Future Bakken Crude Oil Output, Oil Price, USGS Estimates, and Decreases in Well Productivity

Summary Chart ND Bakken/Three Forks Scenarios

There is quite a bit of optimism in the US about potential future crude oil output.  Due to the media reports that the US will become self sufficient in oil output, many Americans believe that oil prices are likely to decline in the future due to the abundance of oil resources.  This view may be too optimistic.

The enthusiasm is based on the success in the North Dakota portion of the Bakken/Three Forks play since 2008. The high oil prices over most of the period from 2008 to 2012 has made the high cost oil from North Dakota profitable. Bakken/Three Forks output in North Dakota has expanded from 43 kb/d in Mar 2008 to 719 kb/d in Mar 2013, a 16 fold increase over 5 years. The media believes these increases will continue, but the rate of increase is slowing considerably.

As a cautionary tale, consider Bakken/ Three Forks crude output in Montana (at link click on formation code in left most drop down box and type "bak" in search box, most output is from the Elm Coulee fields (all charts can be clicked to enlarge):

Real Oil Prices and the Effect on Future ND Bakken Output

I often read The Oil Drum blog and pointed readers of the Drum Beat to my most recent post here.  Rune Likvern asked a question about how future oil prices will effect my scenarios.  This is an excellent question because it is often claimed that the recent surge in US oil output may lead to lower oil prices.  I expect there is a little too much optimism about future output from the Bakken/Three Forks and Eagle Ford plays, but let's consider two scenarios proposed by Mr. Likvern.

Scenario 1 considers a slower rise in real oil prices than I proposed in my previous post, real oil prices rise to $120/barrel (Jan 2013$) by Jan 2018.



Figure 1

Figure 1 requires some explanation.  Break even oil prices rise to the real market oil price by Sept 2016 at $115 per barrel and the wells added ramp down to zero by Dec 2017.  It is assumed that real oil prices continue to rise at 3.29 % per year and that the decrease in well productivity slows to zero as no new wells are drilled.  Eventually the real oil price rises above the break even price and it is assumed that when the real oil price is 110 % or more of the break even oil price that new wells are added and well productivity then continues to decrease.  This cycle repeats 3 times between 2018 and 2037 and explains the bumps in output in 2021-2, 2027-8, and 2033-4.

Updated Well Profile for the North Dakota Bakken and the Effect on future scenarios

Note that all of the "Bakken" Scenarios I have presented, in this post and previous posts only cover the North Dakota portion of the Bakken/Three Forks play.

A recent post by Rune Likvern at the Oil Drum entitled, Is the Typical NDIC Bakken Tight Oil Well a Sales Pitch? has provided some new information which I will use to update my recent scenario for future Bakken output.

Another post by Mr. Likvern from which I gathered considerable knowledge is entitled Is Shale Oil Production from Bakken Headed for a Run with “The Red Queen”? . In addition a post by Heading Out at the Oil Drum had a number of helpful comments by both Mr Likvern and Webhubbletelescope, the entire thread has comments of interest. There are also a number of posts on the Bakken at The Oil conunDRUM  blog(written by Webhubbletelescope) from which I have learned much. I am indebted to both Webhubbletelescope and Mr Likvern for sharing their knowledge.

Bakken Model Suggests 7 Billion barrels total, enough for 1.3 years of US Crude inputs

 

Note that all images can be enlarged with a mouse click.

 

Above is one possible scenario for future output from the Bakken which suggests a total cumulative output of 7 billion barrels (Gb) from 1953 to 2073.  Current US crude oil inputs to refineries is about 15 million barrels per day  (52 week average above 14.9 MMb/d for past 6 months) which is 5.475 Gb per year, the total Bakken output of 7 Gb would supply current refinery inputs for 1.27 years.  When we account for the 0.57 Gb of Bakken which has been produced we are left with about 1.2 years of crude inputs at current levels.

 

The above estimate is based on  a presentation from the North Dakota Industrial Commission (NDIC) Oil and Gas Division (see slides 25 to 30).  This presentation suggests about 41,000 wells will be drilled in the Bakken at a rate of 1500-3000 wells per year, I chose 2460 wells per year and a total of 42,000 wells drilled by Sept 2028.

 

Quick update to tight oil models

I have extended both the Bakken and Eagle Ford Shale models out to 2040.  I have assumed no other significant tight oil plays are developed in the US besides these two, this is a somewhat pessimistic assumption, though most other assumptions are relatively optimistic.  These may balance out in the long run.

As the Bakken becomes fully drilled up at about 40,000 wells (around the end of 2024) it is assumed that drilling rigs are moved to Texas from North Dakota to work the Eagle Ford play and that there is a ramp up in the number of wells drilled there per month as a result.

