ABOARD THE MAERSK DEVELOPER, GULF OF MEXICO -- Hundreds of oil platforms, many of them abandoned, dot the coastline south of Houma, La. Farther from the shore, the number dwindles to dozens, to eventually none at all.

This is where Statoil wants to go -- to the outer reaches of the U.S. continental shelf, where the industry sees huge potential for profit.

"We started to come back to the Gulf of Mexico ... in late 2003," explained William Maloney, vice president for North American production at Statoil. "The whole premise was we thought there was big potential remaining in the Gulf of Mexico that we could get at, and it was a stepwise thing."

Statoil executives recently announced an aggressive push to grow the size and scale of the energy giant over the next eight years. Though the Norwegian government is still the majority shareholder, Statoil's operating model is that of a privately held oil and gas firm -- a key difference that officials there say will make it possible for Statoil to increase its crude oil output dramatically from 1.4 billion barrels per day today to 2 billion barrels per day by 2020.

The Maersk Developer explores for oil on a Statoil lease in a zone far from its nearest neighbor, a production platform just visible on the horizon. Statoil plans to move it to even deeper waters farther offshore in a couple of months. Photo by Nathanial Gronewold.

"For us, North America is really the biggest growth area outside Norway," Statoil CEO Helge Lund told a press gathering at the annual IHS CERA Week energy conference under way in Houston.

The company expects its crude output in North America to hit 500,000 barrels a day by 2020, and though most of that share will come from unconventional oil, Lund acknowledged that hitting that target hinges on discoveries in the ultra-deep waters of the Gulf of Mexico.

The company and its drilling rig contractor both insist that they can do so safely and reliably.

That was the key point the Statoil sought to drive home by flying a small group of reporters to tour the Maersk Developer, the new high-tech semi-submersible rig that Statoil has contracted to drill its latest exploratory well at Kilchurn, a potential crude field that lies an hour's helicopter flight south of Houma.

Maersk's newest offshore rig is indeed impressive. It can operate in up to 10,000 feet of water and is capable of drilling to 40,000 feet, more than seven-and-a-half miles. The rig can take a hit by a surprise wave and get knocked around by up to 360 feet off its target and still continue to drill safely, Maersk officials say.

But despite the rig's advanced instrumentation and ability to digitally read well conditions, pressure and temperature in real time, both companies are not taking any chances in light of the 2010 disaster at the Macondo well.

Multiple redundancies are in place that make entire system failure a remote possibility. And the firms are taking extra lengths to insure themselves against the worst-case scenario, a blowout and complete loss of control.

"Our systems are completely different," said Cor Selen, CEO at Maersk Drilling USA Inc. "We are not the same as the [Deepwater] Horizon."

Focus on blowout preventer

The most notable difference, Maersk and Statoil officials noted, is the company's handling of the blowout prevention technology. That system failed to activate at the ill-fated Deepwater Horizon operation, leading to an estimated 5 million barrels of oil spilled.

Though a Maersk engineer acknowledged that the technology behind their blowout preventer is essentially the same as that used on the Deepwater Horizon, the monitoring of it is not.

Tests are undertaken daily to ensure that the equipment will function reliably if needed. And though the equipment is about five stories tall and weighs a whopping 375 tons, the firms have placed secondary controls at the wellhead, as well, in case the main blowout preventer fails.

And if that secondary equipment fails, Maersk has a third one on the Developer available for swapping out equipment if necessary. A fourth piece rests in a warehouse onshore. Such are the steps that Statoil feels are necessary to put the U.S. government and public at ease with its deepwater offshore expansion plans.

Other advancements in technology visible on the Maersk Developer show the signs of the times, as the oil and gas industry moves its activities into ever deeper waters in areas farther from shore and more isolated than before.

The ship's bridge boasts both navigational equipment and an operations monitoring center, so the rig crew can watch what the drilling crew is doing at any given time. Much of the work is automated and hands-off, reducing the physical labor involved in the process. Efficiency improvements are driven by both cost considerations and the need to enhance safety, officials said.

Kilchurn isn't even a particularly difficult project, Statoil says. The wellhead lies in 3,150 feet of water, well within the Developer's 10,000-foot depth operating range. And it lies in a geologic formation that has long been explored and understood by the industry.

But the company is going deep into it -- the plan is to hit a depth a bit greater than 25,000 feet when drilling is completed, 40 to 60 days from now. Most Gulf of Mexico drilling these days is aiming at the 25,000- to 30,000-foot range, a depth where enormous temperatures and pressures must be counteracted with specialized drilling mud that is often more valuable on a per-barrel basis than the oil itself.

Maersk Drilling's rig operators say they have run into only minor problems with Kilchurn and that drilling, a 24-hour-a-day task, is running along schedule. Next they will move to Bioko, a field that is another 40-minute helicopter flight south of Kilchurn and that lies in more than 8,000 feet of water.

Deep investment

Deepwater wells can take five to seven years from the time exploratory drilling begins to first production and cost hundreds of millions to develop. At a day rate cost of around $1 million to lease the Maersk Developer, Statoil thinks it could cost it up to $120 million or more to drill Kilchurn. And they don't even know if it will ever produce oil.

But results that they are getting all around Kilchurn are encouraging to the firm. At the Tahiti project, Statoil, alongside the main operator Chevron Corp., recently celebrated 100 million barrels of crude produced in 33 months since Tahiti came online in 2009.

"And it's still going strong," said Statoil Gulf of Mexico exploration officer Thomas Reed. "Last time I checked, it was making over 100,000 barrels a day, so that's what we call a major impact field, and that's what we're hoping to find here at Kilchurn."

Statoil says it has two rigs exploring far offshore in the Gulf of Mexico. Projects named Candy Bars, Demon Star and Coral are among others on its list.

Exploring in the Gulf is incredibly expensive, and many wells may never pay off. But when they do, they do so in a very big way.

Offshore projects net companies with stakes in them several billions of dollars and a steady stream of income that they can draw from for 20 years or more. One of Statoil's mature offshore fields in Norway has been producing crude for nearly 40 years.

Maloney said that even though they cost hundreds of millions of dollars to explore and can take up to seven years to produce oil, if ever, offshore wells are still far more profitable than the more predictable onshore shale oil exploration Statoil is undertaking in the Bakken and Eagle Ford shale fields.

Maloney said observers should expect to see many more Statoil-led projects like Kilchurn and Bioko in the Gulf over the next several years.

"We have a machine going now with permits and rigs," he said. "We are going to keep drilling exploration wells. Just because we had some dry holes doesn't mean we don't have a persistence to keep going."