World Natural Gas Oil Shock Model

This post was originally published at Peak Oil Barrel in July 2015

The post that follows relies heavily on the work of PaulPukite (aka Webhubbletelescope), Jean Laherrere, and Steve Mohr.  Any mistakes are my responsibility.

For World Natural Gas URR Steve Mohr estimates 3 cases, with case 2 being his best estimate.

Case 1 URR= 14,000 TCF (trillion cubic feet)

Case 2 URR= 18,000 TCF

Case 3 URR= 27,000 TCF

Jean Laherrere’s most recent World natural gas URR estimate is close to Steve Mohr’s Case 1 at 13,000 TCF.

A Hubbert Linearization(HL) of World Conventional Natural Gas from 1999 to 2014 suggests a URR of 11,000 TCF, an HL from 1982-1998 points to a URR of 6000 TCF for conventional natural gas.

Note that “Conventional” natural gas subtracts US shale gas and US coal bed methane (CBM) from gross output minus reinjected gas for the World.

World Conventional Natural Gas HL (shale gas and CBM output from US deducted)

Currently World cumulative conventional natural gas output (using gross minus reinjected gas following Jean Laherrere’s example) is 4200 TCF, about 38% of the URR.

When shale gas and coalbed methane gas output in the US are added to World Natural Gas, the HL points to a URR of 20,000 TCF, this implies that shale gas, tight gas and CBM might have a combined URR of as much as 9000 TCF.  This matches well with the EIA’s 7000 TCF TRR estimate for shale gas and Steve Mohr’s 2500 TCF estimate for CBM. 

I suspect the combined shale gas and CBM numbers will be lower(4000 TCF), but that conventional gas will be more than 11,000 TCF (about 15,000 TCF) .

World Natural Gas HL below (includes all types of natural gas)

Note that the HL estimate is highly uncertain, the conventional estimate could be a little low (Jean Laherrere estimates 12,000 TCF) and combined shale gas, tight gas, and coal bed methane could vary from 2000 to 9000 TCF. 

For the World the USGS estimates about 16,000 TCF of conventional natural gas resources, the EIA estimates 7000 TCF of shale gas resources, and Steve Mohr estimates 2500 TCF of coalbed methane (CBM).  The total of these three is similar to Steve Mohr’s high case (case 3), I will use 26,000 TCF for my high case (case C).

The USGS estimates about 1000 TCF for US continuous gas (tight gas, shale gas, and CBM) and my low estimate is that the rest of the World will add another 1000 TCF from continuous natural gas resources.

The total when added to the HL estimate for conventional natural gas resources is about 13,000 TCF, which is my low case (case A).

I suggest 3 cases, with Case B (the average of case A and C) as my best guess.

Case A URR=13,000 TCF

Case B URR=19,000 TCF

Case C URR=26,000 TCF

Cumulative discovery data from 1900 to 2010 is used to estimate a discovery model for each of the three cases.  The equation is Q=U/(1+(c/t)^6), where t is years after 1871 (1872=1, 1873=2, etc.), Q is cumulative discoveries of natural gas in TCF, U=URR in TCF, and c is a constant found by a least squares fit to the data.

URR (TCF)            c

13000                    112

19000                    125

26000                    136

Chart with 3 discovery models and cumulative discovery data below.

The gap between the discovery model and the discovery data (for the 19000 and 26000 TCF cases) will be filled by backdated future reserve growth of both conventional and unconventional natural gas discoveries.

As a quick reminder the maximum entropy probability distribution is used to estimate the time from discovery to first production and has the form p=1/k*exp(-t/k) where p is the probability that resources discovered in year zero will become a producing reserve after t years(t=0.5, 1.5,…) and 1/k is the average number of years from discovery to first production.

Note that the median time from discovery to production is lower than the average by about 63%.  If 1/k=29 years, the median time from discovery to first production would be 18 years.

For the models presented, case A has 1/k=25, case B 1/k=29, and case C 1/k=32.

The three scenarios can be compared on the chart below.

Oil Shock Models with Different Ultimately Recoverable Resources of Crude plus Condensate (3100 Gb to 3700 Gb)

The post that follows relies heavily on the previous work of both Paul Pukite (aka Webhubbletelescope) and Jean Laherrere and I thank them both for sharing their knowledge, any mistakes are my responsibility.  

In a previous post I presented a simplified Oil Shock model that closely followed a 2013 estimate of World C+C Ultimately Recoverable Resources (URR) by Jean Laherrere of 2700 Gb, where 2200 Gb was from crude plus condensate less extra heavy oil (C+C-XH) and 500 Gb was from extra heavy (XH) oil resources in the Canadian and Venezuelan oil sands.

