BP’s Thunder Horse drilling rig in the Gulf of Mexico, shown here, is the largest moored semi-submersible oil platform in the world. Located in 1,920 meters of water in the Mississippi Canyon, about 241 kilometers southeast of New Orleans, Thunder Horse oil production has been delayed by technical problems, and is scheduled to produce its first oil in 2008. Photograph is courtesy of BP Public Affairs Staff.

To a “blue-water” oceanographer who studies mid-ocean ridges or deep subduction trenches, the continental shelf — which can extend more than 100 kilometers from shore and measure 200 meters deep — is still the shallows, comprising the nearest-shore part of the transition from shoreline to deep ocean. Beyond the shelf break, the ocean floor slopes sharply downward and descends into a still-mysterious abyss representing a vast, exciting scientific frontier.

In the past decade, the petroleum industry, too, has been venturing into deeper waters — farther out into what the industry and the government refer to as the outer continental shelf (OCS), a more encompassing definition than the stricter scientific term. To the U.S. government, the OCS includes all U.S.-owned submerged lands lying beyond the states’ jurisdiction, ranging from about 6 to about 17 nautical miles offshore.

In the deep waters of the Gulf of Mexico, in particular, the petroleum industry’s deepwater exploration has discovered what appear to be vast, high-quality reservoirs of oil and gas — but that region is only beginning to be explored, due to the tough technical challenges involved in bringing resources buried at extreme depths, pressures and temperatures to the surface.

In the last half of 2006, several world-class discoveries of oil reserves in the Gulf have spurred new efforts in the region and offered new optimism for companies fearing a “peak oil” scenario, in which the world’s growing petroleum demands are projected to outpace new resources. Discovering such vast reserves deep under the seafloor is only one part of the challenge, however, and many more challenges lie ahead before reserves from those fields will arrive at world markets.

The setting
Bordered by Florida, Alabama, Mississippi, Louisiana and Texas, the Gulf of Mexico spans 1.6 million square kilometers. The seafloor of the Gulf is a complicated mishmash of oil and gas seeps, faults, salt domes and sediment from river deposits. Seafloor spreading within the North American Plate, from the Late Triassic (228 million years ago) through the Middle Jurassic (165 million years ago), formed the Gulf, which later subsided and filled with sediment and evaporite deposits, primarily salt. The salt, a key cap for hydrocarbons, migrated southward and upward, creating a complex series of structures among the folds and faults of the reservoir rocks. Because the Gulf has been a passive depositional basin for 75 million years, it contains many layers of sandstones, siltstones and shales. The porous, permeable sandstones form excellent petroleum reservoirs, while the extensive faults and salt caps form both passageways and traps for the reserves rising toward the surface.

Onshore, the Wilcox Formation, an Eocene-aged sandstone (56 million to 34 million years) runs from southeastern Texas through southwestern Louisiana, and has produced mostly natural gas since the 1930s. Such reservoir rocks were not thought to exist farther offshore, in the deepest parts of the Gulf, until the past couple of decades. Additionally, there were financial, as well as technical, limitations to drilling in the deep offshore waters — without high-quality 3-D seismic data that could see below the salt traps and determine where hydrocarbons might be present, the financial risks were high.

Since the early 1990s, however, 3-D seismic surveys have blanketed most of the deepwater Gulf, and have revealed previously hidden prospects. Seabed technology has also revealed reserves hidden below salt pillows, structures of salt that are less dense than the surrounding rocks and intrude vertically into the overlying strata, forming domes that can trap oil and gas.

In 2001, Shell, Amoco, Texaco (now part of Chevron) and ExxonMobil drilled the exploratory BAHA 2 well in 2,375 meters of water in the northwestern Gulf of Mexico, in a region known as the Perdido Fold Belt. The region is part of the Wilcox “trend,” a fault system that extends from west to east across much of Gulf. The faulted rocks date to the Lower Tertiary period, from 65 million years to 24 million years, which encompasses the Paleocene, Eocene and Oligocene.

