The midstream and downstream challenges — roads, transportation and refineries — that face the big Bakken, Eagle Ford, Permian and Niobrara plays preoccupied many speakers at recent conferences in Washington, D.C., and Denver.
And it started with gaining access to the prolific plays in North Dakota.
“The infrastructure is stressed,” Mark Williams, senior vice president of exploration and development at Whiting Petroleum, told a Platts Rockies Oil and Gas Conference.
“The road system is very difficult. It’s difficult to move oil field services in this part of the basin.”
He said the takeaway capacity from the Bakken is currently remaining about six to 12 months ahead of production, “but we need a coordinated effort between industry and local governments” to overcome the road problems.
With the downturn in service costs benefiting from the cutback in dry gas drilling, “a lot of equipment has come out of plays such as Haynesville Shale (in Louisiana and East Texas), looking for work,” Williams said.
Frontier Energy Group Chief Executive Officer Dan Eberhart described the North Dakota infrastructure problems as “dire.”
He said “some roads are literally crumbling. … You’ve got potholes that could eat a truck,” while acknowledging that North Dakota legislators approved a massive investment in roads last year.
More investment needed in NGL systems
But, even if progress is made in that sector, greater investments are needed in pipelines, natural gas liquids processing and gathering systems and finding markets, Tyler Van Leeuwen, project manager with Advanced Resources International, told a conference organized by the Center for Strategic and International Studies and the National Capital Area Chapter of the U.S. Association for Energy Economics.
He said that although tight oil formations in the Bakken and Eagle Ford in Texas, and the Permian basin in Texas and New Mexico, could yield 4 million barrels per day by 2030, and even rise to 9 million bpd, that calculation is based on the assumption of “productive capacity,” which takes into account current prices, the availability of rigs and similar factors.
The Bakken alone is currently flaring 100 million cubic feet per day of natural gas because there is no way to move it off site, Van Leeuwen said.
He said his research and consulting firm estimates U.S. unconventional plays, defined as shale areas where crude can only be extracted using horizontal drilling and multistage hydraulic fracturing, hold 44 billion barrels of mostly light, sweet crude and 57 billion barrels of NGLs.
Sarah Emerson, principal of Energy Security Analysts, said expansion of tight oil prospects could be hindered by how fast midstream assets are improved and how much heavy, sour crude enters the U.S. from Canada.
She doubted the U.S. will even produce 9 million bpd of oil and NGLs “because the price of oil would probably be too low to warrant production.”
“There’s a balance between what we can absorb as a country and what we can produce,” Emerson said, noting the challenges posed by U.S. Gulf Coast refineries that are primarily being set up to process increasing volumes of heavy sour crudes from the Middle East, Africa and Canada, while liquid fuels demand could steadily decline as consumers shift to renewable fuels.
No demand from East Coast — yet
Pipeline and rail transporters at the Platts conference said that although there is the potential to deliver more crudes from the midcontinent to the U.S. East Coast, no projects are in the works and refiners are not yet clamoring for supplies.
Rail executives said crude deliveries to the East Coast might eventually have some potential, but demand has not been forthcoming, especially from East Coast refineries where 690,000 bpd of capacity has been shut down in the Philadelphia area alone.
Sam Calabro, an assistant vice president with Union Pacific Railroad, said his company has established an interchange track with eastern carriers and “could fold deliveries right into our network,” but demand has “not really hit our radar screen at this point.”
Darin Selby, assistant vice president of energy sales and marketing for Kansas City Southern Railway, said carrying either crude or products by rail would be feasible for his company if the need materialized.
However, Calabro said 30,000 tank cars (each one holding about 700-750 barrels) carried crude last year on Union Pacific and should increase “substantially” this year, while Kansas City Southern expects to rise from hundreds of tank cars in 2011 to more than a thousand this year.
Both railroads ship oil from the Bakken and Niobrara, with Union Pacific adding volumes from the Eagle Ford.
Selby quoted the North Dakota Pipeline Authority’s estimate that rail terminal capacity could double this year to 700,000 bpd, more than current Bakken output.
He said opportunities are also building for his railroad to transport frac sands, mainly from Wisconsin where EOG Resources owns a processing facility, and, unlike crude, there is no competition from pipelines.
Jennings: Crude prices will stay volatile
Mike Jennings, chief executive officer of midcontinent refiner Holly Frontier, told a first-quarter earnings call May 7 that new rail infrastructure has narrowed the price differential between Bakken crude and West Texas Intermediate, but cautioned that the premium to ship by rail along with increased production out of the play will keep crude prices volatile.
He said rail activity has gathered pace in a “big way” and the variable cost of rail shipments is probably $8-$10 per barrel.
Jennings said that “considerable” rail infrastructure has been built in the Bakken over recent months, but that has been offset by the rapid growth in output, estimating the annual ramp up is currently running at 150,000-200,000 bpd.
HollyFrontier said it runs 52,000 bpd of Bakken crude at its Cheyenne, Wyo., refinery and 135,000 bpd at its El Dorado, Kan., plant.
But a spokesman said there is not enough pipeline capacity to run enough of either Bakken crude or Canadian heavy crudes.
