The effect of slurry conditioning on bitumen recovery and bitumen froth quality has been studied by using three oil sands ores tested with a laboratory hydrotransport extraction system (LHES) and a Denver flotation cell. Tests with the LHES show that an increase in slurry conditioning time yielded a lowered bitumen recovery for a long flotation time (30 min). Longer slurry conditioning time led to a better bitumen froth quality regardless of flotation time. However the over conditioning could be compensated by higher conditioning temperatures and higher slurry flow velocities. Tests with the Denver flotation cell show that the increase in slurry conditioning time resulted in a higher bitumen recovery and a better bitumen froth quality for both good and poor processing ores for a shorter flotation time of 5 min. For a longer flotation time of 20 min, increasing slurry conditioning time had little impact on bitumen recovery but led to a slightly better bitumen froth quality for the good processing ore whereas no effect on bitumen froth quality of the poor processing ore. Results also show that higher slurry temperatures and stronger mechanical energy input were beneficial to both bitumen recovery and bitumen froth quality for all three oil sands ores tested on both devices. / Chemical Engineering

Due to a policy of no release, oil sands process-affected water (OSPW) produced by the surface-mining oil sands industry in North Eastern Alberta, Canada, is stored on-site in tailings ponds. There is concern regarding the toxic effects of OSPW on aquatic organisms. Knowledge of the chemical composition and toxicity of OSPW is limited. Research is necessary for potential remediation and release of OSPW back into the environment. Due to the large volume and persistency of OSPW, active efforts are necessary for the remediation of OSPW before release and habitat reclamation. Currently, ozonation is considered one possible method for remediation of OSPW by reducing the concentrations of dissolved organic compounds, including naphthenic acids (NAs), which are considered among the primary toxic constituents. However, further work is needed to evaluate the effectiveness of ozonation in reducing the toxicity of OSPW and to ensure that ozonation does not increase the toxicity of OSPW. The overall objective of this work was to determine the toxic effects of OSPW on endocrine disruption and embryo development, using both in vitro and in vivo models, and the effectiveness of ozone treatment for reducing the toxicity of OSPW. In the first study, untreated and ozone-treated OSPW were examined for effects on sex steroid production using the H295R cell line steroidogenesis Assay. The results indicate that exposure to untreated OSPW can significantly decrease synthesis of testosterone (T) and increase synthesis of 17β-estradiol (E2) by 0.55±0.06 and 2.0±0.13-fold, respectively, compared to that of control groups (ρ < 0.05). These effects were due to increased aromatase enzyme activity and decreased E2 metabolism. The results also suggest that ozonation is an effective treatment to reduce concentrations of NAs in OSPW without altering steroidogenesis. In the second study, the T47D-kbluc (estrogen responsive) and MDA-kb2 (androgen responsive) cell assays were used to determine whether OSPW might act as either agonists or antagonists of the estrogen receptor (ER) or androgen receptor (AR), respectively. The estrogenic responses to untreated OSPW were significantly greater by 2.6±0.22-fold compared to control group (ρ < 0.05). Exposure to untreated OSPW produced significant antiandrogenic response in the presence of 0.01, 0.05 and 0.1 nM T by 16±6.5%, 47±7.6% and 75±9.7%, respectively, of that of the corresponding concentrations of T alone (ρ < 0.05). The results suggest that compounds in the dissolved organic fraction of OSPW have estrogenic and anti-androgenic properties, acting as ER agonists and/or AR antagonists. Ozonation of the OSPW partially mitigated the antiandrogenicity but had no effect on the estrogenicity of OSPW. In the third study, the endocrine-disrupting effects of OSPW and ozone-treated OSPW were determined by quantifying relative changes in the abundances of transcripts of genes along the brain-gonad-liver (BGL) axis in male and female fathead minnows (Pimephales promelas). The results indicate that OSPW has endocrine-disrupting effects at all levels of BGL axis and these effects of impaired expression of genes along the BGL axis are sex specific. For example, exposure to OSPW resulted in significantly greater abundances of transcripts of vtg (Vitellogenin), chg-l (Choriogenin L) and chg-h (Choriogenin H minor) by 4.9±1.2, 5.4±1.5 and 3.4±0.78-fold, respectively, compared to those of control groups (ρ < 0.05) in livers from male fathead minnow. However, in livers from female fathead minnows, exposure to OSPW resulted in significantly lesser abundances of transcripts of vtg, chg-l and chg-h by 0.002±0.0011, 0.022±0.007 and 0.036±0.024-fold, respectively, compared to those of control fish (ρ < 0.05). Ozonation of OSPW attenuated the effects on abundances of transcripts of some genes, and the attenuation was more prominent in males than in