Bill Martinez, Anadarko Petroleum Corp.’s general manager for the Delaware Basin, would like anyone unemployed in the U.S. to know that there are plenty of jobs available out here in far West Texas. From truckers to field hands, The Woodlands, Texas-based operator with an exotic international portfolio, as well as other operators in the basin, just can’t find enough local help for a developing new project: the Bone Spring.
Anadarko, along with industry partner Chesapeake Energy Corp., is running a combined eight horizontal rigs in this remote outpost south of the New Mexico border, in the 300 empty miles between Midland-Odessa and El Paso. Not only is qualified help hard to find here, but so are electricity, pipelines and a cell-phone signal.
“We’re on the edge of everything out here,” he says.
Bill Martinez is Anadarko Petroleum Corp.’s general manager for the Delaware Basin, where the company’s first 30 Bone Spring wells have averaged 400 to 1,300 barrels of oil a day.
The Delaware Basin Bone Spring play, stretching from southeastern New Mexico into the West Texas elbow, is the epicenter of a renaissance in the aged and storied Permian Basin. Here, in a region known for its conventional gas production, horizontal drilling combined with hydraulic-fracturing technologies —perfected in shale-gas resource plays—is being deployed for the first time. This time the target is oil, and the techniques have jolted liquid production per well tenfold. In an era of oil envy, those results raise eyebrows—and drilling rigs.
With the price of oil spurring activity, the Permian rig count has increased nearly 250% since April 2009, from 92 to 318 at the end of January, mirroring the rise in oil prices during that time. Horizontal rigs, however, now account for 25% of all Permian rigs—to 64 from 18—with most focused in the Delaware Basin. Here, horizontal permits nearly doubled last year to 445, compared with 226 in 2009, according to Drillinginfo Energy Strategy Partners.
“New technology is giving a rebirth to the Permian,” says Mitchell Wurschmidt, a New York-based senior analyst with Cleveland, Ohio, investment bank KeyBanc Capital Markets. “Economics dictate where industry activity goes, and we’re seeing a lot of operators ramp up” with horizontal targets in the Delaware Basin.
The Bone Spring neighborhood rises on the remote fringe of far West Texas.
The Bone Spring is a Leonardian-age series of formations. Its members include the First, Second and Third Bone Spring sands and corresponding carbonates, and the shallower Avalon shale (both Upper and Lower)—or the Leonard shale if you’re particular, and the Pardue if your logs are old. The Wolfcamp underlies those.
These oily and wet-gas zones have been the target of vertical-drilling efforts with hydraulic stimulation in the past, much like their cousin, the Wolfberry play across the Central Basin Platform to the east, but without much commercial success. Modern horizontal-drilling techniques, though, have changed the equation dramatically.
Leading shale-gas operators, retooling portfolios to include liquids, have amassed positions and are bringing horizontal rigs to bear. Devon Energy, EOG Resources, Cimarex Energy, Energen Resources and Concho Resources are among them. Long-time private local operators like Yates Petroleum, Mewbourne Oil and Nadel and Gussman are turning their bits sideways, too. Most telling: private-equity-backed companies are piecing together positions here.
“New technology is giving a rebirth to the Permian,” says Mitchell Wurschmidt, a New York-based senior analyst with KeyBanc Capital Markets.
Recent results have been strong: estimated ultimate recoveries (EURs) range between 400,000 and 600,000 barrels of oil equivalent (BOE) or higher; a typical well costs $4- to $5 million, depending on depth, per KeyBanc, but can run as high as $7.5 million in Texas where wells are deeper and using more frac stages. Altogether, “they are very good economics,” says Wurschmidt.
The Bone Spring is “the next big thing,” claims Tim Leach, chief executive of Concho Resources Inc. “We’ve seen enough to believe that there will be as much oil recovered in the Bone Spring and the Wolfcamp sections in the Delaware Basin as there is being recovered in the Midland Basin.
“It’s significant for our industry.”
Under an expansive, cloudless sky following a winter storm in Ward County, Texas, Precision Drilling Co.’s Rig #553 drills the curve of the Monroe 34-210-2H beginning at a 10,200-foot vertical depth. The reach will extend 4,000 feet through the Third Bone Spring, or “D” sand. Off to the side, a flare ripples the chilled air, burning off gas that has broken out from the drilling mud. “That’s a good sign,” states Anadarko’s Martinez.
