THE RACE TO REACH DEEP OIL
With global energy prices soaring, Big Oil is spending billions to exploit deposits once thought to be miles beyond our grasp
It is among the least-known feats of Cold War bravura, and if the Soviets had known what it would one day do for Big Oil in America, they probably would never have tried it. It was 1965, and a team of geologists, engineers and roughnecks had set out to drill the deepest hole on the surface of the planet. If all went well, the Kola borehole would descend through 15 km of rock in the Arctic hinterland northwest of Murmansk, eventually brushing up against the half-molten ooze
known as mantle, and yielding no end of invaluable secrets about the earth’s internal physics in the process.
But as with so many ideas that seem simple in principle, complications ensued. The planning dragged on, and when crews finally broke earth in 1970, they were plagued by folding and breaking pipe, as the drill string succumbed again and again to crushing pressure and temperatures topping 100° C. It took 13 years of drilling to reach the 12-km
mark, by which time the hole kept plugging up with hot, shifting rock which behaved more like melting rubber than hard mineral. Crew leaders grew frustrated. Folks at the Kremlin began asking exacdy what the motherland stood to gain from boring a 49,000-foot hole in the ground. In 1989, with the Soviet bloc on the brink of collapse and the team still far from its 15-km target, progress came to a halt: the rig had reached a world-record depth of 12,262 m—2,679 deeper than a gas well in Oklahoma completed 16 years before. But beyond bragging rights, the whole project seemed pointless.
Or was it merely ahead of its time? By the late 1990s, representatives of the world’s biggest oil companies were paying quiet visits to the site, studying core samples, combing the data on temperature, downhole pressure and drilling mud viscosity. What they learned they won’t say, but it’s clear they turned it to quick advantage. In October 2006, after just three months of active drilling, Chevron announced that it had produced oil from an offshore test well extending seven kilometres below the floor of the Gulf of Mexico, a shaft of Kola-like proportions. As much as 15 billion barrels of prime light crude lay at these astonishing depths, the company proclaimed, an amount sufficient to boost U.S. reserves by 50 per cent. The rush has been on ever
since. Companies scurried to secure the few rigs in the world capable of boring through kilometres of water and rock. BP, Shell and Petrobras, Brazil’s state oil company, each have projects under way. In March, two federal sales of offshore leases in the Gulf attracted a record US$3.7 billion in high bids, even though no one can say how much oil is truly recoverable, or what it will cost to get it.
Now, with oil prices hovering around $120 a barrel, that hole outside Murmansk is looking less like folly than inspired foresight. In a widely quoted report last month, CIBC World Markets warned that oil could reach $200 per barrel by 2012, renewing fears of a modern energy crisis. The stakes, say some, are nothing less than global economic stability, as competition for remaining reserves grows and efforts to find a substitute for petroleum fall woefully short. Under the circumstances, so-called “deep oil” represents a desperately needed interim solution: last fall, the investment house Friedman Billings Ramsey & Co. issued a report saying the industry could recover as much as 75 billion barrels from deep-oil projects in the Gulf—five times the amount originally thought—with untold amounts in other deep reservoirs elsewhere on the planet. Analysts say getting it will require patience, perseverance and a calibre of engineering comparable to that of NASA missions. But if the price we are already paying at the pumps is any gauge, we are just thirsty enough to pay for it.
“Let me know when we reach peak technology,” Paul Siegele, Chevron’s vice-president of strategic planning, is fond of telling energy doomsayers. “Then we can talk about peak oil.” His supreme confidence will no doubt be put to the test in the next few years. The world is blowing through oil at a rate of 30 billion barrels per year, tapping it for everything from fuel for the morning commute to plastics in our cellphones. Economic growth in Asia suggests that consumption and prices will keep rising, especially since North America’s annual consumption of 8.4 billion barrels shows few signs of easing. “Even if the world price of oil backed off to a level that makes sense based on the fundamentals, it would probably settle around $80,” says Frank Atkins, a University of Calgary economist who has studied the global oil market. “That’s still very high.”
It’s still not entirely clear where all that crude is going to come from in the future. Fully three-quarters of world oil and gas resources now sit out of the reach of Western companies, under the control of state oil firms or hostile governments, and much of what’s left will require engineering gymnastics to exploit. The Bakken shale forma-
tion that reaches from North Dakota into southern Saskatchewan, for instance, holds as much as five billion barrels of recoverable oil. But accessing it has demanded a complex method of horizontal drilling and rock fracturing that is only now starting to look viable. Similarly, vast reserves of methane hydrates, an icebound form of natural gas found in the Arctic among other locales, could heat
North American homes indefinitely. Yet technology to recover it does not yet exist, and reaching it will cost billions.
No surprise, then, that a handful of the world’s biggest oil firms are looking to go deep, much deeper than previously thought possible. More than a decade before Chevron’s announcement, it and numerous other oil giants began sizing up what appeared to
Deep oil: really, really deep oil
The oil industry has known for decades that there are vast reserves of crude trapped deep in the earth’s crust. Only the development of new computerized imaging techniques and advances in drilling technology have brought those reserves within reach.
