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.