C. According to the results, gaseous CO2 adsorption causes the UCS and Young’s modulus of the bituminous coal to be reduced by up to 53% and 36%, respectively. Super-critical CO2 adsorption causes more significant modifications to the mechanical properties of the bituminous coal, resulting in 40% greater UCS strength reduction and 100% greater Young’s modulus reduction compared to gaseous CO2 adsorption. The greater influence of super-critical CO2 on the UCS of the bituminous coal is thought to be related to the greater adsorptive potential and coal swelling produced for super-critical CO2. The more significant influence of super-critical CO2 on the Young’s modulus of the bituminous coal is thought to relate to the greater dissolution (and thus coal plasticization) potential of the super-critical CO2. N2 saturation was not observed to have any significant effect on the mechanical properties of the bituminous coal. Acoustic emission data collected during testing support of the notion that the coal mass natural cleat system largely contributes to the susceptibility of coal to mechanical weakening by CO2 adsorption. The results show that the mechanical influence of CO2 adsorption on coal is highly dependent on the phase state of the CO2.
Small-angle and ultra-small-angle neutron scattering (SANS and USANS), low-pressure adsorption (N2 and CO2), and high-pressure mercury intrusion measurements were performed on a suite of North American shale reservoir samples providing the first ever comparison of all these techniques for characterizing the complex pore structure of shales. The techniques were used to gain insight into the nature of the pore structure including pore geometry, pore size distribution and accessible versus inaccessible porosity. Reservoir samples for analysis were taken from currently-active shale gas plays including the Barnett, Marcellus, Haynesville, Eagle Ford, Woodford, Muskwa, and Duvernay shales.
Two Pennsylvanian coal samples (Spr326 and Spr879-IN1) and two Upper Devonian-Mississippian shale samples (MM1 and MM3) from the Illinois Basin were studied with regard to their porosity and pore accessibility. Shale samples are early mature stage as indicated by vitrinite reflectance (Ro) values of 0.55% for MM1 and 0.62% for MM3. The coal samples studied are of comparable maturity to the shale samples, having vitrinite reflectance of 0.52% (Spr326) and 0.62% (Spr879-IN1). Gas (N2 and CO2) adsorption and small-angle and ultrasmall-angle neutron scattering techniques (SANS/USANS) were used to understand differences in the porosity characteristics of the samples. The results demonstrate that there is a major difference in mesopore (2–50 nm) size distribution between the coal and shale samples, while there was a close similarity in micropore (<2 nm) size distribution. Micropore and mesopore volumes correlate with organic matter content in the samples. Accessibility of pores in coal is pore-size specific and can vary significantly between coal samples; also, higher accessibility corresponds to higher adsorption capacity. Accessibility of pores in shale samples is low.
Containment security of geologically stored CO2 is improved substantially through trapping mechanisms. Therefore, to simulate the potential viability of a storage site, it is necessary to account for immobilization processes. In this paper, we focus on a quantitative measure for the contribution of hysteresis in reducing plume transport, with particular emphasis on capillary-pressure-induced migration retardation. Rocks with large pore-body-to-throat-size ratio, or a low permeability, are the best candidates for this mechanism to be operative.
In the present work, a self-consistent relative permeability and capillary pressure hysteresis model is incorporated within a simulator. With this model, it is possible to compare and contrast hysteresis-induced retardation to other mechanisms of trapping. The self-consistent parameterization of all of the transport properties is used to quantify sensitivity compactly. The sensitivity of the CO2-plume shape and the amount of CO2 trapped to the strength of the capillary pressure hysteresis is also described.
Simulated results show that the CO2-plume shapes with and without capillary pressure hysteresis are significantly different. As expected, capillary pressure hysteresis retards the buoyant transport of the CO2 plume. Although a portion of the CO2 is connected, and therefore not residual, the plume remains immobile for all practical purposes. Also, because of the decreased driving potential, gravity tonguing below the caprock is reduced in comparison to the case without capillary pressure hysteresis, thus suggesting enhanced storage efficiency. However, the total dissolution of CO2 in saline water is reduced because of the reduced contact area with the brine. Thus, one mechanism of containment is offset by the other.