females. However, impact of ozonation on endocrine-disrupting effects of OSPW was less evident than in the in vitro studies described in Chapter 2 and 3. The results also provide a mechanistic basis for the endocrine-disrupting effects of OSPW from other studies, including impaired reproduction of fathead minnows exposed to OSPW. In the final study the effects of untreated, ozone-treated, and activated charcoal-treated OSPW (OSPW, O3-OSPW, and AC-OSPW) on the survival, growth, and development of embryos of fathead minnows were determined. Compared to the control group, which had an embryo survival rate of 98±2.1%, survival was significantly less when exposed to OSPW (44±7.1%; ρ < 0.05). Eggs exposed to untreated OSPW exhibited a significantly greater rate of premature hatching, and embryos exhibited more frequent spontaneous movements. Incidences of hemorrhage (50±3.4%), pericardial edema (56±7.1%), and malformation of the spine (38±5.4%) were significantly greater in embryos exposed to OSPW compared to control group (ρ < 0.05). Significantly greater concentrations of ROS (1.7±0.11-fold), and greater abundances of transcripts cyp3a, gst, sod, casp9, and apopen (2.4±0.34, 2.2±0.26, 3.1±0.74, 3.3±0.57 and 2.4±0.25-fold, respectively) compared to control groups (ρ < 0.05), indicated that exposure to OSPW caused oxidative stress, which can result in damage to mitochondria and promote activation of caspase enzymes and apoptotic cell death. Removal of dissolved organic constituents in OSPW by ozone treatment, or by activated charcoal, significantly attenuated all of the adverse effects associated with untreated OSPW. The results suggest that the organic fraction of OSPW can negatively impact the development of fathead minnow embryos through oxidative stress and apoptosis, and that ozonation attenuates this developmental toxicity. Overall, the findings from the research described in this thesis provide novel and important insights into the toxicity and mechanisms of the toxicity of OSPW with respect to endocrine disruption and development of embryos of fish. In addition, the research provides compelling evidence that ozonation might be an effective method for accelerating the remediation of OSPW. The results of the research might help regulators develop effective strategies for reclamation, remediation and potential release of OSPW back to the environment.

This research investigated the system by which the social effects of oil sands development on Fort McMurray, a city in northeastern Alberta, are assessed and managed. The research focused on Social Impact Assessment (SIA), Strategic Environmental Assessment (SEA), and the work of an industry initiative, the Regional Issues Working Group (RIWG). The oil sands industry, which involves large, labour-intensive mining and drilling operations in a boom-bust cycle, places considerable pressure on Fort McMurray, a city of approximately 50,000 inhabitants and the only urban area within 350 km of the oil sands. The social effects experienced there include exorbitant housing prices, shortages in service industry labour, insufficient social services, at times, to assist individuals and families who can no longer cope with the difficult conditions in the area, and a variety of other negative effects. Sixteen key informant interviews were conducted with urban planners, municipal politicians, provincial employees, a spokesperson for one of the First Nations in the area, community NGOs, and oil sands industry representatives. Data from the interviews were combined with a literature review and a document analysis. A modified McKinsey 7S Integrated Management Framework was used as a structure for describing and analyzing the Social Effects Assessment and Management System (SEAMS) in Fort McMurray. The SEAMS was found to be weak in comparison to the needs of the community. Project-by-project assessment of oil sands development was found to downplay the cumulative nature of social effects. Furthermore, no legislation or regulation existed that demanded action based on the findings of SIA. As a result, mitigation and management of social effects was insufficient, often occurring only when it was directly in the interests of the oil sands industry. While government and industry have plans in place to resolve some of the negative social effects, their actions were criticized by informants as being uncoordinated, inconsistent and often ineffective. The findings indicate that a strategy for exploiting Alberta's oil sands is necessary. The project-by-project evaluation of oil sands development proposals is not addressing the important long-term and regional social issues that arise as a result of construction and operation of the mines and facilities. A tool recommended for incorporating resolutions to long-term, regional social effects into the development plan is SEA with an explicit Strategic Social Assessment component. This strategic assessment and planning process should be undertaken by a publicly-accountable government body empowered to rationalize the pace of oil sands development based on social, environmental and economic effects, and to coordinate long-term responses by government and industry.