Seismic survey ship sends shock waves through the geologic layers beneath the ocean floor. Sensors behind the ship pick up the reflected signals and produce a 3-D image of the rock formations.
A salt dome in the 23.8million-year-old oligocène geologic layer is identified by the survey
With this information, drill crews are able to “see through” salt layer and target oil deposits miles beneath the sea floor
That’s like drilling through Mount Everest, plus another 2.4 km
be vast deposits lying some 9,000 m below the sea floor, in a geological layer known as the Lower Tertiary that dates back some 40 million years. Not only are these deposits locked thousands of metres underground, many are also in locations where the ocean is as much as 2,000 m deep (they are sometimes referred to as “deepwater” reserves)—an insurmountable challenge for drilling rigs designed in the 1950s, which generally stood in about 200 m of water.
The dynamics of extreme water depth and geology, however, present enormous complications. For starters, vast domes of salt had obscured many of these deposits on seismic test images, and salt is something drillers have historically avoided like radioactive waste. Pressure changes resulting from striking it can cause downhole drilling pipe to bind and break before it reaches the Lower Tertiary; it’s also corrosive on certain metals. “We were petrified [of salt],” Cindy Yielding, BP’s chief geologist in Houston, told one reporter. “We wanted to go around it.” And once through the salt, there were the effects of underground pressure, temperature and rock elasticity that the Kola experience so amply illustrated.
The solutions, as they so often do in oil exploration, came courtesy of Silicon Valley. And only the proceeds of soaring oil prices could have adapted them so brilliantly to the ongoing hunt for petroleum. Seismic testing, after all, is a computer-dependent enterprise: air guns are shot toward the ocean floor, sending echo waves back up to the survey ship; the nuances of those echoes are then recorded and processed to generate a digital image of the geological formations they’ve hit. Trouble was, salt disrupts those concussion waves, creating a virtual wall between the oil and the computer trying to picture it. In the Gulf of Mexico, salt formations can run anywhere
from a few metres to a full vertical kilometre thick, yet their opacity made it impossible to know how much salt you were dealing with, or how much oil lay beneath.
The cascade of digital breakthroughs that have taken place over the past decade provided the pivotal advances. An explosion in computing capacity permitted algorithms that generated images showing the lateral contours and depths of the formations—right down to the deposits underneath. “Imagine taking an image of your head from above,” says Mickey Driver, who speaks for Chevron on the deep-oil projects. “The old technology could show the top of your head, but that was all. Now, with this new wide-area imaging, they can see your nose, your ears, the back of your head. Not only that, but with the extra computing power, you can turn and rotate that image in any direction. Suddenly, it starts to give you that threedimensional look.”
Same goes for the exploratory drilling. In
deepwater, it is done not from stationary rigs, but from ships like the 835-foot Deep Seas, a Chevron-leased driller that is held steady by an impressive system that amounts to reverse autopilot. With each change in wind speed, wave power, ocean current and GPS location, the computer calculates the proper response, then sends messages to the boat’s thrusters, which in turn automatically kick in to keep the drill column stationary. In the meantime, metallurgical improvements have resulted in casing pipe that withstands the scorching heat and pressure that plagued the Kola borehole. At the sea-floor level, operations are monitored by robotic submersibles, which later play key roles in capping, completing and fitting the wells with pipes that will run their product to a production platform on the surface.
The drill head itself, meanwhile, has undergone mechanical transformations brilliant in both their ingenuity and simplicity. The motors propelling today’s bits are powered
not by an above-ground engine, as was once standard on drilling operations, but by the hydraulic pressure of drilling mud, the viscous fluid pumped down from above to cool and clean the bit as it tears through the rock. These so-called “mud motors” are located all the way down the hole, just behind the bit, which solves a long-standing limitation on drilling depth. Picture a garden hose stretched all the way out, says Richard Ranger, a senior policy adviser with the American Petroleum Institute, an industry supported think tank. “Now imagine trying to rotate it from one end. It would turn just fine near your hands, but past a certain point, physics just deny you the ability to do it.” Today’s drill bits, by contrast, receive the same power regardless of how deep they sink, while a constant flow of mud both powers them and circulates the cuttings back up a casing pipe for analysis (they are grandchildren, it’s worth noting, of a mud-driven motor used at Kola; the Soviets claim to have invented the concept, but U.S. patents of downhole motors date back to 1910).
Even the production platforms dwarf the ones in use before the deep-oil revolution:
'Right now, what’s going on in the Gulf of Mexico is truly comparable to what NASA is doing with the space station’
in a deepwater field known as Thunder Horse, located about 240 km south of New Orleans, BP has built an enormous platform that doesn’t stand on the sea floor, but rather “floats” in 2,000 m of water, steadied by underwater ballast and shackled by giant guy lines to the bottom. The purpose is not to drill but to pump: Thunder Horse is designed to produce 250,000 barrels of crude per day, along with 200 million cubic feet of gas, from a network of 25 wells. A small city in its own right, it covers the area of three football fields, has quarters for 185 people and holds a gaspowered generator capable of powering 80,000 homes. It is the world’s largest floating platform, and if all goes as planned, it will begin producing oil later this year.
