The world’s super basins have their roots in deep time and their fruits in long-standing, prolific oil and gas production. But that doesn’t mean the industry understands them completely or knows where they all are.
One potential super basin complex in the Rocky Mountains area of the United States isn’t even officially named yet.
Located mostly in Colorado, Utah and Wyoming, bounded to the northeast by the older Williston Basin and to the west by the Sevier thrust belt, it contains numerous, present-day basins including the Powder River, Big Horn, Wind River, Green River, Uinta, Piceance and Denver basins.
“In our part of the world we don’t have a single large basin. You have this aggregate of Laramide and other-aged basins. It’s not like, for example, the Western Siberian Basin, at all,” said John Curtis.
“We have all these individual basins that contain excellent source and reservoir rock packages, but you would have to add them all up to get a super basin”-level of production, defined as 5 billion cumulative barrels of oil equivalent or more, he noted.
Curtis has worked with GeoMark Research since 1996 where he is currently responsible for U.S. and Canadian Rocky Mountain and SCOOP/STACK petroleum-system/resource-potential studies. He is also professor emeritus of geology and geological engineering at the Colorado School of Mines.
“These foreland basins, like the Western Interior Cretaceous Seaway, and the Appalachian Basin in the eastern United States, were previously thought to be deep, dark and anoxic. We’re finding out that they probably were not that deep, and not constantly anoxic. Although, there likely was restricted circulation,” said Jeff May.
“When we talk about the Powder River Basin, the Big Horn Basin, these other basins, at one time they were all connected as part of the seaway then separated from one another during the Laramide Orogeny,” he added.
May, a former chief geologist for EOG Resources, is now a Denver-based consultant and affiliate faculty member in the Department of Geology and Geological Engineering at the Colorado School of Mines.
“One thing that makes this elongate seaway so unique is that at times it was closed off to the south. The basin at that point acted almost like an extensive estuary,” May noted
“We did have restricted circulation and stratification, and another thing was that it was periodically closed and then opened to the warmer Tethys waters,” he said.
This seaway history largely defines the area and will be one focus at the upcoming AAPG 2021 Global Super Basins Leadership Conference, in presentations on the North American Cretaceous Western Interior Seaway. Curtis will discuss the Cretaceous source rocks of the Rockies, while May and other presenters will discuss the Mowry Shale.
“The Western Interior Seaway has world-class petroleum systems and large, associated hydrocarbon accumulations. The WIS session will cover examples from Canada and the U.S.,” said session chair Steve Sonnenberg, professor in petroleum geology at the Colorado School of Mines.
Niobrara and Mowry Shale Plays
In general, this Colorado-Utah-Wyoming multi-basin area has a known Niobrara Formation play and an emerging Mowry Shale play. The Niobrara notably produces in the Wattenberg Field north of Denver and also in the Silo Field in Wyoming.
“The Niobrara – because it’s shallower, for one thing – we always knew it was a potential reservoir. The Niobrara has a lot longer history of drilling and production,” May observed.
“The Mowry’s deeper. It thins and pinches out in the Denver Basin. And because it’s deeper and tighter, people were not looking at it previously as an economic shale play,” he said.
This region’s depositional character and circulation shifted as the seaway was fully open, then closed to the south, then open again – and ultimately closed – during the Cretaceous.
“The Las Animas arch to the south and other seafloor highs served as sills, partially restricting Tethyan inflow,” said May.
“When the seaway received waters from the south we got more calcareous skeletal material from foraminifera and coccolithophores,” along with the ongoing formation of organo-minerallic aggregates, he said.
“The biologists have been all over this for decades. They call it carbon rain or marine snow,” a shower of organic material falling from upper waters to the deeper ocean, May noted.
“To get the organic material to accumulate in large enough quantity to act as a hydrocarbon source you need three things,” enhanced productivity, decreased detrital dilution and enhanced preservation, he said.
Curtis said the Mowry Shale of the Rocky Mountain region is a source rock due more to enhanced preservation, while the Niobrara Formation is a source rock mainly due more to enhanced productivity.
“The Mowry Shale is just one of multiple source intervals. The (U.S. Geological Survey) has estimated the Mowry has expulsed over 1.2 billion barrels of oil and 2.2 trillion cubic feet of gas into conventional Cretaceous reservoirs. And there’s still a lot of oil and gas left in the Mowry,” May said.
According to USGS studies, there could be 200 million barrels of oil and 200 billion more cubic feet in Mowry production remaining in the Powder River Basin alone, he noted.
Curtis said GeoMark did a study in 2011 of the Niobrara and equivalents in 14 U.S. basins and the Mowry in 11 basins, and “it’s incredible what source-rock and reservoir packages were deposited there.”
“We have quite a migration story,” Curtis said. “If, for example, you look at a map of where Cretaceous-sourced oils occur in the Powder River Basin, the Lower Cretaceous oils are spread pretty much across the basin.”
“These Mowry and other Lower Cretaceous-sourced oils have migrated generally from the generative kitchen area to the east-northeast. If you look at oils from the younger Niobrara and other Upper Cretaceous source rocks, those oils generally stayed close to home, and are much closer to the postulated kitchen,” he explained.
Biomarker distributions in the organofacies of petroleum systems are often distinct in various portions of WIS basins, Curtis noted. Combined with data on isotopes, they enable oil-oil and oil-source correlations to be made with high confidence.
“On the geoscience side, geochemistry data can be mapped to really help your exploration efforts,” he said. “The carbon isotopes and biomarkers are like fingerprints that can characterize the source and migration histories of oils.”
This emerging Niobrara-Mowry super basin complex of separate basins offers multiple play possibilities, including a full range of unconventional resource opportunities.
“There are folks looking at the Piceance and the Uinta (basins), at the Mowry and Niobrara equivalents of rocks found further to the east. Things are ‘quietly active,’” Curtis said. “Right now, the Denver Julesburg and the Powder River are the two most active basins.”
“There’s always work going on in the Green River, and in the Piceance, but as you get gassier the activity slows down because of economics,” he added.
May said operators “are starting to look at a play that sits between the Mowry and the Niobrara. It’s called the Greenhorn limestone.
“There are also abundant sandstone plays – the Frontier, the Turner, the Parkman, the Shannon, the Sussex – there’s a whole series of these interfingered sandstones. They call them halo plays where we are drilling horizontal wells beyond traditional vertical production,” said May.
The term “halo” has been used because the conventional core areas are encircled by areas of lower permeability and porosity, he explained.
“We’re seeing two things happening. We’re tapping into units we used to think were too tight, i.e., low porosity and low permeability. And we’re also going into areas where people weren’t exploring much before,” May said.
One example is the North Park Basin, which “has been a minor basin, as far as exploration goes, over the decades,” he noted.
May said as a geologist at EOG Resources he was once told, “Don’t even think about drilling horizontal wells below 10,000 feet” because they would automatically be uneconomic.
In the Rockies today, “because we’ve improved our drilling economics and improved our abilities, we’re routinely landing horizontals at 12,000 feet, 13,000 feet or deeper,” he said, with wells below 13,000 feet now considered “deep” wells.
“The future lies in getting oil and gas out of deeper intervals and tighter intervals,” May said. “We’re looking at these edgy areas that we just couldn’t produce before with conventional vertical wells.”
“There’s a great deal of remaining potential. There’s no sign of peaking production in any of these Rockies basins,” Curtis noted.
“There will always be operators who can get their overhead down and go in there and get the job done. I’m very bullish on the Rockies, on these Western Interior Seaway basins,” he said.