In the analysis here, I use the Hubbert Linearization (HL) method to estimate World C+C-XH URR to be about 2500 Gb.  The creaming curve method preferred by Jean Laherrere suggests the lower URR of 2200 Gb, if we assume only 200 Gb of future reserve growth and oil discovery.  

Previously, I have shown that US oil reserve growth (of proved plus probable reserves) was 63% from 1980 to 2005.  If we assume all of the 200 Gb of reserves added to the URR=2200 Gb model are from oil discoveries and that in a URR=2500 Gb, oil discoveries are also 200 Gb, then 300 Gb of reserve growth would be needed over all future years (we will use 90 years to 2100) or about 35% reserve growth on the 850 Gb of 2P (proved plus probable) reserves in 2010.  I conclude that a URR of 2500 Gb for C+C-XH is quite conservative.

A problem with the Hubbert Linearization method is that there is a tendency to underestimate URR.

Eagle Ford, Permian Basin, and Bakken and Eagle Ford Scenarios

Increased oil output in the US has kept World oil output from declining over the past few years and a major question is how long this can continue.  Poor estimates by both the US Energy Information Administration (EIA) and the Railroad Commission of Texas (RRC) for Texas state wide crude plus condensate (C+C) output make it difficult to predict when a sustained decline in US output will begin.

About 80 to 85% of Texas (TX) C+C output is from the Permian basin and the Eagle Ford play, so estimating output from these two formations is crucial.  I have used data from the production data query (PDQ) at the RRC to find the percentage of TX C+C output from the Permian (about 44% in Feb 2015) and Eagle Ford plays (40% in Feb 2015).  Dean’s estimates of Texas C+C output are excellent in my opinion and are close to EIA estimates through August 2014.  I used EIA data for TX C+C output through August 2014 and Dean’s best estimate from Sept 2014 to Feb 2015.  By multiplying the % of C+C output from the RRC data with the combined EIA and Dean estimate, I was able to estimate Eagle Ford and Permian output.  The chart below shows this output in kb/d.

 

 

Oil Shock Model for the World - 4100 Gb

I recently used the Oil Shock Model to create a future oil output scenario using Jean Laherrere’s estimate for World C+C URR of 2700 Gb.  About 500 Gb of extra heavy oil from Canadian Oil Sands and Orinoco Belt oil is included in the C+C URR estimate.

 The United States Geological Survey (USGS) estimates that the World C+C URR is 4100 Gb, including 1000 Gb of extra heavy oil.  The chart below is a new scenario created using Paul Pukite’s (Webhubbletelescope’s) Oil Shock Model with Dispersive Discovery.

 

I intended this to be an April Fool's joke.  I do not expect that extra heavy oil output will actually reach 28 Mb/d by 2100.  Note however that Jean Laherrere's 2013 estimate for extra heavy oil(XH) has a peak of about 16 Mb/d in 2070, with a URR of 500 Gb for XH oil. 

I believe that the USGS estimate is too optimistic and think 3100 Gb for C+C-XH and 700 Gb for XH oil for a total C+C URR of 3800 Gb is as high as C+C output will go (my optimistic scenario).

My pessimistic scenario is 2500 Gb of C+C-XH and 500 Gb of XH oil for a total C+C URR of 3000 Gb.  My best guess is 2800 Gb of C+C-XH and 600 Gb of XH oil for a total C+C URR of 3400 Gb.

The Oil Shock Model with Dispersive Discovery- Simplified

The Oil Shock Model was first developed by Webhubbletelescope and is explained in detail in The Oil Conundrum. (Note that this free book takes a while to download as it is over 700 pages long.) The Oil Shock Model with Dispersive Discovery is covered in the first half of the book.  I have made a few simplifications to the original model in an attempt to make it easier to understand.

Figure 1

In a previous post I explained convolution and its use in modelling oil output in the Bakken/Three Forks and Eagle Ford LTO (light tight oil) fields.  Briefly, an average hyperbolic well profile (monthly oil output) is combined with the number of new wells completed each month by means of convolution to find a model of LTO output. 

Oil Field Models, Decline Rates and Convolution

The eventual peak and decline of light tight oil (LTO) output in the Bakken/ Three Forks play of North Dakota and Montana and the Eagle Ford play of Texas are topics of much conversation at Peak Oil Barrel and elsewhere. 

