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This paper presents the findings of fifteen energy audits conducted on industrial sites in Canada's Greater Toronto Area (GTA). The audits covered a range of industries including food processing, packaged goods, and finishing processes (powder-coating). The primary focus of the audits was to analyze the natural gas consumption and the performance of major-gas-consuming equipment. The audits identified natural-gas-consuming equipment that could be optimized to yield energy and operational cost savings and greenhouse gas (GHG) reduction opportunities. Food production plants' energy intensity ranges from 5.59 m3/ft2 to 17.73 m3/ft2. Therefore, there is a significant opportunity to improve energy consumption through better technology integration. The results of the audits indicate a trend of an increase in the percentage of non-productive consumption with non-productive time. The proposed energy-saving measures include reducing non-productive natural gas consumption, gas-fired equipment tune-up, optimizing boiler loads, and reducing oven exhaust by using variable frequency drives (VFDs). The findings of this study could be used to develop a demand-side management program specifically for small- and medium-sized industrial facilities in the Greater Toronto Area and other parts of Canada. [ABSTRACT FROM AUTHOR]

This study presents a systematic workflow for estimating hydrogen storage capacity for a smooth energy transition from natural gas market to hydrogen market to achieve net-zero emissions. The workflow establishes maximum and minimum thresholds for hydrogen storage and considers appropriate storage techniques, including underground or surface facilities. The technique assesses environmental footprint of each storage technique and evaluates associated emission reductions. We apply this workflow to energy market in Alberta and project minimum and maximum storage thresholds of 0.28 and 5 megatonne/year (Mt/year) by 2050. Under three distinct storage scenarios, the storage capacity necessitates 128 salt caverns, 10 million compressed gas tanks, or 78,150 cryogenic liquefied tanks. Salt cavern storage emerges as a promising choice owing to its relatively lower emissions of 0.16 MtCO 2 e/year and a land footprint of 2.56 km2. The net emission reduction achieved is 1.47 MtCO 2 e/year, equivalent to 0.8% of Canada's target emission reduction of 190 MtCO 2 e/year by 2050. • A workflow is developed to forecast required hydrogen storage capacity in Alberta. • Salt caverns emerge as a reliable and practical technique for large-scale hydrogen storage. • The workflow projects the required number of salt caverns for hydrogen storage. • Supplying stored hydrogen to market reduces 1.5 megatonne/year of GHG emissions. [ABSTRACT FROM AUTHOR]

The amount of municipal solid waste (MSW) generation in Canada was 34 million tonnes in 2018. Responsible waste management is challenging, but essential to protect the environment and to prevent the contamination of the ecosystem on which we rely. Landfilling is the least desirable option, and diversion through thermo-chemical conversion to value-added products is a good option for difficult-to-recycle waste. In this study, the amounts, moisture contents, heating values, and compositions of municipally collected solid waste produced in Canada are reported, a classification that is suitable for conversion purposes is proposed, and the potential for thermo-chemical conversion is determined. Much of the waste generated in Canada is suitable for being converted, and its potential for heat or electricity generation was determined to be 193 PJ/yr and 37 TWh/y, respectively. The GHG emissions that are saved through diversion from the landfill, while assuming the generated heat or electricity offsets natural gas combustion, gives a GHG reduction of 10.6 MMTCO2E/yr or 1.6% of Canada's GHG emissions. The blending of waste in feedstocks can have varying effects on the amount of biogenic CO2 produced per unit energy in the feedstock, which is an important consideration for new projects. Other considerations include the heating values, moisture contents, and contaminant levels in the waste. [ABSTRACT FROM AUTHOR]

Natural gas is believed to be a critical transitional energy source. However, natural gas pipelines, once failed, will contribute to a large amount of greenhouse gas (GHG) emissions, including methane from uncontrolled natural gas venting and carbon dioxide from flared natural gas. However, the GHG emissions caused by pipeline incidents are not included in the regular inventories, making the counted GHG amount deviate from the reality. This study, for the first time, establishes an inventory framework for GHG emissions including all natural gas pipeline incidents in the two of the largest gas producers and consumers in North America (United States and Canada) from 1980s to 2021. The inventory comprises GHG emissions resulting from gathering and transmission pipeline incidents in a total of 24 states or regions in the United States between 1970 and 2021, local distribution pipeline incidents in 22 states or regions between 1970 and 2021, as well as natural gas pipeline incidents in a total of 7 provinces or regions in Canada between 1979 and 2021. These datasets can improve the accuracy of regular emission inventories by covering more emission sources in the United States and Canada and provide essential information for climate-oriented pipeline integrity management. [ABSTRACT FROM AUTHOR]