In this current scenario, the tight oil output comes close to matching the EIA 2013 outlook (red diamonds in figure below) from 2018 to 2028, but the output is lower both before and after that period.

Bakken:

Eagle Ford:

 

US Tight Oil:

 

DC

DC





Update on Bakken Model using hyperbolic decline

The recent World Energy Outlook (WEO) published by the International Energy Agency (IEA) predicts that US unconventional output will rise to 5 million barrels per day (Mb/d) in 2020.  This increased crude plus condensate (C+C) output will primarily come from tight oil in the Bakken trend in North Dakota and the Eagle Ford trend in Texas.

I decided to update my model of the Bakken based on information learned while attempting to model the Eagle Ford trend in Texas.  One thing I discovered in my modelling of the Eagle Ford was that the hyperbolic decline model seems to give a better approximation of the Eagle Ford then the Dispersive Discovery Model that I used in my previous Bakken Model.  For this reason I used a hyperbolic decline model for my updated Bakken Model.

The early wells from 2004 to 2007 have a lower well profile with cumulative output about half that of wells starting production between 2008 and 2012.  My previous model had decreases in well productivity of 1 % each month from 2013 to 2019 with new wells starting production in Dec 2019 producing 45 % less cumulative oil than those beginning production in Dec 2012. 

I decided that this was too large a decrease in well productivity to be realistic.  For the updated model, wells starting production in Feb 2013 produce a cumulative output about 0.5 % less than those which started producing the previous month.  Each year the well productivity profile decreases by about 6 % compared to new wells from 1 year earlier.  By Dec 2019 new well productivity has decreased by 66 % compared to new wells from Jan 2013.  The chart above only shows 3 cumulative output curves with one curve (Jun-16) between the Jan 2008 to Dec 2012 cumulative and the
Dec-2019 cumulative curves.  In fact there are 94 curves between the Jan-13 cumulative curve and the Dec-19 cumulative curve one for each month.

The data for C+C output in barrels per day and number of producing wells can be found here. 

In order to forecast future output we assume the average well profile remains unchanged for new wells from Jan 2008 until Jan 2013 and then declines for each month from Feb 2013 to Dec 2019 by 0.5 % as discussed above. 

To estimate the number of producing wells in Oct 2012 we use the average of the change in the number of producing wells (delta # of wells) for the previous 7 months which is 162.  This number is added to the 4629 wells producing in Sept 2012, thereafter the delta # of wells producing is assumed to increase by 3 each month up to Dec 2013 (162, 165, .... , 201, 204) to a total of 7374 producing wells. Note that between Jan 2010 and Sept 2012 the trend in the increase in delta # of wells was 4 per month. So the increase in the delta # of wells producing of 3 represents a decrease from the previous trend. 

This rate of increase of delta # of wells is decreased further to 2 each month from Jan 2014 to Dec 2015 to reach a total # of producing wells of 12870.  The rate of increase of the delta # of wells producing decreases again to 1 per month from Jan 2016 to Dec 2017 and producing wells increase to 19218.  From Jan 2018 to Dec 2019 the delta # of wells producing stays steady at 276 with the total number of wells reaching 25842.  

The model by James Mason suggests 40000 wells would be the saturation point for the Bakken with little room for any further increase in producing wells.  In the chart below notice the rapid dropoff in output after Dec 2019 when new wells are no longer added.  If wells continue to be added at 276 new wells per month then 40000 wells are reached in April 2024, at that point (if Mason's model and my model are both correct) we would see a rapid drop in oil production.

Output peaks at 1.35 Mb/d in early 2019 and then remains on plateau until Dec 2019, this is an example of Rune Likvern's "Red Queen" effect.

I hope to publish a post on the Eagle Ford soon.  For some flavor of this, consider this chart:

The Texas RRC database was used to develop the average well profile.  Note that data is estimated from a combination of Texas RRC data and EIA data.  The Texas data was used to estimate the  percentage of all Texas oil coming from the Eagle Ford trend, then this percentage was multiplied by EIA Texas output to estimate Eagle Ford oil output.

Based on these models I think the upper limit to tight oil output from the Bakken and Eagle Ford in 2020 is about 2.7 Mb/d rather than the 5 Mb/d predicted by the IEA.  Note that these estimates are quite optimistic and should be thought of as an upper bound to what may be attainable. This is an increase of about 1.6 Mb/d over current US tight oil output of about 1.14 Mb/d.  A more realistic scenario might be a doubling of output to 2.3 Mb/d in 2020.

DC

Using a Dispersive Diffusion Model for Bakken Oil Scenarios

There is a great deal of excitement about the increased oil output from the Bakken Oil field in North Dakota.  A recent post by Rune Likvern at the Oil Drum sparked my interest in this topic.  The EIA estimates that under an optimistic high technically recoverable resource (TRR) case that the Bakken might produce as much as 1 Mb/d by 2021 and then remain at that level until 2035.  A paper by James Mason presents a scenario where Bakken output rises to 1.5 Mb/d by 2020 and remains at this level out to 2045.

