Offshore Oil Goes Deep
Planning to drill more than a mile down, Deepstar engineers grapple with formidable challenges in high pressure and low temperature.
Whatever you think of Big Oil, it’s not afraid to roll the dice. And it’s making truly enormous gambles offshore, in water depths once thought all but impossible to conquer.
In the Gulf of Mexico, where half the oil comes from wells in water more than a thousand feet deep, eight wells are now being drilled in “ultra-deep” waters of more than five thousand feet.
In order to cross the one-mile-deep barrier, the industry will need to extend existing technologies. But drillers also must overcome new problems caused by the forbidding combination of low temperatures and high pressure found at such depths.
An industry-wide collaborative effort called Deepstar is attacking the challenges of producing oil profitably in depths up to 10,000 feet. Last week at the Offshore Technology Conference in Houston, project leaders gave an update on their progress.
Among the most critical problems: reconfiguring drilling “mud” systems to handle very high pressures, and pumping oil across a very cold seafloor.
Drilling mud lubricates the drill bit, and its pressure prevents oil or water from gushing up the drill hole. The mud is made from a variety of materials such as the clay mineral bentonite. When digging wells, operators pump the mud down the drill string to the drill bit, and then back up to the surface in a ring known as the annulus, which is formed either by the hole being dug or by the piping around the drill string.
Drillers change the mud weight at intervals to ensure that it is heavy enough to counteract the pressure of fluids that the drill bit encounters, which increases as the hole goes deeper. If the mud is too heavy, it can fracture the sediment and rock around the drill bit, potentially causing catastrophic blowouts of oil or gas.
In ultra-deep waters, maintaining the right mud weight becomes especially complex. Because there is so much mud in an annulus that stretches from well to surface at such depths, it creates high pressure even when light.
Operators can prevent fracturing by fitting supports, known as casings, into the well hole, but this is an extremely slow and costly process. (Contract rates for ultra-deep drilling rigs can hit $250,000 a day.) Each casing must be small enough to fit down the previous one, so this technique also shrinks the diameter of the hole. That means that casings may not only be prohibitively expensive but may lead to a well hole that’s too small for profitable oil removal.
At last week’s conference, James Chitwood of Chitwood Engineering in Houston outlined several emerging technologies that address the problem, including one called dual-gradient drilling.
The idea here is to send drilling mud down as usual, but rather than sending it up to the surface through the annulus, pump it up by a different route, thus eliminating most of the pressure from the mud. The annulus could then be filled with seawater to maintain the right pressure. Mud would still move through the annulus from the bottom of the drilled hole to the pump, so that some casings would still be needed, but far fewer. And the threat of blowouts would also be dramatically reduced.
One collaboration called the SubSea Mudlift Drilling Joint Industry Project plans to have an experimental setup on the seafloor by midyear.
Charles Peterman, director for the project with its designer, the Houston-based Hydril Company, expects this will be the first full test of the technology (though details of such accomplishments are often kept secret within the industry). “There will be areas in water depths somewhere between six and eight thousand feet where [dual-gradient drilling] is probably going to become mandatory,” says Peterman.
Once a successful well is drilled in ultra-deep water, there’s a dizzying number of ways to pump out oil and gas. These fall into two main categories: “dry-tree” and “wet-tree” systems. (The pumping mechanism is called the wellhead, and the valve arrangement on the top of the wellhead is called a Christmas tree.)
Dry-tree systems place wellheads above the well itself on fixed or floating platforms. Wet-tree systems combine wellheads on the seafloor with piping to a centralized platform-a less expensive approach. But wet-tree systems are the hardest to adapt to the harsh deep-sea environment, which involves not just extremely high pressure but chilling temperatures that can play nasty tricks on oil in a pipe.
At temperatures near freezing, the water commonly found in crude oil can form crystallized formations of ice and methane, known as hydrates, that clog up the walls of a pipe. Waxes in the oil can also solidify, exacerbating the problem. These complications get worse as pipes get longer-and oil companies would like to run wet-tree piping as much as 60 miles.
Pushing the Pipeline
There are solutions to this problem such as insulating pipes or using chemicals to block hydrate and wax formation. But these either cost too much or won’t work well enough in the ultra-deep range, says Steven Wheeler, Houston-based Texaco’s sub-sea technology team leader. So the program has identified and ranked new technologies for altering the oil’s temperature, pressure, or both.
An obvious answer, now being tested, is to heat the pipes. While this can stop hydrates and wax, it requires a massive amount of electricity-a commodity that’s not cheap on the open sea. “It’s not like you’re running down a light bulb-we’re talking megawatts of power,” Wheeler notes.
Other options are also on the table, although it’s far too early to pick a winner, experts say.
One potential approach that may seem odd is to actually cool the oil as it comes out of a well. Hydrates and waxes stick to pipe walls because they are attracted by the difference in temperature between the warmer oil and the chilly water outside. If the oil were just as cold, they would still form but keep flowing and not aggregate into clogs. So, companies around the globe are developing “black boxes” to cool the oil to temperatures in surrounding waters. Details of such work are mostly under wraps.
If this achieves sufficient cooling, it will be a big boost for wet-tree systems, says Denby Morrison, offshore technology manager for Shell Global Solutions in Houston.
Development of such technologies will be pricey, but costs pale compared to the total bucks oil companies are putting down. In the past year, for instance, British Petroleum unveiled four projects for waters over four thousand feet with a total cost of about $3 billion. The ultra-deep deposits “are massive fields, and the enticement is big enough to offset the potentially huge financial risks,” says Morrison.