Oil producers focus on Bakken and Eagle Ford as they hunt for crude potential and keep an eye on emerging shales
By Bridget Hunsucker in Houston
January 31, 2013 - The potential crude reserves are scouted. Producers are pioneering. But, will any of the just-emerging tight crude plays scattered across the US onshore post significant results in 2013?
Analysts say some bets have been made, but the industry will watch and wait.
Names like Utica, Anadarko Woodford, Tuscaloosa Marine and Niobrara always seem to pop up when discussing emerging unconventional basins.
"They are all getting mentions, but it's hard to tell if it's just noise until we see some production numbers moving out and drilling rigs moving into those areas," said Sandy Fielden, director of energy analytics at RBN Energy LLC.
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In contrast, the Bakken Shale in North Dakota and the Eagle Ford Shale in South Texas are rarely mentioned without a nod to fast-growing, record-breaking and long-lasting crude production.
"Production is growing so fast, if you added another [Bakken-sized field] on top of it, it would be too much [for the US to] consume," Fielden said.
During 2013, domestic crude production is expected to reach 7.05 million b/d, up from 6.41 million in b/d 2012, according to US Energy Information Administration data. The estimated 2013 level of crude oil production would be the highest level since 1993, the EIA said.
The Bakken Shale in North Dakota and the Eagle Ford Shale in South Texas contribute about two-thirds of US tight oil production, according to the EIA's short-term energy outlook report from December 11.
Activity in the two shales is driving much of the new production growth. The Bakken and Eagle Ford are expected to add nearly 2.4 million b/d of domestic supply by 2022, according to Bentek's Crude Awakening report released in October 2012. Bentek is a unit of Platts.
At the start of December, the Bakken in North Dakota is projected to have produced 813,000 b/d of light sweet shale crude, up 276,000 b/d from the previous year at the same time, according to Bentek data. At the end of 2013, the Bakken is expected to produce 1.03 million b/d. Production for the Bakken shale in Montana is also expected to rise to 97,000 b/d by the end of 2013.
At the end of 2020, Bentek expects the Bakken to produce 1.76 million b/d.
Outpacing the Bakken next year, Eagle Ford's 2013 production levels are expected to rise to 1.18 million b/d by the end of next year, 311,000 b/d higher than in 2012, according to Bentek. In the Eagle Ford, crude and liquids production has was just 100,000 b/d in 2011, according to Wood Mackenzie analysts.
Rounding out the US' top three producing fields is the Permian Basin in Texas and New Mexico, which consists of layers of conventional and tight formations.
In the Permian Basin, production rates for Texas are expected to close 2013 at 1.24 million b/d, up from 1.08 million b/d at the end of 2012, Bentek said.
Texas is bigger
In 2012, "The most attention certainly came from the North Dakota Bakken, but actually growth (in) oil production in Texas exceeded that [of the Bakken] over the last 12 months," said Andy Lipow of Lipow Oil Associates. "They have both shared the limelight -- Texas and North Dakota."
The Bakken received the most market attention in 2012, not only because of record setting production, but because of the "infrastructure challenges that midstream got around during the year," Fielden said.
North Dakota crude oil production shipped by rail has climbed to more than 50% this fall from about 1% in 2009, according to North Dakota state records and leading Bakken producer Continental Resources. Bakken Blend crude now moves by rail to the East, West and US Gulf Coasts. Read a related story about rail shipments of Canadian barrels to Arkansas by Delek.
Continuing logistic issues including a lack of pipeline takeaway capacity, potential government restrictions on shale drilling and the cost of fracking could all impact Bakken production next year, said Turner Mason analyst John Auers.
Nevertheless, growth is expected to continue in the Bakken for five to seven years, Auers said.
Early moves are also being made in young shale plays, analysts said.
Noble Energy expects next year to invest $1.7 billion in the Denver-Julesburg (DJ) Basin within the Niobrara Basin in Colorado, the company said earlier in December. Noble plans to expand the drilling program there to include 300 horizontal wells in 2013.
Noble's "recent announcement regarding its 2013 horizontal Niobrara drilling program makes the DJ Basin the most important" emerging play for next year, said Bentek analyst Jim Klingsporn.
The Niobrara basin is situated mostly in Colorado. It has a long history of oil production but has seen a recent surge in output, according to Turner Mason's 2012 North American Crude Outlook released in mid-September.
There is substantial opportunity in the Niobrara, but production has not matched expectations, Turner Mason said in the report. In 2012, Niobrara production was an estimated 116,000 b/d, and is expected to rise to 138,000 b/d in 2013, according to the Turner Mason report, which does not take into account Noble's drilling plan.