Western Canadian bitumen is becoming a predominant source of energy for North American markets. The bitumen extraction and upgrading processes in the oil sands industry require vast quantities of energy, in the form of power, H2, steam, hot water, diesel fuel, and natural gas. These energy commodities are almost entirely produced using fossil feedstocks/fuels, which results in significant CO2 atmospheric emissions. CO2 capture and storage (CCS) technologies are recognized as viable means to mitigate CO2 emissions. Coupling CCS technologies to H2 and power plants can drastically reduce the CO2 emissions intensity of the oil sands industry. The CO2 streams from such plants can be used in Enhanced Oil Recovery, Enhanced Coal Bed Methane, and underground CO2 storage. The above CO2 sinks currently exist in Alberta and roughly half of its territory is deemed suitable for geological storage of CO2. This study investigates the relationship between energy demands, energy costs and CO2 emissions associated with current and proposed oil sands operations using various energy production technologies. Accordingly, two computer models have been developed to serve as energy planning and economic optimization tools for the public and private sectors. The first model is an industry-wide mathematical model, called the Oil Sands Operations Model (OSOM). It serves to quantify the demands for power, H2, steam, hot water, process fuel, and diesel fuel of the oil sands industry for given production levels of bitumen and synthetic crude oil (SCO), by mining and/or thermal extraction techniques. The second model is an optimal economic planning model for large-scale energy production featuring CCS technologies to reduce CO2 emissions in the oil sands industry. Its goal is to feasibly answer the question: What is the optimal combination of energy production technologies, feedstocks, and CO2 capture processes to use in the oil sands industry that will satisfy energy demands at minimal cost while attaining CO2 reduction targets for given SCO and bitumen production levels? In 2003, steam, H2, and power production are the leading sources of CO2 emissions, accounting for approximately 80% of the total emissions of the oil sands industry. The CO2 intensities calculated by the OSOM range from 0.080 to 0.087 tonne CO2 eq/bbl for SCO and 0.037 tonne CO2 eq/bbl for bitumen. The energy costs in 2003 are $13.63/bbl and $5.37/bbl for SCO and bitumen, respectively. The results from the OSOM indicate that demands for steam, H2, and power will catapult between 2003 and 2030. Steam demands for thermal bitumen extraction will triple between 2003-2012 and triple again between 2012-2030. The H2 demands of the oil sands industry will triple by 2012 and grow by a factor of 2.7 thereafter. Power demands will roughly double between 2003 and 2012 and increase by a factor of 2.4 by 2030. The optimal energy infrastructures featured in this work reveal that natural gas oxyfuel and combined-cycle power plants plus coal gasification H2 plants with CO2 capture hold the greatest promise for optimal CO2-constrained oil sands operations. In 2012, the maximum CO2 reduction level attainable with the optimal infrastructure is 25% while in 2030 this figure is 39% with respect to “business as usual” emissions. The optimal energy costs at maximum CO2 reduction in 2012 are $21.43/bbl (mined SCO), $22.48/bbl (thermal SCO) and $7.86/bbl (bitumen). In 2030, these costs are $29.49/bbl (mined SCO), $31.03/bbl (thermal SCO), and $10.32/bbl (bitumen). CO2 transport and storage costs account for between 2-5% of the total energy costs of SCO and are negligible in the case of bitumen. The optimal energy infrastructures are mostly insensitive to variations in H2 and power plant capital costs. The energy costs are sensitive to changes in natural gas prices and insensitive to changes in coal prices. Variations in CO2 transport and storage costs have little impact on SCO energy costs and a null impact on bitumen energy costs. Likewise, all energy costs are insensitive to changes in the length of the CO2 pipeline for transport.

