Permeability evolution in sorbing media: analogies between organic‐rich shale and coal

Shale gas reservoirs like coalbed methane (CBM) reservoirs are promising targets for geological sequestration of carbon dioxide (CO₂). However, the evolution of permeability in shale reservoirs on injection of CO₂ is poorly understood unlike CBM reservoirs. In this study, we report measurements of permeability evolution in shales infiltrated separately by nonsorbing (He) and sorbing (CO₂) gases under varying gas pressures and confining stresses. Experiments are completed on Pennsylvanian shales containing both natural and artificial fractures under nonpropped and propped conditions. We use the models for permeability evolution in coal (Journal of Petroleum Science and Engineering, Under Revision) to codify the permeability evolution observed in the shale samples. It is observed that for a naturally fractured shale, the He permeability increases by approximately 15% as effective stress is reduced by increasing the gas pressure from 1 MPa to 6 MPa at constant confining stress of 10 MPa. Conversely, the CO₂ permeability reduces by a factor of two under similar conditions. A second core is split with a fine saw to create a smooth artificial fracture and the permeabilities are measured for both nonpropped and propped fractures. The He permeability of a propped artificial fracture is approximately 2‐ to 3fold that of the nonpropped fracture. The He permeability increases with gas pressure under constant confining stress for both nonpropped and propped cases. However, the CO₂ permeability of the propped fracture decreases by between one‐half to one‐third as the gas pressure increases from 1 to 4 MPa at constant confining stress. Interestingly, the CO₂ permeability of nonpropped fracture increases with gas pressure at constant confining stress. The permeability evolution of nonpropped and propped artificial fractures in shale is found to be similar to those observed in coals but the extent of permeability reduction by swelling is much lower in shale due to its lower organic content. Optical profilometry is used to quantify the surface roughness. The changes in surface roughness indicate significant influence of proppant indentation on fracture surface in the shale sample. The trends of permeability evolution on injection of CO₂ in coals and shales are found analogous; therefore, the permeability evolution models previously developed for coals are adopted to explain the permeability evolution in shales.     

Gas breakthrough pressure for hydrocarbon reservoir seal rocks: implications for the security of long-term CO2 storage in the Weyburn field

This paper reports a laboratory study of the gas breakthrough pressure for different gas/liquid systems in the Mississippian‐age Midale Evaporite. This low‐permeability rock formation is the seal rock for the Weyburn Field in southeastern Saskatchewan, Canada, where CO₂ is being injected into an oil reservoir for enhanced recovery and CO₂ storage. A technique for experimentally determining CO₂ breakthrough pressure at reservoir conditions is presented. Breakthrough pressures for N₂, CO₂ and CH₄ were measured with the selected seal‐rock samples. The maximum breakthrough pressure is over 30 MPa for N₂ and approximately 21 MPa for CO₂. The experimental results demonstrate that the Weyburn Midale Evaporite seal rock is of high sealing quality. Therefore, the Weyburn reservoir and Midale Beds can be used as a CO₂ storage site after abandonment. The measured results also show that the breakthrough pressure of a seal rock for a gas is nearly proportional to the interfacial tension of the gas/brine system. The breakthrough pressure of a CO₂/brine system is significantly reduced compared with that of a CH₄/brine system because of the much lower interfacial tension of the former. This implies that a seal rock that seals the original gas in a gas reservoir or an oil reservoir with a gas cap may not be tight enough to seal the injected CO₂ if the pressure during or after CO₂ injection is the same or higher than the original reservoir pressure. Therefore, reevaluation of the breakthrough pressure of seal rocks for a given reservoir is necessary and of highest priority once it is chosen as a CO₂ storage site.     

