At a time when the rest of Canada, and indeed much of the Western World, was looking for alternatives to large custodial mental hospitals, people in the Western Canadian province of Saskatchewan celebrated the opening of one of the country's largest asylums. The province remained committed to the institution throughout the interwar years, offering few alternatives for people deemed insane or mentally defective. People on the outside often saw the asylum as an economic boon, a marker of civilization, or as an institution that was crucial for protecting the health and safety of the public. Patients and their families, however, struggled against an institution where patients were subjected to a broad range of indignities. By carefully considering Saskatchewan's regional social and political culture, I examine the values that were projected onto the asylum by those on the outside and the boundaries that were established between the patients and the public that enabled the public to see the asylum as necessary despite widespread patient suffering. I argue that the public accepted the Weyburn Mental Hospital first as a monument worthy of celebration and then as a necessary, though perhaps regrettable, tool for segregation. The asylum in the interwar years is best understood as a political rather than a medical institution, where politicians and the asylum administration cultivated an image for the institution that conformed to regional values. The government and the media defined the patient experience for a curious public, portraying the institution and its patients in a way that not only legitimized the asylum but that also assigned it meaning far beyond its stated medical function. The values associated with the asylum changed over time, but were always guided by political concerns and were always facilitated by manipulating the relationship between the asylum, its patients, and the surrounding community.

Understanding the controls on fluid migration in reservoir rocks is becoming evermore important within the petroleum industry as significant hydrocarbon discoveries become less frequent and more emphasis is placed on enhanced oil recovery methods. To fully understand the factors controlling fluid migration in the subsurface, pore scale information is necessary. In this study, synchrotron-based X-ray computed microtomography (CMT) is being utilized to extract physically realistic images of carbonate rock cores for the evaluation of porosity and mineralogy in the Mississippian Midale beds of the Weyburn Oilfield in southeastern Saskatchewan. Non-destructive in-situ imaging by CMT is unique as it provides a detailed and novel approach for the description of pore space geometry, while preserving connectivity and spatial variation of pore-body and pore-throat sizes. Here, three-dimensional micron to sub-micron (0.3ìm-100ìm) resolution of CMT is coupled with, and compared against, conventional laboratory-based methods (liquid and gas permeametry, mercury injection porosimetry, electrical resistivity, backscattered electron (BSE) from electron probe micro-analysis (EPMA) and transmitted light microscopy). Petrophysical and mineralogical information obtained from both CMT and conventional methods will have direct implications for understanding the petrophysical mechanisms that control fluid movement in the subsurface of the Weyburn Oilfield.<p>At Weyburn, CO2 gas is being injected into producing horizons to enhance oil recovery and permanently sequester CO2 gas. Fundamental questions exist regarding: (1) The significance of pore geometry and connectivity to the movement of CO2 and other fluids in the subsurface, (2) the nature of the interactions between CO¬2 and pore lining minerals and their impact on petrophysical properties, and (3) the distribution and mineralogy of finely disseminated silicate and carbonate minerals adjacent to pore spaces as interaction among these phases and CO2 may result in permanent sequestration of CO2. <p>The two producing horizons within the Weyburn Reservoir, the Midale Marly and Midale Vuggy units, have variable porosities and permeabilities. Porosity in the Marly unit ranges from 16% to 38% while permeability ranges from 1mD to greater than 150 mD across the field. For the Vuggy unit, porosity ranges from 8% to 21% with permeability ranging from 0.3mD to 500mD. Using CMT, pore space is critically examined to highlight the controlling factors on permeability. Digital processing of CMT data indicates that pore space in the Marly unit is dominated by intercrystalline pores having diameters of approximately 4 ìm. From here, it is noted that the pore-throat radii are approximately ½ the radii of the pore-bodies, having profound implications to current oil recovery methods. Tortuosity values from CMT are also observed to have similar values in three orthogonal directions indicating an isotropic pore space distribution within the Marly unit. Alternatively, the Vuggy unit is found to possess greater pore-body and pore-throat sizes that are heterogeneous in distribution. Based on this, permeability in the Vuggy unit is strongly dependant on pore-length scales that vary drastically between localities.

