t’s sunrise in Canadian, Texas, and theCordillera team is sourcing water. Fracture-stimulation jobs in the Granite Wash li -

quids-rich play of the western Anadarko Basinuse 250,000 barrels of fluid and operators arecompleting an average of a well a day in theTexas Panhandle and western Oklahoma coun-ties that host this stacked bounty.

Privately held Cordillera Energy Partners IIILLC has more than 8,000 wash and other loca-tions to drill on its 400,000-gross- and 225,000-net-acre position. By adding 3,000 to 5,000acres a month in the tightly held, 2.6-million-acre, 130-mile-wide fairway, where it has 40 to50 landmen winning leases acre by acre, it’sdoubling its locations every two years.

In terms of stacked plays, this one is themother of all of them, says George Solich,Cordillera president and chief executive officer.Starting from the top, there are the Pennsylva-nian-age Douglas, Tonkawa, Cottage Grove,Hogshooter, Cleveland, Marmaton, and theCherokee group of sands—Oswego, Prue,Skinner and Red Fork.

Then, there are at least 11 members of theGranite Wash. Next are the deeper Atoka, Mor-row and Springer followed by Mississippian-aged limestones, including St. Louis, Chester,Meramec and St. Genevieve.

“They’re all on top of each other. What’sunique about this part of the world is the

amount of serendipity you have—all in onespot,” Solich says.

In 2012, EnCap Investments LP-backedCordillera plans to drill multi-formation,stacked laterals. In an inter-formational design,horizontal Tonkawa, Marmaton and GraniteWash horizontals will be made from the samepad. In an intra-formational design, it will at-tempt multi-Granite Wash, stacked laterals:horizontals in four of the five liquids-rich Gran-ite Wash members, which sit at the top of theconglomerate.

Dry holes have been nil to date for Cordilleraamong its more than 300 vertical and horizontalwells in the western basin, which involves 15counties, and they are rare among all operatorsacross the play. The nomenclature is a bit of achallenge, though. Like northwesternLouisiana’s Sligo and Pettet formations, namescan be synonymous. In the western Anadarko,members of the Granite Wash are found indrilling records as Des Moines and Colony, forexample, in Oklahoma; in Texas, they’re sim-ply known as Granite Wash and each zone car-ries an alphabetical designation—the A, B, C,D and so on.

The challenge is somewhat the same with theCleveland and Marmaton. In Texas, each is dis-tinct. In Oklahoma, distinguishing them is lessrigorous as the upper Marmaton begins towane. “Atoka Wash is below all of these zonesand that’s a whole other play that’s just gettingstarted,” Solich adds.

Drilled for roughly a century, this was deep-gas country drilled primarily for the overpres-sured, prolific Morrow and Springer dry-gaszones at between 12,000 and 25,000 feet thathave made record wells. For example, BuffaloCreek 1-17, a vertical Chesapeake EnergyCorp. deep Springer, has made more than 60billion cubic feet (Bcf) of gas and has paid outits cost more than 37 times to date.

As gas prices have waned over the years,drilling deep-gas targets has been put aside formore liquids-rich zones that are shallower andless expensive to drill. So, the deep-gas bountyremains for a better-gas-price day—offering yetanother round of big reserves and revenues. Butthe gift to liquids-rich-production seekers is data

THE WESTERNANADARKO BASIN

With dozens of stacked oil, wet-gas and dry-gas formations in this corner ofthe Midcontinent, operators have decades of new high-return, horizontal wellsto drill.

ARTICLE BYNISSA DARBONNE

PHOTOGRAPHY BYPETER C. PIAZZA

I

50 OilandGasInvestor.com ▪ October 2011

“I would ratherbe in this playthan any of theshale plays,”says GeorgeSolich, CordilleraEnergy PartnersIII LLC presidentand chiefexecutive officer,of the liquids-richwesternAnadarko Basin.Facing page: Awind- anddrought-batteredAmerican flagwaves fromCactus DrillingCo. LLC’s Rig 121as it targetsGranite Washnear Reydon inRoger MillsCounty,Oklahoma.

U. VirgilDouglass SS.Tonkawa SS.

Chester LS.Meramec LS.

Osage LS.

Cottage Grove SS.Hogshooter//Cleveland

Morrow SH.Morrow SD.

Marmaton/OswegoPrue

Skinner

Springer

Virg

il

Cis

co

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so.

Hox

Des

mon

.

Dee

se

Atok

.

Dor

n-H

ills

Dor

n-H

ills

Mor

r.Sp

r.Sp

r.

Mer

.O

sag.

