Movement Of CO2 Research Articles

Asymmetrical effects of mesophyll conductance on fundamental photosynthetic parameters and their relationships estimated from leaf gas exchange measurements

Worldwide measurements of nearly 130 C3 species covering all major plant functional types are analysed in conjunction with model simulations to determine the effects of mesophyll conductance (g(m)) on photosynthetic parameters and their relationships estimated from A/Ci curves. We find that an assumption of infinite g(m) results in up to 75% underestimation for maximum carboxylation rate V(cmax), 60% for maximum electron transport rate J(max), and 40% for triose phosphate utilization rate T(u) . V(cmax) is most sensitive, J(max) is less sensitive, and T(u) has the least sensitivity to the variation of g(m). Because of this asymmetrical effect of g(m), the ratios of J(max) to V(cmax), T(u) to V(cmax) and T(u) to J(max) are all overestimated. An infinite g(m) assumption also limits the freedom of variation of estimated parameters and artificially constrains parameter relationships to stronger shapes. These findings suggest the importance of quantifying g(m) for understanding in situ photosynthetic machinery functioning. We show that a nonzero resistance to CO2 movement in chloroplasts has small effects on estimated parameters. A non-linear function with gm as input is developed to convert the parameters estimated under an assumption of infinite gm to proper values. This function will facilitate gm representation in global carbon cycle models.

Implications of pore microgeometry heterogeneity for the movement and chemical reactivity of CO2 in carbonates

We studied the heterogeneity of natural rocks with respect to their pore-size distribution, obtained from mercury-intrusion capillary pressure (MICP) tests, at a scale about one-fifth of the standard plug size (2.5 cm). We investigated two Fontainebleau sandstone and two limestone samples. We found that at the scale of the MICP tests, heterogeneities are practically nonexistent. Still, there are large differences in the capillary curves from one rock type to another. Also, carbonate rocks, unlike Fontainebleau sandstone, show heterogeneities at a scale smaller than the scale used in MICP tests, as seen by the complexity in the mercury saturation versus pressure curves. We used this diversity between the capillary curves and this complexity within a single capillary curve to obtain information about the movement and chemical reactivity of [Formula: see text] in carbonates. The method consists of three steps: first, subdividing the carbonate pore system into microstructural facies, each of them having a specific range of pore throat size (e.g., tight micrite, microporous rounded micrite, small vugs, …); second, getting a characteristic value of their petrophysical properties (namely porosity, effective surface area, and permeability) from the collected MICP data; and third, computing, for experimental conditions corresponding to a transport-controlled system, the dimensionless Péclet and Damköhler numbers, expressed as a function of the aforementioned permeability and effective surface area. These numbers allowed us to infer the dominant process (i.e., diffusion, advection, or kinetics) controlling the dissolution/precipitation reaction induced by the carbonic acid. Because of heterogeneities in the pore microstructure, we found that either diffusion or advection is locally the dominant mechanism, which renders some zones (e.g., vugs or, to a lesser extent, microporous rounded micrite) chemically more reactive than others (e.g., tight micrite or spar cement).

Electrical resistance tomographic monitoring of CO2 movement in deep geologic reservoirs

Deep geologic sequestration of carbon dioxide (CO2) is being evaluated internationally to mitigate the impact of greenhouse gases produced during oil- and coal-based energy generation and manufacturing. Natural gas producing fields are particularly attractive sites for sequestration activities owing to the assumption that the same geologic barrier or cap rock permitting the subsurface regime to act as a long term natural gas reservoir will also serve to permanently contain the injected supercritical CO2. Electrical resistance tomography (ERT) can potentially track the movement and concentration of the injectate as well as the degree of geologic containment using time lapse electrical resistivity changes resulting from injecting the super-critical fluid into the reservoir formation. An experimental cross-well ERT system operated successfully for more than one year obtaining time lapse electrical resistivity images during the injection of approximately one-million tons of CO2 at a depth exceeding 3000m in an oil and gas field in Cranfield, MS, representing the deepest application of the method to date. When converted to CO2 saturation, the resultant images provide information about the movement of the injected CO2 within a complex geologic formation and the development of the saturation distribution with time. ERT demonstrated significant potential for near real-time assessment of the degree of geologic containment and for updating risk analyses of the sequestration process. Furthermore, electrical resistivity imaging of the developing CO2 distribution may provide crucial input about the developing reservoir pressure field that is required for active reservoir management to prevent the occurrence of cap-rock-damaging seismic activity.

