Elk City, population 11,693 at the last official count, is situated on the western edge of Oklahoma. It is also fortuitously on the eastern periphery of the Granite Wash play that stretches beyond the state line 30 miles distant and on into the Texas Panhandle. Elk City roots for the high school Elks, no surprise, although no wild elk have been known to roam the gentle hills of pastureland and crops surrounding the town—ever. It is proud of its Route 66 heritage and features the now-idle Parker Drilling Co. Rig #114 on its main highway through downtown, its highest structure and a symbol of its economy.
The active drilling rigs are scattered around the edge of the town.
Apache Corp. operates three. These rigs are targeting the Marmaton “D,” an overpressured, shallow Granite Wash zone. The Marmaton here in Beckham County is an oil-bearing sandstone formation, not to be confused with the carbonate Marmaton formation in the Oklahoma panhandle. On a predawn drive to the Gregory #216H well, Apache senior production foreman Richard Lovelace points out the battery of tanks for a series of producing wells. The Smith wells, he says, came online at 1,000 barrels of oil and 10 million cubic feet of rich gas a day, on average.
“Big oily wells with NGLs (natural gas liquids),” he describes. “We’re trying to find some more of that.”
That sums up the goal of E&P operators all across the Granite Wash play. Touted until recently as one of the most economic plays in the U.S. due to its liquids-rich gas stream, now the liquids themselves have dropped in value like natural gas before, victim of a supply glut. NGLs historically average 60% of the price of West Texas Intermediate, but plunged to 40% over the summer. NGLs delivered to Conway, Kansas, where most Granite Wash production flows, have fared even worse: ethane—the major part of the wet-gas stream—traded at a 95% discount to Mont Belvieu, Texas, in July.
While operators are quick to point out that drilling for Granite Wash wet gas is still economic, in spite of the recent price downsizing, their actions show they will turn their drill bits toward oil opportunities when available.
Rig data reflects the trend. According to Baker Hughes, 81 rigs were running in the play as of the end of August, a 14 rig exit year-over-year. More telling: gas-directed rigs have declined 63%;the number of oil-targeted rigs jumped 158%.
“The Granite Wash has become more of a targeted oil play for the remaining rigs there,” says KeyBanc Capital Markets analyst David Deckelbaum. “Operators are searching their inventory for Granite Wash zones that possess actual oil as opposed to NGLs, because the local Conway market they’re selling into is so pressured.”
It just so happens that the western Anadarko Basin is rich with stacked-pay potential. And much of that is saturated with tight oil.
Anadarko Basin Reset
As you cross the 100th meridian that is the Texas state line on Oklahoma Highway 6 and into the Panhandle, the Baker Hughes rig app lights up with pin drops. Most Granite Wash activity is concentrated here in Wheeler and Hemphill counties, including many of Apache’s 24 active rigs.
Rob Johnston, Apache vice president, Central region, surveys the scene at the A.C. Smith 41-6H frac site in Wheeler County, targeting the Granite Wash “A” zone. Apache’s fleet is seeking a multitude of horizons in the region, but the Houston-based company unapologetically maintains six rigs aiming for wet-gas Granite Wash zones, the highest concentration for any single formation. “It just keeps on giving,” he says of the play. “It’s amazing.”
Sheer volume drives Granite Wash economics. Recent Apache wells drilled into the Granite Wash A, B, C and Britt zones showed 30-day initial production (IP) rates of 3,200, 2,500 and 4,700 barrels of oil equivalent (BOE) per day (48% liquids).
Estimated ultimate recoveries (EURs) for the same wells range from 1 million BOE to 2.6 million BOE. Although well costs top $10 million, Apache projects a 44% blanket rate of return. “Even if they take a 10-point hit” due to NGL price dropoff, “they pay for themselves, and most a lot more,” Johnston emphasizes.
Apache is no neophyte to the western Anadarko Basin, having planted its flag here as early as 1954. Its legacy position was established in 1977 when the company, via a farm-in acquisition on Oklahoma’s “North Block,” solidified its footprint at 650,000 acres. It spent the next three decades drilling conventional dry gas.