Pen

nsylva

nian

Miss.

GraniteWashShales

Gra

nite

Was

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Wichita Orogeny

Red Fork (Cherokee)

AtokaNovi

13 Fingers LS.

Collingsworth

Gray Wheeler

Custer

Dewey

Greer Kiowa

Woodward

Carson

Hutchinson

Hansford

Hemphill

Lipscomb

Ochiltree

Roberts

Beckham

Ellis

Roger Mills

Washita

Granite WashMaramatonClevelandTonkawa

Armstrong

Carson

Donley

BeaverTexas Woods

TEXAS

OKLAHOMA

Dewey

Woodward

WoodsTEXAS

OKLAHOMAMapArea

Vertical well logsshow a multitudeof pay zonesacross thewesternAnadarko Basin,says BarryMcBride,Cordilleramanager,geology.

Stacked pay inthe basin rangesfrom shallowsandstones, suchas the oilyTonkawa, todeep, liquids-richMississippian-age limestones.

52 OilandGasInvestor.com ▪ October 2011

tempts have become standard.“Horizontal drilling is changing this whole

play dramatically,” Solich says. In short order,624 horizontal completions have already beenmade in the Granite Wash among all operators.At press time, another 235 had been spudded orwere waiting on completion, and more than 200permits for new wells had been issued.

Across the Greater Anadarko Basin, therewere 225 rigs at work this summer onliquids-rich wells with 100 drilling the

western basin. Among these, 65 were targetingGranite Wash; 20, the Cleveland; 10, the newTonkawa light-oil play; and five, Marmaton.

Solich says, “Every Granite Wash zone mea-sures up to some of the best formations in theU.S. The Granite Wash not only passes musterbut it surpasses every resource play out there.”

The liquids-rich Eagle Ford, Bakken andMarcellus too? Yes, he says. The 2.6-million-acre areal extent of this corner of the basin issmaller than the 11-million Eagle Ford, 8-mil-lion Bakken and 22-million Marcellus, but thethickness of Granite Wash pay—averagingsome 2,700 feet—is formidable.

“What’s the thickest part of the Eagle Ford?Two hundred feet? Marcellus, the same?Bakken, 50 or 70? From a 3-D perspective andfactoring just four of the Granite Washbenches, you’re looking at something 10 timesthe size of the Bakken per section, five timesthe Marcellus and 2.5 times the Eagle Ford.That’s because of its thickness.”

Some of the Granite Wash zones are so thickthat more than one lateral in each may be re-quired to fully tap it, he adds. “Granite Washtrumps everything you see. It’s world class.That’s why there are 65 rigs running in theGranite Wash right now.”

And, the simple math doesn’t consider thepotential of overlapping Tonkawa, Marmaton,Cleveland, Cottage Grove and underlyingAtoka, Morrow, Springerand Mississippian limestoneformations, he adds.

from the 16,000 deep-gas vertical wells thathave penetrated the shallower Granite Wash andsome 6,500 others that disclose more of thewestern basin’s wet-gas zones.

“No one looked at this as a great resourceplay until about five years ago,” Solich notes.

The potential of the Granite Wash wasmasked for years because radioactive feldsparminerals in the wash wreaked havoc withgamma rays. Barrry McBride, Cordillera man-ager, geology, says, “It makes it look like it’s areally dirty formation when, actually, it isn’t atall.”

A first horizontal well—after the now leg-endary Mitchell Energy & Development Corp.proved horizontal and multi-stage fracing suc-cess in the Barnett shale near the turn of thecentury—was tried in the western basin in2004, followed by a few more. Solich, whoseDenver-based Cordillera III was launched in2007 after selling two successful iterations—both in the basin—drilled a horizontal washwell in 2007. Beginning in 2010, horizontal at-

Wash economicsBreak-even hurdles are competitive too, ac-

cording to analysts at Tudor, Pickering, Holt &Co. Securities Inc. For Bakken wells, $40 to$65 Nymex oil is needed to make a 10% after-tax internal rate of return, they estimate; theEagle Ford condensate window, $40 to $66; theEagle Ford oil window, $48 to $80; and in theGranite Wash, $49 to $55.

Permeability in these tight sandstone and car-bonate washes and in the Tonkawa, Marmatonand Cleveland rocks ranges from 0.01 to 0.70millidarcy and porosity ranges from 3% to19%. Pressure gradient ranges from 0.4 to 0.65psi per foot.