At the Oil Conundrum, Webhubbletelescope (WHT) presents a dispersive diffusion model to model Bakken output, based on the data presented in Mason's paper.  He tells us that P-naught(P0) is 2.6 million barrels, but he leaves it to the reader to determine D-naught(D0).

P(t)= P0/(1+1/(sqrt(D0*t))

is the equation describing the model and its derivation is presented at the Oil ConunDRUM (link is above).

By trial and error we find D0=0.0023, for month 1 we get a different value from the 580 b/d in the chart above (it should be 1166 b/d), other than that the model agrees.

The North Dakota Department of Mineral Resources estimates the Bakken original oil in place (ooip)at 167 Gb,  Mason suggests total development will lead to 40,000 wells producing which suggests 4.175 Mb of ooip per well.  I chose P0=4.175 Mb and D0=0.00045 (high model) in order to model the Bakken oil data from the North Dakota government.  A low model was also created with P0=4.175 Mb and D0=0.0001.

The models (high, low, and 2.6) are below(2.6 is WHT's original model):

In order to create this model I made a number of simplifying assumptions.  We have the number of wells producing oil for every month from Dec 1953 to July 2012 and the number of barrels produced each of those months.  We are particularly interested in the recent increase in output which began in January 2005.

Using the Bakken Production Model developed by WHT and assuming that the average well follows this model we can create our model in a spreadsheet.  We first find the change in the number of producing wells each month and then assume any increase in the number of producing wells is due to new wells being brought online. We also assume all wells are average wells and we know what the output for every future month will be from those new wells (because we assume they behave as the model predicts.)  Keep in mind that the only input to the model is the change in the number of wells producing each month and two parameters P0=4,175,000 barrels and D0=0.00045, in the equation derived by WHT (see above.)

The first cut is below:

 

The model matches the data quite well from Jan 2010 to July 2012.  The early part of the data from Jan 2005 to Dec 2007 may not be modelled properly by the "high" model.  The differences are more apparent in the following semi-log plot.  (The plot beyond July 2012 is a future scenario discussed below.)

In order to improve the early (before 2010) part of the model I created a "low" model where output per well is about half the level of the "high" model.  This low model was used for wells which started production between Dec 2004 and Dec 2007.

The fit is improved for 2007, 2008, and 2009.  From Jan 2007 to July 2012 the number of producing wells increased at about 4.1 % each month.  To create a future scenario I assumed the "high" model would continue to describe the average well.  This assumption may be problematic as sweet spots become saturated with wells, in the future the low model or some "medium" model may be more appropriate.  The rate of increase of new wells was assumed to decrease by 2.3% each month( so we multiply last month's rate of increase by 0.977 for every future month).  We assume August 2012 will be a 4 % increase in # of wells, Sept 2012 would be 4 times 0.977=3.908%.  We continue in this manner from Aug 2012 to Dec 2017.  The following x-y plot is easier for reading the data:

 

 

Under these assumptions we see that future output from the Bakken would roughly double by Dec 2017 to 1.3 Mb/d.  This scenario is about midway between the EIA's optimistic scenario of 1 Mb/d by 2021 and Mason's middle scenario of 1.5 Mb/d by 2020, though it reaches the plateau 3 to 4 years earlier than those other scenarios.

The following chart shows contributions to output from various years:

Further modelling could guess at future production models which would likely fall between the high and low models presented here.

Edit 10-4-2012

In response to a question at the Oil Drum, I have decided to do a crude approximation of falling well productivity in future years.  I did this by assuming the "high" well profile remains valid until Dec 2014.  Abruptly in Jan 2015 all new wells follow the "low"  well profile as presented above.  The rate that new wells are added also increases to compensate for the fall in well productivity.  Clearly in the real world these changes would happen gradually, but this is a rough approximation of reality.

I also have added two more years to Dec 2019 to this model and I show how output would decline if new wells are no longer added.  If this model approximates reality (a rather large if), the plateau could be maintained until April 2023.  At that point we reach 40000 wells and if Mason's analysis is correct,  no more wells would be added in the North Dakota Bakken and decline would begin.  The decline would be a little flatter than shown above due to the extra 9500 wells.

Another update:

In response to further comments at the Oil Drum, I have attempted to make the model more realistic by creating several average well profiles that decrease by 10 % each year from 2013 to 2019, I also interpolated between the yearly profiles on a monthly basis to make the transition to lower output somewhat smoother.  The rate of increase in wells falls from 4 % to 1 % from Aug 2012 to Dec 2019.

DC