Post‐CO2 injection alteration of the pore network and intrinsic permeability tensor for a Permo‐Triassic sandstone

The aim of this study was to determine the process–structure–property relationships between the pre‐ and post‐CO₂ injection pore network geometry and the intrinsic permeability tensor for samples of core from low‐permeability Lower Triassic Sherwood Sandstone, UK. Samples were characterised using SEM‐EDS, XRD, MIP, XRCT and a triaxial permeability cell both before and after a three‐month continuous‐flow experiment using acidic CO₂‐rich saline fluid. The change in flow properties was compared to those predicted by pore‐scale numerical modelling using an implicit finite volume solution to the Navier–Stokes equations. Mass loss and increased secondary porosity appeared to occur primarily due to dissolution of intergranular cements and K‐feldspar grains, with some associated loss of clay, carbonate and mudstone clasts. This resulted in a bulk porosity increase from 18 to 25% and caused a reduction in mean diameter of mineral grains with an increase in apparent pore wall roughness, where the fractal dimension, D_f, increased from 1.68 to 1.84. All significant dissolution mass loss occurred in pores above c. 100 μm mean diameter. Relative dilation of post‐treatment pore area appeared to increase in relation to initial pore area, suggesting that the rate of dissolution mass loss had a positive relationship with fluid flow velocity; that is, critical flow pathways are preferentially widened. Variation in packing density within sedimentary planes (occurring at cm‐scale along the ‐z plane) caused the intrinsic permeability tensor to vary by more than a factor of ten. The bulk permeability tensor is anisotropic having almost equal value in ‐z and ‐y planes but with a 68% higher value in the ‐x plane (parallel to sedimentary bedding planes) for the pretreated sample, reducing to only 30% higher for the post‐treated sample. The intrinsic permeability of the post‐treatment sample increased by one order of magnitude and showed very close agreement between the modelled and experimental results.     

Gas breakthrough experiments on pelitic rocks: comparative study with N2, CO2 and CH4

The capillary‐sealing efficiency of intermediate‐ to low‐permeable sedimentary rocks has been investigated by N₂, CO₂ and CH₄ breakthrough experiments on initially fully water‐saturated rocks of different lithological compositions. Differential gas pressures up to 20 MPa were imposed across samples of 10–20 mm thickness, and the decline of the differential pressures was monitored over time. Absolute (single‐phase) permeability coefficients (k_abs), determined by steady‐state fluid flow tests, ranged between 10^?22 and 10^?15 m². Maximum effective permeabilities to the gas phase k_eff(max), measured after gas breakthrough at maximum gas saturation, extended from 10^?26 to 10^?18 m². Because of re‐imbibition of water into the interconnected gas‐conducting pore system, the effective permeability to the gas phase decreases with decreasing differential (capillary) pressure. At the end of the breakthrough experiments, a residual pressure difference persists, indicating the shut‐off of the gas‐conducting pore system. These pressures, referred to as the ‘minimum capillary displacement pressures’ (P_d), ranged from 0.1 up to 6.7 MPa. Correlations were established between (i) absolute and effective permeability coefficients and (ii) effective or absolute permeability and capillary displacement pressure. Results indicate systematic differences in gas breakthrough behaviour of N₂, CO₂ and CH₄, reflecting differences in wettability and interfacial tension. Additionally, a simple dynamic model for gas leakage through a capillary seal is presented, taking into account the variation of effective permeability as a function of buoyancy pressure exerted by a gas column underneath the seal.     

Wettability alteration of caprock minerals by carbon dioxide

One of the critical factors that control the efficiency of CO₂ geological storage process in aquifers and hydrocarbon reservoirs is the capillary‐sealing potential of the caprock. This potential can be expressed in terms of the maximum reservoir overpressure that the brine‐saturated caprock can sustain, i.e. of the CO₂ capillary entry pressure. It is controlled by the brine/CO₂ interfacial tension, the water‐wettability of caprock minerals, and the pore size distribution within the caprock. By means of contact angle measurements, experimental evidence was obtained showing that the water‐wettability of mica and quartz is altered in the presence of CO₂ under pressures typical of geological storage conditions. The alteration is more pronounced in the case of mica. Both minerals are representative of shaly caprocks and are strongly water‐wet in the presence of hydrocarbons. A careful analysis of the available literature data on breakthrough pressure measurements in caprock samples confirms the existence of a wettability alteration by dense CO₂, both in shaly and in evaporitic caprocks. The consequences of this effect on the maximum CO₂ storage pressure and on CO₂ storage capacity in the underground reservoir are discussed. For hydrocarbon reservoirs that were initially close to capillary leakage, the maximum allowable CO₂ storage pressure is only a fraction of the initial reservoir pressure.     