Granite Wash wells cost between $6.5- and$9 million, affected up or down mostly bydepth of the targets, which changes from 9,400feet in the northern area of the play to 15,000feet in the south, and the size of the fracture-stimulation treatment. Frac stages number ap-proximately 12. Some 3.7 million pounds ofsand are used per completion. Frac fluid is sim-ple slickwater.

Wells have had first-24-hour or initial pro-duction (IP) of up to 3,500 barrels of oil and 30million cubic feet of wet, 1,280-Btu gas. Theaverage horizontal IPs 9.5 million cubic feet ofgas and 500 barrels of natural gas liquids(NGLs) per day, and the rates are increasing asoperators improve frac techniques and makelaterals longer where 4,680 feet is the maxi-mum allowed.

Estimated ultimate recovery (EUR) is 7.3Bcf equivalent. A recent Cordillera well, A.C.Smith 41-2HB, in the 120-foot-thick Brittbench, made 17 million cubic feet of wet gasand 632 barrels of oil in its first 24 hours.

Cordillera plans to have 10 to 14 rigs at workin 2012—half in the wash and half targetingTonkawa and Marmaton—and 15 to 20 at workin 2013. Much of its acreage is held by produc-tion (HBP), so choosing locations isn’t rushedto hold its position.

It is pushing the Granite Wash play, whichhas been known to be concentrated in the north-easternmost Texas Panhandle, distally to theeast into Oklahoma and north into HemphillCounty. “People think of this as a ‘Texas Pan-handle only’ play, but it’s pervasive throughoutthe area.”

Solich estimates it will take 64,000 horizon-tal wells to develop the play, including all theGranite Wash benches. “It’s going to be amulti-decade development.”

In its plans for multi-formation, stacked later-als, potentially 54 Granite Wash, Marmatonand Tonkawa horizontal wells could be

made from one section: four in each of the 11washes, four in the Marmaton and four in theTonkawa. “We are far from there technologi-cally, though,” Solich says. Some 275 Bcfemay be recoverable per section.

“The bottom line is that liquids-rich GraniteWash wells are the most economic wells drilledanywhere in the U.S. They are greater than100% rate of return. I would rather be in thisplay than any of the shale plays. Period. That’show good this play is.”

The company hit the 100-million-equivalent-a-day net production mark—currently 70% wetgas and 30% oil on a 6:1 basis—in June and ex-pects to hit 130 million equivalent per day byyear-end: 6,200 barrels of oil and 93 millioncubic feet equivalent of gas that carries five tosix gallons of liquids per thousand cubic feet.

October 2011 ▪ OilandGasInvestor.com 53

Gas in theTonkawaformation acts as“solution gas,”helping to pushoil out of thesenew, horizontalwells, says KamilTazi, Cordilleravice president,engineering andplanning. At top,Cactus’ Rig 121drills Cordillera’sWright 1-29HBfor Granite Washpay.

As it increases its rig count, it expects to hit be-tween 250 and 350 million equivalent a day byyear-end 2015.

And, the Granite Wash’s dry-gas zones thataren’t being drilled today are very economic ata $6 Nymex gas price. “If you put $6 on theNymex, it’s hard to find zones out there thataren’t going to make at least 50% returns.”

Tonkawa, ClevelandThe Tonkawa, which sits above the Granite

Wash, sets up primarily east-to-west reservoirshaving oil legs and a gas cap. In the past half-century that it has been produced, operators fo-cused on the gas, which flowed easily intovertical wellbores. The oil remains to betapped, and the remaining gas offers itself up tohelp push the oil into horizontal wellbores ashandy “solution gas.”

Cordillera’s Grand 1-14HC made 1,205 bar-rels of oil and 1.7 million cubic feet of 1,200-Btu gas in its first 24 hours online after a10-frac-stage completion in a 40-foot Tonkawasection. “We think the recovery factor in theTonkawa will be 15% to 20% on primary re-covery because there is solution gas,” saysKamil Tazi, Cordillera vice president, engineer-ing and planning.

For now, economic Tonkawa is believed tobe present under some 1.6 million acres in thewestern Anadarko. Top wells have been madeby Cordillera, Chesapeake, Mewbourne Oil Co.and Rockford Energy Partners III LLC. Chesa-peake has 16 rigs at work on Tonkawa and onthe Cleveland sandstone that sits below it. Itmay increase the count to 25 or 30 in the com-ing years.

Aubrey McClendon, Chesapeake chairmanand CEO, cites these as two of its top four li -quids-rich plays. The others are MississippiLime in the northern basin and the new Uticashale play in Ohio. It also holds sizable posi-tions in the liquids-rich Granite Wash, EagleFord, Permian and Niobrara plays.

