Surprisingly, there is nothing new—except for a technological tweak—about one of North America's "newest" unconventional-resource plays. But that one innovation, horizontal drilling, is making a mountain of difference in the dynamics of the Huron shale, a decades-old play.

The Appalachian Basin is attracting nationwide attention, as well as a furious increase in activity, thanks to the red-hot Marcellus shale play that sprawls across much of Pennsylvania and spills into West Virginia, Ohio and New York. But the southern end of the Appalachian Basin hosts a rejuvenated shale play—the Huron or Lower Huron, which extends through southern West Virginia, western Virginia and eastern Kentucky.

"Big Sandy Field was discovered in the 1920s in eastern Kentucky," explains Steven Schlotterbeck, president of EQT Exploration & Production. "Folks have been drilling in it ever since then. It has over 6,000 producing wells. In late 2006, we started to apply horizontal-drilling techniques to it."

Pittsburgh-based EQT, formerly known as the Equitable Corp., has "made a nice living" for 80 years drilling vertical wells in the Huron shale, according to Schlotterbeck.

"When we started drilling horizontal wells, we had to adapt to a low-pressure reservoir," he says. "But we have had success drilling horizontal wells in the Huron since 2007."

Sales from Huron/Berea (the Berea sandstone lies just above the Huron) horizontal drilling by EQT have increased from 6.9 billion cubic feet equivalent in third-quarter 2009 to 9.9 billion for third-quarter 2010. The company drilled 130 gross wells during the third quarter of this year, with 66 of those horizontal wells. Seventeen targeted the Marcellus play with a typical lateral length of 4,000 feet; and 49 targeted the Huron/Berea play with a typical length of 4,300 feet.

The volume of gas contained in Appalachia's low-pressure shales and tight sandstones is phenomenal. For example, EQT has pegged its proven, possible and probable reserves in the Lower Huron alone at nearly 6 trillion cubic feet (Tcf), with the Berea sandstone holding another 600 billion cubic feet equivalent.

Much of the Huron gas in Kentucky is liquids rich, notes Schlotterbeck. The liquids component improves the economics there, especially in these days of depressed natural gas prices. Processing net revenues for EQT were $23.7 million, or 57% higher, in the third quarter, as a result of a 28% increase in the average natural gas liquids sales price and a 25% increase in liquids volume, nearly all produced from horizontal Huron/Berea wells. Estimates are that $5 gas sold on Nymex actually brings $7.48 per thousand cubic feet, thanks to the liquids production.

Mark Whitley, senior vice president of Range Resources Corp., Fort Worth, characterizes the Huron shale footprint as "very large," extending over several counties and across three states.

Except for its significant size, however, the Lower Huron is in many ways the polar opposite of the more marquee, overpressured Marcellus. The underpressured Huron requires different drilling and completion techniques than the Marcellus. And that critical difference—one of several between the two shales—explains why the Lower Huron has not drawn as much attention.

Time on Their Side

"If there is any drawback, it is because it is underpressured," Whitley says of the Huron shale. "There is not as much gas in it as the Marcellus, but we can drill hundreds of wells when the time is right, because all of our acreage is held by production."

The Huron horizontal wells have ultimate recoveries of about 1 billion cubic feet and cost about $1.3 million to drill and complete. Range has drilled approximately 25 horizontal Huron wells to date on its properties in the Nora Field area of Virginia. It has also drilled horizontal wells in the Berea sandstone and the Big Lime in this field, which is at the southern tip of the Appalachian Basin. All of these zones produce dry gas at attractive economics.

Indeed, the reason operators have not beaten a path to the southern Appalachian Basin's Lower Huron play is not because of a lack of resource potential, but rather because most of the acreage there is already held by previous production.

"The Huron has been the heart of the shale play in Appalachia for 100 years," says Henry Harmon, president of Triana Energy LLC, a private company based in Charleston, West Virginia.

"Most of the larger companies that have extensive held-by-production acreage in the southern end of the basin, like Cabot Oil & Gas, are not very motivated to invest in developing those properties while commodity prices are so low. The major companies have redirected almost all capital expenditures to the Marcellus. The remainder of the Huron play is held by a lot of mom-and-pop companies, which are just not able to embrace the cost of drilling horizontally.

"In addition, we're now seeing a changing regulatory environment that's going to make development even more challenging. Pennsylvania has changed its regulations to adjust to the Marcellus, and West Virginia is now going through a similar regulatory rewrite. It will be significantly harder for small operators to hold acreage in the future, and they will have to learn to deal with the new regulations."

Range Resources' Whitley agrees that "there is no pressure to hold the acreage." Because of that, he says, Range has just one rig running in the Huron, while the company has 850,000 net acres in the Marcellus fairway and has seen its production in the northern part of the Appalachian Basin grow from 26 million cubic feet per day to a projected 200 million daily by year-end 2010.

