New shale plays, best production techniques, costs, and rewards all fell under the microscope as operators, investors, and service experts disclosed their knowledge to shale novices and shale operators alike at the second annual Developing Unconventional Oil (DUO) conference in Denver. More than 2,000 DUO participants attended the conference, many of whom took advantage of Q&A sessions that followed the speaker presentations.
The trending topic was the Rocky Mountain shales, primarily the growing Bakken/Three Forks and emerging Niobrara.
Around the world
More exploration-oriented investors also wanted to know about emerging shale plays on the global stage. However, many independents see the greatest value in US unconventional plays for now. Paul Favret, chief executive of Source Energy Partners LLC, said his company has exited positions in Europe’s shale plays to focus on the US and other areas. Europe has few service operations, high costs, limited accessibility for heavy equipment, and fracturing moratoria nearly everywhere but Poland. The latest well in the Mako Trough in Hungary cost US $74 million to drill to 14,000 ft (4,270 m) and was water-saturated, he said.
Outside Europe, the Szechuan basin in China has potential, and EOG Resources Inc. already is there, but “it's tough to get a private-equity return,” Favret said.
Emerging US shales
Back in the US, emerging unconventional resources include the Tuscaloosa Marine shale, where Devon Energy Corp. is drilling the first of two horizontal wells on its 250,000 acres. Denbury Resources Inc., through its purchase of Encore Acquisition Co. in November 2009, holds 200,000 acres, and Indigo Minerals LLC holds another 240,000 acres.
“In the food chain … the adaptability of the Rocky Mountain oil industry to big changes that we’ve had over the cycles is remarkable,” BoA Merril Lynch vice chairman Tom Petrie said during his Q&A. “Whether it’s gas or oil, the development of unconventionals is a bottoms-up, technically driven (industry) that takes commercially astute people to figure out ‘what do we do now?’” (All photos courtesy of Alexander Rogers)
Other formations getting attention include the Brown Dense in southern Arkansas; the Mowry in the Rockies; the Utica shale in Appalachia, where Chesapeake Energy Corp. holds 1.2 million acres with the EV Partners arm of EnerVest Ltd.; and the Heath shale in central Montana, where Cabot Oil & Gas Corp. is active.
The Mississippi Lime also is getting a closer look from companies including Eagle Energy Co. of Oklahoma LLC and Vitruvian Exploration LLC.
Venoco Inc. and Occidental Petroleum Corp. (Oxy) are working the Monterey shale in southern California, while Zodiac Exploration Corp. is testing the deeper Kreyenhagen shale in the San Joaquin basin.
The main focus of the conference was on the Rocky Mountain area’s shale potential.
Responding to questions about these plays, Tom Petrie, vice chairman of Bank of America Merrill Lynch, called the Bakken and Three Forks plays in the Williston basin “truly world-class opportunities.” Along with the Eagle Ford in Texas and the Niobrara in Colorado and Wyoming, they have the best potential among the oily shales for year-on-year growth over the next decade.
Bakken/Three Forks
According to Jim Volker, chairman and CEO of Whiting Petroleum Inc., the Bakken features “an Oreo cookie” characteristic, with an upper shale overlying the producing middle dolomitic zone and a lower shale overlying the Three Forks formation in the sweet spot of the North Dakota play. Moving to the southwest at the edge of the Upper Bakken, the Bakken lies atop the Three Forks.
Here, the attraction is clear, Volker said. Production rose from 23,000 boe/d in 2006 to 340,000 boe/d by the end of 2010, with 147 rigs at work. Some operators predict a peak as high as 1.2 million boe/d. Wells topping 2,000 boe/d are common, and Brigham Exploration Co. has tested one well at 4,551 b/d and 4.01 MMcf/d.
Volker listed his company’s prime contributors to making the Bakken work. Staged frac treatments top the list, followed by drilling wells on paper (DWOP), which has helped lower horizontal well costs from $8 million to $5.5 million through better scheduling. Microseismic measurement was on the list as well. The technology has been used to measure frac extensions showing fracture reaches of 750 ft, allowing the company to set optimal horizontal leg spacing at 1,500 ft. The company's electronic scanning microscopes let Whiting quickly evaluate cores to find the ideal depths for horizontal wellbores.
