The majors have abandoned the Gulf of Mexico shelf in recent years like rats from a sinking ship. But intriguing targets below 15,000 ft (4,575 m) and the promise of royalty relief are bringing them back.
In 1979 the US Congress, in an effort to decrease that country's dependence on foreign imports, enacted the Section 29 Federal Tax Credit bill. The credits, applied to qualified fuels such as oil shale and tight gas, resulted in a US $60 billion investment made in the recovery of coalbed methane, with gas production from alternative sources peaking between 1989 and 1994.
The perceived threat is not dependence on imports (though that dependence has steadily grown) but tightening gas supplies. There have been a few alarm bells. The National Petroleum Council (NPC) released a study warning that the United States would need 30 Tcf of gas a year to feed its ravenous appetite for energy by the year 2010. Current demand is about 22 Tcf, and states like California already are suffering electricity shortages due to gas supply disruptions.
Where is all of this gas going to come from? The US Minerals Management Service (MMS) is looking to the Gulf of Mexico to continue to supply the country with much of its gas. "If you look at the Gulf of Mexico and immediately adjacent production onshore, it's 50% of the daily gas production in the US," said Andy Hardiman, vice president of Chevron's deepwater business unit in the Gulf. "But the Gulf is a treadmill. It's characterized by fast gas." He added that recent data indicates most of the Gulf's daily production comes from wells that are less than 3 years old.
It's no secret the production curve in the Gulf is not pointing in the same direction as might be hoped to ramp up to 30 Tcf in 9 years. Chris Oynes, MMS regional director for the Gulf of Mexico, said total production in the shallow waters of the Gulf has been declining rapidly, 13% for 1997 through 1999, and probably even faster in 2000. "Deepwater gas is the only thing holding production steady, and we need more," he said.
The NPC study, in fact, spurred the MMS to examine its options. As managers of the nation's natural resources, the agency felt compelled to find the supply to meet the anticipated demand. But the Gulf of Mexico is picked over, isn't it? Even deepwater leases are being gobbled up at such a rate that there's not a whole lot left. And everyone knows the Shelf is dead. Or is it?
Look deeper
In 1998, Shell drilled a well to 17,500 ft (5,300 m) in the Brazos area of the Western Gulf with peak production at 87 MMcf/d of gas and average production at 65.8 MMcf/d for 32 days. The well was lost due to high-temperature, high-pressure (HT/HP) problems, but the company has plans to redrill it.
Nor was Shell the only company to take another look at deep structures on the Shelf. Seismic contractors had long been aware of the potential for deeper exploration in the area, particularly since newer processing techniques recently have enabled them to image structures far below the original zones of interest.
"We've shot 2-D in this area for years, and when we examined the data in areas like West Cameron and High Island, we could identify overpressure at about 2.8 seconds below which resolution was poor," said Marc Lawrence, senior vice president and division manager at Fairfield Industries. "When we reshot it with 3-D, without even using larger airgun arrays, we now could easily resolve deep structures not previously seen."
The threat of the impending supply shortage coupled with the awareness of a potential deep bonanza spurred the MMS to issue a royalty relief notice for the March Central Gulf lease sale. While only new leases are covered in this particular notice, the MMS hopes to issue similar notices for other lease sales and is examining the possibility of offering royalty relief for acreage already leased, encouraging companies with shallower production to look deeper. (See p. 52 for royalty relief details.)
Geology
To understand the deeper geology of the shelf region, one need merely to look to the modern-day deep water and know the Gulf's geologic history, said Jeff Brame, chief geoscientist for Brame Geoscience. "Where the Shelf is now, 5 million years ago it was the slope," he said. "It was not in 200 ft (61 m) of water; it was in 2,000 ft (610 m) of water. The shelf margin and shelf sediments just moved basinward and buried the older slope sediments."
Studying the modern deepwater sediments has provided Brame with a nice analog for these buried slope petroleum traps, which sometimes are more difficult to image due to shallow salt and other problems. "To model slope geology and trapping styles, I prefer to look in today's deep water, where there's nothing that's covering the slope sediments except water, and that's easy to see through with seismic data. Then I apply that information to the deep modern shelf, where the advantage of the buried slope play is that you can access the lucrative deepwater style of play in only 0 to 600 ft (183 m) of water."
Brame consults clients on play concepts in the Gulf, and this one is his favorite. "I do think it's the next hot play in the Gulf," he said. "I don't think a lot of people are prepared for it. But it's not due to a lack of technology, because we've got the technology to do all of this. It's more a lack of widespread knowledge and acceptance of the buried slope play concept."
Economics
Many companies have had some interest in examining these deeper targets for several years. But a variety of constraints have held them back. For one thing, shallower targets on the shelf and bigger targets in the deep water have kept everyone busy for the past few years. Additionally, the risky nature of these wells, most of which will come with the same HT/HP headaches as their deep onshore cousins, was not the type of adventure most companies sought during the most recent downturn when gas sold for less than $2/Mcf.
These hurdles are rapidly diminishing. Shallower shelf targets have all but vanished, and deepwater leases are no longer the low-hanging fruit of a couple of years ago. The wells still pose considerable risk, but onshore deep drilling has taught the industry a thing or two about deep gas prospects. And with gas prices well above $5 on a regular basis, the economics have started to look more attractive.
