Tight Oil, Shale Gas to Drive Lower 48 Production

Tight oil and shale gas plays will be the primary driver behind US Lower 48 production growth through 2020, Wood Mackenzie reports.

A handful of unconventional plays will drive U.S. Lower 48 oil and gas production growth, according to a recent analysis by Wood Mackenzie.

Tight oil production is expected to reach 6 million barrels per day (MMbpd) by 2020 in the Lower 48, thanks to production in the Eagle Ford, Bakken and Bone Spring/Wolfcamp plays in the Permian Basin, John Dunn, who manages Wood Mackenzie’s Lower 48 upstream research, told reporters at a media briefing Wednesday in Houston. Overall U.S. liquids production in 2020 is forecast to reach nearly 9 MMbpd.

Oil and condensate production from the Eagle Ford play in South Texas is expected to reach 2 MMbpd by 2020, while Bakken production is forecast to hit 1.7 MMbpd by 2020, according to Wood Mackenzie estimates. By 2020, oil and condensate production from the Bone Spring/Wolfcamp play in the Permian Basin – the new kid on the block – is expected to reach 800,000 barrels per day (bpd).

Natural gas production in the Lower 48 also is expected to rise -- primarily to the Marcellus and Utica shale gas plays in the U.S. Northeast – with 2020 production of 25 billion cubic feet per day forecast.

After a number of dire years, the outlook for U.S. oil and gas production is a very positive picture, particularly for the Lower 48. 

“It’s about the sub-plays and the stories in those subplays that is making all the difference,” Dunn commented.

For the Bakken and Eagle Ford alone, Wood Mackenzie estimates that $40 billion in capital expenditures will be spent on development this year. Oil and gas companies are now moving from the exploration and appraisal phase to development in the Bakken, Eagle Ford and Marcellus plays. Now that operators have figured them out, they’re trying to make things work where they work where they know it works, said Dunn. The pace of development in the Permian Basin also is picking up, Dunn noted.

North America is not only playing a key role in production CAPEX, it’s very important from a global perspective in terms of reserve additions, Dunn said. Wood Mackenzie analysts found that, from 2007 to 2013, international oil companies – which includes the majors but not national oil companies – doubled their North American reserves, more growth on a volume basis of other regions combined. Individual companies have made big gains, which is why some pure play North America companies have done well, Dunn noted.

While some emerging shale plays in the Lower 48 are making a difference for individual companies, Wood Mackenzie views the specific plays it reviewed as the most prolific in the near-term, said Dunn, adding that, “We don’t see any plays that will be the next Bakken in 2016.”

Bakken Improving, But Smaller Footprint Seen for Three Forks

Wood Mackenzie estimates that 21 billion barrels of light sweet crude oil will be ultimately recovered from the Bakken and Three Forks play in the Williston Basin, higher than the U.S. Geological Survey’s (USGS) April 2013 updated estimate of 7.4 billion barrels. The amount of recoverable Bakken resources has increased as estimated ultimate recoveries for wells have improved, thanks to completion techniques and technologies and to spacing of wells, said Jonathan Garrett, an analyst on Wood Mackenzie’s U.S. Lower 48 Upstream Research team who focuses on the Bakken.

However, Bakken reserve estimates will likely flatten expansion of activity in the Bakken’s core is countered by the smaller-than-expected commercial limit of the Three Forks’ lower benches. Wood Mackenzie estimates the footprint of commercial lower Three Forks development will be between 3,000 and 3,500 square miles. 

Wood Mackenzie’s number is higher than the USGS estimate due to its use of more recent production data, which covers an 18-month period from mid-2012 to the end of 2013. Garrett said Wood Mackenzie took into consideration the likely and proven downspacing patterns of wells used by industry. When calculating its estimate, the USGS assumed less than four wells per spacing unit. Wood Mackenzie views this spacing as conservative, given that they’ve seen much more dense projects throughout the Williston Basin, said Garrett.

High-density development projects have accelerated in the Bakken. Initially, operators were focused on the Middle Bakken in the central and deepest part of the Williston Basin, where they would drill one well into a space to get acreage held by production and to test a field’s commercial limit.

Attention has shifted from held by production drilling to maximizing production with new wells without interfering with existing wells. Operators are still working to optimize the number of wells per pad, Garrett noted. This new phase includes exploration of the Three Forks formation beneath the Bakken in the deepest, most overpressured portion of the play. Three Forks offers upside in that, instead of buying additional acreage, another play could be tapped.

“Like the Wolfcamp, it’s easier to increase value by exploring targets deeper on existing acreage than acquiring new acreage,” said Garrett.

However, Wood Mackenzie anticipates that benches two, three and four of the Lower Three Forks will only be commercial in Williams County. While Continental Resources has several wells on production for the Three Forks’ fourth bench, Wood Mackenzie does not see it as a discrete bench, as only six to eight feet separate benches three and four, said Garrett.

Historically, the Three Forks has been the primary target for drilling on the fringe areas of the Williston Basin, as the Bakken thins out in the northern and southern portions of the basin, but that is changing as well costs decline and estimated ultimate recovery (EUR) rates improve.

“It might not have made sense in 2010 to spend $13 million on a Bakken well with 3,000 barrel of oil equivalent rate; today, it might make sense to spend $6 to $7 million on a well with 300 to 350,000 boe on an EUR basis as the play is becoming more commercial and economic,” said Garrett.

At Elm Coulee, the birthplace of the Bakken, Slawson Exploration Company Inc. and PetroShale Inc. are drilling into the Upper Bakken is taking place; if successful, this will have implications for the rest of the play to the east.

