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Hydraulic fracturing is a controversial practice because of concerns about environmental impacts due to its widespread use in recovering unconventional petroleum and natural gas deposits. However, water-only hydraulic fracturing has been used safely and successfully for many years to increase the permeability of aquifers used for drinking and irrigation water supply. This process extends and widens existing bedrock fractures, allowing groundwater storage to increase. Researchers have studied the behavior of fractured-rock aquifers for decades, but little has been published on the hydraulic and mechanical properties of hydraulically enhanced fractures. In this study, a multi-faceted approach consisting of aquifer and tracer testing is used to estimate the transmissivity and storage coefficient of a hydraulically induced fracture and observe its behavior as a contaminant flow pathway. The results of the aquifer tests indicated a decrease in both the transmissivity and storage coefficient of the fracture of three orders of magnitude after cessation of pumping. The aquifer temporarily experienced incomplete recovery following pumping tests, likely due to slow recharge. After complete recovery occurred, subsequent tests showed that these hydraulic properties returned to their original values, indicating elastic compression of the fracture during periods of applied stress. The results of the tracer test indicated rapid, uniform, one-dimensional flow through the fracture, with average fluid velocity approaching 1 km/day in an induced steady flow field of 6 x 10-5 m3/s (1 gal/min) and a fracture volume of 0.238 m3 (63 gal). The complex heterogeneity of fractured-rock aquifers necessitates the use of multiple lines of testing in order to arrive at a detailed description of the behavior of these systems. This study demonstrates one effective method of investigating a single fracture that can uncover information about the behavior of a hydraulically enhanced aquifer that is otherwise difficult to obtain. / Master of Science

Yes / This paper focuses on the robustness of the regulatory system of British Columbia (BC) from the environmental point of view. It argues that the enforcement of existing regulations is effective due to the active monitoring of compliance by the provincial oil and gas regulator. The regulator has a key role in promoting transparency, public participation and safety and sustainability of shale gas operations. The paper argues that although certain elements in the provincial legislative framework are covered by non-binding guidelines, rather than legislation, the regulator has responded to many of the concerns raised by the public over the shale gas development in BC, including impacts on regional air quality, fresh water contamination and access to water, deforestation, biodiversity and induced seismicity. The regulator has also recognized several key issues, such as baseline water monitoring as an issue requiring further research. This paper concludes that BC has one of the most robust regulatory systems in North America for regulating hydraulic fracturing.

Yes / This paper addresses the regulation of energy resource projects on indigenous lands in the Canadian Arctic and the role of environmental impact assessment in these projects, specifically those involving hydraulic fracturing. Taking an environmental point of view, this paper argues that in the absence of specific territorial legislation applying to shale gas development in Nunavut and the onshore portion of the Inuvialuit Settlement Region in Northwest Territories the federal regulator, the National Energy Board, has a key role in promoting transparency, public participation, safety and sustainable use of natural resources. As part of its environmental protection responsibilities, the Board, inter alia, ensures that an environmental impact assessment is conducted before any proposed hydraulic fracturing activities commence on indigenous lands, which in some cases include an extensive public consultation. In 2013 the Board adopted rigorous guidelines for all onshore oil and gas projects involving hydraulic fracturing which address many of the concerns raised over shale gas development, including surface and groundwater contamination; impact on air quality; induced seismicity and reluctance of industry to disclose chemicals used in hydraulic fracturing. Although these guidelines are non-binding on the Board, their adoption means that it will be challenging for the operators to obtain an authorisation from the Board should they fail to conduct an environmental impact assessment. This paper argues that these guidelines exceed the best practices widely adopted by the Canadian shale gas industry. It concludes that because the guidelines address a number of concerns raised by the public they could potentially be used as the minimum standards for hydraulic fracturing operations in other regions outside Arctic Canada.

Yes / This chapter evaluates the consistency of the United Kingdom (UK) regulatory framework on shale gas with Commission Recommendation 2014/70/EU on minimum principles for the exploration and production of unconventional oil and gas. In the absence of European-wide legislation, European Union (EU) Member States have the right to determine the conditions for exploiting their unconventional energy sources. However, due to the environmental and human health risks associated with hydraulic fracturing, the EU has expressed its interest in ensuring adequate protection of the environment and to creating clear and transparent common standards for the benefit of operators, investors and the public while promoting the interests of those Member States which are currently exploring unconventional energy. It can be argued that the UK regime has been designed to address the environmental risks arising from hydraulic fracturing operations and as such it sets a high environmental threshold for operations. In fact, the UK legislation appears to be more comprehensive than in many other jurisdictions commercially exploiting shale gas, and therefore it has a potential to inform the content of any future harmonising measures on the exploration and extraction of such resources at the EU level.

The Barnett shale basin, the largest onshore gas field in the state of Texas, mainly produces natural gas. The basin’s oil and gas productions have dramatically increased over the past two decades with the enhancement via shale fracturing (fracking) technology. However, recent studies suggest that air emissions from shale fracking have significantly contributed to the growing air pollution problem in North Texas. In this study, air emissions from the Barnett shale basin during the production phase of the oil and gas activities (once the product is collected from the wells) are quantified. Oil and gas production data were acquired from the Texas Railroad Commission for the baseline years of 2010 through 2013. Methodology from prior studies on shale basins approved by the Texas Commission on Environmental Quality was employed in this study and the emission inventories from the production phase sources were quantified. Accordingly, the counties with the most gas operations in the basin, Tarrant, Johnson, Denton and Wise, were found to be the highest emitters of air pollutants. Tarrant County was responsible for the highest emitted NOx (42,566 tons) and CO (17,698 tons) in the basin, while Montague County released the maximum VOC emissions (87,601 tons) during the study period. Amongst the concerned emitted pollutants, VOC was the largest emitted pollutant during the study period (417,804 tons), followed by NOx (126,691 tons) and CO (47,884 tons). Significant Sources of air emissions include: storage tanks, wellhead compressor engines, and pneumatic devices. Storage tanks and pneumatic devices contributed to about 62% and 28% of the total VOC emissions, respectively. Whereas, wellhead compressor engines are primarily responsible for about 97% of the total NOx emissions. Finally, in Tarrant, Wise and Denton counties, the emissions increased during the study period due to increase in the oil and gas production, while Johnson County’s emission contribution declined throughout the study period.