Bakken and Eagle Ford Revised Scenarios

Edit: April 2, 2014  This post was a failed attempt at humor on April Fool's Day.  When a "joke" has to be explained, clearly it is not funny.  I apologize to those who took this seriously.

Essentially I was trying to see what it would take to arrive at the 24 billion barrels of Bakken oil that Harold Hamm often claims.  It takes 69,000 wells (at 2400 new wells per year) and no decrease in new well EUR (up to 2041) to accomplish this with a realistic well profile (similar to USGS estimates).  I really thought that people would realize (given the date), that this should not be taken seriously.

I was incorrect and again my apologies.

Dennis Coyne

Figure 1

There has been a lot of discussion about the United States as the new Saudi Arabia.  Output of crude plus condensate has been expanding rapidly in the light tight oil plays in North Dakota (Bakken) and Texas (Eagle Ford).  In the past I have been very skeptical of how long this rapid increase could continue.

The argument was basically that some areas are more productive than others and that these “sweet spots” would run out of room for new wells eventually and that well productivity would decrease.

I have revised my thinking based on the continually upbeat predictions by CEO’s of successful oil companies such as Harold Hamm of Continental Resources.  In addition, there have been several encouraging pilot projects suggesting that well spacing might be dramatically reduced.  This will allow many more wells to be drilled than the 40,000 wells that I have often used in previous scenarios.

North Dakota Bakken Scenarios

Fig 1 TRR 6 to 11.3 Gb

A recent post at Peak Oil Barrel by Jean Laherrere suggested an ultimate recoverable resource(URR) for the North Dakota Bakken/Three Forks of about 2.5 Gb based on Hubbert Linearization.  This conflicts with a recent (April 2013) USGS mean (F50) estimate of 8.4 Gb.  I decided to update my scenarios based on the range of USGS estimates from F95=6 Gb to F5=11.3 Gb for the North Dakota(ND) Bakken/ Three Forks.  Note that at year end 2011 there were 2.6 Gb of crude proven reserves in ND and at the end of 2007 about 0.5 Gb, I will assume all of this reserve increase came from the Bakken/ Three Forks, so 2.1 Gb of proven reserves added to 0.35 Gb of oil produced from the Bakken/ Three Forks gives us 2.45 Gb for a minimum URR.  The Hubbert Linearization points to about 0.05 Gb of undiscovered oil whereas the USGS suggests 3.5 to 8.9 Gb of undiscovered technically recoverable resource(TRR) in the North Dakota Bakken/Three Forks.

Note that Mr. Laherrere has forgotten more about geology than I know. He may have information that I don't have access to or has read the USGS April 2013 Bakken/Three Forks assessment and found that the report was not credible.  I have assumed in my analysis that the USGS analysis is correct, if it is not then my analysis will also be flawed.  I would love to hear from Mr. Laherrere about the specific problems he sees with the USGS analysis, I no doubt would learn much.

When will US LTO(light tight oil) Peak?

The rapid rise in oil output since 2008 has the mainstream media claiming that the US will soon be energy independent.  US Crude oil output has increased about 2.8 MMb/d (56%) since 2008 and about 2 MMb/d is from the shale plays in North Dakota ( Bakken/Three Forks) and Texas (Eagle Ford). My modeling suggests that a peak from these two plays may be reached by 2016, other shale plays (also known as light tight oil [LTO] plays) may be able to fill the gap left by declining Bakken and Eagle Ford output until 2020, beyond that point we will see a rapid decline.


US Light Tight Oil to 2040

There are two main views: 

1. There will be little crude plus condensate (C+C) output from any plays except the Bakken/Three Forks in North Dakota and Montana and the Eagle Ford of Texas.
2. The other LTO plays will come to the rescue when the Bakken and Eagle Ford reach their peak and keep LTO near these peak levels to about 2020 with a slow decline in output out to 2040.

Where are these “other LTO plays”?  There are a couple of these in Oklahoma and Texas (in the Permian basin, Granite Wash, Mississippian basin), the Appalachian, the Niobrara in Colorado, and others (see slide 17 of the USGS presentation link below).  Is it possible for these LTO plays to offset future declines in the Bakken and Eagle Ford?  I hope to answer that in this post.

Exploring Future Bakken Decrease in Estimated Ultimate Recovery (EUR)






Fig 1

In this post I will explore a number of different scenarios for future North Dakota Bakken crude oil production using an updated interactive spreadsheet which can be downloaded here.  More details can be found later in the post (scroll down to fig 12 and read the paragraph above that figure).  The new spreadsheet allows the user to change when the decrease in new well EUR begins and the length of time from the start of the decrease in EUR to the maximum monthly rate of decrease.  The earlier spreadsheet presented in my previous post had these two parameters fixed at 6 months after June 2013 for the start of the EUR decrease and 18 months for the length of time for the rate of EUR decrease to reach its maximum.

Cool Tools for considering Future Bakken Output

Webster Hubble Telescope (WHT) has a new blog called Context Earth with a cloud hosted server with some of his oil reserve models. See the Red Queen tight oil model 2.  This inspired me to create an interactive spreadsheet which does something similar. 

The spreadsheet is called bakken2.xlsx and can be found here on Google Drive.

One difference between WHT’s “red queen tight oil model 2” and my bakken2 model is that the EUR of new wells is about 280 kb in his model and 340 kb for my model at 30 years. 

A second difference is that my model allows the new well EUR to decrease at any annual rate from -0.1 to .99 (10 % increase to a 99 % decrease) starting in Jan 2014 and rising to the maximum monthly rate by June 2015.

Update to North Dakota Bakken / Three Forks Scenarios

http://www.rigzone.com/news/oil_gas/a/126179/USGS_Estimate_of_Bakken_Three_Forks_Double

The link above is to a Rigzone article discussing the April 2013 USGS Bakken/Three Forks estimate, which was referenced by Robert Rapier at

http://www.energytrendsinsider.com/2013/05/07/estimate-for-williston-basin-oil-resources-is-doubled/#more-13934

The USGS slide presentation can be found at

http://energy.usgs.gov/Miscellaneous/Articles/tabid/98/ID/247/USGS-Releases-Updated-Bakken-and-New-Three-Forks-Oil-and-Gas-Assessment.aspx

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:

Eagle Ford Shale may soon reach 1 million barrels per day(C+C)

I have made a number of comments about the Eagle Ford Shale (EFS) and possible underreporting by the Texas Railroad Commission (TRRC) of crude plus condensate (C+C) output. See my comments at peak oil.com (fourth comment by dcoyne78 on that page) and at peakoilbarrel.com  (see my response to Mike's comment in the comments section.)

The first point is that the TRRC data for Texas(TX) statewide C+C is quite different from the data reported by the US Energy Information Administration (EIA) for TX C+C.

Which data should we believe? 
Edit (Jan 16, 2014) see new chart at bottom of post.