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. / text

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. / text

The Late Jurassic Brae oilfields in the South Viking Graben of the northern North Sea contain naturally high concentrations of carbon dioxide (up to 35 mol %). Fields immediately adjacent to the graben bounding fault display the highest concentrations, with CO2 content decreasing eastward into the basin. It is thought the CO2 was introduced into the region via this fault. This thesis examines the possible source of the high CO2 present in the region, focusing on the graben margin fault as a potential conduit for CO2 flux from depth Investigation of cored sections penetrating the graben bounding fault revealed numerous carbonate cemented fracture arrays. The morphology of the fractures and cements is attributed to hydraulic fracturing induced by episodic release of overpressured fluids up the margin fault from depth. Periods of rapid subsidence omnipresent throughout the tectonic history of the graben are conducive to the generation of overpressure; a feature commonly reported in the region. Samples from the carbonate fracture cements were analysed using a host of techniques, including SEM, EMPA, fluid inclusion, and stable δ13C ‐ δ18O analyses. Using SEM analysis, at least five generations of dolomite cement with concomitant iron sulphide were observed. Cement chemistry and textures indicate precipitation from concentrated CO2–rich fluids. A reported high salinity basinal influx from depth concomitant with proposed CO2 charge into the region ~70 Ma is a probable source for the dissolved solids subsequently precipitated as carbonate in the fracture networks. Fluid inclusion analysis provided sufficient evidence to suggest the influx of hot fluids into the region, presumably sourced from deep in the margin fill. Two distinct δ13C vs. δ18O trends are observed in the isotope data from four wells studied. The trends are interpreted as differential mixing between ascending basinal fluids rich in dissolved inorganic carbon and in situ formation waters dominated by organically derived carbon following the onset of thermal decarboxylation in the Kimmeridge Clay Formation. Dissolution of Zechstein carbonates underlying the region is a credible source for the isotopically heavy CO2 found adjacent to the graben margin (δ13CCO2 = ‐2 to ‐5 ‰) and incorporated into the carbonate cements. Inferred variations in fluid mixing from well to well have implications on the variability of fluid flow along the graben margin with respect to contrasting fault morphologies. A Rayleigh fractionation model accommodating CO2 degassing from a hot ascending isotopically heavy fluid can be invoked to explain the observed carbon‐oxygen isotopic covariations in the fracture cements. Geochemical modelling simulating the ascent of CO2‐rich waters suggests degassing has limited impact on precipitation volumes, with fluid‐rock reactions the most likely driver for extensive carbonate mineralisation observed.