This paper demonstrates how qualitative analysis can be a novel means of investigating theories of error and causation in natural gas pipeline incidents. Qualitative analysis offers unique opportunities to understand process, interactions, and the role of context in identifying active error and latent conditions in incident causation. Through the coding of text from 24 onshore natural gas pipeline incident reports on leaks and explosions in the United States and Canada, our findings reveal a proportion of active and latent errors consistent with other hazardous infrastructure contexts (roughly 3:1 latent‐active ratio across 817 coded errors). These findings underscore the robustness of extant error theory and support the argument for documenting multiple, connected causes of disaster in aggregate. Conclusions highlight the utility of in‐depth case analyses and critique present pipeline incident database aggregation. Our interpretation provides a means to convey complex causation in aggregate form thus enabling more nuanced future qualitative and qualitative analyses. [ABSTRACT FROM AUTHOR]

Large scale, low cost, and low carbon intensity hydrogen production is needed to reduce emissions in the energy and transportation sectors. We present a techno-economic analysis and life cycle assessment of natural gas pyrolysis technologies for hydrogen production, with carbon black (CB) as a co-product. Four designs were considered based on the source of heat to the pyrolysis system, the combustion medium, and use of carbon capture (CC) technology. The oxygen-fired-CB design with CC is the most attractive from financial and environmental perspectives, superior to a conventional steam methane reformer (SMR) process with CC. The estimated pre-tax minimum hydrogen selling prices for the pyrolysis technologies range between $1.08/kg and $2.43/kg when natural gas (NG) costs $3.76/GJ. Key advantages include near-zero onsite GHG emissions of the oxygen-fired-CB design with CC and up to 41% lower GHG emissions compared to the SMR + CC process. The results indicate that natural gas pyrolysis may be a feasible pathway for hydrogen production. • Commercial scale hydrogen production via natural gas pyrolysis pathways is explored. • Options for handling the carbon black product are examined. • Low-carbon hydrogen of $1.7/kgH 2 outperforms the SMR hydrogen at similar conditions. • Cradle to gate GHG emissions between 1.8 and 4.6 kgCO 2 eq/kgH 2 is computed. [ABSTRACT FROM AUTHOR]

Achieving net zero carbon dioxide (CO2) emissions will require the cessation of fossil fuel emissions into the atmosphere, yet the need for 'fuel' and energy storage will remain. One solution could be a carbon‐based fuel system where CO2 of biogenic origin is converted to fuels using hydrogen generated by electrolysis powered by renewable energy sources. Methane has value as an initial target given its prevalence in biogas, use in home heating and in electricity generation. Sources of CO2 in Eastern Canada are dominated by the iron and steel, cement, and aluminium industries, all of which have biogenic fuel options. Collecting all of the potentially biogenic CO2 would displace 75% of current natural gas use and require a 50% increase in generating capacity. Initial efforts could site a carbon capture, utilization, and storage facility near Montreal, QC, with other large‐scale facilities near Hamilton, ON, and Lac St‐Jean, QC. These facilities would be grid connected and expected to operate ~6200 h annually. The most high‐frequency electrolysis events would be 10 h of run time and 2 h of idle time. These periods would peak during the equinox months and be at a minimum during the winter solstice. These operational assumptions will all be subject to the increased variability caused by anthropogenic climate change and increased renewable generation on the grid. A closed‐loop carbon‐based fuel system would require an equivalent price of $250 per tonne CO2. [ABSTRACT FROM AUTHOR]

We use satellite methane observations from the Tropospheric Monitoring Instrument (TROPOMI), for May 2018 to February 2020, to quantify methane emissions from individual oil and natural gas (O/G) basins in the US and Canada using a high-resolution (∼25 km) atmospheric inverse analysis. Our satellite-derived emission estimates show good consistency with in situ field measurements (R=0.96) in 14 O/G basins distributed across the US and Canada. Aggregating our results to the national scale, we obtain O/G -related methane emission estimates of 12.6±2.1 Tg a -1 for the US and 2.2±0.6 Tg a -1 for Canada, 80 % and 40 %, respectively, higher than the national inventories reported to the United Nations. About 70 % of the discrepancy in the US Environmental Protection Agency (EPA) inventory can be attributed to five O/G basins, the Permian, Haynesville, Anadarko, Eagle Ford, and Barnett basins, which in total account for 40 % of US emissions. We show more generally that our TROPOMI inversion framework can quantify methane emissions exceeding 0.2–0.5 Tg a -1 from individual O/G basins, thus providing an effective tool for monitoring methane emissions from large O/G basins globally. [ABSTRACT FROM AUTHOR]