Refinement of the Weyburn-Midale geological and hydrogeological model: Developing a better framework to determine reservoir response to injected CO2 and subsequent CO2 movement

The Weyburn field, operated by Cenovus Energy, currently contains the world's largest amount of injected and geologically stored anthropogenic CO2, with over 20 million tonnes of CO2 sequestered as of June 2012. The IEA GHG Weyburn-Midale CO2 Monitoring and Storage Project is in its second phase of research and, in order to refine the final model, adds new geological and hydrogeological data to the already rich dataset from Phase I.One aspect of geological characterization of the storage site in this phase of research was to further refine the geological model used in Phase I by examining more wells and including additional geological units. Well density has been increased from Phase I to more than 900 wells including 200 newly picked wells to more accurately locate the zero edges of these subcropping Mississippian units. Additionally, the model has been improved to integrate geological units not included in the Phase I model, including: (1) an “Altered Zone” of anhydrite and dolostone at the up-dip edge of the Weyburn-Midale reservoir that forms the caprock to the reservoir subjacent to the regional seal formed by the Watrous Formation; (2) the Frobisher Evaporite, a variably thick anhydrite unit present at the base of the reservoir beneath the northern portion of the field; and (3) the Oungre Evaporite, an anhydrite/dolomite unit within the Ratcliffe Beds present above the majority of the reservoir. Adding these units, with their irregular termination edges, into the Petrel model resulted in unrepresentative reservoir architecture as stacking the multiple Mississippian beds and then truncating them with the sub-Mesozoic unconformity created residual artefacts, which could not be correctly resolved in the resulting 3D grid. It was therefore necessary to delineate the zero edges by using false wells with zero isopach values, and then stack these isopach thicknesses to proportionately fill the 3D grid while maintaining their complex morphology. This resulted in an improved representation of the architecture of the hydrogeological flow units present in the Weyburn reservoir. Other challenges included the various types of data projections. This was resolved by using a consistent methodology for converting between all the coordinate systems.Pressure and hydrochemistry maps for the aquifers of interest (Midale, Frobisher and Ratcliffe) contain straddle tests and new wells drilled since Phase I was completed. Straddle drill stem tests were not included in Phase I of the project. Investigating these tests permits a better evaluation of the possibility of cross-formational flow between the Mississippian aquifers, and of the competency of inter- and intra-aquifer evaporites as potential barriers for fluid movement.Hydrogeological results from this study include: (1) hydrochemistry maps which indicate large variations in total dissolved solids (TDS) within the aquifers of interest (Ratcliffe, Midale and Frobisher) – the observed chemical and density variations have an influence on fluid movement; (2) pressure maps which illustrate unique variations between the aquifers of interest; (3) hydrochemical cross sections which display the lateral and vertical formational movement of fluids in the aquifers of interest; (4) pressure depth plots [P(d)] that demonstrate the original formation pressure present in the aquifers of interest as well as the current pressure regime present in the CO2 flood area; and (5) driving force ratio (DFR) maps that illustrate the combined forces acting on fluid movement within an aquifer and incorporate aquifer structure, TDS, temperature and pressure.The P(d) plots and the DFR maps add valuable insight regarding the fate of fluid movement in the aquifers of interest by locating regions that are in vertical communication as well as identifying areas where stagnation points or down-dip fluid movements are occurring. Additionally, the analysis of a recently completed observation well helps to gain insight into the pressure regime and fluid movement currently present in the storage unit. Results indicate that the Ratcliffe has predominantly horizontal flow and is isolated from the underlying Midale and Frobisher. These hydrogeological results can elucidate the movement of fluids in the Midale, as well as the vertical movement of fluids between the Midale, Frobisher and Ratcliffe.These new data and model were utilized by other research disciplines of the project including risk assessment and modelling of long-term storage. Results indicate that the Midale Beds at the IEA GHG CO2 Weyburn Monitoring and Storage Project are a secure location for CO2 sequestration.

