Background: Hemophilia A is X-linked recessive congenital bleeding disorder. Exogenous infusion of FVIII is the treatment of choice in hemophilia A patients. However, inhibitor development remains the major problem in management of Hemophilia A. It has been showed that IVIG has immunomodulatory effects and it has been being used in the treatment of several autoimmune and inflammatory disorders. Here, we investigated the effect of co-administration of FVIII with IVIG on the development of inhibitor in naive and previously immunized hemophilia A mice. Methods: Initially, hemophiliac mice were immunized by weekly intraperitoneal injection of human recombinant FVIII (rFVIII). The mice then were treated, either by rFVIII/IVIG co-injection or rFVIII alone. In the other experimental group, naive hemophiliac mice were treated with rFVIII/IVIG co-injection for four weeks followed by injection of either rFVIII or rFVIII/IVIG. Plasma's anti-FVIII Ab titer was measured using ELISA. Results: Weekly injection of rFVIII led to the development of anti-FVIII Ab in all previously untreated mice. Treatment of those immunized mice with rFVIII/IVIG co-injection did not reduce the level of pre-existing Ab. On the other hand, naive mice treated with rFVIII/IVIG co-injection showed significantly less Ab titer compared to the mice received rFVIII alone after 4 weeks (mean Ab titre of 1 compared to 39, in rFVIII/IVIG co-injection and rFVIII groups respectively). Although the rFVIII/IVIG-treated mice developed immune response following the injection of rFVIII alone, Ab titer in those that kept receiving rFVIII/IVIG co-injection remained lower compared to other groups during the whole twelve weeks of the experiment. Conclusions: Co-injection of rFVIII with IVIG decreased the anti-FVIII immune response in previously untreated hemophilia A mice. These findings suggest that IVIG co-administration can be effective in management of hemophilia A patients at risk of inhibitor development. / Thesis / Master of Applied Science (MASc)

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. / text

C. elegans is a commonly used genetic model organism due to the ease of genetic screens, transgenesis, and microscopy. Here, I describe methods that improve transgenesis in C. elegans and the development of a genetic screen to identify genes involved in the piRNA pathway. Transgenesis is commonly used for most laboratories that utilize C. elegans and improvements are therefore likely to facilitate research across many research areas. In the first chapter, I characterized a pan-muscular promoter that drives fluorophore expression to help identify C. elegans transgenesis. This promoter is an improved co-injection marker as it drives bright fluorescence with low toxicity and high efficiency. In the second chapter, I study piRNAs which are a large class of non-coding RNA that play important roles in protecting the genome from transposable elements in most animals. The study of piRNAs has mostly focused on their function in the germline, but recent evidence suggests functions in somatic cells such as neurons. To identify genes involved in the piRNA pathway in C. elegans, I performed a chemical genetic screen. I identified one mutant with a somatic phenotype and six mutants with a germline phenotype. I have focused on the germline and sequenced two strains and identified candidate genes involved in the piRNA pathway. Future work will focus on validating and identifying the remaining mutants.

No description available.

No description available.

