The reaction of Mg(NPh2)2 with LiNR2 (R= SiMe3, NiPr, NiBu) generated the same product, [Mg(NPh2)3(THF)][Li(THF)4] which was identified by 1H-NMR and X-ray crystallography. The magnesium-lithium mixed metal complex reacted with excess carbon dioxide in the ice bath to generate the tetralithium complex, Li4(O2CNPh2)4(THF)4 which was identified by 1H-NMR, 13C-NMR, IR, and X-ray crystallography.

Previous experiments - injecting pure CO2 into carbonate cores - showed that the process is a win-win technology, sequestrating CO2 while recovering a significant amount of hitherto unrecoverable natural gas that could help defray the cost of CO2 sequestration. In this thesis, I report my findings on the effect of flue gas ??impurities?? on the displacement of natural gas during CO2 sequestration, and results on unconfined compressive strength (UCS) tests to carbonate samples. In displacement experiments, corefloods were conducted at 1,500 psig and 70??C, in which flue gas was injected into an Austin chalk core containing initially methane. Two types of flue gases were injected: dehydrated flue gas with 13.574 mole% CO2 (Gas A), and treated flue gas (N2, O2 and water removed) with 99.433 mole% CO2 (Gas B). The main results of this study are as follows. First, the dispersion coefficient increases with concentration of ??impurities??. Gas A exhibits the largest dispersion coefficients, 0.18-0.25 cm2/min, compared to 0.13-0.15 cm2/min for Gas B, and 0.15 cm2/min for pure CO2. Second, recovery of methane at breakthrough is relatively high, ranging from 86% OGIP for pure CO2, 74-90% OGIP for Gas B, and 79-81% for Gas A. Lastly, injection of Gas A would sequester the least amount of CO2 as it contains about 80 mole% nitrogen. From the view point of sequestration, Gas A would be least desirable while Gas B appears to be the most desirable as separation cost would probably be cheaper than that for pure CO2 with similar gas recovery. For UCS tests, corefloods were conducted at 1,700 psig and 65??C in such a way that the cell throughput of CO2 simulates near-wellbore throughput. This was achieved through increasing the injection rate and time of injection. Corefloods were followed by porosity measurement and UCS tests. Main results are presented as follows. First, the UCS of the rock was reduced by approximately 30% of its original value as a result of the dissolution process. Second, porosity profiles of rock samples increased up to 2.5% after corefloods. UCS test results indicate that CO2 injection will cause weakening of near-wellbore formation rock.

A low-temperature method, supercritical CO2 fluid (SCCF) technology, was applied for oxidation of metal Zn film on glass substrate at 60¢XC. In this study, Zn film was deposited by DC sputtering at room temperature and post-treated by SCCF, which is mixed with 0.15 vol % H2O. The scanning electron microscopy (SEM) images and transmission electron microscopic (TEM) indicate that high density ZnO Nanotubes were formed on the glass substrate. SCCF technology has shown successful oxidation the Zinc at low temperature for the first time.

Leakage of stored bulk phase CO₂ is of particular risk to sequestration in deep saline aquifers due to the fact that when injected into typical saline aquifers, the CO₂ rich gas phase has lesser density than the aqueous phase resulting in buoyancy driven flow of the fluids. As the CO₂ migrates upward, the security of its storage depends upon the trapping mechanisms that counteract the migration. While there are a variety of trapping mechanisms the mechanism serving as motivation for this research is local capillary trapping. Local capillary trapping occurs during buoyancy-driven migration of bulk phase CO₂ within a saline aquifer (Saadatpoor, 2009). When the rising CO₂ plume encounters a region where capillary entry pressure is locally larger than average, CO₂ accumulates beneath the region. While research is continued by means of numerical simulation, research at the bench scale is needed to validate the conclusions made from simulation work. Presented is the development of a bench scale experiment whose objective is to assess local capillary trapping. The initial step in accomplishing this objective is to understand the fluid dynamics of CO₂ and brine in a saline aquifer which is categorized as two phase immiscible buoyancy driven displacement. Parameters influencing this displacement include density, viscosity, wettability and heterogeneity. A bench scale environment created to be analogous to CO₂ and brine in a saline aquifer is created in a quasi-two dimensional experimental apparatus, which allows for observation of plume migration at ambient conditions. A fluid pair analogous to supercritical CO₂ and brine is developed to mimic the density and viscosity relationship found at pressure and temperature typical of storage aquifers. The influences of viscosity ratio, density differences, porous medium wettability and heterogeneity are observed in series of experimental sequences. Three different fluid pairs with different viscosity ratios and density differences are used to assess density and viscosity influences. Porous media of varying grain size and wettability are used to assess the influence of heterogeneity and wettability. Results are qualitatively consistent with theoretical results and those from previous works. / text

