Can the United States expect to add another big resource to future natural gas supply?
The U.S. Geological Survey has launched a new assessment of technically recoverable hydrocarbon resources in the Arkoma Basin of Arkansas and Oklahoma.
The overall numbers are likely to move upward with the addition of unconventional prospects. That’s no surprise.
But when the final assessment results are released, probably late next year, will the total size of the available resource lift some eyebrows?
The Arkoma Basin – long known for its large conventional gas accumulations – has become a hot spot for unconventional drilling in recent years.
“When the USGS last assessed the Arkoma region in 1995, coalbed gas was the only continuous resource assessed because shale gas was not yet on the radar screen,” said AAPG member Dave Houseknecht, task chief for the Arkoma assessment and geologist for the USGS in Reston, Va.
“Today, the Fayetteville play in Arkansas and the Woodford play in Oklahoma are among the most active shale-gas plays in the U.S.,” he noted.
Now the USGS is contemplating another major, unconventional, tight-sands gas play in the foreland basin of the Arkoma.
“There is growing evidence that the deep part of the basin, the Arkoma-Ouachita foredeep, may be a continuous, basin-centered gas accumulation with tight sandstone reservoirs,” Houseknecht said.
“So, the USGS is proposing to assess the deep basin as a continuous resource, rather than a set of conventional accumulations,” he added.
Bottom line: That should mean an assessment result of more mid-continent natural gas available using today’s technologies.
The independent Potential Gas Committee acknowledged growth in the nation’s available gas resource last summer, when it issued a resource-base estimate of 1,836 trillion cubic feet – highest in the committee’s 44-year history.
Three years from now, will that evaluation look strangely conservative? It might: Mid-continent gas chances should get another upgrade when the USGS issues results for a new Anadarko Basin assessment, which will follow the Arkoma evaluation.
Like the Arkoma, the Anadarko Basin has its own range of unconventional prospects, including the emerging Cana-Woodford shale play.
Houseknecht has an extensive background in the Arkoma. He was a professor at the University of Missouri for 14 years and worked the area heavily.
During much of the Paleozoic, the Arkoma region was a passive, south-facing margin, he noted. However, as the Ouachita orogenic belt loaded that margin during the Late Mississippian through Atokan, the shelf was broken down progressively northward, forming a foredeep.
“This foredeep was truly a basin that was being filled by sediment off the Ouachita Orogeny Belt,” he said.
An intriguing aspect of the Arkoma is its high level of thermal maturity. Existing, high-quality reservoir petrography gives an insight into the basin’s history and its current state, Houseknecht said.
“We knew from that there had been conventional accumulations with their water legs destroyed by thermal maturation,” he noted.
“The data verified that, in this deep area, wells never encounter water and you either have porosity filled with gas or no porosity,” he said.
A long history of drilling in the Arkoma also helped to define the nature of the foredeep, which contains channelized turbidites at depth.
“As long as you hit these channel sands you still encounter gas very low on the structure, with no water. And almost all of these structural accumulations were tested decades ago,” he said.
If these indications do represent a basin-centered, continuous gas play, future drilling in the Arkoma’s known productive area is more likely to be successful.
“Assessing the foreland basin as a continuous accumulation with tight reservoirs provides the potential for a much greater possibility of development,” Houseknecht observed.
Interest in the Arkoma has waxed and waned over the past decades, but has never fallen off the exploration map. The basin is drawing renewed attention today.
“This is due to aggressive development of continuous or unconventional resources, including shale gas and coalbed gas and innovative approaches to enhanced development of gas resources in tight sandstone reservoirs,” Houseknecht said.
“It also reflects continued success in finding new, though generally small, gas fields in the frontal thrustbelt of the Ouachita Mountains and in the old fairway along the northern margin of the basin,” he added.
Many mid-continent operators have a good understanding of the Arkoma and the Ouachita belt area. The USGS has invited companies to share their knowledge and to comment on the resource evaluation.
“We have visited with the Arkansas and Oklahoma geological surveys and with several production companies active in the basin to seek feedback,” Houseknecht said.