Gas hydrates are inclusion compounds of a water backbone that encloses gaseous molecules. Thanks to their applications in gas recovery, carbon capture and storage, gas storage, and flow assurance, generating high quality data and predictions of their properties is paramount. A review of novel techniques using first principles density functional theory and molecular dynamics simulations methods coupled to auxiliary simulations methods is presented herein. Structure I (sI), structure II (sII), and structure H (sH) hydrates have been studied extensively, with studies of their material strength showing that it is often misleading to use the properties of ice instead of the difficult‐to‐determine gas hydrate properties. Key differences between the three structures and their possible guests are presented. The interfacial properties of gas hydrates display key behaviours that control nucleation and growth, which are important phases in controlling and monitoring their formation. Gas hydrate thermal properties are also examined, with key differences existing between guests and some unusual alignment in the cages shown for carbon dioxide, ethane, and ethylene oxide sI hydrates. First principles infrared spectroscopy is also examined, with techniques showing that these signatures can be tied to and predict material properties to improve the speed of analysis. Therefore, by quantifying, modelling, predicting, and explaining their formation and dissociation, and linking these to their thermal, material, and interfacial properties, a database of reliable data for science and engineering methods and applications is formed to provide a basis for further work. [ABSTRACT FROM AUTHOR]

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Canada's historical legal framework for hydrocarbon development persists, creating a 'carbon energy overhang' that impedes the transition to a low-carbon economy on which Canadian governments have embarked. As a result, Canada remains a petro-state, the fourth largest global oil producer with the third largest reserves. There have been greenhouse gas emission reduction initiatives, particularly by the federal government, including a national carbon tax (that survived constitutional challenge), renewable energy initiatives, energy transition legislation establishing net zero goals, and a promised cap on oil and gas industry emissions. However, two major barriers remain, notably (1) the national economic importance of the oil and gas industry with its oil sands centrepiece, located mainly in the province of Alberta; and (2) very limited room to cut electricity generation emissions, with over 80 per cent of electricity already produced by renewables and nuclear, and a lack of interprovincial transmission interties with these renewable electricity (mainly hydro)-producing provinces that export large quantities of energy to the United States. [ABSTRACT FROM AUTHOR]

The occurrence and emissions of methane (CH4) from above-ground urban natural gas infrastructure is poorly understood. Compared to below-ground infrastructure, these facilities are relatively easy to monitor and maintain and present an opportunity for cost-effective CH4 reductions. We present a case study and methodology for detecting, attributing, and quantifying CH4 emissions from fence line measurements at above-ground natural gas facilities in the City of Calgary, Alberta, Canada. We produced bounding-box concentration maps by walking around the outer fence of 33 facilities with a backpack-configured trace gas analyzer and a tablet with integrated GPS. Wind measurements were acquired simultaneously from a fixed location on site with a 3D sonic anemometer. We fused geolocation, CH4 concentration, and wind data to determine the likelihood each facility was emitting. We found one definitive leak by carrying out measurements directly alongside an exposed section of pipe. Based on the presence of methyl mercaptan (CH3SH) odor, peak ΔCH4, and the difference between downwind and upwind ΔCH4, we interpret a high plausibility that 22 facilities were emitting CH4, followed by 2 with a medium plausibility, and 8 with a low plausibility. Once verified to plausibly emit, these data were used to estimate emissions flux at six facilities where near-field obstructions were limited. The estimated emissions flux for six facilities was 66.31 mg CH4 s−1, or 2.1 tonnes CH4 yr−1 if this flux remained constant. Overall, this study indicates most above-ground natural gas facilities surveyed in Calgary were emitting CH4. These facilities represent easy mitigation targets for reducing CH4 emissions and improving environmental performance. To our knowledge, this is the first study to integrate qualitative and quantitative information to predict detection plausibility in a complex measurement setting. Implications: The fence line methodology outlined in this study represents an extension of source assessment modes in the US EPA's Other Test Method 33A for human portable systems. This has implications for standardization of emissions measurement in situations where other platforms (e.g., vehicles) are less effective due to access limitations. We believe the methodology presented could become a recognized standard based on performance from controlled testing and added to the regulatory toolkit for emissions verification and compliance. [ABSTRACT FROM AUTHOR]

