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05 05, 2014 by Fuel Fix
Seven decades after oil companies first bored wells beneath the Gulf of Mexico, it retains its allure, as recent discoveries tempt the industry with the prospect of pulling crude from 200-million-year-old rock buried miles below the seafloor.
The Gulf’s appeal is so strong that it anchors many oil companies’ portfolios, despite an onshore drilling boom that is putting rigs to work from North Dakota to West Texas.
“This basin keeps reinventing itself,” said University of Texas Austin geologist John Snedden. “We keep finding new plays. And that’s why everybody’s here.”
The oil riches of the Gulf and coastal territories around the globe draw tens of billions in oil company investment — and they’re drawing tens of thousands of industry professionals to this week’s Offshore Technology Conference in Houston.
And while offshore wells can be at least 30 times more expensive than the ones on land, they promise bigger yields — with production that can span decades — in contrast to what some energy analysts describe as the “drilling treadmill” necessary to keep oil flowing from onshore shale plays.
Companies from around the world are active in the Gulf, employing more than 40 mobile drilling units to work on projects stretching hundreds of miles from the coast.
That reflects a resurgence in Gulf action. The drilling level now is higher than before the slowdown prompted by the deadly 2010 blowout of BP’s Macondo well that killed 11 workers and spilled oil for three months.
“These numbers have not been seen in the Gulf of Mexico before,” said Wood Mackenzie analyst Jackson Sandeen.
Technological innovations are helping to unlock untapped areas of the Gulf — and even allowing companies to breathe new life into old projects.
For instance, BP is adding new wells to tap still-unrecovered resources around its Thunder Horse and Atlantis platforms.
And Shell is working to link its 100-million-barrel Cardamom field to its Auger facility, 20 years after that platform first debuted in the Gulf. Shell expects Cardamom production to add 50,000 barrels of oil equivalent in daily production.
“It’s a story of opening up new frontiers,” said John Hollowell, an executive vice president at Shell Oil Co.—the Houston-based U.S. arm of Royal Dutch Shell.
“The combination of continued advancements in technology and innovation, combined with attractive new frontiers to open up new opportunities for oil and gas development make the Gulf of Mexico a place of attractive investment now and well into the future.”
Seismic and supercomputers
The industry is exploiting advances in seismic equipment and supercomputing power that make it possible to see through salt deposits to once-invisible layers beneath and generate detailed maps of the geology.
Many deep-water Gulf wells have plumbed the Miocene play, a relatively porous layer of the earth’s crust formed up to 24 million years ago. Recent Miocene projects have focused on oil-bearing rock below a canopy of underground salt.
But oil companies also are investing more in the Lower Tertiary, deposited during the older Paleogene period of the earth’s geological history and located even farther underground.
Also beckoning is the Jurassic Norphlet formation — 200 million-year old sediment where Shell is appraising recent discoveries, and where Murphy Oil is drilling its Titan wildcat well in hopes of unlocking a potential 200-million-barrel resource.
The Jurassic trend is still an oil industry frontier, compared even to Lower Tertiary.
Wells have been drilled through thick ribbons of salt into Lower Tertiary rocks for about a decade, but only two projects are actively producing oil from it – Shell’s Perdido complex and Petrobras’ Cascade. Another, Chevron’s Jack St. Malo platform, is set to come online later this year.
Other Lower Tertiary discoveries include BP America’s Kaskida, Cobalt International Energy’s North Platte, and Anadarko Petroleum Corp.’s Shenandoah prospect — which these companies operate with other partners.
The Lower Tertiary wells are technically challenging, marked by high pressures and extreme reservoir depths. Just to get to the pay zone, companies must drop drill bits through as much as two miles of water, then drill through perhaps three miles of salt and another two miles of rock.
And once there, the companies have to wrestle crude out of dense rock that resists giving up the prize locked within.
