Browsing by Subject "Carbon sequestration"
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Item Aggregating pore space ownership for geologic sequestration of CO2(2011-05) Rozsypal, Audrey Marie; Groat, Charles G.; Dzienkowski, John; Duncan, IanThe injection operator for a carbon dioxide sequestration project must control the reservoir and associated pore space within the project boundaries to allow for orderly development of the storage facility. A large number of interest owners within a project area is likely to make reaching unanimous agreement among all owners of pore space unlikely, and thus control of the reservoir difficult. In order to facilitate geologic sequestration of carbon dioxide on privately owned land in the United States, or on land for which the minerals or pore space are privately owned, a scheme for aggregating the ownership of pore space is needed. To allow geologic sequestration projects to move forward with less than unanimous consent of interest owners, states can employ various methods of aggregating pore space ownership. This paper examines oil and gas unitization statues and statutes creating groundwater districts to find legislative regimes useful for achieving pore space ownership aggregation. Among the approaches discussed, aggregation of pore space ownership through a unitization model is the most likely choice. Taking that one step further and setting up new unit operating agreements for enhanced oil recovery to serve as a repository for incremental geologic sequestration, and eventual full sequestration activities, provides a firm path toward reducing carbon dioxide emissions while respecting property rights. This paper also compares the few existing pore space aggregation statutes in the United States, which achieve aggregation of pore space ownership through either unitization or eminent domain. The state that appears to be the best equipped to deal with aggregation of pore space ownership is Wyoming. Wyoming has been a leader in developing legislation to deal with pore space ownership before other states. North Dakota and Utah are also very well situated to move forward with carbon sequestration activities.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 Black mangrove (Avicennia sp.) colony expansion in the Gulf of Mexico with climate change : implications for wetland health and resistance to rising sea levels(2010-12) Comeaux, Rebecca Suzanne; Allison, Mead A. (Mead Ashton); Bianchi, Thomas S.; Mohrig, David; Wilson, Clark R.Populations of black mangroves (Avicennia sp.) are hypothesized to expand their latitudinal range with global climate change in the 21st century, induced by a reduction in the frequency and severity of coastal freezes, which are known to limit mangrove colony extent and individual tree size, as well as an overall warmer climate. The Gulf of Mexico is located at the northward limit of black mangrove habitat and is therefore a prime candidate for population expansion with global warming. This expansion may come at the expense of existing Gulf coastal saline wetlands that are dominantly Spartina spp. marsh grasses. The present study was conducted to focus, not on the extent to date of this replacement, but to examine the potential implications of a marsh to mangrove transition in Gulf wetlands, specifically 1) resistance to accelerating eustatic sea level rise (ESLR) rates, 2) wetland resistance to wave attack in large storms (increased cyclonic storm frequency/intensity is predicted with future climate warming), and 3) organic carbon sequestration and wetland soil geochemistry. Field sites of adjacent and intergrown Avicennia mangrove and Spartina marsh populations in similar geomorphological setting were selected in back-barrier areas near Port Aransas and Galveston, TX (two sites each) as part of a larger-scale planned study of the full latitudinal transition of the western Gulf funded by the National Institute for Climate Change Research (U.S. Department of Energy). The reconnaissance conducted for site surveys show that black mangrove populations in this part of Texas are clustered near inlet areas, suggesting seed transport vectors are a major control on colony establishment, and likely, on the potential rapidity of wetland habitat replacement. Resistance to ESLR was tested by 1) creating high-accuracy (±1 cm) elevation maps over ~5,000 m² areas of adjacent mangrove and marsh areas, and 2) measuring mineral and organic matter accumulation rates (Pb/Cs radiotracer geochronology, loss on ignition) from auger cores. Elevation surveys in Port Aransas indicate mangrove vegetated areas are 4 cm higher in elevation than surrounding marsh on an average regional scale, and 1 to 2 cm higher at the individual mangrove scale: at the Galveston sites, any trend is complicated by the area's pre-existing geomorphology and the relative youth of the mangrove colonies. ¹³⁷Cs accumulation rates and loss on ignition data indicate that mineral trapping is 4.1 times higher and sediment organics are 1.7 times lower in mangroves at Port Aransas; no such definable trends exist at the Galveston sites or in calculated ²¹⁰Pb sediment accumulation rates. This additional mineral particle trapping in mangroves does not differ in grain size character from marsh mineral accumulation. Elevation change may also be effected by root volume displacement: live root weight measurements in the rooted horizon (~0 to 20 cm depth) are consistently higher in mangrove cores from Port Aransas and the site at the west end of Galveston Island. Port Aransas porosities are lower in mangrove rooted horizons, with a corresponding increase in sediment strength (measured by shear vane in the cores), suggesting mangrove intervals may be more resistant to wave-induced erosion during storm events. Port Aransas mangroves exhibit higher pore water redox potentials and salinities over entire core depths and depressed pH over rooted intervals, suggesting a distinct diagenetic environment exists relative to marsh sites. Increased salinities and higher redox potentials may be a function of the rooting network, which introduces oxygen into the sediment and focuses evapo-transpiration and salt exclusion within this zone: this may prove advantageous when competing with marsh grasses by elevating salinities to levels that are toxic for Spartina. Trends observed in the more mature systems of Port Aransas are generally absent at the Galveston sites, suggesting the youth and physically shorter stature of these systems means they have not yet established a unique sediment signature.Item Carbon dioxide solubility and mass transfer in aqueous amines for carbon capture(2015-08) Li, Ph. D., Le; Rochelle, Gary T.; Freeman, Benny D; Sanchez, Isaac C; Svendsen, Hallvard F; Dugas, Ross EAmine scrubbing is the state of the art technology for CO2 capture, and solvent selection can significantly reduce the capital and energy cost of the process. This work presents rigorous CO2 mass transfer and solubility data at expected process conditions for more than 20 aqueous amines and amino acid salts. Amino acid salts are generally not competitive with aqueous amines as solvents for CO2 capture, particularly from coal fired power plants. The capacity of amino acid salts is intrinsically low (0.2 – 0.35 mol/mol alkalinity). Piperazine (PZ) blends have good overall performance. 