Cleveland and Tonkawa wells have acombined EUR of 600,000 barrels of oilequivalent (BOE), Chesapeake esti-

mates. The company discovered the GraniteWash horizontal play in 2007 and has 420 mil-lion cubic feet equivalent a day of gross oper-ated production there. It discovered theTonkawa horizontal play in 2008 and was anearly developer of the horizontal Cleveland.From the latter two, Chesapeake’s gross oper-ated production is 25,000 BOE per day gross.

It holds 720,000 net acres—or 20% to 30%54 OilandGasInvestor.com ▪ October 2011

Cordillera’s A.C.Smith 41-2HB inWheeler County,Texas, had first-24-hourproduction of 17million cubic feetof gas, 1,554barrels of gasliquids and 632barrels of oilfrom the Brittbench of theGranite Washconglomerate inthe midst of oneof several TexasPanhandle windfarms.

Could he have imagined just 10 years ago thelong-plied basin would see this new attention?“No, I really didn’t. I think the rest of the indus-try would agree. As you know, even in the late1990s, we were seeing waterfall decline curvesyear over year and it really looked like theLower 48 was a depleted asset.

“To imagine we could go back in these oldoil fields with new horizontal drilling and frac-ture stimulation and find a hell of a lot more oiland gas, I can’t say I saw that coming. Butthere’s an adage that the best place to find oil isin an oil field. It continues to ring true.”

Perrin and the Rockford team noticed hori-zontal success in the western Anadarko byGHK Co., Chesapeake, EOG Resources Inc.,Highland Oil & Gas LLC and Jones EnergyLtd., for example, in the past few years and gotto work on its own horizontals there in 2009,targeting the Tonkawa in four operated wellsand also making an operated oil discovery fromCottage Grove.

“We’re continuing to focus on the Tonkawa,but the Cottage Grove is now a stand-alone,economic target. That’s a new, underexploiteddiscovery. It’s a little deeper than Tonkawa. Wedrilled three vertical pilot holes to look at Cot-tage Grove before completing in the Tonkawa,”Perrin says.

Some operators’ IPs out of Tonkawa are asmuch as 1,250 barrels of oil and 2 millioncubic feet of wet gas a day. Rockford’s

10-2H Inselman in southern Ellis County, Ok-lahoma, made 525 barrels of oil and 1.5 millionof gas from about 8,400 feet. Chesapeake’s1011H Day, completed last year in HemphillCounty, Texas, went online at 487 barrels of oiland 1.4 million of gas.

Perrin estimates EUR from horizontalTonkawa wells is 180,000 to 200,000 barrels ofoil and 1 Bcf of gas. “This play has been a littlebit under the radar. It’s been pretty hot out herefor a couple of years and I suspect that, in thenext few quarters, we will see some of the com-peting private-equity-backed companies bringtheir assets to market. There’s a lot of acreagetrading for large amounts of money.”

Rockford itself may be among them, as Per-rin is considering divesting Rockford III byyear-end, as leasing costs have grown to asmuch as $4,000 an acre. “We were fortunate toget in there in the summer of 2009 by makingtwo small producing-reserve acquisitions andwith new leasing. We jumped out to the east ofthe play, in front of the leasing frenzy in thewestern area, and put together two townships ofcontiguous acreage. We have confirmed com-mercial Tonkawa there and that is also wherewe made the Cottage Grove oil discovery.”

Rockford is using 3,600- to 4,200-foot later-als and nine to 14 frac stages. Besides its fouroperated Tonkawa and one deeper CottageGrove well, it has participated in 36 others.“Our game plan, when we got in this, was to

of the total prospective for Cleveland andTonkawa—of its more than 2 million acres inthe Greater Anadarko Basin. “One reasonyou’ve not heard too much about these plays isthat Chesapeake’s…position…is so dominantthat no other public E&P company has beenable to build a meaningful competing interestand talk up the play,” McClendon says.

To date, it has drilled 116 Cleveland andTonkawa horizontals with finding and develop-ment costs of about $12 per BOE. On 160-acrespacing, it estimates it has 4,400 net locationsfor the two formations and possibly some 2 bil-lion BOE of net, unrisked potential.

“These two plays will remain primary driversof Chesapeake’s surging liquids production inthe years ahead,” McClendon says.

