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Exploration and Production of Shale and Tight Resources

A product of the Energy and Mines Ministers’ Conference

Technologies such as horizontal drilling and multi-stage hydraulic fracturing have enabled hydrocarbon production from shale and tight reservoirs that were previously uneconomic in North America.

Canadian Production

Shale and tight resource production is growing, helping to offset declines in conventional production. In 2014, shale gas accounted for approximately 4 percent of total Canadian natural gas production while tight gas accounted for 47 percent. By 2035, the Canada Energy Regulator (CER, formerly the National Energy Board) expects tight and shale gas production together will represent 80 percent of Canada’s natural gas production.

In 2014, tight oil accounted for more than 10 percent of total Canadian crude oil production. By 2030, the CER projects moderate growth in light oil production from tight oil plays in the Western Canadian Sedimentary Basin (WCSB) as conventional heavy oil production declines. However, the development of tight oil reservoirs is still in early stages in Canada. The extent to which these resources can be produced from is largely undetermined.

Canadian Shale and Tight Gas Production

Figure 1 - Canadian Shale and Tight Gas Production
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Figure 1: Graph showing Canadian shale and tight gas production between 2000 and 2013. Production grew from three billion cubic feet per day in 2000 to seven billion cubic feet per day in 2013.

Canadian Tight Oil Production

Figure 2 - Canadian Tight Oil Production
Text Version - Figure 2

Figure 2: Graph showing Canadian tight oil production between 2005 and 2013. Production grew from near zero in 2005 to 350,000 barrels per day by 2013.

Source: National Energy Board (2015)

In Canada, shale and tight production activities are located primarily in Western Canada, and exploration has been pursued in only a handful of provinces.


Over 500,000 oil and natural gas wells have been drilled in Canada since the first commercial oil well in North America was dug in Oil Springs, Ontario, in 1858, more than thirty years after the first commercial natural gas well was dug in Fredonia, New York, in 1821.

At Norman Wells in the Northwest Territories, oil was discovered in 1920 which flowed from naturally-fractured shale deposits connected to the underlying conventional oil pool.

In Alberta and Saskatchewan, natural gas has been produced from the Second White Speckled Shale for decades. In these early cases, there was typically sufficient natural fracturing to allow economic recovery using shallow, vertical wells.

The first Canadian tight gas production that resulted from horizontal drilling and multi-stage hydraulic fracturing came from the Montney Formation in British Columbia in 2005. The first modern Canadian shale gas production came from the Horn River Basin in 2006, also found in northeast British Columbia.

Interest in other Canadian shale and tight plays started around the same period in British Columbia, Alberta, New Brunswick, Nova Scotia and Quebec. From 2005 to 2008, higher oil prices gave companies the incentive to apply technologies used to produce shale and tight gas to tight oil formations in Western Canada.

Development Process

The time required to develop shale and tight resources ranges from a few years to more than a decade.

Step 1: Exploration

Utica Shale

Figure 3 - Utica Shale

Source: National Energy Board (2009)

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Figure 3: Photo of Utica Shale near Montmorency Falls, Quebec. A hammer is shown for scale.

Before production, a producer must first assess the potential of a reservoir and begin the applicable regulatory process.

To prepare a site for exploratory drilling, a producer will take the following steps:

  • Study the reservoir’s geology (e.g. geological assessment, seismic surveys)
  • Lease mineral rights
  • Apply for licences and permits
  • Consult with landowners, other stakeholders and potentially affected First Nations

How does industry assess the potential of shale or tight reservoirs?

  • Geological Assessment: Where a shale or tight formation is prospective for oil or natural gas that has formed and been trapped in place, the initial assessment would include a study of the formation's organic matter and thermal history to determine what kind of hydrocarbons (e.g., oil or gas) have been formed.
    • The rocks would also be tested to measure the portion of hydrocarbons that are free in the pore spaces and the portion that are attached to the walls of any pore spaces.
    • For any shale or tight formation, other assessments would include the thickness and geographic distribution of the formation, the mineral content of the rock, and the rock's physical properties (e.g., permeability, porosity, and brittleness).
  • Seismic Survey: Seismic reflection profiles are used to characterize the geometric and volumetric parameters of sites, such as the depth and internal variations within a deposit. During a ground seismic survey, the reflection along rock planes of acoustic waves generated by vibrator trucks or small buried dynamite charges is recorded.