3.5 m PZ/3.5 m 2-amino-2-hydroxymethyl-propane-1,3-diol (Tris) shows good absorption rates, good capacity, and low solvent viscosity. 6 m PZ/2 m hexamethylenediamine (HMDA) has moderate absorption rates, capacity, and a high viscosity. High solvent viscosity has been shown to reduce CO2 absorption rate and increase sensible heat cost. A simplified speciation model (SSM) was developed in MATLAB to represent CO2 VLE in a mono-amine solvent using only four adjustable parameters. The model can also predict liquid phase speciation. Primary and secondary amines were shown to have different CO2 VLE dependence on amine pKa. At pKa higher than 8, secondary amines have lower carbamate stability than primary amines. A correlation was developed to predict the SSM parameters based on the amine type and amine pKa. The third order overall reaction kinetic expression better explains the mass transfer data at process conditions than the more widely applied second order overall expression. A new Bronsted correlation was developed to represent the third order concentration based kinetic constant at 40 °C for primary and secondary amines: 〖log〗_10 (〖k_(c-3)〗^* )=-11.728+1.113∙p〖K_a〗_amine. This work shows the absorption rate of CO2 at process conditions do not always increase with amine pKa. As the reaction rate constant increases with amine pKa, the free amine available for CO2 absorption decreases. As the result, for primary and secondary mono-amines, the optimum amine pKa for the best mass transfer performance is around 8.7 (at 40 °C).Item Constraining the data and investment needs for obtaining a carbon dioxide injection permit in the United States(2021-08-09) Barnhart, Taylor H.; Hovorka, Susan D. (Susan Davis)To keep global temperature increases below 2 ̊C, utilization of carbon capture and storage (CCS) must proliferate, but the U.S. has only issued two Underground Injection Control (UIC) Class VI permits for carbon dioxide (CO₂) storage in saline formations. An impediment to CCS development is uncertainty regarding investment requirements for selecting and characterizing a storage site to obtain an injection permit. A Class VI permit application requires adequate site characterization to ensure that no underground sources of drinking water (USDWs) will be negatively impacted by CO₂ storage. Collection of characterization data involves financial expenditures at different project development investment gates. Here these gates are designated as Feasibility, Site(s) Selection, Detailed Characterization, and Permit Preparation. To estimate the potential investments at each gate, a novel approach was developed and applied to 31 case study storage sites in the Southeast Regional CO₂ Utilization and Storage Acceleration Partnership (SECARB-USA) region. This approach included development of a data needs framework, which consists of data required under Class VI regulations, data for multiphase fluid flow modeling, and data for development of a site monitoring program. Two site evaluation rubrics were derived from this data needs framework to assess the urgency and availability of data at a site. The cost of site characterization is a function of the data density (data availability) and data urgency of a site. These rubrics were used to assign scores to the 42 data needs in the data needs framework, and the subsequent data need scores were referenced to a characterization activity cost index to estimate the costs at each investment gate for each site. Results indicate that the total characterization cost across the case study sites are nearly identical unless high cost characterization activities, such as conducting a 3-D seismic survey or drilling, coring, and testing a characterization well, are unnecessary because the data already exist. Existence of these data lowers project risk as early investment gates can be passed with lower investments. Other trends in the dataset reinforce the value of stacked storage sites for reducing costs and existing well penetrations for providing subsurface dataItem CO₂ solubility and dissolution rate: the epic battle between ions and CO₂ for water, energy and space(2015-12) Gilbert, Kimberly Dawn; Bennett, Philip C. (Philip Charles), 1959-; Cardenas, Meinhard B; Breecker, Daniel O; Zhang, Tongwei; Cygan, Randall TCO₂ dissolution into deep subsurface brines is regarded as a viable means of reducing CO₂ atmospheric emissions. Dissolved ions affect CO₂ solubility (CCO₂) and the rate of dissolution, but the mechanisms of the effect are not clearly understood and thus CCO₂ prediction is difficult. We measured CCO2 and solution density up to 140°C and 35.5 MPa-PCO₂ in water, NaCl, CaCl₂, Na2SO₄, and NaHCO₃ solutions up to 3.4 molal and Bravo Dome mixed brine. CCO₂ weakly correlated to ionic strength and water activity. Strong correlations (R² > 0.92) were identified between CCO₂ and each of ΔGhydr, ΔHhydr, ΔShydr, and the electrostricted water concentration, ha; calculated from ion concentration and hydration number. Traditional empirical CCO₂ prediction models require extensive experimental work to determine parameters. We use a novel prediction approach by applying a mole balance on water, then evaluating the energy required to remove water from hydrated ions to solvate CO₂. The resulting model developed using moderated multiple regression shows that CCO₂ is dependent on CO₂fugacity (f), temperature (T), ha, and the solution hydration energy (G): all of which are specified or previously catalogued variables. A model (R²=0.92) is generated from 503 data points from this study and literature and includes the squares of each variable and interactions. Interactions between f, T, ha and G evaluated using spot-light analysis indicate that: 1) competition for water molecules significantly impacts CCO₂; 2) T and f interact to exacerbate a decrease in open water structure concentration; and 3) hydrated ions may dampen thermal agitation and reduce open structure collapse caused by increased T. The interactions of this research are likely extensible to the dissolution of any non-polar gas into a salt solution. CO₂ dissolution rate measurements demonstrated that convection occurred in experimental reactors with dissolving CO₂; however, the system was diffusion limited due to a thin diffusion layer. Density measurements revealed salt solution volume decreases with increasing CO₂, which results in: 1) faster mass transfer of dissolved CO₂ and 2) increased CO₂ total storage capacity (TSC). In 1 m Na₂SO₄ at 60°C and 10 MPa volume decreases yielded a 20% TSC increase.Item CO₂ storage in deltaic environments of deposition : integration of 3-dimensional modeling, outcrop analysis, and