Privately held, Tulsa-based Rockford En-ergy Partners has made a play of the GraniteWash and, more recently, the Tonkawa.Backed by private-equity firm SFC EnergyPartners LP, the E&P was formed in April2008 as a fourth start-up by Chuck Perrin,president and CEO. He’s been working theAnadarko Basin since 1979, first with Citgo,then with Apache Corp. and more recentlywith his privately held Sapient Energy Corp.and Rockford I, II and now III.October 2011 ▪ OilandGasInvestor.com 55

“To imagine wecould go back inthese old oilfields with newhorizontal drillingand fracturestimulation andfind a hell of a lotmore oil and gas,I can’t say I sawthat coming,”says 32-yearAnadarko Basinoperator ChuckPerrin, RockfordEnergy PartnersIII LLC presidentand CEO.

buy small leasehold interests in the westernwindow and go to school on other operators.We wanted to learn as much as we could beforewe started drilling our own wells.”

The wells cost $4- to $4.5 million each andmay decline soon to $3.5 million each as effi-ciencies and best practices are gained. “We’veactually seen one operator drill four wells forunder $3.5 million each,” Perrin says.

Meanwhile, at Oklahoma City-based Chesa-peake, which was founded in 1989, theAnadarko Basin is home. Steve Dixon, execu-tive vice president, operations, and chief operat-ing officer, says the basin holds so manyhydrocarbons, it’s no surprise it’s not over.“We’re just getting started with horizontaldrilling on what we will be able to mine fromthe basin,” he says.

In a portion of its Granite Wash play, thecompany plans to offer units in a drilling trust,raising a forecasted $600 million to fund furtherdevelopment.

On its short list to do in the play is to fur-ther define the Tonkawa’s sweet spot.“We have quite a bit of vertical-well

control to see where it is present, but very fewhorizontals have been drilled so far. We areputting a number of rigs on it, so well control isincreasing.”

And, it continues to add acreage overTonkawa where permeability is 0.001 to 0.04millidarcy, porosity is 6% to 12%, pressure is3,000 to 4,500 psi, and production is about 60%oil, 15% NGLs and 25% gas.

EUR on its Tonkawa wells is more than400,000 BOE each on 160-acre spacing, saysJohn Kapchinske, Chesapeake senior vice pres-

ident, geosciences. Looking at the entire western Anadarko

stratigraphic column, how many formationscould be productive with laterals in them at,say, $80 oil? “Well, there are so many, really,”Dixon says. “In the washes, there are multiplezones, stacked. There are multiple memberseven of the Cleveland. It’s a very rich basin.”

211 and countingAt press time, Jones Energy spudded its 500th

well in its 23-year history, and 211 of these arejust Cleveland horizontals it began drilling in2004. In the past year, it’s been averaging one aweek. The Metalmark Capital LLC-backed, pri-vately held E&P founded by third-generationTexas geologist Jonny Jones has doubled staffto 56 in the past 18 months alone.

Gross operated production from its Cleve-land wells is 45.6 million cubic feet of wet gasand 4,078 barrels of oil a day. On a net basis, itis roughly half that and at a net capex cost inthe play since inception of some $250 million.

“There are more than 1,100 horizontal wellsdrilled now in the Cleveland and we’ve madeabout 20% of those, which is pretty amazingfor our size,” says Mike McConnell, presidentand COO of the Austin, Texas-based company.Running at about the same pace is super-inde-pendent EOG Resources Inc.

Jones’ year-end 2010 proved reserves totaled7.3 million barrels of oil, 200 Bcf of dry gasand 22.3 million barrels of NGLs. “It’s amaz-ing the effect of NGLs right now in our rev-enues: 70% of our production is natural gas, but67% of our revenues come from either oil orNGLs. We are definitely focusing on more li -

56 OilandGasInvestor.com ▪ October 2011

Steve Dixon,ChesapeakeEnergy Corp.chief operatingofficer, says,“We’re justgetting startedwith horizontaldrilling on whatwe will be ableto mine from thebasin.” At top, aformerhomestead nearthe Texas-Oklahomaborder.

flowback problems. Stephen Roberts, Jonessenior vice president, Anadarko Basin, says,“Now we have about four months of data tocompare 11 stages with 20 with a recommenda-tion coming soon on precisely how many stagesare most effective on our wells.”

McConnell believes there is more experi-mentation with frac techniques in the Clevelandtoday than in any time in its recent history. “Bycutting down the number of stages, we’ve hadsignificant cost savings. We may not be gettingas much production as fast, but we are focusingon margin per well. We have 250 locations leftto drill in the Cleveland, so we want to get thisright and optimized.”

Its Cleveland wells cost some $3 millioneach; with only 11 frac stages, less.

It has adjusted its lateral length too. Robertssays, “We are getting 4,200 to 4,400 feet of lat-

quids-rich Cleveland locations and morecrude,” McConnell says.

