T?he Appalachian Basin in the Eastern U.S. is jam-packed with tight, hard sediments, formed in Earth’s deep past, eons before mammals, dinosaurs or any vertebrate life forms graced the planet. These ancient rocks were the first to produce hydrocarbons from drilled wells.

Natural gas flowed from Devonian shale in 1821, when James Monroe was president and Missouri joined the young and expanding United States. Entrepreneur William Hart drilled a well in Fredonia, New York, to a depth of 70 feet in Devonian Dunkirk shale. Hart fashioned a pipeline from hollowed-out logs and transported the gas to the town center, where it fueled streetlights on the main avenue.

Oil’s anniversary is more renowned. In 1859, with the nation on the brink of civil war, Colonel Drake drilled his legendary well in Titusville, Pennsylvania, and hit oil in Devonian-aged Venango sandstone.

In the ensuing century and a half, operators have drilled hundreds of thousands of wells into Devonian sediments in Appalachia. One could reasonably surmise that most every Devonian deposit has been thoroughly investigated by this intense scrutiny.

Yet, in a wonderful recurring theme of the oil business, technologies and fresh understandings of shale-gas plays have made Appalachia’s Devonian shale today’s hot ticket. Companies ranging from Texas mega-independents to hometown operators are fervent fans. Even Venango County, the site of Colonel Drake’s inaugural well, is caught up in Devonian shale enthusiasm.

Devonian shales attain thicknesses of more than 2,000 feet in the Appalachian Basin, split into numerous named intervals that interfinger with clastics from the great Catskill Delta to the east.

The size of the resource is phenomenal: in 2002, the U.S. Geological Survey assessed mean technically recoverable resources in the Appalachian Basin’s Devonian shale total petroleum system at 30.7 trillion cubic feet (Tcf) of gas, plus 550 million barrels of gas liquids. Four discrete black-shale units were estimated to contain 12 Tcf; with the advent of current gas-extraction drilling and completion techniques, many in the industry believe the recoverable resource is now far larger.

Obviously, excellent gas prices drive the entire Devonian-shale train. Ready access to the nation’s premier gas market, the Northeast, is another strong mover. Companies see tremendous opportunities to access Tcfs of gas resources at attractive finding and development costs, and to earn solid rates of return in the process.
What was old has become new again.

Huron Breakthrough

The Lower Huron shale is a mighty producer of gas, and has been so for nearly a century. Long before the Barnett shale in North Texas came to prominence, thousands of Lower Huron wells were flowing huge volumes of gas from eastern Kentucky’s Big Sandy Field. Shallow vertical wells, completed in intensely fractured shales and associated sand lenses, have recovered some 2.5 Tcf since 1914.

But the Lower Huron is quite unlike the Barnett. It’s severely underpressured: pressure gradients are just 0.2 psi per foot. Some workers believe the gradient is low because of the Tcfs of gas that have been pulled from the Big Sandy area; others think the great amount of fracturing and faulting in this part of the Appalachian mountain front allowed gas to leak off.

Two years ago, Pittsburgh-based Equitable Resources Inc. launched an effort to drill horizontal wells in Lower Huron shales. Equitable, which was founded by George Westinghouse in the 1870s, produces 220 million cubic feet net per day from the basin.

The company was in the midst of a shift to a new strategy. The old-line Appalachian operator wanted to transform itself from an integrated, utility-style gas company to a strongly growing producer and nimble midstream per­for­mer. It held tre­mendous assets: 3.3 mil­lion acres of Appalachian leases served by a midstream system that laced through eastern Kentucky, southern West Virginia and southwestern Virginia.

But it needed growth, and more growth than it could get from business-as-usual vertical wells.

Its vehicle for change was horizontal drilling. Equitable figured out how to air-drill horizontal laterals in the low-pressure shales that were ubiquitous across its leasehold, and then stimulate those wellbores with multiple treatments.

