Browsing by Subject "Carbon dioxide storage"
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Item Carbon dioxide storage in geologically heterogeneous formations(2013-12) Chang, Kyung Won; Hesse, Marc; Nicot, Jean-Philippe, 1958-Geological carbon dioxide (CO₂) storage in deep geological formations can only lead to significant reductions in anthropogenic CO₂ emissions if large amounts of CO₂ can be stored safely. Determining the storage capacity, which is the volume of CO₂ stored safely, is essential to determine the feasibility of geological CO₂ storage. One of the main constraints for the storage capacity is the physical mechanisms of fluid flow in heterogeneous formations, which has not been studied sufficiently. Therefore, I consider two related problems: a) the evolution of injection-induced overpressure that determines the area affected by CO₂ storage and b) the rate of buoyant fluid flow along faults that determines the leakage of CO₂. I use a layered model of a sandstone reservoir embedded in mudrocks to quantify the increase in storage capacity due to dissipation of overpressure into the mudrocks. I use a model of a fault surface with flow barriers to constrain the reduction in the buoyancy-driven leakage flux across the fault. Using the layered model with injection at constant rate, I show that the pressure evolution in the reservoir is controlled by the amount of overpressure dissipated into ambient mudrocks. A main result of this study is that the pressure dissipation in a layered reservoir is controlled by a single dissipation parameter, M, that is identified here for the first time. I also show that lateral pressure propagation in the storage formation follows a power-law governed by M. The quick evaluation of the power-law allows a determination of the uncertainty in the estimate of the storage capacity. To reduce this uncertainty it is important to characterize the petrophysical properties of the mudrocks surrounding the storage reservoir. The uncertainty in mudrock properties due to its extreme heterogeneity or limited data available can cause large variability in these estimates, which emphasizes that careful characterization of mudrock is required for a reliable estimate of the storage capacity. The cessation of the injection operation will reduce overpressure near the injector, but regional scale pressure will continue to diffuse throughout the whole formation. I have been able to show that the maximum radius of the pressure plume in the post-injection period is approximately 3.5 times the radius of the pressure plume at the cessation of injection. Two aquifers can be hydraulically connected by a fault cutting across the intermediate aquitard. If the upper aquifer contains denser fluid, an exchange flow across the fault will develop. The unstable density stratification leads to a fingering pattern with localized zones of upwelling and downwelling along the fault. Due to the small volume of the fault relative to the aquifers, the exchange-flow will quickly approach a quasi steady state. If the permeability of the fault plane is homogeneous, the average number of the quasi-steady plume fingers, (nu), scales with the square root of the Rayleigh number Ra and the exchange flux measured by dimensionless convective flux, the Sherwood number, Sh, is a linear function of Ra. The dispersive flux perpendicular to the flow direction induces the formation of wider fingers and subsequently the less convective flux parallel to the flow direction. In the flow system with larger Ra, even the same increase in transverse dispersivity [alpha]T causes stronger impact of the mechanical dispersion on the vertical exchange flow so that (nu) and Sh reduce more with larger [alpha]T . Both measured characteristics, however, follow the same scaling for the non-dispersive homogeneous case by using a modified Rayleigh number, Ra*, considering the mechanical dispersion. The presence of flow barriers along the fault triggers unsteady exchange flow and subsequently controls the growth of the plume fingers. If the barriers are sufficiently wide to dominate the flow system, they create preferential pathways for exchange flow that determines the distribution of the quasi-steady fingers, and (nu) converges to a constant value. In addition, wider barriers induce substantial lateral spreading and enhance the efficiency of structural trapping, and reduce the exchange rate but still follows a linear relationship function of the effective Rayleigh number, Raeff , defined by the vertical effective permeability. This study is motivated by geological CO₂ storage in brine-saturated aquifer, but the effect of geological heterogeneity is also important in many other geological and engineering applications, in particular the risk assessment of the injection operations or the migration of hydrocarbons in tectonic-driven or hydraulically