The influence of fracture anisotropy on CO2 flow

AbstractGreenhouse gas mitigation through geological storage of carbon dioxide is dependent on rock formations storing CO2 effectively. Secure containment for periods of 100 × 105 years nee7ds to be verifiable. The effectiveness of geological storage is reliant on the chemical and physical properties of the geological storage complex and its ability to inhibit migration of CO2. Petroleum reservoir data and field evidence show that fracture networks often act as pathways for fluid movement, potentially allowing fluids to migrate to the surface within the time scale of interest. We demonstrate the importance of predicting the effects of fracture networks on flow, using a case study from the In Salah CO2 storage site, and show how fracture permeability is closely controlled by the stress regime determining the conductive fracture network. Our results demonstrate that fracture network prediction combined with present‐day stress analysis can be used to successfully predict CO2 movement in the subsurface.

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

AbstractNumerical 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.

Atmospheric and soil-gas monitoring for surface leakage at the San Juan Basin CO2 pilot test site at Pump Canyon New Mexico, using perfluorocarbon tracers, CO2 soil-gas flux and soil-gas hydrocarbons

Near-surface monitoring and subsurface characterization activities were undertaken in collaboration with the Southwest Regional Carbon Sequestration Partnership on their San Juan Basin coal-bed methane pilot test site near Navajo City, New Mexico. Nearly 18,407 short tons (1.670×107kg) of CO2 were injected into 3 seams of the Fruitland coal between July 2008 and April 2009. Between September 18 and October 30, 2008, two additions of approximately 20L each of perfluorocarbon (PFC) tracers were mixed with the CO2 at the injection wellhead. PFC tracers in soil-gas and in the atmosphere were monitored over a period of 2 years using a rectangular array of permanent installations. Additional monitors were placed near existing well bores and at other locations of potential leakage identified during the pre-injection site survey. Monitoring was conducted using sorbent containing tubes to collect any released PFC tracer from soil-gas or the atmosphere. Near-surface monitoring activities also included CO2 surface flux and carbon isotopes, soil-gas hydrocarbon levels, and electrical conductivity in the soil. The value of the PFC tracers was demonstrated when a significant leakage event was detected near an offset production well. Subsurface characterization activities, including 3D seismic interpretation and attribute analysis, were conducted to evaluate reservoir integrity and the potential that leakage of injected CO2 might occur. Leakage from the injection reservoir was not detected. PFC tracers made breakthroughs at 2 of 3 offset wells which were not otherwise directly observable in produced gases containing 20–30% CO2. These results have aided reservoir geophysical and simulation investigations to track the underground movement of CO2. 3D seismic analysis provided a possible interpretation for the order of appearance of tracers at production wells.

Estimating CO2 plume size: A correlation for site screening

Plume size is an important factor in the consideration of a site for CO2 sequestration. Flow model simulations are the accepted means of estimating plume size, but the development of geologic and numerical flow models requires a significant quantity of data, analyses and staff resources. These may not be readily available. Additionally, a proper geologic model should reflect all of the available rock and fluid properties and a general understanding of the dominant mechanisms influencing CO2 injection and movement in the injection interval. The time and resources required for flow model simulations can be substantial.During site screening, when multiple sites are being considered, rigorous modeling of the geology of a site may be impractical and cost prohibitive. In such a situation, a reliable correlation tool that would provide a comparative indication of plume size at different sites and provide a hierarchy of site choices for additional tests and analyses or for advanced geologic modeling would be desirable.A right circular cylinder was used with a range of Monte Carlo-derived storage efficiency factors to estimate CO2 plume size (lateral extent). The cylinder was described using net thickness and effective porosity. The storage efficiency factor included four displacement efficiency terms, which were areal, vertical, gravity, and microscopic displacement efficiency. For site screening, it was assumed that there was more certainty in thickness and porosity at a specific site than for basin-scale (regional) screening. Consequently, the correlations in this paper require the cumulative mass of injected CO2, net thickness, and effective porosity.The plume size correlations were compared with 13 flow model simulations where net thickness, cumulative CO2 injection, and permeability were varied. Plume size values obtained from the 13 models compared very well with the plume size values obtained from the right circular cylinder correlations. Additionally, the storage efficiency values from each model compared well with the storage efficiency values obtained using the Monte Carlo simulations. The method was applied to published data on the Sleipner CO2 storage field and gave relatively good results considering the elliptical shape of the Sleipner CO2 plume.

