BRISBANE, Australia -- Attendees of the DUG Australia conference recently hosted by Hart Energy in Brisbane gained valuable advice regarding key developments in two of the largest U.S. unconventional basins.

In a keynote address, Dick Stoneburner, former president, North American shale production division, BHP Billiton Ltd., recounted the first steps in the “making of North America’s Eagle Ford play” and described how unconventional exploration required a “different way of thinking,” compared with conventional exploration.

In the Marcellus, meanwhile, attendees heard Marcellus Shale Coalition CEO Kathryn Klaber provide advice on handling what might follow an unconventional discovery in the realm of regulatory, political and community issues, and how best to anticipate and proactively address concerns arising from parties unfamiliar with energy matters.

In drawing a distinction between the two play types, Stoneburner said that exploration involving a conventional reservoir is approached “from the outside in,” with seismic helping to “narrow in on the prospect.” By contrast, project identification in the unconventional is based on an “inside-out concept.” Seismic control works “inside-out” to define the aerial extent of the play, and reservoir quality analysis is required over a very broad area of the basin.

“It’s a different way of thinking. You have to have a scale that is much larger than what you might have in conventional exploration,” said Stoneburner. “All we really knew about the Eagle Ford was that it was a source rock in a petroliferous basin. We didn’t know much about the porosity. We didn’t know much about the reservoir characteristics. The one thing we knew was that it was extremely large. We knew it was in excess of 10 million acres.”

Stoneburner, who served as president of Petrohawk Energy Corp. prior to its purchase by BHP Billiton, also recalled a lesson from his experience in the Haynesville.

“What we learned from the Haynesville was: be smart, be quick and be quiet. In the Haynesville, prices got out of control. In the Eagle Ford, we did it totally under the cover of night. No one knew what we were doing.”

Key findings that helped with the discovery of the Hawkville field in 2008 were logs from a previously drilled well showing over 250 feet of Eagle Ford with excellent resistivity, geochemistry data from well cuttings showing good thermal maturity and seismic evidence of a reservoir across the mini-basin. By the fall of 2008, in little more than two months, an acreage position of 160,000 had been assembled.

The first well was drilled in July 2008 and completed in October. A second well was spud in September and completed shortly thereafter. With these two wells, and a third to the east, said Stoneburner, “I was convinced that that we had enough evidence that this reservoir was across the entire acreage position because of the seismic control. So we drilled three exploration wells and then went into appraisal.”

Thereafter, recalled Stoneburner, it was “all about the rocks. Everything you can do to get data out of that wellbore, and on the surface, you do. And you don’t worry about the cost, because in the overall scheme of things, it’s a drop in the bucket when you develop tens of thousands of wells. Nothing is more imperative than having core data and properly analyzing that core.

“It’s not just about what’s in the rocks. It’s about how they behave under certain stresses and certain conditions that you are going to subject those rocks to, i.e. hydraulic fracturing.”

Five years after its discovery, the Eagle Ford play is in full development, with about 10,000 wells permitted to date, noted Stoneburner. Approximately 290 wells are being drilled in the play each month.

With an average estimated ultimate recovery (EUR) of 450,000 barrels of oil equivalent (boe) per well, the risked remaining resource from more than 70,000 undrilled locations is estimated at 28 billion boe, said Stoneburner, citing an ITG Energy report. Spacing assumptions range from 110 acres in the dry gas areas to 40 acres in the oil window.

With the play breaking even at oil prices as low as $62/bbl, BHP has an estimated remaining resource of 1.7 billion boe. EOG Resources’ remaining resource is estimated at 2.2 billion boe, according to ITG.

According to Stoneburner, the factors leading to the Eagle Ford’s growth were “truly unprecedented,” including petrophysical parameters “among the best, if not the best, of any known shale reservoir.” In terms of growth, production has now surpassed 900,000 boe/d from zero in 2008, “and when you think about 290 wells per month, that’s going to go nowhere but up.”

In the Marcellus play, Klaber noted that, despite Pennsylvania’s history of oil development, a need for further education existed as oil and gas development was “a relatively new phenomenon” on the East Coast. Encompassing 95,000 square miles, noted Klaber, the Marcellus stretched over “five different states with five different approaches.”

In fact, as Klaber pointed out, three areas adjoining Pennsylvania — New York, the Delaware River Basin and Maryland — are currently closed to development due to prolonged regulatory processes or, in New York’s case, a ban. This leaves Ohio to the west and W. Virginia to the southwest, along with Pennsylvania, open to development.

Klaber emphasized the need to be proactive and transparent in explaining oil and gas issues. “If you see an issue, don’t hide from it. Get out in front of it,” she said. “If we don’t get out there and explain this, and do it aggressively, we’re going to pay down the road.”

In Pennsylvania, Klaber pointed to a broader understanding of how the state benefits from oil and gas development, highlighting the tax revenues generated by oil and gas, as well as oil and gas royalties and revenues earmarked for road construction. She noted all 67 counties in Pennsylvania shared in the “impact fee” levied on the industry, even if specific counties had no oil and gas activity.

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