While non-core Bakken areas offer opportunities for smaller, equity-backed operators to enter the play, production resulting from this activity will not be enough to change the impact of the lower Three Forks smaller economic footprint, Garrett noted.

Due to limited pipeline infrastructure, Bakken operators have relied on railroad to ship crude to market. The amount of Bakken crude being transported by rail has more than doubled, from 30 percent in early 2012 to 70 percent more recently. However, rail is not just a stop gap measure. With the netback for barrels minus transportation, crude by rail is still preferred as it fetches a price closer to North Sea Brent crude versus Cushing, Okla., prices.

“Companies are making money, even though rail is expensive,” Garrett commented.

By 2016, the gap capacity gap between rail and pipeline capacity is expected to shrink due to three pipeline projects: Enbridge’s expansion of its pipeline to Superior, Wisconsin, the Double H pipeline to Guernsey, Wyo., and Energy Transfer Partners’ planned pipeline project that would take Bakken crude to the Gulf Coast.

Energy Transfer Partners’ project offers the best of both worlds, with premium Gulf Coast pricing and low transportation rates, Garret noted. Gulf Coast pricing is why operators are sending barrels by rail to markets such as California, Washington State and Philadelphia. However, companies will want flexibility to use either rail or pipelines, and will not go all-in on either mode of transportation.

Operators also are starting to get out ahead of rail safety regulations coming down the pipeline. Earlier this year, the American Association of Railcars reported it would implement new standards for tanker cars that would require thicker walls. However, the $15,000 to $20,000 per tanker car retrofit costs will not be enough to deter production from the Bakken or Three Forks, Garrett noted.

Eagle Ford Production to Rival Alaska’s North Slope at Peak

The Eagle Ford’s estimated crude and condensate production in 2020 will equal the production from Alaska’s entire North Slope at its peak, nearly half of the production from Ghawar, the world’s largest onshore field, and 150 percent of combined Bakken and Three Forks production on a barrel of oil equivalent-basis, said Cody Rice, who works on Wood Mackenzie’s Lower 48 Upstream Research team and focuses on the Gulf Coast, Permian and Mid-Continent regions.

Wood Mackenzie this year raised by 23 percent its estimate of Eagle Ford production in 2020 from its previous estimate made last fall, and its estimate of 2014 CAPEX spending. This year, operators will spend $27 billion in CAPEX on the Eagle Ford, $4 billion higher than Wood Mackenzie’s fall 2013 estimate, with nearly 80 percent of spending focused on the play’s condensate core.

The costs of drilling more than 3,000 wells a year is the primary driver behind CAPEX spending, said Rice. This year, 3,300 wells will be drilled in the Eagle Ford. The number of wells will level off, with a slight year-on-year increase in 2014, but 3,000 wells a year will generate a massive amount of production and CAPEX. The Eagle Ford play also still offers a massive opportunity, with $122 billion in remaining NPV 10, said Rice.

Many people think of the Eagle Ford in three main areas – shallow and oily in the north, deeper and gassier in the south, with a condensate window in the middle. Wood Mackenzie broke down the Eagle Ford into nine subplays to allow a better focus on benchmarking comparisons and economics.

The estimated 2 MMbpd that will Eagle Ford will produce in 2020 is massive, but that level will not be prorated across the play. Instead, three of the nine sub-plays within the Eagle Ford – which include the Karnes Trough, Maverick Condensate, Southeast Gas, Edwards Condensate, Black Oil, Maverick Oil, Hawkville Condensate, Southwest Gas, Northeast Oil – will comprise 60 percent of the Eagle Ford’s 2020 production. The Karnes Trough, which comprises only 3.8 percent of Eagle Ford acreage, will produce 25 percent of that total production.

Location is key to success in the Eagle Ford, with early entry into the play, accessing the play’s core for strong liquids and IP rates, and keeping costs low on the margins, said Rice. 

“I’ve heard people say that majors can’t be successful in the Eagle Ford, and that costs are a key predictor of success, and I’ve heard some say it’s IP or liquids weighting.”

However, Wood Mackenzie’s research findings support none of these claims individually. Instead, access to the play’s core, where IP rates and liquids weighting offer a good return, is critical. Here, the gas drive mechanism is available to keep IP rates up, while enough liquids exist. This is true for large and small companies.

New Kid on Block Permian

Wood Mackenzie believes the Wolfcamp play in the Permian Basin is an elite shale play, and belongs in the same conversation as the Bakken and Marcellus plays, said Benjamin Shattuck, Wood Mackenzie Lower 48 Upstream analyst who focuses on the Permian.

The oil-soaked Permian Basin, which has been producing for a century, is at the jumping off point for a long future of production, Shattuck said. The B bench of the Wolfcamp is the most prolific, while the A and C benches of the play are more marginal. Results are improving for A and C bench and will keep improving, but not enough to reach the production level seen in B. Rolling in A and C with B will increase per acre value from $9000 to between $17,000 and $18,000, but it’s not the same as multiplying the value by three.

Unlike the Eagle Ford – where location is key to success – companies who have at least five years of proprietary knowledge of the basin or more than 70 percent of onshore CAPEX focused on the Wolfcamp, tend to outperform their peers, Shattuck said. Operators are making strong headway in terms of increasing value on a per section basis and achieving cost savings, with the more than $115 billion in spending in Wood Mackenzie’s base case to rise as derisking continues. However, derisking of marginal benches won’t mean much through the end of the decade, as midstream and personnel constraints in the Permian will make it difficult for operators to expand operations.

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