The Role of Static and Dynamic Modeling in the Fort Nelson CCS Project

Spectra Energy Transmission and the Energy & Environmental Research Center, through the Plains CO2 Reduction Partnership, are investigating potential commercial-scale carbon capture and storage in a saline formation near Fort Nelson, British Columbia, Canada, by conducting detailed modeling and predictive simulations of injection at the Fort Nelson site. The results of the Fort Nelson modeling activities are providing insight regarding the movement of sour CO2; the potential effects that large-scale sour CO2 injection may have on neighboring natural gas production fields; and the deployment of selected monitoring, verification, and accounting techniques.

A Numerical Simulation Study for the Distributed CCS

CO2 through the hydrogen manufacturing process in the refinery generates at about 100, 000 tones per year typically. A small-medium size CO2 geological storage in a distributed CCS plant is needed for the CO2 in the refinery and a research work commenced in 2010. In the research work, several subjects have been examined about the geological structure as well as the surface equipments to make clear the distributed CCS plant in the refinery processes. Those subjects are bundled to aim to create a promotion model in the oil refining industry to make the hydrogen society with the carbon free. The research includes the simulation for the CO2 movement in the geological storage aquifer in the model field. Simulation, where the TOUGH2 code was used, was carried out in the model field in a case of an amount of 100,000 tones per year of CO2 into a shallow aquifer.TOUGH2 code with the parameters as suitable to the micro-bubble as possible was tentatively used and it can come to a conclusion that the CO2 in micro-bubble will be stored much safely because the smaller buoyancy of the CO2 micro-bubble is expected. The simulation results inferred that gaseous CO2 is stored in the shallow reservoir in the model field and no leakage is detected during the 20 years injection period.

Is the recovery of (photo) respiratory CO2 and intermediates minimal?

Is the recovery of (photo) respiratory <scp>CO</scp>₂ and intermediates minimal?

A parametric study of coal mass and cap rock behaviour and carbon dioxide flow during and after carbon dioxide injection

In recent years, scientists have focused on processes which can be used to reduce greenhouse gas emissions, and CO2 sequestration in deep coal seams and saline aquifers has been identified as a potential method. However, there is a fundamental lack of understanding concerning the flow and mechanical phenomena that occur when CO2 is injected into coal seams. The main objective of this parametric study is to model the effect of CO2 injection pressure on cap rock deformation and investigate the possibility of leakage or back-migration of CO2 to the atmosphere through the cap rock. The COMSOL Multiphysics numerical simulator was used to investigate the effect of CO2 injection on coal and other adjacent rock strata. For the purpose of the model, a 200m long and 5m thick coal seam was assumed to be lying below a 200m long and 3m thick cap rock layer 1000m below the surface. According to the model’s results, the cap rock deforms considerably just after injection in an upward direction due to the CO2 movement, and the amount of deformation greatly depends on the injecting gas pressure. When the injecting gas pressure is increased from 10.2MPa to 30MPa, the cap rock is raised from 0.2mm to 15mm during the injecting period. Moreover, CO2 first spreads and is stored in the coal mass and then after about 3–4years it starts to move towards the cap rock layer. In the second stage of the study, a small rock fracture was inserted between the cap rock and the coal layer and a sudden increase in leakage of CO2 to the cap rock through the fracture was observed. The existence of a rock fracture is highly possible, and may happen naturally in coal seams. This model shows that this kind of fracture greatly increases the risk of back-migration of CO2 into the atmosphere. The model can be used to study general coal mass and cap rock behaviour and the back-movement of CO2 flow to the atmosphere.

