More than $2 billion will be spent this year on exploring, developing and producing from the Upper Devonian-Lower Mississippian Woodford shale in Oklahoma.
What makes the Woodford play work?
That’s not a trivial question for an industry trying to generate shale-gas plays wherever it can.
And it’s a vital consideration for an industry that plans to drill hundreds of wells in the Woodford, hoping the play will become the next Barnett shale-type bonanza.
The Woodford has all the right traits for a successful shale-gas play, including thermal maturity for gas generation, a good geological setting, attractive lithology and mineralogy, and the right amount and type of total organic carbon.
In fact, one of those characteristics makes it a superb shale play.
The biggest single chunk of money aimed at the Woodford this year – about $500 million – will be invested by the play’s dominant driller, Newfield Exploration Co. of Houston.
But more than 25 operators have tried at least one Woodford well recently.
Devon Energy Corp. and Chesapeake Energy Corp. of Oklahoma City and Cimarex Energy Co., Antero Resources Corp. and St. Mary Land & Exploration Co. of Denver have been active players in the Woodford.
So have XTO Energy Inc. of Houston, Pablo Energy Inc. of Amarillo, Texas, PetroQuest Energy Inc. of Lafayette, La., and Continental Resources Inc. of Enid, Okla.
Right now the heaviest drilling in the Woodford play is centered on the western end of the Arkoma Basin, in southeastern Oklahoma.
“The activity in the state’s been tremendous,” said AAPG member Charles Wickstrom, managing partner for Spyglass Energy Group LLC in Tulsa. “The play has expanded as far west as Canadian County in the Anadarko Basin. Devon, Chesapeake and Cimarex are the most active operators out there.
“And the play has moved as far south as Marshall County in the Ardmore Basin,” he Newfieldcontinued. “Range (Resources Corp. of Fort Worth) is one of the biggest working interest holders there.”
Wickstrom said his company holds interests in 25 Woodford horizontal wells. At the recent AAPG annual meeting in San Antonio he presented the overview “Woodford Shale Gas in Oklahoma, 2008” to a standing-room only session.
“On the flanks of the Ozark Uplift we have a company that’s drilling the shallow areas of Mayes County,” he said. “They’re drilling vertical wells and getting production of 20-100 mcf a day.”
And in Garvin County in south-central Oklahoma, Cimarex is testing the Woodford on the flanks of the Arbuckle Uplift, Wickstrom noted.
Today, heavily fractured Woodford wells in the core play area can produce over 10 million cubic feet of gas per day for the first week, with average initial production in the five-to-six million range.
That’s exceptional for a play that began quietly in 2003-04.
“It started as a vertical play – I won’t say we had a grand vision of the Woodford being what it is today,” said Sam Langford, Newfield Exploration manager of commercial development, planning and acquisition.
“While we were leasing back then, Devon actually drilled four or five horizontal wells – they got into it about the same time,” Langford noted. “Being the Barnett king, that was sort of their bailiwick.”
‘Really Good Surprises’
Newfield approached the Woodford looking at potential in the Cromwell, Wapanucka, Woodford and other formations in “a vertical, multi-zone commingled play combined with coalbed methane,” Langford said.
Then several things began to happen at once.
The company targeted Woodford completions and “got some really good surprises,” he said. The Barnett shale transformed into an extensive play driven by horizontal drilling and multi-stage fracs. And natural gas prices began to rise and kept going up.
It became obvious that the Woodford was going to be a big deal.
“Currently, the Woodford shale play is concentrated primarily in the western part of the Arkoma Basin where the thermally mature area is thicker than it is to the north,” said AAPG member Brian Cardott, geologist for the Oklahoma Geological Survey.
“The structure map shows that the Woodford reaches thermal maturity at a relatively shallow depth compared to other basins,” he said.
Vitrinite reflectance (Ro%) of the principal Woodford play area varies from 0.5, indicating roughly the start of the oil window in thermal maturity, up to and above 3.0, pushing the upper limit of the dry-gas window.
“One of the nicest things about these gas-generating organic shales is that most of the gas is within the oil window,” Cardott said.
