Chevron goes to extremes in the Gulf of Mexico

The oil giant is spending billions to tap new oil fields in deepwater far offshore. Take an up-close look at how it’s done.

Jason Morehouse, 35, is wearing navy-blue coveralls. Around six feet tall, he has a buzzcut under his hardhat and a thick goatee that extends about two inches below his chin. At the moment he’s giving me a tour of Tahiti—not the Polynesian island, but a $2.7 billion Chevron oil production platform about 190 miles south of New Orleans. Tahiti sits in more than 4,000 feet of water and is a modern marvel of engineering. When it began producing oil in 2009, it was a pretty big deal for the company. Still is, in fact. Jack, however, is gargantuan.

“I haven’t been out there,” says Morehouse, who is clearly pumped about Tahiti’s younger and much bigger sibling. “I’d really like to get a look at it.”

Morehouse is the operations supervisor on Tahiti, which means he’s in charge of making sure that the floating industrial complex efficiently and safely produces some 34,000 barrels of oil and 14 million cubic feet of natural gas per day. It’s a serious responsibility—and one he embraces with gusto. (“I gotta warn you,” he says, “I get pretty excited about all of this stuff,” before launching into an inspired discourse about high-pressure and low-pressure separator tanks.)

When I ask him if he’d like his next assignment to be on Jack, he displays admirable loyalty to his own floating home. “Being on Tahiti is just as exciting,” says Morehouse. “Some of what they’re doing at Jack is more advanced, and some of what we’re doing is more cutting-edge.”

It’s a perfectly rational and diplomatic answer. But I hear it there—a tinge of envy in his voice.

After all, the Jack/St. Malo (to give its full name) platform is the newest, biggest thing going for Chevron, No. 3 on this year’s Fortune 500 list, with $220 billion in revenues, in the Gulf of Mexico. In fact, it’s the largest structure of its kind in the Gulf, period. The $7.5 billion floating production facility has a displacement of 160,000 metric tons and is designed to process oil and gas drawn from wells in two separate fields—Jack and St. Malo—that are as deep as 29,000 feet below sea level. Utilizing some 480,000 total feet of pipe, the platform will be able to process up to 177,000 barrels per day of hydrocarbons. (In the oil industry the term “platform” is used for structures that pull and process oil from wells, whereas a “rig” is used for those that drill.) Jack/St. Malo sits in 7,000 feet of water, and is located roughly 90 miles south of Tahiti—significantly farther out into the Gulf. It’s the frontier.

Jack is also symbolic of the big bet that the company is making in the Gulf of Mexico on production in deepwater—defined by Chevron CVX 0.14% as more than 1,000 feet—as a growth driver for years to come. In addition to Jack, which should begin producing oil by the end of 2014, Chevron is prepping a slightly smaller cousin, a $5.1 billion platform called Big Foot, to begin production in 2015. It also has a 42.9% stake in Hess’s HES 0.84% $2.3 billion Tubular Bells deepwater development, which should start producing oil this year. The model for major oil and gas projects is typically for one company with a majority stake to take the lead, but to share the investment costs with two or three of its peers. For instance, Chevron holds a 50% stake in the Jack field and 51% of the St. Malo reservoir, with stakeholders such as Petrobras of Brazil and Norway’s Statoil sharing in the projects.

To be sure, the Gulf of Mexico is hardly the only offshore area where Chevron is investing heavily. It operates in deepwater off the west coast of Africa and in Brazil, for instance. And its biggest capital investments by far are in a pair of projects off the northwestern coast of Australia. The cost of its Gorgon liquefied natural gas mega-project, originally budgeted at $37 billion and scheduled to begin producing gas in 2015, has risen to $54 billion. (Chevron is the lead developer, with a 47.3% stake, and is sharing the investment with Exxon Mobil XOM -0.08% and Shell, among others.) The nearby Wheatstone LNG development has a price tag of $29 billion and will begin producing gas in 2016.