That all changed in June 2009, when Apache dropped all rigs in the region, economics squeezed by rising costs and falling prices.
“Twenty years ago companies were drilling into dry-gas formations like the Atoka, Red Fork, Springer, Morrow and Skinner,” says Johnston, who joined the company in 1982 as a geologist. “We are not drilling a one of those now. With gas prices where they are, I don’t think you can make money on that.”
With 150 vertical Granite Wash wells as guidance, Apache sank its first horizontal Granite Wash well in July 2009, the Hotstetter. It produced 15 million cubic feet (MMcf) of gas and 1,000 barrels of oil per day. Every well here since has been horizontal.
Dubbing this era the Golden Age of Drilling, Johnston says, “Horizontal has allowed us to target plays that were not economic previously. A lot of acreage in between these (vertical well) sweet spots became important overnight.”
When it restarted operations, the company aimed to test as many geographic locations and geologic formations as possible with horizontal wells. “We did a lot of experimenting. Astoundingly, most of them worked,” Johnston says. “Almost all were economic.”
Pumping $750 million in capex into the western Anadarko region this year, Apache’s cornucopia of economic targets includes the Granite washes (six rigs), Tonkawa (five), Cottage Grove (four), deep Marmaton (three), Marmaton sand (one), Cleveland (two), Cherokee (one) and Canyon Wash (two). The division entered the year with six rigs, and will exit with 26, having drilled 250 wells.
Yet that’s just a drop in the bucket. Johnston has done the math and calculates Apache has an inventory of 35,000 drilling locations across its broad Granite Wash position in Texas and Oklahoma. That assumes four horizontal wells and four zones per section—and doesn’t count dry-gas opportunities. “Somewhere down the road we’ll probably exceed that,” he says. “We’re opportunity rich.”
Black-oil targets notwithstanding, Apache—which values rate-of-return over sizzle plays—still drives the largest portion of its Central division capex to the Granite Wash proper. Johnston emphasizes the company’s dedication to wet-gas Granite Wash development has not suffered at the expense of the regional oilier opportunities. “We’re adding,” he says, noting the oil-directed rigs deployed through the year are lighter horsepower due to shallower targets.
Unlike a shale where drilling is repeatable and predictable, the Granite Wash is heterogenous—rock properties and thickness vary across the play. Johnston sees this as opportunity. “We can high grade by targeting areas where we expect in excess of 10 MMcf and 1,500 barrels a day. Some wells will blow away shale economics, but not every well will.”
This process starts with its deep databank of vertical well control. Apache then leans heavily on detailed mapping and geosteering the drill bit into specific horizons—as many as five within the Granite Wash column—targeting sweet spots of larger grain, higher porosity and greater fractures. It’s this high-grading that maintains the Granite Wash as a high-return project. “It gets its money back quicker than other projects.”
Like the North Block acquisition, Apache step-changed its position in the region with the addition of 312,000 core acres via a $2.8-billion deal for Cordillera Energy Partners in April. In addition to the Granite Wash, Cordillera stockpiled the portfolio with opportunities in the Tonkawa, an oily zone in which Apache was deficient. Now, the Tonkawa is the second-largest program in the region behind the Granite Wash.
“We look for offsets to marginal vertical oil wells. If you find a vertical Tonkawa well that made 20,000 barrels, turn it sideways and you can often see 300,000 barrels.”
Granite Wash economics slightly exceed those of the Tonkawa because of rates, he says, “but it is close behind.” And like what occurred on the North Block acreage, Johnston foresees decades of infill drilling on the Cordillera piece.
The Cottage Grove formation has caught Johnston’s attention, too. Uneconomic as a vertical target, “we’re making 1,000-barrels-a-day wells horizontally.”
Not to be overlooked: the Cherokee in Harper County, Oklahoma. “We’re seeing a thousand barrels a day out of a little horizontal.” Unlike the low-perm Granite Wash, the Cherokee is a high-permeability carbonate, and maybe better played vertically. “Once you get a straw in the reservoir, it doesn’t matter if the straw is horizontal or vertical.”