Les méthodes géophysiques non intrusives sont requises pour caractériser la zone vadose, les réservoirs d’hydrocarbures, ou les sites de stockages de CO₂. Nous analysons l’impact d’une injection de CO₂ gazeux sur la conductivité électrique et les propriétés électrocinétiques des roches carbonatées partiellement ou totalement saturées grâce aux méthodes de polarisations provoquée et spontanée. Les données sont analysées au regard au regard de mesures effectuées sur une roche chimiquement neutre, vis-à-vis du CO₂, c’est-à-dire , un grès de Fontainebleau. Nous comparons également nos résultats aux données de la littérature. Le coefficient de couplage électrocinétique est un paramètre clé, dont nous allons étudier la dépendance vis-à-vis de la saturation, sujet hautement débattu de nos jours. En utilisant la méthode de polarisation spontanée, nous étudions les relations entre le coefficient de couplage électrocinétique, la pression capillaire ainsi que la perméabilité relative au sein des roches carbonatées. Un système expérimental a été élaboré pour mesurer simultanément la perméabilité relative, l’indice de resistivité et le coefficient de couplage électrocinétique en écoulement diphasique de type eau-gaz, en fonction de la saturation en azote ou en dioxyde de carbone. Les résultats sont comparés à des modèles théoriques basés sur les approches de Brooks et Corey et van Genuchten, dont les exposants nous permettent d’ajuster les données avec les modèles de pression capillaire avec succès. Les échantillons sont saturés avec des saumures de différentes compositions, dont les ions sont mono- ou divalents et pour lesquelles la force ionique est comprise entre 10⁻⁴ et 10⁰ Mol L⁻¹. La valeur absolue du coefficient de couplage électrocinétique augmente lorsque la force ionique de la solution diminue, ce qui a déjà été observé dans les roches gréseuses. Le potentiel zêta a été calculé en utilisant une version modifiée de l’équation d’Helmholtz-Smoluchowski, qui prend en compte les effets liés à la conductivité de surface. Comme pour le coefficient de couplage, la valeur absolue du potentiel zêta chute lorsque la force ionique augmente. Nous nous intéressons également aux effets liés à une injection de CO₂ et à la dissolution de la calcite sur la valeur de ce potentiel zêta. Enfin, nous utilisons la méthode de polarisation provoquée pour déterminer l’influence de conductivité de l’eau porale sur la conductivité électrique complexe, la chargeabilité normalisée ainsi que le temps de relaxation en milieu carbonaté non saturé. Nous montrons que ces paramètres peuvent être considérés comme des paramètres de polarisation de la double couche électrique lorsque la conductivité de l’eau porale est comprise entre 10⁻³ et 10⁰ S m⁻¹. / Minimally intrusive geophysical methods are required to characterize both the vadose zone of the Earth, hydrocarbon reservoirs and CO₂ sequestration. We investigate the impact of gaseous CO₂ on both electrical conductivity and electrokinetic properties of limestones under saturated and unsaturated conditions, using the spectral induced polarization and the self-potential methods. These data are contrasted with measurements performed on a Fontainebleau sandstone and data from the literature. That said, the dependence of a key parameter, the streaming coupling coefficient, with the saturation remains highly debated. Using the self-potential method, we explore the relationship between the streaming potential coupling coefficient, the capillary pressure curves and the permeability in carbonate rocks characterized by distinct textures. A new core flooding system is used to measure simultaneously both the relative permeability, the resistivity index and the streaming potential coupling coefficient in steady-state two-phase flow conditions as a function of the saturation with CO₂ or N₂. The results are compared with a recently developed theoretical model, which can accommodate either the Brooks and Corey or the van Genuchten models for the capillary pressure curves. Saturation was achieved with monovalent and divalent brines with ionic strength ranging from 1x10⁻³ Mol L⁻¹ to 1x10⁰ Mol L⁻¹. The magnitude of the coupling coefficient increases with decreasing ionic strength similarly to the trend observed for sandstones. The zeta potential has been calculated at full saturation using a modified version of the Helmholtz-Smoluchowski equation that accounts for surface electrical conductivity. Under atmospheric conditions, the magnitude of the zeta potential is decreasing with the increase of the ionic strength. We also investigate the effects of a CO₂ release and the calcite dissolution on the magnitude of the zeta potential. Finally, we use the spectral induced polarization method to determine the pore water conductivity effects on the complex electrical conductivity, the normalized chargeability and the main relaxation time during drainage in a clay free limestone. We also show evidences that these parameters could be considered as polarization parameters of the electrical double layer in the pore water conductivity range 10⁻³ - 10⁰ S m⁻¹.