subsurface application(2018-05) Beckham, Emily Christine; Meckel, Timothy AshworthCarbon sequestration in geologic reservoirs is a proven method for reducing greenhouse gas emissions. Deltaic deposits are attractive candidates for CO₂ storage projects due to their prominent role as hydrocarbon reservoirs. This research informs subsurface deltaic reservoir characterization and performance for carbon sequestration through integration of geocellular modeling, outcrop analyses, and seismic mapping of prospective offshore CO₂ reservoirs. Results emphasize the importance of recognizing sequence stratigraphic architectures for predicting CO₂ migration. Initially, a model of a deltaic system was generated from a prior laboratory flume deposit to better understand fundamental (but generalized) aspects of reservoir and seal performance. This model was scaled and assigned geologic properties, generating a novel and extremely high-resolution geologic model. Physical architectures represented in the geologic model are consistent with global examples of deltaic reservoirs as well as the facies, stratal stacking pattern, and grain size variability in outcrops studied in this research. Twenty CO₂ injection simulations were run on the geologic model to understand the relationship between reservoir heterogeneity and fluid migration. Baffles affecting migration are identified as the shale layers between sand clinoforms and regressive surfaces in the highstand-lowstand systems tracts. Primary trapping surfaces influencing CO₂ migration are the regressive surfaces in the transgressive systems tract (TST), where migration pathways converge along common surfaces. These sequence stratigraphic observations are then applied to reservoir characterization in 3D seismic data from offshore Gulf of Mexico. The regional, sequence stratigraphic surfaces are well represented in sub-surface data. Hydrocarbon production data indicate fluid accumulation in TST stratigraphy, similar to the geologic modeling results, suggesting some predictability of fluid flow in deltaic settings. The novel integration of datatypes produces enhanced understanding of subsurface fluid flow in deltaic environments.Item Examining supercritical CO₂ dissolution kinetics during carbon sequestration through column experiments(2011-08) Kent, Molly Elizabeth; Bennett, Philip C. (Philip Charles), 1959-; Romanak, Katherine; Cardenas, Meinhard B.Carbon sequestration is a method of capturing and storing excess anthropogenic CO₂ in the subsurface. When CO₂ is injected, the temperature and pressure at depth turn it into a supercritical (SC) fluid, where density is that of a liquid, but viscosity and compressibility resemble a gas. Ultimately the SC CO₂ is trapped at depth either by low permeability sealing layers, by reactions with minerals, or by dissolving into fluids. The injected CO₂ is buoyant and initially exists as a non-aqueous hydrophobic layer floating on top of the subsurface brine, up against the upper sealing formation, but over time it will dissolve into the brine and potentially react with minerals. The details of that initial dissolution reaction, however, are only poorly understood, and I address three basic questions for this research: What is the fundamental kinetics of SC CO₂ dissolution into water? How fast does dissolved CO₂ diffuse away from the source point? And what geochemical conditions influence the dissolution rate? To answer these questions I employed a high pressure flow-through approach using a column packed with coarse quartz sand. The system was both pressure and temperature controlled to have either liquid or SC CO₂ present, and was typically run at 100 Bar, 0.5 to 2.5 mls/min, and 28-60°C. After establishing the hydraulic parameters for the column using two conservative tracers (Br, As), injections (5 and 20 [mu]l) were made either as aqueous solutions equilibrated to high pressure CO₂, or as pure liquid or SC CO₂ into 0.1 mmol NaOH. For all experiments the pH of the system was monitored, and [CO₂] over time was calculated from those data. For injections of brine with dissolved CO₂, transport was conservative and was nearly identical to the conservative tracers. The CO₂ quickly mixes in the column and does not react with the quartz. The liquid and SC CO₂ injections, however, do not act conservatively, and have a very long tailing breakthrough curve that extends to tens of pore volumes. I hypothesize that the SC CO₂ is becoming trapped as a droplet or many droplets in the pore spaces, and the long breakthrough tail is related either to the rate of dissolution into the aqueous phase, the diffusion of dissolved CO₂ away from the phase boundary, or the reaction with the NaOH, limited to the narrow contact zones in the pore throats. Because of the speed at which acid-base reactions occur (nanosecond kinetics), I infer that the rate limiting step is either surface dissolution or diffusion. From plots of ln[CO₂] v. time I obtained values for k, the specific rate of the dissolution reaction R=-k[CO₂]. No trend for k was seen with respect to changes in temperature, but k did show a trend with respect to changing flow rate. k increased from an average value of 3.05x10⁻³ at 0.5 ml/min to an average value of 3.38x10⁻³ at 1.6 ml/min, and then held constant at the higher flow rates, up to 2.5 ml/min. I interpret these data to show that at low flow rates, the reaction is diffusion limited; the fluid nearest the contact zone becomes saturated with dissolved CO₂. At higher flow rates, the fluid is moving fast enough that saturation cannot occur, and the kinetics of the dissolution reaction dominate. Simple geometric models indicate that the CO₂/water interface is shaped like a spherical cap, indicating that the snapped-off CO₂ is forming a meniscus in the pore throat, limiting the surface area across which dissolution can occur.Item Factors determining rapid and efficient geologic storage of CO₂(2011-08) Jain, Lokendra; Bryant, Steven L.; Lake, Larry W.Implementing geological carbon sequestration at a scale large enough to mitigate emissions will involve the injection of supercritical CO₂ into deep saline aquifers. The principal technical risks associated with such injection are that (i) buoyant CO₂ will migrate out of the storage formation; (ii) pressure elevation during injection will limit storage rates and/or fracture the storage formation; and (iii) groundwater resources will be contaminated, directly or indirectly, by brine displaced from the storage formation. An alternative to injecting CO₂ as a buoyant phase is to dissolve it into brine extracted from the storage formation, then inject the CO₂-saturated brine into the storage formation. This "surface dissolution" strategy completely eliminates the risk of buoyant migration of stored CO₂. It greatly mitigates the extent of pressure elevation during injection. It nearly eliminates the displacement of brine. To gain these benefits, however, it is essential to determine the costs of this method of risk reduction. This