Thesis (M.S.)--Ohio University, November, 2007. / Title from PDF t.p. Includes bibliographical references.

The accumulation of CO2 in the atmosphere is considered to be the main reason for the global warming effect. The emissions can be reduced substantially by capturing and storing the CO2. The CO2SINK project was Europe’s first onshore project for the geological storage and monitoring of CO2. This project started operation near the town of Ketzin, Germany in the North East German basin in April 2004 and has continued as the CO2MAN project since April 2010. The main focus of the project was to develop the basis for Carbon Capture and Storage techniques by injecting CO2 and monitoring of CO2 in a saline aquifer in order to develop confidence for future geological storage of CO2 in Europe. In September 2004, a pilot seismic survey was performed in order to determine the necessary parameters for the conduction of a later 3D baseline seismic survey[i].  The pilot survey was performed along two perpendicular profiles near to the CO2 injection site. Pseudo 3D and 2D reflection seismic data were acquired. The results from 2D processing of the data contributed to planning of the 3D baseline survey. In this study the pseudo 3D data from the pilot seismic reflection survey is used to perform 3D processing for the first time. A significant part of the study is the correlation of results with the 3D baseline seismic survey and borehole data. All significant horizons, possible faults and traces of remnant gas were identified. Correlation with the 3D baseline, integration with the borehole data and time/depth contour maps showed good agreement with the 3D baseline survey and well log data. Low fold data, acquisition geometry, time shifts and source generated noise produces severe distortion in the data. Due to these limitations it was difficult to obtain good quality images. Careful processing that involved static corrections and more accurate velocity analysis were the key steps for successful imaging. These results were combined with bore-hole information for an integrated interpretation.

Thesis--Auburn University, 2009. / Abstract. Includes bibliographic references (p.71-87).

The increased level of greenhouse gases due to human activity is the main factor for climate change. CO2 is the main constitute among these gases. Subsurface storage of CO2 in geological systems such as coal reservoirs is considered as one of the promising perspectives. Coal can be safely and effectively utilized to both store CO2 and recover CH4. By injecting CO2 into the coal beds, methane is released with CO2 adsorption in the coal matrix and this process is known as enhanced coal bed methane recovery (ECBM). Zonguldak Coal Basin is one of the Turkey&amp / #8217 / s important coal resources. Since the coal seams in Bartin-Amasra field are found relatively deeper parts of the basin comparing to other places, this basin was not studied detailed enough yet. Bartin-Amasra basin was found convenient for enhanced coalbed methane recovery. The lithologic information taken from the Turkish Hard Coal Enterprise (TTK) was examined and the depths of the coal seams and the locations of the wells were visualized to perform a reliable correlation between seams existed in the area. According to the correlations, 63 continuous coal layers were found. A statistical reserve estimation of each coal layer for methane was made by using Monte Carlo simulation method. Uncertainty is an important parameter in risk analysis, for this reason the results were determined at probabilities of P10, P50 and P90. Enhanced coalbed methane recovery was simulated with CMG-GEM module using Coal Layer #26 which has more initial gas in place. The effects of adsorption, cleat spacing, compressibility, density, permeability, permeability anisotropy, porosity and water saturation parameters were examined in enhanced coalbed methane recovery by the simulation runs. The initial methane in place found in all these coal layers both in free and adsorbed states were estimated using probabilistic calculations resulted in possible reserve (P10) of 72.97 billion scf, probable reserve (P50) of 47.74 billion scf and proven reserves (P90) of 30.46 billion scf. Since the Amasra coal reservoir is not saturated with water, almost 10% of the total gas in place was found to be in the cleats as free gas. Coal layer #26 has an area of 4099 acres, average thickness of 6.23 ft and depth of 545 m (Karadon formation). P50 reserve estimation was 6.47 billion scf in matrix and 0.645 billion scf in fracture. Although the decrease in cleat porosity was less when shrinkage and swelling effects included, the decrease in cleat permeability as a function of porosity diminished the methane production. Cumulative methane production was enhanced with the injection of carbon dioxide (ECBM) approximately 23% than that of CBM recovery. Although closing the wells to production because of CO2 breakthrough had a negative effect on methane production initially, there was no difference between ultimate methane productions whether the wells remained open or closed, but more carbon dioxide was sequestered when the production ceased at the wells. Injected carbon dioxide amount of 5192 tonnes/year in base case was only capable to sequester only 0.3% of the yearly carbon dioxide emission of Zonguldak &Ccedil / atalagzi Power Plant nearby. Considering the gas in place capacity of the coal layer #26 as 15% of the resource area-A, it can be said that the project aiming ECBM recovery rather than carbon dioxide sequestration would be successful. In spite of water saturated coal reservoirs where the water production is required initially, it can be possible to start immediately the injection of CO2 with methane production for a dry coal reservoir. Cleat permeability being one of the most crucial parameter in the coal reservoir affected the rate of methane production. The more free gas was found in higher porosity cleat systems. Although the cumulative methane production was increased when the cleat porosity rose, methane recovery percentages were remained almost constant. The lower the cleat spacing the higher the rate of transfer between fracture and matrix was observed. The rate of gas desorption from the coal matrix and subsequent diffusion to both butt and face cleats was higher than the rate of flow in the face cleats, then production was flow-limited, pressure-driven and was defined by Darcy&amp / #8217 / s Law. The cumulative CH4 production was higher when the coal was denser. The change in coal compressibility affected slightly the cleat porosity and therefore the cleat permeability due to the change in reservoir pressure. Langmuir volume is defined as maximum adsorption capacity. Kozlu formation (deeper than Karadon formation) having lower Langmuir volume resulted in higher ultimate recovery because of lower Langmuir pressure than that of Karadon formation. In base case (Karadon formation), although the higher Langmuir volume was used, less methane production was observed. Permeability anisotropy generated the CO2-CH4 front in elliptic shape.