Inclusion of accurate hysteresis models is important for qualifying storage sites constrained by spatial-domain limits. It is anticipated that site-acceptability criteria would change as a result of this study, thereby impacting risk evaluation.
Mineral precipitation and dissolution in subsurface environments can have a dramatic effect on the permeability and porosity of formations and hence exert a feedback on the fluid flow. Many parameters influence mineral precipitation and dissolution, but the one addressed here concerns precipitation or dissolution that arises from mixing of saturated solutions with different salinities (or temperatures). This effect arises because the solubility of a mineral in solution depends non-linearly on salinity (or temperature). Examples include calcite precipitation and/or dissolution resulting from mixing of fresh and saline waters in coastal carbonate formations, or the precipitation of anhydrite (CaSO4) upon mixing of hydrothermal solutions with seawater. The present preliminary study focuses on flow, precipitation and dissolution along a salt water-fresh water interface in a porous medium. Emphasis is placed on the quantitative evolution of the flow field in both time and space, under different flow regimes and chemical compositions. Flow experiments were performed in a 2D flow cell packed with 1 mm diameter glass beads. Salt water and fresh water, both saturated with CaCO3, were injected simultaneously at equal flow rates at two inlets. The effluent acid from the outlets was collected and analyzed for Ca2+ concentration, in order to calculate precipitated/dissolved calcium carbonate (based on molar volume of the component) during the experiments. The equilibrium concentration of dissolved calcium carbonate in salt water was found to be higher than in fresh water. Calcium carbonate tended to precipitate in the mixing zone because the resulting mixture became supersaturated. The precipitation rate of calcium carbonate, and the forms of precipitation and subsequent dissolution, are highly dependent on the flow rate, the chemical composition of the injected fluids, and the salinity gradient.
Claystone caprocks are often the ultimate seal for CO2 underground storage when residual CO2 gas reaches the reservoir top due to buoyancy. Permeability changes of a fractured claystone due to seepage of CO2-enriched brine and water vapor-saturated CO2 gas was investigated, combining percolation experiments with molecular modelling. A flow-through reactor was used to inject, at 25 °C, a cyclic flow of water vapour-saturated CO2 gas and CO2-enriched brine through fractured claystone samples mainly composed of calcite, silica and clay minerals (45 %, dominated by kaolinite). Results show that brine flow induces a large porosity increase (up to 50 %) in the vicinity of the fracture due to dissolution of calcite and silica, while permeability remains unchanged. Conversely, cyclic flows of CO2-brine and CO2-gas increase the fracture aperture after each gas flow period, producing a progressive increase of the sample permeability (Andreani et al., 2008). Molecular modelling (Jouanna et al., 2010; Pèpe et al., 2010), realized via the ab initio and molecular mechanics code GenMol (Pèpe, 2010), predicts the attraction/repulsion effort at the kaolinite/brine/kaolinite contact between clay particles. Two numerical experiments predicts decohesion for a pH value of the interstitial brine between 7.5 (equilibrium fluid) and 3.2 (CO2-enriched brine). Refined studies are necessary to precise the exact critical pH value. In conclusion, the hydraulic aperture of the fracture is controlled by a twofold mechanism. Firstly, calcite and silica grains contained in claystone are dissolved by the CO2-brine flow, thus creating a porous altered layer on the fracture surface. Permeability of this altered zone is not significantly changed because clay particles (volume fraction > 0.4) form a continuous framework. Then, when the CO2-gas phase enters the porous structure, strong chemical gradients are set up at the fluid-gas interface due to diffusion of CO2, causing a decrease in pH within the interstitial fluid. This, in turn, decreases the attraction forces linking the clay particles that loose cohesion and are subsequently removed by the next CO2-brine flow. This scenario shows that, for the studied claystone, the sole seepage of CO2-brine through a fracture would not alter its permeability, while cycling flow of CO2-gas and CO2-brine increases fracture aperture and consequently decreases the caprock seal capacity. Andreani, M., Gouze, P., Luquot, L. & Jouanna, P. (2008). Geophy. Res. Letter 25 L14404. Jouanna, P., Pèpe, G., Dweik, J., Gouze, P. (2010). J. Crystal Growth, doi:10.1016/j.jcrysgro.2010.08.009 (in press). Pèpe, G., Dweik, J., Jouanna, P., Gouze,P., Andreani, M., Luquot, L. (2010). J. Crystal Growth, doi:10.1016/j.jcrysgro.2010.08.012 (in press). Pèpe, G. (2010). http://www.cinam.univ-mrs.fr/pepe