Sulfate accumulates in the post-combustion CO₂ capture system and must be removed to re-use amine efficiently. Removal of sulfate from the amine-based postcombustion CO₂ capture system through a solvent reclaiming process may reduce CO₂ capture costs. This work determines the solubility of K₂SO₄ and Na₂SO₄ in 2 to 8 m PZ loaded with CO₂ and develops a thermodynamic and process model for the reclaiming process. At 40°C the solubility of Na2SO₄ in 8 m PZ with a CO₂ loading of 0.3 is 0.3 m Na2SO₄ and that of K₂SO₄ is 0.1 m K₂SO₄. Sulfate solubility in PZ solutions is represented by the empirical models: K₂SO₄: ln(Ksp) = 10.53I[superscript 0.3] - 0.98[PZ][subscript T] -3440/T - 2.42 ; Na₂SO₄: ln(Ksp) = 2.137I[superscript0.3] - .6505[PZ][subscript T] -826/T + 265 where [PZ][subscript T] = 2*(molality of PZ). A K₂SO₄ and Na₂SO₄ solubility thermodynamic model was developed in the eNRTL framework in the Fawkes model for PZ/CO₂/H₂O in Aspen Plus[trademark]. The energy cost of the Na process when removing the equivalent of 100 ppm SO₂ from the flue gas, ranging from $0.1-0.5/ton CO₂, was practically the same as the K process(ranging from $0.1-0.8/ton CO₂). The K₂SO₄ recovered in the process can be used as fertilizer. However, the KOH will still cost $0.6/tonne CO₂. If it is not possible to sell the K₂SO₄ as fertilizer because of the impurities that may be present on the K₂SO₄crystals, the chemical cost of the process would increase to $2/tonne CO₂. The chemical cost for the Na case is $0.7/tonne of CO₂. / text

Two Arabidopsis lines, 10’4 and 3’1, with partial-repression, constitutively of mitochondrial pyruvate dehydrogenase kinase that could alter dark respiration (Rd) were grown on rockwool to reduce off-gassing from peat that interfered with assessment of Rd. At the rosette stage, Rd and photosynthesis (Pn) at high CO2 were greater than at ambient CO2, and Rd was greater for whole-plant than single leaf measurements due to the contribution of non-laminar tissues. However, whole-plant and leaf Rd and Pn were similar on a leaf-area-basis comparing mutants with controls. Whole-plant, analyses during reproductive stage showed that although, the inflorescence contributed as much as 90% of daily C-gain when the rosette leaves senesced, canopy-Pn on a surface-area-basis at each CO2 level remained similar to those at the rosette stage. At each CO2 level, the transgenic and control lines were similar indicating that the mutation resulted in no direct or indirect effect of Rd or Pn. / Ontario Graduate Scholarship, Green Crop Net Work

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CO2 injection is an effective method for performing enhanced oil recovery (EOR). There are several factors that make CO2 useful for EOR, including promoting swelling, reducing oil viscosity, decreasing oil density, and vaporizing and extracting portions of crude oil. Moreover, the ease with which CO2 becomes soluble in oil makes it an ideal gas for EOR operations. However, there are several problems associated with CO2 flooding, especially when reservoir heterogeneity exists. The efficiency of CO2 is hindered by mobility problems, which result from the unfavorable mobility ratio. In such cases, the injected CO2 leads to an early breakthrough, which means fingering through the target zone occurs while leaving most of the residual and/or trapped oil untouched. Furthermore, an increase in the CO2 to oil ratio makes the EOR project uneconomical. However, if there are techniques available to control the injected CO2 volume, the problems just mentioned can be resolved. Nowadays, several methods are applied to control the CO2 flooding in heterogeneous porous media. In the present study, the CO2 coreflood system was integrated with a computed tomography (CT) scanner and obtained real-time coreflood images of the CO2 saturation distribution in the core sample. Throughout this study, two polymers, Polydimethylsiloxane (PDMS) and Poly (vinyl ethyl ether) (PVEE), were tested to assess their ability to increase the CO2 viscosity and therefore improve sweep efficiency. A drop-in pressure test was first conducted to evaluate the viscosifier's ability to increase CO2 viscosity; therefore, reduce its mobility. The results showed that the PDMS polymer has the greatest influence on increasing the CO2 viscosity and reducing its mobility. Also, the PVEE polymer has lower mobility than that of neat CO2. Based on the coreflood experiments, injection of viscosified CO2 using the PDMS polymer resulted in the highest oil recovery among the other injection tests have been conducted. Also, the laboratory tests show that injecting the viscosified CO2 using the PVEE polymer led to higher oil recovery than from the neat CO2 injection. This research serves as a preliminary study in understanding advanced CO2 mobility control using the thickening agents technique and will provide an insight into the future studies on the topic.

CO₂, without question, the most famous greenhouse gas, is known to have an increasing concentration in both the atmosphere and oceans. To slow down the pace not only of global warming but also the ocean acidification, several routes are proposed to effectively reduce the net emission of CO₂. Compared to Carbon Capture and Sequestration/Storage (CCS), Carbon Capture and Utilisation (CCU) has much more potential because of the lower costs of scale up and higher profitability to potentially attract capital investment. Different from the conventional CCU route which is to reduce CO₂ to fuels with hydrogen generated via renewable-energy-driving electricity, two processes are investigated in this thesis; that of Dry Methane Reforming (DMR) and the DeHydrogenation of Propane by CO₂ (DHP by CO₂). The projects on these two processes not only develop catalysts which would be suitable for the reaction performance, but also the ultimate aim is to link the processes with a renewable energy source (in the thesis we chose Solar Thermal Heating).Thermodynamic calculations and process simulations were also evaluated. The results of DMR unfortunately did not indicate a promising future to link with Solar Thermal Heating due to the very high temperature required during the process. However, the results of thermodynamic calculations and process simulations in DMR project illustrate a good opportunity to utilise flue gas in industry through the so-called Tri- Methane Reforming (TMR). In the DHP by CO₂ process, the catalysts developed were less promising than the ones in DMR due to the severe side-reactions occurred which significantly decreased the selectivity for the desired product. However - and importantly - through our thermodynamic calculations and process simulations, the DHP by CO₂ process has a bright future if the Solar Thermal Heating can be applied with the relative lower temperature requirement, making the CO₂ utilisation process much easier to be fulfilled than DMR.