An eQUEST model was developed to conduct a simulation study of a natural gas engine-driven heat pump (GEHP) for an office building in Woodstock, Ontario, Canada. Prior to the installation of the GEHP, the heating and cooling demands of the office building were provided by rooftop units (RTUs), comprising of natural gas heater and electric air conditioner. Energy consumption for both GEHP and RTUs were monitored for operation in alternating months. These recorded energy consumptions along with weather data were used in the regression analysis. The developed eQUEST models were validated and calibrated with the regression analysis results with respect to the ASHRAE Guideline 14–2014. The eventual models were then applied to investigate the potential annual energy consumption, greenhouse gas (GHG) emission and energy cost savings achieved by using the GEHP in Woodstock, and other cities in Canada, particularly in Ontario. [ABSTRACT FROM AUTHOR]

The main petroleum product transported through pipelines in Canada is diluted bitumen (dilbit), a semiliquid form of heavy crude oil mixed with natural gas condensates to facilitate transport. The weathering, fate, behavior, and environmental effects of dilbit are crucial to consider when responding to a spill; however, few environmental studies on dilbit have been completed. We report on 11‐d‐long experimental spills of dilbit (Cold Lake Winter Blend) in outdoor microcosms meant to simulate a low‐energy aquatic system containing natural lake water and sediments treated with low (1:8000 oil:water) and high (1:800 oil:water) volumes of dilbit. In the first 24 h of the experiment, volatile hydrocarbons quickly evaporated from the dilbit, resulting in increased dilbit density and viscosity. These changes in dilbit's physical and chemical properties ultimately led to its submergence after 8 d. We also detected rapid accumulation of polycyclic aromatic compounds in the water column of the treated microcosms following the spills. The present study provides new information on the environmental fate and behavior of dilbit in a freshwater environment that will be critical to environmental risk assessments of proposed pipeline projects. In particular, the study demonstrates the propensity for dilbit to sink under ambient environmental conditions in freshwaters typical of many boreal lakes. Environ Toxicol Chem 2019;38:2621–2628. © 2019 SETAC [ABSTRACT FROM AUTHOR]

Canada-wide climate change plans have been put in place in the form of legislation and emission reduction programs. As part of these measures, reduced amounts of natural gas can be vented, incinerated, or flared. These programs have a direct impact on the Canadian oil and gas industry. Other measures mandate the decommissioning of high-emission thermal power plants, such as coal-fired generation. At the same time, governments are encouraging the wide-scale adoption of distributed energy resources (DERs). Because of these changes, natural gas fired DERs have been proliferating in oilfields to consume the byproduct natural gas and most major oil and gas companies are diversifying their portfolio to include generation assets. It is a more sustainable and environmentally friendly scenario as compared to the previous status quo. From an electric utility standpoint, this represents a change in paradigm, because distribution systems are traditionally planned to be radial and only experience power flowing from the substation to the load centers. This change requires utilities to adapt to new concerns and requirements, which span from operation to health and safety hazards. Among these, anti-islanding is likely the most important concern to allow the safe and reliable operation of a distribution system. The standard method to avoid unintended islanded operation is the direct transfer trip. Under exceptional circumstances, the utility may waive this requirement if an alternative acceptable method is in use. This article addresses existing anti-islanding schemes and covers in detail an alternative anti-islanding method native to many inverters. This article contains the philosophy of such method and measurement results captured during commissioning of a DER containing the scheme. Furthermore, this article highlights the evolution of inverter-based generator technologies and how the revision of applicable standards (IEEE 1547) can improve the reliable operation of such DERs. [ABSTRACT FROM AUTHOR]

In the USA and Canada where most of global shale oil and gas development has occurred, due to concerns about climate change the national governments have adopted new regulations to further significantly reduce national methane emissions from the upstream oil and gas industry. The 2016 US Environmental Protection Agency emissions standards and 2018 Canadian methane regulations build on decades old oil and gas conservation schemes to further reduce the volume of methane that is released from facility equipment leaks and venting. In Canada, venting methane at new oil and gas well sites is now prohibited. Operators are required to capture and use a much larger volume of natural gas than in the past. A negotiated settlement of the first US emissions reduction enforcement action was reached in April 2018. The facility operator agreed to pay a civil penalty of US $610,000 and spend a minimum of $2 million to install new technology at its facilities to further reduce methane emissions. The creative settlement agreement contains a comprehensive set of conditions to provide for a reduction in upstream industry emissions. [ABSTRACT FROM AUTHOR]

