In 1956, Shell Oil Co. geologist Marion King Hubbert predicted that if the rate of oil extraction at the time continued into the future, worldwide production would peak in the year 2000. As accessible reserves were depleted, production would fall after the turn of the century until the world as good as ran dry around 2150. Oil production in the U.S. did peak in 1970, as Hubbert said it would. However, his predictions were based on the consumption of reserves accessible by the technology of the day. The industry’s anxiety over “peak oil” motivated the invention of ways to extract what was considered inaccessible.
“Peak oil was and is a right concept, but it wasn’t understood properly,” says Soheil Asgarpour, president of the Petroleum Technology Alliance Canada (PTAC). Over the past 10 years, the successful extraction of oil and gas from vast hard-to-reach reservoirs has all but ended talk of peak oil, thanks to the rise of what many in the industry call “technological oil.”
“When you look at the way that reservoirs are deposited, you have to think of it like a triangle. At the peak of that triangle, you have some really low-hanging, easy oil. As you move down, you get to larger deposits but they are much, much more challenging,” Asgarpour explains. “You’re going to reach peak oil with that low-hanging fruit.”
Innovation was needed to overcome the world’s dependence on declining conventional oil reserves.
Unconventional sources like tight shale deposits and the oil sands called for radically new extraction methods. Many of them, namely steam-assisted gravity drainage (SAGD) and hydraulic fracturing, had been around for decades. However, scientific advances made in the past 10 years have led to a proliferation of unconventional production in North America, opening reserves many times larger than what was available in Hubbert’s time. “When you look at oil and gas 30 years ago, it was about deposits, about securing land. Now with those new technologies, we know that it is no longer a resource-driven industry; we are a technology-driven industry. Technologies are more important than the deposits,” Asgarpour says.
In situ oil sands recovery was pioneered in the 1970s by Roger Butler of Imperial Oil Ltd., using cyclic steam stimulation (CSS) to coax bitumen from the ground. SAGD came along later. Cenovus Energy Inc.’s Foster Creek project, which neighbors Imperial’s Cold Lake facilities, was initiated as a pilot project in 1996, and since commercial production started in 2001, it is now one of the most productive oil sands projects in Alberta. Before that time, which also saw Suncor Energy Inc. and Canadian Natural Resources Ltd. develop SAGD operations, the in situ steam-injection bitumen extraction technique was unproven, and considered too expensive for commercial use.
Professor Robert Schulz from the University of Calgary’s Haskayne School of Business explains that climbing world oil prices combined with recent advances in thermal-assisted extraction methods is what finally made the technology commercially viable. Today it accounts for more than half of Alberta’s oil sands production, and has in most sites replaced its less efficient forebear, CSS. “The oil sands were always available but only at a certain price,” Schulz says. “So the technology that was available had to wait for the world demand and price volatility to get to the level where it was viable.” That technological evolution was necessary for the continued growth of the oil sands industry, because according to CAPP’s latest Crude Oil Forecast, only 20 per cent of Alberta’s 167 billion barrels of proven oil sands reserves exist in shallow enough deposits to be recovered by mining.
As SAGD opened the oil sands, hydraulic fracturing advanced along similar lines. CAPP’s latest forecast credits horizontal drilling and multi-stage hydraulic fracturing with reversing the North American decline in production from mature basins since 2005, and for the biggest increase in crude oil production in the U.S. since the 1950s.
Figures from the Alberta Energy Regulator (AER) confirm CAPP’s outlook, saying that within the last decade, the use of multi-stage, hydraulic fracturing of low permeability plays is responsible for increasing light and medium crude oil production in the province at a rate not seen since the early 1970s. The AER’s supply and demand outlook for 2014 to 2023 says the province’s 11,516 productive horizontal wells account for half of all crude oil production in Alberta, despite representing only a quarter of all producing oil wells.
Pressure pumping is still an industry in its infancy. Clinton Tippett of the Petroleum History Society in Calgary says fracturing techniques are constantly being refined to overcome the geological challenges in tight plays. He says one challenge presented in unconventional operations, and that operators have had to learn to deal with, is that “Different rocks break differently.” He adds that “One of the variables that you have in the equation is how much proppant – the grains of sand basically that you push into the rock to hold the fractures open – how much of that should you use, and what size it should be, what stage of the job you should do it.” Tippett says that problem has inspired the latest innovation in the unconventional oil and gas sector, and that is better seismic mapping.