Those two projects are crucial to Chevron’s future. But developing previously unreachable portions of the Gulf of Mexico not only gives the company a way to replace declining reserves elsewhere but also serves as a way to hone techniques it can export to other parts of the world. “Chevron has specifically identified deepwater as one of its key technological areas of expertise,” says Pavel Molchanov, an oil industry analyst with Raymond James.

Chevron’s big push into deeper water in the Gulf is also emblematic of a broader comeback for oil and gas development in the region after BP’s horrific Deepwater Horizon accident in April 2010, in which an explosion killed 11 workers and led to one of the largest oil spills in history. A government-imposed drilling moratorium afterward had a chilling effect on production in the Gulf of Mexico. But investment is on the rise and the Gulf is set to surge.

The unexpected boom in onshore oil and gas production driven by development of shale-drilling techniques has deservedly dominated the energy story in the U.S. over the past several years. However, deepwater production in the Gulf may be poised to grow at a faster rate going forward. According to analyst Molchanov of Raymond James, onshore production in the U.S. grew at an annual rate of 4.7% for the five years through 2012, while production in the Gulf of Mexico actually shrank during the same period. But Molchanov estimates that from 2012 to 2020, offshore production in the Gulf, mainly from deepwater, will grow 8.3% per year, vs. 6.1% for onshore oil and gas. And Chevron will be one of the biggest beneficiaries. “Chevron could easily double production [in the Gulf] by 2020,” says Molchanov.

To learn more about how the oil major is making this push, I recently took a trip down to the Gulf for an up-close look. My first stop was the Kiewit shipyard in Ingleside, Texas, where Chevron’s Big Foot platform was in the process of being assembled and tested, and where Jack was housed for final fabrication before it was towed out and put in position in the Gulf recently to begin the monthslong process of readying it for production.

As I drove over the causeway from Corpus Christi to Ingleside on a cloudy Tuesday morning, I could see Big Foot’s gargantuan profile across the bay. It was the largest structure in view. Turns out, it’s even more awe-inspiringly large when you get near it. The platform is some 500 feet from the top of its flare boom to the bottom of its four-legged hull, and houses an onboard power plant that could support a small city. Sitting in the water, it’s roughly the height of a 30-story building, and each deck has the dimensions of a football field. The hull was built in Korea and arrived in Ingleside in March 2013 after a two-month sea voyage. But that was just the beginning of the assembly process.

At the shipyard, operated by the employee-owned industrial giant Peter Kiewit—No. 236 on this year’s Fortune 500, with $11.8 billion in revenues—there are some 1,600 Kiewit workers and subcontractors dedicated to the Big Foot project, plus around 300 Chevron employees. (On any given day there are 240,000 people working for Chevron globally, and only about 60,000 of them are employees.) The topside living quarters and processing equipment were built in the U.S. and installed on the hull at the Kiewit yard.

Big Foot is what’s known as a “tension leg” platform, and in the yard there are more than 16 miles of pipes, or “tendons,” which will serve as the legs and will be used to secure and stabilize the platform in water more than 5,000 feet deep. Most of the work of attaching the tendons to the ocean floor and connecting the wells must be done by underwater robots called remotely operated vehicles, or ROVs. Nothing about pulling oil and gas out of reservoirs buried thousands of feet below the ocean floor is simple or small-scale.

Around 7 a.m. a couple of days after visiting the shipyard, I boarded an AgustaWestland AW139 helicopter owned by Chevron in New Orleans for the ride out to Tahiti and Jack/St. Malo. Helicopters are an essential logistical element of offshore oil production. Workers on the deepwater platforms typically work 14 days on and 14 off, with the shifts staggered by groups. So there are always employees to ferry back and forth.

Chevron maintains its own fleet of 32 helicopters and one fixed-wing amphibious plane in the Gulf. “We have our own air force,” says Steve Thurston, the head of Chevron’s deepwater exploration and projects unit, known within the company as DWEP. To meet its growing capacity needs for trips out to the far-off platforms like Jack, the company recently ordered some new Sikorsky helicopters that seat up to 19 passengers each.