Before implementing CO2 storage on a large scale its viability regarding injectivity, containment and long-term safety for both humans and environment is crucial. Assessing CO2–rock interactions is an important part of that as these potentially affect physical properties through highly coupled processes. Increased understanding of the physical impact of injected CO2 during recent years including buoyancy driven two-phase flow and convective mixing elucidated potential CO2 pathways and indicated where and when CO2–rock interactions are potentially occurring. Several areas of interactions can be defined: (1) interactions during the injection phase and in the near well environment, (2) long-term reservoir and cap rock interactions, (3) CO2–rock interactions along leakage pathways (well, cap rock and fault), (4) CO2–rock interactions causing potable aquifer contamination as a consequence of leakage, (5) water–rock interactions caused by aquifer contamination through the CO2 induced displacement of brines and finally engineered CO2–rock interactions (6). The driving processes of CO2–rock interactions are discussed as well as their potential impact in terms of changing physical parameters. This includes dissolution of CO2 in brines, acid induced reactions, reactions due to brine concentration, clay desiccation, pure CO2–rock interactions and reactions induced by other gases than CO2. Based on each interaction environment the main aspects that are possibly affecting the safety and/or feasibility of the CO2 storage scheme are reviewed and identified. Then the methodologies for assessing CO2–rock interactions are discussed. High priority research topics include the impact of other gaseous compounds in the CO2 stream on rock and cement materials, the reactivity of dry CO2 in the absence of water, how CO2 induced precipitation reactions affect the pore space evolution and thus the physical properties and the need for the development of coupled flow, geochemical and geomechanical models.
Compressional- and shear-wave velocities were measured in the laboratory in seven sandstones (porosities ranging from 6 to 29%) and one unconsolidated sand (37% porosity) saturated with n-hexadecane (C16H34) both before and after CO2 flooding. CO2 flooding decreased compressional-wave velocities significantly, while shear-wave velocities were less affected. The magnitude of these effects was found to depend on confining and pore pressures, temperature, and porosities of the rocks. The experimental results and theoretical analysis show that the decreases in compressional-wave velocities caused by CO2 flooding may be seismically resolvable in situ. Therefore, seismic—especially high-frequency, high-resolution seismic—methods may be useful in mapping and locating CO2 zones, tracking movements of CO2 fronts, and monitoring flooding processes in reservoirs undergoing CO2 flooding.
To determine the possible influence of CO2 on the pore structure and mineralogy of the New Albany Shale (Devonian–Mississippian), experiments were conducted utilizing Indiana shale samples of varying total organic carbon content under various conditions. After the shale samples were heated to as high as 150°C in Teflon-lined high-pressure reaction cells with either distilled water or NaCl brine and CO2, the reaction products were characterized by mesopore and micropore analysis, X-ray diffraction and scanning electron microscope analysis of the shale residue, and fluid chemistry analysis of the reactant brine. Results from CO2-saturated shale and distilled water showed no changes in shale pore structure relative to shale samples without CO2 surface saturation.A second series of experiments was run at 80°C, using 50,000ppm NaCl brine, 60-mesh ground shale (2:1 by mass), and varying amounts of solid CO2 (dry ice). The pressure in the reaction cells was controlled by the partial pressure of CO2 and ranged from 100 to 3500psi (0.69 to 24.13MPa). Post-reaction brine samples showed up to thousands of ppm of K, Mg, and Ca in solution. The concentration of Ca and Mg in the brine tended to increase in proportion to the increasing partial pressure of CO2. The same experiments using chips of shale from the New Albany Shale showed lower concentrations of the cations in solution, but displayed a similar pattern of increasing Ca and Mg with increasing CO2 pressure. Scanning electron microscope examination of the shale chips confirmed the dissolution of carbonate-mineralized biogenic structures in the shale.