The thing that is most attractive to Anadarko regarding its Bone Spring project is that the production is 80% oil, and the 20% gas is saturated with liquids. “There is a lot of value in the gas as well,” he says.
Before 2009, the Delaware Basin was a deep, dry-gas field producing from the Pennsylvanian formation. Anadarko, which held a large position there, wanted more flexibility, more liquids. A number of companies had dabbled in the Bone Spring zones, but not many had studied it hard or viewed it as a resource play. So Anadarko put its technical team to work.
The first well came on making 1,200 barrels of oil a day. “That caught a lot of attention,” Martinez says.
A driller at the console for Precision Drilling’s flex-rig #553. Facing page, Precision’s Rig #553, as seen from the driller’s enclosed cabin.
That was in October 2009. A year and 30-plus wells later, Anadarko is producing upward of 7,500 barrels of oil and 14 million cubic of gas daily from the Bone Spring. It’s still early in the development stage, but Anadarko is very encouraged by the margins. Martinez states, “We haven’t drilled a dry hole.”
The company holds approximately 600,000 gross acres in the play—about 300,000 net—concentrated in Ward, Loving and Reeves counties prospective for both Bone Spring and Avalon shale. It operates under an area of mutual interest agreement in conjunction with Chesapeake. “We’re excited about the multiple oil objectives in this area,” he says.
And prospectivity? “We can map these horizons over an extensive area, and we are still finding new horizons that are prospective. There’s a lot of potential and we don’t know yet how big the full development will be.”
Five operated rigs are plying the play for Anadarko with another three operated by Chesapeake, all currently seeking the Bone Spring.
For completions, the company has experimented with cement liners, but more often is turning to open-hole packer systems due to efficiency and time considerations, says Martinez. “We’re able to complete more wells at a lower cost and in less time.”
The company is varying the number of stages, with seven to 10 the norm, having tested up to 14. Lateral lengths are from 3,500 to 4,000 feet with plans to extend when leasehold permits. It is also experimenting with how much sand to pump: While more sand can lead to higher initial production, it comes at a cost, he says. Capital efficiency is a priority for Anadarko. Over its first 30 wells, stabilized initial production (IP) rates have averaged between 400 and 1,300 barrels of oil a day.
Anadarko’s Avalon program is in an early exploration mode. The company is encouraged by the initial tests and plans to drill several more Avalon wells in 2011.
Martinez touts Anadarko’s expertise in drilling efficiencies as a competitive advantage. Wells that initially took in excess of 50 days to drill are now routinely being drilled in less than 30. Well costs have dropped in spite of inflationary pressure. “We are confident that we’ll continue to reduce our costs with greater efficiencies,” says Martinez.
Will the Bone Spring become a significant asset in Anadarko’s portfolio? “I think the fact that we are running five rigs demonstrates the confidence we have in this area.”
Going forward, Martinez believes Anadarko will create significant value and competitive returns in its West Texas oil strategy. “We expect to maintain an active drilling program in the Bone Spring, and we will continue to improve our value proposition and capital efficiency in our development activities.”
During the course of 2010, Devon Energy Corp. repositioned its entire portfolio, cashing out of its long-term international and Gulf of Mexico offshore assets with the mission to reinvest much of the proceeds of $10 billion into onshore North America projects with accelerated returns. Like many of its peers, Devon is directing some 90% of its 2011 budget to oil and liquids-rich opportunities.
One of those focus areas will be in the Permian Basin, where Devon is a tenured operator with about 1 million acres and 44,000 barrels of oil equivalent per day of production, of which 70% is oil and natural gas liquids. And while the Wolfberry on the Eastern Shelf of the basin in Texas will command the Oklahoma City-based company’s attention as a vertical play, it is also gearing up a horizontal-drilling program on the Northwest Shelf in southeastern New Mexico in the Bone Spring sands and Avalon shale, where it holds some 370,000 acres collectively.
“Industry has not drilled a dry hole in the Avalon shale,” says Don DeCarlo, Devon’s senior vice president of its western division.
Don DeCarlo, Devon’s senior vice president of its western division, confidently anticipates a bright future with “tremendous upside” out of these horizons.
“These plays are relatively new in terms of the horizontal component, but we’re seeing exciting things happen weekly with new wells coming on and testing different concepts.”