developed faults in reservoirs. Better understanding of fluid flow in geologically heterogeneous formations will allow more precise estimate of the reservoir capacity as well as more efficient operation of injection or production wells.Item Empirical analysis of fault seal capacity for CO₂ sequestration, Lower Miocene, Texas Gulf Coast(2012-05) Nicholson, Andrew Joseph; Meckel, Timothy Ashworth; Tinker, Scott W. (Scott Wheeler); Trevino, Ramon H.; Steel, Ronald J.The Gulf Coast of Texas has been proposed as a high capacity storage region for geologic sequestration of anthropogenic CO₂. The Miocene section within the Texas State Waters is an attractive offshore alternative to onshore sequestration. However, the stratigraphic targets of interest highlight a need to utilize fault-bounded structural traps. Regional capacity estimates in this area have previously focused on simple volumetric estimations or more sophisticated fill-to-spill scenarios with faults acting as no-flow boundaries. Capacity estimations that ignore the static and dynamic sealing capacities of faults may therefore be inaccurate. A comprehensive fault seal analysis workflow for CO₂-brine membrane fault seal potential has been developed for geologic site selection in the Miocene section of the Texas State Waters. To reduce uncertainty of fault performance, a fault seal calibration has been performed on 6 Miocene natural gas traps in the Texas State Waters in order to constrain the capillary entry pressures of the modeled fault gouge. Results indicate that modeled membrane fault seal capacity for the Lower Miocene section agrees with published global fault seal databases. Faults can therefore serve as effective seals, as suggested by natural hydrocarbon accumulations. However, fault seal capacity is generally an order of magnitude lower than top seal capacity in the same stratigraphic setting, with implications for storage projects. For a specific non-hydrocarbon producing site studied for sequestration (San Luis Pass salt dome setting) with moderately dipping (16°) traps (i.e. high potential column height), membrane fault seal modeling is shown to decrease fault-bound trap area, and therefore storage capacity volume, compared with fill-to-spill modeling. However, using the developed fault seal workflow at other potential storage sites will predict the degree to which storage capacity may approach fill-to-spill capacity, depending primarily on the geology of the fault (shale gouge ratio – SGR) and the structural relief of the trap.Item Model-based cost analysis for pressure and geochemical-based monitoring methods in CO2-EOR fields: application to field A(2016-05) Bolhassani, Behnaz; Young, Michael H.; Hovorka, Susan D.; Sun, Alexander Y.Decision making using monitoring data from CO2 geological storage (GS) projects can be multifaceted and complex because of geological, environmental, political, and economic factors. This study primarily focuses on economic and technical aspects of monitoring projects for CO2. The focus of this research is to compare the economic effectiveness of pressure-based monitoring (PBM) and geochemical-based monitoring (GBM) on CO2 leakage detection in CO2-EOR sites where risk for leakage assumed to be plugged and abandoned (P&A) wells, however methodology can be easily applied to CO2 storage in saline aquifers as well. PBM can detect leakage from pressure anomalies, while GBM method detects leakage from alteration in fluid chemistry. In this paper, analytical and semi-analytical models for PBM and GBM techniques were applied to calculate the number of monitoring wells required for monitoring anomalies, which could be due to leakage of CO2. In this study, we assumed that leakage through P&A wells represents the main risk factor. The goals of this study are to determine the cost effectiveness of PBM and GBM as a means to maximize the spatial coverage of the monitoring network in the vicinity of P&A wells. We used different analytical models for PBM and GBM, and overlaid the spatial coverage of each well onto a typical Texas Gulf Coast field site (known as Field A), thus identifying the intersection of each monitoring well and potentially leaking P&A well. Then, based on the available cost data, the costs of each PBM and GBM well were estimated and the two monitoring techniques were compared economically, assuming a pre-determined budget is available to invest on monitoring. The results showed that the spatial coverage of each PBM well was much higher than each GBM wells, and that the total capital and operational cost per PBM well was lower than each GBM well. For theoretical site used in this work, only 29 PBM wells were needed for full coverage of the field site, while 169 GBM wells were required. Therefore, we concluded that PBM technique is a more cost effective option, considering the parameters and assumption in this case study.