Even as recently as today, U.S. producers are benefiting from the wisdom of legendary 19th-century newspaper editor, reformer and politician Horace Greeley who once offered the sage advice, "Go West, young man."

Indeed, the Rocky Mountain region is virtually exploding with drilling activity as operators flock to the area to unlock the trillions of cubic feet of gas potential trapped within its unconventional-resource plays.

However, with the recent unconventional gas-resource drilling successes in the Barnett shale in the Fort Worth Basin in Texas, the Fayetteville shale in north-central Arkansas and the Woodford shale in southeastern Oklahoma, producers are now increasingly hearing the call, "Go East!"

There may be much merit to this mindset. One of the bigger operators in all three plays, Oklahoma City's Chesapeake Energy Corp., estimates that to the east of the Barnett-where its leased acreage could hold 4- to 6 trillion cubic feet (Tcf) of recoverable gas reserves-the rich 200- to 300-foot-thick shale sections under its holdings in the Fayetteville may yield ultimate recoverable gas reserves of 6 Tcf while the Woodford might offer up another 1 Tcf.

Houston's Newfield Exploration Co. is even more sanguine about the potential of the Woodford. By that company's calculations, its acreage in the southeastern Oklahoma shale play could hold a treasure trove of 3 to 6 Tcf of recoverable gas, depending on whether its Woodford position is developed on 80- or 40-acre spacing.

Says Lee K. Boothby, president of Newfield's Midcontinent business unit, "When you consider that we are today a 2.3-Tcf company, in terms of overall proved reserves, this means that the Woodford play has the potential to more than double our size."

Such perceived company-maker potential may seem a bit dwarfed when one listens to Houston's Southwestern Energy Co.-the biggest leaseholder in the Fayetteville. After drilling on less than half its Fayetteville acreage, this independent is now convinced that it has exposure to ultimate gross recoverable reserves of 11.2 Tcf.

With such a treasure trove in front of it-which assumes average ultimate gross production of 1.4 Bcf per well and 80-acre well spacing-the operator this year plans to drill and complete 400 to 450 more wells in the Fayetteville at a cost of $925 million, which includes capex for a gathering system. Comparatively, its 2006 Fayetteville spending was around $400 million.

To understand the target that Southwestern is pursuing today in the region is to appreciate how a little serendipity a few years ago played a significant role in the company's remarkable growth in the play.

It all began in 2002 when the operator discovered that its older wells in the shallow Wedington sand-in the northwest Arkansas part of the Arkoma Basin-were actually producing four to eight times more gas than should have been in place in that Mississippian-age sand.

"What we found was that we were getting gas contribution in those old, conventional wells from the surrounding 50- to 70-foot-thick shale sections above and below the Wedington," explains Harold Korell, Southwestern chairman and chief executive officer. "That's when the first light bulb came on."

Still, 50- to 70-foot shale sections didn't seem very prospective. So the company undertook a study of the eastern part of the Arkoma in north-central Arkansas where the majors had drilled deeper wells through the Mississippian to look at the Arbuckle play during the 1970s.

"We found that the shale sections in the eastern part of the basin, particularly in Conway and Van Buren counties, were more than 200 feet thick," recalls Korell. "That's when the second light bulb went on for us-that we had thick shale targets in the Fayetteville, at depths ranging from 1,500 to 6,500 feet."

To unlock the potential of the Fayetteville, Southwestern has mainly focused on drilling horizontal wells, typically with 2,000-foot lateral extensions, so that the wellbore can make more contact with the low-permeability shale rock.

At the same time, the company is using a combination of both slick-water fracs and cross-linked gel fluids in its well completions at various intervals along the laterals to carry pumped sand into the shale reservoirs in an effort to optimize the rate at which gas flows back into the wellbore.

With such drilling and completion techniques, which cost an average $2.3 million on a per-well basis, the operator expects to achieve ultimate gas-recovery rates of 1.3 to 1.5 Bcf per well. Not bad economics in light of the play's gas-takeaway capacity.