Much of the excitement is occurring in areas where the Bone Spring or Delaware formation have already been developed vertically, says DeCarlo. “We’re using that data and putting wells in between, or extending those channel plays with horizontal drilling.”
One of Devon’s horizontal targets is the Second Bone Spring, a quality conventional channel sand that is not pervasive throughout the acreage, but “comes and goes,” per DeCarlo, requiring more geoscience to hit it right. Depending on location, pay thickness ranges from 20 to 100 feet thick. Devon has some 200,000 acres prospective for the Second Bone Spring in Lea and Eddy counties, New Mexico.
Stacked pumping units from days gone by in Mintone, Texas, the only town in Loving County, the nation’s least populated.
“The Bone Spring is a little tough geologically to find good spots and get a drilling program working. When we can get in those channels and put down horizontals, we’re making some quite impressive wells.” About 500 barrels a day or more, he touts, and “these wells hold up pretty well.” Here, the pay is mostly oil: “Very commercial.”
Bone Spring activity thus far is centered in areas known for relatively strong vertical well performance, and so far so good, he says, as all of Devon’s wells have produced in the hundreds of barrels per day. In third-quarter 2010, Devon announced Strawberry 7 Federal 4H at a production rate of 700 barrels of oil per day. The company has drilled 10 operated Bone Spring wells and various others through nonoperated interests, including with Cimarex.
Devon models 350,000 barrels of oil equivalent and cost of $3.8 million per well, which equates to a 30% rate of return “pretty consistently” at $80 oil. “In the Second Bone Spring we’re not derisking, we’re in development phase.” Devon has two rigs running in its Hackberry region.
“We feel confident about our Bone Spring play,” he says. “If you can find it in a meaningful way, the Second Bone Spring is quite a nice play. It would be a play any company would want in its inventory.”
Some of Devon’s Bone Spring activity is spilling south over the state line into Texas, where it has a “sizeable” acreage position in Loving County in front of the play. There, the company is testing the Third Bone Spring and has two wells completed. DeCarlo considers this region exploratory, but “we’re encouraged by what we’re seeing down there as well.”
On the top side of the Bone Spring strata, Devon is studying the Avalon shale, in which about 200,000 acres are prospective. Unlike the deeper Bone Spring members, which are sandstone, the Avalon is a true shale with ample fractures and streaks of sandstone and siliceous material. “It’s pretty prolific depending on if you catch it right and get your wells completed properly. We’re seeing some nice rates come out of some of those Avalon wells.”
To date the company has 12 operated Avalon-targeted wells across a 30-mile swath. Completions feature 4,000-foot lateral lengths with eight to 10 stages. Devon is currently testing its first 8,000-foot extended-reach lateral into the Avalon, and is experimenting with tighter perforation spacing.
Based on EURs of 400,000 to 600,000 barrels of oil equivalent for these wells, Devon is projecting returns of 20% to 40%, but DeCarlo notes it’s early to say. The company presently has three rigs derisking the Avalon with plans to add another. Thirty Avalon-focused wells are in queue for the year.
“Industry has not drilled a dry hole in the Avalon shale,” he emphasizes. “There have been some better wells than others, but we have not had a bone dry well.”
Yet he does note the higher gas-to-oil (GOR) ratio in the Avalon compared with the Bone Spring sands, about 50% dry gas on average, with the rest oil and natural gas liquids (NGLs). Gas is more prevalent on the western side of the play, with oil becoming more dominant moving east.
The Bone Spring play has made the isolated Loving County courthouse in Mintone, population 15, a busy place.
“Even though we might make more BOEs out of the Avalon, it is more expensive and has a gas component to it,” he says, “so the economics in the Second Bone Spring in many cases are substantially better.”
Decline rates, too, remain an unknown factor for Avalon economics. “We’re not seeing the rates hold up as well as in a conventional sandstone reservoir. It appears we’re going to see higher-rate, higher-decline wells out of the Avalon shale than out of the Bone Spring sands.”
And while the jury is still out regarding the Avalon, DeCarlo says production from the formation will ultimately be substantial. “A large portion of the play is going to end up being deemed commercial,” he says.
