Browsing by Subject "Carbon storage"
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Item Aqueous formate solution for geological carbon storage : numerical simulation and geochemical interaction studies(2023-05-04) Oyenowo, Precious Olufemi; Okuno, Ryosuke, 1974-; Mirzaei-Paiaman, AbouzarCarbon storage in geologic formations has been considered an important technology that reduces the carbon intensity of fossil fuels-based industrial processes. Carbon capture and storage (CCS) conventionally uses carbon dioxide (CO₂) as a carbon carrier. However, various shortcomings of the conventional CCS are related to the physical properties of CO₂, such as low carbon density at low to moderate pressure, low mass density, low viscosity, immiscibility with water, and corrosivity. In particular, CO₂ injection often results in inefficient use of pore space in the formation under subsurface heterogeneities. This report is centered on the novel idea of using a formate solution as an aqueous carbon carrier for geologic carbon storage. Formate is the conjugate base of formic acid. Formate can be produced from CO₂ via electrochemical reduction (CO₂ ECR). The CO₂ ECR technology is not yet industrialized, although it has been substantially improved over the past few years in the energy transition with the current technology readiness level of 5 to 6. The cost of formate produced industrially using the technology is unknown. We measured the viscosities and densities of formate solutions in brine, over a range of formate concentrations and temperatures. The measured data were used in numerical reservoir simulations of formate injection: (i) into an aquifer, and (ii) into an oil reservoir. Compared to simulations of CO₂ injection using the same reservoirs, results consistently showed that the formate injection case resulted in more stable fronts of oil and water displacement. The more stable fronts yielded the oil recovery and carbon storage that were insensitive to the injectant breakthrough. Cost-revenue analysis using the simulation results showed the formate breakeven cost for the oil reservoir case was within the literature estimates of the cost of formate production via CO₂ ECR. The results support the necessity of research and development for efficient CO₂ ECR systems. Geochemical interaction studies were carried out to understand the effect of formate injection (at concentrations up to 30-wt%) on carbonate rock, and the effect on the rock wettability. Experimental data from Amott wettability tests and core floods with limestone cores were analyzed to mechanistically understand the wettability alteration observed in the experiments. Static calcite dissolution tests showed that the degree of calcite dissolution increased with increasing formate concentration in a NaCl brine even with an initially neutral pH. Geochemical modeling indicated that the increased calcite dissolution could be caused by the formation of calcium formate complexes that reduced the activity coefficient of the calcium ion and drove the calcite dissolution. The Amott test results and history matching of the core flooding data showed that high-concentration formate solutions rendered the initially oil-wet core to a more water-wet state.Item Assessing seagrass ecosystem status and condition : multi-scale applications of a long-term monitoring program(2021-04-29) Congdon, Victoria Marie; Dunton, Kenneth H.; Hardison, Amber K; Hall, Margaret O; McClelland, James WFluctuations in seagrass abundance and distribution often signify changes in abiotic conditions, including irradiance, temperature, salinity, and nutrient concentrations that can have long-term effects on coastal ecosystems. Stress responses by seagrasses trigger physiological effects that modify morphology and if conditions persist, alters structure at the meadow-scale. Since seagrasses are important indicators of ecosystem condition, long-term monitoring can help us identify factors that influence seagrass habitats through time and space. Such relationships between seagrass structure (i.e., plant physiology, architecture) and environmental conditions can better inform resource managers on the status and trends of seagrass ecosystems. This work investigates the applicability of long-term seagrass monitoring programs in Texas and Florida to: (1) estimate organic carbon stores along the Texas coast; (2) assess seagrass responses to a major disturbance in Texas; (3) characterize seagrass edge effects; and (4) evaluate the effectiveness of ecological indicators in identifying changes in seagrass condition within Florida and Texas. Areas with greater carbon stocks (up to 400 g C m⁻² in living biomass) corresponded to increases in cover and biomass; moreover, greater carbon storage capacity was associated with Thalassia testudinum, a more physically robust species (i.e., wide leaves, thick belowground tissues), than Halodule wrightii or Syringodium filiforme. Interestingly, despite the robust architecture of T. testudinum, this late successional species was more sensitive to a Category 4 hurricane than the prolific pioneer species (H. wrightii) as measured by greater