The In Situ Aquifer Test Facility (ISATF) has been established on Suncor Energy Inc’s (Suncor) oil sands mining lease north of Fort McMurray, Alberta to investigate the fate and transport of oil sands process-affected (PA) water in the Wood Creek Sand Channel (WCSC) aquifer. In 2008, the ISATF was used for preliminary injection experiments in which 3,000 and 4,000 L plumes of PA water were created in the WCSC. Following injection, the evolution of the plumes was monitored to determine if naphthenic acids (NAs) naturally attenuated in the WCSC and if trace metals were mobilized from the aquifer solids due to changes in redox conditions. Post-injection monitoring found groundwater velocities through the aquifer were slow (~3-10 cm/day) despite hydraulic conductivities on the order of 10-3 m/s. While microbes in the WCSC were capable of metabolizing acetate under the manganogenic/ferrogenic redox conditions, field evidence suggests naphthenic acids behaved conservatively. Following the injections, there was an apparent enrichment in the dissolved concentrations of iron, manganese, barium, cobalt, strontium and zinc not attributable to elevated levels in the PA injectate. Given the manganogenic/ferrogenic conditions in the aquifer, Mn(II) and Fe(II) were likely released through reductive dissolution of manganese and iron oxide and oxyhydroxide mineral coatings on the aquifer solids. Because naphthenic acids make up the bulk of dissolved organic carbon (DOC) in the injectate and are apparently recalcitrant to oxidation in the WCSC, some question remains as to what functioned as the electron donor in this process.

Naphthenic acids (NAs) are a group of carboxylic acids that are found in hydrocarbon deposits such as the oil sands bitumen. These compounds are a well-known corrosive agent and a toxic component in the oil sands process water (OSPW). Due to Alberta’s zero discharge policy, OSPW cannot be released and must be stored until toxic components like NAs are remediated. One technique that has shown potential is to physically adsorb NAs onto a copolymer generated from economical biomaterials. Therefore, the project can be divided into three sections: 1) Synthesis of β-cyclodextrin (β-CD) copolymer for the sorption of p-nitrophenol (PNP); 2) Synthesis of chitosan-based copolymers (Chi-Glu) for the sorption of PNP; 3) Sorption of carboxylates and NAs using Chi-Glu copolymers. PNP sorption was used as a probe to understand the physicochemical properties of the copolymers. In the first section, β-CD was reacted with sebacoyl chloride (SCl) and terephthaloyl chloride (TCl) at various mole ratios. Characterization was done using Fourier Transform Infrared Spectroscopy (FT-IR), thermogravimetric analysis (TGA), 1H NMR spectroscopy (1H NMR), elemental analysis (CHN), and nitrogen porosimetry. Copolymers synthesized at mole ratios of β-CD to SCl from 1:1 to 1:3 were hydrolyzed at acidic and basic conditions. Therefore, sorption studies were not done at these ratios. The same occurred for 1:1 to 1:3 TCl copolymers. Sorption studies with PNP at pH 4.6 demonstrated enhanced sorption capacity when comparing with a standard: granular activated carbon (GAC). The sorption capacity, Qm (mmol/g), ordered from largest to smallest is 1:9 SCl>1:9 TCl>1:6 SCl> GAC> 1:6 TCl. Chi-Glu copolymers were synthesized by cross-linking glutaraldehyde with pristine chitosan. A systematic study on the effects reaction conditions have on the sorption capacity of the materials was done. Three conditions were changed: pH, temperature, and mole ratios. Chi-Glu copolymers were synthesized at various chitosan to glutaraldehyde mole ratios (1:400, 1:700, 1:1000). Sufficient time was allowed for the aging process. Characterization was done using TGA, FT-IR, CHN, and nitrogen porosimetry. Sorption study with PNP were done at pH = 7.0 and 9.0. At pH = 7.0 sorption capacity appears to correlate to the quantity of homo-polymerized glutaraldehyde: 1:700>1:1000>1:400. While at pH = 9.0, the sorption capacity is