It also conducted a one-day presentation in Norman, Okla., about the Arkoma assessment, hosted by the Oklahoma Geological Survey in early November.
“That was really an important part of this whole process,” noted AAPG member Stan Paxton, hydrologic studies chief for the USGS in Oklahoma City and a member of the assessment team.
“It was free, open to the public, and we had 175 people,” he said. “The OGS did a great job of running that workshop and we got a lot of feedback.”
Paxton adds to the team his regional understanding and helps evaluate the resource potential of the Arkoma’s shale-gas plays. He said the approach begins with analyzing shale outcrops.
“We’ve got one location where we have 230 feet of the Woodford Shale – it’s probably the only place where you get to see the whole Woodford at once,” he said.
That analysis will include spectral gamma-ray readings, vitrinite reflectivity, mineralogical studies and X-ray diffraction, assisted by the USGS lab in Denver.
“We’ve been trying to put together a database that represents the properties of the shales found in the Arkoma Basin,” Paxton explained.
“There are only a couple of companies that are putting a big effort into understanding the nature of these shales,” he said, “at least publicly.”
Across the Border
Key to the results is a grasp of the Woodford Shale in Oklahoma and the Fayetteville Shale in Arkansas, and their equivalents. Comparisons can be tricky.
“The mineralogy of the two shales is really quite different. Everybody in the industry knows this: A shale is not just ‘a shale,’” Paxton said.
“It’s difficult with the stratigraphic complexities to equate the Fayetteville Shale in Arkansas to the Caney (Shale in Oklahoma) as well as you’d like,” he added.
Houseknecht noted the importance of, and the difficulties involved in, understanding the nature of these shales in both sides of the Arkoma.
“One of the big shale-gas questions that we, and industry, are struggling with involves the laterally equivalent shales on either side of the border,” he observed.
“In Oklahoma, the Woodford Shale is a good producer but there have been very few tests of the Chattanooga Shale in Arkansas,” he said. “Does the Chattanooga have potential in Arkansas similar to that of the Woodford in Oklahoma?”
And the same holds true for the extent of Fayetteville-Caney-aged shales across the basin.
“The role is reversed in the younger shale formations,” Houseknecht noted. “In Arkansas, the Fayetteville is a good producer but the Caney does not seem to have the same potential, even though numerous wells have tested it – and, it is producing in a number of wells.
“So, does the Caney have more widespread potential in Oklahoma?” he asked. “And how does that potential compare to the Fayetteville?”
Looking for Clues
Paxton identified a number of challenges involved in assessing the potential of the Arkoma’s shale-gas plays, questions that will have to be addressed – though not necessarily resolved – before the final numbers are issued.
“The biggest challenge, believe it or not, is having detailed paleontology data we can tie to the analysis, especially the gamma-ray results,” he said.
Another question mark involves the helpfulness of existing production data. Shale gas has been talked about for quite a while, so it’s easy to forget how new shale-gas plays really are. There is little long-term record of shale production, anywhere.
“The production history can help us with short-term projections, but for longer term projections we don’t have a lot to stand on right now. A special challenge is having enough long-term production history to be confident in our EURs,” Paxton said.
Beyond that, he commented, “it’s a very exciting time to be looking at shales and finding out what they tell us about the geology. Because of the economic incentive, we’ve got a new pair of glasses on.”
A good understanding of shales in the Arkoma can help the USGS evaluate the potential of other shale-gas plays.
“The big question,” Houseknecht said, “for both the older Woodford-Chattanooga and younger Fayetteville-Caney is: Does productivity potential decline with increasing thermal maturity and depth of burial?
“This question is not only being asked by industry for these formations, but also for similar shale-gas formations in other basins, including the Marcellus in the Appalachian Basin and the Barnett in the Fort Worth Basin,” he noted.
And because of its history, the Arkoma “is a basin we believe can be studied and used as an analogue for evaluating other high-thermal maturity basins elsewhere in the world,” he said.
How much recoverable natural gas does the Arkoma Basin hold? Inevitably, today’s assessment will give way to the capabilities of tomorrow.
“As technology improves,” Paxton noted, “there’s always more out there.”