At the single largest unconventional oil and gas conference in the U.S., one might expect that the dour economics of low commodity prices would dominate conversation. But that would be only partially correct.

In a speech opening the DUG Eagle Ford event, held in San Antonio in late October, Greg Leveille, ConocoPhillips’ general manager for unconventional reservoir technology, admitted that “production growth is taking a timeout due to the oil price collapse.” He was upbeat, however, about the potential for emerging technology to bolster production over the next several years.

Leveille said the company now has just six rigs drilling in the Eagle Ford. But rig count and actual production are two different stories, he pointed out. Like a staircase, production in South Texas has climbed during the past five years, peaking this past summer at 1.5 million barrels (MMbbl) of oil per day, he said. Today, the South Texas shale’s yield is three times that of Alaska and three times that of California. In other words, the Eagle Ford will be a big-time player for years to come.

Built-in factors feed this success, Leveille said: exceptional geology, particularly in the sweet spots, and a host state with a strong oil heritage where regulations are favorable toward producers. Those producers are improving drilling and completion efficiencies and successfully paring costs, aided by rapid technological advancements, he said.

Technology implemented in the Eagle Ford has room to run. “In the next five years, we will see the same amount of technological progress that we saw in the previous five years,” Leveille said. “Even if oil prices do not rise, we can still make this a vibrant industry—if we make the right choices.”

The Karnes Advantage

Operators outlined strategies behind some of the Eagle Ford’s most significant production advances, with new pockets of opportunity, such as Encana Corp.’s Kenedy area wells in Karnes County, continuing to surface. Jeff Balmer, general manager of Encana’s western operating area, said recent wells there were “outperforming” and that Kenedy was proving to be an “absolutely outstanding area” among the company’s Eagle Ford holdings.

“The Kenedy area is the best area we have,” he said. “We wish we had 100 times more inventory there.”

The Eagle Ford is one of Encana’s four “strategic” assets, and it has a current-year budget of $500 million to $600 million. Balmer summed up the play’s superior qualities as “better wells, lower costs and an increasing inventory.”

Encana plans to bring some 70 to 80 net wells onstream in the Eagle Ford this year. Production averaged 57,000 barrels of oil equivalent per day (boe/d) in August, up 25% from second-quarter 2015 levels, with liquids making up 85% of output.

“I anticipate nothing but good growth opportunities in the Eagle Ford, both in what we know already, and what we’ll discover over the course of the coming year to two years,” said Balmer.

The Kenedy area is one of three development focus areas for Encana in Karnes County, Balmer said. Using a modified choke schedule, recent wells have been brought on gradually and, after 60 days, are in some cases still making 1,500 to 1,600 boe/d, with “really flat declines.” The play runs northwest to southeast, getting a little deeper as it moves south. While the oil produced in the northern section is 40 degree gravity API, it improves to more than 50 degrees in the south.

Encana’s two additional focus areas in Karnes County are Graben and Panna Maria. Balmer described the Graben as being “structurally complex” but cited a recent well—the best yet in that area—that flowed 800 to 1,200 boe/d in the first 30 days, an increase of about 400 boe/d over the rate of three nearby wells that came on at 400 to 800 per day. In terms of completions, other wells in the Graben area have benefited from keeping fracture cluster spacing below 50 feet, he noted.

The Graben area is “slightly more challenged but still a great place to be,” he said.

In addition to its Graben program, Encana plans to drill up to four Upper Eagle Ford tests (in contrast to the primary target in the Lower Eagle Ford) in the fourth quarter, with results expected in early 2016. It has drilled two of these to date.

Tests of the Austin Chalk are also a “possibility,” Balmer said.

Excluding the Austin Chalk, Encana’s well inventory in the play is up 50% since its May 2014 Eagle Ford acquisition from Freeport-McMoRan Copper & Gold Inc. for $3.1 billion.

In the interim, Encana has focused on trimming drilling and completion costs. Relative to fourth-quarter 2014, when D&C costs were running $7.4 million, it has reduced those costs by $2 million to a sum of $5.4 million as of August for a 5,000-foot lateral well. And, the company reports its Eagle Ford wells’ EURs are 400 to 900 thousand barrels of oil equivalent (Mboe), up from 250 to 800 Mboe at the time of the acquisition.

Encana plans to run two rigs in the Eagle Ford through the end of the year; the use of Pacesetter rigs has shaved time-to-drill to about 9.5 days, Balmer said.

The company has few reservations about its big acquisition in the shale. “If Encana had a chance to do it all again, we absolutely would. It’s a fantastic place to be,” Balmer said.

Austin Chalk Wine Rack

More than one speaker made it clear that Karnes County, Texas, is not only about the Eagle Ford Shale. BlackBrush Oil & Gas LP’s COO, Mark Norville, said that adding a little Austin Chalk into its recipe has given well results an IRR kick to 250%.

The San Antonio private producer told attendees it is co-developing the two zones along the Karnes Trough on four-well pads. It places two wells in the Eagle Ford at 300-foot spacing and staggers another two in the Austin Chalk zone above, at 300 feet, each separated by about 150 feet. It’s known as a “wine rack” pattern.