work provides a framework for optimization of the process, and hence for cost minimization. Several investigations have tabulated the storage capacity for CO₂ in regions around the world, and it is widely accepted that sufficient pore volume exists in deep subsurface formations to permit large-scale sequestration of anthropogenic CO₂. Given the urgency of implementing geologic sequestration and other emissions-mitigating technologies (storage rates of order 1 Gt C per year are needed within a few decades), the time required to fill a target formation with CO₂ is just as important as the pore volume of that formation. To account for both these practical constraints we describe in this work a time-weighted storage capacity. This modified capacity integrates over time the maximum injection rate into a formation. The injection rate is a nonlinear function of time, formation properties and boundary conditions. The boundary conditions include the maximum allowable injection pressure and the nature of the storage formation (closed, infinite-acting, constant far-field pressure, etc.) The time-weighted storage capacity approaches the volumetric capacity as time increases. For short time intervals, however, the time-weighted storage capacity may be much less than the volumetric capacity. This work describes a method to compute time-weighted storage capacity for a database of more than 1200 North American oil reservoirs. Because all of these reservoirs have been commercially developed, their formation properties can be regarded as representative of aquifers that would be attractive targets for CO₂ storage. We take the product of permeability and thickness as a measure of injectivity for a reservoir, and the product of average areal extent, net thickness and porosity as a measure of pore volume available for storage. We find that injectivity is not distributed uniformly with volume: the set of reservoirs with better than average injectivity comprises only 10% of the total volumetric storage capacity. Consequently, time weighted capacity on time scale of a few decades is 10% to 20% of the nominal volumetric capacity. The non-uniform distribution of injectivity and pore volume in the database coupled with multiphase flow effects yields a wide distribution of “filling times”, i.e. the time required to place CO₂ up to the boundaries of the formation. We define two limiting strategies based on fill times of the storage structures in the database and use them to calculate resource usage for a target storage rate. Since fill times are directly proportional to injectivity, smallest fill time corresponds to best injectivity and largest fill time corresponds to smallest injectivity. If best injectivity structures are used first, then the rate at which new structures would be needed is greater than if worst injectivity structures are used first. A target overall storage rate could be maintained for longer period of time when worst injectivity structures are used first. Because of the kh vs PV correlation, most of the pore volume remains unused when no extraction wells are used. Extraction wells require disposal of produced brine, which is a significant challenge, or beneficial use of the brine. An example of the latter is the surface dissolution process described in this thesis, which would enable use of a much greater fraction of the untouched pore volume.Item Geochemical effects of elevated methane and carbon dioxide in near-surface sediments above an EOR/CCUS site(2013-05) Hingst, Mary Catherine; Young, Michael H.; Romanak, Katherine DunckerCarbon capture, utilization and storage (CCUS) aims to reduce CO₂ emissions by capturing CO₂ from sources and injecting it into geologic reservoirs for enhanced hydrocarbon recovery and storage. One concern is that unintentional CO₂ and reservoir gas release to the surface may occur through seepage pathways such as fractures and/or improperly plugged wells. We hypothesize that CO₂ and CH₄ migration into the vadose zone and subsequent O₂ dilution and Eh and pH changes could create an increased potential for metal mobilization, which could potentially contaminate ground and surface waters. This potential has not been addressed elsewhere. Goals of this study are to understand how the potential for metal mobilization through soil pore water may increase due to CO₂ and CH₄ and to assess potential impact to aquifers and/or the biosphere. The study was conducted at a CCUS site in Cranfield, MS, where localized seepage of CH₄ (45%) from depth reaches the surface and oxidizes to CO₂ (34%) in the vadose zone near a plugged well. Four sediment cores (4.5-9m long) were collected in a transect extending from a background site through the area of anomalously high soil gas CO₂ and CH₄ concentrations. Sediment samples were analyzed for Eh and pH using slurries (1:1 vol. with DI water) in the field and for occluded gas concentrations, metal (Ba, Co, Cr, Cu, Fe, Mn, Ni, Pb and Zn) concentrations, moisture content, organic carbon content, and grain size in the laboratory. Data from the background reference area (no gas anomaly: occluded gas ~21% O₂, <1% CO₂, 0% CH₄) showed oxidized conditions (Eh from 464-508mV) and neutral pH (7.0-7.8) whereas samples collected near the gas anomaly (13-21% O₂, 0.1-5% CO₂, <0.1% CH₄) were more reducing (Eh 133-566mV) and more acidic (pH = 5.3-8.0). Significant correlations were found between Eh and O₂ (r = 0.95), pH and CO₂ (r = -0.88), and between these parameters and acid-leachable metals in samples from within the soil gas anomaly. Correlations quickly weaken away from the anomaly. Statistically, total metal concentrations, except for Ba, are similar in all cores. Acid-mobile metal concentrations, above 5m, increase toward the gas anomaly. The percent of water-mobile metals is very low (<2%) for all metals in all cores, indicating freely-mobile metals are not affected by elevated CO₂/CH₄. Conclusions are: 1) oxidation of CH₄ to CO₂ depletes O₂ causing reducing conditions; 2) high CO₂ and low O₂ affect Eh and pH of sediments which in turn alters mineralogy and bond strength between sediments and adsorbed ions; 3) intrusion of strongly acidic fluids (pH of acid used was 0.39) into these sediments could potentially remove weakly bonded metals or dissolve minerals. Implications from this study are that Eh needs to be considered along with pH when analyzing contamination potential, and that exposure of sediments to reducing, followed by acidic conditions, increases the potential for metal mobilization in the vadose zone. More research is needed to determine the concentration of gases (CO₂, CH₄ and O₂) that will create Eh and pH levels that could affect the mineralogy and sorption mechanism potentially leading to metal mobilization. Methods for assessing potential metal mobilization may be useful for site characterization and risk assessment.Item The geologic and economic analysis of stacked CO₂ storage systems : a carbon management strategy for the Texas Gulf Coast(2010-08) Coleman, Stuart