Feature Story: The Shale Gas Revolution 

Shale Gas Revolution 

The advent of commercially viable shale gas extraction has altered the global balance of power in regards to energy production — creating both big opportunities and new challenges for Canadian producers

Commercially viable shale gas extraction has changed the world for producers, consumers and governments. By unlocking previously inaccessible supplies of natural gas out of shale rock formations using the process of hydraulic fracturing, producers now have access to unprecedented natural gas resources.

Globally, it’s estimated that the technological leap represented by hydraulic fracturing has effectively increased the world’s gas reserves by 32 per cent. In North America, conventional resources of natural gas had been headed towards an early 21st century decline as wells matured and reserves were gradually depleted. Now, both Canada and the United States sit upon massive, global-scale reserves. Canada has an estimated 100-year supply, leading to the possibility of ramped-up exports to an energy-hungry world. The United States, meanwhile, has used hydraulic fracturing to become the number one natural gas producer in the world.

Recoverable Shale Gas Resources

For consumers and governments, the benefits of a stable and affordable long-term energy supply—particularly one billed as the world’s cleanest-burning hydrocarbon fuel, with significantly less GHG emissions and air contaminants than coal or oil—are obvious. For producers, the shale gas revolution has certainly sparked some great opportunities, but it has also created key challenges to overcome.

Hydraulic fracturing—the use of pressurized liquid to fracture rock formations deep under the earth—has been used to stimulate production in oil and gas wells since the 1940s. Horizontal drilling, the technique of drilling vertically to a certain depth and then turning the pipe to drill horizontally so as to follow the plane of a rock formation layer (in so doing, exposing substantially more of the wellbore to the producing formation) is also not an overnight technology, having been in commercial use since the 1980s.

Western Canada Resource Plays

Nonetheless, when in 1997, Mitchell Energy & Development Corp. (since acquired by Devon Energy) perfected the combination of using horizontal drilling and hydraulic fracturing within the Barnett shale play in Texas so as to extract natural gas profitably, something radical happened. The fracking technique they developed spread like wildfire across the basin and by 2005, gas production was surging across the States.

“The scale of the transformation is unprecedented,” says Mark Pinney, CAPP Manager of Natural Gas Markets. “The industry surprised itself with how effective this technology would be and how efficiently it would perfect it."

Once uneconomical to tackle, a 20 per cent recoverability rate is now typical for shale-gas formations—enough to make extraction profitable under most circumstances. 

The scale of North American shale gas reserves is world class. The U.S. Potential Gas Committee increased its annual reserve estimate of U.S. natural gas resources in 2013 to 2,384 trillion cubic feet (Tcf), largely due to the inclusion of an estimated 1,073 Tcf of potential shale gas. Meanwhile, Canada’s natural gas resources are estimated to be between 700 to 1,300 Tcf. To put this in perspective, Canadians consumed a total of three Tcf of natural gas in all of 2013.

“Given this tremendous resource potential, Canada has plentiful supplies to meet current domestic consumption, while also building towards new markets for natural gas, both domestically and overseas,” notes Brad Herald, Vice President Western Canada Operations.

The shale gas revolution is not without challenges. Drilling is expensive, capital can be skittish, and international competition for markets is heating up. Ironically, while hydraulic fracturing has opened up the potential of vast global-scale natural gas reserves, in recent years Canadian natural gas production has been declining. Between 2007 and 2013, production fell from just over 16.5 billion cubic feet per day (bdf/d) to about 14 Bcf/d.

“The reason for this is quite simple,” says Pinney, “Currently, almost all of our exports go to the United States. With the dramatic increase in shale gas production south of the border, competition has increased, and demand for Canadian natural gas has fallen.”

The traditional export markets for Canadian natural gas include American consumers in the West, Mid-West and Eastern U.S. Of the 13.7 Bcf/d produced in Western Canada in 2012, 5.3 Bcf/d (or 39 per cent) were consumed domestically, while 8.4 Bcf/d (61 per cent) was exported into the United States. However increased production from shale plays in the southern and eastern United States means that supply and competition, particularly into the Mid-West and Eastern markets, will increase.  “Over the long run,” notes Pinney, “especially as more transportation infrastructure is built to carry U.S. shale gas into these markets, we’ll see a gradual but inevitable decline in demand for Canadian natural gas.”

Pinney recently helped create a Natural Gas Forecast that looked into a number of scenarios for Canadian natural gas producers. In what Pinney describes as a “market constrained” case where producers are unable to find new markets for product, Canadian production of natural gas is predicted to fall below 12 Bcf/d by 2020.

At the same time as demand is falling, so has the export price for natural gas. From a July 2008 annual average of US $8.42 per thousand cubic feet (Mcf), the U.S. natural gas export price slid to an annual average of $2.78 in 2012. The drop was driven in part by oversupply, but a warm winter and post-recession economic malaise also slackened North American demand. As the market price of gas dropped, production in the U.S. has remained high, further weakening prices. A harsh winter in 2013/14 and improving economic conditions have permitted a recovery back up to an average of $6.57 per Mcf over the first half of 2014, but much of this increase is expected to be temporary. As of July 2014, the Henry Hub price has been hovering around just under $4 per Mcf.

The combination of falling demand and low prices has created serious challenges for producers invested in Canadian production. In many cases, this has forced producers to drill strategically. Some, for example, have shifted wells from dry to wet gas plays, taking advantage of strong natural gas liquid (NGL) prices. 

