Future U.S. Light Tight Oil Update

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Includes: BNO, DBO, DNO, DTO, DWT, OIL, OILK, OILX, OLEM, OLO, SCO, SZO, UCO, USL, USO, UWT, WTID, WTIU
by: Ron Patterson

By Dennis Coyne

In a previous post on U.S. LTO future output, there were suggestions that a bottom-up approach might be better than the top-down approach, and I agree. I will attempt the bottom-up approach here. The chart below is a quick summary, based on three different oil price scenarios (high, medium, and low). The dashed line is just the average of the low and high oil price scenarios. Data is from Enno Peters' website shaleprofile.com and the EIA. (Click on "Tight Oil Production Estimates" for tight oil output data.)

Clearly, I do not know what future oil prices will be, but my expectation is that oil prices will be between the high and low price scenarios presented below.

Note that oil prices are assumed to remain at $80/b, $100/b, and $120/b (all in 2016$) from 2040 to 2050 in the low, medium, and high oil price scenarios respectively. For comparison, the oil price reference scenario (Brent crude spot price in 2016$) for the EIA's Annual Energy Outlook 2017 is also presented.

In the past, I have developed scenarios for the North Dakota (ND) Bakken/Three Forks (TF) and the Eagle Ford. That analysis has been combined with new analyses of the Permian Basin and "other LTO," where other means US LTO not produced in the ND Bakken/TF, Eagle Ford, or from Permian Basin horizontal wells. Also included in "other LTO" is roughly 7% of horizontal Texas Permian basin wells that could not be easily separated from vertical well output on the same lease as explained by Enno Peters.

The low, medium, and high oil price scenarios presented above are applied to all areas of US LTO output to develop three separate scenarios for each of the four areas (Bakken, Eagle Ford, Permian, and other LTO), and these are then combined to create the US LTO scenarios presented in the first chart.

The economically recoverable resources (ERR) for the three scenarios are 29 Gb, 38 Gb, and 43 Gb for the low, medium, and high oil price scenarios respectively. The high/low average (dashed line) has an ERR of 36 Gb. The Permian Basin scenarios are presented below.

ERR is 10 Gb, 17 Gb, and 20 Gb for the three oil price scenarios and 15 Gb for the high/low avg scenario (dashed line). The "other LTO" scenario is presented below.

The ERR of the three scenarios ranges from 6 Gb to 7 Gb. This analysis would be improved by separating out the Niobrara and doing that analysis separately; possibly this will be covered in a future post.

The ND Bakken/TF Scenario is presented below.

The Eagle Ford Scenarios

The economic assumptions used in the discounted cash flow analyses are shown below, it was assumed that in the long run, wells that are expected to be profitable will be completed.

chart/

Note that for other LTO $1 million would be too low a well cost for a horizontal multistage fracked well, but for a vertical well, this might be roughly correct. I don't have good information for areas besides the Bakken, Eagle Ford and Permian on costs, so this is a guess.

Average Well Profiles for late 2016 are shown in chart below, cumulative output in barrels on vertical axis and months from first output on horizontal axis.

The chart below shows the total number of US LTO wells completed for the medium oil price scenario on the right-hand axis. The maximum annual rate of US LTO completion in this scenario is 14,200 wells per year in 2021 (January to December), from January 2014 to December 2014 about 13,800 LTO wells were completed. This scenario has a rate of well completion only 2.9% higher than the previous maximum annual rate of well completion in 2014. The peak rate of output for the medium oil price scenario is 6495 kb/d in Oct. 2021, 1825 kb/d higher than the previous peak of 4670 kb/d in March 2015.

The high oil price scenario has a peak output of 6813 kb/d in Jan. 2022 (318 kb/d higher than the peak output of the medium oil price scenario), total wells completed of 233,500 by Sept. 2031 and a maximum annual rate of well completion of 15,400 wells per year in 2021 (11.6% higher than the previous peak annual rate of well completion in 2014).