Fracking in Canada

Technologies

The first commercial application of hydraulic fracturing was by Halliburton Oil Well Cementing Company (Howco) in 1949 in Stephens County, Oklahoma and in Archer County, Texas, using a blend of crude oil and a proppant of screened river sand into existing wells with no horizontal drilling. In the 1950s about 750 US gal (2,800 L; 620 imp gal) of fluid and 400 lb (180 kg) were used. By 2010 treatments averaged "approximately 60,000 US gal (230,000 L; 50,000 imp gal) of fluid and 100,000 lb (45,000 kg) of propping agent, with the largest treatments exceeding 1,000,000 US gal (3,800,000 L; 830,000 imp gal) of fluid and 5,000,000 lb (2,300,000 kg) of proppant."

In 2011 the Wall Street Journal summarized the history of hydraulic fracturing,

"Only a decade ago Texas oil engineers hit upon the idea of combining two established technologies to release natural gas trapped in shale formations. Horizontal drilling—in which wells turn sideways after a certain depth—opens up big new production areas. Producers then use a 60-year-old technique called hydraulic fracturing—in which water, sand and chemicals are injected into the well at high pressure—to loosen the shale and release gas (and increasingly, oil)."

— Wall Street Journal 2011

Horizontal oil or gas wells were unusual until the 1980s. Then in the late 1980s, operators along the Texas Gulf Coast began completing thousands of oil wells by drilling horizontally in the Austin Chalk, and giving 'massive' hydraulic fracturing treatments to the wellbores. Horizontal wells proved much more effective than vertical wells in producing oil from the tight chalk. In the late 1990s in Texas, combining horizontal drilling and multi-stage hydraulic fracturing techniques made large-scale commercial shale gas production possible. Since then, shale gas wells have become longer and the number of stages per well has increased. As shale gas companies target deeper, hotter, more unstable reservoirs, drilling technologies have been developed to tackle challenges in various environments.

In parallel with the advancement in drilling technologies, injection technologies have also seen changes.

Cost and lifespan of hydraulic fracturing

Oil producers spend US$12 million upfront to drill a well but it is so efficient and produces so well during its short, 18-month lifespan, that oil producers using this technology can still make a profit even with oil at $50 a barrel.

Lifespan of hydraulic fracturing:

The lifecycle of shale gas development can vary from a few years to decades and occurs in six major stages, as described by Natural Resources Canada (NRC), assuming all approvals from the various regulatory authorities have been obtained:

• Stage One: Exploration, which involves applying for the appropriate licenses and permits, leasing the mineral rights, Indigenous consultations, community consultations and geophysical studies, including geological assessments and seismic surveys;
• Stage Two: Site preparation and well construction, which includes exploratory drilling to determine the physical and chemical characteristics of the rock and to assess the quality and quantity of the resource;
• Stage Three: Drilling, which includes horizontal drilling;
• Stage Four: Stimulation, which is the use of hydraulic fracturing to enable the hydrocarbons to flow to the wellbore;
• Stage Five: Well operation and production, which can operate for 10 to 30 years; and,
• Stage Six: End of production and reclamation, which requires the company to properly seal the well, clean and inspect the site. Reclamation occurs over several years as the company remediates any contamination, restores soil profiles, replants native vegetation and any other reclamation work required by local regulations.

Alberta

Because of its vast oil and gas resources, Alberta is the busiest province in terms of hydraulic fracturing. The first well to be fractured in Canada was the discovery well of the giant Pembina oil field in 1953 and since then over 170,000 wells have been fractured. The Pembina field is a "sweet spot" in the much larger Cardium Formation, and the formation is still growing in importance as multistage horizontal fracturing is increasingly used.

The Alberta Geological Survey evaluated the potential of new fracturing techniques to produce oil and gas from shale formations in the province, and found at least five prospects which show immediate promise: the Duvernay Formation, the Muskwa Formation, the Montney Formation, the Nordegg Member, and the basal Banff and Exshaw Formations. These formations may contain up to 1.3 quadrillion cubic feet (37,000 km³) of gas-in-place.

Between 2012 and 2015, 243 horizontal multistage fractured wells were drilled in the Duvernay Formation producing 36.9 million barrels (5.87 million cubic metres) of oil equivalent, distributed in 1.6 million bbl (250 thousand m³) of oil, 11.7 million bbl (1.86 million m³) of natural-gas condensate, and 23.6 million bbl (3.75 million m³) of natural gas. 201 of these wells were drilled in the Kaybob assessment area, whereas 36 wells, were drilled in the Edson-Willesden Green area and 6 wells in the Innisfail area, with horizontal lengths between 1000 and 2800 meters and well spacings between 150 and 450 meters. The development of condensate-rich areas in the Duvernay formation remain steady as the natural-gas condensate is a key product to dilute the bitumen produced from the closely located oil sands deposits in Athabasca, Peace River, and Cold Lake, and is traded with the same reference price as WTI oil.