After a stopover at Chevron’s shore base in Leeville, La., to pick up extra fuel and fix a minor mechanical issue, we embarked on the roughly one-hour flight from the coast to the Tahiti platform. It’s a commute that offers plenty of time to be alone with your thoughts—or doze. There’s not much to look at below other than the mesmerizing shimmer of sunlight on the crystal-blue ocean water and the occasional streaks of algae.

We stopped at Tahiti to take on more fuel, then took off again and flew out to Jack/St. Malo, arriving just before noon. The helicopter circled for a while, but we didn’t land on either of Jack’s two helipads. Chevron has some 500 people working to get Jack operational by the end of the year. During the setup, the workers live on a hotel ship, or “floatel,” that is anchored next to the platform. To report for work, they walk across a gangway. After about 20 minutes of circling, we flew back to Tahiti, landed, and had lunch. Then I got my tour from Jason Morehouse.

Morehouse went to college at Auburn University and got a Ph.D. in engineering at the University of Texas. He has a pair of Auburn stickers on his hardhat and describes his arrangement with Texas as “purely a business relationship” and nothing more. “When it comes to sports,” he says, “my loyalty is to Auburn.” He also seems to have a genuine passion for his work. He spent time working as an engineer for Chevron onshore before he was given the “rare opportunity” to work on the platform. “The day that I found out I was going to Tahiti was one of the most exciting of my life,” he says, and seems to mean it. During his 14-day shifts, says Morehouse, he tends to work 16 or 17 hours per day.

One key to the new development of deepwater fields such as Tahiti and Jack is advanced seismic imaging technology, which makes it possible to “see” through a layer of salt in the earth’s crust that used to obscure the view for exploration geologists. The Tahiti reservoir, for instance, is buried at a depth of 23,000 to 28,000 feet and lies beneath a salt canopy that is up to 15,000 feet thick.

To keep Tahiti working smoothly—its production was at 99.2% of full capacity in 2013, Morehouse proudly informs me—the facility has a crew of roughly 180, about half of whom are on board at a time, including a small army of electricians, mechanics, and contractors, who are on a 24/7 schedule of maintenance work. “It’s a big platform, but it’s still a tight-knit group,” says Morehouse.

The oil from Tahiti comes out of the well hot, Morehouse tells me, reaching the platform at around 145 degrees Fahrenheit. It gets heated up even more, to around 170 degrees, because that makes it easier to separate the oil, gas, and water. Five years after it went operational, the platform is still adding capacity. It may not be quite as huge as Jack, but in the brave new world of deepwater oil, it’s definitely still a pretty big deal.

But Molchanov estimates that from 2012 to 2020, offshore production in the Gulf, mainly from deepwater, will grow 8.3% per year, vs. 6.1% for onshore oil and gas.
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The EIA is already forecasting about 1 million barrels@ day growth in US oil production for 2014-2015. And then a flat growth pattern afterwards.

So I wonder if those percentages are front loaded so most of the gains are in 2014-2015.

Any ideas as to how that translates into barrels per day?

We already saw that Eagle Ford while slowed down considerably is now expected to still put in 100,000 barrel @ day increases each year for 2016-2020.

Also, the Bakken while slowed considerably is expected to raise its production in 2016-2020. By an amount I’ve since forgotten. But I recall seeing the revised estimates.

1.33 MMBPD x 8.3% = 0.11 MMBPD
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a little over 100,000 barrels @ day. So those numbers are about right.

Likely the 75k permian basin and 75k for the rest of the USA will probably be low. maybe by a lot.

I added up the eia production increases 2013-2014 for the oil fields in oklahoma, colorado, wyoming, and utah. together they came in at roughly 130,000 barrels@ day. Utah and Wyoming are just getting started. Hard to say what the numbers will be 2016-2020.

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