DeCarlo expects horizontal-drilling activity in the Delaware Basin to expand into the Wolfcamp and in the upper Penn shale. “A lot of different things are being tested out here.” In fact, Devon is running five rigs in undisclosed “other” plays within the Permian, targeting conventional formations with horizontal wells.
With many competing projects within Devon’s restructured portfolio, can the Bone Spring and related plays compete for capex? Says DeCarlo, “They don’t ask me to look at what I can do to slow down activity, I’ll tell you that.”
Yet, “There’s still some uncertainty and I fully expect we’ll have some bumps in the road, but we’ve got enough hooks in the water that we’re going to be pretty successful out here. We’re looking at not just this year, but the long term. There’s a rich opportunity here.”
Next big thing
If any company can claim to be King of the Permian, it is Concho. It runs the most rigs, at 31, and has some 1 million gross acres. Core areas are focused on the Wolfberry play in Texas and the Yeso in New Mexico, which it virtually has locked up. Now, with more than 150,000 net acres amassed, the Bone Spring has emerged as a third core focus for the company and is its fastest-growth area.
Concho now has five rigs drilling the Bone Spring, “and I would anticipate that rig count growing in the future,” says Tim Leach, chief executive officer. Bone Spring drilling represents some 20% of the company’s $1.1-billion capital budget this year, about $200 million, and up from almost none a year ago.
“The Avalon shale is gassier than the Bone Spring, but initial production rates are higher in the Avalon, which is why it still competes on rate of return,” says Tim Leach, chief executive of Concho Resources Inc.
“This play is important. Relative to the other things we’re doing, it will grow. It has become a significant portion of our capital budget and has the potential to dramatically affect our reserves,” he says.
Concho solidified its position in Bone Spring territory with its $1.3-billion acquisition of privately held Marbob Energy Corp. in October 2010. The company had been courting Marbob for three years prior. The Artesia, N.M.-based operator held 2,300 drilling locations in the Yeso—one juicy reason for Concho’s persistent interest—and another 1,000 locations in the Bone Spring on 80,000 net acres. Marbob was a first-mover and aggressive operator in the play.
In advance of the acquisition, Marbob had drilled about 60 wells into Bone Spring formations. Leach says, “They had a lot of information and success there. We were thrilled with getting both of these positions.” Concho retained Marbob’s technical team in the deal.
Within the Delaware Basin, Concho is targeting four subplays: in New Mexico, the Avalon shale and the First and Second Bone Spring; and in Texas what Leach calls the “Wolfbone,” a vertical oil play drilled to the Wolfcamp formation.
Regency’s Bone Spring station handles associated gas produced by Anadarko and shipped to Waha.
To date Concho has drilled some 80 horizontal wells into the Bone Spring. Lateral lengths range from 4,000 to 5,000 feet with up to 18 fracture stages, which Leach anticipates will become the typical well on 160-acre spacing. “Industry believes there is a very large amount of recoverable oil in the basin, but it will take us quite a while to figure out the most economic and efficient way to recover it.”
About half of its Delaware Basin activity is concentrated in the First and Second Bone Spring, and the other in the Avalon shale. “We’ve had consistent results across the area,” he adds.
Concho’s Bone Spring wells average 60% oil and 40% wet gas, while Avalon wells show a one-third split between oil, dry gas and NGLs. “The Avalon shale is gassier than the Bone Spring, but IP rates are higher in the Avalon, which is why it still competes on rate of return.”
Horizontal Bone Spring well costs run in the $6-million range. Average wells across the play make about 600 barrels of oil per day. When the play first started, the company modeled EURs of 200,000 to 400,000 barrels.
Leach doesn’t reveal updated recovery models, but notes the industry is reporting results in the range of 400,000 to 600,000 barrels of oil equivalent, and “we are bringing on wells that look very similar to the rest of the industry as far as our early production. It is certainly commercial.”
In its core Midland Basin Wolfberry and Yeso plays, internal rates of return run at 60%. In the Delaware Basin, though he notes it is early, Leach says, “I think the Bone Spring is going to compete very well on a per-well basis with those two. The difference about the Bone Spring is that there is so much running room, and so much potential for reserve and production growth.”
Rather than being concerned about drilling and completion techniques, the industry’s biggest challenge in the region is instead infrastructure.