A dissertation submitted to the Faculty of Engineering and the Built Environment, University of the Witwatersrand, Johannesburg, in fulfilment of the requirements for the degree of Master of Science in Engineering. 10 February, 2017. / Climate change due to the ever-increasing emission of anthropogenic greenhouse gases arising from the use of fossil fuels for power generation and most industrial processes is now a global challenge. It is therefore imperative to develop strategies or modern technologies that could mitigate the effect of global warming due to the emission of CO2. Carbon capture and storage (CCS) is a viable option that could ensure the sustainable use of cheap fossil fuels for energy generation with less CO2 emission. Amongst existing CCS technologies, absorption technology using monoethanolamine (MEA) is very mature and widely embraced globally. However, the absorption technology has a lot of challenges such as, low CO2 loading, high energy requirement for solvent regeneration, corrosive nature etc. On this note, the adsorption technology using solid sorbents is being considered for CO2 capture due to its competitive advantages such as flexibility, low energy requirement for sorbent regeneration, non-corrosive nature etc. On the other hand, adsorbents have a very vital role to play in adsorption technology and there is need to understand the behaviour of adsorbents for CO2 capture under different operating conditions in order to adapt them for wider applications. On this note, the study contained in this dissertation investigated the adsorption behaviour of a novel polymer-based adsorbent (polyaspartamide) during post-combustion CO2 capture using experimental study and mathematical modelling approach. Polyaspartamide is an amine-rich polymer widely used in drug delivery. In addition, its rich amine content increases its affinity for CO2. Its porosity, thermal stability and large surface area make it a promising material for CO2 capture. In view of this, polyaspartamide was used as the adsorbent for post-combustion CO2 capture in this study. This dissertation investigated the kinetic behaviour, the diffusion mechanism and rate limiting steps (mass transfer limitation) controlling the CO2 adsorption behaviour of this adsorbent. Furthermore, effect of impurities such as moisture and other operating variables such as temperature, pressure, inlet gas flow rate etc. on the CO2 adsorption behaviour of polyaspartamide was also investigated. Existing mathematical models were used to understand the kinetics and diffusion limitation of this adsorbent during CO2 capture. Popularly used gas-solid adsorption models namely; Bohart- Adams and Thomas model were applied in describing the breakthrough curves in order to ascertain the equilibrium concentration and breakthrough time for CO2 to be adsorbed onto polyaspartamide. Lagergren’s pseudo 1st and 2nd order models as well as the Avrami kinetic models were used to describe the kinetic behaviour of polyaspartamide during post-combustion CO2 capture. Parameter estimations needed for the design and optimization of a CO2 adsorption system using polyaspartamide were obtained and presented in this study. The Boyd’s film diffusion model comprising of the interparticle and intra-particle diffusion models were used to investigate the effect of mass transfer limitations during the adsorption of CO2 onto polyaspartamide. Data obtained from continuous CO2 adsorption experiments were used to validate the models in this study. The experiments were conducted using a laboratory-sized packed-bed adsorption column at isothermal conditions. The packed bed was attached to an ABB CO2 analyser (model: ABB-AO2020) where concentrations of CO2 at various operating conditions were obtained. The results obtained in this study show that temperature, pressure and gas flow rate had an effect on the adsorption behaviour of polyaspartamide (PAA) during CO2 capture. Polyaspartamide exhibited a CO2 capture efficiency of 97.62 % at the lowest temperature of 303 K and pressure of 2 bar. The amount of CO2 adsorbed on polyaspartamide increased as the operating pressure increased and a decrease in the adsorption temperature resulted in increased amount of CO2 adsorbed by polyaspartamide. The amounts of CO2 adsorbed on polyaspartamide were 5.9, 4.8 and 4.1 mol CO2/kg adsorbent for adsorption temperatures of 303, 318 and 333 K, respectively. The maximum amount of CO2 adsorbed by polyaspartamide at different flow rates of 1.0, 1.5 and 2.5 ml/s of the feed gas were 7.84, 6.5 and 5.9 mmol CO2/g of adsorbent. This shows that higher flow rates resulted in decreased amount of CO2 adsorbed by polyaspartamide because of low residence time which eventually resulted in poor mass transfer between the adsorbent and adsorbate. Under dry conditions, the adsorption capacity of polyaspartamide was 365.4 mg CO2/g adsorbent and 354.1 mgCO2/g adsorbent under wet conditions. Therefore, the presence of moisture had a negligible effect on the adsorption behaviour of polyaspartamide. This is very common with most amine-rich polymer-based adsorbents. This could be attributed to the fact that CO2 reacts with moisture to form carbonic acid, thereby enhancing the CO2 adsorption capacity of the material. In conclusion, this study confirmed that the adsorption of CO2 onto polyaspartamide is favoured at low temperatures and high operating pressures. The adsorption of CO2 onto polyaspartamide was governed by film diffusion according to the outcome of the Boyd’s film diffusion model. It was also confirmed that intra-particle diffusion was the rate-limiting step controlling the adsorption of CO2 onto polyaspartamide. According to the results from the kinetic study, it can be inferred that lower temperatures had an incremental effect on the kinetic behaviour of polyaspartamide, external mass transfer governed the CO2 adsorption process and the adsorption of CO2 onto polyaspartamide was confirmed to be a physicochemical process (both physisorption and chemisorption). / MT2017

The CO2SINK (and CO2MAN) project is the first onshore CO2 storage project in Europe. The research site is located near the town of Ketzin, close to Potsdam in Germany. Injection started in June 2008, with a planned injection target of 100,000 tonnes of CO2. In February 2011, around 45, 000 tons of CO2 had been injected into the saline aquifer at an approximate depth of 630 m. This thesis focuses on time-lapse analysis of borehole seismic data, surface seismic data and reservoir characterization at the Ketzin site. Baseline Moving Source Profiling (MSP) data were acquired in the borehole Ketzin 202/2007 (OW2), along seven lines in 2007. The zero-offset Vertical Seismic Profile (VSP) data were acquired in the same borehole. The main objective of the VSP and MSP survey was to generate high-resolution seismic images around the borehole. After modeling and data processing, the sandy layers within the Stuttgart Formation can potentially be imaged in the VSP and MSP data whereas reflections from these layers are not as clearly observed in the 3D surface seismic data. 2D and pseudo-3D time-lapse seismic surveys were conducted at the Ketzin site. Interpretation of 2D baseline and repeat stacks shows that no CO2 leakage related time lapse signature is observable where the 2D lines allow monitoring of the reservoir. This is consistent with the time-lapse results of the 3D surveys showing an increase in reflection amplitude just centered around the injection well. The results from the pseudo-3D surveys are also consistent with the 3D seismic time-lapse studies and show that the sparse pseudo-3D geometry can be used to qualitatively map the CO2 in the reservoir with significantly less effect than the full 3D surveying. The 2nd pseudo-3D repeat survey indicates preferential migration of the CO2 to the west. There are no indications of migration into the caprock on either of the repeat surveys. Amplitude Versus Offset (AVO) analysis was performed on both 2D and 3D repeat surveys. A Class 3 AVO anomaly is clearly observed on the 3D repeat data and matches the synthetic modeling well. No AVO anomaly was observed on the 2D repeat data, which was anticipated, but the result shows signs of a pressure response at the reservoir level in the data. Reflection coefficients were calculated using surface seismic data (3D and pseudo-3D) at the site. Pre-injection calculations agree well with calculations from logging data. Post-injection calculations are in general agreement with the seismic modeling, but generally show higher amplitudes than those expected. The full 3D data show a better image of the reflection coefficients before and after injection than the pseudo-3D data and can potentially be used to make quantitative calculations of CO2 volumes. The pseudo-3D data only provide qualitative information.