The effect of deformation on permeability development in anhydrite and implications for caprock integrity during geological storage of CO2

Geological storage of CO₂ in depleted oil and gas reservoirs is one of the most promising options to reduce atmospheric CO₂ concentrations. Of great importance to CO₂ mitigation strategies is maintaining caprock integrity. Worldwide many current injection sites and potential storage sites are overlain by anhydrite‐bearing seal formations. However, little is known about the magnitude of the permeability change accompanying dilatation and failure of anhydrite under reservoir conditions. To this extent, we have performed triaxial compression experiments together with argon gas permeability measurements on Zechstein anhydrite, which caps many potential CO₂ storage sites in the Netherlands. Our experiments were performed at room temperature at confining pressures of 3.5–25 MPa. We observed a transition from brittle to semi‐brittle behaviour over the experimental range, and peak strength could be described by a Mogi‐type failure envelope. Dynamic permeability measurements showed a change from ‘impermeable’ (<10^?21 m²) to permeable (10^?16 to 10^?19 m²) as a result of mechanical damage. The onset of measurable permeability was associated with an increase in the rate of dilatation at low pressures (3.5–5 MPa), and with the turning point from compaction to dilatation in the volumetric versus axial strain curve at higher pressures (10–25 MPa). Sample permeability was largely controlled by the permeability of the shear faults developed. Static, postfailure permeability decreased with increasing effective mean stress. Our results demonstrated that caprock integrity will not be compromised by mechanical damage and permeability development. Geofluids (2010) 10 , 369–387     

Effects of pore fluid flow and chemistry on compaction creep of calcite by pressure solution at 150°C

Uni‐axial compaction creep experiments were performed on crushed limestone and analytical grade calcite powders at 150°C, a pore fluid pressure of 20 MPa, and effective axial stresses of 30 and 40 MPa. Previous experiments have shown that compaction under these conditions is dominated by intergranular pressure solution (IPS). The aim of the present tests was to determine the inter‐relationship between pore fluid chemistry, compaction rate and the rate‐controlling process of IPS. Intermittent flow‐through runs conducted using CaCO₃ solution showed no effect on creep rate at low strains (<4–5%) but a major acceleration at high strains (5–10%). Measurements of the Ca concentration present in fluid samples revealed the build‐up of a high super‐saturation of CaCO₃ during compaction under zero flow conditions, especially at high strains. Active flow‐through led to a drop in Ca concentration, which corresponded with creep acceleration. Addition of NaCl to the pore fluid, at a concentration of 0.5 m , increased the creep rate of the analytical grade calcite samples roughly in proportion to the enhancement of calcite solubility. Addition of Mg²⁺ and to the pore fluid, in concentrations of 0.05 and 0.001 m, respectively, caused major retardation of compaction creep. Integrating our mechanical, flow‐through and chemical data points strongly to diffusion‐controlled IPS being the dominant deformation mechanism in the calcite‐water system under closed‐system (zero flow) conditions at low strains (<4–5%), giving way to precipitation control at higher strains. Our fluid composition data suggest that this transition is because of accumulation of impurities in the pore fluid. As Mg²⁺ and phosphate ions are common in natural pore fluids, it is likely that retarded precipitation will be the rate‐limiting step of IPS in carbonates in nature. To quantify diagenetic compaction and porosity‐permeability reduction rates by IPS in carbonates needs to account for this.     

