Liquids plays rejuvenate Lower 48 onshore basins

Oct. 3, 2011
Plays for oil or wet gas have revitalized exploration and development in the US onshore Lower 48.

Alan Petzet
Chief Editor-Exploration

Paula Dittrick
Senior Staff Writer

Plays for oil or wet gas have revitalized exploration and development in the US onshore Lower 48.

Economic drilling, most of it horizontal, has pushed up the active rig count to its highest level since 2008 and is reversing production declines in some areas, operators report. The Baker Hughes Inc. weekly count was at 1,991 rigs as of Sept. 23, and nearly two thirds of the rigs were drilling horizontally.

The various plays are spawning new gathering systems, pipelines, gas processing plants, and even rail transportation for the liquid hydrocarbons. They have created thousands of jobs, raised water use issues, and attracted regulatory scrutiny.

The stock market has crushed many energy stocks in the past few months, but Raymond James & Associates has forecast that US production growth of circa 11% in 2011 should drive 2012 capital spending and cash flow up 10-15% in 2012.

EOG Resources Inc. Chief Executive Officer Mark Papa believes horizontal shale plays will account for an uptick in US oil production of 1.5 million b/d by 2015 relative to what US production would have been without them.

Goldman Sachs economists in an Aug. 8 note forecast US oil production, which includes natural gas liquids, at 8.06 million b/d for 2011 and 10.27 million b/d for 2017. Unconventional liquids are expected to play a significant role in future production.

This article is a summary by OGJ editors of several of the plays that have restored new excitement in this collection of mature North American onshore basins just as offshore drilling struggled to recover from a federal moratorium.

Bakken-Three Forks play

A rough 2010-11 winter in North Dakota and Montana slowed field operations in the Bakken-Three Forks, but drilling has remained strong.

North Dakota had 190 rigs running in late September, and IHS Inc. has reported that 1,150 horizontal wells have been drilled since Jan. 1, 2009.

Continental Resources Inc., Enid, Okla., tallied various organizations' estimates of Bakken potential and came to a figure of 24 billion bbl of estimated ultimate recovery. Based on well performance in the prior 12 months, Continental in August hiked its EUR model in the North Dakota Bakken to 603,000 boe/well from 518,000 boe.

IHS, meanwhile, which had forecast that the play would be producing 800,000-1 million b/d by 2018, said in August 2011 that output already appears to be ahead of that curve.

The drilling of so many wells often leads to serendipitous discoveries, and a Marathon Oil Corp. exploration official said he sees a number of other plays getting ready to take off in the Williston basin.

EOG began shipping some of its Bakken crude by railroad unit train to Cushing, Okla., on Dec. 31, 2009, and Tesoro Corp. will start rail shipments to its Anacortes, Wash., refinery in 2012.

With Cushing storage at capacity, some Bakken oil is finding its way to Louisiana. The Keystone XL pipeline, if built, could in time help break the Cushing snarl.

Eagle Ford/Cretaceous Trend

This play in the Gulf Coast and Maverick basins has nearly caught up with the Bakken in terms of drilling with an estimated 169 rigs running.

Production has grown from nothing to 125,000 b/d of oil and condensate in less than 18 months, IHS noted, and the play is estimated to hold 2-9 billion bbl of oil and condensate and 40 tcf of gas plus NGL recoverable.

Pipelines are filling, and before numerous new ones can be laid, EOG will ship 20,000 b/d of Eagle Ford crude by rail by the end of 2011.

The jury is still out on the potential of the slightly deeper, gas-prone Pearsall shale in the Maverick basin.

Across the Rio Grande, Petroleos Mexicanos completed its first horizontal Eagle Ford well in Mexico earlier this year.

Farther east along the Cretaceous Trend, the first few exploratory wells are being drilled to test the deeper Tuscaloosa marine shale in Louisiana and Mississippi. A 1997 Louisiana State University study estimated that 7 billion bbl of oil might be recoverable from that formation.

Niobrara and Mancos

The age-equivalent formations have produced for decades in discrete fields in Colorado, New Mexico, Utah, and Wyoming.

EOG found Niobrara oil in Colorado's North Park basin but had transportation constraints and moved over to the Denver basin, discovering Hereford Ranch field at the Jake well. Several other operators have followed with five and six-figure acreage positions.

The two formations are known source rocks in numerous Rocky Mountain basins, and Niobrara is productive in Canada where it's called the Second White Specks.

Permian basin oil plays

Of about 900 rigs running in Texas, nearly 400 are in West Texas where the new plays combined with carbon dioxide enhanced oil recovery have reversed a decades-long production decline.

Apache Corp., at 92,000 boe/d, second only to Occidental Petroleum Corp. in oil output in the region, is using rail cars to ship NGL to Louisiana until a Permian gas processing plant is up and running.

The basin hosts numerous conventional and unconventional oil plays. Apache is completing its second horizontal well in the Cline shale, between Wolfcamp and Strawn, in Glasscock County.