The combustion of fossil fuels results in the release of carbon dioxide to the atmosphere, a known greenhouse gas. Evidence suggests that “most of the observed increase in global average temperatures…is very likely due to the observed increase in anthropogenic greenhouse gas concentrations” (IPCC, 2007). One solution currently being examined is carbon capture and storage (CCS). The advantage of CCS is that it does not require an actual reduction in the amount of carbon dioxide emissions created, but reduces emissions to the atmosphere by storing the greenhouse gases in the subsurface. Fundamentally, CCS works in the reverse of oil and gas production. Instead of extracting fluids from the subsurface, CCS injects carbon dioxide (CO2) into the pore spaces of developed oil and gas reservoirs, saline aquifers, or coal bed seams (Bachu, 2007), where it exists in a dense but low-viscosity phase (Supercritical state). The Gulf Coast Carbon Center, based at the University of Texas at Austin’s Bureau of Economic Geology, is currently evaluating the State of Texas Offshore Lands (STOL) in the Gulf of Mexico (GOM) in order to evaluate the carbon-storage capacity in the state owned lands. “Capacity is defined as the volume fraction of the subsurface within a stratigraphic interval available for [CO2] sequestration” (Hovorka, 2004). There are a variety of methods currently used to calculate capacity. With so many options, how does a project decide which method to employ in determining capacity? This paper discusses the methods, presents an analysis of the benefits and drawbacks of the various methods, and develops a process for future projects to utilize in determining which methodology to employ. Additionally, storage capacity is calculated using the various methods presented, in order to compare the methods and understand their various advantages and drawbacks. Reservoir specific simulations are expected to predict smaller capacities in comparison to more broad static methods. This will provide end member predictions of capacity, shedding light on what can be expected in best case and worst case scenarios. The lessons learned from this study can be applied to future endeavors and formations all over the world. / text

