Texaco Inc. geologist Robert Ryan didn’t suspect he was helping change the energy future of the Gulf of Mexico when he gave the go-ahead for a well that would break the world record for deep-water drilling.
The project known as BAHA, undertaken in 1996 by Texaco and its partners, Royal Dutch Shell Plc (RDSA), Amoco Corp. and Mobil Corp., was a dry hole. That normally would’ve made it a flop. Instead, BAHA’s discovery of oil-rich sands where none were thought to exist was the first step in unlocking a $1.5 trillion trove of crude that’s revived the prospects of a body of water many thought had long ago given up most of its fossil-fuel riches.
Just as technology has allowed explorers to tap vast new oil and natural gas supplies in onshore shale fields, it’s now reinventing the Gulf. BAHA was the first deep-water well to try plumbing the Lower Tertiary, a layer of the earth’s crust formed more than 25 million years ago after mammals had replaced dinosaurs as the dominant life form.
A series of recent finds in the ultra-deep has profoundly changed the thinking on U.S. offshore geology, with 2013 seeing the Gulf of Mexico become one of the most promising frontier oil plays in the world and the fastest-growing offshore market.
New seismic equipment and computer power has allowed explorers to see into once-invisible layers of rock. Engineering innovations enable them to drill five miles into the earth through waters more than 10,000 feet deep, where temperatures are more than hot enough to boil water and high pressures approach the weight of four cars resting on one square inch.
The Gulf is heading for record deep-water output equivalent to almost 2 million barrels of oil a day in 2020, according to industry researchers Wood Mackenzie Ltd. The U.S. estimates about 15 billion barrels of recoverable oil remain to be found in the Lower Tertiary.
While most U.S. shale fields have now been identified and mapped, the Gulf is seen as having much bigger yet-to-be-discovered potential -- 48 billion barrels of oil compared to the 13 billion barrels estimated for onshore and coastal oilfields, according to U.S. data.
Investment is pouring in, with 42 drilling rigs operating in 1,000 or more feet of water as of Sept. 9 -- 35 percent more than four years earlier, according to U.S. data on the Gulf. By the end of 2015, 60 rigs are slated to be working in the deep water off U.S. shores, estimates Brian Uhlmer, an analyst at Global Hunter Securities LLC in Houston.
It’s a dramatic turnaround for the Gulf, which saw interest wane in the previous decades as old wells dried up and explorers shifted their attention to search Africa, Latin America and Asia. By October 1989, offshore crude output had dwindled to 678,000 barrels a day, down 28 percent from 943,000 barrels five years earlier, according to Energy Department data.
“Deep water wasn’t working for us,” said Ryan, now Chevron’s chief of global exploration, who worked for Texaco in the 1990s before it was acquired by Chevron. Yet they still weren’t ready to walk away.
In 1995, geologists and engineers from four of the world’s biggest oil companies -- Texaco, Amoco, Shell (RDSA) and Mobil --packed into a Houston conference room to discuss what was described as the biggest undrilled geologic structure left in the continental U.S.
The companies had joined together a block of leases in the Gulf of Mexico that had languished for about 10 years. They were excited by the massive up swell of rock that formed the subterranean structure -- the type of dome that in other places had yielded abundant oil and gas. But doubts ran high about drilling.
The prospect was in deeper water than ever had been drilled -- 7,625 feet. Based on current geologic understanding, the scientists worried the formation wouldn’t contain the kind of oil-bearing sands that would justify drilling such an expensive frontier well. “It was thought that sands settled closer to shore,” said Ryan, who at the time was in charge of Gulf of Mexico exploration for Texaco.
After hours of tense debate, the four partners agreed to drill. It was risky, yes. It also promised to reveal a vast new store of knowledge about the potential of the deep water Gulf. The only way to mitigate the risk of future drilling is to get a well in the ground and find out what’s there.
“Somebody has to drill that first well,” Ryan said, recalling the difficult decision in an interview last month in his Houston office. It’s all about building the story, well by well. “You’re piecing it together,” he said.
The next vote -- on what to name the well -- was almost as contentious. Naming privilege generally goes to the majority partner and operator, while the four companies were equal owners. Squabbling followed, Ryan recalls, until one of the geologists in the room, eager to step out for a smoke, hit on the solution: each company contributed a word, and the first letter of each word formed the name. So Brachiosaurus (Shell), Alpha Centauri (Texaco), HI-C (Mobil) and Anaconda (Amoco) became BAHA.
Shell, which had a drilling rig under contract ready to start, was named the operator of the project.
As feared, the BAHA well was a dry hole. Technical difficulties forced the companies to stop drilling before they’d even hit their target depth. But the real value of the well was in what it did find: a layer of oil-bearing sand where they didn’t think it would exist.
“More sand than you could shake a stick at,” Ryan said. “It busted every model we had.”
Ryan still has the custom shirt and hat made to commemorate the well, with the embroidered BAHA logo underscored by the bragging point: “Ultra-Deepwater.” The shirt was a testament to the landmark nature of the well, since such souvenirs are usually reserved for discoveries, not dry holes.
The results made BAHA 2 a no-brainer, though it took five more years for the companies to study the formation and decide where the next well should go.