“This Type II kerogen also generates a bitumen network of migration pathways,” he added, “connecting the organic matter together.”
Not Created Equal
This variance in thermal maturity is one reason the Woodford doesn’t resemble the Barnett play closely. Another is the variety of geological settings present in Oklahoma.
Moving north toward Kansas the Woodford thins and eventually pinches out. To the west in the Anadarko Basin, the formation drops lower and “you fall off the face of the Earth,” Langford noted.
“When people first heard about the Woodford they immediately thought ‘Barnett.’ They thought “Fayetteville’ – millions of acres with little variation. We’ve been telling people for over a year, ‘It’s not all created equal,’” he said.
If there’s a special attribute that makes the Woodford work, it can be summed up in two words:
“One of the main characteristics of the Woodford shale is that the mineralogy is silica-rich.
It’s these silica-rich rocks that are very brittle and generate fractures. The Woodford behaves very well in fracturing techniques,” Cardott said.
“One of the reasons the Woodford has been so predominant over the Caney Formation, which is the equivalent of the Barnett shale in Texas, is that in Oklahoma the Caney has a clay-rich lithology that absorbs the fracture energy,” he added.
Silica-rich rock is perfect for the multi-stage fracs used in today’s shale-gas plays, and it also ensures an abundance of natural fracturing in the Woodford.
“The big thing that makes it work is the silica content,” Langford said. “It’s already fractured before we mess with it.”
While the Woodford isn’t a shallow gas play, it isn’t especially deep in its core area. Langford estimated Newfield’s drilling depths at 6,000-13,000 feet, with an average pay thickness of 125 feet.
The company has been able to minimize the number of drilling pads needed and amount of equipment required on-hand to drill the Woodford play. It’s pushed overall finding and development costs down toward $2/mcf, and even lower with long-lateral development.
“Our objective is to have as few vertical holes as possible with as many lateral feet as possible, because the cost of the vertical hole is essentially wasted money,” Langford said.
“Drilling the vertical hole has more complications. There’s a lot more of it, and there’s a lot more complexity than there is above the Barnett,” he added.
Newfield spaces its laterals 660 feet apart and skids rigs to work on a section. The lateral length has now extended to nearly 5,000 feet, so that one lateral stretches across the full mile.
With fracturing spaced at about 5,000 feet, many of the longest laterals are taking nine-stage fracs.
“The frac near the end of the 5,000-foot lateral is just as good as the one at the turn,” Langford said. “It looks like you can pump a frac close to a mile.”
$igns of $uccess
There’s no doubt that Woodford development has benefited hugely from lessons learned in the Texas Barnett. Because of that earlier experience, operators were able to move up the shale-gas learning curve much faster in Oklahoma, according to Langford.
Most of the initial Woodford shale exploration was drilled on 2-D seismic – but Newfield and other operators have been diligent in acquiring 3-D. A clearer seismic image can be essential for avoiding natural fractures that extend into water-bearing formations, especially when fracing.
With so much natural fracturing present in the Woodford, 3-D seismic also is needed for geosteering long laterals that have to stay within-formation across significant fault-throws.
“In the Woodford, 3-D is the magic key – that’s what allows you to do the thing right,” he said. “We navigate through 150-foot faults now every day and never miss a beat.”
How much money will be made in the Woodford play? There’s no other estimate than this:
Earlier this year, Newfield issued a chart showing that finding and development costs of $2/mcf in the Woodford can produce before-tax internal rates of return above 50 percent. But that chart went up only to a flat NYMEX price of $10/mcf.
For now, operators will continue to improve efficiencies and extend the Woodford play as much as possible. Fine-tuning includes considerations of frac-spacing and well-spacing.
“Our next big question is, ‘What is the spacing going to be?’” Langford noted. “Is it a 40-acre play or is it a 60-acre play – or an 80-acre play?”
Today, the economics of Woodford shale gas could hardly look better. The play might not be another Barnett, but it is a compelling opportunity with room to run.
“If the economics of the Arkoma Basin hold up across the other Woodford play areas, this should be a viable play for years to come.”