ASPO-USA Co-founder Steve Andrews recently talked with Canadian geoscientist David Hughes on the outlook for shale oil. 

Q: Andrews–Production from shale oil plays has been impressive and has taken the national energy dialogue by storm.  When did you sense that the shale oil plays had the kind of muscle they are currently showing?

A: Hughes—The Bakken certainly came on the radar five years ago, not only in the US but also in Canada. So it certainly caught my attention, but it wasn’t until I started working on my Drill-Baby-Drill report in 2012 that I really got into the data enough to truly understand what was going on with the Bakken.  It certainly was phenomenal.  I looked at production through May of 2012 for that report, and at that point it was already over half-a-million barrels per day.  The Eagle Ford was not anywhere close to that, though the Eagle Ford has caught up and could even be ahead of the Bakken now.

So there is definitely muscle there.  The big question is, how sustainable is that in the long term?

Q:  You’re known for following the numbers closely.  Based on your analysis, how does your view of the next five years of shale oil production compare with that of a couple of the high-profile perspectives: the EIA’s and CitiGroup’s January 2012 forecast?

A:  It’s interesting that the EIA has changed their outlook.  For example, if you look at the April 2012 Annual Energy Outlook, they projected close to 12,000 locations available to drill in the Bakken and Three Forks formations.  In their April 2013 Outlook, they’ve projected 43,000 drilling locations, so they’ve almost quadrupled their estimate of the number.  And in the Eagle Ford they’ve doubled their estimate of drilling locations to 22,000.  As a result, they’ve doubled their estimate of recoverable oil.  However, if you look at the 2013 EIA forecast for tight oil, they’re actually pretty conservative compared to CitiGroup.  The 2013 EIA reference case forecast projects a second peak in US oil production in about 2019, reflecting a 2020 peak and decline of tight oil.

In last year’s Outlook, the EIA had an estimated EUR [Estimated Ultimate Recoverable] figure for the average Bakken oil well of 550,000 barrels of oil.  Since then they’ve actually lowered that quite a bit, to an average of 93,000, 211,000 and 372,000 barrels for Montana, non-core North Dakota and core North Dakota areas, respectively, while radically increasing their estimate of drillable locations.  So the EIA is a voice of conservatism compared to CitiGroup.  Ed Morse’s January 2012 CitiGroup report suggested that the Bakken and Eagle Ford would each rise to more than one million barrels per day and would plateau there until at least 2022 and presumably beyond that.

But when you look at any projections they critically depend on how many drillable locations you have.  I looked at EIA’s estimates for the Bakken and compared them to maps of well productivity and distribution (figures 1 and 2), and I would say they have over-estimated the number of remaining drillable locations by about 60%.  So if the EIA’s well density for the Bakken—two wells per section—is correct, there may be 26,000 locations total.  There have been about 6,000 wells drilled to date, so that leaves about 20,000 left to be drilled.