Understanding the controls on fluid migration in reservoir rocks is becoming evermore important within the petroleum industry as significant hydrocarbon discoveries become less frequent and more emphasis is placed on enhanced oil recovery methods. To fully understand the factors controlling fluid migration in the subsurface, pore scale information is necessary. In this study, synchrotron-based X-ray computed microtomography (CMT) is being utilized to extract physically realistic images of carbonate rock cores for the evaluation of porosity and mineralogy in the Mississippian Midale beds of the Weyburn Oilfield in southeastern Saskatchewan. Non-destructive in-situ imaging by CMT is unique as it provides a detailed and novel approach for the description of pore space geometry, while preserving connectivity and spatial variation of pore-body and pore-throat sizes. Here, three-dimensional micron to sub-micron (0.3ìm-100ìm) resolution of CMT is coupled with, and compared against, conventional laboratory-based methods (liquid and gas permeametry, mercury injection porosimetry, electrical resistivity, backscattered electron (BSE) from electron probe micro-analysis (EPMA) and transmitted light microscopy). Petrophysical and mineralogical information obtained from both CMT and conventional methods will have direct implications for understanding the petrophysical mechanisms that control fluid movement in the subsurface of the Weyburn Oilfield.<p>At Weyburn, CO2 gas is being injected into producing horizons to enhance oil recovery and permanently sequester CO2 gas. Fundamental questions exist regarding: (1) The significance of pore geometry and connectivity to the movement of CO2 and other fluids in the subsurface, (2) the nature of the interactions between CO¬2 and pore lining minerals and their impact on petrophysical properties, and (3) the distribution and mineralogy of finely disseminated silicate and carbonate minerals adjacent to pore spaces as interaction among these phases and CO2 may result in permanent sequestration of CO2. <p>The two producing horizons within the Weyburn Reservoir, the Midale Marly and Midale Vuggy units, have variable porosities and permeabilities. Porosity in the Marly unit ranges from 16% to 38% while permeability ranges from 1mD to greater than 150 mD across the field. For the Vuggy unit, porosity ranges from 8% to 21% with permeability ranging from 0.3mD to 500mD. Using CMT, pore space is critically examined to highlight the controlling factors on permeability. Digital processing of CMT data indicates that pore space in the Marly unit is dominated by intercrystalline pores having diameters of approximately 4 ìm. From here, it is noted that the pore-throat radii are approximately ½ the radii of the pore-bodies, having profound implications to current oil recovery methods. Tortuosity values from CMT are also observed to have similar values in three orthogonal directions indicating an isotropic pore space distribution within the Marly unit. Alternatively, the Vuggy unit is found to possess greater pore-body and pore-throat sizes that are heterogeneous in distribution. Based on this, permeability in the Vuggy unit is strongly dependant on pore-length scales that vary drastically between localities.

No description available.