Oil production from Apache’s Central region tripled last year, exiting 2011 at 6,000 barrels a day. Midway through third-quarter 2012, production has already quadrupled to 26,500 barrels per day. Count 7,000 barrels from the Cordillera acquisition; the rest is organic.
“One of the greatest things about the Anadarko Basin is it’s so deep. You have known productive strata down to 26,000 feet. And shallow production hasn’t been targeted in decades, because it is tight oil. With horizontal drilling, my guess is we’ll be drilling on this for decades to come.”
The division is second in capex within Apache’s portfolio behind only the Permian Basin. “There’s no question it’s a renewed focus of the company,” Johnston says. “It’s on a sharp incline.”
Whole Hog For Hogshooter
The Granite Wash for the past two years has been the premier play for Houston’s Linn Energy, consuming 50% of its overall annual $1-billion capex, and remains so today. Some 600 locations are on deck to be drilled. However, the company has shifted all eight of its rigs away from traditional Granite Wash zones—the Carr, Britt, A, B and F—and toward the Kansas City Hogshooter zone uphole, which is, as expected, oil producing.
“We have made a material shift in our program toward oilier zones,” says Mark Ellis, Linn chairman, president and chief executive. “We are driven by revenue generation per unit of production, and there is tremendously more margin drilling the Hogshooter wells than the liquids-rich Granite Wash wells. This shift to oily zones should offset the current pricing environment for natural gas and gas liquids for us for a couple of years while we let prices recover a bit.”
In April, Linn completed its first three Hogshooter wells in the Frye Ranch area of Wheeler County, Texas, with an average 2,500 barrels of oil and 3 MMcf of gas per day. “That prompted us to be comfortable extending that program and shifting the majority of our rig count toward Hogshooter wells,” adds Ellis. “We’ve gone from a traditional Granite Wash liquids-rich gas play, to an oil play with our eight rigs predominately focused on the Hogshooter.”
Arden Walker, Linn executive vice president and chief operating officer, says returns on those Hogshooters are 100% plus. “We’re going to drill the locations we believe will deliver the best returns first. In this commodity-price environment, that means Hogshooter.”
Linn has identified 50 Hogshooter locations on its 70,000 net acres in Texas. It also has 25,000 net acres on the Oklahoma side and plans to drill a Hogshooter well in the Mayfield area of Oklahoma in the fourth quarter. The company expects to complete an additional 20 Hogshooter wells by year-end, and will map out its 2013 program based on those results.
Will they all look like the first three? “I hope so,” says Walker, “but zones do change quite a bit over this play.” The first wells targeted the thickest intervals, which can be 400 feet. “We are going to see some variability.” Linn models IPs of 1,700 barrels a day for the program.
Hogshooter wells cost Linn approximately $8.5 million to drill and complete with a 4,500-foot lateral, about the max for the unit size. Completions involve 10 to 12 stages, 3 million pounds of sand, and 150,000 to 200,000 barrels of slickwater. Linn recycles about 80% of flowback water to a central facility. “It’s both an environmental driver and a cost driver,” explains Walker.
Moving oil to market in the Hogshooter, however, is a challenge, Walker says, as infrastructure is simply not there to move it. “We’re trucking 100% of the oil right now. In April, for a few days, we had 7,500 barrels a day of new oil coming out of one lease. When we put on new Hogshooter wells, we’re going to have that same kind of increase coming again.”
What’s to become of Linn’s Granite Wash? “It’s a nice area to be in because it’s one of those plays that just keeps giving,” explains Walker. “We have a lot of development future there that will take us 10 years to drill. We’ll take our time and see what happens.”
At current spot prices, the Granite Wash zones still generate 30% or higher rate of returns—nothing to be ashamed of, notes Walker. “But if we have 100% returns, we’re going to drill those before 30% returns.” The Carr and Britt zones will still be developed, just in turn. “They have to compete for capital.”
In other zones, Linn participates in 100 wells annually in the Cleveland play in the northern part of the Texas Panhandle, with plans to add a rig there. It is watching industry results in the Tonkawa and Lansing formations. “We’re fast followers,” says Walker.
