Optimizing The Eagle Ford

In the heat of $100 oil, 81% of the Eagle Ford Shale play was economic, according to Drillinginfo CEO Allen Gilmer, and “that’s pretty outstanding.” In the cooler days of $50 to $60 oil, while rigs along the trend have thinned by half, “the rigs are still focusing in those same areas as they have in the past—we’re not seeing a ton of migration,” he said.

Gilmer estimated some 75% of the Eagle Ford remains economic at current prices for “best in class” operators, while 45% to 50% of the geography holds up for average operators.

Even in today’s constrained economic climate, the best of the Eagle Ford still trends along the condensate/black oil window from the Karnes Trough in DeWitt and Karnes counties, Texas, down through McMullen and LaSalle counties. “We’re seeing activity stay strong inside that condensate area,” Gilmer said.

SunTrust Robinson Humphrey analyst Will Derrick said the most economic portion of the Eagle Ford is one of the top three plays—if not the absolute best—in the U.S., along with the premier positions in the Permian and Utica.

“The Eagle Ford has probably one of the most economic rates of return in North America, primarily because the wells are largely oil-based, and it’s more mature than other plays. The maturity means the play is much further along that curve of operational efficiency, so operators can really benefit from lower service costs and quicker drilling and completion times.”

The operators that have achieved “shale scale” with efficient operations are able to realize 30% and better returns—even in the current environment, he said, and rig adds could be coming in the third quarter. But for those operators with less advanced operations, “adequate returns are tough to achieve,” he noted.

Gilmer said the competition for big iron and crews within the Eagle Ford before prices softened means service cost reductions have come quickly. “That’s where you’re seeing a true 30% cost cut now.”

Operators Sanchez Energy, Encana Corp. and Carrizo hold acreage up and down the Eagle Ford trend.

So how resilient is the Eagle Ford to commodity price weakness?

“It’s close to the lowest breakeven of any of the resource plays out there,” said Andy Agosto, vice president of business development for Carrizo Oil & Gas Inc. “The great thing about the Eagle Ford is that the strong economics and the predictability of the results allow us to navigate through these volatile times and keep the company’s financial metrics in check. We can be nimble.”

Steady ahead

In the eyes of Wells Fargo Securities analysts, Carrizo’s 82,500-net-acre position in the Eagle Ford’s oil window is among the best, not just in the basin, but globally.

“It is a world-class asset with 80% of inventory having a NPV-10 breakeven of less than $43 per bbl WTI,” said Wells Fargo analyst David Tameron in a June report. “The company has a 16-year inventory at current rig level, with location count headed higher. …Enhanced completions, downspacing and continued efficiencies all provide additional upside potential in our view.”

While Carrizo’s portfolio features top positions in the Niobrara, Delaware Basin, Utica and Marcellus plays, the Eagle Ford commands the lion’s share of the Houston-based company’s capex program this year, with $375 million targeting the play. “It is clearly—now and into 2016—going to be the primary asset for the company,” said Agosto. “We view it as the premier asset in the industry right now.”

In spite of the oil price degradation year-over-year and a 28% capex trim in the basin, the company has maintained its three-rig program, predominantly in LaSalle County, Texas, with guidance to grow companywide crude oil production by 18% year-over-year. Although the company planned to ramp activity to five rigs before the downturn, Agosto said the current low-oil-price environment is an opportunity to experiment and maximize performance, teeing up a more efficient program in advance of an acceleration.

“The real focus shifted from aggressive growth to looking at the assets and how we can get more out of them,” he said. “In 2015, as service costs are low, we feel that gives us a unique opportunity to try some things at low cost. We’re looking at a broad range of different techniques and strategies that hopefully will drive up EURs and well profitability.”

First, costs to drill and complete a long-lateral Eagle Ford well have dropped from $7.5 million in late 2014 to $5.6 million presently, a combination of a 19% reduction in service costs as well as cost efficiencies derived from operations. Over the past year, Carrizo traded out its entire rig fleet for custom-built third-generation rigs, reducing drilling times. “We’re now routinely drilling and casing wells in less than 10 days” on an average 6,100-foot lateral, Agosto said. “That strategy has worked out well.”