“The Delaware Basin is large and underexplored,” says Leach. At issue is water—both for drilling and for disposal uses—as well as electricity and take-away capacity. Drilling activity now orbits existing infrastructure in the north of the basin and in Texas. But, “some of the play on the state line is way out on the frontier as far as infrastructure is concerned.”
From a private-equity perspective, Kyle Miller, senior vice president of Energy Trust Partners, says there are two things he likes about the Bone Spring: the potential to establish an operated position in an emerging play with running room, and to assemble a position with scale.
Wunderlich Securities analyst Irene Haas has reported that Concho is a natural consolidator of the Bone Spring, and Leach confirms the company is looking to lease or acquire “every day.”
Although too early to discuss resource potential, he compares Concho’s Bone Spring position to that in the Midland Basin, where it holds 50,000 net acres. “We have three times that in the Bone Spring,” he points out.
Leach says he’s asked often if Concho can maintain its historic growth rates while remaining a Permian-focused player. “The Bone Spring helps answer that question,” he says. “We can continue to do the same things that have made us successful in the past, and we can continue to grow at the same rate. The Bone Spring is going to be a big part of that answer.”
Nadel and Gussman LLC has more than 80 locations in the Avalon shale play in New Mexico, but the Tulsa-based privately held company is watching and waiting to see how the evaluation of this oil-shale rock develops.
“The industry hasn’t cracked the code yet,” claims Scott Germann, general manager for Nadel and Gussman Permian LLC. According to core data, he says, this is an organic-rich, thermally mature shale and siltstone interval, and like all oil-shale plays, there is a learning curve.
“If you look at the decline plots, the gas decline is fine, but the oil portion has a rapid decline. There’s no flattening in the oil,” he says. “Perhaps we’re not treating the shale well enough, not drilling long-enough laterals or we don’t have enough stages. Maybe there are artificial lift issues.”
“Everybody is looking for longevity—we all want payout, but we also want a long-life well,” says Scott Germann, general manager for Nadel and Gussman Permian LLC.
But he holds out hope that technology will ultimately sustain the Avalon. “There are large amounts of hydrocarbons in place in the Avalon and, once the industry does make the breakthrough, growth will be rapid.”
He points out that the data is from early exploration wells, and wells completed in 2010 improved. The first well in the play is less than 18 months old, with most of the wells not having 12 months of data. “We’re still getting better at it, but we’re watching and trying to decide if this is a play where the economics are going to make it for a private company.”
For now, Nadel and Gussman is playing the Second Bone Spring sands, where it has about 50 horizontal locations. It first attempted to produce Bone Spring and Avalon from a vertical wellbore with six fracture stages, modeling its Wolfberry program in Glasscock County, Texas, but it simply didn’t work, says Germann. “We made gas and oil, but we couldn’t get enough volume.”
Instead, the economics of the Bone Spring sands are much more proven and less risky from a reserves standpoint when drilling sideways, he confirms. “That’s the play that is kicking off hard right now. The Second Bone Spring sand is ringing the bell in New Mexico and the Third Bone Spring sand is ringing it in Texas.”
Traditionally a gas player in the Morrow and Atoka plays, now Nadel and Gussman’s western Permian activity is a 50/50 joint venture with Harvey E. Yates Co. that is called Nadel and Gussman HEYCO LLC. Yates, which was heavily weighted to oil, contributed acreage in Eddy and Lea counties, New Mexico, to the deal, and Nadel and Gussman contributed management and capital.
The combo has drilled three horizontal wells thus far, with several more planned for 2011. One of the early wells IP’d at a stabilized rate of 400 barrels of oil and 1 million cubic feet of gas per day, and a year later is now making 80 barrels a day.
“The 30-day IP rate is fine and great,” he says, “but we really want to see how much oil and gas we can make in the first year. Everybody is looking for longevity—we all want payout, but we also want a long-life well.”
In 2011, Germann says, the company will drill five to six operated horizontal wells and one of those will be to test the Avalon.
“We were looking for a play that occurred over the entire basin, and the Bone Spring/Avalon shale gives us that opportunity. This play gives an opportunity to turn legacy gas properties we already own into high-liquids properties, and for a company our size, that’s a big thing.”
With almost half of its reserves in the San Juan Basin and gas prices solidly soft, Energen Corp., like many gas-weighted E&Ps, is on a mission to shift its balance to include more oil and liquids. Energen, though, has an advantage: an underlevered balance sheet and a large legacy position in the Permian Basin.