The sleeping giant is the Atoka, says Ellis. A deep, dry-gas interval, the Atoka remains quiet because of the current pricing profile. But Ellis points to one Linn Atoka well that came on at 35 MMcf equivalent per day and maintained that rate for some time.
“We’ve had some fantastic results from the Atoka,” Ellis says. “When gas prices begin to recover, we’re going to see some nice Atoka targets. But we don’t want to blow down those kinds of reserves at current gas prices.”
Considering the vast number of hydrocarbon-bearing formations subsurface, Linn has developed a method to drill, complete and produce multiple zones without shutting in or delaying production. Its “SimOps,” or simultaneous operations technique, involves placing barriers around producing wells while drilling another on a multiwell pad in development, and completing adjacent wells with the fracture-stimulation equipment offsite using a buried line to the wellhead.
“That’s been a game-changer for us,” says Walker. “We can complete the well at the same time we’re drilling and producing on the pad. It is critical for this play because you have multiple wells from the same pad targeting all these different zones. We envision potentially having eight or more wells on these locations because all of these zones exist in many of these areas.”
Linn will exit 2012 with 60 operated wells drilled into the Granite Wash during the year, a pace just right for a company focused more on distributions per unit than production growth. “We could easily support a faster rig program on this acreage, but we’re taking a balanced, paced approach,” says Ellis.
Not shy about making acquisitions—with $3 billion in new deals year to date—Ellis says he would love to add more Granite Wash inventory. “As prices continue to be challenged on the gas side, and more companies going into next year are less hedged, I think we’ll see a flurry of assets hitting the market to fund other capital programs.”
Extending The Marmaton
Tulsa, Oklahoma-based Unit Corp. likes the synergies in the Midcontinent provided by its three-legged platform of contract drilling, gathering and processing, and E&P. It plans to bring all three to bear on its recently announced acquisition of Granite Wash E&P assets and related gathering and processing infrastructure (primarily in Western Oklahoma and the Texas Panhandle) from Noble Energy, which was set to close mid-September.
The $617-million deal includes 25,000 net acres in the core Granite Wash play of the Texas Panhandle and more than doubles Unit’s Granite Wash leasehold to a total of 46,000 net acres. It triples its inventory of potential locations to more than 800. Unit president and chief executive Larry Pinkston believes in the longer-term economics of the play.
“Granite Wash economics are great,” he says. “Not as good as six months ago, but still good.” Having done 30 years of drilling in the basin, “It’s an area we understand very well.”
Specifically, at $90 oil, $2.50 gas and $40 per barrel of NGLs, Unit’s rate of return is 35%, a fair measure of the current pricing environment. Unit drilled 28 horizontal Granite Wash wells through 2011, and expects to have another 25 completed by year-end 2012. Average IPs and reserves are 5.7 MMcf equivalent per day and 4.0 billion cubic feet (Bcf) equivalent, respectively, of which about 50% is oil and gas liquids. Costs trend to $5.5 million with a 4,000-foot lateral and 11 fracture-stimulation stages. The company will spend $130 million on the Granite Wash this year.
Nonetheless, Pinkston acknowledges the present NGL price environment, in conjunction with sustained lower gas prices, is influencing Unit activity in the play. The company is running four rigs here now, but will drop to two by year-end. “Are we as aggressive as we were a year ago? No, we’ve slowed down. Liquids pricing is certainly a driver.”
Still, he anticipates NGL prices will improve within three to six months. With most of Unit’s existing acreage and the new acreage from Noble being held by production, timing becomes less critical, he says.
“Most of your production occurs in the first six months. You don’t want to produce that much of your production stream in a period of low commodity pricing.”
Pinkston remains bullish, expecting to ramp up to eight to 10 rigs in the Granite Wash by year-end 2013, with four to six of those drilling on Noble properties. The company has identified 12 potentially productive Granite Wash zones and now has commercial wells in seven of those, which it plans to develop with pad drilling.