Experimental investigation of carbon dioxide trapping due to capillary retention in saline aquifers

Capillary trapping is a physical mechanism by which carbon dioxide (CO₂) is naturally immobilized in the pore spaces of aquifer rocks during geologic carbon sequestration operations, and thus a key aspect of estimating geologic storage potential. Here, we studied capillary trapping of supercritical carbon dioxide (scCO₂), and the effect of initial scCO₂ saturation and flow rate on the storage/trapping potential of Berea sandstone. We performed two‐phase, scCO₂‐brine displacements in two samples, each subject to four sequential drainage–imbibition core‐flooding cycles to quantify end‐point saturations of scCO₂ with the aid of micro‐ and macro‐computed tomography imaging. From these experiments, we found that between 51% and 75% of the initial CO₂ injected can be left behind after the brine injection. We also observed that the initial scCO₂ saturation influenced the residual scCO₂ saturation to a greater extent than the rate of brine injection under the experimental conditions examined. In spite of differences in the experimental conditions tested, as well as those reported in the literature, initial and residual saturations were found to follow a consistent relationship.     

Numerical model of pore‐pressure diffusion associated with the initiation of the 2010–2011 Guy–Greenbrier,Arkansas earthquakes

We model pore‐pressure diffusion caused by pressurized waste‐fluid injection at two nearby wells and then compare the buildup of pressure with the observed initiation and migration of earthquakes during the early part of the 2010–2011 Guy–Greenbrier earthquake swarm. Pore‐pressure diffusion is calculated using MODFLOW 2005 that allows the actual injection histories (volume/day) at the two wells to diffuse through a fractured and faulted 3D aquifer system representing the eastern Arkoma basin. The aquifer system is calibrated using the observed water‐level recovery following well shut‐in at three wells. We estimate that the hydraulic conductivities of the Boone Formation and Arbuckle Group are 2.2 × 10^?2 and 2.03 × 10^?3 m day^?1, respectively, with a hydraulic conductivity of 1.92 × 10^?2 m day^?1 in the Hunton Group when considering 1.72 × 10^?3 m day^?1 in the Chattanooga Shale. Based on the simulated pressure field, injection near the relatively conductive Enders and Guy–Greenbrier faults (that hydraulically connect the Arbuckle Group with the underlying basement) permits pressure diffusion into the crystalline basement, but the effective radius of influence is limited in depth by the vertical anisotropy of the hydraulic diffusivity. Comparing spatial/temporal changes in the simulated pore‐pressure field to the observed seismicity suggests that minimum pore‐pressure changes of approximately 0.009 and 0.035 MPa are sufficient to initiate seismic activity within the basement and sedimentary sections of the Guy–Greenbrier fault, respectively. Further, the migration of a second front of seismicity appears to follow the approximately 0.012 MPa and 0.055 MPa pore‐pressure fronts within the basement and sedimentary sections, respectively.     

The role of the stress regime on microseismicity induced by overpressure and cooling in geologic carbon storage

Fluid injection in deep geological formations usually induces microseismicity. In particular, industrial‐scale injection of CO₂ may induce a large number of microseismic events. Since CO₂ is likely to reach the storage formation at a lower temperature than that corresponding to the geothermal gradient, both overpressure and cooling decrease the effective stresses and may induce microseismicity. Here, we investigate the effect of the stress regime on the effective stress evolution and fracture stability when injecting cold CO₂ through a horizontal well in a deep saline formation. Simulation results show that when only overpressure occurs, the vertical total stress remains practically constant, but the horizontal total stresses increase proportionally to overpressure. These hydro‐mechanical stress changes result in a slight improvement in fracture stability in normal faulting stress regimes because the decrease in deviatoric stress offsets the decrease in effective stresses produced by overpressure. However, fracture stability significantly decreases in reverse faulting stress regimes because the size of the Mohr circle increases in addition to being displaced towards failure conditions. Fracture stability also decreases in strike slip stress regimes because the Mohr circle maintains its size and is shifted towards the yield surface a magnitude equal to overpressure minus the increase in the horizontal total stresses. Additionally, cooling induces a thermal stress reduction in all directions, but larger in the out‐of‐plane direction. This stress anisotropy causes, apart from a displacement of the Mohr circle towards the yield surface, an increase in the size of the Mohr circle. These two effects decrease fracture stability, resulting in the strike slip being the least stable stress regime when cooling occurs, followed by the reverse faulting and the normal faulting stress regimes. Thus, characterizing the stress state is crucial to determine the maximum sustainable injection pressure and maximum temperature drop to safely inject CO₂.     