The increasing concentration of CO_(2) has been linked to global warming and changes in climate. Geologic sequestration of CO_(2) in deep saline aquifers is a proposed greenhouse gas mitigation technology with potential to significantly reduce atmospheric emissions of CO_(2). Feasibility assessments of proposed sequestration sites require realistic and computationally efficient models to simulate the subsurface pressure response and monitor the injection process, and quantify the risks of leakage if there is any. This study investigates the possibility of obtaining closed form expressions for spatial distribution of CO_(2) injected in brine aquifers and gas reservoirs. Four new semi-analytical solutions for CO_(2) injection in brine aquifers and gas reservoirs are derived in this dissertation. Both infinite and closed domains are considered in the study. The first solution is an analysis of CO_(2) injection into an initially brine-filled infinite aquifer, exploiting self–similarity and matched asymptotic expansion. The second is an expanding to the first solution to account for CO_(2) injection into closed domains. The third and fourth solutions are analyzing the CO_(2) injection in infinite and closed gas reservoirs. The third and fourth solutions are derived using Laplace transform. The brine aquifer solutions accounted for both Darcyian and non-Darcyian flow, while, the gas reservoir solutions considered the gas compressibility variations with pressure changes. Existing analytical solutions assume injection under constant rate at the wellbore. This assumption is problematic because injection under constant rate is hard to maintain, especially for gases. The modeled injection processes in all aforementioned solutions are carried out under constant pressure injection at the wellbore (i.e. Dirichlet boundary condition). One major difficulty in developing an analytical or semi-analytical solution involving injection of CO_(2) under constant pressure is that the flux of CO_(2) at the wellbore is not known. The way to get around this obstacle is to solve for the pressure wave first as a function of flux, and then solve for the flux numerically, which is subsequently plugged back into the pressure formula to get a closed form solution of the pressure. While there is no simple equation for wellbore flux, our numerical solutions show that the evolution of flux is very close to a logarithmic decay with time. This is true for a large range of the reservoir and CO_(2) properties. The solution is not a formation specific, and thus is more general in nature than formation-specific empirical relationships. Additionally, the solution then can be used as the basis for designing and interpreting pressure tests to monitor the progress of CO_(2) injection process. Finally, the infinite domain solution is suitable to aquifers/reservoirs with large spatial extent and low permeability, while the closed domain solution is applicable to small aquifers/reservoirs with high permeability.

Started as an EOR technique to produce oil, injection of carbon dioxide which is essentially a greenhouse gas is becoming more and more important. Although there are a number of mathematical modeling studies, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments to characterize relevant chemical reactions associated with injection and storage of CO2 in carbonate formations. Porosity changes along the core plugs and the corresponding permeability changes are reported for varying CO2 injection rates, temperature and salt concentrations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. It was observed that either a permeability improvement or a permeability reduction can be obtained. The trend of change in rock properties is very case dependent because it is related to distribution of pores, brine composition and as well the thermodynamic conditions. As the salt concentration decreased the porosity and thus the permeability decrease was less pronounced. Calcite scaling is mainly influenced by orientation and horizontal flow resulted in larger calcite deposition compared to vertical flow. The duration of CO2 &ndash / rock contact and the amount of area contacted by CO2 seems to have a more pronounced effect compared to rate effect. The experiments were modeled using a multi-phase, non-isothermal commercial simulator where solution and deposition of calcite were considered by the means of chemical reactions. The calibrated model was then used to analyze field scale injections and to model the potential CO2 sequestration capacity of a hypothetical carbonate aquifer formation. It was observed that solubility and hydrodynamic storage of CO2 is larger compared to mineral trapping.

Thesis(M.S.)--Auburn University, 2007. / Abstract. Vita. Includes bibliographic references (p.103-108).

Sequestration of carbon dioxide (CO2) into subsurface porous sandstone is proposed as a method for reducing accumulation of anthropogenic emissions of CO2 into the atmosphere. Natural exposures of reservoir and top-seal pairs in central and southeastern Utah are identified as analogs to proposed CO2 injection targets. Reservoir and top-seal pairs in natural analog exposures are analyzed in tandem to evaluate evidence for paleo-migration of fluids and/or hydrocarbons from the reservoir through the top seal. The San Rafael Swell and Monument Uplift exhibit similar structure and exposures of Jurassic units yet differ in amount and type of host rock alteration due to variable amounts and types of fluids and/or hydrocarbons that migrated along faults and fractures. Macroscopic scale analysis of each monocline included processing of satellite imagery, and creation of depth contour maps. At the mesoscopic scale, fracture spacing acquired from scanline station measurements identified increased fracture frequency in proximity to major fault zones. At the microscopic scale, percentage of degradation and type of mineralization in pore space were used to verify increased fluid flow in proximity to major fault zones. Faults with possible intersections with multiple antithetic faults at depth have an increased probability of allowing for upward migration of fluids and/or hydrocarbons along the fault plane and damage zone, effectively bypassing the top sealing formations. Fault leakage potential maps identified areas where seal bypass along major faults would likely occur during sequestration of CO2. The method was validated by identifying potential migration pathways for oil seeps on the Little Grand Wash fault in central Utah. The San Rafael Swell was geometrically modeled through restoration of eroded formation tops along the fold axis to quantify the interaction between an outward migrating CO2 plume and varying degrees of faulting and fracturing. Analysis of the migration of a CO2 plume front through time exhibits an increasing probability of the outward migrating plume intersecting a leaking feature, with the highest probability of the advancing plume intersecting a potentially leaking feature achieved when faults with 1+ km trace length and mean fracture spacing of 17 cm are taken into consideration. (177 pages)