Currently, Southwestern's Fayetteville gas output-for which it received an average of some $6.50 per thousand cubic feet in 2006-flows into the Ozark and Centerpoint pipelines, which run west to northeast across Arkansas and ultimately to end-users in the Midwest. In addition, the producer has signed an agreement with Boardwalk Pipeline Partners to build another pipeline system that will ultimately transport Fayetteville gas to Northeast markets.

No one-trick pony in the Fayetteville, Southwestern is also eyeing two other gas-bearing shales within the play: the Moorefield-slightly deeper than the Fayetteville at around 7,000 feet-and the 4,500- to 5,000-foot Chattanooga, a Devonian-age rock that in southeastern Oklahoma is known there as the Woodford.

"There's probably 130,000 net acres in the eastern portion of our Fayetteville holdings where the Moorefield shale might be prospective, so it's a horizon to which we'll be drilling several horizontal wells this year," says Korell. "As for the Chattanooga, which lies under the western part of our Fayetteville acreage, we drilled one vertical well last year to test that shale and it produced like a Fayetteville well initially."

The contribution the multi-pay Fayetteville play might ultimately make to Southwestern's asset base? The company's year-end 2006 companywide reserves totaled a little more than 1 Tcfe; its annual production, about 72 Bcf equivalent (Bcfe). "So the potential of the Fayetteville far exceeds-by multiples-our current reserve and production profile."

Dual-Play Focus

Active in virtually every onshore U.S. gas basin east of the Rockies, Chesapeake Energy Corp. last year grew estimated proved proves 19%, to a record 9 Tcfe, while increasing year-over-year daily production from 1.4 to 1.7 Bcfe. What's particularly notable about this operator is that half its domestic drilling is focused on shales.

It's not surprising, therefore, that in 2005-after studying Southwestern's experience in the Fayetteville-the company began moving aggressively into that play, amassing by the following year some 350,000 net acres it thinks are prospective, particularly in White County in the central part of the Fayetteville fairway, as well as in Van Buren, Conway, Faulkner and Cleburn counties.

The big attraction? Steve Dixon, executive vice president and chief operating officer, says, "We felt that at shallow depths of 2,500 to 5,000 feet, the Fayetteville wouldn't be very costly, that its shale sections were thick enough over such a large area that it could have multiple Tcfs of gas reserves in place, and that the play was repeatable such that we could just drill well after well, build infrastructure and turn it very much into a gas manufacturing-type operation."

That's not all. Since the company is fracing so many different types of shale wells throughout the country, it believes it can leverage that extensive knowledge into better approaches to drilling and completing Fayetteville wells versus competitors that might have experience in only one or two shale plays.

Aubrey K. McClendon, chairman and chief executive officer, says, "Traditionally, the industry had to solve for geological risk every time it went out and drilled a well-but with the advent of horizontal drilling and better completion technologies, such as multi-stage, slick-water fracs, we're no longer solving so much for geological risk as we are engineering risk.

Last year was a relatively modest one for the producer in the Fayetteville. At a cost of $44 million, it drilled six vertical pilot wells to evaluate the limits of the play, 17 horizontal wells with average lateral extensions of 3,500 feet, plus three more horizontals in various stages of completion at press time. In addition, it spent another $25 million to participate in some 140 other Fayetteville wells.

This year, however, Chesapeake is charging ahead in the play with a full head of steam. The producer has budgeted $330 million to drill and complete 125 horizontals while it begins to drive per-well costs down from the $3- to $4-million range to $2.9 million. In addition, it expects to participate in another 100 Fayetteville wells at a cost of $25- to $30 million.

To lower its completion costs, the company points out that, since slick-water fracs require the movement of a lot of fluid per well, it has built its own reservoir north of Searcy County, Arkansas, from which water can be piped to a 50-square-mile area.

Dixon says, "When you're drilling in remote areas as we are, trucking water to and from well locations can get very expensive."

Ultimately, the play will be developed on 80-acre spacing. McClendon says, "That means we can eventually drill about 4,500 new wells, each with ultimate recoverable reserves of 1.6 Bcf. After royalties, we expect to net 1.4 Bcf per well. Multiply that by 4,500 wells and it becomes clear that we've potentially captured about 6 Tcf of gas under our Fayetteville leasehold. So this shale play is very significant for Chesapeake."