EOG's Papa noted that shale oil plays offer good economics and among the lowest break-even points of all US oil plays.

He said West Texas Intermediate crude oil prices would have to drop below $60/bbl on the New York Mercantile Exchange—and industry would have to believe prices were going to hold at that level for awhile—before oil companies would cut back on shale oil exploration and development.

The West Texas Permian Wolfcamp shale potentially could rank as one of the 10 largest US oil fields, Papa told a Barclays Capital CEO Energy-Power Conference in New York on Sept. 8.

"The play is truly in the first inning," Papa said. EOG has 131,400 net acres in the play where it identified multiple pay targets and had completed 14 horizontal wells as of Sept. 8. It is running two rigs and expects to ramp up development in 2012.

Ridgeline Energy Services Inc., Calgary, said last week it will recycle water for an undisclosed client operator that has estimated likely reserves of 65 million boe in the Leonard shale on 31,000 of its 120,000 net acres in the play in New Mexico. The company will treat produced and flowback water from the client's centralized oil production facility for reuse in hydraulic fracturing or disposal.

Marcellus and Utica shales

The supergiant Marcellus shale gas play in Pennsylvania and West Virginia rolls on with a rig count hovering around 100.

The US Geological Survey provided more encouragement in August with an estimate that the play contains an undiscovered, technically recoverable resource of 84 tcf of gas and 3.4 billion bbl of natural gas liquids. New participants still are joining the play.

One operator, Range Resources Corp., has placed its first two Upper Devonian gas wells on line but is developing its Marcellus shale acreage first to hold the leases. Later it will develop the deeper Utica shale, for which it has quantified but not disclosed the potential.

In eastern Ohio, Chesapeake Energy Corp. announced its first four discovery wells last week after a sprawling land play for Utica shale leases. Only about three dozen Utica drilling permits had been issued through mid-September.

Anadarko basin Granite Wash

Around a dozen operators are drilling laterals in 12 or more fractured, low-permeability formations in the Anadarko basin known collectively as Granite Wash.

The area centers on Custer, Washita, Beckham, and Roger Mills counties, Okla., and adjacent Texas Panhandle counties.

Horizontal multifrac wells are providing years of relatively low-risk drilling in immature sandstones 1,000-1,500 ft thick vertically with as many as seven to eight sand stringers with permeabilities of 0.002-0.008 md.

New productive intervals are being found, including several that are not Granite Washes and some that have never been drilled horizontally.

As long ago as the 1970s, many wells drilled to 15,000 ft or deeper for gas discovered oil indications in the Granite Washes that were uneconomic in vertical wellbores. A 4,000-ft lateral with as many as 20 frac stages today can IP an average 55 MMcfd and 350 b/d, 50% oil, condensate, and NGL, or 10 or more times that of a vertical well.

As a gas basin, the Anadarko lacks liquids pipelines, and with the increased drilling during drought water is a major issue. Trucks are in high demand to haul water and hydrocarbon liquids until it becomes clear where to lay gathering systems.

Midcontinent Mississippi lime

This conventional formation is a thick, high-permeability carbonate at about 6,000 ft that has been partly drained by 7,800 vertical wells in northern Oklahoma and southern Kansas the past 30 years.

One operator, SandRidge Energy Inc., has drilled 111 horizontal wells and believes it has established reserves that average 390,000 bbl of oil equivalent/well.

SandRidge is completing its first well in Comanche County, Kan., and is also drilling in Harper, Sumner, and Barber counties.

The company said the play needs a 30,000 b/d water disposal well and water gathering system for every 10 producing wells.

Smackover Brown Dense

Drilling is just getting under way in a horizontal play for oil in Upper Jurassic Lower Smackover Brown Dense dolomite along the Arkansas-Louisiana state line.

Southwestern Energy Co. has a well permitted in Columbia County, Ark., and plans to drill in Claiborne Parish, La., before the year is up. Devon Energy Corp. has a permit to drill in Morehouse Parish, La.

Southwestern disclosed that it holds 460,000 net acres and has made a $150 million investment in land and geoscience work. It said the formation's commerciality is undermined but promising. The company's first well will go to 8,900 ft true vertical depth and have a 3,500-ft lateral.

Monterey shale onshore

With only 50 rigs running in California, a shale that ranks as one of the oldest plays in the US is attracting more participants in several basins.

Occidental Petroleum Corp.'s 2009 Kern County discovery reawakened interest in California, and in May 2010 Oxy said it was starting a 4-year development program for shale production. It said it would appraise more than 15 identified areas, drill 10-15 test wells/year, and shoot the largest 3D seismic program in California history.

Venoco Inc., Denver, is a proponent of drilling the Monterey vertically onshore. Underground Energy Inc., Santa Barbara, has Monterey prospects in the Asphaltea area in the Santa Maria basin in northern Santa Barbara County.

At current oil prices and with horizontal drilling and multistage fracturing, some operators suggest Monterey shale oil recovery eventually could eclipse that of the Bakken.

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