We perform a novel set of laboratory experiments that depict CaCO3 precipitation upon mixing between saturated fresh and salt water solutions, thus simulating mixing diagenesis in a coastal aquifer. The experimental results are shown to agree with the result predicted from a relatively simple mathematical model, thus suggesting that the model may be extrapolated to natural environments. Application of the model to the coastal aquifer of Mallorca, Spain indicates calcite precipitation is reducing porosity at a rate of ∼13% per 10,000 years. Consideration of precipitation processes can thus explain contradictory interpretations of natural evolution in carbonate formations.
Contrast-matching ultrasmall-angle neutron scattering (USANS) and small-angle neutron scattering (SANS) techniques were used for the first time to determine both the total pore volume and the fraction of the pore volume that is inaccessible to deuterated methane, CD{sub 4}, in four bituminous coals in the range of pore sizes between {approx}10 {angstrom} and {approx}5 {micro}m. Two samples originated from the Illinois Basin in the U.S.A., and the other two samples were commercial Australian bituminous coals from the Bowen Basin. The total and inaccessible porosity were determined in each coal using both Porod invariant and the polydisperse spherical particle (PDSP) model analysis of the scattering data acquired from coals both in vacuum and at the pressure of CD{sub 4}, at which the scattering length density of the pore-saturating fluid is equal to that of the solid coal matrix (zero average contrast pressure). The total porosity of the coals studied ranged from 7 to 13%, and the volume of pores inaccessible to CD{sub 4} varied from {approx}13 to {approx}36% of the total pore volume. The volume fraction of inaccessible pores shows no correlation with the maceral composition; however, it increases with a decreasing total pore volume. In situ measurements of the structure of one coal saturated with CO{sub 2} and CD{sub 4} were conducted as a function of the pressure in the range of 1-400 bar. The neutron scattering intensity from small pores with radii less than 35 {angstrom} in this coal increased sharply immediately after the fluid injection for both gases, which demonstrates strong condensation and densification of the invading subcritical CO{sub 2} and supercritical methane in small pores.
CO(2) capture and geologic sequestration is one of the most promising options for reducing atmospheric emissions of CO(2). Its viability and long-term safety, which depends on the caprock's sealing capacity and integrity, is crucial for implementing CO(2) geologic storage on a commercial scale. In terms of risk, CO(2) leakage mechanisms are classified as follows: diffusive loss of dissolved gas through the caprock, leakage through the pore spaces after breakthrough pressure has been exceeded, leakage through faults or fractures, and well leakage. An overview is presented in which the problems relating to CO(2) leakage are defined, dominant factors are considered, and the main results are given for these mechanisms, with the exception of well leakage. The overview includes the properties of the CO(2)-water/brine system, and the hydromechanics, geophysics, and geochemistry of the caprock-fluid system. In regard to leakage processes, leakage through faults or fracture networks can be rapid and catastrophic, whereas diffusive loss is usually low. The review identifies major research gaps and areas in need of additional study in regard to the mechanisms for geologic carbon sequestration and the effects of complicated processes on sealing capacity of caprock under reservoir conditions.
A direct measurement of the pH of water in contact with supercritical CO2 was made by observing the spectra of a pH indicator with a UV-vis spectrophotometer. The pH was analyzed under pressures of 70-200 atm and temperatures of 25-70 degrees C, The measured pH varied from 2.80 to 2.95, and relative standard deviations of <1.5% were achieved, The effects of pH on the efficiency of supercritical fluid extraction of metals and ionizable organic species in water-containing systems are discussed.
