EOR In The Bakken -- June 8, 2016

Active rigs:

	6/8/2016	06/08/2015	06/08/2014	06/08/2013	06/08/2012
Active Rigs	26	82	194	189	214

RBN Energy: the potential for enhanced oil recovery in shale plays.

While EOR on conventional, vertical wells continues—even with the low-price challenges that all producers face—shale producers may finally be getting a handle on how to cost-effectively employ EOR in horizontal wells that were hydraulically “fracked” a few years back and have since experienced typical (steep) shale production declines.   

EOG Resources, a leading innovator in shale production, in May (2016) confirmed what it said was four successful pilot tests of an internally developed EOR process on a total of 15 producing horizontal wells in the Eagle Ford shale play (one well in the first pilot, then four wells, then four again, then six).  

A fifth—and much larger--“field-scale” pilot involving 32 producing wells is planned for  2016, with the expectation that from 2017 on EOR will be a regular part of EOG’s Eagle Ford development.  EOG’s EOR process, developed over the past three years, is proprietary, but what we can glean from what’s been said is this:

• The process involves the injection of natural gas produced by EOG in the same Eagle Ford fields in which the pilots have been place—in other words, the gas was readily available at low cost, unlike CO2, which Oxy needs to pipe in from afar to its Permian EOR operation at considerable cost. (EOG’s EOR is still economically viable at $5/MMBtu gas.)
• The EOR technique is not all that capital intensive, averaging only about $1 million/well. Operating costs are low too, and the “finding cost” of adding to EOG’s potential reserves is $6/bbl or less.
• EOG’s Eagle Ford shale acreage positions (including 529,000 acres in the play’s “oil window”) feature unique geologic properties—including “strong geologic containment” (that is, virtually impermeable layers above and below the seam where the horizontal drilling was done)—that provides vertical containment for initial, high-density completions and then, during the EOR process, keeps the gas injection in contact with the targeted reservoir.  (In other words, if the production layer isn’t well-sealed top and bottom, the injected gas can’t do its job, which is to become “miscible”—or mixed in with—the oil remaining in the seam and drive incremental oil recovery.)
• The incremental production response occurs quickly, typically within the first two to three months of gas injection, and holds steady for longer than initial production (IP) from the primary well completion.
• The combination of lower operating costs and steady production delivers a return profile that complements EOG’s primary horizontal drilling and fracking program.  That is, primary drilling focused on areas with high IP rates deliver high returns and short paybacks, while the EOR pilots have a very different profile: more modest upfront capital investment followed by a more sustained period of incremental oil production and cash flow.
• The rate of return is reported to be on par with EOG’s primary drilling; at $40/bbl oil, the after tax rate of return (ATROR) for EOG’s EOR is greater than 30% (at $50/bbl the ATROR tops 50%), and the present value index (PVI)—the net present value (NPV) divided by the capital investment (an efficiency measure for investment decisions)--is greater than 2.