Operators are increasingly proving an oily, Eagle Ford-play extension northeast of the original play's core.

"It seems like a lot more people are starting to get it,” Steve Herod, Halcón Resources Corp. president, said of investor understanding about the extension’s potential. “The momentum is definitely picking up. It’s not just us [drilling it].”

Anadarko Petroleum Corp., Apache Corp., Clayton Williams Energy Inc., SM Energy Co., Comstock Resources Inc. and privately held operators have rigs at work in the area as well. “They’re starting to talk about it more.”

West of the San Marcos Arch, where more than 5,000 oil wells have been made in the Eagle Ford now, the formation underlies the Austin Chalk and sits above the Buda Limestone. Moving east of the arch, into Fayette, Bastrop, Burleson and Brazos counties, the upper and lower Eagle Ford reappear.

Apache has more than 10 lower-Eagle Ford wells east of the arch now in Burleson and Brazos counties in the heart of the old, Austin Chalk-producing Giddings Field, whose abundant oil pay is partially self-sourced and partially sourced from the Eagle Ford beneath. It plans to spend $300 million on the Eagle Ford program this year in its 182,000 net acres, with four rigs running to drill more than 40 wells gross, it reports.

Its Stasny-Porterfield 1H came on with 728 barrels of oil equivalent (boe) in a peak, 24-hour test from a 5,515-foot lateral; its Stasny-Porterfield 2H, with 597 boe from 5,303 feet of lateral. Its Leone 2H came on with 611 boe and averaged 257 bbl/d in its first 30 days from a 4,747-foot lateral; Reveille 7H produced 535 bbl/d in its first 30 days from a 4,909-foot lateral.

Meanwhile, Halcón, which has 100,000 net acres in the Giddings Field area, expects it has more than 1,000 drilling locations at 800-foot spacing. This year, its plan is to spud some 50 gross wells with three rigs at work. It has reduced drill days to about 12 and to as few as seven for a 7,400-foot lateral in its Ridgeback 1H and a 6,500-foot lateral in its McDonald 2H.

Frack days are three or four. Drilling cost is about $3.7 million for some 7,600 feet of lateral; with the completion, the wells cost some $9 million to $9.5 million each.

The company believes it has delineated the core of the east-of-the-arch Eagle Ford play with its well results and data from old wells that had been drilled through the formation for pay from Buda, said Charles Cusack, CEO.

“There are hundreds of control points. It is peppered with Buda wells,” Cusack said. “That’s what enabled us to go in there, describe the reservoir characteristics and have a very high degree of confidence in where the core area—the sweet spot—is. That’s where we’ve concentrated our acreage acquisitions.”

At the northern end of its position in Brazos County, Halcón’s Javelina 1H came on with 1,171 boe in February; its Wombat 1H, with 839 boe in January. In the middle of its position, at the border of Brazos and Burleson counties, Reveille 1H came on with 1,416 boe in March and Stasny Honze 1H with 1,262 boe last August. At the southern end in Burleson County, Stifflemire 1H came on with 1,066 boe in March.

From its leasehold, the pay is about 90% oil and the pressure gradient is 0.65 to 0.7. “It’s very commercial. We’ve drilled over 60 wells in the Eagle Ford,” Cusack said.

Wells are being landed in the bottom section where the rock is about 41% clay, 22% calcite, 13% quartz and 16% dolomite. The clay isn’t swelling clay, though, Cusack added. “And that’s good news. It’s one of the main reasons it works very well.”

Apache estimates a 7,000-foot lateral drains 160 acres at 1,000-foot spacing, and that net pay— the lowermost Eagle Ford section—is 45 feet thick in its leasehold. Its shorter-lateral wells are costing $8.3 million each. EUR apiece is 330,000 boe, 56% oil and 31% NGL. Its working interest is 100% and its net revenue interest, 80%. Its rate of return is 25% at $90 oil and $27 gas liquids.

The eastern Eagle Ford is more similar than dissimilar to the western Eagle Ford, said Cusack, who, with many other members of the Halcón team, founded the western play in 2008. “It’s slightly lower porosity and slightly higher clay content [which consumes some of the pore space], but it’s about the same overall thickness,” he said.

Halcón is spending more on its wells than other operators by drilling longer laterals; it estimates its wells have an EUR of 452,000 boe. “We drill and complete our wells differently so our costs are higher, but our EUR is higher,” Herod said. “We’re looking at the whole package. What’s the rate of return? What’s the PV-10? You can ‘poor boy’ it, if you want to, but you don’t get nearly as much [return].”

For propping the rock, which is at about 9,000 feet, sand is of sufficient strength, Cusack added. But because the eastern Eagle Ford is more brittle, more sand is needed—1,500 pounds per foot or as much as 5,700 tons per 7,600-foot lateral. “It has a higher proppant intensity and a longer lateral.”

Frack stages are about 300 feet apart. In April, production was some 9,300 boe per day, net to Halcón.

For years, the eastern Eagle Ford has been drilled through by wells on their way to deeper pay. “What makes this work now is the completion design,” said Cusack. “We believe 100% of our acreage is in the core of the play. We have very consistent results across our entire position in Brazos and Burleson counties.”

Herod said, “We think we’ve de-risked all of it now. The investment community hasn’t recognized that yet. We’ve established that it is repeatable and we’re making really good wells for good, economic cost.”

New chalk walls

In some of its leasehold, the company has rights to the overlying Austin Chalk and underlying Buda. But, Herod said, Halcón’s work will focus on the Eagle Ford. The chalk, hosting more than 10,000 wells now in its roughly 80-year history, and the underlying Buda are both naturally fractured, hit-or-miss plays in the Giddings Field area.

