Since 2005, the “total oil supply” for the United States as reported by the Energy Information Administration increased by 2.2 million barrels per day. Of this, 1.3 mb/d, or 60%, has come from natural gas liquids and biofuels, which really shouldn’t be added to conventional crude production for purposes of calculating the available supply. Of the 800,000 b/d increase in actual field production of crude oil, almost all of the gain has come from shale and other tight formations that horizontal fracturing methods have only recently opened up. Here I offer some thoughts on how these new production methods change the overall outlook for U.S. oil production.
Let me begin by clarifying that “shale oil” and “oil shale” refer to two completely different resources. “Oil shale” is in fact not shale and does not contain oil, but is instead a rock that at great monetary and environmental cost can yield organic compounds that could eventually be made into oil. Although some people have long been optimistic about the potential amount of energy available in U.S. oil-shale deposits, I personally am pessimistic that oil shale will ever be a significant energy source.
By contrast, the expression “shale oil”, or the more accurate term “tight oil”, is often used to refer to rock formations that do contain oil and that sometimes might actually be shale. The defining characteristic is that the rock is not sufficiently porose or permeable to allow oil to flow out if all you do is drill a hole into the formation. However, enterprising drillers have discovered that if you create fissures in the rock by injecting water (along with sand and some chemicals to facilitate the process) at high pressure along horizontal pipes through the formation, oil can seep back through the cracks and be extracted.
As seen in the figure above, these horizontal fracturing methods have been the main factor behind recent increases in U.S. field production. The key question is how much more growth we should expect. Leonardo Maugeri, senior manager for the Italian oil company Eni, and Senior Fellow at Harvard University, has a new paper in which he predicts that the U.S. could get an additional 4.17 million barrels per day from shale/tight oil plays by 2020, though he notes that any such predictions are problematic:
the huge differences in permeability, porosity, and thickness of a shale/tight oil formation require many more exploration wells be drilled in different areas of the field before making it possible to have an idea of the effective recoverability rate from the whole formation…. it is impossible to make any reasonable evaluation of the future production from a shale/tight oil formation based on the analysis of a few wells data and such limited activity.
To put the 4.17 mb/d number in perspective, total U.S. field production of crude oil in 2011 was 5.68 mb/d. If 4.17 mb/d could be added to that, it would almost put us back to where we were in 1970. Alternatively, 4.17 mb/d represents 22% of the 18.8 mb/d currently consumed by the U.S. and 4.7% of total world consumption.
Maugeri describes the assumptions under which he arrived at his estimate for the Bakken tight formation in North Dakota and Montana as follows:
- A price of oil (WTI) equal to or greater than $70 per barrel through 2020;
- A constant 200 drilling rigs per week;
- An estimated ultimate recovery rate of 10 percent per individual producing well (which in most cases has already been exceeded) and for the overall formation;
- [original oil in place comes to 300 billion barrels];
- A combined average depletion rate for each producing well of 15 percent over the first five years, followed by a 7 percent depletion rate;
- A level of porosity and permeability of the Bakken/Three Forks formation derived from those experienced so far by oil companies engaged in the area.
The above assumptions detail the total quantities that Maugeri estimates can eventually be extracted (a stock variable), but they clearly are not enough to calculate an annual production rate for the year 2020 (a flow variable) which is the key number Maugeri is reporting. His analysis also makes use of a proprietary database of results for existing wells. What he evidently did was to calculate average well completion rates and flow rates per well from that database and extrapolate those forward, though he does not tell the reader what were the actual summary averages that he used for this calculation nor indicate in what way the $70 assumed price enters the calculations. His paper really just seems to provide his own summary judgment as to what his private database implies rather than specifics that other analysts could use to evaluate or reproduce his claims.
I recently attended an excellent conference on oil market fundamentals, whose proceedings can be viewed online if your budget allows for a hefty registration fee. One of the presentations was by Morningstar analyst Jason Stevens, who estimated the 2015 potential U.S. tight crude oil production using two different approaches. The first approach, which Stevens called a “top-down” approach, was to “use best-in play curves and assume repeatability and similar results in emerging plays,” which sounds identical to Maugeri’s methodology, and indeed, Stevens’ calculations used the identical 200 rigs per week assumption for Bakken as did Maugeri. But whereas Maugeri predicted we’d see 1.5 mb/d additional Bakken production by 2020, Stevens calculated that the area might only add 150,000 b/d or so by 2015. On the other hand, Stevens’ calculations suggested about a 900,000 b/d gain for the Eagle Ford in Texas by 2015, compared with 1.47 mb/d anticipated by Maugeri for 2020.
Stevens also calculated a forecast using a second method that he described as “bottom up”, which used specific production forecasts for 16 of the individual firms involved in these plays, and assumed that the fraction of each area’s total production represented by these particular firms would stay constant. This bottom-up calculation leads to an expected additional flow by the particular firms studied of almost 1 mb/d by 2015, implying perhaps 3 mb/d combined production from all drillers in the plays. Thus Stevens’ bottom line was similar to that of Maugeri’s, although the specifics differ.
In addition to the uncertainties noted above about extrapolating historical production rates, the rate at which production declines from a given well over time is another big unknown. Another key point to recognize is the added cost of extracting oil from tight formations. West Texas Intermediate is currently around $85/barrel. With the huge discount for Canadian and north-central U.S. producers, that means that producers of North Dakota sweet are only offered $61 a barrel. Tight oil is not going to be the reason that we return to an era of cheap oil, for the simple reason that if oil again fell below $50/barrel, it wouldn’t be profitable to produce with these methods. Nor is tight oil likely to get the U.S. back to the levels of field production that we saw in 1970. But tight oil will likely provide a source of significant new production over the next decade as long as the price does not fall too much.
It is a separate critical question how much additional production may come worldwide from other sources, and how far this new production will go toward offsetting declining production from existing mature fields. Maugeri is also quite optimistic about these issues as well. I hope to take up a discussion of these separate questions in a subsequent post.