The success of this technology has been breathtaking. In 2007, it grew its proved, probable and possible (3P) reserves 26% to a total of 7.2 Tcf equivalent (Tcfe). Through 2012, it expects to average a production-growth rate of 12% per year.

“We are a technology leader in the basin,” says Murry Gerber, chairman and chief executive. Since Equitable developed its air-drilling technique in low-pressure Devonian shales, it has drilled more than 200 such tests, mainly in the Lower Huron. This year, it plans to drill more than 300 horizontal wells. It has a dozen rigs at work on horizontal tests, and shortly plans to add another four.
Equitable’s bread-and-butter play is the Lower Huron, which accounts for nearly three-fourths of its 3P reserves. Horizontal wells in this shale deliver five times the reserves of traditional vertical ones. At a cost of $1.2 million, a horizontal well can recover between 750 million and 1.5 billion cubic feet equivalent (Bcfe) of gas. That assumes a 3,500-foot lateral with up to nine frac stages. Recovery efficiencies are 40% for a single-leg horizontal, an exceptional improvement from 8% in a standard vertical well.

Those are numbers that can be taken to the bank. Equitable has 4,700 existing vertical Lower Huron shale wells, and it has modeled and matched the horizontals to assure integrity in the decline curves. “We have a stunningly large database and long time frames over which to make that judgment.”

And the costs could potentially drop further. “Horizontal drilling in low-pressure shales is now more cost-effective than vertical wells,” he says. “And we think we can lower costs further.”
On that front, Equitable recently drilled its first Lower Huron multilateral. This approach relies on many lengths of branched laterals to intersect natural fractures, instead of accessing those fractures through artificial stimulations in a single bore. Multilaterals can work in Lower Huron shales because air drilling is so cheap. The test case, drilled near Hazard, Kentucky, featured 13,000 feet of laterals. The cost was $1 million and first-month production averaged 300,000 cubic feet per day.

The company plans several multilaterals this year. “These geometries could be potential replacements for fracturing in the low-pressured shales. A multilateral can cost $800,000 to $1 million, substantially less than a fracture-stimulated, single-leg horizontal.” Even if recoveries stay flat, there’s significant leverage to costs.

“Effectively, we’re farming this gas,” says Gerber.

Expanding Business

Another company that is developing a horizontal shale program in the low-pressured Lower Huron is Lexington, Kentucky-based NGAS Resources Inc. The firm holds 271,000 net acres, much of it in its core area in eastern Kentucky, just southwest of Big Sandy Field.

“We have more than 1,000 producing wells and nearly 600 miles of gas-gathering infrastructure in southern Appalachia,” says Bill Daugherty, president and chief executive officer. NGAS posted 14% growth in production in 2007; production revenue grew by 16% and gas-gathering revenue by 41% over the reported 2006 levels.

“Each shale is different, and even within a specific area there are significant differences,” says Mike Wallen, vice president. “We are still in the process of analyzing which areas we are going to test first, and how we’re going to run out testing programs.”

3-D seismic is almost impossible in the rough terrain of eastern Kentucky, with the added complication that many of the mountains have been mined for coal. In this part of Kentucky, drilling and testing wells is more cost-effective than shooting seismic.

In NGAS’ area, the Lower Huron is about 80 feet thick. It’s a dark, organic-rich, highly fractured shale. “Drilling in Big Sandy Field has been under way for almost a century, and most of the work now is on the periphery of the traditional activity,” says Brint Camp, vice president, geology. Rock pressures are 75 pounds in the old areas, and it’s been pin-cushioned to the extent that horizontal wells are difficult to place.

Leatherwood Field, where NGAS has kicked off its horizontal program, sits just southwest of Big Sandy. It features depths to Lower Huron from 4,200 to 5,000 feet. Existing wells in the field mainly produce gas from Devonian shale and oil from Big Lime, a Mississippian unit just above the Lower Huron. Pressures run 450 to 500 pounds.

Vertical Devonian shale wells in Leatherwood cost approximately $325,000 each and recover roughly 100- to 275 million cubic feet of gas. Based on Equitable’s experience on neighboring leases in Big Sandy, NGAS expects its horizontal tests will cost between $1- and $1.2 million and recover between 750 million and 1.5 Bcfe.