Geological sequestration of CO₂ in deep saline reservoirs is one of the ways to reduce its continuous emission into the atmosphere to mitigate the greenhouse effect. The effectiveness of any CO₂ sequestration operation depends on pore volume and the sequestration efficiency of the reservoir. Sequestration efficiency is defined here as the maximum storage with minimum risk of leakage to the overlying formations or to the surface. This can be characterized using three risk parameters i) the time the plume takes to reach the top seal; ii) maximum lateral extent of the plume and iii) the percentage of mobile CO₂ present at any time. The selection among prospective saline reservoirs can be expedited by developing some semi-analytical correlations for these risk parameters which can be used in place of reservoir simulation study for each and every saline reservoir. Such correlations can reduce the cost and time for commissioning a geological site for CO₂ sequestration. To develop such correlations, a database has been created from a large number of compositional reservoir simulations for different elementary reservoir parameters including porosity, permeability, permeability anisotropy, reservoir depth, thickness, dip, perforation interval and constant pressure far boundary condition. This database is used to formulate different correlations that relate the sequestration efficiency to reservoir properties and operating conditions. The various elementary reservoir parameters are grouped together to generate different variants of gravity number used in the correlations. We update a previously reported correlation for time to hit the top seal and develop new correlations for other two parameters using the newly created database. A correlation for percentage of trapped CO₂ is also developed using a previously created similar database. We find that normalizing all risk parameters with their respective characteristic values yields reasonable correlations with different variants of gravity number. All correlations confirm the physics behind plume movement in a reservoir. The correlations reproduce almost all simulation results within a factor of two, and this is adequate for rapid ranking or screening of prospective storage reservoirs. CO₂ injection in saline reservoirs on the scale of tens of millions of tonnes may result in fracturing, fault activation and leakage of brine along conductive pathways. Critical contour of overpressure (CoP) is a convenient proxy to determine the risk associated with pressure buildup at different location and time in the reservoir. The location of this contour varies depending on the target aquifer properties (porosity, permeability etc.) and the geology (presence and conductivity of faults). The CoP location also depends on relative permeability, and we extend the three-region injection model to derive analytical expressions for a specific CoP as a function of time. We consider two boundary conditions at the aquifer drainage radius, constant pressure or an infinite aquifer. The model provides a quick tool for estimating pressure profiles. Such tools are valuable for screening and ranking sequestration targets. Relative permeability curves measured on samples from seven potential storage formations are used to illustrate the effect on the CoPs. In the case of a constant pressure boundary and constant rate injection scenario, the CoP for small overpressures is time-invariant and independent of relative permeability. Depending on the relative values of overall mobilities of two-phase region and of brine region, the risk due to a critical CoP which lies in the two-phase region can either increase or decrease with time. In contrast, the risk due to a CoP in the drying region always decreases with time. The assumption of constant pressure boundaries is optimistic in the sense that CoPs extend the least distance from the injection well. We extend the analytical model to infinite-acting aquifers to get a more widely applicable estimate of risk. An analytical expression for pressure profile is developed by adapting water influx models from traditional reservoir engineering to the "three-region" saturation distribution. For infinite-acting boundary condition, the CoP trends depend on same factors as in the constant pressure case, and also depend upon the rate of change of aquifer boundary pressure with time. Commercial reservoir simulators are used to verify the analytical model for the constant pressure boundary condition. The CoP trends from the analytical solution and simulation results show a good match. To achieve safe and secure CO₂ storage in underground reservoirs several state and national government agencies are working to develop regulatory frameworks to estimate various risks associated with CO₂ injection in saline aquifers. Certification Framework (CF), developed by Oldenburg et al (2007) is a similar kind of regulatory approach to certify the safety and effectiveness of geologic carbon sequestration sites. CF is a simple risk assessment approach for evaluating CO₂ and brine leakage risk associated only with subsurface processes and excludes compression, transportation, and injection-well leakage risk. Certification framework is applied to several reservoirs in different geologic settings. These include In Salah CO₂ storage project Krechba, Algeria, Aquistore CO₂ storage project Saskatchewan, Canada and WESTCARB CO₂ storage project, Solano County, California. Compositional reservoir simulations in CMG-GEM are performed for CO₂ injection in each storage reservoir to predict pressure build up risk and CO₂ leakage risk. CO₂ leakage risk is also estimated using the catalog of pre-computed reservoir simulation results. Post combustion CO₂ capture is required to restrict the continuous increase of carbon content in the atmosphere. Coal fired electricity generating stations are the dominant players contributing to the continuous emissions of CO₂ into the atmosphere. U.S. government has planned to install post combustion CO₂ capture facility in many coal fired power plants including W.A. Parish electricity generating station in south Texas. Installing a CO₂ capture facility in a coal fired power plant increases the capital cost of installation and operating cost to regenerate the turbine solvent (steam or natural gas) to maintain the stripper power requirement. If a coal-fired power plant with CO₂ capture is situated over a viable source for geothermal heat, it may be desirable to use this heat source in the stripper. Geothermal brine can be used to replace steam or natural gas which in turn reduces the operating cost of the CO₂ capture facility. High temperature brine can be produced from the underground geothermal brine reservoir and can be injected back to the reservoir after the heat from the hot brine is extracted. This will maintain the reservoir pressure and provide a long-term supply of hot brine to the stripper. Simulations were performed to supply CO₂ capture facility equivalent to 60 MWe electric unit to capture 90% of the incoming CO₂ in WA Parish electricity generating station. A reservoir simulation study in CMG-GEM is performed to evaluate the feasibility to recycle the required geothermal brine for 30 years time. This pilot study is scaled up to 15 times of the original capacity to generate 900 MWe stripping system to capture CO₂ at surface. / text