inversely proportional to the degree of crosslinking: 1:400>1:700>1:1000. By increasing the pH at the shrinkage phase, PNP was weakly bound onto the Chi-Glu copolymer. Varying temperature before gelation caused a decrease in the sorption capacity with PNP. Sorption studies involving carboxylates and NAs were done at pH = 9.0 at ambient temperature using Chi-Glu copolymers (1:400, 1:700, and 1:1000) and chitosan. Three carboxylates were chosen to reflect the diverse components in NAs. Varying degrees of cyclization (Z = 0, -2, -4) and lipophilic surface area were the main criteria for carboxylates. The sorption capacity depended mainly on the lipophilic surface area (LSA) with sorption capacity highest for 2-hexyldecanoic acid (S1) which has the largest LSA and lowest for, trans-4-pentylcyclohexanecarboxylic acid (S2) and dicyclohexylacetic acid (S3). Unfortunately, cross-linking with glutaraldehyde does not enhance sorption as pristine chitosan retained a higher sorption capacity compared to Chi-Glu copolymers. Acros and Fluka NAs were chosen for sorption and no significant sorption was recorded for any copolymers. Problems involving the micellization process can explain the lack of sorption.

This research investigated the system by which the social effects of oil sands development on Fort McMurray, a city in northeastern Alberta, are assessed and managed. The research focused on Social Impact Assessment (SIA), Strategic Environmental Assessment (SEA), and the work of an industry initiative, the Regional Issues Working Group (RIWG). The oil sands industry, which involves large, labour-intensive mining and drilling operations in a boom-bust cycle, places considerable pressure on Fort McMurray, a city of approximately 50,000 inhabitants and the only urban area within 350 km of the oil sands. The social effects experienced there include exorbitant housing prices, shortages in service industry labour, insufficient social services, at times, to assist individuals and families who can no longer cope with the difficult conditions in the area, and a variety of other negative effects. Sixteen key informant interviews were conducted with urban planners, municipal politicians, provincial employees, a spokesperson for one of the First Nations in the area, community NGOs, and oil sands industry representatives. Data from the interviews were combined with a literature review and a document analysis. A modified McKinsey 7S Integrated Management Framework was used as a structure for describing and analyzing the Social Effects Assessment and Management System (SEAMS) in Fort McMurray. The SEAMS was found to be weak in comparison to the needs of the community. Project-by-project assessment of oil sands development was found to downplay the cumulative nature of social effects. Furthermore, no legislation or regulation existed that demanded action based on the findings of SIA. As a result, mitigation and management of social effects was insufficient, often occurring only when it was directly in the interests of the oil sands industry. While government and industry have plans in place to resolve some of the negative social effects, their actions were criticized by informants as being uncoordinated, inconsistent and often ineffective. The findings indicate that a strategy for exploiting Alberta's oil sands is necessary. The project-by-project evaluation of oil sands development proposals is not addressing the important long-term and regional social issues that arise as a result of construction and operation of the mines and facilities. A tool recommended for incorporating resolutions to long-term, regional social effects into the development plan is SEA with an explicit Strategic Social Assessment component. This strategic assessment and planning process should be undertaken by a publicly-accountable government body empowered to rationalize the pace of oil sands development based on social, environmental and economic effects, and to coordinate long-term responses by government and industry.