Asgarpour agrees subsurface mapping is “key” to the future of technological oil, and not just in well completion. He is keen on an airborne mapping project PTAC is participating in. With it, Asgarpour says, industry can measure steam chamber growth in SAGD projects to know where steam is going.
As successful as SAGD and multi-stage fracturing has been, the search for new ways to develop unconventional oil has led to a few (as of today) disappointments. Toe-to-heel-air-injection (THAI) pioneered by Petrobank Energy and Resources Corp. (now Touchstone Exploration Inc.) is one that struggles to match SAGD’s recovery rates. It aims to mobilize bitumen through in situ combustion that would heat most of a reservoir by igniting part of it, a technique also called “fire-flooding.” So far, field tests have not recovered enough oil to make THAI commercially attractive.
Larry Thorhaug of Touchstone says the company is still trying to make its THAI technology work. After producing an unprofitable maximum of 400 barrels of oil per day at its demonstration facility in Conklin, Alberta, Touchstone moved its pilot project to Kerrobert, Saskatchewan, in 2011 where a scaled-down field test is capitalizing on Saskatchewan’s simpler regulatory process. Touchstone has said it needs THAI to produce around 1,000 bpd for the company to break even, but as of the end of 2013, the site only produced 152 bpd.
Perhaps a more promising development can be found through in situ heating without steam or solvents. Athabasca Oil Corp. refers to its convection heating process as thermal-assisted gravity drainage, or TAGD. Unlike other thermal recoveries, TAGD uses no water. Rather, a network of coiled heating cables is sent downhole where an electric current heats the entire reservoir. Matthew Taylor, vice-president of capital markets and communications for Athabasca, likens it to an in-floor heating system or a stovetop. Aside from that, TAGD is a typical gravity-assisted drainage production method.
TAGD also heats the resource to roughly 150 C, whereas SAGD typically injects steam at twice that temperature, making Athabasca’s technique a theoretically cheaper operation. The absence of water is also expected to drive down Athabasca’s costs. “The initial capital investment is significantly lower than, say, a comparable SAGD project because you’re not investing in all the steam generation facilities,” Taylor says.
Athabasca Oil’s TAGD process is in the fourth phase of field tests. If it continues to prove successful, Taylor says the company has its eye on using TAGD to unlock Alberta’s carbonate reserves. The technology could potentially open hundreds of billion of barrels of new reserves. “At this point we believe it is better suited to the carbonates. Given the mobility of the oil and the reservoir characteristics, SAGD is a proven technology in the clastic sands,” says Taylor. TAGD “is not going to replace SAGD for oil sands recovery.”
Calgary’s privately held E-T Energy Ltd. is using a similar process but with a water flood, called electro-thermal dynamic stripping process, or ET-DSP. A key dilemma with using heat to mobilize heavy crude, as most gravity-assisted technologies do, is you need a fuel source to create that heat, and that comes with a cost. Unfortunately, no better method has been marketed than using hydrocarbons, either to create steam for SAGD and THAI or an electric current in TAGD or ET-DSP.
Schulz recalls the buzz five years ago about building nuclear plants to power unconventional oil extraction, which is another idea that fell by the wayside. “That never really materialized and that was no surprise. The cost of a nuclear power plant is unpredictable in North America. The length of time that it would take to do a nuclear power plant would be probably five years for talks, five years for hearings, five years to build it, three years to get it optimized. That’s 18 years out and that’s too long for almost anybody,” he says.
As long as industry searches for new ways to reach deeper into the world’s oil deposits, there will be successes and failures. Asgarpour is one that is confident the Canadian energy industry will find a way to prove up new reserves, and move further down the so-called reserve triangle, no matter the challenge. He points out that every time the world approaches the new definition of peak oil, industry presses ahead and finds a technological solution. “You are going to end up always overcoming that, so you never really reach a peak – or at least within the next few hundred years you are not going to reach that peak oil,” he says.
By Suzy Thompson
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