The Intergovernmental Panel on Climate Change (2001) reports that increased anthropogenic greenhouse gas (GHG) emissions, of which carbon dioxide (CO2) is the main component, have caused the Earths temperature to rise. Therefore, it is necessary to find ways to reduce GHG emissions and to deal with the emissions that continue to be produced. Carbon capture and storage (CCS) is one method that is being considered to deal with GHG emissions, specifically CO2 emissions. The basic idea behind CCS is that CO2 is captured from a point source, such as a power plant, and is then transported to a storage site (e.g., an oil or gas reservoir), where it is subsequently stored. The International Energy Agency Greenhouse Gas Programme (IEA GHG) began a CO2 geological sequestration pilot project in 2000 in Weyburn, Saskatchewan as part of an enhanced oil recovery project operatedby Cenovus (formerly EnCana) in the Weyburn Field (White et al. 2004). The research presented in this thesis evaluates the sealing potential of the Lea Park Formation in the Weyburn Field by determining its permeability and CO2 breakthrough pressure. In this context, breakthrough pressure describes the differential pressure between a wetting phase (e.g., formation brine) and a non-wetting phase (e.g., CO2) that is sufficient to enable the non-wetting phase to form a connected flow system across a given volume of porous medium (e.g., a rock sample). A new system for measuring the permeability and CO2 breakthrough pressure of shales was developed in this research. The development effort included extensive trouble-shooting and, ultimately, the development of sample preparation and testing procedures. The new system was used to conduct permeability and CO2 breakthrough pressure tests on shale samples from the Lea Park Formation (i.e., Lea Park shale) and the Colorado Group (i.e., Colorado shale). Permeability results for samples from the Lea Park shale ranged from 14 to 35 nd (1410-21 to 3510-21 m2), and between eight and 46 nd (810-21 to 4610-21 m2) for the Colorado shale. A CO2 breakthrough pressure for the Lea Park shale was determined to be 0.02 MPa, while values of 0.02 and 2.7 MPa were measured for the Colorado shale. The CO2 breakthrough pressure test results indicate that the Lea Park shale will not withstand large pressures before allowing CO2 to flow through it. However, the permeabilities are extremely low; hence the rate of flow would be low. In other words, the low permeability of the Lea Park shale will be the controlling factor in terms of the rate of potential CO2 leakage through it. Calculations based on the properties measured in this research suggest that the time required for CO2 to flow from the base to the top of the Lea Park Formation would be on the order of ten thousand years. Based on diffusion coefficients published for other shales, calculations suggest that CO2 leakage via chemical diffusion would be several times slower leakage via hydraulically-driven flow.

The Intergovernmental Panel on Climate Change (2001) reports that increased anthropogenic greenhouse gas (GHG) emissions, of which carbon dioxide (CO2) is the main component, have caused the Earths temperature to rise. Therefore, it is necessary to find ways to reduce GHG emissions and to deal with the emissions that continue to be produced. Carbon capture and storage (CCS) is one method that is being considered to deal with GHG emissions, specifically CO2 emissions. The basic idea behind CCS is that CO2 is captured from a point source, such as a power plant, and is then transported to a storage site (e.g., an oil or gas reservoir), where it is subsequently stored. The International Energy Agency Greenhouse Gas Programme (IEA GHG) began a CO2 geological sequestration pilot project in 2000 in Weyburn, Saskatchewan as part of an enhanced oil recovery project operatedby Cenovus (formerly EnCana) in the Weyburn Field (White et al. 2004). The research presented in this thesis evaluates the sealing potential of the Lea Park Formation in the Weyburn Field by determining its permeability and CO2 breakthrough pressure. In this context, breakthrough pressure describes the differential pressure between a wetting phase (e.g., formation brine) and a non-wetting phase (e.g., CO2) that is sufficient to enable the non-wetting phase to form a connected flow system across a given volume of porous medium (e.g., a rock sample). A new system for measuring the permeability and CO2 breakthrough pressure of shales was developed in this research. The development effort included extensive trouble-shooting and, ultimately, the development of sample preparation and testing procedures. The new system was used to conduct permeability and CO2 breakthrough pressure tests on shale samples from the Lea Park Formation (i.e., Lea Park shale) and the Colorado Group (i.e., Colorado shale). Permeability results for samples from the Lea Park shale ranged from 14 to 35 nd (1410-21 to 3510-21 m2), and between eight and 46 nd (810-21 to 4610-21 m2) for the Colorado shale. A CO2 breakthrough pressure for the Lea Park shale was determined to be 0.02 MPa, while values of 0.02 and 2.7 MPa were measured for the Colorado shale. The CO2 breakthrough pressure test results indicate that the Lea Park shale will not withstand large pressures before allowing CO2 to flow through it. However, the permeabilities are extremely low; hence the rate of flow would be low. In other words, the low permeability of the Lea Park shale will be the controlling factor in terms of the rate of potential CO2 leakage through it. Calculations based on the properties measured in this research suggest that the time required for CO2 to flow from the base to the top of the Lea Park Formation would be on the order of ten thousand years. Based on diffusion coefficients published for other shales, calculations suggest that CO2 leakage via chemical diffusion would be several times slower leakage via hydraulically-driven flow.