Completions are experiencing similar efficiencies. Agosto cited the work Carrizo has done as its dedicated Halliburton frack crew has pushed completed stages north of seven per day, “which is industry-leading. We’re almost double the stages per day than what we were when we first started.”

The other side of completions is ultimate recoveries and overall economics. Carrizo is testing Halliburton’s Biovert technology, as well as pumping up to 2,000 pounds per lateral foot of sand in some wells. Results are anticipated in the third quarter.

Also, by deploying a log for each lateral, so-called “engineered” completions attempt to target the most productive rock along the lateral length for stimulation—and bypass low-quality zones. Where before Carrizo completed a stage every 240 feet, now it is testing the potential of “using the data to determine where we put our perfs and where we inject the water and sand.”

Additionally, the company is employing cutting-edge microseismic technology. “That allows us to look at microseismic on a multiwell pad in every single stage on every single well that we frack, so we get much more data than the traditional method,” Agosto said. Results are pending.

Carrizo has worked down its downspacing pattern to 330 feet between wells on the majority of its acreage, but now it is testing a “stagger stack” concept in the Lower Eagle Ford Formation to further increase potential drilling locations. “We are very confident that stagger stacking in some configuration is going to work. Whether it adds 30% or 80% to the location count, time will tell.”

At 330-foot spacing for each layer, the effective spacing is 165 feet apart, he said. “There may be some degradation in unique EUR per well, and that may be OK, if from an overall reserves and net present value standpoint it makes sense.” The company will also look to infill this multilayered concept in areas already drilled.

Add to that, at press time, Carrizo was drilling its first test into the Upper Eagle Ford reservoir. “Our hope is that an Upper Eagle Ford well is going to look very much like a Lower Eagle Ford well,” he said.

Carrizo currently publishes its net locations as 954, but vice president of investor relations Jeff Hayden said that number could double without adding acreage. “If you were to layer in everything—full 330-foot spacing, stagger-stack, the Upper Eagle Ford—you could get to a number north of 2,000 net locations. We’re very excited about the potential to increase the inventory.”

Added Agosto, “That’s why, in terms of stagger-stacking and completion technologies, we’d like to get it right as quickly as we can so we can apply those lessons to all those remaining wells.”

Carrizo manages its initial production (IP) flows at between 500 and 600 bbl/d per well, keeping them flat for the first two to three months. On an open choke, the wells could flow more than 1,000 bbl/d in some cases, Agosto said, but the company is not focused on high IPs. The EUR is 510,000 boe, generating a 34% IRR at $55 oil.

The Eagle Ford garners nearly 80% of Carrizo’s total drilling and completion capex currently, and “through at least 2016, it’s going to be our major area of activity,” he said. “Given the combination of the oil we produce, the good netbacks, capital costs and the reserves, this is still the best play to be in of all the resource plays in the U.S. We’re fortunate to have such a large percentage of our upside in the Eagle Ford.”

Maximizing NAV

Of the top three oil plays, the Eagle Ford’s proximity to Gulf Coast refineries gives it an advantage over the Bakken, and it has an advantage in its maturity compared to the Permian’s horizontal plays, said SunTrust’s Derrick, who follows a number of Eagle Ford operators. “We feel it’s top-tier.”

The most active companies have already figured out what they believe is the best way to drill it, and although they may tweak it, generally “the play is in pure manufacturing mode,” Derrick said, “where they’re just punching out wells one after another.”

That’s not to say improvements can’t be made while in motion. “It’s a game of maximizing the NAV, essentially,” he said. “At this point, operators are looking at optimizing their inventory to get the best net present value.”

The drive to maximize NAV has created a contrarian result, though. “As companies look to optimize their inventory, some are considering looser spacing and getting the higher EUR, because the price is lower and doesn’t justify cramming your wells together to get the higher economics at the expense of lower recovery. You might give up 10 acres on spacing to get that higher EUR.”

Derrick noted the Eagle Ford companies covered by SunTrust have maintained their level of activity from last year, although some had plans to accelerate before the price fall.

The benefit of continued drilling versus stepping back, he said, is they continue to improve processes and drilling and completion techniques. Then when they move into areas adjacent to their core, “they’re finding the economics to be much better than when they went in last time.”