Hedrick; Jablonowski, Christopher J.; Hovorka, Susan D.; King, Carey W.Stacked storage systems are a viable carbon management operation, especially in regions with potential growth in CO₂ enhanced oil recovery (EOR) projects. Under a carbon constrained environment, the industrial Texas Gulf Coast is an ideal area for development of stacked storage operations, with a characteristically high CO₂ intensity and abundance of aging oil fields. The development of EOR along the Texas Gulf Coast is limited by CO₂ supply constraints. A stacked storage system is implemented with an EOR project to manage the temporal differences between the operation of a coal-fired power plant and EOR production. Currently, most EOR operations produce natural CO₂ from geologic formations. A switch to anthropogenic CO₂ sources would require an EOR operator to handle volumes of CO₂ beyond EOR usage. The use of CO₂ in an EOR operation is controlled and managed to maximize oil production, but increasing injection rates to handle the volume of CO₂ captured from a coal plant can decrease oil production efficiency. With stacked storage operations, a CO₂ storage reservoir is implemented with an EOR project to maintain injection capacity equivalent to a coal plant's emissions under a carbon constrained environment. By adding a CO₂ storage operation, revenue can still be generated from EOR production, but it is considerably less than just operating an EOR project. The challenge for an efficient stacked storage project is to optimize oil production and maximize profits, while minimizing the revenue reduction of pure carbon sequestration. There is an abundance of saline aquifers along the Texas Gulf Coast, including the Wilcox, Vicksburg, and Miocene formations. To make a stacked storage system more viable and reduce storage costs, maximizing injectivity is critical, as storage formations are evaluated on a cost-per-ton injected basis. This cost-per-ton injected criteria, also established as injection efficiency, incorporates reservoir injectivity and depth dependant drilling costs to determine the most effective storage formation to incorporate with an EOR project. With regionally adequate depth to maximize injectivity while maintaining reasonable drilling costs, the Vicksburg formation is typically the preferred storage reservoir in a stacked storage system along the Texas Gulf Coast. Of the eleven oil fields analyzed on a net present value basis, the Hastings field has the greatest potential for both EOR and stacked storage operations.Item Grain-scale controls on seal integrity in mudrocks : capillary entry pressure and permeability prediction(2020-06-26) Bihani, Abhishek Dilip; Daigle, Hugh; Lake, Larry W; Prodanovic, Masa; Espinoza, David N; Hayman, Nicholas WMudrocks serve as geological traps and seals for carbon sequestration or for hydrocarbon formation, where mudrock capillary seals having high capillary entry pressure prevent the leakage of underlying fluids. However, they can fail if the buoyant pressure of the trapped fluid overcomes the threshold pressure of the seal. Mudrocks are composed primarily of silt-size and clay-size grains in various fractions. Microstructural observations of mudrocks have shown a silt bridging effect, whereby sufficiently abundant silt-size grains will create a stress chain across the rock matrix to preserve large pores and throats. At shallower depths, this effect can create a dual porosity system, consisting of larger pores and throats near the coarser grains, and smaller pores and throats existing only between the finer clay grains. If the preserved larger pores and throats are connected across a mudrock, it may increase the absolute permeability, and reduce the capillary threshold pressure and tortuosity, thereby decreasing its sealing capacity. Using pore-network modeling, artificial bidisperse grain packs (packings of two sizes) were generated, with and without the effect of gravity, to understand the effects of deposition and compaction on the petrophysical properties. It was observed that when the fraction of larger grains reaches about 40 - 60 % of the total volume of the grain pack, the capillary threshold transitions to a lower value and permits fluid percolation across the grain pack. The discrete element modeling (DEM) compaction simulations showed that on increasing large grain concentrations, strong force chains are formed across large-large and small-large grain contacts which decreases coordination numbers and shields larger pores. An image analysis workflow consisting of multiple filtering and user-guided segmentation steps was used to identify pores, silt grains, and clay from scanning electron microscope (SEM) images of sediments from the Kumano Basin offshore Japan. Statistical analysis showed that larger pores are better preserved when surrounded by detrital, silt size grains, and the presence of a higher fraction of silt-size grains led to a higher concentration of larger pores. The distributions of pore characteristics at different depths showed that larger pores are observed in samples with higher silt fractions despite being deeper. Since the images only offer a 2D view of the 3D rock structure, a digital rocks workflow was applied to reconstruct the mudrock pore space. Lattice Boltzmann simulations were run on the reconstructed grain packs to simulate capillary drainage using high-performance computing. The results showed that at all depths, the capillary threshold pressure for the grain packs with a higher silt fraction was lower than those with a lower silt fraction and that capillary threshold pressure also increased with depth. Thus, using a combination of pore-network modeling, DEM simulations, image analysis, and lattice Boltzmann simulations, I found that there is a significant dependence of the grain concentration and texture on the petrophysical properties. Improving our understanding about the influence of grain concentrations, spatial positions, and sizes on the fluid flow behavior is an important step towards a better characterization of mudrock seals and can help improve risk management efforts in anthropogenic waste storage and estimates of the reserve capacity of petroleum reservoirsItem High order stratigraphic framework of intraslope growth faulted subbasins offshore Matagorda Bay, Texas(2021-12-09) Franey, John D.; Meckel, Timothy AshworthCarbon capture and storage (CCS) is currently one of the leading atmospheric emission mitigation technologies. To have meaningful impact on the atmosphere CO₂ concentrations, megatons (10⁶) of CO₂ must be removed from the carbon cycle permanently. This requires a subsurface geologic storage sites that are both volumetrically significant and secure over geologic time-scales. The northern Gulf of Mexico (GOM) has the ability to serve as a major location for CCS. Miocene strandplain systems in the GOM are an ideal stratigraphy for such storage due to their proximity to emissions sources, quality sand reservoirs, and depth relative