“The stacked-pay opportunity we’re looking at is within the Granite Wash,” says Pinkston. “The efficiencies of operating in a set formation are tremendous.”
But while Unit is temporarily slowing in the Granite Wash, it is ramping up in oil-prone plays, primarily a new core position in the Mississippian, and particularly its 103,000-net-acre Marmaton play in Beaver County, Oklahoma, located in the Panhandle.
“We’re looking for new areas that have oil production,” he says. “Given the same volume metrics, economics on a 90%-crude play are better than a play with half the liquids stream being NGLs.”
After drilling some 70 operated Marmaton wells over the past two years, typical 30-day IPs average 310 BOE per day, almost all oil, with 130,000 BOE of estimated reserves. That’s at a cost of $2.8 million—the Marmaton is much shallower than the Granite Wash—with a 4,000-foot lateral and 16-stage fracture stimulation. Count that as a 23% rate of return, per Unit. Two rigs have been drilling the play in 2012 with a $75-million budget.
Pushing the Marmaton envelope, Unit completed its first extended lateral of 9,500 feet. That well averaged 960 BOE per day over a 30-day period, resulting in a jump in EUR to around 400,000 BOE at a cost of $4.5 million.
Brad Guidry, Unit executive vice president, says the economics for the longer lateral well are “fantastic—100%-plus rate of return. Our intent going forward is to drill as much as we can with extended laterals.”
That objective may be optimistic, however, due to the current spacing requirements. Three additional long-lateral wells are scheduled to come online in 2012. Unit will keep two rigs active in the play.
“The Marmaton is a big play for us,” Pinkston says. “We have a lot of locations to be drilled.”
For Jones Energy, the Austin-based producer founded in 1988 by Jonny Jones, the son of legendary oilman Jon Rex Jones, the Cleveland formation has dominated activity for the past six years. It may come as a surprise to learn Jones’ wells account for 20% of total horizontals in the play. The private company has drilled 232 to date in Lipscomb and Ellis counties, with another 220 locations to go.
“Our company is more technically sophisticated than people might give us credit for being an independent company,” says Jones president Mike McConnell. “We have drilled over 550 wells and over 365 of those have been horizontals.”
Indeed, Jones has drilled very few vertical wells since 2004, and has been a joint-venture partner with ExxonMobil, BP, ConocoPhillips, Devon Energy and Samson Resources due to the drilling team’s ability to boost economics.
“We can turn an economically marginal play into one that is healthy, in some cases knocking up to $1 million off of traditional drilling costs. That’s something we’re pretty good at,” says McConnell. The business is about margin: “Our goal is not to just have the best results, but to be the lowest-cost driller and get top-quartile results for that investment.”
The primary method for slashing costs is in completion techniques. In 2005 Jones began using the Packers Plus open-hole completion system, a methodology that costs $500,000 less than cased-hole completions, and has experienced a 92% success rate ever since. Near-term well costs have averaged $3.2 million and are trending down.
“If you save $500,000 on each completion with three to five rigs running, that adds up over time,” says McConnell. “We’re getting the exact same production as other methodologies, but we’ll take that $500,000 and put it in the bank today. It is good for us and our partners.”
Kristel Franklin, Jones Energy senior vice president, Anadarko group, adds, “We’re able to frac an 18- to 20-stage well with a 4,300-foot lateral in one day.” Typical Cleveland IP 30-day results: 1.6 MMcf per day of 1,250 Btu gas coupled with 300 barrels of oil. Decline curves match those of cased-hole completions. “We haven’t been able to discern a distinct difference,” she says. Jones is spacing five Cleveland wells per section.
That low-cost mindset makes a difference with current pricing. Jones’ 100-section Cleveland block is less oily than in Ochiltree County, and produced NGLs are delivered to the Conway, Kansas, plant, which is experiencing historically low prices. “Economics have waned a lot,” says Franklin. “We love our Cleveland play because of its high liquids content, but when you have your price slashed in a big way, it does make a difference.”