Decreasing CO2 partial pressure triggered Mg–Fe–Ca carbonate formation in ancient Martian crust preserved in the ALH84001 Meteorite

We retrace hydrogeochemical processes leading to the formation of Mg–Fe–Ca carbonate concretions (first distinct carbonate population, FDCP) in Martian meteorite ALH84001 by generic hydrogeochemical equilibrium and mass transfer modeling. Our simple conceptual models assume isochemical equilibration of orthopyroxenite minerals with pure water at varying water‐to‐rock ratios, temperatures and CO₂ partial pressures. Modeled scenarios include CO₂ partial pressures ranging from 10.1325 to 0.0001 MPa at water‐to‐rock ratios between 4380 and 43.8 mol mol^?1 and different temperatures (278, 303 and 348 K) and enable the precipitation of Mg–Fe–Ca solid solution carbonate. Modeled range and trend of carbonate compositional variation from magnesio‐siderite (core) to magnesite (rim), and the precipitation of amorphous SiO₂ and magnetite coupled to magnesite‐rich carbonate are similar to measured compositional variation. The results of this study suggest that the early Martian subsurface had been exposed to a dynamic gas pressure regime with decreasing CO₂ partial pressure at low temperatures (approximately 1.0133 to 0.0001 MPa at 278 K or 6 to 0.0001 MPa at 303 K). Moderate water‐to‐rock ratios of ca. 438 mol mol^?1 and isochemical weathering of orthopyroxenite are additional key prerequisites for the formation of secondary phase assemblages similar to ALH84001’s ‘FDCP’. Outbursts of water and CO_2(g) from confined ground water in fractured orthopyroxenite rocks below an unstable CO₂ hydrate‐containing cryosphere provide adequate environments on the early Martian surface.     

Real‐time quadrupole mass spectrometer analysis of gas in borehole fluid samples acquired using the U‐tube sampling methodology

Sampling of fluids in deep boreholes is challenging because of the necessity of minimizing external contamination and maintaining sample integrity during recovery. The U‐tube sampling methodology was developed to collect large volume, multiphase samples at in situ pressures. As a permanent or semi‐permanent installation, the U‐tube can be used for rapidly acquiring multiple samples or it may be installed for long‐term monitoring applications. The U‐tube was first deployed in Liberty County, TX to monitor crosswell CO₂ injection as part of the Frio CO₂ sequestration experiment. Analysis of gases (dissolved or separate phase) was performed in the field using a quadrupole mass spectrometer, which served as the basis for determining the arrival of the CO₂ plume. The presence of oxygen and argon in elevated concentrations, along with reduced methane concentration, indicates sample alteration caused by the introduction of surface fluids during borehole completion. Despite producing the well to eliminate non‐native fluids, measurements demonstrate that contamination persists until the immiscible CO₂ injection swept formation fluid into the observation wellbore.     