reductions in cover and blade length in mixed (−16 vs. +1 %) and monospecific (−20 vs. +2 %) beds. We identified 11 metrics contributing to the dissimilarity between edge and interior habitats, with greater leaf widths, leaves shoot⁻¹, δ¹⁵N values, and epiphytes specific to edges. Importantly, many of the same metrics overlap as indicators for assessing ecological condition. Cover, shoot allometry and species composition were sensitive indicators of large-scale climatic disturbances (i.e., droughts, hurricanes). Our findings illustrate the breadth of long-term monitoring data in assessing differential responses to carbon stores and disturbances arising from distinct physiology and structure. Moreover, the use of common ecological indicators acquired from long-term monitoring programs highlight the prospect of broad-scale applications which can be used to develop seagrass management and conservation initiativesItem Coupling flow and poromechanics simulations for geological carbon storage(2021-11-30) Lu, Xueying, Ph. D.; Wheeler, Mary F. (Mary Fanett); Balhoff, Matthew T.; Sharma, Mukul M.; Prodanovic, Masa; Gamba, Irene M.Under the framework of the Paris Agreement, achieving carbon neutrality by the middle of the century is the fundamental solution to cope with the Climate Crisis. Carbon Capture, Storage, and Usage (CCUS) is a key group of technology to achieve a net-zero energy system. A high-fidelity model that depicts the multiphysics of the carbon storage processes over multiple temporal and spatial scales is essential to predict the fate of injected CO₂ and the associated geological formation. In this dissertation, we address several computational challenges arising from high-fidelity simulations of coupling geomechanics models to the multiphase multicomponent fluid flow models for geological carbon sequestration. The necessity of the coupling is first demonstrated using field data from the Cranfield site. Numerical experiments demonstrate that coupling geomechanics enables more accurate estimation of storage volume by considering the geological formation deformation. The geomechanics simulations also depict the stress evolution in both the reservoir and caprock during the carbon storage processes, which is key to ensure caprock integrity for both short-term and long-term success of the project. However, geomechanics simulations are computationally expensive in field-scale simulations. We develop several multiscale adaptive algorithms that root on rigorous a posteriori error estimates of the Biot system solved with a fixed-stress split. Error indicators are developed using residual-based a posteriori error estimates, with theoretical guarantees. We validated the effectiveness of the error indicators with Mandel's problem and proposed novel adaptive algorithms leveraging these a posteriori error estimators. The efficiency of these error estimators to guide dynamic mesh refinement is demonstrated with a prototype unconventional reservoir model containing a fracture network. We further propose a novel stopping criterion for the fixed-stress iterations using the error indicators to balance the fixed-stress split error with the discretization errors. The new stopping criterion does not require hyperparameter tuning and demonstrates efficiency and accuracy in numerical experiments. We also formulate a three-way coupling algorithm for fluid flow models and poromechanics models. The three-way coupling uses an error indicator at each time step to determine if the mechanics equation must be solved and whether the fixed-stress iterative coupling is necessary; otherwise, only the flow equation is solved with an extrapolated mean stress. The convergence of three-way coupling is established for the single-phase flow and linear elasticity with numerical validations. We further extend the algorithm to the compositional flow model. Field scale simulations demonstrate the accuracy and efficiency of the three-way coupling algorithm in that the mechanics update time is reduced significantly compared to the standard fixed-stress split. Another attempt is to integrate Bayesian optimization into the high-fidelity simulations for carbon injection scheduling optimization. The proposed framework represents a first attempt at incorporating high-fidelity physical models and machine learning techniques for data assimilation and optimization for field-scale geological carbon sequestration applications. The high-fidelity multiphysics simulations strictly honor the physical processes during carbon sequestration, while the Bayesian optimization provides a rigorous statistical framework that balances the exploration-exploitation tradeoff, and effectively searches the surrogate solution space. A benchmark with other commonly used algorithms such as genetic algorithm and evolution strategy demonstrates a very high potential of further applications of Bayesian optimizationItem Experimental measurement of sweep efficiency during multi-phase displacement in the presence of nanoparticles(2013-05) Aminzadeh Goharrizi, Behdad; DiCarlo, David Anthony, 1969-The efficiency of one fluid displacing another in permeable media