Whiting currently is drilling parallel horizontal wells 2 miles long with up to 40 frac stages. In an area containing wells with 300,000 boe of estimated ultimate recoveries, Whiting expects a 2.5:1 return on its investment. The company probably will not slow drilling unless oil prices drop below $60/bbl, Volker said.
The company uses plug-and-perf technology on its well completions, but Volker is looking forward to a Baker Hughes multi-port system that could, for example, divide the horizontal leg into three ported sections with 20 frac intervals per port for a total of 60 staged fracs.
He also would like to see microseismic improvements that would more accurately show fracture height growth.
Like Whiting, Brigham Exploration uses perf-and-plug zipper fracs with swell packer and frac crews alternating between the parallel horizontal wellbores for more efficient use of manpower. The company currently uses 38 frac stages, said Bud Brigham, chairman, president, and CEO.
Taylor Reid, executive vice president and chief operating officer of Oasis Petroleum Inc., said his company tried sliding-sleeve frac treatments before moving to perf-and-plug. Sliding-sleeve treatments take only three to four days, while perf-and-plug operations take seven to nine days, but the better production makes up for the added time, Reid said.
"You will see Chesapeake in the next few months announce a number of investment initiatives where we are going to buy companies who believe that they have technological breakthroughs that need to be tested on gas-to-liquids,” said Chesapeake Energy Corp. chairman and CEO Aubrey K. McClendon at the DUO conference and expo presented by Hart Energy.
“When we look at the data, we see a linear increase in production with additional stages with no fall-off,” he said. “Applying that to the field, a $100,000 frac stage adds 50,000 boe at a cost of $8/boe. That’s why the company is moving from its current 28-stage treatments to 36-stage fracs.”
To move production to market, the least expensive technique is to ship to the Mandan refinery in North Dakota, Reid said. The next best solution, according to Reid, is the Enbridge or Bridger pipeline, and the third option is shipping by rail.
Both Enbridge Inc. and True Cos. are expanding their pipeline operations in the Bakken play, but these expansions, coupled with the Mandan refinery capacity, fall well below the predicted 800,000 b/d to 1.2 million b/d of forecast production.
Greg Hill, executive vice president and president, worldwide E&P at Hess Corp., uses both of those options and plans to buy rail cars. For 140,000 b/d of production, he said the company would need 14 unit trains a week.
Niobrara
There are only 26 drilling rigs working in the Niobrara in the Denver-Julesburg (DJ) basin of Colorado and Wyoming, but by mid-May 2011, more than 100 horizontal wells had been drilled to the formation, and more than 400 additional wells were scheduled.
Prime territory for the liquids portion of the play is in northern Weld County, Colo., particularly the area that lies in the giant Wattenberg field, which has a potential 4 to 5 Bbbl of recoverable oil.
A frac stage in the Niobrara costs around $90,000, compared with $220,000 per stage in the Eagle Ford, the extra cost of which is “all in hydraulic horsepower,” according to Brad Fisher, CEO of Carrizo Oil & Gas Inc. His company uses sliding-sleeve completions in the Niobrara and plug-and-perf in the Eagle Ford. That results in $3.5 million wells in the Niobrara and $7.5 to $8 million wells in the Eagle Ford.
Manuj Nikhanj, vice president of Ross Smith Energy Group, said the Niobrara is more complex than the Bakken. It's underpressured instead of overpressured – largely with matrix instead of natural fracture permeability – and controlling costs will be a major factor in the shale play’s development, Nikhanj said.
Continue reading additional online coverage:
DUO 2011: Hess Confidently ‘Manufacturing’ Oil In The Bakken
DUO 2011: Stimulation Of Unconventional Oil Reservoirs Is A New Frontier
DUO 2011: North Dakota Is Open For Business
Participants walk the show floor at the recent DUO conference in Denver. The trending topic was the Rocky Mountain shales, primarily the Bakken/Three Forks and emerging Niobrara.