“We’ll be happy anywhere in that range,” says Wallen. “These are very economic wells.”

To date, NGAS has drilled five horizontals on its acreage. Four are completed and one is drilling. This year, it plans up to 20 Lower Huron horizontals.

There’s another benefit that horizontal wells bestow in this part of the world. Coal is king in Kentucky, and NGAS has frequently had proposed locations denied by companies working coal on the same acreage it wants to drill.

“Since our pay zones are well below mineable coal, horizontal wells offer the company more flexibility, both in surface and subsurface locations,” says Daugherty. “We can plan locations in the valleys below several of the coal seams that are being mined, greatly reducing the amount of coal that would be sterilized with the wellbore of a standard vertical well.”

NGAS is commencing its horizontal completion efforts with nitrogen fracs. Its philosophy is never to let fluids touch the shale. “The Packers Plus-style system has made the biggest difference in completions in horizontal wells in our part of the world,” says Camp. “The costs are lower—we don’t need to run coiled tubing, perforating guns or plugs, and we can keep fluids off the formation.” NGAS even uses nitrogen to seat the balls between stages. (For more on the Packers Plus system, see “Horizontal Resources,” Oil and Gas Investor, April 2008.)

“We are so concerned with fluids because the shale is sensitive, and fluids can cause a lot of problems in low-pressured horizontals.”

From surface to total depth, including a 3,000- to 3,500-foot lateral, NGAS can drill a horizontal well in about 12 days. It orients its laterals to intersect the abundant natural fracture swarms at right angles, which means the wellbores head northwest-southeast in the crinkled countryside of eastern Kentucky. Because oil can be encountered in shallow pay zones, NGAS sets casing through those intervals and then starts its curve.

The company designs its laterals to cut across the entire 80-foot Lower Huron shale section. Steering depends on whether the bore is traveling updip or downdip.

Although NGAS is targeting Lower Huron in this round of drilling at Leatherwood, it also has Cleveland potential on its acreage. The next Lower Huron area it will test is its Straight Creek Field, where the shale is a little shallower and 60 feet thick.

Additionally, the company has holdings on the south side of Pine Mountain Fault. There, the Lower Huron is thicker and deeper than at Leatherwood, but vertical shale wells have been poor performers, primarily due to the additional costs of deeper drilling.

“We have a tremendous amount of acreage there, and plan to drill one or two test wells. Depending on results, we can determine the longer-term plan,” says Camp.

Ohio Action

A new public company targeting Lower Huron is Unbridled Energy Corp. The firm, which is headquartered in Calgary, also staffs an office in Pittsburgh.

“Horizontal shale wells are truly a paradigm shift for Appalachia,” says Joe Frantz, Pittsburgh-based president and chief executive. The company is working Lower Huron in south-central Ohio, where the formation shallows up to depths of about 1,500 feet. Although many wells penetrated the Lower Huron on the way down to Ohio’s popular Silurian Clinton reservoirs, until recently the potential of the shale has not been looked at closely.

Unbridled acquired 25,000 acres in its Ohio Valley project in Jackson County, and sold half the project to Equitable. The partners are leasing in an area of mutual interest that encompasses 11 townships. The area is lively: Cabot Oil & Gas Corp. is drilling successful Lower Huron wells south of the Ohio River in West Virginia, and two companies have five horizontal wells in progress just east of Unbridled’s acreage, and another four vertical tests to the west.

Unbridled and Equitable have kicked off a three-well horizontal program that triangulates their acreage position. Laterals will be 2,500 to 3,000 feet in length, and Unbridled expects to use either straight nitrogen or nitrogen foam in its completions. “We’ll use the Packers Plus assembly to do multiple stimulations, anywhere from six to eight treatments per lateral.”

