With conventional natural gas supply from the Gulf of Mexico (GOM) and other traditional U.S. basins drying up and widespread liquefied natural gas (LNG) access still a question mark, the GOM ultra-deep shelf play is the wild card that could help to pick up some of the slack in domestic supplies, according to Matthew Anstead, an analyst with Wood Mackenzie.
But it's a long shot, in that potential resources so far are speculative and the technology to produce from ultra-deep wells -- deeper than 25,000 feet -- currently doesn't exist. In an upcoming study tentatively titled "GOM Deep Shelf 2004," Wood Mackenzie's Upstream Research group said multiple 1-4 Tcf sized fields could be highly profitable for producers who are willing to take the risk on the virtually unknown.
"It's a very exciting play, but there is just so little information as there has been no real success as of yet," Anstead told NGI. "Assuming it does come off -- and you're talking about the possibility of multiple 1-4 Tcf sized fields -- it could absolutely transform the Gulf of Mexico shelf and take the pressure off of this supply issue the U.S. is facing. However, it's still the early days. I still think it is going to be a few years yet until we fully understand the ultra-deep shelf."
In an effort to increase deep gas and oil production, the Minerals Management Service (MMS) published a proposed rule in February in the Federal Register that would give increased drilling time to leaseholders who plan to drill ultra-deep wells.
As for the estimated amount of reserves in the ultra-deep shelf, Anstead said they cover a wide range. "We have heard the prospect sizes are in the range of 250 Bcf up to 8 Tcf, with an average of around 1 Tcf," he said. "We do our economics on a base case of 1 Tcf up to about 4 Tcf because we think maybe that 8 Tcf is pretty 'blue sky stuff.' Nobody has found a 1 Tcf field in the ultra-deep shelf, so it is still speculation. These things have to be pretty chunky in order for companies to...spend that sort of money on something that has a chance of success."
Anstead noted that the ultra-deep shelf report is actually a small component of a larger study, which the company is hoping to publish in May or June. While the study is very speculative right now, the analyst said that when finished, it will be a highly detailed bottom-up view of the ultra-deep shelf.
"Just like with conventional deep shelf plays, we are most interested in the economics of the ultra-deep shelf play and how particular companies are getting on relative to each other," he said. "The ultra-deep shelf is very much in its early stages. There have been very few wells that have been drilled."
Anstead said the Upstream group has run some economic models to try to understand the realities of what the prospects need to deliver in order for them to be economically viable. "Obviously, we are taking into account what we think are the levels of risk that the companies who are involved in the ultra-deep shelf are taking and from that, we have some ideas of what the wells cost to drill and we are able to develop a story."
The analyst highlighted the Blackbeard West ultra-deep shelf prospect, which is currently being drilled to 32,000-35,000 feet by ExxonMobil in the Newfield Treasure Island play. "That potentially, as we understand it, is a well that could cost as much as $100 million," he said.
Anstead noted that the first well is likely going to take a year to drill, and there will likely be the need for "three, four or five wells like that" to fully test the play, or maybe more. "So we are talking about a pretty significant lead time until we have concrete information about the ultra-deep shelf and whether it is going to deliver on the promises that everyone has speculated about," he said.
Because of the sizeable costs associated with getting deep gas to market, Anstead said only the largest companies can afford to take the risk. "That's absolutely the case," Anstead said, noting that there are also other hurdles.
He added that one of the interesting things about participants in the area has been the recent exits. "Shell and BP have both recently effectively exited the shelf," the analyst noted. "They saw it as noncore and as a declining basin. One that didn't stack up versus their economic threshold. Now all of the sudden, if there is success in the ultra-deep, they have put themselves in a bit of a tricky position because it is going to cost them quite a lot of money to get back in. Whereas if you look at companies like Apache and ChevronTexaco, who are major interest holders in the GOM shelf, they can afford to sit back a little bit and see what happens."
Another interesting sidebar on the ultra-deep shelf is the technology aspect, Anstead said. "While these things might take a year to drill, even if companies were able to find something, it would be a few years before the technology would be available to produce it." The analyst noted that because of the depth, producers will need to be able to deal with high temperatures and high pressures. "The downhole equipment needed doesn't exist yet, so it has to be built and tested before it can be installed," Anstead said. "We imagine that if they were to spot something today, it would take a year to drill it and then possibly another year to two years to bring it on."
From the base case economics that Wood Mackenzie has run, Anstead said ultra-deep prospects might require $100 million for the exploration well and $60 million for each additional well. "If we run the numbers on that, it looks like a payback period of about five-and-a-half years and a break-even gas price of about $1.40/Mcf." However, he noted that this was for a single development if a Tcf in reserves was found, not full-cycle economics. "Full-cycle, that number is very much higher."
Anstead said the questions of how much deliverability will there be from the wells and the size of the prospects are more important to the economics than the actual well costs themselves, the lead times and the technology. "That's the stuff that people don't know anything about," he said.
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