Simulation of the impact of faults on CO2 injection into sandstone reservoirs

Numerical simulations of multiphase CO₂ behavior within faulted sandstone reservoirs examine the impact of fractures and faults on CO₂ migration in potential subsurface injection systems. In southeastern Utah, some natural CO₂ reservoirs are breached and CO₂‐charged water flows to the surface along permeable damage zones adjacent to faults; in other sites, faulted sandstones form barriers to flow and large CO₂‐filled reservoirs result. These end‐members serve as the guides for our modeling, both at sites where nature offers ‘successful’ storage and at sites where leakage has occurred. We consider two end‐member fault types: low‐permeability faults dominated by deformation‐band networks and high‐permeability faults dominated by fracture networks in damage zones adjacent to clay‐rich gouge. Equivalent permeability (k) values for the fault zones can range from <10^?14 m² for deformation‐band‐dominated faults to >10^?12 m² for fracture‐dominated faults regardless of the permeability of unfaulted sandstone. Water–CO₂ fluid‐flow simulations model the injection of CO₂ into high‐k sandstone (5 × 10^?13 m²) with low‐k (5 × 10^?17 m²) or high‐k (5 × 10^?12 m²) fault zones that correspond to deformation‐band‐ or fracture‐dominated faults, respectively. After 500 days, CO₂ rises to produce an inverted cone of free and dissolved CO₂ that spreads laterally away from the injection well. Free CO₂ fills no more than 41% of the pore space behind the advancing CO₂ front, where dissolved CO₂ is at or near geochemical saturation. The low‐k fault zone exerts the greatest impact on the shape of the advancing CO₂ front and restricts the bulk of the dissolved and free CO₂ to the region upstream of the fault barrier. In the high‐k aquifer, the high‐k fault zone exerts a small influence on the shape of the advancing CO₂ front. We also model stacked reservoir seal pairs, and the fracture‐dominated fault acts as a vertical bypass, allowing upward movement of CO₂ into overlying strata. High‐permeability fault zones are important pathways for CO₂ to bypass unfaulted sandstone, which leads to reduce sequestration efficiency. Aquifer compartmentalization by low‐permeability fault barriers leads to improved storativity because the barriers restrict lateral CO₂ migration and maximize the volume and pressure of CO₂ that might be emplaced in each fault‐bound compartment. As much as a 3.5‐MPa pressure increase may develop in the injected reservoir in this model domain, which under certain conditions may lead to pressures close to the fracture pressure of the top seal.     

Fluid effect on hydraulic fracture propagation behavior: a comparison between water and supercritical CO2‐like fluid

The initiation of hydraulic fractures during fluid injection in deep formations can be either engineered or induced unintentionally. Upon injection of CO₂, the pore fluids in deep formations can be changed from oil/saline water to CO₂ or CO₂ dominated. The type of fluid is important not only because the fluid must fracture the rock, but also because rocks saturated with different pore fluids behave differently. We investigated the influence of fluid properties on fracture propagation behavior by using the cohesive zone model in conjunction with a poroelasticity model. Simulation results indicate that the pore pressure fields are very different for different pore fluids even when the initial field conditions and injection schemes (rate and time) are kept the same. Low viscosity fluids with properties of supercritical CO₂ will create relatively thin and much shorter fractures in comparison with fluids exhibiting properties of water under similar injection schemes. Two significant times are recognized during fracture propagation: the time at which a crack ceases opening and the later time point at which a crack ceases propagating. These times are very different for different fluids. Both fluid compressibility and viscosity influence fracture propagation, with viscosity being the more important property. Viscosity can greatly affect hydraulic conductivity and the leak‐off coefficient. This analysis assumes the in‐situ pore fluid and injected fluid are the same and the pore space is 100% saturated by that fluid at the beginning of the simulation.     

Carbon dioxide controlled earthquake distribution pattern in the NW Bohemian swarm earthquake region,western Eger Rift,Czech Republic – gas migration in the crystalline basement

The ascent of magmatic carbon dioxide in the western Eger (Oh?e) Rift is interlinked with the fault systems of the Variscian basement. In the Cheb Basin, the minimum CO₂ flux is about 160 m³ h^?1, with a diminishing trend towards the north and ceasing in the main epicentral area of the Northwest Bohemian swarm earthquakes. The ascending CO₂ forms Ca‐Mg‐HCO₃ type waters by leaching of cations from the fault planes and creates clay minerals, such as kaolinite, as alteration products on affected fault planes. These mineral reactions result in fault weakness and in hydraulically interconnected fault network. This leads to a decrease in the friction coefficient of the Coulomb failure stress (CFS) and to fault creep as stress build‐up cannot occur in the weak segments. At the transition zone in the north of the Cheb Basin, between areas of weak, fluid conductive faults and areas of locked faults with frictional strength, fluid pressure can increase resulting in stress build‐up. This can trigger strike‐slip swarm earthquakes. Fault creep or movements in weak segments may support a stress build‐up in the transition area by transmitting fluid pressure pulses. Additionally to fluid‐driven triggering models, it is important to consider that fluids ascending along faults are CO₂‐supersaturated thus intensifying the effect of fluid flow. The enforced flow of CO₂‐supersaturated fluids in the transitional zone from high to low permeability segments through narrowings triggers gas exsolution and may generate pressure fluctuations. Phase separation starts according to the phase behaviour of CO₂‐H₂O systems in the seismically active depths of NW Bohemia and may explain the vertical distribution of the seismicity. Changes in the size of the fluid transport channels in the fault systems caused, or superimposed, by fault movements, can produce fluid pressure increases or pulses, which are the precondition for triggering fluid‐induced swarm earthquakes.     