Encana, for example, has sharpened its focus from 15 to five plays—two in Canada and three in the U.S.—upon which it now focuses 75 per cent of the company’s capital expenditures. Wet gas work in the Montney and Duvernay has taken the place of dry gas production in the Horn River. Unfortunately, this process of shifting and retrenching also meant that Encana had to cut 20 percent of its staff in 2013.

At the same time, Encana realizes it still has a valuable resource and is optimistic about the future. Richard Dunn, Encana Vice President of Government Relations Canada says “We’ve got very strong plays,” says Dunn. “We expect prices will continue with a modest recovery. We’re retaining natural gas optionality in our portfolio.”

The price drop in North American natural gas also forced energy company Unconventional Gas Resources Canada to retrench and revise strategies. A key has been to find ways to reduce costs.

“There were still opportunities out there that we could explore for, evaluate and develop in a low-price gas environment,” says Unconventional’s CEO, Mike Gatens.

For example, the company moved into the Montney, which, as of spring breakup 2014, featured more operating wells than any gas play on the planet. “That’s turned out to be the company maker for us,” says Gatens. 

Informally partnering with Progress Energy, Talisman and Painted Pony, the company shared expenses on the higher-cost, higher-risk early evaluation phase of development. The partners went their own way once results were positive. Further cost reduction came with confidence and experience, says Gatens. Costs per well dropped approximately 50 to 60 per cent, reflecting overall long-term well-productivity increases and reduced production costs in the shale gas sector.

While adaptive strategies are key to company prosperity in the short-term, long-term growth will require a change in the status quo, particularly when it comes to export markets.

“The United States is our number one importer of natural gas, and they will continue to be a key consumer for the foreseeable future,” says Herald, “However, if the industry is to grow and take advantage of this tremendous resource potential, we need to develop new markets for Canadian natural gas.”

With consumers in Asia currently paying as high has $15 per MMbtu, and with energy demand in Asia expected to grow substantially over the next two decades, there is a clear opportunity to get higher returns by shipping product overseas in the form of liquefied natural gas, or LNG. 

Market Revolution

Though Encana is not directly engaged with LNG export projects, it is a strong supporter. “LNG is absolutely critical to the growth of the resource base in Western Canada,” Dunn says.

Gatens also supports offshore LNG, citing the appealing stability of 20-year supply agreements. However, he stresses these projects won’t come online for several years. While gas may eventually move to foreign markets, he is convinced North American economic growth will yet bring substantial opportunity. “We can grow North American production, and Canada can play a key role,” he says.

Such opportunities include powering oil sands development. The Canadian oil sands are already the largest single consumer of natural gas. 
Gas is used in various aspects of the bitumen extraction process, for example the generation of steam used in SAGD in situ wells, and as a feedstock to upgrade bitumen. According to CAPP’s most recent Crude Oil Forecast, oil sands production is expected to almost triple, from 1.9 million barrels per day (b/d) in 2013, to 4.8 million b/d in 2030. 

“This kind of growth would certainly help drive domestic consumption,” says Pinney, who notes that oil sands represents 15 per cent of current natural gas consumption in Canada.

Another area of growth is electricity generation, with natural gas expected to offset coal and nuclear energy in electricity production. “Currently, electricity production consumes about 1.5 Bcf/day of natural gas. If natural gas power generation is used to replace several aging nuclear power plants in Ontario by 2030, this amount could increase to 2.1 Bcf/day,” notes Pinney.

A small but potentially robust growth area is anticipated to be in the area of natural gas vehicles using LNG and compressed natural gas. B.C. Ferries, recently announced that it would begin using ferries powered by LNG. Translink, meanwhile, the B.C. Lower Mainland’s transit authority, has announced the purchase of 180 buses that run on compressed natural gas.

In his Natural Gas Forecast, Pinney also explores a scenario which envisions success in the development of new markets for Canadian natural gas. By modeling the inclusion of new LNG exports and growth in domestic consumption via oil sands, electricity generation and natural gas vehicles, a rosier future for producers is envisioned—with production rising to 16 Bcf/d by the mid 2020s. 

LNG Demand

Growth also relies on maintaining social licence in the face of public concerns. Although hydraulic fracturing is a mature, proven technology with thousands of wells having undergone hydraulic fracturing in Canada and the United States without incident, worries particularly regarding the technology's potential impact on drinking water continue.

To assist producers, CAPP has tailored supportive resources focusing on public communication, the environment and generating social licence through responsible practices. CAPP also utilizes outreach initiatives to manage and respond to concerns about water usage, air quality, wildlife management and hydraulic fracturing technology. 

“We are reaching out into the communities we operate in to provide information about the industry, the resource and extraction methodologies,” says former CAPP Vice President Western Canada, David Pryce.

CAPP has created a set of best practices for use by its members. Among its features are guidelines on alternatives to fresh water usage such as accessing municipal wastewater supplies. As well, in accordance with the document, CAPP producers utilize the Frac Focus database, rising above proprietary concerns and making public the chemical makeup of their fracturing fluids. “It’s important to the public to be able to see that there is industry transparency,” says Pryce. 

 Attracting capital while generating economic return favourable to government and industry will remain the shale-gas sector’s biggest challenges, says Pryce, as will the regulatory and policy environment, which has had to keep up with the evolution of industry practices. A positive development in this regard is the Alberta Energy Regulator’s potential implementation of play-based regulations to simplify approvals for new wells. As well, a move to a regulated increase in pad drilling is cost effective and minimizes land disturbance.

“At the end of the day, we’re optimistic for industry,” says Herald. “We have a world-scale resource of the cleanest burning hydrocarbon. Consumers in Canada and around the world want our energy, and we’re working hard to build the new markets needed to deliver that energy competitively and safely, and for the benefit of all Canadians.”

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