The effect of aquifer condition on methane recovery for CO2 injection in coalbed

To estimate methane recovery from an enhanced coal bed at the field scale, it is important to understand CO2 movement. Since coal beds are generally connected with aquifers, CO2 movement is affected by aquifer position and strength. Under conditions of no aquifer, CO2 initially has a tendency to move to the top layer of the coal seam due to the buoyancy effect. However, the permeability of the upper layer is decreased due to the swelling effect. The viscosity flow effectively improves CO2 movement due to high permeability in the bottom layer. Because of the offsetting effects of viscosity and gravitational flow, the vertical sweep efficiency of injected CO2 is very effective. Thus, methane recovery is highly calculated. Under conditions of an upper aquifer, CO2 flow in the bottom layer decreased as the injected CO2 leaked to the aquifer. As the hydraulic connection between the overlying aquifer and the coal seam is strong, the vertical sweep efficiency is weakened due to the high gas leakage rate. Therefore, methane recovery decreases. However, under conditions in which an aquifer is at the bottom, methane recovery should be high because the gas-leakage rate is almost negligible. Under conditions with an aquifer edge, injected CO2 in the coal bed has an asymmetric flow because pressure is only supported in the flow direction of the aquifer. As the pressure is greater at the aquifer, the asymmetric flow is gradually strengthened by changes in the equilibrium caused by viscosity and gravity. Consequently, enhanced coalbed methane recovery has irregular efficiency, in part due to the CO2 movement. However, by suitably adjusting the CO2 injection site and production well perforation, total methane recovery can be made more efficient, despite producing an asymmetric flow of injected CO2. These findings clearly indicate that production or injection plans for enhanced coalbed methane must be designed to consider CO2 movement.

The effect of precipitation events on inorganic carbon in soil and shallow groundwater, Konza Prairie LTER Site, NE Kansas, USA

Abstract Monthly sampling for 1 year at the Konza Prairie LTER (Long-Term Ecological Research) Site in northeastern Kansas shows a connection between the annual cycles of CO2 in soil air and shallow groundwater DIC (dissolved inorganic C). Soil air CO2 reached 6–7% in July to mid-August, when moisture was not limiting to soil respiration. Following the annual maximum there was a sequential decrease in CO2 in three soil horizons to less than 0.5% because of moisture deficiency in the late summer and temperature decline in the fall and winter. Groundwater pCO2 reached its maximum of 5% in October; the lag-time of 2–3 months may correspond to the travel time of soil-generated CO2 to the water table. The time-variable CO2 caused an annual carbonate-mineral saturation cycle, intensifying limestone dissolution and DIC production when CO2 was high. The C flux depended on respiration and rainfall regimes, and had two main pathways. Transport of soil CO2 in the dissolved form with diffuse flow of recharge water was the most effective during the growing season so long as soil moisture was present. Downward movement of gaseous CO2 and equilibration with groundwater at the water table was favorable in July to August. Storm rainfall events recharged the aquifer within a few hours through preferential flow and stream–groundwater interaction, resulting in dilution of groundwater rather than forcing entrapped CO2 downward. Calculated C flux from the unsaturated zone to the unconfined aquifer in the monitoring period was 0.26 ± 0.03 M/m2/a of C, which is less than 1% of the CO2 that is released by soil to the atmosphere via efflux. However, meteoric precipitation was only 72% of average annual precipitation during the study period, so this study represents dry-condition flux. In addition, increased respiration rates due to warming of the atmosphere have the potential to cause a higher C flux to the saturated zone, intensifying weathering and groundwater acidification, so that further study is suggested.