There are drier areas of the Cleveland play.The company holds exposure to approximately112 sections over Cleveland, all HBP, but itisn’t drilling the 15% to 20% window that of-fers drier gas. These targets will be tappedwhen natural gas prices improve. “Right now,we’re just taking advantage of the fact thatNGL prices are very high and it’s adding to ournumbers,” McConnell says.

Its four rigs at work include one targetingGranite Wash, one on Cleveland and two on theArkoma Basin’s Woodford shale in eastern Ok-lahoma, where it picked up HBP acreage earlierthis year from privately held Southridge EnergyLLC and Pablo Energy II LLC.

In the Cleveland, it has taken completions inthe past year from nine frac stages to 20, but ithas dropped back to 11 lately to reduce costsand minimize exposure to mechanical and

Jones Energy isexperimentingwith the numberof frac stages itwill use in theCleveland,ranging from 11to 20, and is alsodrilling negative-vertical sectionwells tomaximize laterallength, saysStephen Roberts,senior vicepresident,Anadarko Basin.

From 211operatedCleveland wellsto date, JonesEnergy Ltd. ismaking 45.6million cubic feetof wet gas and4,078 barrels ofoil a day, gross,says MikeMcConnell,president andchief operatingofficer.Range Resources Corp. made headlines

this spring, reporting a horizontal St.Louis limestone well in the western

Anadarko Basin that came in at 13.8 millioncubic feet of gas and 903 barrels of liquidsor 19.2 million cubic feet equivalent per day.Even more remarkable is that, after produc-ing for seven months as of this July, the wellwas making 12.3 million cubic feet of gasand 760 barrels of liquids or 16.8 millionequivalent per day from the carbonate rock.

“Payout was within weeks,” says JeffVentura, Range president and chief operat-ing officer. It had another one under way thissummer and plans three more by year-end.

The St. Louis limestone is a member ofthe Mississippian-age limestones that aremaking gas liquids and oil from the northernbasin along the Oklahoma and Kansas bor-der. “When you move to the St. Louis, it’svery conventional,” Ventura says. “Youhave a really high-permeability, high-qualityreservoir there as evidenced by the higherflow rate unlocked with horizontal drilling.

“But you’ve got to find that up on a struc-ture. So you have to have more of a conven-tional trap, either a closed structure orthree-way closure against the fault. Sothey’re more distinct, discrete targets thatyou’re looking at.

“The good news is our guys have identi-fied a handful of those, and we’ve leasedthem. I’m encouraged about future potentialfor what that can be. But these leases arenew. We’ve got a lot of time (to drill them).”The Fort Worth-based company is primarilyfocusing today on converting its leaseholdover Marcellus shale in Appalachia to “held

by production.”George Solich, Cordillera Energy Partners

III LLC president and chief executive offi-cer, notes there are many faults in the area ofthe western Anadarko Basin that Range isdeveloping. “It’s a ‘honey pot’ well,” hesays of Range’s St. Louis hole. “A majorfault system runs up there. There is a verticalGranite Wash well there that—out of onezone with four feet of perforations—has pro-duced 200 barrels of oil a day for 10 years.We call it ‘The ATM.’”

With 400,000 gross acres in the westernAnadarko, Cordillera has St. Louis Limeprospective on its acreage, but the formationis deeper than the Granite Wash that it is fo-cusing on and, with few wells drilled as deepas the Mississippian limestones in the area,there is less vertical-well control. A 3-Dseismic shoot would be necessary to de-riskit, Solich says.

“A seismic play doesn’t fit well for ourbusiness model,” says Barry McBride,Cordillera manager, geology. “From thesesmic shoot to the processing to the inter-pretation, it’s almost a two-year turnaround.”

As a private-equity-backed E&P, Cor -dillera’s exit horizon is three to five years.Solich says of a two-year, 3-D project,“That’s over half the expected lifespan ofour company before you even start drilling.But the Mississippian limestone is underhere in the western Anadarko. The Hunton isunder here, the Woodford, the Springer, theMorrow, the Atoka.

“There aren’t enough geologists, engi-neers, rigs or water to get after all of it rightnow—or bankers.”

ST. LOUIS LIME

October 2011 ▪ OilandGasInvestor.com 57

from 12 of these today in sweet spots that madevertical wells economic.

“Horizontal drilling has made a lot of theareas between the sweet spots prospective,”says Rob Johnston, Apache vice president, cen-tral region. “So, all of a sudden there’s been abig push to lease up all the areas between thosesweet spots. We’re finding some of the besthorizontals are not drilled in the sweet spots butbetween them, where you still have pressure.”