Other well discoveries in the Perdido belt soon followed, including Unocal’s Trident well in 2001 and Shell’s Great White well in 2002, establishing that the region held significant oil potential. Drilled down 6,250 meters (beneath 2,953 meters of water), Trident set a world record at the time for water depth, which was soon broken by new wells drilled ever farther offshore in the Gulf.

Offshore leases in the Gulf of Mexico are divided into blocks in western, central and eastern planning areas. Many of the major petroleum fields discovered so far have been in the western area, in Alaminos and Keathley canyons, and in the central area, in Walker Ridge and Green Canyon. Image is courtesy of MMS.

Shortly after the Great White discovery, BHP Billiton announced a find in their Cascade prospect, a large salt structure primarily of Miocene-age (24 million to 5 million years) lying about 444 kilometers to the east, in the Walker Ridge area of the central Gulf. This find extended the Wilcox “play,” or reserves field, far to the east across the Gulf, and suggested that the Wilcox trend had the potential to be a world class petroleum system.

More Gulf discoveries in 2003, including Petrobras’ Chinook and Unocal’s Saint Malo discoveries, further extended the Lower Tertiary trend, from the Perdido belt in Alaminos Canyon, through Keathley Canyon and to Walker Ridge. And it was in the Lower Tertiary rocks that the biggest discoveries of 2006 were found.

Into the Deep
The Gulf of Mexico is hardly a last frontier: It and its environs have been explored for more than 100 years, but for many it represents a new hope for oil. World oil demand is projected to increase by more than 1.6 million barrels a day in both 2007 and 2008, compared with a growth rate of 0.8 million barrels a day in 2006, according to the U.S. Energy Information Administration. China accounts for about one-third of that projected growth.

With a looming oil crisis in mind, the United States has been anxious to lure companies to explore its deep waters. In 1995, the U.S. Minerals Management Service instituted a program to encourage companies to invest in exploration and production of oil and natural gas from properties they already leased in the Gulf of Mexico. The Outer Continental Shelf Deep Water Royalty Relief Act (DWRRA) of 1995 — later redefined and extended, in 2000 — offers companies with leased property in the Gulf a temporary financial break, particularly if they were drilling in very deep water. Companies were exempt from paying royalties on much of the oil and gas they produced, under certain conditions: First, the company must show that without that relief, the field is not economically viable; second, oil and gas produced in deeper-water fields are given more relief than in shallower fields.

The plan worked, according to MMS, with more than half of the 7,800 active oil and gas leases in the Gulf located in deep water. The royalty relief act spurred companies to “snatch up as many [leases] as they could,” in the hope that technology would catch up before they expired, says Zoe Sutherland, an analyst at energy consulting firm Wood Mackenzie.

Environmentalists worry, however, that the royalty incentives and tax breaks make restrictions on drilling in the Gulf too lax, while the risk of spills still remains. Furthermore, leases issued in 1998 and 1999 lacked clauses that would end the royalty waivers when oil and gas prices increased to certain limits. To address these concerns, the U.S. House of Representatives passed legislation in January denying Gulf leases to companies that do not agree to price thresholds. That legislation has now passed on to the Senate.

Companies worry that, if approved, the legislation could raise the stakes in the Gulf, delaying leasing and production. By 2005, enthusiasm for drilling in the deep had been flagging: Deep drilling is expensive and technically challenging, with the costs of drilling each well as much as $100 million, and the average success rate for such wells hovering around 25 percent for many companies in recent years. In terms of additions to the total reserves, 2004 and 2005 were “disappointing” years, adding less than 1 billion barrels to total reserves, according to a report released by Wood Mackenzie on Feb. 1, 2007.

Then came 2006, a banner year for discoveries in the Gulf. That year, nearly 1.5 billion barrels of oil equivalent, a unit that combines oil and gas reserves and production into one number, were added to the total reserves, Wood Mackenzie stated in the report. Half of the reserves increase came from two major Gulf discoveries: BP, along with Anadarko Petroleum and Devon, a 240-meter-thick layer of hydrocarbon-bearing sands, or “pay,” at its Kaskida prospect in Keathley Canyon, about 400 kilometers southwest of New Orleans; and Hess discovered a 145-meter-thick layer of pay at its Pony prospect in Green Canyon in the central Gulf.