depends greatly on the pore-scale dynamics at the main wetting front. Experiments have shown that the frontal dynamics can result in two different flow regimes: a stable and an unstable front. In stable displacements, any perturbation of the front will diminish with time and the effect of variation in permeability will be lessened. In contrast, in unstable displacements any perturbation of the front will grow with time and any variation in permeability will be magnified. In this dissertation, the stability of two different displacement processes are contemplated; a) vertical infiltration of dense liquid into dry sand from above and b) horizontal displacement of nanoparticle suspension with high pressure liquid CO₂. Significant insights are obtained by measuring the in-situ flow patterns in real time with a light transmission method and CT scanning. Vertical infiltration of dense fluid into dry sands from above is often observed to be unstable and produce gravity driven fingers. The formation of gravity fingers can have large consequences on the sweep efficiency of a displacement. Infiltration experiments showed that gravity driven fingers have a unique saturation profile known as saturation overshoot with a higher saturation at the finger tips than the saturation at the finger tail. Despite the vast number of theoretical and experimental investigations, conditions under which the front is unstable, remain unclear. To determine what controls the saturation overshoot and how it relates to the dynamics at the initial wetting front, saturation overshoot was measured as a function of flux for seven different liquids. These liquids gave a range of molecular weights, viscosities, and vapor pressures. It is found that for each fluid there is a flux (called overshoot flux) below which saturation overshoot ceases and the front is diffuse. The magnitude of the overshoot flux depends inversely on the invading fluid's viscosity and shows little or no dependence on the invading fluid's surface tension, vapor pressure, or miscibility with water. Since the saturation overshoot is not described by the continuum multi-phase flow models, the experimental results are used to develop a semi-continuum model that bridges the continuum-scale and pore-scale physics. The proposed model predicts the observed dependence of overshoot on media permeability and invading fluid properties. At the planned depth for CO₂ injection, either as an enhanced oil recovery technique or for CO₂ storage, CO₂ is typically less dense and less viscous than the in-situ fluid. Therefore, CO₂ injection is unstable and produces viscous fingers. This can greatly reduce the efficiency of a CO₂ flood or CO₂ storage capacity of an aquifer. To remedy this behavior, surface treated nanoparticles were used to reduce the mobility of injected CO₂. Displacement experiments were performed at low pressure with a CO₂ analogue (n-octane) fluid and at high pressure with liquid CO₂. Saturation distributions and pressure drops were measured in real time with the CT scanner when high pressure liquid CO₂ or n-octane was used to displace brine in different cores with and without suspended nanoparticles. In the presence of nanoparticles, the displacement front is more spatially uniform with a later breakthrough compared to the same experiment with no suspended nanoparticles. These observations suggest that nanoparticle stabilized foam, which forms during the displacement, acts to suppress the instability. It is argued that the generation of droplets occurs at the leading front of all drainage displacements. In the presence of nanoparticles, these droplets are preserved when nanoparticle adhere at the fluid-fluid interface. The new mechanism for foam generation described here, provides an interesting alternative for mobility control in CO₂ floods. Moreover, the same mechanism can potentially a) increase the CO₂ storage capacity of an aquifer, b) enhance the CO₂ capillary trapping, and c) provide an engineered barrier to CO₂ leakage from a storage sites, thereby alleviating the risk of contaminating the overlying fresh groundwater resources for CO₂ storage projects.Item Numerical Simulation of the Storage of CO2 and COi-H2S Gas Mixture in Deep Saline Aquifers(2005-05) Ozah, Robin; Pope, Gary A.; Sepehrnoori, KamyNumerical simulations were performed to understand the flow and storage potential of pure CO2 and CO2-H2S gas mixtures in deep saline aquifers. Flow and distribution of the injected CO2 and CO2-H2S gas mixtures in different forms in typical aquifers were studied. During injection of the supercritical gas/gas mixture into the aquifer, the gases follow the first drainage curve. Subsequently, however, the flow of brine and gas is counter-current and driven mostly by gravity, so hysteresis in the relative permeability curve results in substantial volumes of gas trapping as well as more contact with brine and this in turn leads to both more dissolution in the brine and more reactions and thus storage as precipitated minerals. Strategies for maximizing these beneficial storage effects were studied. Simulations using a compositional reservoir .simulator.