BP made a potentially groundbreaking discovery in New Mexico, which could open up a new area for shale gas development.
BP was drilling in a little-known area in northern New Mexico, in a place called the Mancos Shale. The British oil giant reported huge figures from the shale gas well, suggesting the Mancos could provide a massive new source of U.S. shale gas.
The initial 30-day production rates of the new well hit 12.9 million cubic feet of gas per day, a figure that tops horizontal wells in the highly prolific Eagle Ford shale, which often see wells producing 8 to 12 million cubic feet per day. And the production figures are the highest in 14 years within the San Juan Basin, which encompasses southwest Colorado and northeast New Mexico, and includes the Mancos Shale.
“We are delighted with the initial production rate of this well,” said Dave Lawler, CEO of BP’s U.S. Lower 48 onshore business. “This result supports our strategic view that significant resource potential exists in the San Juan Basin, and gives us confidence to pursue additional development of the Mancos Shale, which we believe could become one of the leading shale plays in the U.S.” BP plans on relocating its U.S. headquarters to Denver, a sign of how important the British oil company views the Rocky Mountain region.
A USGS report from 2016 estimates that the Mancos Shale holes 66.3 trillion cubic feet of natural gas, enough to rank the Mancos as the second largest shale play in the country, just behind the Marcellus.
The impressive results come from acreage that BP acquired two years ago, in an area that at the time had no natural gas rigs in operation.
But there still plenty of hurdles for BP and any other company hoping to turn the Mancos into a major source of shale gas. First, they need to prove that the BP well was not simply a fluke. "The next test now will be showing some repeatability," said Linda Htein, senior research manager of Wood Mac's upstream research team, according to the Houston Chronicle. "Will they be able to repeat these results in another five wells? They think there's potential for scalability here."
Also, costs need to come down. David Deckelbaum, an energy analyst at Keybanc Capital Markets, told Bloomberg that the geology in the Mancos is much more complex than some more well-known shale plays. Drillers need to go deeper and drill through difficult rock formations. That means that it can cost as high as $13 to $15 million per well in the Mancos, about twice as much as typically seen in the Marcellus at $5.5 to $7 million, while the white-hot Permian Basin sees costs on the order of $8 to $10 million per well.
However, drilling in new areas is always tricky at first. Costs are high because companies are starting from scratch, learning the area, trying to figure out where the best spots to drill are. There is also a lack of infrastructure in the beginning, which keeps costs high and slows the ability to ramp up because of an inability to ship product. These things get worked out in time – costs tend to fall the more drilling activity scales up.
But the Mancos will still struggle to compete with more well-established shale gas basins. Why drill in the Mancos instead of the massively prolific and relatively cheap Marcellus Shale? Or why not drill in the Permian, where you can produce oil as well as gas? Plus, those plays have pipelines and processing facilities that make it easy to offload what a company produces.
But the gusher from BP suggests that investing in this new area could be worth the trouble.
“Given the very strong initial production rates of this well, we believe there is potential for the Mancos Shale to be a large gas play,” BP spokesman Brett Clanton told the Denver Post. “It’s still early, but based on this initial success, we will be drilling more wells in the Mancos this year.”
By Nick Cunningham of Oilprice.com