Tracers – Past, present and future applications in CO2 geosequestration

Chemical tracers have been used in various C capture and storage (CCS) projects worldwide primarily to provide information regarding subsurface migration of CO2 and to verify CO2 containment. Understanding the movement and interactions of CO2 in the subsurface is a challenging task considering the variety of states in which it exists (i.e. gas, liquid, supercritical, dissolved in water) and the range of possible storage mechanisms (i.e. residual or capillary trapping, dissolved in water, structural trapping or incorporation into minerals). This paper critically reviews several chemical tracer applications and case studies for CCS projects. In many instances, there are parallels (e.g. tracer classes and applications) between tracers in the oil and gas industry and in CCS. It has been shown that chemical tracers can complement geophysical measurements (e.g. seismic) in understanding the formation behaviour of CO2. Although tracers have been successfully used in many CCS projects, some fundamental information, for example partitioning and adsorption, about the behaviour of tracers is still lacking and this can be an issue when interpreting tracer data (e.g. determining leakage rates). In this paper the deployment and recovery of chemical tracers and their use on various CCS projects are described.

Aquifer Management To Accelerate CO2 Dissolution and Trapping

Summary Bulk-phase CO2 injection into saline aquifers can provide substantive reduction in CO2 emissions if the risk arising from aquifer pressurization is addressed adequately through mechanisms such as brine production out of the system (Anchliya 2009). While this approach addresses the risks associated with aquifer pressurization it does not address the problem of ensuring CO2 trapping as an immobile phase and its accumulation at the top of the aquifer. The performance of bulk-CO2-injection schemes highly depends on the seal-integrity assessment and presence of thief zones. The accumulated pocket of free CO2 can readily leak through a breach in the aquifer seal. Ideally, the aquifer should be monitored as long as the free CO2 is present, but if the CO2 is not immobilized, it is expected to remain underneath the seal rock for more than 1,000 years. Therefore, long-term monitoring of the seal integrity and avoiding leakage will be very costly. To minimize the free CO2 below the caprock, we propose an engineered system to reduce aquifer pressurization and accelerate CO2 dissolution and trapping. We achieve these objectives through effective placement of brine injection and production wells to facilitate the lateral movement (hence, residual and solubility trapping) of CO2 in the aquifer and impede its upward movement. The simulation results for example engineered well configurations in this paper suggest that substantial improvements in immobilizing CO2 can be achieved through increasing enhanced solubility and residual trapping that result from better CO2-injection sweep efficiency. This approach has the potential to greatly reduce the risk of CO2 leakage both during and after injection. The controlled injection of CO2 with this technique reduces the uncertainty about the long-term fate of the injected CO2, prevents CO2 from migrating toward potential outlets or sensitive areas, and increases the volume of CO2 that can be stored in a closed aquifer volume during the CO2-injection period. Field-scale compositional simulation cases are discussed, and sensitivity studies are used to provide guidelines for well spacing and flow rates depending on aquifer properties and the volume of CO2 to be stored. Although it requires additional drilled wells, the active engineered configuration proposed for CO2 injection significantly reduces the reservoir volume required to effectively sequester a given volume of CO2, and the increase in the cost caused by additional wells is recovered by dramatic reduction in monitoring cost.

Predicting subsurface CO2 movement: From laboratory to field scale

Finding an appropriate model for time-lapse seismic monitoring of [Formula: see text]-sequestered carbonate reservoir poses a great challenge because carbonate-rocks have varying textures and highly reactive rock-fluid system. We introduced a frequency-dependent model based on Eshelby’s inclusion and differential effective medium (DEM) theory that can account for heterogeneity in microstructure of rocks and squirt flow. We showed that the estimated velocities from the modified DEM theory match well with the laboratory measurements (ultrasonic) of velocities of carbonate rocks saturated with [Formula: see text]-rich water. The theory predicts significant decrease in saturated P- and S-wave velocities in the seismic frequency band as a consequence of porosity and permeability enhancement by the process of chemical dissolution of carbonates with the saturating fluid. The study also showed the combined effect of chemical reaction and free [Formula: see text] saturation on the elastic properties of rock. We observed that the velocity dispersion and attenuation increased from complete gas saturation to water saturation. The proposed model can be used to invert geophysical measurements to detect changes in elastic properties of a carbonate reservoir and interpret the extent of [Formula: see text] movement with time. These are the key elements to ensure that sequestration will not damage underground geologic formation and [Formula: see text] storage is secure and environmentally acceptable.

