Deepwater explorer Kerr-McGee is hoping next year to drill its first exploration well into the geologically deep Eocene or lower tertiary trend, among the hottest plays in deeper waters of the Gulf of Mexico.
“Possibly next year you’ll start seeing some wells showing up on our schedule in that play type,” David Hager, Kerr-McGee’s senior vice president of exploration and production, said March 25 at the UBS Global Oil & Gas Conference in Austin, Texas.
However, Oklahoma-based independent Kerr-McGee has no intention of placing all its bets on the promising but risky lower tertiary, located roughly 28,000 feet below sea level in water depths ranging up to 10,000 feet.
“We think it’s appropriate from a risk-reduction strategy to not have all of our prospects in any one play type, because history tells us that some of these play types work and some don’t,” Hager said. “So we think it’s appropriate to have exposure to multiple plays from a geological perspective in deepwater Gulf.”
Nevertheless, the lure of potential elephant-size oil fields is just too much for Kerr-McGee to resist, despite the cost of exploration wells that can run up to $50 million and more a pop.
“We’re interested in that play (and) think it is a viable play,” Hager said. “We have a presence in that play (but) we’ve not drilled any prospects yet. We’re doing processing around some of those right now.”
Lower tertiary discoveries remote
Thus far, notable lower tertiary discoveries include Great White in Alaminos Canyon and St. Malo, Cascade, Chinook and Jack in Walker Ridge. Shell recently announced a discovery at its seven-block Stones prospect, located between St. Malo and Cascade.
However, current lower tertiary discoveries are all located in remote areas of “ultra-deepwater” Gulf, where currently there are no pipelines or other transportation system to carry oil or natural gas to market.
Hager suggested that many deepwater operators, which apparently include Kerr-McGee, would like to see a production flow test from one of the lower tertiary discoveries before jumping into the frying pan.
Production flow tests are rarely conducted in the deepwater Gulf of Mexico because of the expense and the time it takes to prepare them. The test alone can run $30 million. Instead, industry generally relies on sophisticated seismic technology and downhole tools for readings on fluids, pressures and other reservoir characteristics.
Nonetheless, just to be sure, “I think we will see a test out there in the not too distant future,” Hager said. “That’s going to be a very important piece of data to see how the wells will perform. Everybody wants to see a test out there.”
In fact, at least one player in the lower tertiary — independent Devon Energy — has openly discussed the possibility of conducting a production test on one of the discoveries in Walker Ridge.
“It’s an important step but also quite expensive,” Devon President John Richels told investors last September. “But we need to see a production test and that’s something we’re moving towards doing.”