A dissertation submitted to the Faculty of Engineering and the Built Environment, University of the Witwatersrand, Johannesburg, in partial fulfilment of the requirements for the degree of Master of Science in Engineering, 2016 / Global climate change is among the major challenges the world is facing today, and can be attributed to enhanced concentrations of Greenhouse Gases (GHG), such as carbon dioxide (CO2), in the atmosphere. Therefore, there is an urgent need to mitigate CO2 emissions, and carbon capture and storage (CCS) is amongst the possible options to reduce CO2 emissions. Against this background, this work investigated the synthesis and performance evaluation of Polyaspartamide (PAA) adsorbent for CO2 capture. In particular, the effect of the presence of water-soluble amines in the amine-grafted poly-succinimide (PSI) (referred to as Polyaspartamide (PAA) adsorbent), was investigated. Methyl Amine (MA) and Mono-Ethanol Amine (MEA) were employed as water-soluble amines and the effect of changes in their concentration on CO2 adsorption capacity was investigated as well. Water-soluble amines were incorporated to allow water solubility of the adsorbent paving the way for freeze-drying to improve the geometric structure (surface area, pore volume and pore size) of the adsorbent. Initially, the PSI was loaded with Ethylenediamine (EDA), forming PSI-EDA. The water-soluble amines were grafted to PSI-EDA, with the EDA added to improve the chemical surface of the adsorbent for CO2 capture. NMR and FTIR analyses were performed and confirmed the presence of MA and MEA amine groups in the PAA, thereby indicating the presence of the grafted amines on the backbone polymer. BET analysis was performed and reported the pore volume, pore size and surface area of the freeze-dried material. It was observed that the physical properties did not change significantly after the freeze-drying compared to literature where freeze-drying was not employed. An increase in adsorption capacity with an increase in MA and MEA concentrations in MA-PAA and MEA-PAA samples was observed. At low amine concentrations (20% amine and 80% EDA grafted), MEA-PAA was observed to exhibit higher adsorption capacity compared to the MA-PAA samples. At high amine (100% amine grafted) concentrations, MA-PAA samples displayed higher adsorption capacity. Three runs were performed on each sample and the results obtained were reproducible. The best adsorption capacity obtained was 44.5 g CO2/kg Ads. Further work was then performed to understand the effects of operating variables on CO2 adsorption as well as the interactive effect using the Response Surface Methodology approach. The experiments were done by use of CO2 adsorption equipment attached to an ABB gas analyzer. A central composite design of experiment method with a total of 20 experiments was employed to investigate three factors, namely, temperature, pressure and gas flow rate. Six regression models were drawn up and mean error values computed by use of Matlab, followed by response surfaces as well as contours, showing the influence of the operating variables on the adsorption capacity as well as interaction of the factors were then drawn up. The results obtained displayed that each of the factors investigated, temperature, pressure and gas flowrate had an incremental effect on the adsorption capacity of PAA, that is, as each factor was increased, the adsorption capacity increased up to a point where no more increase occurred. Adsorption was seen to increase for both an increase in gas flowrate and adsorption pressure to a maximum, thereafter it starts to decrease. A similar trend was observed for the interaction between temperature and pressure. However, the interaction between gas flowrate and temperature was such that, initially as the temperature and the gas flowrate increase, the adsorption capacity increases to a maximum, thereafter, the temperature seizes to have an effect on the adsorption capacity with a combined effect of decreasing temperature and increasing gas flowrate resulting in a further increase in adsorption capacity. It was confirmed that the operating variables as well as the flow regime have an effect on the CO2 adsorption capacity of the novel material. The highest adsorption capacity was obtained in the pressure range 0.5 bar to 1.7 bar coinciding with the temperature range of 10 oC to 45 oC. The interaction of gas flowrate and adsorption pressure was such that the highest adsorption capacity is in the range 0.8 bar to 1.5 bar which coincides with the gas flowrate range from 35 ml / min to 60 ml / min. In conclusion, the best adsorption capacity of 44.5 g / kg via the TGA and 70.4 g / kg via the CO2 adsorption equipment was obtained from 100 % MA grafted PSI. / GR2016