Derrick observes average IRRs along the Karnes Trough “well north of 50%” in today’s climate, and around 30% near Carrizo’s package in LaSalle County as well as in part of Sanchez’s position in Dimmit and Webb counties. Trending into the wet gas window, though, IRRs drop to the 20% range, due to soft NGL prices.

“We believe the economics today in the wet gas are not nearly as good as six months ago, but continue to believe the volatile oil window in LaSalle through Karnes is the most economic area. As you continue up into Gonzalez and the southern part of Fayette counties, that looks extremely promising and can be very economic.”

Since adding the Eagle Ford to its portfolio in 2014, Encana Corp. has made it one of four plays it will fund this year. “The best rocks we have there are very economic at $50 oil,” said Jeff Balmer, Encana vice president and general manager of western operations.

New digs

Over the past two years, Calgary-based Encana Corp. pushed aggressively to restructure its portfolio, including adding a 45,000-acre position in the core of the Eagle Ford Shale in June 2014. And just in time, too. As the price of oil began swooning soon thereafter, the South Texas position rose to become one of the top four economic programs that the company elected to fund in 2015.

“We wanted to focus on areas that have the best rocks so that we can leverage our efficiencies and technological advances to give us the biggest return,” said Jeff Balmer, Encana vice president and general manager of its western operating area. “And the Eagle Ford was one of the easily identifiable areas that rose to the top.”

Encana’s position lies in the northern half of Karnes County, Texas, in the volatile oil window, with its focus area around Kenedy, Texas. The area will receive some $550 million of capital this year, roughly 25% of total company capex, and second only to the Permian program, another 2014 Encana acquisition.

Since taking over the asset, by the end of the first quarter Encana had improved both spud-to-rig release and IP 30-day rates by 25%, and drilling costs by 30%. On inherited wells, using a variety of lift techniques, it improved base production some 50%.

“The best rocks we have there are very economic at $50 oil,” Balmer said. “With the robust type curves along with the cost reductions on drilling and completions, the economics are strong.”

Encana models EURs per well on a scale of 250,000 to 700,000 boe/d, with 600-plus well locations in inventory. Like other operators, the company is going “a little bigger, a little tighter” on its completion designs, “but we get a substantially better well out of it.”

One trigger to bump the EUR is in the cluster spacing, he said. The company currently is spacing stages at 250 feet, and the perforation clusters at 50 feet within the stage. “When we design clusters that are 50 feet or less, we see substantially improved results.” Two times EUR, in fact, per its published results.

The other high-return improvement is in proppant loading. Where historically, wells were pumped at 1,000 pounds of sand per foot, Encana has tested up to 3,500-plus pounds per foot. Balmer refrained from divulging which load proved most economic, saying the results were early. “We’re still zeroing in on the correct profitability cocktail.”

Like Carrizo, Encana also manages the choke at IP, preferring to control the early flowback at around 800 to 900 bbl/d. “The choke management schedule appears to work in conjunction with the reservoir to allow a flatter decline through time. We have found that not pulling the wells as hard early, results in better performance over the first six months, and we think greater ultimate recovery.” Because the wells are still producing relatively flat currently, “an EUR estimate would be premature.”

Encana is also looking at going back in to spot another well between legacy wells drilled 500 to 600 feet apart, effectively at 30-acre spacing. That, of course, requires a focused effort on geosteering and anti-collision mechanisms to avoid existing wells, but “we see potential to infill drill these locations, and we’ve had some success doing that.”

While Encana doesn’t differentiate between the Lower and Upper Eagle Ford, it too is looking at stagger-stacking laterals in the formation. Historical wells were landed in the lower part of the Lower Eagle Ford, and the company is testing landing another lateral in the Upper Lower Eagle, and stimulating upward.

“We’re going to test it,” Balmer said. “We’re trying to optimally develop the Eagle Ford in both the horizontal and vertical spacing systems.”

Refracks are another technique to upsize value. “Any time you inherit a group of wells, in all likelihood, some are going to be underperforming.” After cleaning out the wells, the company has gone back in with its high-intensity frack design used on new wells, and boosted wells producing zero to 100 up to 650 bbl/d. With several completed, early refracks cost $3 million, with cost reductions anticipated. The company has identified more than 50 candidates.