There is some evidence that the pressure gradient might be more favorable in this part of Ohio than in the southern part of the basin. “Some wells have good surface pressures. We’re in a relatively new area, and maybe we’ll see a gradient as high as 0.35 psi per foot,” says Frantz.

Unbridled plans to drill and frac its first three wells, and if the wells are successful it will immediately begin development work.

A key factor for Unbridled’s selection of south-central Ohio was its proximity to pipelines. One location already has access and the two others are quite close. “We’re a small company and we have to sell gas fast.”

The company also holds 13,000 acres in Chautauqua County, New York, that has potential for more than 300 Medina wells. A thick Hamilton Group shale occurs there that could be prospective; Marcellus shale is present, but thin.

And, Unbridled has started an initial leasing effort in the Marcellus in Pennsylvania and is in negotiations with several operators to joint venture. Frantz is also looking to expand its Lower Huron and Marcellus activities in the southern slice of the basin.

“That’s the nice thing about Appalachia. There are so many shales here. And, there are so many tight-gas-sand targets besides the shales that are good horizontal opportunities.”

Marcellus Money

As successful as Lower Huron horizontals are, what has tantalized the industry is the potential offered by Appalachia’s Marcellus shale.

The Marcellus is a dark, organic-rich shale that shares some key similarities to the Barnett. It occurs across a wide sweep of West Virginia and Pennsylvania, and even edges into New York. It can be found at comparable depths to the Barnett, and reaches similar thermal maturities. Significantly, throughout much of its extent, the Marcellus is normal to slightly geopressured, a key point for many explorers.
Indeed, the Marcellus appears to have all the elements needed to develop into an extensive shale-gas play.

A clear difference between the Marcellus and Barnett is thickness. Compared with 450 feet in the Barnett core area, the Marcellus varies from 50 to around 250 feet. In many areas, it runs 100 feet.

Leasing has been sizzling in the Marcellus, with prices boiling from $5 to some $3,000 per acre (in certain hotly competitive spots) during the past two years. Estimates are that a couple hundred new Marcellus wells have been drilled, mainly vertical. Now, operators are drilling a flurry of horizontal wells, in counties ranging from Susquehanna and Bradford in far northeastern Pennsylvania to Washington and Greene in the southwestern corner of the state, and down into northern West Virginia.

It’s very early in the play’s life, and well histories are short to nonexistent. Announced flow results range up to nearly 6 million cubic feet per day from horizontal wells, although vertical completions in the range of 50,000 per day are not unheard of.

Today, large-scale Marcellus plays are firmly in the portfolios of marquee shale players: EOG Resources Inc., Chesapeake Energy Corp., Southwestern Energy Co. and XTO Energy Inc. The list of companies working the play is long and varied. Cabot Oil & Gas Corp., CNX Gas Corp., Talisman Energy Inc., Penn Virginia Corp. and Atlas Energy Resources LLC, among others, have serious efforts under way. And, new companies and companies new to shale plays are jumping in as well.

Luckily, there’s plenty of room for everyone, since the area prospective for Marcellus covers some 30 million acres.

Shale Trailblazer

The pioneer in the application of modern technology and state-of-the-art exploration thinking to Marcellus exploration is Range Resources Corp. The operator, based in Fort Worth, Texas, has been working the shale for four years.

Range is an interesting mix of a vintage Appalachian operator and an experienced Barnett player. The company has its roots in Appalachia and holds 2 million acres across the basin. At the same time, it ranks in the top tier of Barnett shale producers.

“We have about 1.15 million acres that are prospective for Marcellus,” says Jeff Ventura, executive vice president and chief operating officer. The company operates some 10,000 wells and produces around 134 million cubic feet a day in the basin.

In 2004, it completed its first Marcellus well—in Pennsylvania’s Washington County, where the shale occurs at about 6,000 feet. The next year, it punched three more vertical wells and started its first horizontal. During 2006, it drilled three horizontals and 10 verticals.

Range has now drilled 19 horizontal and 70 vertical Marcellus wells, making it far and away the operator with the most tests under its belt.

