New data suggest the Eagle Ford shale may soon become the biggest producing shale play in Texas.
With production at 66,000 boe/d day in July 2011, the Eagle Ford shale play in South Texas remains overshadowed by its more mature neighbors, the Barnett shale (877,000 boe/d) and the Haynesville shale (708,000 boe/d). But a surge in new drilling activity suggests that is about to change.
Data research firm Evaluate Energy projects the Eagle Ford shale may soon become the biggest producing shale play in Texas, if not the entire US. Drilling activity in the Eagle Ford has been growing dramatically for the past year, and at the end of 1Q 2011, it was the area with the most new wells being drilled in the state, Evaluate Energy found. According to the report, “the Eagle Ford play is looking like it will soon catch up with and overtake its neighbors.”
Going longer, getting cheaper
Magnum Hunter Resources Corp. is one of the companies tackling the Eagle Ford play. CEO Gary Evans said at the IPAA OGIS New York conference in April 2011, “One of the things we’re striving to do in the Eagle Ford is to go out further.”
With seven wells completed and producing in the play, the company has upsized from 1,219-m (4,000-ft) laterals to its most recent lateral of 1,829 m (6,000 ft), although 244 m (800 ft) was lost at the toe due to mechanical problems. “We’re fracing more stages, too,” he said. “We’re trying to get up to 20 stages per well.” Most Magnum Hunter wells to date have been completed with 14 to 16 fracture stages.
The company holds 25,000 net acres, most of those part of 50% operated joint venture partnerships with Hunt Oil Co., EOG Resources Inc., and GeoSouthern Energy Corp. Most of its acreage is concentrated in the oil window of Gonzalez County, with some in Fayette, Lee, and Atascosa counties, where the average thickness of the Eagle Ford is 23 m to 46 m (75 to 150 ft), with 8% to 10% porosity and 60% to 80% brittle rock.
Its latest wells have averaged 1,200 to 1,300 boe/d. “Our goal is to get to 2,000 boe/d per well IP (initial production),” Evans said. Current wells are typically leveling out at 400 to 600 b/d. Production is 98% oil, “not condensate,” he clarified. Magnum Hunter is running one rig, and Hunt has another focused on JV acreage. Evans expects to have 15 wells on production by yearend 2011.
Well costs are near US $8.2 million at present, but Evans is determined to drive costs down. “The last well we drilled was $7.5 million; our goal is to get to $7.2 million,” Evans said.
Monitoring service companies is crucial to keeping costs down. “We hammer on these guys. If you’ve got 10 pump trucks and we only need eight, send the other two home. Don’t charge us for that,” he said. Magnum Hunter also buys a lot of its own equipment, whether lighting, frac tanks, or well agitators.
Dealing quickly with mechanical issues is another focus of cost cutting. “When something goes wrong – cut and run,” Evans advised. “You stay there for three days fooling around trying to trip a hole, and that’s when your costs go out the roof.”
One big problem Eagle Ford operators encounter that affects the success of a well is staying in zone. “Steering is crucial for staying in zone. We’re 100%. We don’t get out of zone,” he said.
Magnum Hunter runs high-case and low-case economics. Based on a 1,280 b/d model with a 500,000 bbl equivalent estimated ultimate recovery (EUR), the internal rate of return (IRR) is 36% at $80 oil and 64% at $100. Modeling 613 b/d and a 362,000 bbl equivalent EUR, a low case, the IRR is 23% at $80 and 39% at $100.
Magnum Hunter has paid an average of $375/acre for its position, Evans said, but today acreage is leasing for around $1,500 to $2,000.
“We’re willing to try new things; there are better ways to do this,” Evans said. The company is experimenting with new technology in Atascosa County, where it has 3,000 acres that are 100% operated, with two producing wells. “A year or two from now we’ll be doing things differently than we’re doing them today. Look at all these resource plays; you’re seeing better recoveries, better production, and better reserves … because we’re learning.”
Rosetta Resources Inc. also is getting good results in the Eagle Ford.
“Our Eagle Ford assets continue to outperform our expectations,” said CEO and President Randy Limbacher, summing up 1Q 2011 during a conference call.
Rosetta holds 65,000 acres in the Eagle Ford play, but it has focused its attention up to now on its 26,500-acre Gates Ranch prospect in northern Webb County. During 1Q 2011, Rosetta drilled nine wells and has current production of 120 MMcf/d, up from zero 18 months prior.
In fact, the strong well performance makes the Houston-based company’s published 7.2-Bcfe type curve obsolete. “The Eagle Ford wells are behaving nicely,” Wunderlich Securities analyst Irene Haas observed. “The data clearly shows that the newer wells are producing at higher rates than implied by the 7.2-Bcfe type curve.” And those newer wells are curtailed by some 15 to 20 MMcf/d due to short-term infrastructure constraints.
Rosetta’s Senior Vice President of Asset Development, John Clayton, added, “We’d like to see what these wells can do when they’re not curtailed.”