Jones has trimmed its Cleveland rigs to three from four year-over-year, and is high-grading prospects for oilier sweet spots. “We have the flexibility to ramp up or down based on well economics,” says McConnell. With all of its acreage held by production, “there’s no reason to be in a hurry to drill reserves if we think liquids are in a temporary low.” Being conservative and drilling within cash flow tempers the pace as well.
Similarly, with a small position on the northern edge of the Granite Wash at the Hemphill and Roberts counties border, Jones has dropped its rigs. These have been redeployed in the Arkoma Woodford shale, a new and more economic venture.
The company is sniffing out acquisition opportunities as well. “We are uniquely positioned to make money in a lower-price environment. We can be competitive in a purchase because we may be one of the few that can drill in this environment and still make a good return,” McConnell says.
The Old And The New
Chaparral Energy Corp. has high expectations for its 200-million-barrel-potential, CO2 enhanced oil recovery (EOR) program, but that is a three- to five-year project before seeing a return on investment. Near term, the Oklahoma City company expects its portfolio of 400,000 unconventional acres, including 48,000 in the Oklahoma and Texas panhandles Marmaton play, to pay off big.
On the northwestern rim of the Anadarko Basin, the Marmaton formation here is a carbonate facies about 6,200 feet deep extending through four counties: Beaver and Texas in Oklahoma, and Lipscomb and Ochiltree in Texas. Chaparral is the third-largest acreage holder, with Unit Corp. and Cabot Oil & Gas the other major operators in the play. Serendipity played a part for Chaparral, as the Marmaton overlies its legacy Morrow position as part of its EOR program.
“It’s very oily,” says Chaparral chief executive Mark Fischer. “Very little gas, which makes for great economics in today’s market.”
Chaparral has one producing Marmaton well to date, a 4,500-foot lateral well in central Beaver County that was fraced in 12 stages. It featured a 30-day IP of 350 barrels of oil per day. After five months online, it is still flowing 100 barrels daily, along with 900 barrels of water. The company expects to have three Marmaton wells producing by year-end.
With EURs estimated at 160,000 barrels of oil and well costs of $4- to $4.5 million, Fischer projects returns will exceed 35%. “Given good performance, we would expect to do substantially more drilling here next year, probably 10 to 15 horizontal wells.”
Natural fracturing creates a unique challenge here, too. “You have a tendency to lose circulation, and potentially dry drill the well throughout the horizontal portion.” Such circumstances can result in the bit sticking in the wellbore, but the first well “came off slick,” he says.
Should the economics hold, Chaparral will develop some of its leasehold, which partially sits on the same acreage above the Morrow CO2 injection zone at 7,800 feet, on 160-acre spacing. “We’ll end up with four wells per section, and 300 wells potentially to drill. We’ll be playing that for a long time.”
To a lesser extent, Chaparral is developing a 10,000-acre Granite Wash project in Roger Mills and Washita counties, Oklahoma, and Hemphill County, Texas. Production is generally good, he says, with initial rates showing 4- to 8 MMcf per day of gas, and 400 to 800 barrels of oil per day. It’s most recent well, the Wright 122-2H, recorded flowrates of 10 MMcf per day and 1,000 barrels of oil per day.
Within the Granite Wash interval itself, Fischer counts 13 different pay zones. Chaparral generally targets the “B” zone, and has successfully tested the “C” in two locations. “We have yet to drill a Granite Wash “A” zone well, but you can bet it will be forthcoming.”
Even with current NGL pricing, the Granite Wash still has superior economics due to production volumes, says Fischer, from 45% to 75% rate of returns (RORs) “depending on a lot of things.” A 10-well annual program is planned.
While not currently an operator there, Chaparral is additionally participating in Hogshooter wells in Wheeler and Hemphill counties, Texas. Its initial well, the Davis 64 #6H, averaged 3,500 barrels a day IP with rich associated gas.
“We’re excited about the Hogshooter and think it has real potential,” he says. “Right now, with limited penetrations, you drill a well and within two months you have all kinds of offsets. You’re going to be looking at a 600,000 to 800,000 BOE EUR.”
The economic numbers look good, he says. Although early in the life, “I could tell you 75% to 100% rates of return are achievable, and that feels pretty good.”