The geochemical evolution of very dilute CO2‐rich water in Chungcheong Province,Korea: processes and pathways

A geochemical study was carried out on the CO₂‐rich water occurring in granite areas of Chungcheong Province, Korea. In this area, very dilute and acidic CO₂‐rich waters [62–242 mg l^?1 in total dissolved solid (TDS), 4.0–5.3 in pH; group I) occur together with normal CO₂‐rich waters (317–988 mg l^?1 in TDS, 5.5–6.0 in pH; group II). The concentration levels and ages of group I water are similar to those of recently recharged and low‐mineralized groundwater (group III). Calculation of reaction pathways suggests that group I waters are produced by direct influx of CO₂ gas into group III type waters. When the groundwater is injected with CO₂, it develops the capacity to accept dissolved solids and it can evolve into water with very high solute concentrations. Whether the water is open or closed to the CO₂ gases becomes less important in controlling the reaction pathway of the CO₂‐rich groundwater when the initial pco ₂ is high. Our data show that most of the solutes are dissolved in the CO₂‐rich groundwater at pH > 5 where the weathering rates of silicates are very slow or independent of pH. Thus, groundwater age is likely more important in developing high solute concentrations in the CO₂‐rich groundwaters than accelerated weathering kinetics because of acidic pH caused by high pco ₂.     

Chemical and isotopic signatures of Na/HCO3/CO2‐rich geofluids,North Portugal

Geochemical and isotopic studies have been undertaken to assess the origin of CO₂‐rich waters issuing in the northern part of Portugal. These solutions are hot (76°C) to cold (17°C) Na–HCO₃ mineral waters. The δ²H and δ¹⁸O signatures of the mineral waters reflect the influence of altitude on meteoric recharge. The lack of an ¹⁸O‐shift indicates there has been no high temperature water–rock interaction at depth, corroborating the results of several chemical geothermometers (reservoir temperature of about 120°C). The low ¹⁴C activity (up to 9.9 pmC) measured in some of the cold CO₂‐rich mineral waters (total dissolved inorganic carbon) is incompatible with the presence of ³H (from 1.7 to 4.1 TU) in those waters, which indicates relatively short subsurface circulation times. The δ¹³C values of CO₂ gas and dissolved inorganic carbon range between ?6‰ and ?1‰ versus Vienna‐Peedee Belemnite, indicating that the total carbon in the recharge waters is being diluted by larger quantities of CO₂ (¹⁴C‐free) introduced from deep‐seated (upper mantle) sources, masking the ¹⁴C‐dating values. The differences in the ⁸⁷Sr/⁸⁶Sr ratios of the studied thermal and mineral waters seem to be caused by water–rock interaction with different granitic rocks. Chlorine isotope signatures (?0.4‰ < δ³⁷Cl < +0.4‰ versus standard mean ocean chloride) indicate that Cl in these waters could be derived from mixing of a small amount of igneous Cl from leaching of granitic rocks.     

Characteristics of CO2‐driven cold‐water geyser,Crystal Geyser in Utah: experimental observation and mechanism analyses

Geologic carbon capture and storage (CCS) is an option for reducing CO₂ emissions, but leakage to the surface is a risk factor. Natural CO₂ reservoirs that erupt from abandoned oil and gas holes leak to the surface as spectacular cold geysers in the Colorado Plateau, United States. A better understanding of the mechanisms of CO₂‐driven cold‐water geysers will provide valuable insight about the potential modes of leakage from engineered CCS sites. A notable example of a CO₂‐driven cold‐water geyser is Crystal Geyser in central Utah. We investigated the fluid mechanics of this regularly erupting geyser by instrumenting its conduit with sensors and measuring pressure and temperature every 20 sec over a period of 17 days. Analyses of these measurements suggest that the timescale of a single‐eruption cycle is composed of four successive eruption types with two recharge periods ranging from 30 to 40 h. Current eruption patterns exhibit a bimodal distribution, but these patterns evolved during past 80 years. The field observation suggests that the geyser's eruptions are regular and predictable and reflect pressure and temperature changes resulting from Joule–Thomson cooling and endothermic CO₂ exsolution. The eruption interval between multiple small‐scale eruptions is a direct indicator of the subsequent large‐scale eruption.     