KeyBanc Capital Market’s Jack Aydin is willing to take a guess: “We estimate EURs could be well north of 8.5 Bcf/well on average in the Gates Ranch area.”
The company has begun three-well pad development, resulting in a cost savings of $500,000/well and has a lease operating expense of $0.15.
“Rosetta continues to optimize drilling and completion operations, which have offset service cost inflation,” said Michael Bodino, managing director and head of energy research for Global Hunter Securities. “Spud-to-release has decreased over the past 15 months from 27 days to 15, and pad development allows the rig to mobilize in hours rather than the previous five to seven days.” Downspacing remains imminent, as the company believes it is recovering just 20% of hydrocarbons in place. “The current well inventory of 236 wells is based on spacing of roughly 80 to 110 acres,” Haas noted. “If downspacing is feasible, the Gates Ranch well count could double to 441. Using the current type curve of 7.2 Bcf per well, this implies an incremental 1.5 Tcf before royalty.”
Bolstered by recent asset sales and $385 million in liquidity, Rosetta has added a third rig to its program to test acreage beyond Gates Ranch, specifically 25,000 acres in the liquids windows in southern Gonzalez, central Dimmit, northern LaSalle, and Encinal counties. It plans to have 58 horizontal wells drilled and completed by year-end.
But with the ramp-up comes challenges. Even with firm take-away commitments in hand, Limbacher continues to closely watch the midstream infrastructure situation.
“Two potential pressure points are trucking capacity and the reliability of firm gas transportation,” he said.
Oil hauling in South Texas is extremely tight and will continue to be for some time, Limbacher said. The company has sufficient trucking capacity now but is moving toward other solutions such as rail, additional pipelines, and barges.
Gas take-away is challenged as well, even with firm commitments for existing production.
“We’ve seen our midstream partners struggling from time to time to provide firm capacity for which we’ve contracted,” he said. Rosetta has moved gas to other carriers on a short-term basis. “Expect us to continue to develop additional take-away options to ensure plenty of gas pipeline capacity for our key projects.”
SM Energy holds 250,000 net acres in the Eagle Ford shale. According to President and CEO Tony Best, “This is a company-maker for SM Energy. It’s a great position.”
SM holds 165,000 net 100%-operated acres, mostly in the rich-gas window in Webb and LaSalle counties, where it is working three rigs presently and plans to go up to six by year-end. They also holds a 25% nonoperated position of 85,000 net acres with Anadarko Petroleum Corp. in Maverick and Dimmit counties, with 10 rigs running.
Take-away capacity in the Eagle Ford is an issue for some operators, but Best assured attendees at the April 2011 IPAA OGIS New York conference that the company is in a good position to handle increasing production.
“We’ve been able to secure significant takeaway capacity, and we’ve contracted for the drilling and completion services that we’re going to need for this year and next,” he said. “That is going to be critical in our ability to ramp up in the program.”
SM now has takeaway commitments for 150 MMcf/d through midyear, going to 300 MMcf/d by the end of 2012. It also has secured a new take-away agreement for an additional 190 MMcf/d when a pipeline arrives in 2013.
“By mid-2014 we will have 470 MMcf/d of take-away capacity to accommodate our program in this play,” Best said.
Comparing these numbers with total company-wide production for 2010, “That is clear evidence of the significant impact the Eagle Ford can have on SM Energy and the opportunity we see in front of us in this play,” Best said. “It’s a pretty exciting time for us.” SM expects to drill 80 wells (70 net) by year-end.
Best of play
Carrizo Oil & Gas Inc. holds 33,000 net acres in the condensate window of LaSalle and Dimmit counties. President and CEO S.P. (Chip) Johnson IV said at the New York symposium that many think this will have the best economics of any area of the Eagle Ford. “It’s extremely profitable,” he said.
The company is looking to expand its position through lease acquisitions, focusing in Dimmit, northern LaSalle, McMullen, and Atascosa counties, Johnson said. The goal is to target the play where it is shallower than 3,000 m (10,000 ft), with some condensate but with a majority stream of oil production. The hurdle at present is cost. “It’s very hard to find more acreage here now at a reasonable price,” he said.
Nonetheless, in early June Carrizo bolstered its position with 13,000 new acres for $1,650/acre up front and a total cost of approximately $5,500/acre once carried drilling costs are factored in.
All of Carrizo’s first three Eagle Ford wells had initial production of more than 1,000 b/d of oil on a 24-hour rate. The following two came in at 735 bbl and 815 bbl at restricted rates. Average EURs with well expectations of 70% liquids and 30% rich gas are 400,000 boe (300 million net), with total target reserves of 92 MMboe.
Total well costs are $7 million to $7.5 million with 1,500-m (~5,000-ft) laterals and 18 frac stages, drilled into the condensate window above 3,000 m (10,000 ft). Finding and development costs average $23.33/well, with a 54% rate of return at $100 oil and $4 gas.
The company anticipates completing three wells a month from June through the end of the year. It now estimates it has 230 locations on 115-acre spacing.
This article was modified from the original from the July 2011 issue of Oil and Gas Investor and has been reprinted with permission.