Once burned off as a byproduct of oil production, natural gas has found new life in the 21st century, and the industry has its sights set high. Thanks to technological innovations, there is more of it available than ever, a fact that is ushering in a paradigm shift in global energy supply. With uses from electricity to public transportation to fertilizer for crops, natural gas is clean burning, efficient, abundant and well-positioned to gain prominence.
Conventional gas wells are drilled vertically and access pockets of gas trapped in porous sedimentary rock. In contrast, unconventional wells are drilled horizontally and are aimed at coalbeds, shales and tight sands, which are non-porous and need to be fractured before they release their gas. While conventional resources are still the baseline for the industry (the majority of the natural gas consumed in the world is still derived from conventional wells), that is already changing.
The U.S. Energy Information Administration (EIA) estimates there are over 6,000 trillion cubic feet (TCF) of proven natural gas reserves globally. But the U.S. National Petroleum Council gauges global unconventional gas-in-place to be at 33,000 TCF – over 6,000 TCF are technically recoverable with today’s technology, although mostly unproven. These would all make use of unconventional drilling techniques – combined with hydraulic fracturing – which are now capable of efficiently extracting resources in areas that were never previously considered economical.
“George Mitchell is regarded as kind of the father of this [unconventional] technology,” says Dan Cohn, a senior research scientist at MIT and executive director of the school’s natural gas study. Cohn says Mitchell, the founder of Mitchell Energy & Development Corp., pioneered the combination of hydraulic fracturing and horizontal drilling for commercial production in the 1980s and 1990s; in 2001, he sold the company to Devon Energy for $3.5 billion.
Today, hydraulic fracturing and horizontal drilling accounts for 30 per cent of Canadian production and 40 per cent of production in the United States. With unconventional gas producers like Mitchell and XTO Energy being purchased by major corporations (Devon is one of the largest independent oil and gas producers in the U.S., and XTO was bought by Exxon for $41 billion in 2009), the term unconventional is becoming a misnomer.
In 2009, global natural gas consumption was around 107 TCF per year, according to estimates from the EIA; projections to 2020 foresee consumption increasing by 1.8 per cent per year, tapering to a 0.9 per cent increase from 2020 through to 2035. Unconventional techniques will figure most prominently in North America’s future, where the U.S. is expected to account for over 85 per cent of global production growth to 2035.
“Predictions are that by 2030, tight gas and shale gas could be 70 to 80 per cent of North America’s natural gas supply,” says Michael Binnion, president and CEO of Questerre Energy. “We’re really entering into a major paradigm shift, not just in energy markets, but for society too.”
Resistance to change
The response to unconventional drilling has been a mix of excitement and skepticism. Opponents of horizontal drilling and hydraulic fracturing have been vocal about their fear over ecological consequences, despite 30 years of commercial production experience and commitment from industry leaders to maintain best practices.
The largest controversy in North America is occurring in areas that have traditionally been importers of oil and gas and are heavily populated, such as the St. Lawrence lowlands in Quebec and the Marcellus Shale in the Appalachian Basin of the northeastern United States. In May, the Quebec government announced that exploration will be put on hold for 30 months while environmental impacts are assessed. This is a setback for Binnion, and Questerre, which has over one million prospective gross acres in the province’s shale gas plays.
“Quebec currently imports all of its natural gas from Alberta and British Columbia,” says Binnion, who points out that a significant amount of shale gas is already consumed by Quebecers. “If you really care about the environment, you should produce your energy locally because then [the province] can know, control and trust how its energy is produced,” he adds.
Regional pricing, global supply
There are 48 known shale basins in 32 different countries, and there is still considerable uncertainty about the price and quantity of gas that will be produced from them. As a result, making predictions about the shape of markets and the relationships between them has become increasingly difficult. “There are three liquid natural gas import terminals in Canada alone that were cancelled because of shale gas,” recalls Binnion.
Cohn and his colleagues at MIT found that there are three separate regional natural gas markets in the world, North America, Europe and Asia, each with unique supply and transport options. “In Asia, [the price of] natural gas, on an energy basis, has been coupled relatively closely to that of oil; in Europe, it’s kind of in between; and in the United States, there has been a significant decoupling,” he explains. This makes natural gas significantly cheaper in North America than elsewhere, for the time being.
As North America is set to become a net exporter of natural gas for the first time in history, all eyes are on Asia and, in particular, Japan to receive the North American supply. Japan’s imports alone account for 10 per cent of the global total, and all of it arrives as liquid natural gas (LNG). There are 25 import terminals operating there, with six in construction or planned. Close to half of the world’s LNG exports are used to fuel Japan’s energy sector, a statistic that is predicted to increase due to the recent nuclear crisis in that country. Binnion believes that an export infrastructure fits well with further shale gas development in North America and that it would have a levelling effect on the global prices.
Not a pipe dream anymore
Liquefying natural gas adds an extra $4 per million BTU to the cost, according to Cohn, due to the energy required to cryogenically treat and transport the gas. But over time, that figure is becoming workable, and plans to build an LNG export facility on the Pacific Coast are going ahead smoothly.
Kitimat LNG, a project based in Kitimat, British Columbia, is owned by a partnership between Apache Canada, EOG Resources Canada and Encana Corporation. Between them, they also own the Pacific Trail Pipeline Limited Partnership, which is developing the transmission system that will eventually link the partnership’s 19 TCF in resources from the Western Canadian Sedimentary Basin to the Kitimat facility.
The Kitimat LNG project will have an initial capacity of five million tonnes per year of LNG output, with the potential to double that figure. The target for the first shipment is 2015, and last July, the company announced that it had entered into an agreement to purchase an industrial site in Kitimat, where they hope to stage a work camp, lay-down and storage area as development moves ahead.