to overpressure. This study focuses on a suite of strike parallel subbasins within the Lower Miocene offshore Matagorda Bay, TX. Each subbasin has potential to serve as a future carbon sequestration site. Accurate mapping of subbasins’ stratigraphy is necessary to understand the variable thickness and associated risk of reservoir-sealing shale intervals, recognizing that injection beneath thicker, more uniformly distributed shales is more favorable. These intervals must be mapped at high resolution (4th order cyclicity) to understand the individual components in assessment and risk analysis. This research generates a novel dip-steered seismic volume which is leveraged to improve seismic attribute calculations and mapping at the 4th order. The dip-steered seismic volume records the seismic dip in the inline and crossline direction of seismic features at the intersection of every inline, crossline, and seismic sample. This volume is used to generate a model of dense, 3D, auto-tracked horizons across each subbasin. The models better connect high resolution, but sparse, well log data and low resolution, but continuous, seismic data. Thickness distributions and shale interval maps generated from the models aid in risk assessment. Based on the resulting shale thicknesses, the suite of subbasins should be further considered as future storage sitesItem Investigating the geochemical alterations in an aquifer due to long-term sequestration of CO2 using time-lapse seismic information(2015-12) Han, Sang Hyon; Sepehrnoori, Kamy, 1951-; Srinivasan, Sanjay; Sen, MrinalThe effects of chemical interaction between injected CO2, brine, and formation rocks are often ignored in sequestration studies because chemical reactions are assumed to be localized to carbonate rocks that make up only a small proportion of the potential reservoirs. It is conjectured in this work that long-term exposure of certain types of clays and cement material to CO2-brine mixtures can induce chemical reactions and subsequent alteration of rock properties that can be subsequently detected in time-lapse seismic surveys. This is demonstrated using a case-study structured after the Cranfield field injection site. Geochemical alterations of the reservoir rock are quantified by performing reactive transport simulations and subsequently using rock physics models to translate the altered petrophysical properties into seismic responses. The study quantifies the long-term geochemical effects of CO2 injection on the seismic response and conversely, presents an approach to invert the reservoir regions contacted by the CO2-saturated brine based on the observed seismic response. Time lapse or passive seismic monitoring is an effective method for mapping the progress of the CO2 plume through the subsurface. But, because of the lack of resolution of the seismic information, it is necessary to use the seismic information together with prior geologic knowledge about the surface in order to identify if there is any migration of CO2 into regions that might be deemed sensitive e.g. overlying aquifers or faults. Because of uncertainties in the prior geologic description of the reservoir, the feasibility of implementing a model selection process is explored in this work. The model selection procedure utilizes the observed well data and reference seismic map to select a subset of models. The flow simulation of CO2 injection and forward seismic modeling were repeated for the newly generated reservoir models, and the seismic responses were compared for the reaction and non-reaction cases. The study showed that the effects of geochemical reactions on petrophysical properties and resultant spatial distribution of fluid saturation were visible in the seismic response. Major differences in seismic responses were detected in regions of the reservoir where significant amount of minerals were dissolved and precipitated. These regions were at the top of the reservoir due to the reactions caused by the buoyant CO2 plume. The presence of carbonate facies, even in small proportion, plays an important role in geochemical reactions and their effect is manifested at the seismic scale. The unique model selection methodology presented in this thesis is efficient at detecting the important features in the seismic and injection response that is induced by the geochemical alterations occurring in the reservoir. The results of this time-lapse study can provide new interpretation of events observed in time-lapse seismic data that might lead to a better assessment of leakage pathways and other risks.Item Investigation of coupled thermo-chemo-mechanical processes for safe carbon geological storage(2018-11-01) Jung, Hojung; Espinoza, David N.; Wheeler, Marry F; DiCarlo, David A; Balhoff, Matthew T; Hosseini, Seyyed ASafe and permanent CO₂ storage in geological formations requires reservoir geomechanical stability. Injection of CO₂ into the subsurface changes the local pore pressure and, further, alters the effective stresses due to poro-thermo-chemo-mechanical coupled responses. Changes of pore pressure and effective stress may disrupt the host formation mechanical equilibrium. This alteration may result in geomechanical failure events such as fault reactivation and hydraulic fracturing. Such events can favor fluid migration paths for injected CO₂, induce seismic activity, and cause surface uplift. Examples of field observations during CO₂ injection include: (1) surface uplift at the In Salah project in Algeria, (2) absence if bottom-hole pressure (BHP) increase during injection in Cranfield, Mississippi, and (3) induced seismicity with magnitude M>1 in Decatur, Illinois. In this context, accurate estimations of pore pressure build up and local stress alteration induced by CO₂ injection are critical to avoid geomechanical perturbations. However, current models and predictions often assume relatively homogeneous reservoirs without taking into account compositional behavior. Further, the effects of temperature and chemical reactions have not been rigorously incorporated into the interpretation of local stress alteration and the well response to CO₂ injection. This dissertation shows geomechanical analyses of CO₂ geological sequestrations by three field case studies: Frio CO₂ sequestration pilot test in Texas, Cranfield CO₂ sequestration in Mississippi, and Crystal Geyser in Utah. Both Frio and Cranfield case studies are studied with the help of reservoir simulation and history matching of field data including assimilation of vertical heterogeneity from well-logging analysis and calibration with laboratory experiments. The Frio case study focuses on examination of reservoir capacity of a compartmentalized volume to avert fault reactivation. The Cranfield case study analyzes the influence of thermo-chemo-elastic processes on wellbore fracturing induced by CO₂ injection. The Crystal Geyser case study investigates the long-term chemical effects of CO₂-charged brine on rock mechanical properties through analyses and