You can’t accuse the U.S. oil and gas industry of conventional thinking.
Unconventional resource plays are sprouting up across the country, especially projects in search of gas or oil production from shale.
To track these new shale plays, you have to look beyond the Barnett shale in the Fort Worth Basin and farther than the Fayetteville in the Arkoma Basin.
- The Devonian shale in the Appalachian Basin.
- The Mowry shale in the Powder River Basin.
- The Mancos shale in the Uinta Basin.
- The Woodford shale in the Ardmore Basin.
- A Floyd/Neal shale play in the Black Warrior Basin.
- The Barnett shale in the Permian Basin.
- The New Albany shale in the Illinois Basin.
- The Pearsall shale in the Maverick Basin.
- The Chattanooga shale in Arkansas and Tennessee.
- The Hovenweep shale in the Paradox Basin.
- The Bend shale in the Palo Duro Basin.
- A Barnett/Woodford shale play in the Delaware Basin.
- Another Barnett/Woodford shale play in the Marfa Basin.
- Other, largely untested targets like the Hermosa/Gothic shale in the Paradox Basin, the Baxter shale in the Vermillion Basin and, possibly ...
The shale in your back yard, if you have some.
‘A Lot of Promise’
The deepest thinking exploration involves several upcoming and projected new wells with total depths of 12,000 feet or more, all assessing horizontal well prospects for shale gas.
One significant new shale play targets the oldest producing petroleum system in the United States.
The Devonian Shale-Middle and Upper Paleozoic system in the Appalachian Basin contains a technically recoverable 31.4 trillion cubic feet of gas, 562 million barrels of gas liquids and 7.5 million barrels of oil (mean estimate), according to a U.S. Geological Survey estimate by Robert Milici and Christopher Swezey.
The Big Sandy field in eastern Kentucky was identified as a major Appalachian gas reservoir in the late 1800s. It has produced from Devonian shale since 1921, with expected ultimate recovery of more than 3 Tcf.
“I think the area’s got a lot of promise to it,” Milici said. “The Big Sandy gas field has been known as a good producer for a long time.
“It’s just a matter of figuring out how to get the hydrocarbons out of the rest of the area,” he added.
The USGS assessment noted that Col. Edwin Drake discovered this petroleum system in August 1859 with the nation’s first commercial oil well, which TDed at 69.5 feet.
Range Resources Corp. of Fort Worth holds 410,000 lease acres in an emerging Appalachian-Devonian black shale gas play in Pennsylvania.
“Really, the Appalachian Basin is where the roots of the company started. We’ve been there for a long time,” said Jeff Ventura, Range Resources chief operating officer.
Ventura said the company holds a total of 2.3 million gross, 1.9 million net acres in the basin as well as 400,000 royalty acres.
By the end of 2006, Range Resources had 12 vertical and one horizontal wells online in the Devonian shale play.
“Our initial effort was to drill three vertical wells and just pump the big slickwater fracs down them. We’ve also done a lot of reservoir modeling there,” Ventura said.
“Results from the initial wells indicate an estimated resource potential of between 0.6 to 1 Bcf per vertical well,” he said.
Ventura estimated Range Resources’ net unrisked reserve potential in the play at up to 2.5-5 Tcf. Plans call for drilling 60 additional vertical and eight horizontal wells in 2007.
A financial sweetener for Devonian shale gas is its proximity to major markets. Ventura said the company gets a 35-cent/Mcf premium to NYMEX for its Appalachian production, compared to a discount of as much as $1.50/Mcf in the Rockies.
According to Milici and Swezey, the Appalachian Devonian strata can be divided into two groups:
- Pre-orogenic lower and middle Devonian strata dominated by stable shelf sedimentary deposits.
- Syn- to post-orogenic middle Devonian to early Mississippian strata that resulted from tectonism, subsidence and filling of a foreland basin.
The middle-Devonian Marcellus and Millboro shales, black shales at the base of the Catskill delta, extend widely and probably were deposited in relatively deep water as the basin first developed, they said.
A number of upper-Devonian gas shales alternate with units that contain less organic material. They cite Dennison (1985), who notes that middle-Devonian sea-level transgressions generally resulted in deposition of limestone, while cyclical upper-Devonian flooding events resulted in deposition of black shale.
Milici said the overall basin is considered underpressured.
“When you get a major decollement, like you do below the Pine Mountain fault, what the drillers found out years ago -- they would go in there with cable tools -- is that you have a major blowout zone,” he said.
“The areas of limited decollement in fault-prone Devonian shale are good producers, and that’s why Big Sandy works, I think,” he added.
Ventura said the northern part of the Devonian shale play area is slightly geopressured, while the southern part is underpressured and naturally fractured.
“In the northern part of the basin, from the West Virginia-Pennsylvania border north, there’s a lot of gas in place but you don’t have that natural fracturing, so the stimulation methods of utilizing nitroglycerin or newer foam fracing don’t work,” he noted.
Conversely, slickwater fracing isn’t optimal in the southern area because of the low pressure, he said.