When glacial cycles occur above low‐permeability geologic formations, such as the shale and limestone units being considered for nuclear waste disposal in Canada, pressures may differ greatly from normal hydrostatic conditions. Although shale also often has the propensity to generate separate phase fluids like natural gas, it is largely uncertain how the processes that control this behavior might affect water pressure evolution during glacial loading cycles. Therefore, this study investigates the relationships among these system components via an example site that exhibits both a dramatic underpressure and potential evidence for gas phase methane in situ. A simple 1‐D representation of the site was constructed, and hydromechanical coupling during a glacial cycle was simulated with and without gas phase methane present. Results indicate that, while the presence of gas phase dampened the effects of the loading cycle due to its higher compressibility compared to water, it did not preclude underpressure development. Plain Language Summary: To protect water resources from contamination, many countries are planning to store nuclear waste underground within very tight layers of rock. To assess the safety of this strategy, we must understand how fluids might move through these rock layers over long periods of time. Anomalous pressures in low‐permeability rocks offer clues into long‐term flow processes, but natural gas complicates the pressure evolution. Therefore, in this study we performed mathematical simulations of water flow under the influence of glacial forces, with and without natural gas present. While gas phase somewhat counteracted the glacial effects due to its higher compressibility, underpressures similar to the measured values were still produced in both single‐phase and multiphase simulations. These results help to improve our understanding of the processes that might occur within the rocks at nuclear waste repository sites after they are built, thus protecting humans from potential contamination. Key Points: Vertical stresses from both ice weight and crustal flexure were incorporated in a 1‐D model of a proposed nuclear waste repository siteGas phase dampened the effects of glacial loading on simulated long‐term water pressure evolution at the proposed repository siteHydromechanical coupling could have led to underpressure in shale at the site, even if gas phase methane is assumed to be present in situ [ABSTRACT FROM AUTHOR]

A significant transition in Canada's electricity system is needed to achieve the zero-emission target that has been set for 2035. Many studies have charted possible decarbonization pathways to achieve this target, but most focus on commercially available generation technologies. In this study, we modify and deploy the electricity system planning model, COPPER, to explore the role of emerging technologies in Canada's electricity system transition under a suite of plausible scenarios. Results show that, if developed and deployed, low- or non-emitting thermal technologies alongside offshore wind could contribute to the transition on the national scale, but specific adoption patterns differ by province: provinces that must phase out fossil fuel generation add natural gas with carbon capture and storage to provide dispatchable capacity with low operation cost; provinces with an emissions cap or inflexible network integrate hydrogen combustion that operates as peaking facilities; offshore wind and small modular reactors are part of the optimal mix for emissions constrained provinces or provinces with a flexible network, respectively. Since the best-suited technologies differ by region, provinces should explore available opportunities, including emerging technology, identify suitable options, and leverage them to facilitate their electricity system transitions. • Dispatchable non- or low-emitting technologies can play a major role in the future. • Gas with carbon capture and storage can be used to meet the baseload demand. • Hydrogen has the potential to substitude natural gas. • Offshore wind is expected to contribute to the transition modestly. • Further reductions in small modular nuclear reactors costs are required to become cost-effective. [ABSTRACT FROM AUTHOR]

We examined the historical deposition of polycyclic aromatic compounds (PACs) recorded in radiometrically-dated lake sediment cores from a small, conventional oil and gas operation in the southern Northwest Territories (Cameron Hills), and placed these results in the context of previously published work from three other important regions of western Canada: (1) the Athabasca oil sands region in Alberta; (2) Cold Lake, Alberta; and (3) the Mackenzie Delta, NT. Sediment PAC records from the Cameron Hills showed no clear changes in either source or concentrations coincident with the timing of development in these regions. Changes were small in comparison to the clear increases in both parent and alkyl-substituted PACs in response to industrial development from the Athabasca region surface mining of oil sands, where parent PAC diagnostic ratios indicated a shift from pyrogenic sources (primarily wood and coal burning) in pre-development sediments to more petrogenically-sourced PACs in modern sediments. Cores near in-situ oil sand extraction operations showed only modest increases in PAC deposition. This work directly compares the history and trajectory of contamination in lake ecosystems in areas of western Canada impacted by the most common types of hydrocarbon extraction activities, and provides a context for assessing the environmental impacts of oil and gas development in the future. [ABSTRACT FROM AUTHOR]

