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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]

North American and European jurisdictions are considering repurposing natural gas infrastructure to deliver a lower carbon blend of natural gas and hydrogen; this paper evaluates the greenhouse gas reduction potential and cost-effectiveness of the repurposing. The analysis uses a bottom-up economy-wide energy-systems model of an emission-intensive jurisdiction, Alberta, Canada, to evaluate 576 long-term scenarios from 2026 to 2050. Many scenarios were included to give the analysis broad international applicability and differ by sector, hydrogen blending intensity, carbon policy, and hydrogen infrastructure development. Twelve hydrogen production technologies are compared in a long-term greenhouse gas and cost analysis, including advanced technologies. Autothermal reforming with carbon capture provides both lower-carbon and lower-cost hydrogen compared to most other technologies in most futures, even with high fugitive natural gas production emissions. Using hydrogen-natural gas blends for end-use energy applications eliminates 1–2% of economy-wide GHG emissions and marginal GHG abatement costs become negative at carbon prices over $300/tonne. The findings are useful for stakeholders expanding the international low-carbon hydrogen economy and governments engaged in formulating decarbonization policies and are considering hydrogen as an option. • Bottom-up economy-wide energy systems model of 576 long-term scenarios. • Long-term cost and GHG footprint of 12 H 2 production technologies analysed. • Economy-wide hydrogen-natural gas blending eliminates 1–2% of GHG emissions. • H 2 -natural gas blends increase energy costs unless the carbon price is over $300/t. [ABSTRACT FROM AUTHOR]

A comprehensive technical analysis of available industry-reported well activity and production data for Alberta in 2011 has been used to derive flaring, venting, and diesel combustion greenhouse gas and criteria air contaminant emission factors specifically linked to drilling, completion, and operation of hydraulically fractured natural gas wells. Analysis revealed that in-line ("green") completions were used at approximately 53% of wells completed in 2011, and in other cases the majority (99.5%) of flowback gases were flared rather than vented. Comparisons with limited analogous data available in the literature revealed that reported total flared and vented natural gas volumes attributable to tight gas well completions were ~6 times larger than Canadian Association of Petroleum Producers (CAPP) estimates for natural gas well-completion based on wells ca. 2000, but 62% less than an equivalent emission factor that can be derived from U.S. EPA data. Newly derived emission factors for diesel combustion during well drilling and completion are thought to be among the first such data available in the open literature, where drilling-related emissions for tight gas wells drilled in Alberta in 2011 were found to have increased by a factor of 2.8 relative to a typical well drilled in Canada in 2000 due to increased drilling lengths. From well-by-well analysis of production phase flared, vented, and fuel usage natural gas volumes reported at 3846 operating tight gas wells in 2011, operational emission factors were developed. Overall results highlight the importance of operational phase GHG emissions at upstream well sites (including on-site natural gas fuel use), and the critical levels of uncertainty in current estimates of liquid unloading emissions. [ABSTRACT FROM AUTHOR]