The sheer scale of enterprise is worth putting into perspective, say long-time observers of the industry. Chevron’s Tahiti field, located not far from Thunder Horse, is projected to cost $3.5 billion. Its platform covers three acres, with a “topside,” or on-deck structure, weighing 100,000 tonnes. Royal Dutch Shell spent $1 billion on a nearby field called Mars, while leading a consortium of companies including Chevron and BP on a project called Perdido to develop three separate fields in a 48-km radius. Estimated cost: $4 billion. “The investment I’m seeing right now in equipment and technology amazes me,” says Bruce Wells, executive director of the Washington-based American Oil & Gas Historical Society. “Right now, what’s going on in the Gulf of Mexico is truly comparable to what NASA’s doing with the space station.
That’s why the industry’s screaming right now at the University of Oklahoma for petroleum engineers, for geologists. You can’t be a cowboy or a wildcatter out there any more.”
Yet for each man-made nebula blinking across the Gulf in the night, questions linger. Again and again, “glitches” have prevented the Gulf projects from realizing their early promise. To industry types, they are predictable hazards of a challenging environment. “This stuff is not for the faint of heart,” says Driver, trotting out a common line among the companies that have invested heavily in deep oil. But skeptics might be forgiven for wondering whether these are depths we were ever meant to reach. If you can fly too close to the sun, one surmises,
perhaps you can pry too far into the earth.
The first sign of trouble was an act of God, albeit a predictable one. In July 2005, Hurricane Dennis swept across the Gulf Coast’s storm alley, unmooring ships and, among other colossal acts of mischief, throwing BP’s Thunder Horse platform into a dangerous list. Crews righted the mammoth facility, but the threat posed by hurricanes clearly made an impression in the industry. In September, Chevron announced that production at its Tahiti project, originally scheduled for the middle of this year, had been delayed until mid-2009 because testing revealed a fault in the giant metal shackles needed to hold its production platform on the sea floor.
Meantime, early results from the wells that are producing suggest that the Lower Tertiary isn’t about to cough up its oil without a fight. Analysts cite a menu of complications, from
“compartmentalization” of oil in small reservoirs to pressures so great that petroleum simply can’t escape the rock. An even greater concern has been low-water drive, where the upward pressure brought to bear on the oil from below is too weak to push it up the pipe. Such was the case with K2, a field drilled by Anadarko Petroleum Corp. that failed to reach its 80,000-barrel-a-day target, and will require a costly process of chemical-gas injections to extract most of the estimated two billion barrels in its reservoir.
For Julie Wilson, lead analyst for the Gulf region with Wood Mackenzie energy consultants, such experiences underline the
caveats the industry and public alike should attach to deep oil. “The wells run so far down, and are so far from the production facilities,” she says. “The reservoirs’ characteristics are a lot less favourable. I think the sort of excitement we saw [in 2006] is always followed by a serving of realism. There might be a lot of oil down there, but getting it out is another question.”
As such, the deepwater Gulf epitomizes the new, higher-cost energy reality. The 2008 profits reaped from cheaper-to-recover oil must now be invested in the means to recover the expensive stuff, and sure enough, the industry socked $765 billion into research, technology and new production between 1992 and 2006, according to a recent study produced by Ernst & Young for the American Petroleum Institute. Still, says Wilson, companies are struggling to access oil they can recover in large quantities. “It’s difficult to find, and difficult to produce,” she says. “You have to go into areas like the ultra-deepwater, or the Arctic, where you’re trying to reach resource once considered too difficult.”
Of course, as long as a barrel of oil fetches US$100 or more, they’ll keep trying. And the smart money says they’ll eventually succeed. “If you look at the 20 or 30 years that have intervened between the times people start predicting that we’re going to run out of oil,” says Atkins, the University of Calgary economist, “proven reserves have increased every time. When the world price of oil is high, projects like the ones in the Gulf become more profitable. People are going to rush to get more oil on stream.” The Alberta oil sands are Exhibit A: 20 years ago, critics disparaged the projects as wasteful and uneconomic. But oil prices soared, technology improved and today the Alberta oil sands produce more than a million barrels of crude a day.
That may be why Rehan Rashid, of Friedman Billings, remains bullish on deep oil, despite the troubling early returns. “This simply is a question of history repeating itself,” he says. “The only question is, has the new technology progressed enough to exploit everything that’s available?” It certainly explains why Chevron has laid out lease money for a newer, better drill ship. With a price tag of $650 million, the Discoverer Clear Leader is slated for delivery next year, and will be capable of boring an astonishing 12,000 m into the sea floor. That’s a depth, recall, that defeated one dauntless team of Soviets after decades of pioneering drill work. But by 2010, it will be a necessary routine performed from the deck of floating barges that by the companies’ own reckoning will cost $750,000 a day to operate. The gang at Kola, it is safe to assume, would be green with envy. M
'Excitement is always followed by a serving of realism. There might be a lot of oil down there, but getting it out is another question.1