Step 2: Site preparation and well construction

Exploratory drilling is essential to determine a prospective rock formation’s physical and chemical characteristics and to assess the quality and quantity of the resource.

To prepare a site, a producer will take the following steps:

  • Build the access road and construct the well pad
  • Drill the initial hole (wellbore) to determine if the well looks promising

The hole is drilled in two or more stages, with at least a surface hole over shallow zones, sometimes an intermediate hole that is drilled from the bottom of the surface hole to somewhere above the top of the targeted formation, and a production hole that is drilled into the targeted formation.

As each stage is finished, a steel pipe is run along the length of the wellbore and cemented into place. This way, the shallow zone and the groundwater behind it is protected by at least two pairs of steel and cement barriers. As well, the well pressure is contained and the wellbore is stabilized. The rock section not being targeted can therefore be isolated from well operations while the targeted formation is being hydraulically fractured and later produced.

Step 3: Drilling

Horizontal Versus Vertical Wells

Figure 4 - Horizontal Versus Vertical Wells

Source: JuneWarren-Nickle's Energy Group (2008)

Text Version - Figure 4

Figure 4: Schematic of a horizontal well and a vertical well using multi-stage hydraulic fracturing.

Vertical wells in shale and tight formations have difficulty producing at economic volumes because wells intersect only a limited amount of prospective rock. This limits how much oil and natural gas can be produced.

Horizontal drilling is a technique that involves initially drilling a vertical well from the surface and then progressively directing it horizontally through the target zone.

The horizontal leg of horizontal wells is drilled along one to three kilometres of prospective rock. Thus, while the costs of drilling a horizontal well are significantly higher than a vertical well, the increased production from the larger body of rock is more than enough to offset those extra costs. This makes the horizontal well economically successful where a vertical well might be an uneconomic.

Step 4: Stimulation

Microseismic Imaging

Figure 5 - Microseismic Imaging
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Figure 5: Microseismic imaging of a horizontal well during hydraulic fracturing.

Even with horizontal drilling, most reservoir rocks containing shale and tight resources must be stimulated to enable the hydrocarbons to flow to the wellbore.

Hydraulic fracturing is a common stimulation technique, often referred to as “fracking” in industry jargon. The method involves the injection of pressurized water into the rock unit, usually mixed with a small volume of sand and chemical additives.

How does hydraulic fracturing work?

During hydraulic fracturing, water is injected into the rock unit under very high pressures until the rock cracks and fractures.

Sand (proppant) is added to the water and injected into the formation to prevent the artificially created fractures from closing. The fractures thus remain open and allow the oil or natural gas to flow to the well-bore.

Chemical additives (generally representing less than 1 percent of the fluid) are used for several purposes, mostly to increase viscosity, optimize post-fracturing water recovery or protect the production pipe casing from corrosion. The fracturing fluid used is specific to each operator and differs from one formation to another.

Industry generally targets formations located more than one kilometre deep, and hydraulic fracturing is only permitted below the deepest freshwater aquifers.

Step 5: Well operation and production

After hydrocarbons have been unlocked from the shale or tight reservoir and are able to flow to the wellbore, they are collected at the well head using methods similar to those for conventional oil and gas.

Once a well is in production, it commonly produces for 10 to 30 years. Producing wells are monitored and inspected for leaks.

Step 6: End of production and reclamation

When a well is no longer productive, it is abandoned and the land is reclaimed.

Before abandonment, the well must be properly sealed by the company. First the company cleans and inspects the inside of the wellbore, making any needed repairs.

Second porous formations and groundwater zones are isolated from each other and the wellbore with cement. The well is then filled with non-corrosive fluid. Finally, the company cuts the well casing below surface level and plugs the well by installing a vented cap.

Reclamation occurs over several years. To restore the land, the company must clean or remediate any contamination detected, remove foreign materials, restore soil profiles, replant native vegetation and landscape according to regulatory requirements.


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