Equipment firms feel pressure as deep-water work heats up

As the search for oil goes deeper into water and rock, it encounters increasingly hostile conditions — including pressure more than 1,000 times what we feel at sea level and temperature three times hotter than a Houston summer day.

And that has made high-pressure-high temperature technology a central focus of research at BP, Royal Dutch Shell, FMC Technologies and other companies venturing into the Gulf of Mexico’s Paleogene region — a 23 million-year-old geologic layer where pressure can be 20,000 pounds per square inch and temperatures can top 350 degrees Fahrenheit.

These conditions were deemed too difficult to drill in even 10 years ago, but now are considered the next frontier among many of the oil industry experts gathered at Reliant Park for the Offshore Technology Conference.

“The time of easy oil and gas is gone,” said Gerald Schotman, chief technology officer for Shell. “We will take these reservoir management challenges as they come. It is not a specific choice we make — it is a choice that comes with tapping into oil and gas that has been hidden from this industry.”

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The Paleogene reservoirs are located in water as much as two miles deep, and can be another 30,000 feet under the ocean floor.

Manufacturers like FMC Technologies are working with offshore operators including BP, Shell and Chevron to develop equipment that can function in the temperature and pressure of such environments.

The motivation is access to billions of barrels of oil.

“It will open up a lot of additional resources globally,” said Kevin Kennelly, BP’s vice president of technology and head of the company’s Project 20K, a Houston-based effort to design and build equipment that can operate safely under as much as 20,000 pounds of pressure per square inch and temperatures exceeding 300 degrees Fahrenheit.

Sea level pressure is 14.7 pounds per square inch.


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Kennelly said BP estimates that equipment meeting Project 20K specifications could open access to 10 billion to 20 billion barrels of resources in reservoirs worldwide, including BP’s Tiber and Kaskida Fields in the Gulf of Mexico. “We saw that we had discoveries on our books that we couldn’t develop if we didn’t have these kinds of technologies,” he said.

But to do so means rethinking drilling and production equipment — the wellheads, the pumps, the blowout preventers — so they can survive pressure that can crush some types of metal.

“When you build equipment for higher pressures, the first the thing that comes to mind is to build it bigger,” Kennelly said, explaining that using heavier equipment has worked in the past for wells with greater pressure. At about 15,000 pounds per square inch, however, the equipment becomes too unwieldy and heavy to be of practical use for drilling, Kennelly said.

Heavier equipment is also more vulnerable to the natural elements.

“With a bigger diameter, it not only is heavier,” said Li Sun, a mechanical and materials engineering professor at the University of Houston. “There are currents and waves which shake it and cause fatigue. It adds a lot of force onto those connections and parts, which makes it easier for them to fail.”

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Temperatures create a separate set of problems.

Existing equipment can perform in conditions up to 300 degrees Fahrenheit. But somewhere between 350 to 400 degrees Fahrenheit, the metal now in use begins to warp, providing a textbook example of what engineers call the “coefficient of thermal expansion.”

“As you heat things up, they tend to grow, and they will grow at different rates,” said Eric Gebhardt, vice president of engineering for GE Oil & Gas, who said that his engineers do simulations to predict how the equipment will perform in extreme conditions. “You build a 3-D model, put defects in different angles and orientation and see how the material reacts.”

But the heat deep in the Earth isn’t the only problem. Some materials have to withstand the cold temperatures of the ocean depths, and some have to tolerate both — an even more complex problem than just withstanding heat, said Randy Wester, director of global subsea engineering of FMC Technologies.

The industry is looking into certain rubbers and metal alloys to substitute for the iron used now, seeking a complicated array of characteristics — stronger, lighter, and affordable.

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The people wrestling with the problems face a long time horizon.

BP’s Project 20K, which it began last year with partners FMC Technologies and KBR, is multiyear.

“I don’t think anyone will say we are actually there,” said Eric van Oort, a petroleum engineering professor at the University of Texas at Austin who worked on several deep-water projects with Shell. “But I have seen how enabling technologies have come along in the past, and that is why I think this nut will eventually be cracked as well.”