measurements on rock samples from the field, where a natural CO₂ leakage analog exists. The following conclusions are a result of this dissertation. CO₂ dissolution into brine reduces pore pressure build up significantly in small and compartmentalized reservoirs. Thermo-elastic and chemo-elastic effects alter local stresses and may trigger injector fracturing at bottom-hole pressures lower than expected. Capturing phase behavior, coupled thermo-chemo-mechanical processes, and reservoir heterogeneity are important factors to estimate reservoir capacity and prevent geomechanical perturbations.Item Microbial responses to CO₂ during carbon sequestration : insights into an unexplored extreme environment(2014-05) Santillan, Eugenio Felipe Unson; Bennett, Philip C. (Philip Charles), 1959-; Cardenas, Bayani; Shanahan, Timothy M; Omelon, Christopher R; Altman, Susan JWhen CO₂ is sequestered into deep saline aquifers, significant changes to the biogeochemistry of the system are inevitable and will affect native microbial populations both directly and indirectly. These communities are important as they catalyze many geochemical reactions in these reservoirs. We present evidence that the injection of CO₂ will cause a large scale disturbance to subsurface microbial populations which will ultimately affect the solution and mineral trapping of CO₂ as well as the movement of CO₂ charged water through the subsurface. Representative subsurface microorganisms including a Gram negative bacterium (G⁻), two Gram positive bacteria (G⁺), and an archaeon were tested for CO₂ survival at pressures up to 50 bar and exposure times up to 24 hours. CO₂ tolerance varied but shows effects on microbes is more complex than just decreasing pH and is not significantly dependent on cell wall structure. Imaging reveals that CO₂ disrupts the cytoplasm possibly from changes to intracellular pH. The geochemical effect of CO₂ stress is a decrease in metabolic activity such as Fe reduction and methanogenesis. Subsurface microbial populations interact with the surrounding reservoir minerals which likely influence their ability to survive under CO₂ stress. When the G⁻ organism was grown in the presence of a mineral substrate, survival depended on the mineral type. Quartz sandstone provided a good substrate for survival while kaolinite provided a poor substrate for survival. Biofilms on quartz sandstone were rich in extracellular polymeric substances (EPS) that likely act as a barrier to slow the penetration of CO₂ into the cell. The release of toxic metals from mineral dissolution at high PCO₂ enhanced cell death. To understand the long term effects of CO₂ on microbial communities, water samples were taken from CO₂ springs in the western United States and compared to unaffected springs. Community 16S rRNA sequence data suggests that CO₂ exposed environments exhibit lower microbial diversity, suggesting environmentally stressed communities. However, differences among diversity in the springs surveyed also indicates other environmental factors that affect diversity beyond CO₂. Furthermore, the isolation of a novel fermentative Lactobacillus strain from a CO₂ spring, indicates viable microbial communities can exist at high PCO₂.Item Potential value extraction from TxDOT’s right of way and other property assets(2011-12) Paes, Thiago Mesquita; Prozzi, Jolanda; Caldas, Carlos H.Many Departments of Transportation (DOTs), including Texas Department of Transportation (TxDOT), have been challenged by inadequate funding from traditional federal and state fuel taxes, increasing construction cost, aging highway system, traffic congestions, and recent natural disasters, compromising their primary mission to provide safe vehicle transportation routes with adequate capacity. Furthermore, environmental awareness and sustainability concept have strengthened and sparked debates in Congress, culminating with several regulatory policies that affect, inclusively, transportation projects. This scenario has prompted DOTs to pursue innovative ways to reduce maintenance cost (at minimum) and generate revenue (at maximum) exploiting their assets, and to meet the new regulations. Likewise, the Center of Transportation Research at The University of Texas at Austin undertook a comprehensive research study to identify and determine when, where, and under what circumstances TxDOT should pursue the implementation of which Value Extraction Application (VEA), and how to effectively recognize and involve key stakeholders. As a result, 11 VEAs were identified. In addition, a methodological framework – embedding a multi-attribute criteria analysis matrix as the decision making method - was devised to guide TxDOT throughout the process of identifying, evaluating, comparing, and selecting the most appropriate VEA while a list of stakeholders associated with each VEA and a stakeholder analysis framework was provided to help TxDOT to identify and reach out key stakeholders.Item Pre-injection reservoir evaluation at Dickman Field, Kansas(2011-08) Phan, Son Dang Thai; Sen, Mrinal K.; Srinivasan, Sanjay; Grand, StephenI present results from quantitative evaluation of the capability of hosting and trapping CO₂ of a carbonate brine reservoir from Dickman Field, Kansas. The analysis includes estimation of some reservoir parameters such as porosity and permeability of this formation using pre-stack seismic inversion followed by simulating flow of injected CO₂ using a simple injection technique. Liner et at (2009) carried out a feasibility study to seismically monitor CO₂ sequestration at Dickman Field. Their approach is based on examining changes of seismic amplitudes at different production time intervals to show the effects of injected gas within the host formation. They employ Gassmann's fluid substitution model to calculate the required parameters for the seismic amplitude estimation. In contrast, I employ pre-stack seismic inversion to successfully estimate some important reservoir parameters (P- impedance, S- impedance and density), which can be related to the changes in subsurface rocks due to injected gas. These are then used to estimate reservoir porosity using multi-attribute analysis. The estimated porosity falls within a reported range of 8-25%, with an average of 19%. The permeability is obtained from porosity assuming a simple mathematical relationship between porosity and permeability and classifying the rocks into different classes by using Winland R35 rock classification method. I finally perform flow simulation for a simple injection technique that involves direct injection of CO₂ gas into the target formation within a small region of Dickman Field. The simulator takes into account three trapping mechanisms: residual trapping, solubility trapping and mineral trapping. The flow simulation predicts unnoticeable changes in porosity and permeability values of the target formation. The injected gas is predicted to migrate upward quickly, while it migrates slowly in lateral directions. A large amount