The link above is to a Rigzone article discussing the April 2013 USGS Bakken/Three Forks estimate, which was referenced by Robert Rapier at
The USGS slide presentation can be found at
and click on the slide presentation pdf link near the bottom of that page.
Near the end of that slide presentation it breaks out the 7.4 BBO for all of the US Bakken/Three Forks into Montana and North Dakota sections of the play. North Dakota has a mean estimate of 5.8 BBO of undiscovered technologically recoverable resources (TRR) in the Bakken/ Three Forks.
I had been ignoring the "undiscovered" and was incorrectly interpreting the estimate as the full TRR, until I read the following in the Rigzone article:
"While the estimates for Bakken oil resources would appear to be the same for 2008 and 2013, the size of the Bakken estimate increased as well, a USGS spokesperson told Rigzone in an email statement."
"It's deceptive, because although our current estimate of 3.65 billion barrels of oil for the Bakken is numerically the same as the 2008 assessment for the Bakken, you have to remember that oil companies have been producing millions of barrels of oil since the 2008 assessment, gradually transforming the undiscovered resources to the proven reserves then production barrels," the spokesperson commented. "Because our assessments do not include proven reserves or produced barrels of oil, the 3.65 billion does represent an increase."
About 2.2 BBO of proven reserves have been added in North Dakota since 2005 (from 0.4 BBO in Dec 2005 to 2.6 BBO in Dec 2011 according to the EIA). If it is assumed that all of these reserves were due to the Bakken/ Three Forks play, then a mean estimate for the total TRR for North Dakota might be as large as 8 BBO and the F5 estimate (or 3P estimate) for total TRR might be as large as 11 BBO. The F95 (or 1P) estimate of total TRR for the Bakken/Three Forks is about 6 BBO.
Based on this, many of my recent Bakken scenarios might underestimate future Bakken output so I have revised them accordingly.
The range of the TRR from the low to high scenario is quite close to the USGS F95 and F5 estimates of 6 to 11 BBO. These scenarios all increase the new wells added to an annual rate of 2200 wells per year by mid 2016 (185 wells/month starting in June 2016). Previous scenarios added wells at a rate of 1800 wells per year until Dec 2014 and then increased the wells added to a maximum of 2000 wells per year in mid 2016. Note that the NDIC (North Dakota Industrial Commission) expects the future wells added per year to be between 1800 and 3000 wells/year. I have also presented scenarios at peakoil.com (Shale Oil Boom thread) and peakoilbarrel.com where the wells added per year remain at the present level of 1800 new wells per year.
I decided to use three different well profiles to give my low, medium, and high scenarios, note that these well profiles are different from my previous post.
Med TRR- qi=10570, b=0.81, di=0.0883, EUR(10)=259 kb, EUR(20)=311 kb, EUR(30)=339 kb
High TRR- qi=11750, b=1.26, di=0.145, EUR(10)=283 kb, EUR(20)=371 kb, EUR(30)=430 kb
Low TRR- qi=10500, b=0.45, di=0.069, EUR(10)=235 kb, EUR(20)=256 kb, EUR(30)=264 kb
These well profiles are Arps hyperbolics with equations of the form (in Excel notation):
Monthly output=qi/(POWER((1+b*di*t),(1/b))), and t is months from first output and output is in barrels per month. I use t at mid month so t=0.5, 1.5,….., 359.5.
Well productivity (EUR) for all three TRR scenarios is given in figure 3 above.
When we consider economically recoverable reserves (ERR) we need to make assumptions about real oil prices, average well cost, transport costs, royalty and tax payments, operating expenses (OPEX), and other costs. We also need to assume an annual discount rate used to calculate the net present value (NPV) of future income streams from sales of output from a given well.
I assume transport costs of $9/ barrel, OPEX of $4/barrel, royalty and taxes of 20 % of well head revenue (refinery gate revenue-transport costs), other costs of $3/barrel, and an annual discount rate of 12.5 %. Real Oil prices follow the EIA’s AEO 2013 reference case adjusted to May 2013 $, and well costs are assumed to fall from $9 million per well in Jan 2013 to $7 million in Feb 2016 (about 8% per year) and then remain at that level.
As profits fall below $1 million per well in 2019, it is assumed that fewer new wells are added per day and this reduces the rate of decrease in well EUR. The following chart shows the progression of new well EUR over time when economics are introduced as well as the changes in the annual rate of decrease of new well EUR and how this corresponds to the number of new wells added per day.
Note that the Maximum rate that wells are added over the mid 2016 to mid 2018 period is 2200 new wells per year (about 6 new wells per day), by 2025 the rate that new wells are added has fallen by a factor of 6. After 2040 prices are assumed to remain flat and it is no longer profitable to add new wells, total producing wells reach a maximum of about 26000 wells in late 2040.
Below is a chart of the ERR for all three scenarios with the same underlying economic assumptions used for the Low TRR and high TRR cases.
Clearly there are many assumptions which have been made to create these scenarios. All may be proven wrong by future events. Well costs may not decrease as fast as I have assumed (or they may decrease faster), well productivity decrease is assumed to begin in Jan 2014 and gradually increase to an annual rate of decrease of 16 % ( my guess is that the range is likely to be between 12 % and 24 %), this guess could also be either low or high. Real oil prices could follow the EIA's AEO 2013 low or high price case rather than the reference case assumed here. In the future I may explore a few of these possibilities, clearly high prices are more likely under the low scenario and low prices are more likely in the case of the high scenario.
A final note on the decrease in EUR of the average new well. The 16 % annual rate was not chosen randomly, the recent USGS mean estimate for the North Dakota portion of the Bakken/Three Forks was chosen as the target for my medium TRR scenario. It was assumed that this decrease in EUR would gradually accelerate beginning in Jan 2014 and the shape of the % EUR curve in figure 3 above was thought to be reasonable and results in a TRR very close to my target.