The Graben

A significant portion of Encana’s holdings lie in a contiguous area paralleling the Karnes-Wilson county line, in a structurally complex area known as the Graben. This subterranean trough between two fault lines creates drilling challenges. Although it was not given much value in the acquisition, Balmer said this region represents upside for Encana.

“When we inherited the play, those wells were subeconomic. Through application of improvements and fracture stimulation technologies, along with the decreased cost, we’ve made that Graben area economically competitive in the portfolio. We’ve drilled and produced some very economic wells already in the Graben.”

Conceivably, EURs could double from historical Graben wells, he postulated. “We have a fairly large inventory left to be drilled in the Graben, maybe half of our inventory. That could be a fun place to drill some oil wells.”

Encana is currently running two rigs in the Eagle Ford this year, down from four, and will focus on “the good stuff in and around the Kenedy area,” said Balmer. The slower program has advantages. “It allows us to make substantial progress in understanding the reservoir while keeping active.”

And while the company hasn’t announced a targeted 2015 production growth rate, or decline, Balmer said, “For the year, we plan to be ahead versus our January entry rate.”

The attitude of experimentation comes from the top down, Balmer emphasized. “We would prefer to give it a shot to understand what we’ve got. We are methodically learning without risking everything.

“The best rocks just keep on giving. The Eagle Ford is clearly near the top.”

Optimize or fade

Drillinginfo’s Gilmer said we’re living in a world of haves and have-nots when it comes to producers, and the division is not based on just cash.

“It’s based on your ability to recognize what are good practices and how do you maximize those practices. We’re in a world now where we’re trying to define better practices,” he said.

The better operators view this slowdown as an opportunity to learn about their rocks and how to optimize them, and they are able to produce their holdings at two to three standard deviations above what they should be producing given the rock quality, he said. Even the most successful operators are not yet optimizing every piece.

“The best operators are not doing everything we know how to do according to technology today. Even the best are leaving 10% or more behind from just what we know about.”

verage operators that are eking out minimal returns at $50 oil could, in most cases, produce 30% to 40% more with the same spend, if they knew how to better optimize what they have. Less successful operators, further, are taking acreage in which a good producer could get 500 bbl/d from a well and getting 200. “Those are never going to pay out,” Gilmer said.

“There are literally dozens—hundreds—of things you’re doing to produce a well, and it’s not any one thing” to achieve optimization, he added. “Everybody has been dealing with this huge, multivariant equation, jumbling these things around to see what relatively does better. Add them all together and there is big leverage.”

How? Data, naturally, warehoused and analyzed by outfits such as Drillinginfo. “The experimentation has been done by thousands of wells already drilled. Take those dollars you’re putting into the ground and try something new, and use that as a benchmark against those things you are able to predict.”

The data, he said, will show how to maximize producibility.

“This is truly the framework for figuring out how to be a better operator, to maximize your ROI. Those at the top end of their producibility have the ability to raise cash. The world is their oyster. Those that haven’t been able to figure it out and who don’t have liquidity are not going to get there. The world is not their oyster.”

Sanchez Energy CEO Tony Sanchez III (left) and COO Chris Heinson debundled the company’s procurement bidding process. Above, Sanchez breaks down its per-well cost savings on its Catarina acquisition.

Breaking it down

The biggest challenge that Eagle Ford operator Sanchez Energy Corp. faced with the fallen commodity prices was how to keep returns at the same level they were before the plunge, said Sanchez COO Chris Heinson.

“For our company, that meant falling back and figuring out how we could best leverage scale of operations, and see if we could take the efficiency improvements we were already doing on procurement and logistics to a larger percentage of our operations.”

First and foremost, that meant debundling the services provided—particularly regarding hydraulic stimulations—and having each service rebid. For instance, service companies bid only on the horsepower for pumping, while sand is sourced directly from the mines, and chemicals directly from chemical manufacturers. “If there was a middle man, we attempted to eliminate it.”