“For what we’re trying to do as a company,” Herod said, “the chalk and the Buda are not going to do anything for us. The Eagle Ford is what is repeatable from well to well to well.”

Cusack added, “We have a couple thousand locations to drill in the Eagle Ford. A couple dozen wells in another formation just doesn’t move the needle for us.”

For privately held Enervest Ltd. and its MLP, EV Energy Partners LP, however, the chalk continues to push the distribution-paying needle for its business model. And, changing up some of its new-well completions, it is demonstrating some bonus chalk-pay potential.

Beginning in 2007 with an acquisition from Anadarko, EnerVest and EVEP have accumulated some 800,000 gross, held-by-production acres for about $900 million in Giddings Field and the area, including from Marathon Oil Corp., ExxonMobil Corp. and other operators. EVEP owns a roughly 14% interest in the chalk area with EnerVest funds owning the balance.

Where the chalk is oily, EnerVest is re-entering old chalk wells and fracking them; in areas where the chalk is less naturally fractured, it is drilling new wells and fracking them.

Dave Kyte, senior vice president of EnerVest Operating Co. and head of its Austin Chalk portfolio, began work in the play in 1990 for Union Pacific Resources Group Inc. as it and others were converting it to horizontal wellbores. Anadarko bought UPR in 2000 and Kyte joined EnerVest in 2007 when it bought the leasehold from Anadarko.

EnerVest and EVEP are getting a 50% rate of return from re-entering old wells and drilling new ones, said Mark Houser, EVEP president and CEO. “Dave and the team have been working the chalk a long time. We’ve seen, year after year, that it is just a real cash machine. There is a ton of hydrocarbon in place. With new technology coming in and being able to reinvent these wells, we continue to increase the recovery.”

Kyte said the new-well play is where the chalk lacks as much natural fracturing. “We felt like we could step out and enhance some of these fractures.”

In the past, water fracks--pumped at as high a rate as possible in the horizontals—worked in one area of the play. “We said, ‘Well, if we can go in and, instead of just pumping one frack with a cemented liner, maybe we can put in six or eight packers and pump more fracks with an uncemented liner. Maybe the program would work.’

“That’s pretty much how it has evolved. At UPR, we always thought there was a lot more recovery potential.”

The re-entry wells cost about $1 million each; the new wells, about $6 million, tapping the chalk’s matrix porosity that is up to 8% and is mostly about 3% to 5%.

“With the water fracks, the laterals had not been cased, so the water took the path of least resistance to extend some of these natural fractures to intersect other ones. It worked in some areas and, in other areas, it didn’t work at all,” Kyte said.

Dentritic fracturing was used to displace the oil by injecting water, causing the oil to rise to the wellbore. Also, some of EnerVest’s re-entries apply the “inhibition” technique in which water is used to displace oil that is stuck where the chalk is tighter. “We shut the well in for a couple of weeks and, when we bring it back on, we get a tax credit [from the Texas Railroad Commission] for the incremental oil.”

But the modern staged frack is indicating all new potential from the chalk, Kyte said. “With these big, natural fractures, you couldn’t get a good cement job because you had nothing to contain a conventional frack. You could pump as high a rate as you wanted and there was no pressure increase. You weren’t initiating new fracks. That was the problem.”

EnerVest in the Eagle Ford

Shortly after acquiring the Anadarko position, EnerVest and EVEP formed a joint venture with Apache, in which Apache gained drill-to-earn rights below the Austin Chalk in the more than 400,000 acres. Apache was aiming to test the Eagle Ford in the area. Its vertical W.H. Giesenschlag “C” 1 came on with 133 bbl/d in February 2008 and made 4,800 bbl in its first five months online—or about 32 bbl/d.

“At the time, frankly, the completion technology didn’t work,” Kyte said. Apache let it lie, but returned to EnerVest to reattempt it. Houser said, “We were getting an override until late last year. We reconfigured the deal so we’re 50/50 partners with them. It was a win/win because it gave us more leverage in the play and it gave them a better netback.”

EnerVest will participate in up to 50 Eagle Ford wells this year with Apache and other operators. It also plans to drill one of its own. Kyte said, “The Eagle Ford varies across our area from 100 feet to several hundred feet thick, but the zone—the lower Eagle Ford—that is being targeted is the same zone that is being targeted to the west.”

EnerVest has participated in eight Eagle Ford wells to date. Houser said, “Right now, we’re estimating we are going to participate in 40 wells this year with Apache, Halcón and others. We have so much acreage and there is a lot of activity. I was out with an investor near College Station and I counted six rigs drilling the Eagle Ford within two miles.”

The modern, upside potential from the legacy, producing properties it has purchased over the years is a bonus to EnerVest and EVEP as technology advances, he added. The companies are also in the Utica liquids and Gallup oil plays via acquisitions of properties producing from other formations in the Appalachian and San Juan Basins.

Houser said of the Eagle Ford and new chalk opportunities, “We try to build consolidated positions and this is one of those where we built a dominant position and, once you get into a really good position, good things can happen.”

With more than 5,000 wells online now for Eagle Ford pay west of the San Marcos Arch, operators with acreage east are proving an economic Eagle Ford play there as well.

New east-of-the-arch Eagle Ford wells are targeting oil pay in the legacy, Austin Chalk-producing Giddings Field and nearby area.

The upper and lower Eagle Ford reappear east of the San Marcos Arch in the East Texas Basin where the lower Eagle Ford remains organic-rich.

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