The Woodford play in southeastern Oklahoma, however, where the producer has about 100,000 net acres, is a bit more challenging, concedes the Chesapeake chairman. "If all that acreage were productive, and assuming 160-acre spacing, we could drill about 800 wells that might yield ultimate recoverable reserves of about 2 Bcf per well. That would translate into roughly a Tcf of reserves net to us versus 6 Tcf in the Fayetteville and 4 to 6 Tcf in the Barnett in the Forth Worth Basin."

Still, a Tcf here and there is nothing to sneeze at. That's why Chesapeake last year put its toe into the 5,000- to 10,000-foot, Mississippian-age, Woodford by drilling one vertical and one horizontal well-both commercially successful-at a cost of $6 million. Besides this, it participated in another 73 Woodford wells at a cost of $35 million. Says Dixon, "The latter effort was important because it allowed us to save some learning-curve dollars."

And learn it apparently did. The company's 2007 capex for the play is a far more aggressive $60 million, which will allow it to drill between 17 and 20 horizontals in Coal, Hughes and Pittsburg counties-areas it considers the Woodford's sweet spot. Also, it plans to spend an additional $35 million to participate in some 70 wells in the play plus shoot more 3-D seismic to better understand the Woodford.

Lowering Costs

A start-up in late 2004, Houston's Petrohawk Energy Corp. wasted no time getting into both the Fayetteville and Woodford plays. Since that time, it has built up a roughly 10,000-net-acre position in the Fayetteville, mainly in Pope, Van Buren and Cleburn counties, and a 4,000-net-acre position in the Woodford, in both the Arkoma and Ardmore basins.

"Our decision to pursue prospects in the Fayetteville and Woodford is a part of our overall strategy to grow within gassy basins," says Floyd Wilson, Petrohawk chairman and chief executive officer. "These activities are very complementary to our resource-type drilling in the North Louisiana Cotton Valley play and other parts of the Midcontinent.

"So in the case of the Fayetteville and Woodford, it isn't like we're casting off in a new direction. They're simply different plays, new acreage, where we feel we can bring to bear our experience in horizontal drilling and modern frac technologies to create good economics."

A rapidly growing operator, Petrohawk more than doubled its proved reserves in 2006, to 1.1 Tcfe, and when probable and possible reserves are thrown in, the producer looks more like a 3.5 Tcfe company.

In the two plays, Petrohawk's real field experience is occurring in the Fayetteville, where since early 2006 it has drilled five wells to vertical depths of 3,000 to 3,500 feet, with horizontal laterals, encountering shale beds 200 to 300 feet thick.

In early May, three of those wells had been completed and were producing a combined 8.7 million cubic feet of gas per day. In the case of the other two wells, one was being completed while the fifth was being evaluated for a horizontal sidetrack.

"Our first three wells in the Fayetteville appear to be above-average producers and we're anticipating average ultimate reserve recoveries of 2 to 2.5 Bcf per well," says Weldon Holcombe, senior vice president of Petrohawk's Midcontinent region. "Since we operate 18 sections, and we believe there's ultimate recoverable gas reserves of 30 Bcf per section, this means we could be looking at adding 540 Bcf of gross shale-gas reserves on just our operated acreage."

With the average cost to drill each Fayetteville well around $2.5 million, and gas prices where they currently are, the play is very economic, notes Wilson. "However, the challenge for every operator is getting costs down and turning the play into more of a manufacturing-style drilling program that's repeatable, somewhat cookie-cutter, so that there's not a lot of R&D work required on every operation."

To lower costs, Petrohawk is using high-angle and extended-reach drilling technology with polymer- and oil-based muds, says Holcombe. "This allows us to have less non-productive time when drilling-fewer trips, fewer hole problems and less time running casing." Thus, it takes the company only 21 days to move a rig in, drill the well to total depth, run casing and move to the next Fayetteville well location.

In the completion phase of its Fayetteville horizontal wells, the company is using a series of up to eight open-hole packers to isolate each 300- to 400-foot frac stage in the lateral sections of its wells while it sequentially stimulates each isolated section of the formation with very large, high-rate, slick-water fracs, preceding them with acid.

The benefit of slick-water fracs? Wilson says, "They allow you to extend your frac hundreds of feet into the formation so that you can break up more of the rock, thereby allowing for the drainage of a larger area of the formation into the wellbore."