“With gas prices depressed, we’ve tried to press the accelerator on the oil side of the picture,” says James McManus, Energen chairman and chief executive. “We identified three attractive plays: The Wolfberry, the Bone Spring and the Avalon shale.”
In the past year Energen, headquartered in Birmingham, Alabama, has secured four acquisitions toward that goal—two in the Wolfberry and two across the Avalon/Bone Spring—for some $385 million. “The economics are very nice in the Third Bone Spring. And we think the Avalon is potentially very good.”
Of Energen Corp.’s drilling in the Third Bone Spring, James McManus, chairman and chief executive, says, “The good news is you get a lot of cash flow on the front end, and the rates of return are robust.”
Energen was first exposed to Third Bone Spring vertical production in the late 1990s through a 50% nonoperated partnership with Cimarex in Warwink West Field in Ward and Winkler counties, Texas. By 2006, Cimarex began experimenting with horizontal laterals out of existing vertical wellbores and, when it liked the results, Energen acquired its own leases in the region. It drilled its first operated horizontal well in late 2009 and has drilled nine to date, and has participated in another 23 to date with Cimarex.
Before it acquired 40,000 net acres in December from SandRidge Energy Inc. in Loving, Reeves, Ward and Winkler counties near its existing holdings, Energen had been eyeing the position even when it was held by Forest Oil Corp., subsequently sold to SandRidge. But when SandRidge, a vertical operator, put that acreage back on the market, Energen knew what treasures it held.
“We were excited about the prospect of picking up that acreage. We liked the Bone Spring potential, and we thought the acreage was prospective for Avalon shale.”
Energen stepped up with a $110-million bid at $2,750 an acre. “We thought it was an attractive, consolidated acreage position that would be difficult to replicate.”
In January, it added another 17,000 acres, bringing its total in the Delaware Basin to 80,000 acres. It estimates all are prospective for the Avalon with 250 drilling locations (based on 320-acre spacing), with 50,000 of the total ripe for Third Bone Spring with 150 locations.
“If the Avalon works,” McManus says, “we might have two horizontal wells on one location.”
Of Energen’s $700-million capital budget, 80% is directed to Permian projects, with $120 million earmarked for a four-rig program in the Bone Spring—up from two now—and another $9 million for an Avalon test this year.
Drill-pipe thread-protector caps are stacked on pallets.
Between 2010 and 2013, the company is pushing to increase oil production by 60% with the Permian at the epicenter. Of that, the Bone Spring offers “significant growth potential—we feel confident about a large portion of that acreage.”
As such, Third Bone Spring activity has matured to full development mode. “We and others have some proven success, and we’re trying to determine how extensive the play is going to be. We know it works in certain parts where we’ve drilled.”
Vertical depth to reach the Third Bone Spring in Texas is about 11,000 feet. Energen is stretching laterals out to 4,500 feet, with up to 10 frac stages. Recent wells have come on at 550 barrels of oil a day or so. Here, well costs run about $7.5 million. And, with an average gross EUR of 450,000 barrels of oil equivalent, the rate of return at current strip prices exceeds 30%, says McManus.
Results have been consistent across the company’s acreage as well, he reports. “We’ve had a tight band of performance.”
Yet declines are steep, he acknowledges, addressing a concern voiced by observers, but he emphasizes that economics are good at current strip prices. “The good news is you get a lot of cash flow on the front end, and the rates of return are robust. It’s commercial where we’ve drilled it, and I believe the play is going to be very viable.”
The Avalon shale is all upside to the liquids ratio target, as any resulting production is not built into the company model. “We’ve not counted the Avalon as a sure thing,” he notes, but nonetheless the company has high expectations. At press time, Energen was drilling its first Avalon well.
“I’m hopeful the Avalon will be successful too. It’s a different animal, and it’s still unknown how extensive it’s going to be.”
What impact might the Bone Spring and Avalon have on Energen? Considering its total 400 locations, says McManus, “With estimated gross recoveries of 400,000 to 500,000 barrels, that’s a lot of potential oil that we might be able to bring out of the ground. That’s how I think about it.”
The Bone Spring play straddles the New Mexico/Texas border. Overleaf, oil and production-associated water is trucked out while infrastructure is developed.