Then, on Sept. 5, Chevron, Devon Energy and Norway’s Statoil announced a successful well test in a massive field in the Lower Tertiary in the Gulf. The well, called Jack-2, was drilled at a spot 280 kilometers off the Louisiana coast, in more than 2,133 meters of water. The deepest successful well test in the Gulf to date, it was a technical achievement, drilled to 8,588 meters of total depth. It was also an expensive, $100 million gamble — although geophysical data suggested the field was vast and viable, no one had ever extracted oil from such a deep well in a high enough volume to make such a venture commercially viable. The field’s estimated reserves could be 3 billion to 15 billion barrels; 15 billion barrels represents half of the U.S. current reserves.

While promising, the Jack-2 test is only a first step, however. For a field to be commercially viable, not only should the reservoir be of high quality and the oil flow easily, but both infrastructure and drilling technology must be available. With the Jack-2 test, companies were able to assess the oil’s quality and how well it flows, but whether actually drilling and producing the oil from such depths will be cost-effective remains to be seen, Sutherland says.

“After the well test, they understood the reservoir a little better,” Sutherland says. “The next big challenge is designing technology to produce that well.” It may take several more years to solve some of those problems, she says. “The technology is only just beginning.”
Using the results of the Jack-2 test to design wells and facilities, a new project by Devon, called the Cascade project, is scheduled to start up in 2009, and could become the first Lower Tertiary discovery to actually produce oil, according to Stephen Hadden, Devon’s senior exploration and production vice president.

The success of the Jack-2 well also suggests that other deep-sea reserves around the world, once thought to be too difficult or expensive to recover, may now become recoverable. Such reserves may lie offshore of Britain, in the North Sea, as well as off the coasts of Brazil, West Africa and in the Nile River Delta, Egypt.

Drilling into the future
According to MMS, of the 782 active deepwater leases in the Gulf projected to lapse in 2007, 756 of them are still “untested.” In such a short time period, it is unlikely that all of these prospects will be drilled.

Among the technical and financial challenges companies will face in the next few years is a dearth of state-of-the-art rigs, such as Transocean Inc.’s advanced deep-sea rig Cajun Express, which drilled the Jack-2 well. As drilling picks up, “the problem at the moment is rig availability,” Sutherland says. “There’s a limit to how many rigs can operate in such deep water.” And because they are now in higher demand, the rental prices for such rigs are already on the rise, as well as the cost of skilled labor.

Other companies face technical delays, such as the BP-operated Thunder Horse project, located in the Boarshead Basin, 200 kilometers southeast of New Orleans. Lying in 1,900 meters of water, the field is 6,000 meters below the seafloor and is the largest in the Gulf of Mexico. Problems with the platform’s sub-sea equipment have delayed first production into mid-2008. Furthermore, the Gulf is famously prone to hurricanes, such as Hurricane Dennis in 2005, which severely damaged BP’s Thunder Horse rig.

How to get the oil back to shore is another problem. The drilling sites are far offshore, and there are no pipelines in place to carry the hydrocarbons. Other possible ways to transport the oil include floating production systems — large ships equipped with processing facilities, storage and an offloading system that are moored to a location for a long period. Such systems are also less of a financial investment than a permanent platform, allowing a company to drill just one or two production wells and gather information on the reserves before investing more money.

With these technical delays and difficulties, some skeptics are questioning whether the promise of the deep-sea discoveries will ultimately be realized in time to catch up with skyrocketing world petroleum demands. Rather than debunking the peak oil theory, skeptics say, the very technical achievement of the Jack-2 well also highlights the difficulty of extracting these reserves.

“Any attempt to put a figure on the production forecast from the Lower Tertiary at this point would be pure speculation,” said Gero Farruggio, an analyst at Wood Mackenzie, in a press release accompanying the February report. “What is certain — the upstream playground in the Gulf of Mexico has just got a lot bigger.”

Gramling is a staff writer for Geotimes.

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