The latest shale play to take flight is a streamlined version of the resource plays now familiar to the industry. This newest play is young and chock full of rich gas, and its economics are decidedly positive.

Setting the scene

The Eagle Ford shale trends across a great swath of Texas, stretching from Giddings Field in Brazos and Grimes counties down into the Maverick Basin in Maverick County. The Cretaceous Eagle Ford has long been known as a majestic source rock, supplying hydrocarbons to the great Austin Chalk fields and giant East Texas field. Now it is coming into full plumage as a formidable self-sourced reservoir.

The shale takes its name from Eagle Ford in Dallas County. From its surface outcrop, it plunges to depths of more than 14,000 ft (4,270 m) in South Texas. As its depth varies, so does its hydrocarbon content, ranging from dry gas to oil.

These variations, along with internal facies changes, combine to make portions of the Eagle Ford trend particularly attractive to explorers.

Indeed, a couple of areas appear to have all variables aligned correctly to deliver good resource potential.

“The play exhibits considerable heterogeneity along strike, but specific areas already hold viable, commercial potential,” said Robert Clarke, Houston-based lead analyst, Gulf Coast, for international consulting firm Wood Mackenzie.

“This is largely due to a high-Btu production stream and reasonable drilling costs. The Eagle Ford is not likely to grow to be as large as the Woodford or Fayetteville plays, but early analysis suggests it could be very profitable.”

Just a handful of wells produce from the Eagle Ford, and these have all been drilled in the past year. Production histories are lacking.

“But results are intriguing, and production from the early wells seems to be holding up quite nicely,” Clarke said.

Hatching a play

Houston-based Petrohawk Energy Corp. disclosed the Eagle Ford’s potential to the public last fall when it announced a hefty discovery in La Salle County. Since that revelation, interest in the shale has soared.

The company teamed with an independent geologist from Corpus Christi, Texas, to generate the play concept. The initial phase was extensive subsurface analysis of the regional Eagle Ford that was followed by geochemical and petrologic analyses of well samples in the prospective area.

Petrohawk had no previous position in this corner of South Texas, but it liked the prospect’s similarities to the Haynesville shale. The Eagle Ford and Haynesville have comparable thickness, gas-in-place volumes per section, and total organic carbon (TOC) values. In the prospect area, the Eagle Ford was some 250 ft (76 m) thick and occurred at depths between 11,000 and 12,000 ft (3,353 m to 3,658 m).

This piece of the patch had some shallow production, and deep control was sufficient to narrow focus to a particular locality. Immense ranches dominated the land picture, which made it a prime place to quickly put together a sizeable resource play.

Petrohawk began to acquire leases in early 2008 and rapidly pulled together 160,000 net acres. It drilled its first well in Syndicate field in La Salle County near Fowlerton. Last October, it announced its STS-241-#1H as a discovery flowing 7.6 MMcf/d of gas and 250 b/d of condensate from a 3,200-ft (975-m) lateral fractured in 10 stages.

The company confirmed the play with its Dora Martin #1-H, drilled 14 miles (22.5 km) to the west. This well tested 8.3 MMcf/d with no condensate, from a 4,300-ft (1,311-m) lateral fractured in 12 stages.

The Eagle Ford took flight. Petrohawk’s third well, Donnell #1H, probed the eastern side of its acreage in McMullen County — 18 miles (29 km) east along strike from the discovery well. It made 3.6 MMcf/d of gas and 395 b/d of condensate. That was followed by the Brown Trust #1H, drilled in the vicinity of the STS-241-#1H, which made 8.1 MMcf/d of gas and 200 b/d of condensate.

Petrohawk had discovered a field that stretched more than 30 miles (48 km) along strike, and each of its tests encountered highly prolific reservoirs in the Eagle Ford. The company has dubbed its find Hawkville.

“Our field is geologically bounded,” said Dick Stoneburner, executive vice president and chief operating officer. “The Eagle Ford is everywhere, but we’re in a little mini-basin of high-porosity/ high-resistivity facies. It’s clearly a local and very mappable deposit.”

An unusual feature, given remarkable homogeneity in the shale reservoir itself, is the rapid change from dry gas to rich gas and condensate across Petrohawk’s leasehold. “The variances in condensate yield and maturity are a result of different thermal maturity across our position,” Stoneburner said.

To the southwest, core from Petro-hawk’s Dora Martin well recorded thermal maturities of 1.4% Ro. At its STS well in the center of its position, Ro is 1.1%. Vertical depth to the reservoir is the same; company geoscientists surmise that the southwestern portion of its leasehold was once buried more deeply but later uplifted by the Chittim Arch, a Tertiary structural feature that trends into the area from the northwest.

Although the play was predicated on its analogy to the Haynesville, the two shales do exhibit some striking differences.

The Eagle Ford, Cretaceous in age, features a pressure gradient of 0.65 psi/ft and contains lots of carbonates; the Jurassic Haynesville has gradients of up to 0.90 psi and minor carbonates.

“The Eagle Ford’s carbonate content is 70% in some places, and clay content is very low,” said Stoneburner. “It makes completions easier — the Eagle Ford fracs like a dream.”

Certainly, the Eagle Ford is far more amenable to drilling and completion work than the Haynesville. The Eagle Ford does not require large volumes of high-strength proppant. In its Eagle Ford laterals, which are typically 3,500 to 4,000 ft (1,067 to 1,219 m) long, Petrohawk runs about 100,000 pounds of 100-mesh and 200,000 pounds of 40/70 proppant in each frac stage. The operator uses mainly white sand, but it does tail in each stage with some premium proppant.

The company believes potential estimated ultimate recoveries of Eagle Ford horizontal wells will likely fall between 4 and 7 Bcf equivalent (Bcfe) a piece. Drilling costs are plummeting: Petrohawk’s initial horizontal test cost US $12 million and took more than 75 days to drill, while its latest well was drilled for $4.5 million in just 22 days. “We have eliminated a host of costs such as drilling pilot holes and setting intermediate casing,” Stoneburner said. “The pressure is not high, and these are not troublesome rocks to drill.”

The sharply lower drilling and completion costs have immediate effects on the play’s metrics, Stoneburner said. “We are drilling sub-$5 million wells for 5 Bcfe or more. The economics are off the chart.”

Petrohawk’s Eagle Ford leases are split by the Frio River. The company runs one rig on the southwest side of the river and one on the northeast and is phasing in additional rigs that will raise the count to six. Initially, it planned to spend $50 million on the play this year; recently it upped that commitment by $70 million.

According to Stoneburner, it is likely that other areas in the expansive Eagle Ford trend will be found that hold the same prolific facies identified by Petrohawk. “But so far, I think that we have found the best rock.”

This article is adapted from a longer piecethat ran in the July 2009 issue of Oil and Gas Investor.