Concurs Holcombe, "One of the keys to economic success in this play will be effectively and efficiently stimulating as much rock as possible, and that's what the packer-system and slick-water frac technologies achieve."

This year, the company is increasing its capex in the Fayetteville to $37 million to drill and complete 27 gross wells. In the similarly thick, 8,000-foot Woodford play, where Petrohawk has participated as a nonoperator through 2006, the company also plans to increase spending to drill eight to 10 well gross wells.

Fracing the Woodford

For Oklahoma City-based Devon Energy Corp., its entry into the Woodford in southeastern Oklahoma in early 2003 was a natural extension of its earlier success in the Barnett in the Fort Worth Basin.

"When we bought Mitchell Energy & Development in 2002, we saw that the technology to get gas out of dense shale bodies as in the Barnett was really opening up," says J. Larry Nichols, Devon chairman and chief executive officer. "And as we developed our knowledge and expertise in the Barnett, where we now produce on a gross basis about 850 MMcf of gas per day-almost half the current gas output from that play-we started looking around the country for other places that would be prospective for shale gas."

The Woodford, particularly in Coal and Hughes counties, looked very attractive, in terms of having the requisite thickness and geologic characteristics to apply the knowledge the operator had gained in the Barnett, he adds. "Currently, we're producing on a gross basis about 32 million cubic feet of gas per day in the Woodford but expect a 2007 exit rate there of 70 million per day and ultimately, about 200 million of daily gross output."

To put this potential contribution in some perspective, Devon produced 214 million barrels of oil equivalent (BOE) worldwide last year, including 815 Bcf of gas. Annualized, the company's Woodford gas output could reach nearly 73 Bcf.

With about 70,000 net acres under lease in the play, Devon is targeting Mississippian-age shale rock at depths ranging from 6,000 to 10,000 feet. "It's a pretty rich black shale, the thickness ranging from about 140 to 175 feet," says Stephen J. Hadden, Devon senior vice president, E&P. "Potentially, the gas reserves under our acreage could be as much as 1 Tcf."

Since 2004, the producer has drilled 35 horizontal wells in the play, each costing around $4 million to drill and complete. Last year, with a capex budget of $80 million for the Woodford, it drilled 21 of those wells. Comparatively, the company plans to spend about $140 million to drill and complete upwards of 50 more horizontals this year. The average initial production from each well drilled is about 3 million cubic feet per day and Devon is estimating ultimate recoverable reserves of around 2.5 Bcf per well.

"As we learned with the Barnett, matching the right frac technology with a particular reservoir is always important when it comes to unlocking the optimum value in shale plays," notes Hadden. "Early in the Woodford play, we tried some gel fracs, but later moved to slick-water fracs. We found them cheaper and more efficient, in terms of getting better production performance."

Slick-water fracs, he points out, allow for higher pump rates and higher volumes of water and sand to penetrate a targeted formation such that an operator can optimally extend the fracture system and get more of the formation's gas flowing into the wellbore. Put another way, the water pressure of the frac shatters the rock in the formation, creating millions of avenues for gas to escape from the rock into the wellbore.

Another value-added technology Devon is bringing to bear in the Woodford is 3-D seismic. "Being able to image a reservoir in great detail before we drill helps us avoid geological hazards that might be present in a shale formation and determine the optimal locations to position our horizontal wells," explains Hadden.

In the completion phase, the operator is also employing micro-seismic technology. "It's a tool that allows us to track and map the path a frac job may take in a wellbore-such that we can actually see how the frac is being distributed in a reservoir," he says. "In short, it provides a good picture of how effectively we're completing a well."

To handle the increasing amount of production that will result from Devon's stepped-up horizontal drilling in the Woodford, the company is continuing to expand its gas-gathering system in the region and is constructing a gas-processing plant with the capacity to handle 200 million cubic feet per day. Additionally, it has made a volume commitment to the Boardwalk Gulf Processing Pipeline project in southeastern Oklahoma that will give the producer about 1.6 Bcf per day of takeaway capacity to transport its gas from both the Woodford and the Barnett shales to markets in the Northeast and Southeast.

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