Storage and transfer of hydrogen (H 2) from production sites/plants to large-scale demanding industries are one of the most challenging obstacles to hydrogen adoption. Hydrogen liquefaction and its chemical storage in the form of ammonia (NH 3) can be used for safe and economic transportation. High energy consumption and carbon dioxide (CO 2) emissions to supply the utility of these systems can limit the production of liquid H 2 and liquid NH 3. Therefore, efficient design and practical strategies to store hydrogen at a large scale with minimal energy consumption and CO 2 emissions are necessary. In this research, an innovative hybrid system for portable hydrogen storage and power generation with zero CO 2 emission through liquefied natural gas (LNG) regasification is developed. The proposed structure includes a cryogenic air separation unit, magnesium–chloride hydrogen production process, ammonia production system, hydrogen liquefaction cycle, and Rankine/oxy-fuel power plants. The heat loss of the proposed structure is utilized to supply the required heat load for the thermo-electrochemical unit. The LNG regasification operation is utilized for pre-cooling the hydrogen liquefaction system and the necessary refrigeration of the air separation process and the final products. The developed structure is fed by 1883 kmol/h LNG, which is converted to 120 kmol/h liquid NH 3 , 180 kmol/h liquid H 2 , 924.5 liquid CO 2 , and 16.09 MW power. The thermal and exergy efficiencies for the designed system are 20.33% and 22.76%, respectively. The results of the exergy investigation reveal that the largest contribution of exergy destruction occurs in heat exchangers (31.27%), combustion chamber (34.65%), and turbines (8.12%). The economic evaluation indicates that the net annual profit, added value, and payback period are 15.93 US$/yr, 0.0779 US$/kWh, and 5.646 yr, respectively, based on the energy potential of Newfoundland and Labrador in Canada. Three-objective optimization approach using the combination of genetic algorithm and neural network exhibits that the energy efficiency and net annual profit based on the Bellman-Zadeh approach increase up to 27.04% and 45.20 US$/MMBTU, respectively, and the irreversibility reduces to 99.4 MW. [Display omitted] • A novel structure for production of power, liquid H 2 , liquid NH 3 , and liquid CO 2 is developed. • The LNG regasification is used in hydrogen liquefaction and air separation systems. • The waste heat of the oxy-fuel power plant is recovered in Mg–Cl unit for hydrogen production. • The system exergy efficiency and payback period are 22.76% and 5.646 yr, respectively. • A combination of the GA and AI is used for optimization. [ABSTRACT FROM AUTHOR]

The upward trend in global natural gas consumption, combined with fugitive and combustion GHG emissions released along its supply chain and use, make the natural gas sector a large GHG emitter and a prime candidate for creative solutions to reducing environmental impact. In this study, the environmental and economic implications of substituting natural gas-powered drivers with electric drivers at compressor stations in Canada's natural gas transmission system are evaluated. GHG emissions associated with the business as usual compressor drivers compared to conversion to electrically driven drivers in 6 Canadian provinces incorporating temporally resolved grid emissions are analyzed. Additionally, the economic difference in the operational costs of natural gas and electricity driven compression is determined and combined with GHG results to estimate the cost of carbon savings for conversion. Results show that electric compressors result in GHG savings in 4 out of the 6 provinces. The large share of fossil fuels in Alberta's and Saskatchewan's electricity grids result in natural gas-powered drivers having lower GHG emissions. Operational costs are larger for electric compression and are found to be competitive with natural gas drivers economically only in some provinces if a social cost of carbon (carbon tax) are included. The study shows promising GHG reduction opportunities if electric drivers are employed in provinces where the electricity grid has low carbon intensity. [ABSTRACT FROM AUTHOR]

Bitumen extracted from oil sands which is abundant in Canada needs to be partially upgraded in order to meet pipeline specifications before being sent to downstream refineries. Hydrotreating where expensive hydrogen is involved at high pressure (15 ∼ 20 MPa) is commonly employed as the technique to satisfy the upgrading requirement. In this study it is reported that a partially upgraded crude oil can be readily produced from bitumen under methane environment at mild conditions (400 °C and 3 MPa) without H 2 engagement under the facilitation of 5%Mo/ZSM-5 (SiO 2 /Al 2 O 3 = 23:1). The methane participation into the upgrading process was evidenced by analyzing the products obtained from the methanotreating of styrene and n -butylbenzene, the model compounds to represent heavy oil, as well as the heat effect during upgrading. Direct evidence of methane incorporation into the product molecules is observed on 1 H, 2 D and 13 C NMR spectra, revealing that the carbon and hydrogen from methane occupy the phenyl carbon sites and aromatic and benzylic hydrogen sites, respectively, in the product molecules. Through extensive catalyst characterizations using TEM, XRD, and XPS, the excellent catalytic upgrading performance might be closely related to the highly dispersed molybdenum oxide particles on the zeolite support at partially reduced oxidation state for better methane activation. The outcomes from this research could not only create an innovative route for more profitable natural gas utilization, but also benefit bitumen partial upgrading in a more economical and environmentally friendly way. [ABSTRACT FROM AUTHOR]