Range Resources considers the Appalachian Devonian black shale a key play area where it intends to be an industry leader, according to Ventura. The company recently opened a Pittsburgh office to oversee work there.
Playing the Permian
The company also is involved in an emerging Barnett shale play in another long-time producing area, the Permian Basin, where it holds 20,000 acres with estimated reserve potential of 400-500 Bcf.
That play offers attractive secondary opportunities in other formations, primarily the Woodford, Fusselman and Wolfcamp, Ventura said.
“Because the Barnett in the Permian is clearly a different beast, we’ve chosen to focus on other areas. I think our strategy of being followers out there has been successful,” he said.
The company does operate in the Fort Worth Barnett -- “We’ve just drilled some killer wells in Tarrant County,” Ventura said -- and has plans to expand the eastern limits of the play into Ellis County.
“We recently brought online a well that’s producing at 12 million cubic feet equivalent per day, the highest well rate in the Fort Worth Basin Barnett shale to date,” he said.
Ventura said Range Resources hopes to become a leader in the major Barnett play area, as well.
“We’ve got a lot of people in our company now who helped unlock the Barnett for the industry,” Ventura explained.
“The big challenge to me always comes down to people,” he said. “Do you have the technological competence -- the people -- to extract the resources economically?”
Powder River Activity
A USGS assessment update issued last year estimated the mean undiscovered hydrocarbon resource in the Powder River Basin at 16.6 Tcf of gas, 639 million barrels of oil and 131 million barrels of natural gas liquids.
A Powder River Mowry play is one of the few new shale plays primarily producing oil.
Brigham Exploration, Abraxas Petroleum and American Exploration are all involved in the Mowry shale play, centered in Converse and Niobrara counties, Wyoming.
By March, Brigham had drilled 18 vertical wells and two pilot horizontal wells in the play. Its first well flowed 120-160 barrels of oil per day from an outer, uncased section of the well bore and 50-90 barrels per day from 1,381 feet of cased bore after stimulation.
Abraxas said the lower Cretaceous Mowry is a siliceous silty shale up to 175 feet thick at 7,500-10,000 feet. It estimated ultimate recovery comparable to the Bakken (MBOE) and a drill-frac cost of about $3 million per well.
‘Off and Running’ in Utah
Another new play has unfolded in the very thick Mancos shale group in Utah’s Uinta Basin, said Steve Schamel of GeoX Consulting in Salt Lake City.
“It’s off and running -- this is a resource that’s now established. There are quite a few wells that will soon become part of the public record,” he said.
Schamel said he has identified five Cretaceous units in Utah with shale gas potential, four of them members of the Mancos.
These units were deposited in a basinward position within the Western Interior Seaway, foredeep basin to the Sevier thrustbelt, according to Schamel.
Deposition in proximity to heavily vegetated, fluvial-deltaic shorelines resulted in a high humic component of organic matter in the basinal shales, he said.
Operators in the basin already have drilled the Mancos play area for higher production, Schamel noted.
“They’re currently producing from sands above the Mancos and now they’re drilling into the Mancos,” he said. “So the indications are very good that we will have substantial gas shale production in the future.”
Something Old, Something New
Newfield Exploration Co. has broken open a Woodford shale play in the western Arkoma Basin, where it plans to spud 150 wells in 2007.
Now a new Woodford play is quickly developing south of that production in Oklahoma’s Carter, Love, Marshall and Bryan counties in the Ardmore Basin.
Bankers Petroleum Ltd. of Calgary has announced that its first well in the Ardmore Woodford flowed 470 Mcf and six barrels of condensate per day with 25 percent of the frac fluid still unrecovered.
The company estimated original gas in place at 222 Bcf per section based on a Schlumberger gas shale log analysis.
Ed Gallegos of Iron Sights Operating Inc. in Stillwater, Okla., said his company has 17,000 net acres in the play area. Others in the play include Range Resources, Wagner and Brown, Cimarex Energy, Chesapeake Energy, Walter Oil & Gas, Antero Resources and Oracle Resources.
Gallegos said drilling has encountered about 300 gross feet of Woodford pay overlain by 60 feet of fractured Woodford.
“The total Woodford interval is 300 feet thick with the upper 60 feet being chert, then 120 feet of organic black shale, 100 feet of shale-chert laminations and 10 feet of green shale with a detrital interval on the bottom of the sequence,” he said.
Porosities are in the 20-26 percent range as interpreted by density logs, and “in addition, you have all the tectonics in this area that have enhanced the natural fracturing,” he said.
A 3-D seismic shoot is under way in the Cumberland Syncline extension area of the basin, according to Gallegos.
“That’s going to uncover a lot of Ordovician highs that haven’t been drilled,” he noted.
Gallegos expects operators in the Ardmore Woodford play to move toward fractured horizontal wells soon, improving production rates.
“There are several vertical wells in the area with cumulative production of 2-5 Bcf,” he said. “If horizontal drilling enhances the Woodford production here as it has in other areas, this should turn out to be the best shale production in the state.”