However, Bentek shows in a December report (after Noble's announcement) that DJ Basin production alone should rise to about 140,000 b/d in mid 2013. The DJ Basin production is expected to end the year near 120,000 b/d, according to Bentek data.
"Oil has been produced there for a long time," Auers said about the Niobrara Basin. "There has been mixed results, but the potential could be huge."
Like Noble, Continental Resources next year will continue to pioneer an area of the Woodford Basin within the Anadarko Basin in Oklahoma that the company has coined SCOOP, short for the South Central Oklahoma Oil Province.
What's the SCOOP?
Continental currently has a leasehold of more than 170,000 net acres, and expects a net reserve potential of 1.8 billion barrels of oil equivalent. The new play is "one of the thickest, best-quality resource shale reservoirs in the country," according to a company presentation given to investor's in October.
SCOOP is located just south of and has six times the reservoir volume of the Cana field, said Jim Bucci, geologic manager for the southern region exploration department, during the presentation. Because of this the company has increased its acreage there by 80% in the last 18 months, The company has drilled or participated in 35 wells in the SCOOP play and has confirmed hydrocarbon resources in an area greater than 600,000 miles.
The Anadarko Basin, located mostly in Oklahoma and Kansas has an estimated undiscovered recoverable conventional reserves of 102 million barrels and 393 million barrels of undiscovered recoverable shale reserves, Turner Mason said in the report citing a 2010 USGS study.
"Nearly 80% of the region’s reserves are in shale formations and the addition of these reserves has increased the total recoverable estimates by nearly five-fold," according to the report.
Including both states, total Anadarko Basin production is expected to end 2013 at 267,000 b/d up 35,000 b/d from the end of 2012, according to Bentek data.
It's too early to forecast potential production rates for the Utica Shale in Ohio and the Tuscaloosa Marine Shale in central Louisiana and southern Mississippi, Auers said.
"At this point in time, the Utica is a crap shoot," Auers said. However, "it could be a big important supply source for suppliers in the region," he said.
Area refiners are already gearing up to receive the crude, and because of the relatively small volumes, Utica production will generally be transported by trucks, Turner Mason said in the report.
The crude would eventually compete with the Bakken Blend crude that is being railed to the East Coast if production ramps up, Dahlman Rose analyst Sam Margolin said. The crudes are of the same quality.
Utica production is expected to steadily rise in the near term and then hit 120,000 b/d at the end of the decade, according to the Turner Mason report.
"For the Tuscaloosa Marine Shale, the oil there is significant, but no producer has produced consistent and economic well results," Klingsporn said.
EOG Resources is working on its first two wells in the shale, but competitor Devon Energy has indicated that they will slow activity in the play because of high costs, he said.
"A drawback to the play is that the drilling and completion costs are high due to the depth of the formation," according to the Bentek report.
In the Tuscaloosa Marine, the targeted marine zone is found on average 10,000 to 14,000 feet deep. It is similar age to the Eagle Ford Shale and is estimated to have a reserve of about 7 billion barrels of oil that can be reached with horizontal drilling technology.
If "just one of the [new] areas emerges as the next Bakken or Eagle Ford then this could dramatically change the oil production growth outlook in the next 10 years in North America," according to Bentek.
Already crude oil stocks are expected to grow to a peak in April 2013 of 390.8 million barrels before declining to 346.5 million barrels at the end of the year. Stocks will end 2012 near 358.2 million barrels, according to the EIA. A good deal of
stored crude has collected in Cushing, Oklahoma, the location for the NYMEX light sweet crude futures contract. West Texas Intermediate is the crude basis for the contract.
Next year a new benchmark could emerge along the Gulf Coast as pipeline capacity opens to the region from the Midwest.
A good deal of Eagle Ford crude is already trading along the Gulf Coast, and there has been talk of an Eagle Ford benchmark in connection with Enterprise Product Partner's Echo Terminal, Fielden said.
The Houston-area terminal, which has an initial storage capacity of 750,000 barrels, is positioned to link onshore production areas with onshore refineries. The terminal took its first oil in early November.
"More likely a Houston quote for WTI will emerge," Fielden said. "There will be an Eagle Ford quote or index, but it won't be as important as WTI. After more pipeline capacity comes online, WTI will make its way to the Gulf Coast from both the
Permian Basin and Cushing, he said.
Ultimately, Midwest and Gulf Coast prices will move closer together in 2013, Fielden said. "There has to be space available to move Cushing to the Gulf Coast," he said. "It won't be in the first quarter [of 2013]. It will happen at the end of the year."
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