Carbon Dioxide Migration Pathways in Proteins.

Some of the most important biological processes, such as carbon fixation, are dependent on protein-gas interactions. The motion of CO2 through the enzyme phosphoenolpyruvate carboxykinase was investigated using extensive all-atom molecular dynamics simulations. Three discrete migration pathways were located, suggesting the protein directs the movement of CO2. The chemical nature of these pathways is discussed, as are their biotechnological ramifications.

Controlled CO2 injection into heterogeneous geologic formations for improved solubility and residual trapping

Geologic CO2 storage (GCS) has been proposed as a potentially viable climate change mitigation option. Among the trapping mechanisms known for permanent CO2 storage in saline aquifers, solubility and residual trapping are important for safe short‐term entrapment. These storage mechanisms are hampered by density‐driven upward CO2 movement that inhibits the lateral migration of the plume, leaving a large portion of the aquifer volume unexposed to CO2 and unavailable for storage. Heterogeneity of aquifer hydraulic properties and high horizontal/vertical hydraulic conductivity ratio of geologic formations are two competing mechanisms that can hinder upward CO2 migration. Postinjection displacement of free‐phase CO2 is somewhat controlled by the heterogeneity in rock permeability and porosity distributions. In particular, low permeability shale layers that act as vertical flow barrier and high‐permeability horizontal channels that form flow conduits can spread the CO2 plume laterally in the aquifer. In this paper, we consider CO2 storage in heterogeneous saline aquifers and propose controlled CO2 injection, based on existing knowledge of heterogeneity, to increase CO2 contact with brine and improve the solubility and residual trapping and the overall aquifer storage potential. We examine two optimization methods: directly maximizing the total stored gas in the aquifer, and maximizing the sweep efficiency of the CO2 flood to promote uniform displacement in all directions. We consider the effect of geologic uncertainty on the performance of the controlled injection schemes by using an ensemble of model realizations to represent the uncertainty in aquifer property distribution. We also show how a controlled injection can be used to mitigate the risk of leakage from potential pathways, such as an abandoned well, by restricting CO2 movement toward the leakage zone. Our results suggest that controlled injection can lead to substantial improvements in residual and dissolution trapping and can be used to divert a CO2 plume from approaching sensitive zones or leakage pathways.

CO2 disposal as hydrate in ocean sediments

Reducing carbon dioxide (CO2) emissions is becoming a significant environmental goal and undertaking worldwide, and is expected to be a major concern in the future. In this regard, sequestration of CO2 in geological formations is of great interest. However, CO2 is buoyant under the pressure-temperature conditions of typical geological sites, contributing to the risk of leakage. Storage of CO2 as hydrate avoids this limitation. Much of the ocean sediments at depths of a few hundred meters below the ocean floor provide appropriate conditions for CO2 hydrate formation. Furthermore, ocean sediments may provide conditions at which the density of liquid CO2 is greater than the density of water, making liquid CO2 gravitationally stable (i.e., non-buoyant).In this study, we investigate storage of CO2 as hydrate below the ocean floor. We identify conditions where the initial pressure-temperature conditions are suitable for CO2 hydrate formation and demonstrate the effect of changes caused by injection. In particular, the changes in pressure as a result of injection and the increase in temperature due to hydrate formation, both of which could lead to upward movement of CO2, are investigated. Sensitivity studies are conducted to determine appropriate conditions for large scale CO2 storage. In particular, the effects of ocean depth and injection depth in the sediment on flow of CO2 toward the ocean floor are studied.The results of calculations for static conditions and modeling under dynamic conditions show that CO2 hydrate formation and gravitational stability of CO2 in the upper parts of the ocean sediments for some areas of the ocean can restrict upwards flow of CO2 toward the seabed. If the ocean depth and sediment depth for injection of CO2 are properly chosen, large volumes of CO2 can be reliably stored in the sediment.