The first increased-density—or secondary-re-covery—verticals were drilled in the westernbasin in the late 1970s and early 1980s. John-ston likens the play today to then—“all of asudden, we have our second wind.”

Besides Granite Wash, formations Apache istargeting with a roughly 10-rig program areCleveland, the oily Cherokee clastic carbonatein Harper County where it has made 20 produc-ers out of 22 attempts, and Hogshooter sand-stone. Earlier this year, it added 20,000 acres inthe western basin.

Over the productive Granite Wash, Apachecontrols some 200,000 gross acres and abouthalf of that is net; over Cleveland, 43,000 grossand 26,000 net; and Cherokee, 90,000 gross.Virtually all of it is HBP. Johnston notes thatOklahoma producers will often emphasizegross, and not just net, leasehold, because evena small interest in a unit can get a well drilled inthe state.

In Hogshooter, Apache is leading operatorsin testing horizontals, drilling six successful lat-eral producers in the formation for some $7.5million each and making a first-30-day IP aver-age of 1,100 barrels of oil and 2.7 million cubicfeet a day of wet gas. It might take a look atCottage Grove too. For now, it’s taking a passon Tonkawa and the deep St. Louis limestone,Johnston says.

Apache is also the first company to testmulti-lateral wellbores—that is, two horizontalwells, one in each of two wash members, fromthe same surface wellbore—in the GraniteWash, which offers seven distinct members inApache’s acreage. The depth difference of the

eral, which is the maximum you can do withinstate requirements. We are also drilling nega-tive-vertical section wells to maximize laterallength when necessary.”

Prices for Cleveland leasehold are rangingfrom $300 an acre where potential is lessknown to $2,000, and Jones isn’t buying. “It’shard for us to want to buy leases for $2,000 anacre when we have years’ worth of drilling pro-gram without any lease cost,” McConnell says.

Besides that, virtually all of Jones’ AnadarkoBasin leasehold—over Cleveland, GraniteWash and other formations—is HBP. “It’s im-portant to us to not be a captive of leasehold ex-pirations. We can move rigs around to the mosteconomic areas. We slowed down in the Cleve-land a bit in the past couple months because weare in no hurry. It is a gift to not have to chaseleasehold expiration, which is a problem for alot of companies. We’ve worked hard to be inthat position.”

The company expects it will have drilled 41Cleveland wells this year, and it may comeback over its leasehold in the future for wetMarmaton and dry Atoka gas. Of the latter, Mc-Connell says, “We look at that as a natural-gasoption on our acreage. If the price for gas wentup to $6, the Atoka opens up, where todaywe’re not going to drill it. I don’t think anyoneis drilling Atoka today.”

At press time, Jones brought a Granite Washwell online at 6 million cubic feet of wet gas aday, choked back, in Hemphill County with 15frac stages for significantly less than the $4.3million expected. Of the potential of the west-ern Anadarko Basin, McConnell says, “It’sphenomenal.”

From tertiary to primaryApache Corp. has seen the western Anadarko

Basin from primary recovery to secondary andtertiary—and now back to primary, with the ap-plication of horizontal wellbores and multi-stage fracing. The Houston-based company,founded in 1954, discovered several verticalGranite Wash fields in the 1970s and producesOctober 2011 ▪ OilandGasInvestor.com 59

Above, a sea offresh waterawaits fraccrews uponreporting to thisGranite Washwellsite south ofCanadian, Texas,for completion.Facing page, aSchlumbergercrew fracs aTonkawa oil wellin Ellis County,Oklahoma.

In theHogshooterformation,Apache Corp. hasmade six lateralproducers withaverage first-30-day production of1,100 barrels ofoil and 2.7million cubic feeta day of wet gas,says RobJohnston, vicepresident,central region.

60 OilandGasInvestor.com ▪ October 2011

Facing page, arig drilling forChesapeakeEnergy Corp.overlooks theBlack KettleNationalGrassland inwesternOklahoma andthe drought-driedCanadian Riverbed.

two wash zones the well tapped is about 500feet. The frac in each was complementary, saysTim Sullivan, Apache reservoir-engineeringmanager, central region, “which is what wewere hoping for.”

The lower zone tested 6 million cubic feet ofwet gas a day. After it was produced for awhile, the upper zone was tested for another 6million. Eventually, the production was com-mingled. NGL content was about 300 barrels aday per zone.

Johnston says, “It worked out well. Wedrilled two wells for about the cost of 1.7 wells.It adds a lot of complexity to drilling and com-pletion design, but we’ll do it again and I’msure the industry will too.”