Geologic storage of CO(2) requires that the caprock sealing the storage rock is highly impermeable to CO(2). Swelling clays, which are important components of caprocks, may interact with CO(2) leading to volume change and potentially impacting the seal quality. The interactions of supercritical (sc) CO(2) with Na saturated montmorillonite clay containing a subsingle layer of water in the interlayer region have been studied by sorption and neutron diffraction techniques. The excess sorption isotherms show maxima at bulk CO(2) densities of ≈0.15 g/cm(3), followed by an approximately linear decrease of excess sorption to zero and negative values with increasing CO(2) bulk density. Neutron diffraction experiments on the same clay sample measured interlayer spacing and composition. The results show that limited amounts of CO(2) are sorbed into the interlayer region, leading to depression of the interlayer peak intensity and an increase of the d(001) spacing by ca. 0.5 Å. The density of CO(2) in the clay pores is relatively stable over a wide range of CO(2) pressures at a given temperature, indicating the formation of a clay-CO(2) phase. At the excess sorption maximum, increasing CO(2) sorption with decreasing temperature is observed while the high-pressure sorption properties exhibit weak temperature dependence.
The Mount Simon sandstone and Eau Claire shale formations are target storage and cap rock formations for the Illinois Basin-Decatur Geologic Carbon Sequestration Project. We reacted rock samples with brine and supercritical CO(2) at 51 °C and 19.5 MPa to access the reactivity of these formations at storage conditions and to address the applicability of using published kinetic and thermodynamic constants to predict geochemical alteration that may occur during storage by quantifying parameter uncertainty against experimental data. Incongruent dissolution of iron-rich clays and formation of secondary clays and amorphous silica will dominate geochemical alterations at this CO(2) storage site in CO(2)-rich brines. The surrogate iron-rich clay in the model required significant adjustments to its thermodynamic constants and inclusion of incongruent reaction terms to capture the change in solution composition under acid CO(2) conditions. This result emphasizes the need for experiments that constrain the conceptual geochemical model, calibrate mean parameter values, and quantify parameter uncertainty in reactive-transport simulations that will be used to estimate long-term CO(2) trapping mechanisms and changes in porosity and permeability.
PRINSAS is a Windows program that takes as input raw (post-reduction) small-angle neutron and small-angle X-ray scattering (SANS and SAXS) data obtained from various worldwide facilities, displays the raw curves in interactive log–log plots, and allows processing of the raw curves. Separate raw SANS and ultra-small-angle neutron scattering (USANS) curves can be combined into complete scattering curves for an individual sample. The combined curves can be interpreted and information inferred about sample structure, using built-in functions. These have been tailored for geological samples and other porous media, and include the ability to obtain an arbitrary distribution of scatterer sizes, the corresponding specific surface area of scatterers, and porosity (when the scatterers are pores), assuming spherical scatterers. A fractal model may also be assumed and the fractal dimension obtained. A utility for calculating scattering length density from the component oxides is included in the program.
1] We simulate two-fluid-phase flow at the pore scale using a lattice Boltzmann (LB) approach. Using a parallel processing version of the Shan-Chen model that we developed, we simulate a set of ideal two-fluid systems and a model two-fluid-phase porous medium system comprised of a synthetic packing with a relatively uniform distribution of spheres. We use the set of ideal two-phase systems to validate the approach and provide parameter information, which we then use to simulate a sphere-pack system. The sphere-pack system is designed to mimic laboratory experiments conducted to evaluate the hysteretic capillary pressure saturation relation for a system consisting of water, tetrachloroethylene, and a glass bead porous medium. Good agreement is achieved between the measured hysteretic capillary pressure saturation relations and the LB simulations when comparing entry pressure, displacement slopes, irreducible saturation, and residual entrapment. Our results further show that while qualitatively similar results are obtained when comparing systems consisting of 1200 spheres and 150 spheres, there is a significant difference between these two levels, suggesting a lower bound on the size of a representative elementary volume.