By 2001, Mobil was part of Exxon, Amoco was part of BP Plc (BP/) and Texaco was becoming part of Chevron in a wave of Big Oil mergers meant to give the companies enough heft to explore in ever-more remote and hostile regions of the world.
Even though BAHA 2 turned out to be another dry hole, it showed the extent of the oil-bearing sands in the deep water Gulf. Michael Mahaffie, a member of Shell’s exploration team, remembers watching the drilling logs transmitted to his Houston office, mapping the rock as the drill bit moved deeper into the Lower Tertiary.
“I immediately flew to New Orleans to show Shell leaders what we discovered -- the ‘whopper sand,’” he recalled in an e-mail last month. “It was a major revelation to be able to correlate the seismic data to the extensive and continual sands that we found, which covered two-thirds of the deep-water Gulf of Mexico.”
Other companies had begun exploring in and around the edges of the zone, and more wells quickly followed. BAHA 2 had shown not only the enormous potential of the Lower Tertiary sands, it also demonstrated the enormous cost, at more than $100 million per well. To be economic, discoveries needed to be big.
Shell hit oil at its Great White prospect the following year, 2002, and the company was on its way to multiple finds in the Lower Tertiary. By 2006, Shell was ready to announce plans to produce oil through a floating facility from the region known as Perdido, a project it owns jointly with Chevron and BP.
The Perdido complex -- which produces from the Great White, Tobago and Silvertip wells -- was the first Gulf project from the Lower Tertiary to begin output, with the companies announcing the startup on March 31, 2010.
Less than a month later, exploration stopped in the Gulf as BP dealt with the explosion at its Macondo well that triggered the largest U.S. offshore oil spill.
Drilling was shut down for months as regulators reviewed safety practices. The U.S. bolstered its oversight of the offshore industry after Macondo and added new protections for deep-water projects, such as setting up offshore containment systems in the event of a leaking oil well, said Lars Herbst, Gulf of Mexico regional director for the Bureau of Safety and Environmental Enforcement in New Orleans.
Companies used the pause to further their studies of the Lower Tertiary and fine-tune their drilling strategies, the University of Texas’ Snedden said.
“We’re seeing the benefits of that reinvestigation,” he said.
BP, after facing years of criticism for the spill that’s set to cost it more than $40 billion, hasn’t recoiled from the Gulf. The London-based company still boasts the most licenses in the region and says it will have eight rigs drilling this year, more than ever before.
Petroleo Brasileiro SA (PETR3), known as Petrobras, started production from its Cascade/Chinook wells in the Lower Tertiary last year.
Anadarko Petroleum Corp. (APC) has said its Shenandoah find in the Lower Tertiary may be one of the largest projects in the Gulf.
New technology has been the key to unlocking “one of the unrivaled basins of the world” thanks to its geology, commercial potential, and pipeline and production infrastructure, said Ernie Leyendecker, Anadarko’s vice president of Gulf exploration.
“All three of those things give the Gulf significant advantages over almost anywhere else in the world.”
Chevron expects oil to start flowing next year at its Jack/St. Malo project.
The Jack and St. Malo fields are about 280 miles south of New Orleans and within 25 miles of each other. The company’s production platform for the project is built to handle the equivalent of as much as 177,000 barrels of oil a day.
Chevron remains among the most bullish companies on the Gulf of Mexico, with five rigs currently drilling there -- a record for the company.
“What catches our attention is the potential,” Ryan said, “billions of barrels right in our own backyard.” And it’s still in its infancy, he said. Chevron has identified some 45 drilling prospects in its inventory in the Lower Tertiary.
A key breakthrough has been new seismic tools that allow companies to see through layers of salt deposits that previously blocked their vision, opening up new parts of the formation to exploration. Conventional wisdom among geologists was that there would never be oil found beneath the salt -- a belief blown apart as wells such as Jack and St. Malo proved oil was hidden there, after all.
Costs remain high, at about $1 million a day to drill ultra-deep wells in deep water. Risks remain high too as companies remain in exploration mode. Cobalt International Energy Inc. (CIE) announced a dry hole on Aug. 19 in the Lower Tertiary. Even as its stock dropped 15 percent that day, the company was undeterred, saying it would use the knowledge it gained from its dry hole to keep drilling.
The success rate in the Lower Tertiary so far has been about 60 percent, with 40 percent of discoveries having commercial potential -- a “tremendous” rate considering that 30 percent is considered good, Chevron’s Ryan said.
The value of the Lower Tertiary extends far beyond the Gulf of Mexico as companies tackle similar ultra-deep projects and formations off the coasts of Africa and Latin America. The engineering, seismic technology and basic experience obtained in the Gulf can be leveraged to lower costs and raise success rates in those regions.
The Gulf is the “tip of the spear” for that sort of learning,’’ Ryan said. The Lower Tertiary is a parable of re-exploration, showing how the future of the oil and gas industry depends on using new technology to re-discover already-explored regions.
When the 57-year-old executive started his career in the 1970s, 600 feet was considered “deep water.” Shale was useless rock. Oil didn’t exist below the salt layer.
“In the span of one person’s career -- just one person’s career -- two plays that couldn’t exist according to our professors and our mentors are now some of the biggest plays in the world,” he said.
“In the end, we need all of them.”
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