Still, these wells will be expensive, and operators will look to a variety of sources to help defray the cost and risk, including royalty relief and industry partners. "You're probably looking at a one-in-six or one-in-eight type of geologic risk for these deep plays," Hardiman said. "When you add commercial risk on to it, that takes you to one in 10 or one in 12. To find something that would be meaningful, you need larger field sizes. Once you're on the commercial curve, you need to know the distribution of commercial discoveries. And you have to multiply by another risk factor.
"That would probably take you to the one-in-20 or one-in-25 risk factor, to actually find something meaningful to the company and meaningful to the gas supply, where you could find a series of 50 million-bbl fields."
Independents, who hold most of the leases on the Shelf, will no doubt seek partners to distribute the risk. Majors are more likely to have the deep pockets for these deep wells, but they'll need to justify spending the money on the Shelf rather than in the deep water or somewhere else in the world. Brame thinks the economics of the deep Shelf play hold up.
"Companies that understand the buried slope concept are going to come back to the Shelf knowing they won't find 200-million-bbl fields, but they don't need to because of the water depth," he said. "If you look at a certain rate of return, 50 million bbl will make you more money in the shallow water than 200 million bbl will in deep water."
Seismic advances
Most seismic data brokers are in the process of repackaging their Shelf data with an eye toward the deeper horizons. This is not a trivial task.
"We've gone back and reprocessed a large number of individual 3-D surveys, transformed them into one survey and created one contiguous regional coverage on the shelf," said Patrick Ng, manager of WesternGeco's North and South America multiclient library. "There's a lot of streamer data that's been acquired over the years, but the surveys have been shot in different configurations or orientations. Now we have one complete reprocessed regional coverage with the same bin size."
One of the most important reprocessing tools for this work is prestack depth migration, which helps place structures and anomalies more accurately in depth. Cost-prohibitive just a few years ago, this process is becoming almost routine and is often offered as a derivative product for seismic datasets.
"Prestack imaging is almost a parallel to what we observed a few years ago when we started from 3-D and then added dip move-out and other special processing technology," Ng said. "But this time the value of prestack imaging, when compared to the previous product, is like a different operating system - it's a step change vs. being merely an incremental improvement."
Most contractors agree it's too early to push ahead on plans to shoot new data. While sudden interest in an area often creates near-panic among seismic contractors (think Brazil in 1999), this area has been shot so many times, and some of the data is recent enough, that blanket spec surveys are unlikely.
"We really need an oil company to drill one of these deep wells successfully," said Karen El-Tawil, vice president of sales for TGS-Nopec. "Then everybody might start reshooting the data."
Drilling challenges
All of the play concepts and high-resolution seismic images in the world won't do much good if there are no rigs capable of drilling to these depths. Luckily, drilling contractors have been mindful of these challenges and have begun building new, premium-class rigs and upgrading their current rigs.
Still, not many are available. While a jackup rig can manage the shallower water depths on the Shelf, much of the equipment on the deck of that jackup is likely to be substandard when it comes to drilling deep wells. Rowan Drilling recently did a break-down of costs needed to upgrade a standard jackup and listed 16 items that would need attention, everything from adding engines and generators to extending the derrick and cantilever. Total cost for the overhaul was estimated at $37 million. An additional $18 million would be lost in day rates while the rig was in the shipyard being upgraded.
"Whenever people talk about royalty suspensions, critics tend to talk about corporate welfare and giving companies a free ride," said Paul Kelly, senior vice president of special projects for Rowan. "But what we are trying to demonstrate is that if the drilling contractors are going to have to do these upgrades, we're going to have to be paid for them. Our costs to the operator are going to be higher as well as all of the things that the operators are going to have to do from a technical, engineering and equipment standpoint."
Not all rigs will need to be overhauled. Rowan has been building Gorilla class rigs partially in anticipation of a trend to drill deeper wells. They are large, high-horsepower, HP/HT drilling units designed to operate in hostile environments.
Chiles Offshore has three Le Tourneau Super 116 jackups working. While they are not as large as the Gorilla class units, they were purpose-built for HP/HT wells. The rigs were ordered in 1997 and are the only new jackups built specifically for Gulf of Mexico operations. They can readily drill 18,000 ft to 22,000 ft (5,500 m to 6,700 m), saving considerable time for the operator.
While contractors certainly want to meet demand with rig supply, the cost and the risk of the play make it unlikely that HP/HT wells will cause a tight market in the near term. "This play won't take off instantaneously because the wells are so expensive," said Bill Plamondon, vice president of marketing and sales for Chiles Offshore. "If you are drilling to 18,000 ft to 22,000 ft, you are talking $15 million to $20 million wells. Not a whole lot of companies are able to do that." Certain operators allocate a portion of their E&P budgets, perhaps 10% to 20%, to exploratory drilling, he said, and new discoveries will be the driving force for exploration activity.
As with any other hot play, the deep Shelf is just one big discovery away from being front-page news. That well already may have been drilled. Shell drilled a well in High Island in late 2000, and as of press time details were not available. It also made its presence felt in the 2000 Western Gulf lease sale, jumping back up on the Shelf in a big way. Nor is Shell a maverick in this game. Seismic contractors are seeing plenty of renewed interest in the area from other operators, and the MMS apparently has had enough positive feedback to not only offer royalty relief for the Central Gulf leases but to consider it for other areas as well.
If the economics hold out, the play could go a long way toward helping the country meet its 30 Tcf goal. "It's the single most important gas supply issue in my mind in the US," Hardiman said. "How do you maintain production? If you can't maintain it, you've got a serious problem. If you don't like $6 gas, you're going to hate $12 gas."