Even as the price of oil declined dramatically in 2014, hydraulic fracturing in so-called "sweet spots" such as the Cardium and Duvernay in Alberta, remained financially viable.

British Columbia

The most shale gas activity in Canada has taken place in the province of British Columbia. In 2015, 80% of the natural gas production in the province was produced from unconventional sources, where the portion of the Montney Formation located in British Columbia (BC) contributed 3.4 billion cubic feet (96 million cubic metres) per day, corresponding to 64.4% of the province's total gas production. This formation contains 56% of the province's recoverable raw gas that corresponds to an estimate of 29.8 trillion cubic feet (840 billion cubic metres), and the remaining recoverable gas is distributed in other unconventional gas plays as the Liard Basin, Horn River Basin, and Cordova Basin, all of them located in the northeast portion of the province.

Talisman Energy, which was acquired by the Spanish company Repsol in 2015, is one operator company that "has extensive operations in the Montney shale gas area." In late July 2011 the Government of British Columbia gave Talisman Energy, whose head office is in Calgary, a twenty-year long-term water licence to draw water from the BC Hydro-owned Williston Lake reservoir.

In 2013, the Fort Nelson First Nation, a remote community in northeastern B.C. with 800 community members, expressed frustration with royalties associated with gas produced through hydraulic fracturing in their territory. Three of British Columbia's four shale-gas reserves – the Horn River, Liard and Cordova Basins are on their lands. "Those basins hold the key to BC's LNG ambitions."

Saskatchewan

The Bakken shale oil and gas boom underway since 2009, driven by hydraulic fracturing technologies, has contributed to record growth, high employment rates and increase in population, in the province of Saskatchewan. Hydraulic fracturing has benefited small towns like Kindersley which saw its population increase to over 5,000 with the boom. Kindersley sells its treated municipal wastewater to oilfield service companies to use in hydraulic fracturing. As the price of oil dropped dramatically in late 2014 partially in response to the shale oil boom, towns like Kindersley became vulnerable.

Quebec

The Utica Shale, a stratigraphical unit of Middle Ordovician age underlies much of the northeastern United States and in the subsurface in the provinces of Quebec and Ontario.

Drilling and producing from the Utica Shale began in 2006 in Quebec, focusing on an area south of the St. Lawrence River between Montreal and Quebec City. Interest has grown in the region since Denver-based Forest Oil Corp. announced a significant discovery there after testing two vertical wells. Forest Oil said its Quebec assets has similar rock properties to the Barnett shale in Texas.

Forest Oil, which has several junior partners in the region, has drilled both vertical and horizontal wells. Calgary-based Talisman Energy has drilled five vertical Utica wells, and began drilling two horizontal Utica wells in late 2009 with its partner Questerre Energy, which holds under lease more than 1 million gross acres of land in the region. Other companies in the play are Quebec-based Gastem and Calgary-based Canbriam Energy.

The Utica Shale in Quebec potentially holds 4 trillion cubic feet (110 km³) at production rates of 1 million cubic feet (28,000 m³) per day. From 2006 through 2009 24 wells, both vertical and horizontal, were drilled to test the Utica. Positive gas flow test results were reported, although none of the wells were producing at the end of 2009. Gastem, one of the Utica shale producers, took its Utica Shale expertise to drill across the border in New York state.

In June 2011, the Quebec firm Pétrolia claimed to have discovered about 30 billion barrels (4.8 km³) of oil on Anticosti Island, which is the first time that significant reserves were found in the province.

Debates on the merits of hydraulic fracturing have been on-going in Quebec since at least 2008. In 2012 the Parti Québécois government imposed a five-year moratorium on hydraulic fracturing in the region between Montreal and Quebec City, called the St. Lawrence Lowlands, with a population of about 2 million people.

In February 2014, prior to announcing her provincial election campaign, former Premier of Quebec and former leader of the Parti Québécois (PQ), Pauline Marois, announced that the provincial government would help finance two exploratory shale gas operations as a prelude to hydraulic fracturing on the island, with the province pledging $115-million to finance drilling for two separate joint ventures in exchange for rights to 50% of the licences and 60% of any commercial profit. It was the first oil and gas deal of any size for the province. With the change in government that occurred in April 2014, the Liberals of Philippe Couillard could change that decision.