Expensive dry holes
The first wave of these wells, drilled into what geologists call the Outboard Lower Tertiary trend, had a success rate as high as 70 percent. But oil explorers have had far less luck tapping the Inboard Lower Tertiary and the Jurassic, with several recent finds too insignificant to produce.
“We’ve had some successes, but we’ve also had some very expensive dry holes,” said Snedden, the UT geologist.
Cobalt has experienced both in the space of a year, celebrating its North Platte discovery in December 2012 before determining eight months later that its Ardenne well just 54 miles away was a failure.
“The Lower Tertiary appears to be not quite as robust and as productive as they had hoped,” said Leta Smith, director of oil and gas supply for the consulting firm IHS. “But companies are still moving ahead with it.”
They do that because when deep-water wells do work out, the payoff can be high-volume, long-lasting production equivalent to scores of onshore wells.
For instance, production data for two wells in the Eagle Ford Shale of South Texas show they yielded an average of 360 and 283 barrels per day during their first eight months. By contrast, the first well in Petrobras’ Lower Tertiary Cascade project is producing 12,000 barrels of oil daily.
Onshore shale production requires pulling oil out of impermeable rocks with hydraulic fracturing, using sand, water and other fluids under pressure to create fissures underground. Gulf wells, so far, generally have tapped into more porous sediment and large pools formed from biological deposits tens of millions of years ago.
Such projects can keep delivering oil long after the wells are bored.
Unconventional, dense onshore shale, by contrast, often requires continual drilling and fracturing to keep the crude flowing.
That cycle may be unsustainable, especially if oil prices decline, said Rebecca Fitz, senior director of upstream strategy and completion for IHS Energy.
“You have to drill to produce,” Fitz said. “Some companies have told me the only way you make money is if you stop drilling, but then production decreases.”
$300 million wells
Given the sharp differences between offshore development and the recent boom in unconventional oil production onshore, it is difficult to compare their value.
Oil companies know that successful deep-water projects generate scale and large returns.
“Deepwater is proven,” Fitz said. “But U.S. unconventionals are a completely different business model and the industry as a whole is really trying to grapple with how do you compare the investment proposition and the time to payoff.”
Where onshore shale wells may cost $3 million to $5 million, Snedden estimates that the average Lower Tertiary well costs around $150 million. Wood Mackenzie’s Sandeen puts the number higher; he said the Lower Tertiary wells are expected to cost $300 million to drill and complete.
Wells tapping the Miocene trend — the recent deep-water mainstay — average a more affordable $80 million.
“The Lower Tertiary is a play for deep pockets, as well as a play that requires a long time horizon,” Sandeen said.
The first phase of Chevron’s Jack St. Malo platform, for example, has a $7.5 billion price tag — but a production capacity of 177,000 barrels of oil equivalent per day.
That potential allows deep-water Gulf projects to lure capital despite competition from onshore shale, said Shell’s Hollowell.
“Our deep-water Gulf of Mexico opportunities, as expensive as they are, are still something Shell chooses to invest in,” he said. “And it’s an attractive investment.”
Decades of life
Some oil companies seek a mix of U.S. projects — staking out territory on land as well as in the water so comparatively inexpensive and reliable onshore shale drilling can help offset costly, risky offshore ventures.
“The Gulf of Mexico carries a lot of risk. The success rate is lower, the costs are much higher and the cycle times are much longer, so it’s going to take you longer to get your cash flows,” Sandeen said. “Because of the risky nature of the business, it is beneficial to have something to complement it.”
Oil companies that can afford such diverse portfolios find two big advantages in the Gulf relative to many other offshore regions.
It boasts an oil and gas infrastructure built up over decades, with pipelines and ports helping to bring those products to the petrochemical plants dotting the Gulf Coast.
The U.S. Gulf also offers a relatively stable regulatory environment, without hostile interests or fickle government overseers.
All of that gives companies the confidence to invest in the region and build ultra-deep-water facilities with 30-year lifespans, said Andy Radford, a senior policy adviser with the American Petroleum Institute.
In the Gulf, he added, “there are decades more life.”
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