Transportation costs for sand, in particular, were trimmed by 4 cents per pound just by procuring a regional provider. The company is careful not to pay for horsepower or capacity not needed on a particular job, as each service is bid on a job-by-job basis.

Year-over-year, Houston-based Sanchez has realized a 40% drop in well costs, from $7.4 million to $4.5 million and still trending lower. Heinson estimates one-third of that savings is from the industrywide trim by service providers, while the remaining two-thirds derives from internal efficiencies. “Today, 100% of our activity is done this way,” he said, up from a third since last October.

That, he said, has kept wellhead economics in line with those before the commodity fall, around a 35% IRR. “That’s kept us active and going.”

Overall, Sanchez controls nearly a quarter-million acres in the Eagle Ford trend, but Tony Sanchez III, CEO, said the company has centralized its operations on a 106,000-acre ranch in the gas condensate window in Dimmit and Webb counties, Texas, known as Catarina. The company acquired this patch from Shell last summer and has wasted no time in optimizing results there. All of its three operated rigs are there, down from six last year.

“Catarina is by far our largest asset, and we had the most potential for near-term impact,” Sanchez said. “It had decreased in production when we took it over, and putting our capital into it ramped it back up to where it is now. And it’s simplified the debundling process.”

The company has successfully worked through a backlog of wells drilled but not completed by Shell, testing new completion designs. While Shell posted EURs of 400,000 to 500,000 boe, Sanchez said these new completions are tracking approximately 20% higher than its own guided EUR of 600,000 to 700,000 boe.

After testing high-intensity fracks up to 800,000 pounds of sand per stage, Sanchez “dialed it back” to around 450,000 pounds, Heinson said. “We just didn’t see the benefit of those much larger stage jobs.”

Sanchez is now bringing online its first self-drilled wells from three pads, testing longer laterals where it can. Inherited laterals averaged 5,200 feet, and Sanchez is extending that by another 1,000 feet on existing pads, and pushing up to 7,000 feet in greenfield areas.

Initial results average 50% higher than the previous operator’s, he noted, and on the longer lateral wells, exceeding 8,200 feet, “we are now seeing internal estimates of EURs as high as 1.5 million barrels of oil equivalent per well. Our two longest-tenured tests are tracking more than double our guidance.”

Those estimated recoveries, targeting the Lower Eagle Ford, were drilled for about a 30% increase in well cost.

“We’re beginning to get a better handle on how these wells are performing, and as we’re testing longer laterals. These wells have had strong production.”

To maximize drilling efficiencies, all of Sanchez’ wells are drilled from pads, usually six to eight wells together, and using modern rigs that take just 45 minutes in a well-to-well move.

“That opens all sorts of options,” said Heinson, “like batching wells, where we drill all the vertical holes on one pad, then all of the laterals at the same time. We see great savings from that.”

Wells now consistently take fewer than 10 days to drill, with some coming in under seven days spud to total depth.

Eagle Ford times three

Although many Eagle Ford operators recognize the potential of a Lower and Upper Eagle Ford striation, Sanchez sees three distinct zones on portions of its acreage. What others deem “Upper,” Sanchez calls middle.

“We have an upper Upper Eagle Ford that is looking very promising in early results that we’re the only ones testing,” he said. “We are becoming increasingly confident that, at least on a portion of our Catarina, we see three distinct benches that we think are commercially viable for development today, in spite of current commodity prices.”

Sanchez identifies some 1,350 locations thus far on its Catarina acreage, including 150 from the Upper Eagle Ford, and 3,300 locations Eagle Ford-wide. Its planned budget for 2015 is $600- to $650 million, mostly in the Eagle Ford, and guides to a 38% increase in production year-over-year. The combination of cost savings and cash flow from increased production should free up some opportunistic capital, said Sanchez.

“We’re going to take excess capital and deploy it back into non-Catarina assets where we had previously been drilling. Those areas have the added benefit of being oily, so they will add more oil to our production mix.”

Sanchez has used this dip in oil and gas prices to look inward and focus on how the company runs its business and how it approaches well performance optimization, artificial lift optimization and capital efficiency, Sanchez said.

“We’re trying to make the most of this downturn. It’s forced a culture change in our company to focus on margins, which gets lost in the shuffle when things are hot.”