Petrolia Inc., Corridor Resources and Maurel & Prom formed one joint-venture, while Junex Inc. was still seeking a private partner.

In November 2014 a report published by Quebec's advisory office of environmental hearings, the Bureau d’audiences publiques sur l’environnement (BAPE), found "shale gas development in the Montreal-to-Quebec City region wouldn’t be worthwhile." BAPE warned of a "magnitude of potential impacts associated with shale gas industry in an area as populous and sensitive as the St. Lawrence Lowlands." The Quebec Oil and Gas Association challenged the accuracy of BAPE's report. On 16 December 2014 Quebec's Premier Philippe Couillard responded to the BAPE report stating there will be no hydraulic fracturing due to a lack of economic or financial interest and a lack of social acceptability.

New Brunswick

New Brunswick's increased use of natural gas was facilitated by a single event: the arrival of natural gas from Nova Scotia's Sable Offshore Energy Project via the Maritimes and Northeast Pipeline (MNP) in January 2000.

Exploration and Production

The following timeline illustrates the development of New Brunswick's natural gas production industry, post-1999.

2003: Natural gas is discovered and begins at McCully. Producing reservoir is Hiram Brook formation sandstone.

2007: A 45-kilometre pipeline is constructed to connect the McCully gas field with the Maritimes and Northeast mainline and a gas processing plant is constructed in McCully area.

2007: Two natural gas gathering pipelines are constructed (450 metres and 2,000 metres in length) to tie in two existing well pads (F-28 and L-38) to the existing gathering system.

2007: Expansion of the McCully natural gas production including the construction of six new well pads and gathering pipelines.

2008: Further expansion of the McCully natural gas system including construction of a 3.4 kilometre pipeline to tie in well pad I-39.

2009: First hydraulic fracturing of a horizontally drilled well in New Brunswick in the McCully area.

2009: Start of exploratory drilling and hydraulic fracturing in the Elgin area, south of Petitcodiac.

2009–2010: The first shale-targeted wells are drilled in New Brunswick – four wells in the Elgin area, south of Petitcodiac. None are producing.

2014: The last hydraulic fracturing carried out in New Brunswick to date. Corridor Resources conducted hydraulic fracturing using liquid propane at five wells in the McCully and Elgin areas.

Hydraulic fracturing fluid

Under the Canada Oil and Gas Operations Act, the National Energy Board (NEB) requests operators to submit the composition of the hydraulic fracturing fluids used in their operation that will be published online for public disclosure on the FracFocus.ca website.

Most of hydraulic fracturing operations in Canada are done using water. Canada is also one of the most successful countries in the world to use carbon dioxide as fracturing fluid, with 1,200 successful operations by the end of 1990 Liquefied petroleum gas is also used as a fracturing fluid in provinces where usage of water is prohibited such as New Brunswick.

Possible related earthquakes

The sharp seismicity increase observed in recent years in the Western Canada Sedimentary Basin is inferred to be triggered by hydraulic fracturing operations. Most of the seismic events reported in this period are closely located to hydraulic fracturing wells completed in western Alberta and northeast British Columbia. In response to this increased seismicity, in 2015 the Alberta Energy Regulator released the Subsurface Order No. 2 that requires mandatory implementation of a Traffic-Light Protocol (TLP) based on the local magnitude (M_L) of seismic events detected during the monitored operations. According to this TLP, the hydraulic fracturing operations can continue as planned when the M_Lof the detected seismic events are below 2.0 (green light), must be modified and reported to the regulator when a seismic event of M_L between 2.0 and 4.0 is detected (amber light), and must be immediately ceased when a seismic event of M_L > 4.0 is detected within 5 km of a hydraulic fracturing well (red light). The BC Oil and Gas Commission implemented a similar TLP where the seismicity and surface ground motions must be adequately monitored during hydraulic fracturing operations, and must be suspended if a M_L > 4 is detected within 3 km from the well. M_L > 4 has been chosen as a red-light threshold by both jurisdictions in western Canada (Alberta and British Columbia) as a seismic event with magnitude below 4 corresponds to a minor earthquake that may be lightly felt, but with no expected property damage. The following table lists some amber or red-light TLP seismic events reported in the Horn River Basin in northeast BC, and in Fox Creek, Alberta. The increased seismic activity in these two areas have been closely attributed to hydraulic fracturing operations.

Provincial regulations associated with hydraulic fracturing

In Canada, hydraulic fracturing operations are governed by a number of provincial acts, regulations, guidelines, and directives. In this section, existing regulatory instruments are listed by province. Note: lists of provincial governing regulations are not exhaustive and new directives are drafted and implemented by the provincial government as necessary.