Harmon maintains the Huron has tremendous potential.

"Much of it was originally drilled on 2,000-foot spacing," he says. "A recent study indicated that on 80-acre spacing, we have depleted only 10% to 12% of the gas in place. Horizontal drilling, large fracs and systematic drilling will still produce a lot of gas out of what were once thought to be depleted fields."

When asked how much acreage his company has in the Huron, Harmon jokes, "Not nearly enough."

Triana has about 40,000 net acres in the play, according to Harmon, and also partners with other operators there.

The biggest challenge to Huron development? Insufficient pipeline take-away capacity and other infrastructure deficits.

"Companies will have to pay for firm transportation in order to upgrade facilities and assure access to markets," he observes. "There are not a lot of midstream players in the southern end of the basin."

Drilling with Air

Because the Huron is a harder, more brittle shale, operators can drill with air as the circulating medium, and so reduce costs. Huron wells vary in vertical depth from 7,000 feet in northern Virginia to below 5,000 feet in southern West Virginia and below 3,500 feet in eastern Kentucky, according to Harmon. Although Triana has drilled laterals as long as 9,000 feet, "5,200 feet is about as far as you want to push pipe in these formations," Harmon says.

"The nice thing is the Huron is a shale that will drill nicely on air. It's competent enough that it will hold. Our drilling company, Highland Drilling, recently drilled its one-thousandth shale well on air."

Highland Drilling has eight rigs now working the Huron play. Triana Energy has drilled 12 horizontal wells in the Huron to date in 2010, with eight more planned before July 2011. After that, the drilling program will depend on what happens to natural gas prices, Harmon emphasizes. Development costs typically average about $1.25 per thousand cubic feet of reserves. Initial production rates are lower in the Huron than in the higher-pressured Marcellus, but the decline curves look about the same.

"You almost never drill a bad well in the southern end of the basin," says Harmon, "because you always have a bail-out zone. We're also drilling horizontally in the Berea sandstone, and have done stacked laterals where the shales are properly situated. Drilling multiple targets is a very economic way to approach this development."

An average Huron well drilled to a depth of 4,500 to 5,000 feet costs about $1 million, says EQT's Schlotterbeck.

The underpressured nature of the Huron shale allows companies to use mostly nitrogen fracs, or high-quality foam fracs that are at least 90% nitrogen, instead of the slickwater fracs that have become popular in the Marcellus and many of the other unconventional shale-gas plays.

"Because the Huron is naturally underpressured, there is no opportunity to use conventional (frac) techniques," Schlotterbeck explains. "The key is to remove as much water as possible."

Stacked Targets

The Huron play is actually a number of stacked targets, including the Berea tight sand and the Cleveland, Rhinestreet, Huron and Lower Huron shales.

"They are all part of the Devonian package," Schlotterbeck says. "We refer to it as the Huron/Berea play. On some pads, we are drilling horizontal laterals in the Huron and Cleveland on top of each other. We are targeting two- to two-and-a-half targets per location on average."

EQT commonly drills lateral and multilateral wells in multiple zones, with each treated as a separate zone.

"Nora Field, which we own with EQT, is a stacked pay," Range's Whitley says. "The primary pay is coalbed-methane reservoirs at 1,100 to 2,500 feet. Below that is the Berea tight sand, Big Lime and below that is the Huron, which is another Devonian shale."

In June, Range acquired natural gas properties in western Virginia from a subsidiary of Chesapeake Energy for $135 million. The assets are contiguous to and partially overlap Range's existing Nora/Haysi holdings. The acquired properties currently produce 10 million cubic feet equivalent per day and include 115,000 net acres of leasehold and 30 miles of gas-transmission lines. Range estimates the proved reserves associated with the acquisition total 125 billion cubic feet equivalent.

The acquisition blocks up more than 350,000 acres for future development in stacked-pay reservoirs of the shallow coalbed-methane, horizontal tight-gas horizons and the deeper Huron shale, according to Whitley. He points out that the same reservoirs are currently being developed in adjoining Nora Field. Based on results of infill drilling in Nora Field over the past year, Range believes the acquired acreage has significant infill-drilling and behind-pipe opportunity with attractive economics, even at current low gas prices.

"Nora Field (which sits in Virginia across the border from Big Sandy Field in Kentucky) has tremendous upside," Whitley claims. "We own almost 300,000 acres with a 50% working interest and 56.5% net revenue interest."

The horizontal wells are producing at least two to three times as much gas as the older vertical wells, according to Whitley.

Schlotterbeck concurs.

"Vertical wells in the Huron average 75,000 to 100,000 cubic feet per day, he says. A typical horizontal is 400,000 per day. That is a four-fold increase by drilling horizontally."

And that is a remarkable development for a formation that has been producing natural gas for nearly 80 years.