Carbon dioxide (CO2) is formed when fossil fuels such as oil, gas and coal are burned in power producing plants. CO2 is naturally found in the atmosphere as part of the carbon cycle, however it becomes a primary greenhouse gas when human activities disturb this natural balanced cycle by increasing levels in the atmosphere. In light of this fact, greenhouse gas mitigation strategies have garnered a lot of attention. Carbon capture, utilization and sequestration (CCUS) has emerged as a possible strategy to limit CO2 emissions into the atmosphere. The technology involves capturing CO2 at the point sources, using it for other markets or transporting to geological formations for safe storage. This thesis aims to understand and probe the chemistry of the reactions between CO2 and iron-bearing sediments to ensure secure storage for millennia. The dissertation work presented here focused on trapping CO2 as a carbonate mineral as a permanent and secure method of CO2 storage. The research also explored the use of iron-bearing minerals found in the geological subsurface as candidates for trapping CO2 and sulfide gas mixtures as siderite (FeCO3) and iron sulfides. Carbon dioxide sequestration via the use of sulfide reductants of the iron oxyhydroxide polymorphs lepidocrocite, goethite and akaganeite with supercritical CO2 (scCO2) was investigated using in situ attenuated total reflection Fourier transform infrared spectroscopy (ATR-FTIR), X-ray diffraction (XRD) and transmission electron microscopy (TEM). The exposure of the different iron oxyhydroxides to aqueous sulfide in contact with scCO2 at ~70-100 ˚C resulted in the partial transformation of the minerals to siderite (FeCO3). The order of mineral reactivity with regard to siderite formation in the scCO2/sulfide environment was goethite < lepidocrocite ≤ akaganéite. Overall, the results suggested that the carbonation of lepidocrocite and akaganéite with a CO2 waste stream containing ~1-5% H2S would sequester both the carbon and sulfide efficiently. Hence, it might be possible to develop a process that could be associated with large CO2 point sources in locations without suitable sedimentary strata for subsurface sequestration. This thesis also investigates the effect of salinity on the reactions between a ferric-bearing oxide phase, aqueous sulfide, and scCO2. ATR-FTIR was again used as an in situ probe to follow product formation in the reaction environment. X-ray diffraction along with Rietveld refinement was used to determine the relative proportion of solid product phases. ATR-FTIR results showed the evolution of siderite (FeCO3) in solutions containing NaCl(aq) concentrations that varied from 0.10 to 4.0 M. The yield of siderite was greatest under solution ionic strength conditions associated with NaCl(aq) concentrations of 0.1-1 M (siderite yield 40% of solid product) and lowest at the highest ionic strength achieved with 4 M NaCl(aq) (20% of solid product). Based partly on thermochemical calculations, it is suggested that a decrease in the concentration of aqueous HCO3- and a corresponding increase in co-ion formation, (i.e., NaHCO3) with increasing NaCl(aq) concentration resulted in the decreasing yield of siderite product. At all the ionic strength conditions used in this study, the most abundant solid phase product present after reaction was hematite (Fe2O3) and pyrite (FeS2). The former product likely formed via dissolution/reprecipitation reactions, whereas the reductive dissolution of ferric iron by the aqueous sulfide likely preceded the formation of pyrite. These in situ experiments allowed the ability to follow the reaction chemistry between the iron oxyhr(oxide), aqueous sulfide and CO2 under conditions relevant to subsurface conditions. Furthermore, very important results from these small-scale experiments show this process can be a potentially superior and operable method for mitigating CO2 emissions. / Chemistry