The last six months have yielded an impressive string of successful horizontal wells. Range has released results on 15 of its horizontals: “To date, our best well has flowed 5.8 million a day, and our last 10 wells have averaged rates of 4.1 million,” says Ventura. “We’re really excited about these rates, which are comparable to some of the better parts of the Barnett.”

Range has deep experience in the Barnett, and it sees many differences between that shale and the Marcellus. “People try to simplify the trend, but it’s very complex. It’s not just about thickness and fracturing; total carbon content, porosity, gas in place, depth, pressure and thermal maturity all have to be considered.”

Geological differences aside, the Marcellus trend offers Range three solid economic advantages when compared with the Barnett. Appalachian gas fetches a $0.35 premium per million Btu to Nymex prices, versus as much as $2 less than the Nymex price for gas from the Barnett play. Also, royalty rates average 15% in the Marcellus, compared with 25% in North Texas, and Range’s lease bonuses were far lower than in North Texas. The company held a huge inventory of legacy acreage that fortuitously overlays prospective Marcellus areas, and it was leasing selected areas at reasonable prices prior to the current land rush.

In 2008, Range plans to drill 40 horizontal Marcellus wells. It drills single-leg horizontals with fluid, and has been experimenting with various completion assemblies. Multiple slick-water fracs are its preferred treatment in the shale.

In the shallower portions of the play, from 6,000 to 6,500 feet deep, it expects Marcellus development wells will cost roughly $3 million to drill and complete. Deeper parts of the play will require more expensive wells, naturally.

One of the challenges is infrastructure. Appalachia has some of the biggest pipes in the ground running through it, and it’s close to premium markets. The key is gathering—portions of the Marcellus trend are overlain by old producing fields connected to low-pressure gathering systems, and other sections are in virgin areas with no infrastructure.

“This year, we’re building gathering into areas where we have successful wells, we’re continuing to delineate with horizontal wells, and we’re continuing to aggressively lease in select areas,” he says.

“The Marcellus is exciting. There are a number of shale plays onshore in the U.S. that look like they are working, but there are also some that are not working,” he says. “We’re happy that we’ve gotten the kind of traction that we have in the Marcellus.” Certainly, the upside for the company is eye-popping potential in the 10- to more than 15-Tcf range.

Furthermore, Range is active in the Lower Huron play, specifically in its Nora Field area in Virginia. “Our horizontal Lower Huron wells are all air drilled, and we use Packers Plus-type completions.”

Last year, Range drilled its first Lower Huron horizontal, and this year will drill 10 more across its roughly 300,000-acre position in the area. The zone has not yet been developed at Nora, although it has been penetrated by some 90 vertical tests that were deepened below the shallower tight-gas sands.

“With this program, we can potentially derisk 1.5 Tcf net to Range by year-end.”

This being Appalachia, Range also has a number of other shale and tight-sand horizons that are quite prospective for applications of new technology. Those will largely have to wait, however.

“We have a great portfolio and a lot of opportunities, but right now we are focused on the Marcellus shale, the Lower Huron and coalbed-methane potential at Nora, and the Barnett shale,” says Ventura. Range estimates the net unrisked reserve potential from its unbooked drilling inventory and emerging plays ranges from 16 to 22 Tcfe, or as much as 10 times its current reserve base.
“Bottom line, our growth potential has never been greater.”

Barnett Experience

One of the seasoned shale operators from North Texas’ Barnett play that has entered the Marcellus is Chief Oil & Gas LLC.

After Devon Energy Corp. bought Chief’s extensive Barnett shale holdings in 2006, the Dallas-based private firm looked for new projects. It picked two major areas: the Marcellus shale in Appalachia and the Utah Overthrust play.

“We saw the Marcellus as a shale play that shared several similarities with the Barnett,” says Tony Carvalho, senior vice president, geology. “We also liked the idea that it was Devonian in age, instead of Mississippian or younger, and that the play had lots of running room.”

Beyond such usual metrics as thickness, total organic content and thermal maturity, Chief liked the stage of Marcellus exploration. “We lease aggressively, and the timing of the play fit our business model better than some of the competing shale plays.”