In the Cleveland, the success rate is equallyhigh. The challenge there is staying in zone,says Ken March, exploitation manager, centralregion. “If you get out of the zone, you don’tmake a well. We don’t have any wells you cancall a dry hole, but we do have a range of IPsand reserves and it’s a function of how well youkeep your lateral in zone.”

Horizontal drilling in the western Anadarkohas changed everything, Johnston says. “Whowould have thought acreage would cost over$2,000 an acre in an area where we used to pay$300? But it’s giving us enough to do for a fewyears.”

How many years? “We have thousands of lo-cations identified, so a long time.”

It’s an incredible statement for an interna-tional oil and gas company whose long-pliedonshore U.S. plays compete with somewhatvirgin plays abroad. “Yet this was Apache’sfirst play and continues to play a vital role on agoing-forward basis,” Johnston says.

“It’s ironic that a mature gas region, wherewe are operating on acreage acquired in the1970s, is generating rates of return here that areas good as in some of our new, very-underex-ploited regions.”

Take-awayThe liquids-rich Anadarko Basin is changing

the American NGL production profile too. GrossU.S. NGL output had declined from a record2.034 million barrels a day in 2001 to 1.459 mil-lion in 2006. A new record was set at 2.036 mil-lion in September 2010, according to the EIA,and the figure has continued to grow since.

Research firm Bentek Energy LLC, in ayear-end 2010 report, “The Rich Get Richer,”cites “the liquids fairway” from South Texas tothe Bakken oil play in North Dakota andSaskatchewan, plus the wet-gas window of theMarcellus shale play in Appalachia, as makingthe revival. The new onshore supply is offset-ting declining Gulf of Mexico wet-gas volumesas drilling there remains impaired by the U.S.Bureau of Ocean Energy Management, Regula-tion and Enforcement.

Prices for NGLs are at a premium as a resultof the 1:22 oil to gas price differential. NGLsare trading for more than $57 a barrel or, on a

million-Btu basis, for $15.80 per million Btu,compared with dry gas at $4 and West TexasIntermediate crude oil at $14.83.

“New pipeline and fractionation capacityprojects are under way,” Bentek notes. “Petro-chemical companies are pursuing the capabilityto run higher volumes of ethane. Gathering sys-tems and gas-processing plants are under con-struction from South Texas to the Rockies toAppalachia.”

As the center of U.S. NGLs production isshifting west, away from the Gulf of Mexico,“the increased distance of much of the newproduction from ‘fractionator alley’ and thepetrochemical markets along the Gulf Coast isdriving new midstream investments inpipelines, gas-processing plants and other fa-cilities necessary to support increasing NGLvolumes.”

To take the growing NGL output from theAnadarko Basin to Gulf Coast end-users,DCP Midstream LLC plans to convert

and reverse ConocoPhillips’ Seaway refined-products pipeline to deliver 150,000 barrels ofNGLs a day, instead, to the Gulf Coast by mid-2013.

In addition, Midcontinent operator OneokInc. has plans to expand its Midcontinent-to-Gulf NGL pipeline. And, at press time, Enter-prise Products Partners LP and partnersannounced plans for the new Texas ExpressPipeline that will take an initial 280,000 barrelsof NGLs a day—expandable to 400,000—tothe Gulf Coast for fractionation and end-use.

Bentek forecasts NGL production out of theGreater Anadarko Basin will increase 60% by2020.

Getting oil out of the western Anadarko isalso a challenge. Brad Eubanks, productionmanager for Apache’s central region, says get-ting volumes from the western Anadarko tomarket “is constantly a problem but so farwe’re able to keep up. It’s just a product of ourown success and the industry’s success. Wetripled our oil production this year and wetripled it last year. We’re in a gas region butwe’re drilling a lot of oily wells. Moving thatoil in a basin that was all gas has become a realchallenge.”

Cordillera’s Solich says, “This is a renais-sance, something I’ve never seen in my career.Right in the midst of this old, prolific basin,these rocks are going to produce every bit, ifnot more, than the shale plays. It’s part of thehorizontal-completion revolution.”

He notes that the basin—for all its growingoutput, relatively low well costs and repeatabil-ity—doesn’t make headlines like the Marcel-lus, Eagle Ford and Bakken. “Maybe weshould have called it a shale,” he quips. In fact,there is shale mixed within the Granite Washconglomerate.

“We laugh about it. But, I’ll repeat this: Whenyou stack up the potential of the westernAnadarko, it will be greater and more economicthan most of the shale plays. I would rather be in