The federal government's decision to impose a minimum national price on carbon emissions has the potential to make certain businesses in the country less competitive. Specifically, there are emissions-intensive and trade-exposed industries across Canada that compete against producers from other jurisdictions where governments do not put a price on carbon. For these industries, the obligation to pay a carbon price creates a competitive disadvantage. Specifically, these businesses will face higher costs and may encounter a loss of market share to international competitors from jurisdictions that lack the same emission-control measures. That not only hurts Canadian businesses, it could also negate any emissions reductions that carbon pricing in Canada achieves on a global scale. The federal government has opted to protect such emissions-intensive, tradeexposed businesses using subsidies called output-based allocations (OBAs). This is the same system that Alberta is introducing through its forthcoming Carbon Competiveness Regulation. It also shares certain similarities with cap-and-trade programs, such as those in Ontario and Quebec, which provide free allocations of emissions permits to certain firms. OBAs are a desirable complementary policy to a carbon price as they maintain the incentive for producers to invest in production methods and facilities that are less emissions intensive. So while producers are still, nevertheless, subsidized to offset the tax burden of the carbon price, they will, under an OBA system, see greater benefits the more they work to reduce their emissions intensity. Still, to function most effectively and most efficiently, an OBA policy should follow certain key principles. The most critical principle in the design of an OBA policy is ensuring that OBAs are allocated to facilities independent of their individual emission levels, and allocated equally (on a per unit basis) to facilities producing the same product. One of the major flaws with Alberta's current Specified Gas Emitters Regulation (SGER) is that it does not follow this principle. Rather, subsidies under SGER are allocated based on a facility's historical emissions intensity. As a result, more generous subsidies are given to those facilities that are "dirtier" (that is, those with higher emissions intensities) than to "cleaner" facilities with lower emission intensities. Secondly, it is important for a well-designed OBA policy to have transparent costs. Including a clear accounting of OBAs in government finance reports will ensure the public is fully aware of the revenues being directed to the subsidies. Thirdly, OBAs for different facilities are best allocated using a classification system based on the product being produced, and not using more conventional industry-classification codes. Commonly used conventional industry classifications--for example, conventional oil and natural gas extraction--group together facilities that produce distinct products and compete in different markets. Consequently, this classification will not recognize the various levels of emissions intensity and trade exposure within an industry. This will result in some facilities receiving more OBAs than they should and others receiving less than they should. Finally, a well-designed OBA system should seek to be as administratively efficient as possible with minimal implementation costs imposed on government and businesses. It is important to recognize that the federal carbon price and OBAs are a new policy and that many large emitting facilities have been making investment decisions based on a previous regulatory environment. Therefore, a compromise approach may be to initially provide an output subsidy based on a facility's past emissions intensity (as Alberta has historically done under its SGER system) and then to transition gradually to the optimal OBA system over time. [ABSTRACT FROM AUTHOR]

The article provides information on the economic growth of Canadian Oil & Gas Compaines in the year 2013 as compare to the world. It also states on the Exploration and Production Companies of Canada. Topics discussed includes natural gas liquid, international trade and energy industries production.

Moving to a low-carbon future will create challenges for Canada’s fossil-fuel industries, but opportunities in the form of a new market for low-carbon goods and services. The challenges for the resource sector will vary across commodities. Competition in the new market for low-carbon goods and services will be tough; sustained competitive advantage will be difficult to maintain due to capital mobility. With these challenges in mind, this article proposes three questions for Canadians looking ahead to a low-carbon future. First, how large will the market for low-carbon goods and services be? Second, where are Canada’s advantages likely to lie in serving these markets? Finally, what are the roles for Canada’s existing natural-resource industries in a low-carbon economy, and what are the strategies to maximize the value of these resources? [ABSTRACT FROM AUTHOR]

The Peace River district of Northeastern British Columbia, Canada is a region of natural gas production that has undergone rapid expansion since 2005. In order to assess air quality implications, Willems badge passive diffusive samplers were deployed for six two-week exposure periods between August and November 2013, at 24 sites across the region to assess the ambient concentration of nitrogen dioxide (NO 2 ) and sulfur dioxide (SO 2 ). The highest concentrations of both species (NO 2 : 9.1 ppb, SO 2 : 1.91 ppb) during the whole study period (except the 1st exposure period), were observed in Taylor (Site 14), which is consistent with its location near major industrial sources. Emissions from industrial activities, and their interaction with meteorology and topography, result in variations in atmospheric dispersion that can increase air pollution concentrations in Taylor. However, relatively high concentrations of NO 2 were also observed near the center of Chetwynd (site F20), indicating the importance of urban emissions sources in the region as well. Observations of both species from the other study sites document the spatial variability and show relatively high concentrations near Fort St. John and Dawson Creek, where unconventional oil and gas development activities are quite high. Although a few sites in Northeastern British Columbia recorded elevated concentrations of NO 2 and SO 2 during this investigation, the concentrations over the three-month period were well below provincial annual ambient air quality objectives. Nonetheless, given the limited observations in the region, and the accelerated importance of unconventional oil and gas extraction in meeting energy demands, it is imperative that monitoring networks are established to further assess the potential for elevated ambient concentrations associated with industrial emissions sources in the Peace River region. [ABSTRACT FROM AUTHOR]