Chief has already accumulated nearly 500,000 acres prospective for Marcellus; one of its areas of concentration is Lycoming County, Pennsylvania. This slice of the trend contains some of the thickest sections of Marcellus shale. At an average of 240 feet, Lycoming County’s Marcellus is not too far off the 300 to 400 feet of total shale encountered in many parts of the Barnett play.

“By moving into north-central Pennsylvania, we avoided problems with held-by-production acreage,” he says. “We do think that the whole trend northeast of Pittsburgh has potential, but that part of the play didn’t fit our strategy of early leasing.”

To date, Chief has drilled four vertical wells and one horizontal in Lycoming County and a vertical well in Marshall County, West Virginia. It is currently drilling its second horizontal well. Budgeted costs are $1.5 million for a vertical and $3 million for a horizontal well.

Several striking contrasts to the Barnett are already apparent. Complex structural dips in the Marcellus are sharply different than the average 1.5-degree dip of Barnett strata. Chief, which uses seismic in front of all of its laterals, plans to acquire a 3-D seismic survey in Lycoming County, and considerable miles of 2-D data.

“The terrain is a significant challenge. Shooting seismic and putting in roads is not at all like North Texas. One thing that makes Pennsylvania look very reasonable to us is that our other big project is in Utah’s Overthrust belt.”

Also, the Marcellus appears not to be as rich in silica as the Barnett, which contains 50% to 55%. In Lycoming County, the Marcellus is argillaceous and silica content is about 30%.

“Natural fractures seem to play a much more major role in Appalachia than they do in North Texas,” says Carvalho. “We have two joint sets and a possible problem with fractured top and bottom seals. In some places, we question the presence of top seal at all.”

These factors add together to make the Marcellus a more technically demanding play than the Barnett. “We are changing frac stimulations and completions to deal with intensely fractured, higher-frac-gradient, clay-rich rocks. The complexity of the overall job is much higher.”

On its first horizontal, Chief drilled with air to a point above the Marcellus, then mudded up to cut the curve and land the lateral. It took the hole out about 2,100 feet, and it plans to complete it shortly through cemented liner.

The company has two rigs at work, and will stay at that level for the foreseeable future. Soon, it will move one rig to southwestern Pennsylvania to test the Marcellus in Fayette County. Chief’s leases are spread throughout the play and it is accumulating data to narrow its focus.

“Once we make a discovery, we’ll get another rig for development work. We will run through our exploration program with the two rigs, and then ramp up to prove up individual areas.” Each development area, at least in the northeastern section of the trend, will require infrastructure construction from the ground up. Fortunately, two major transmission lines run through Lycoming County.

“Right now we don’t know where the Tarrant County or core equivalent is, but that’s what we’re looking for.”

More Marcellus

Beyond its extensive holdings in low-pressured shales, Equitable also holds 400,000 acres in the geopressured Marcellus play in northern West Virginia and Pennsylvania. The company has drilled its first horizontal Marcellus test in the pressured shale in Pennsylvania’s Greene County, where the shale reaches 90 feet thick. Currently, it’s drilling a vertical Marcellus test in Wetzel County, West Virginia.

“We think the Marcellus will get developed with a series of horizontal and vertical wells,” says Gerber.

It’s also drilling a vertical Ordovician Utica shale test from the same well pad, projected to a depth of 13,600 feet. The company expects to see 350 feet of Utica at the site. After drilling is complete, it will frac both the horizontal Marcellus and vertical Utica wells with large slick-water treatments.

“We’re building a pipeline to the location, and we plan to test and produce both the Marcellus and Utica,” he says. It’s eager to amass long-term production information on both of the reservoirs.

In 2008, Equitable has slated 12 to 16 Marcellus wells, both vertical and horizontal, spread across its acreage. “We want to identify the best areas for development. The potential gas reserves are staggeringly large.”

USGS Assessment Of Appalachia's Devonian Shale