All may be quiet on the dry gas front, but recent results from the Fayetteville’s first mover show that this shale gas play is still paying dividends and has growth potential to boot.

The Barnett shale may bear the legacy of having authored the shale gas story in North America, but within its Texas-sized shadow stands an equally noteworthy geologic counterpart, the Mississippian-age Fayetteville shale.

This Arkansas shale gas resource has proven that, like the Barnett, it packs an impressive punch – even though the latest heavyweights, South Texas’ Eagle Ford and Ohio’s Utica, have seemingly pushed it to the sidelines for much of this year.

Although the Fayetteville has not been in the spotlight, the play continues to deliver significant volumes of natural gas at a time when the domestic commodity has become a hot-ticket item in the power sector.

According to the Arkansas Oil and Gas Commission, cumulative production from the Fayetteville stood at 2.2 Tcf as of July 2011. With 20 Tcf of recoverable gas in place, this world-class resource will continue to draw investment despite a soft gas-pricing environment.

While low gas prices have steered some operators away from dry gas toward oiler assets, the play’s discoverer believes the Fayetteville is an economically viable target and is carrying on with its long-term development there.

Another Barnett

First mover Southwestern Energy Co. is credited with discovering the Fayetteville shale play, which Jack Bergeron, general manager of the Houston-based company’s Fayetteville Shale Division, says is one of the lowest-cost natural gas resources in the US.

According to Bergeron, in 2002, a team of explorers at Southwestern determined the Wedington sandstone reservoir in the traditional fairway portion of the Arkoma basin in Arkansas was producing far more natural gas than could be reasonably explained by conventional analyses. Further investigation revealed the sandstones sat directly above an organic-rich shale that the team determined was more than likely contributing to the Wedington gas production.

After a nearly year-long study, the team concluded the shale displayed rock and fluid properties similar to the prolific Barnett shale play in the Fort Worth basin in Central Texas, and thus the Fayetteville was born in the hills of Arkansas.

Southwestern subsequently launched an aggressive leasing campaign in early 2003, and in 2004 the company’s Thomas 1-9 discovery well, approximately 113 km (70 miles) east of its Wedington gas production, was successfully drilled and began producing gas from the formation.

Further exploration and development of the Fayetteville has since proved up a substantial and unexpected new source of natural gas reserves in the Arkoma basin.

The tight source rock as identified by Southwestern extends across northern Arkansas from the state’s western edge throughout north-central Arkansas, with the play encompassing more than 2 million acres. Across the field, the shale’s thickness can range from 15 m to more than 168 m (50 to more than 550 ft) and varies in depth from 457 m to 1,981 m (1,500 ft to 6,500 ft).

“What the Fayetteville revealed was that the Barnett shale – the type model for all gas shale plays – was not unique,” Bergeron said, and that another Barnett-like gas resource could compete alongside the famed play.

Currently, Southwestern’s average Fayetteville well costs approximately US $2.8 million to drill and complete, he said. “These costs, combined with the area’s low lease operating costs, result in economics that exceed the company’s internal rate of return hurdle at a Nymex gas price of $4/Mcf held flat for the life of the well,” Bergeron said, adding that other Fayetteville qualities such as its dry-gas nature and relatively shallow producing depths (Southwestern’s average true vertical depth for 2011 is approximately 1,134 m (3,719 ft)) make this a low-cost gas play.

According to Bergeron, the company’s strategy for the Fayetteville is to generate above-average returns while investing within the cash flow generated.

As of October 2011, Southwestern was operating 19 drilling rigs in the Fayetteville shale play, including 12 rigs capable of drilling horizontal wells. (Image courtesy of Southwestern Energy)

Developing the Fayetteville

From the discovery of the Fayetteville in 2004 through yearend 2010, Southwestern has spudded 2,445 wells and estimates it has more than 10,000 additional gross wells yet to be drilled. The company currently holds approximately 916,000 net Fayetteville acres, which, according to Bergeron, is a dominant position in the play compared to Exxon Mobil Corp.’s approximate 550,000 net acres and BHP Billiton Petroleum Ltd.’s approximate 487,000 net acres. This large resource base has provided opportunity to exploit and develop the Fayetteville through economies of scale, Bergeron said, and production numbers tell the success story. Southwestern produced 350 Bcf in 2010 and is projecting its Fayetteville production could be approximately 23% higher in 2011. In the company’s recent 3Q 2011 results, oil and gas production from its Fayetteville operations totaled 111.9 Bcf, up from 92.3 Bcf in 3Q 2010. Because of its strong operating results, Southwestern has revised upward its production guidance for the remainder of the year, with approximately 430 Bcf to 434 Bcf expected to come from the Fayetteville shale.

According to Bergeron, horizontal drilling techniques and hydraulic “slickwater” fracturing treatments have proven to be the most efficient solution for developing the Fayetteville. As the play has moved more toward full-field development, the company operates its own rigs to drill consecutive wells from the same pad, he said. And its multiwell pad development program further provides opportunities for more efficient completion operations.

Currently, Southwestern’s completion operations during the fracture stimulation phase are predominately consecutive operations using “zipper” style techniques (i.e. hydraulic fracturing alternating between two wells, with one well being stimulated while operators on the other well are perforating or setting plugs).

These frac operations are conducted 24 hours a day, seven days a week, Bergeron said.

The company has followed a “vertical integration strategy” to maximize efficiency that has involved:

Using fit-for-purpose rigs;

Gathering its gas production (plus third-party production); and

Establishing its own water resources team that sources

water for fracture stimulation operations.

With water management a primary concern in shale development, Southwestern has constructed 167 ponds that are the property of the landowners and collectively hold 67 MMbbl of water. It also has entered contracts for the use of 250 ponds previously constructed by private landowners that can hold 38 MMbbl. Additionally, the team manages 350 permits for creek and stream withdrawals, allowing for an annual usage of 40 MMbbl.

As part of its vertical integration, Southwestern has formed an internal sand company complete with a company-owned sand mine, which opened in November 2009, that produces the majority of its proppant.

In September 2009, Southwestern also established a Logistics Operations Center (LOC) to manage the movement of approximately 5,000 tractor trailer loads of water, drilling fluids, and proppant per week in the field, 24 hour a day, seven days per week. The LOC also helps to reduce road traffic, which can result in safer roads and more efficient transportation, Bergeron said.

Similarly, the company opened a technical center in October 2010 that collects samples and performs lab analysis on water, drilling fluids, sand, and other earth materials, in addition to natural gas. By performing many of its own services in the play, Bergeron said the company estimates it is saving approximately $230,000 per well.

Efficiency gains

“While the company has been a leading example of how the gains in knowledge and technology in the Fayetteville have bolstered its production and reserves, the amount of work that is still yet to be done, and resulting gains in efficiency, are often overlooked,” Bergeron said.

He noted that unlike many areas where costs are increasing, Southwestern’s cost to drill and complete wells in the Fayetteville have been flat to declining over the past three years. Another example Bergeron cited is the time to drill Southwestern’s Fayetteville wells, where the time from reentry-to-reentry has dropped from an average of 11 days in 2010 to an average of 8 days in 2011.

Citing more than 10,000 gross wells yet to be drilled by the company, Bergeron said there is much more to be learned and talked about regarding what it takes to effectively develop the Fayetteville shale.

“Despite these milestones, the company is not satisfied,” he said, noting that Southwestern will continue to strive to find ways to learn more about how to make this very tight rock more productive for less cost.

Firmly rooted in the Arkansas Fayetteville for many decades, “Southwestern is committed to timely drilling its large inventory of wells while remaining the lowest-cost producer in the play,” Bergeron said.