A year into production, the Eagle Ford wells show EURs of 740 Mboe, while the Austin Chalk wells trump that at 890 Mboe. Measured against $65 oil and $3 gas prices, the economics sing: 245% and 263%, respectively.

“In everything we’re doing, we’re combining the Eagle Ford and Austin Chalk,” said Norville, “which we feel the numbers show you should develop … together in this region.”

BlackBrush holds 66,500 net acres (239,000 gross) in various parts of the Eagle Ford play but is actively drilling at the northern end of Karnes County. Ares Management recapitalized the company in early 2015.

While the Austin Chalk has produced some 838 million barrels (MMbbl) of oil in 40 Texas counties over the years, Norville said the Austin Chalk is “basically still unexplored” where it overlaps the condensate and oil windows of the Eagle Ford. “There is still a huge area that is untapped.”

Before the recapitalization, BlackBrush had tested two short lateral wells in Karnes County at 800 and 1,700 feet each. In three years, the wells cumulatively produced 110,000 and 234,000 bbl of oil each, double the boe per stage of vertical wells previously.

In early 2015, the company drilled two long-lateral Austin Chalk wells with an average length of 4,200 feet with 19 stages and “Eagle Ford-style” fracks. Those wells had average initial production rates of 2,200 bbl/d and 3.77 MMcf/d, with average cumulative rates to date of 320 Mbbl and 750 MMcf.

“In the first 200 days, those wells are outperforming the short laterals, and we’re assuming right now about 90,000 boe per stage in the Austin Chalk,” he said.

Subsequent wells have tightened stage spacing to 225 feet from 300. Proppant loading has increased from 700 pounds per foot to 2,500, and from 90 bbl of water per minute to 100, using 100 mesh sand. The frack design has boosted EURs to 890 Mbbl per well.

“Both of these [Eagle Ford and Austin Chalk], at $50 per barrel, are in the 250% IRRs [range],” Norville said.

BlackBrush currently is drilling or leaving uncompleted eight wells in the Austin Chalk on co-development Eagle Ford pads. The company contributes a quarter of the Austin Chalk production in Karnes County currently.

Downhole microseismic indicates “great connectivity” between the Austin Chalk and Eagle Ford Shale with the co-development, Norville said, but he has concerns the results wouldn’t be the same if the Austin Chalk were developed later.

“If you go back at a later date, you could see problems with that fluid influencing the Eagle Ford. If you’re going to get the best of the reserves, you need to do it at the same time,” he said.

Norville sees opportunity to co-develop the Upper Eagle Ford Shale as a third bench in a similar wine-rack design.

Extending The Runway

Surviving the downturn for some operators—particularly the smaller ones—depends on how far they can extend their operational and cash runways. Lowering D&C costs is the solution in most cases.

Halcón Resources Corp. has done that in El Halcón Field, its East Texas portion of the Eagle Ford in Burleson and Brazos counties.

At the DUG event, Halcón president Steve Herod said that a year ago, the company’s Eagle Ford individual well costs were $9.5 million. But since then, costs have dropped substantially: “pipe, tank batteries, consultants; rope, soap and dope,” he said. “So now, we are spending about $6.75 million [completed] for a three-string well.”

Three-well pad drilling is expected to further lower costs to under $6 million on a consistent basis. “We’re going into full pad development,” he said.

Halcón’s drilling group has more than 100 wells under its belt. “Every time I think our drilling group has hit the max on efficiency improvements, they are able to go a bit further and reduce the spud-to-rig release time another three or four hours,” Herod said.

A year ago, the DUG Eagle Ford discussion would have centered on completions: how to space frack clusters, how much sand to use, for example. “Now it’s about all these meetings with your bankers,” he said. “We’ve done a lot actually to help extend our runway.”

The company’s El Halcón Field is east of the main Eagle Ford fairway and consists of 100,000 net acres and proved reserves of 41.7 MMboe. About a third of the company’s total production comes from the Eagle Ford with the rest originating in the Bakken Shale.

Halcón has only one rig running in El Halcón but the quality of the rock is significant, Herod said.

“You could put a rig in [Texas A&M’s] Kyle Field’s end zone and probably make a 1,000-bbl/d well,” he joked.

In 2014, Eagle Ford operators were running 216 rigs, according to Baker Hughes Inc. That had fallen about 64% to 77 rigs as of October.

The shale produces about 1.8 MMbbl/d currently. With the downturn in oil prices, the latest data show a reduction of about 62 Mbbl/d in September alone, Herod noted. “I have to think this 70 or so rig count is going to be here for a while and production will come down.”

With one rig working in the second and third quarters, Halcón expected to have spudded 12 to 15 gross operated wells by year-end in El Halcón. It spudded four wells and brought eight online during the quarter ended June 30, and on average, the performance is in line with its type curve of 452 Mboe on a per-lateral-foot basis, Herod said.

The company expects completed well costs to decrease by as much as $1 million more per well in the near term as it transitions to development mode and multiple wells per unit/pad.

Comments