 The decline rates of individual wells are very steep, especially early in the life of the well (as much as 75% in the first year for the average Eagle Ford well), though the decline rates become lower over time and eventually stabilize at around 6 to 7% per year in the Bakken. 

 What is not obvious is that for the entire field (or play), the decline rates are not as steep as the decline rate for individual wells. I will present a couple of simple model to illustrate this concept.

Much of the presentation is a review of ideas that I have learned from Rune Likvern and Paul Pukite (aka Webhubbletelescope), though any errors in the analysis are mine. 

 A key idea underlying the analysis is that of convolution. I will attempt an explanation of the concept which many people find difficult.

I think the best way to present convolution is with pictures. Chart A below shows a relationship between oil output (in barrels per month) and months from the first oil output for the average well in an unspecified LTO play. 

 This relationship is a simple hyperbola of the form q=a/(1+kt), where a and k are constants of 13,000 and 0.25 respectively, t is time in months, and q is oil output. Chart A is often referred to as a well profile. The values for the constants were chosen to make the well profile fairly similar to an Eagle Ford average well profile. EUR30 is the estimated ultimate recovery from this average well over a 30 year well life.

Eagle Ford Output and Texas Condensate and Natural Gas

Edit: May 14, 2014

Material was added on May 14 to update my Eagle Ford Model, see end of post.

This is a brief update on Eagle Ford Crude plus Condensate (C+C) output through February 2014.  February Eagle Ford C+C output was about 1200 kb/d by my estimate.

 

Figure 1- RRC Data provided by Kevin Carter 

I have used my usual method of estimation where I find the percentage of total Texas(TX) C+C output that is from the Eagle Ford(EF) play (%EF/TX is the label that I use) and multiply this by the EIA’s estimate of TX C+C output.  The chart shows the Railroad Commission of Texas (RRC) Eagle Ford estimate (EF RRC) in thousands of barrels per day (kb/d), the EF est (kb/d) as described above, the percentage of EF C+C that is condensate (EF %cond/C+C), and the %EF/TX also described above.

As before I would like to thank Kevin Carter who created a method to simplify gathering the Eagle Ford data.

Eagle Ford Update

Figure 1

It has been a while since I have updated my estimate of actual output from the Eagle Ford.

Kevin Carter (KC at Peak Oil Barrel) graciously offered help pulling together data for the 39 fields which make up the Eagle Ford play (see this page at the RRC of TX, spreadsheet download here .)
Kevin has strong programming skills in Visual Basic for Applications (VBA) and has made the job of gathering the Eagle Ford data considerably easier.  Thank you Kevin!

My previous estimates only included the Eagleville fields (Eagle Ford 1 and Eagle Ford 2 and the inactive Eagle Ford and Eagle Ford Sour fields), Briscoe Ranch, Sugarkane, Dewitt, Gates Ranch, Hawkville, and Eagle Ridge fields.  Together these 10 fields produce about 99% of Eagle Ford C+C output so these previous estimates are not bad, this new estimate includes all Eagle Ford output reported by the RRC from June 1993 to January 2014.

Note that from June 1993 to Dec 2006 C+C monthly output from the Eagle Ford play was 12 b/d or less, which is why the chart starts at Jan 2007.

An Excel spreadsheet with the data can be downloaded here .  More below the fold.

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.

Future Bakken Output and the Average Well Profile

In my June 14 post I discussed future decreases in average well productivity based on a single average well profile to create scenarios which would match the range of technically recoverable resources (TRR) in a recent USGS estimate for the Bakken/ Three Forks.

A recent discussion at the June 15, 2013 Drumbeat at the Oil Drum was very interesting with Rune Likvern providing  great insight (as usual) into recent data on Bakken output in North Dakota.

Mr Likvern believes that we may be seeing a decrease in average well productivity because a simulation with wells added at a rate of 125 well per month from Jan 2013 to April 2013 is showing greater output than recent data with 70 fewer wells added (500 for simulation vs 570 actual).  A decrease in average well productivity is one possible explanation.  An alternative possibility is that the average well profile may be different from the average well profile that Mr. Likvern has chosen.

I have created various well profiles in an attempt to match James Mason's work, Rune Likvern's work, the NDIC typical well, and the actual production data from the NDIC.  I have recently created some newer well profiles by using a minimization of the sum of the squared residuals between the model and data over the period from Jan 2010 to April 2013.  When no constraints are put on the minimization we get qi=11070, b=0.41, and d=0.078 (I call this model 7).

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.