Of all the strategies to reduce carbon emissions, carbon dioxide (CO₂) geological sequestration is an immediately available option for removing large amounts of the gas from the atmosphere. However, our understanding of the transition behavior between Forchheimer and Darcy flow through porous media during CO₂ injection is currently very limited. In addition, the kinetic mass transfer of SO₂ and CO₂ from CO₂ stream to the saline and the fully coupling between the changes of porosity and permeability and multiphase flow are two significant dimensions to investigate the brine acidification and the induced porosity and permeability changes due to SO₂ co-injection with CO₂. Therefore, this dissertation develops a multiphase flow, contaminant transport and geochemical model which includes the kinetic mass transfer of SO₂ into deep saline aquifers and obtains the critical Forchheimer number for both water and CO₂ by using the experimental data in the literature. The critical Forchheimer numbers and the multiphase flow model are first applied to analyze the application problem involving the injection of CO₂ into deep saline aquifers. The results show that the Forchheimer effect would result in higher displacement efficiency with a magnitude of more than 50% in the Forchheimer regime than that for Darcy flow, which could increase the storage capacity for the same injection rate and volume of a site. Another merit for the incorporation of Forchheimer effect is that more CO₂ would be accumulated in the lower half of the domain and lower pressure would be imposed on the lower boundary of the cap-rock. However, as a price for the advantages mentioned above, the injection pressure required in Forchheimer flow would be higher than that for Darcy flow. The fluid flow and contaminant transport and geochemical model is then applied to analyze the brine acidification and induced porosity and permeability changes due to SO₂ co-injection. The results show that the co-injection of SO₂ with CO₂ would lead to a substantially acid zone near the injecting well and it is important to include the kinetic dissolution of SO₂ from the CO₂ stream to the water phase into the simulation models, otherwise considerable errors would be introduced for the equilibrium assumption. This study provides a useful tool for future analysis and comprehension of multiphase Darcy-Forchheimer flow and brine acidification of CO₂ injection into deep saline aquifers. Results from this dissertation have practical use for scientists and engineers concerned with the description of flow behavior, and transport and fate of SO₂ during SO₂ co-injection with CO₂ in deep saline aquifers.