As reserves of conventional crude oil are depleted, there is a growing need to develop unconventional oils such as heavy oil and bitumen from oil sands. In terms of recoverable oil, Canadian oil sands are considered to be the second largest oil reserves in the world. However, the upgrading of bitumen from oil sands to synthetic crude oil (SCO) requires nearly ten times more hydrogen (H₂) than the conventional crude oils. The current H₂ demand for oil sands operations is met mostly by steam reforming of natural gas. With the future expansion of oil sands operations, the demand of H₂ for oil sand operations is likely to quadruple in the next decade. As natural gas reforming involves significant carbon dioxide (CO₂) emissions, this sector is likely to be one of the largest emitters of CO₂ in Canada. <br> <br>In the current H₂ plants, CO₂ emissions originate from two sources, the combustion flue gases from the steam reformer furnace and the off-gas from the process (steam reforming and water-gas shift) reactions. The objective of this study is to develop a process that captures CO₂ at minimum energy penalty in typical H₂ plants. <br> <br>The approach is to look at the best operating conditions when considering the H₂ and steam production, CO₂ production and external fuel requirements. The simulation in this study incorporates the kinetics of the steam methane reforming (SMR) and the water gas shift (WGS) reactions. It also includes the integration of CO₂ capture technologies to typical H₂ plants using pressure swing adsorption (PSA) to purify the H₂ product. These typical H₂ plants are the world standard of producing H₂ and are then considered as the base case for this study. The base case is modified to account for the implementation of CO₂ capture technologies. Two capture schemes are tested in this study. The first process scheme is the integration of a monoethanolamine (MEA) CO₂ scrubbing process. The other scheme is the introduction of a cardo polyimide hollow fibre membrane capture process. Both schemes are designed to capture 80% of the CO₂ from the H₂ process at a purity of 98%. <br> <br>The simulation results show that the H₂ plant with the integration of CO₂ capture has to be operated at the lowest steam to carbon (S/C) ratio, highest inlet temperature of the SMR and lowest inlet temperatures for the WGS converters to attain lowest energy penalty. H₂ plant with membrane separation technology requires higher electricity requirement. However, it produces better quality of steam than the H₂ plant with MEA-CO₂ capture process which is used to supply the electricity requirement of the process. Fuel (highvale coal) is burned to supply the additional electricity requirement. The membrane based H₂ plant requires higher additional electricity requirement for most of the operating conditions tested. However, it requires comparable energy penalty than the H₂ plant with MEA-CO₂ capture process when operated at the lowest energy operating conditions at 80% CO₂ recovery. <br> <br>This thesis also investigates the sensitivity of the energy penalty as function of the percent CO₂ recovery. The break-even point is determined at a certain amount of CO₂ recovery where the amount of energy produced is equal to the amount of energy required. This point, where no additional energy is required, is approximately 73% CO₂ recovery for the MEA based capture plant and 57% CO₂ recovery for the membrane based capture plant. <br> <br>The amount of CO₂ emissions at various CO₂ recoveries using the best operating conditions is also presented. The results show that MEA plant has comparable CO₂ emissions to that of the membrane plant at 80% CO₂ recovery. MEA plant is more attractive than membrane plant at lower CO₂ recoveries.