Migration of metamorphic CO2 into a coal seam: a natural analog study to assess the long‐term fate of CO2 in Coal Bed Carbon Capture,Utilization, and Storage Projects

This study assesses the displacement of coalbed methane by CO₂ migration along a fault into the coal seam in the Yaojie coalfield. Coal and gas samples were collected continuously at various distances in NO.2 coal seam from F19 fault. Vitrinite reflectance, maceral, and pore distributions and proximate analysis of fourteen coal samples were performed. Gas components, concentrations, carbon isotopes of 28 gas samples were determined. We examined the coal–gas trace characteristics of coalbed methane displaced away from the fault by CO₂ injection after geological ages. From east to west, away from the F19 fault, the CO₂ concentration decreased, whereas the CH₄ concentration increased gradually. The δ¹³C values for CO₂ varied between ?9.94‰ and 1.12‰, suggesting a metamorphic origin. A wider range of values (from ?9.94‰ to 20‰) was associated with the mixing of microbial carbon dioxide, isotopic fractionation during CO₂ migration through the microporous structures of coals, and/or carbon isotope fractionation during gas–water exchange and dissolution of CO₂. Away from the F19 fault, the volumes of micropores, mesopores and macropores decrease gradually. The Dubinin–Radushkevich (DR) micropore volume decreased from 0.0059 to 0.0037 cm³ g^‐1, and the mesopore and macropore volumes decreased from 0.066 to 0.026 cm³ g^‐1. The CO₂ injection can mobilize aromatic hydrocarbons and mineral matter from coal matrix, resulting in the decrease in the absorption peak intensity for coal samples after supercritical CO₂ treatment, which indicates that chemical reactions occur between coal and CO₂, not only physical adsorption.     

Quantitative analysis of COH fluids synthesized at HP–HT conditions: an optimized methodology to measure volatiles in experimental capsules

The quantitative assessment of COH fluids is crucial in modeling geological processes. The composition of fluids, and in particular their H₂O/CO₂ ratio, can influence the melting temperatures, the location of hydration or carbonation reactions, and the solute transport capability in several rock systems. In the scientific literature, COH fluids speciation has been generally assumed on the basis of thermodynamic calculations using equations of state of simple H₂O–nonpolar gas systems (e.g., H₂O–CO₂–CH₄). Only few authors dealt with the experimental determination of high‐pressure COH fluid species at different conditions, using diverse experimental and analytical approaches (e.g., piston cylinder + capsule piercing + gas chromatography/mass spectrometry; cold seal + silica glass capsules + Raman). In this contribution, we present a new methodology for the synthesis and the analysis of COH fluids in experimental capsules, which allows the quantitative determination of volatiles in the fluid by means of a capsule‐piercing device connected to a quadrupole mass spectrometer. COH fluids are synthesized starting from oxalic acid dihydrate at P = amb and T = 250°C in single capsules heated in a furnace, and at P = 1 GPa and T = 800°C using a piston‐cylinder apparatus and the double‐capsule technique to control the redox conditions employing the rhenium–rhenium oxide oxygen buffer. A quantitative analysis of H₂O, CO₂, CH₄, CO, H₂, O₂, and N₂ along with associated statistical errors is obtained by linear regression of the m/z data of the sample and of standard gas mixtures of known composition. The estimated uncertainties are typically <1% for H₂O and CO₂, and <5% for CO. Our results suggest that the COH fluid speciation is preserved during and after quench, as the experimental data closely mimic the thermodynamic model both in terms of bulk composition and fluid speciation.