of gas is concentrated around the injection well bore. Thus my flow simulation results suggest low trapping capability of the original target formation unless a more advanced injection technique is employed. My results suggest further that a formation below our original target reservoir, with high and continuously distributed porosity, is perhaps a better candidate for CO₂ storage.Item Structural controls on CO₂ leakage and diagenesis in a natural long-term carbon sequestration analogue : Little Grand Wash fault, Utah(2011-08) Urquhart, Alexander Sebastian MacDonald; Meckel, Timothy Ashworth; Eichhubl, Peter; Laubach, Stephen E. (Stephen Ernest), 1955-; Flemings, Peter B; Hesse, Marc A; Tinker, Scott WThe Little Grand Wash normal fault near Green River, eastern Utah, hosts a series of naturally occurring CO₂ seeps in the form of active and extinct CO₂-charged springs distributed along the fault zone. I have studied the association of fault structure with CO₂-related alteration as an analogue for the long-term (1,000- to 10,000-year) effects of leakage through faults in CO₂ sequestration reservoirs. Structure and alteration in a portion of the Little Grand Wash fault zone were mapped at a 1:700 scale in order to determine the association of faulting with CO₂-related diagenesis. I combined structural and diagenetic mapping were combined with laboratory analyses of mineralogical, isotopic and textural changes in order to assess controls on the migration of CO₂ traveling up the fault and its effects on the fault itself. The fault zone is 200 m wide at its widest and contains 4-5 major subparallel fault segments that form multiple soft- and hard-linked relay ramps. The area includes a travertine deposit and related sandstone alteration: outcrop-visible coloration, porosity-occluding calcite cement and veins occasionally so abundant that they obliterate the rock fabric. Structural mapping shows that the travertine is located at an intersection of major fault segments constituting the hard link of a 450-meter-long relay ramp. Sandstone alteration is confirmed to be related to the CO₂ seep by mapping its distribution, which shows a decrease in concentration away from the travertine, and by the unique isotopic signature of calcite cement near the travertine. At distances greater than 25 m from the travertine intense alteration disappears, though scattered fault-subparallel veins and patchy, burial-related calcite cement remain. Intense alteration is limited to major fault overlaps and does not permeate the fault zone along its entire length, nor does it extend outside the zone. This indicates that rising CO₂-laden fluids do not flow uniformly through the entire fault zone, but that vertical flow is channeled at fault intersections. In thin section, porosity near the travertine has been extensively or completely occluded by calcite cement. Permeability in some conduit samples is less than 1 mD, three or four orders of magnitude lower than sandstone away from the travertine. In active CO₂ conduits, such reduction in porosity and permeability would occlude the preferred flow conduit and ultimately restrict upward flow of CO₂-charged water. X-ray diffraction detects small amounts of goethite and hematite and a decrease in chlorite-smectite in altered conduit sandstones. Calcite is abundant, but many authigenic minerals predicted by geochemical models of CO₂ influx into sandstone reservoirs are not observed, including kaolinite, aragonite, dolomite, siderite, ankerite or dawsonite. This difference between observed and predicted mineral occurrence likely results from differences in mineral kinetics between natural and laboratory systems. Prediction of leakage risk based on fault geometry improves the ability to assess the suitability of potential carbon sequestration reservoirs, many of which will be faulted. The point seep nature of leakage through a fault zone limits the amount of CO₂ that can escape over time and also enables targeted surface monitoring for CO₂ escape into the atmosphere--both critical for ensuring the effectiveness of injection projects and earning the trust necessary for carbon sequestration to gain public acceptance. The point seep nature of leakage also accelerates the rate at which conduits may seal through mineralization, since precipitation from a large volume of fluid is focused in a narrow conduit. The presence of multiple fossil and active seep locations along the Little Grand Wash fault, active at different times in the geologic past, indicates that cementation may be effective in sealing single conduits but that fault systems with complex geometry such as Little Grand Wash may continue to leak for a long period of time.Item Time-lapse seismic monitoring for enhanced oil recovery and carbon capture and storage field site at Cranfield field, Mississippi(2013-12) Ditkof, Julie Nicole; Bangs, Nathan Lawrence Bailey; Meckel, Timothy AshworthThe Cranfield field, located in southwest Mississippi, is an enhanced oil recovery and carbon sequestration project that has been under a continuous supercritical CO₂ injection by Denbury Onshore LLC since 2008. Two 3D seismic surveys were collected in 2007, pre-CO₂ injection, and in 2010 after > 2 million tons of CO₂ was injected into the subsurface. The goal of this study is to characterize a time-lapse response between two seismic surveys to understand where injected CO₂ is migrating and to map the injected CO₂ plume edge. In order to characterize a time-lapse response, the seismic surveys were cross equalized using a trace-by-trace time shift. A normalized root-mean-square (NRMS) difference value was then calculated to determine the repeatability of the data. The data were considered to have “good repeatability,” so a difference volume was calculated and showed a coherent seismic amplitude anomaly located through the area of interest. A coherent seismic amplitude anomaly was also present below the area of interest, so a time delay analysis was performed and calculated a significant added velocity change. A Gassmann-Wood fluid substitution workflow was then performed at two well locations to predict a saturation profile and observe post-injection expected changes in compressional velocity values at variable CO₂ saturations. Finally, acoustic impedance inversions were performed on the two seismic surveys and an acoustic impedance difference volume was calculated to compare with the fluid substitution results. The Gassmann-Wood fluid substitution results predicted smaller changes in acoustic impedance than those observed from acoustic impedance inversions. At the Cranfield field, time-lapse seismic analysis was successful in mapping and quantifying the acoustic impedance change for some seismic amplitude anomalies associated with injected CO₂. Additional well log data and refinement of the fluid substitution workflow and the model-based inversion performed is necessary to obtain more accurate impedance changes throughout the field instead of at a single well location.