The article describes the problems that burden Canada's wholesale electricity market, the potential for hydropower imports to solve those problems, and the regulatory changes needed to accomplish it. Topics include New England's reliance on natural gas-fired generation as a consequence of simple economic and environmental realities, practical advantages of natural gas, and the reduction in the emission of pollutants by power plants.

The oil sands resource in Western Canada are a considerable energy asset for Canada, but the energy and emissions intensities of producing this petroleum resource are substantially worse than that of conventional petroleum resources. With requirements for carbon-intensity reduction, new, less emissive recovery processes must be developed to enable continued production and cash flow from this important resource. The largest source of carbon emissions on in-situ in oil sands recovery processes, such as Steam-Assisted Gravity Drainage (SAGD), is steam generation, where natural gas is combusted. An alternative to conventional steam generation is Direct Contact Steam Generation (DCSG), where steam is generated in the combustion flame, and with rich oxygen combustion, the steam plus carbon dioxide mixture is injected into the reservoir. We explore the carbon intensity of DCSG and compare it to existing once-through steam generation using life cycle analysis. The results reveal considerable environmental benefits with nearly 30% emission reduction when applying a DCSG in SAGD instead of an OTSG. The results suggest that oil sands operators could improve their emissions intensity significantly if they adopted DCSGs in their operations. [Display omitted] • In-situ oil sands recovery processes use once-through steam generation (OTSG). • Steam-Assisted Gravity Drainage recovery process has high greenhouse gas emissions. • Direct contact steam generation (DCSG) injects steam + carbon dioxide into reservoir. • Life cycle assessment results demonstrate that DCSG is better than existing OTSG. • DCSG yield nearly 30% reduction of greenhouse gas emissions versus OTSG. [ABSTRACT FROM AUTHOR]

Combined cooling, heating, and power (CCHP) systems are considered energy efficient and they can be economically rewarding only when the inter-dependencies of energy prices for electricity and natural gas (NG) are properly accounted for. The goal of this study is to determine the optimal hourly energy prices for electricity and NG for a non-autonomous CCHP system using particle swarm optimization algorithm based on bi-level programming approach. Based on optimal sizing and configuration of the CCHP system, the rewards for both the distribution utility and the industrial energy consumer are analyzed. For simulation purposes in this study, a CCHP system with known loads operated in Ontario, Canada, based on actual energy prices is examined. For a CCHP system with gas turbine (GT) as prime mover, the optimal energy prices for on-peak and off-peak periods for spring, summer, fall, and winter for electricity and NG are determined. It is found that for the on-peak period, if the electricity prices in winter are 1.16, 1.56, and 1.75 times greater than those in summer, fall, and spring, respectively, and if the NG prices in winter are 1.19, 1.64, and 1.86 times greater than those in summer, fall, and spring, respectively, the rewards for distribution utility and industrial energy consumer are guaranteed. Based on the simulation results, it is determined that, under the optimal hourly energy prices for electricity and NG, the industrial energy consumer meets in excess of 92% of its needed electricity by the CCHP system that is sized and configured optimally with capital recovery of 2–3 years. [ABSTRACT FROM AUTHOR]

The United States and Canada have seen a competitive and technological revolution in unconventional natural gas production in the 21st Century—dramatically lowering the price of gas and displacing high-carbon coal with low-carbon gas for power generation. This gas revolution came from an earlier revolution in the regulation of gas pipelines, which ended the obstruction of gas markets by pipeline interests. Neither revolution has spread to Europe, where increasingly protectionist EU legislation has effectively blocked competitive pipeline entry and related gas markets. As a result, unconventional gas is untapped, coal displaces gas for power generation, and oil-linked gas prices have cost EU consumers a staggering $425 billion more than their US counterparts have paid since 2009 for about the same quantity of gas. Europe faces a serious institutional challenge to adopting the kind of pipeline regulation that facilitates the competitive flow of natural gas supplies and the accompanying lower carbon emissions. (JEL: D23, K23, L14, L51, L95, N70, Q54) [ABSTRACT FROM AUTHOR]