Western Canadian bitumen is becoming a predominant source of energy for North American markets. The bitumen extraction and upgrading processes in the oil sands industry require vast quantities of energy, in the form of power, H2, steam, hot water, diesel fuel, and natural gas. These energy commodities are almost entirely produced using fossil feedstocks/fuels, which results in significant CO2 atmospheric emissions. CO2 capture and storage (CCS) technologies are recognized as viable means to mitigate CO2 emissions. Coupling CCS technologies to H2 and power plants can drastically reduce the CO2 emissions intensity of the oil sands industry. The CO2 streams from such plants can be used in Enhanced Oil Recovery, Enhanced Coal Bed Methane, and underground CO2 storage. The above CO2 sinks currently exist in Alberta and roughly half of its territory is deemed suitable for geological storage of CO2. This study investigates the relationship between energy demands, energy costs and CO2 emissions associated with current and proposed oil sands operations using various energy production technologies. Accordingly, two computer models have been developed to serve as energy planning and economic optimization tools for the public and private sectors. The first model is an industry-wide mathematical model, called the Oil Sands Operations Model (OSOM). It serves to quantify the demands for power, H2, steam, hot water, process fuel, and diesel fuel of the oil sands industry for given production levels of bitumen and synthetic crude oil (SCO), by mining and/or thermal extraction techniques. The second model is an optimal economic planning model for large-scale energy production featuring CCS technologies to reduce CO2 emissions in the oil sands industry. Its goal is to feasibly answer the question: What is the optimal combination of energy production technologies, feedstocks, and CO2 capture processes to use in the oil sands industry that will satisfy energy demands at minimal cost while attaining CO2 reduction targets for given SCO and bitumen production levels? In 2003, steam, H2, and power production are the leading sources of CO2 emissions, accounting for approximately 80% of the total emissions of the oil sands industry. The CO2 intensities calculated by the OSOM range from 0.080 to 0.087 tonne CO2 eq/bbl for SCO and 0.037 tonne CO2 eq/bbl for bitumen. The energy costs in 2003 are $13.63/bbl and $5.37/bbl for SCO and bitumen, respectively. The results from the OSOM indicate that demands for steam, H2, and power will catapult between 2003 and 2030. Steam demands for thermal bitumen extraction will triple between 2003-2012 and triple again between 2012-2030. The H2 demands of the oil sands industry will triple by 2012 and grow by a factor of 2.7 thereafter. Power demands will roughly double between 2003 and 2012 and increase by a factor of 2.4 by 2030. The optimal energy infrastructures featured in this work reveal that natural gas oxyfuel and combined-cycle power plants plus coal gasification H2 plants with CO2 capture hold the greatest promise for optimal CO2-constrained oil sands operations. In 2012, the maximum CO2 reduction level attainable with the optimal infrastructure is 25% while in 2030 this figure is 39% with respect to “business as usual” emissions. The optimal energy costs at maximum CO2 reduction in 2012 are $21.43/bbl (mined SCO), $22.48/bbl (thermal SCO) and $7.86/bbl (bitumen). In 2030, these costs are $29.49/bbl (mined SCO), $31.03/bbl (thermal SCO), and $10.32/bbl (bitumen). CO2 transport and storage costs account for between 2-5% of the total energy costs of SCO and are negligible in the case of bitumen. The optimal energy infrastructures are mostly insensitive to variations in H2 and power plant capital costs. The energy costs are sensitive to changes in natural gas prices and insensitive to changes in coal prices. Variations in CO2 transport and storage costs have little impact on SCO energy costs and a null impact on bitumen energy costs. Likewise, all energy costs are insensitive to changes in the length of the CO2 pipeline for transport.

The In Situ Aquifer Test Facility (ISATF) has been established on Suncor Energy Inc’s (Suncor) oil sands mining lease north of Fort McMurray, Alberta to investigate the fate and transport of oil sands process-affected (PA) water in the Wood Creek Sand Channel (WCSC) aquifer. In 2008, the ISATF was used for preliminary injection experiments in which 3,000 and 4,000 L plumes of PA water were created in the WCSC. Following injection, the evolution of the plumes was monitored to determine if naphthenic acids (NAs) naturally attenuated in the WCSC and if trace metals were mobilized from the aquifer solids due to changes in redox conditions. Post-injection monitoring found groundwater velocities through the aquifer were slow (~3-10 cm/day) despite hydraulic conductivities on the order of 10-3 m/s. While microbes in the WCSC were capable of metabolizing acetate under the manganogenic/ferrogenic redox conditions, field evidence suggests naphthenic acids behaved conservatively. Following the injections, there was an apparent enrichment in the dissolved concentrations of iron, manganese, barium, cobalt, strontium and zinc not attributable to elevated levels in the PA injectate. Given the manganogenic/ferrogenic conditions in the aquifer, Mn(II) and Fe(II) were likely released through reductive dissolution of manganese and iron oxide and oxyhydroxide mineral coatings on the aquifer solids. Because naphthenic acids make up the bulk of dissolved organic carbon (DOC) in the injectate and are apparently recalcitrant to oxidation in the WCSC, some question remains as to what functioned as the electron donor in this process.