Monday, February 22, 2016

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.


Details for the three cases are in the following three charts, with extraction rates (from producing reserves) and annual decline rates on the right axis.  The gas output is gross gas minus reinjected gas, dry gas will be about 91% of the gross minus reinjected gas (1980-2011 average).

Case A below.


Case B:


Case C:

Below I present a few more charts with the focus on case B, note that the eventual URR is highly uncertain but is likely to be between Case A and C in my view, case B is just the average of the case A and case C URR.

My guess is that the World URR for natural gas will be between 17,000 and 21,000 TCF or +/- 10% of case B, future extraction rates and thus the shape of the output curve after 2014 are unknown.

Producing reserves for case B (also called proved developed producing (PDP) reserves):


Case B discoveries, new producing reserves(n) added to producing reserves (P) each year, and natural gas extracted from P each year (x), aka production.

The extraction rate is e and x=e*P. 

Every year n reserves are added to P and x reserves are extracted, if n>x. then P increases and if n
If P1 is producing reserves in year 1 and P2 is producing reserves in year 2, then

Often when the decline rate of the model is lower than expected it is because we are forgetting about the new reserves that are continually being developed.  It is unlikely that new reserves will stop being developed in the near term, so n is not zero, it will gradually decrease unless disrupted by political or economic crises.



Natural Gas is at an earlier stage of development than crude oil and there is greater uncertainty about eventual ultimately recoverable resources (URR).  Estimates range from 13,000 TCF (Jean Laherrere) to 28,000 TCF (combined EIA and USGS estimates for conventional, shale, and tight gas plus Steve Mohr’s case 3 estimate for coal bed methane.) 

I decided on matching Laherrere’s estimate (13,000 TCF) for my low case based on Hubbert Linearization for conventional natural gas and conservative estimates of World shale gas, tight gas, and coal bed methane URR (2000 TCF total).  For the high case I decided to use Mohr’s case 2 estimate for coal bed methane along with USGS and EIA estimates for other natural gas rescources, URR =26,000 TCF.  My best guess is just the average of the low and high case, the scenarios presented peak in 2018, 2039, and 2049.

Supplemental charts for Case A and C below:

Case A

Producing reserves


Discoveries, new producing reserves, and production


Case C charts:




  1. Natural Gas projections are likely the hardest to get right, but are in need of the oil shock model because NG is so sensitive to demand fluctuations. Hubbert Linearization would never work here and that's why all the past HL models of NG production failed so badly.

    1. Thanks WHUT,

      A lot will depend on demand. If coal use falls demand might be relatively high unless wind and solar ramp quickly. Though technically possible, the price differentials will be important. It is a bit of a catch 22 if renewables cause demand for fossil fuels to fall, then the price of fossil fuel falls which reduces the incentive to switch to alternatives. I am working on a bare bones demand model, but it is basic, it might give the general outlines.

  2. "Ghawar has long been into decline. I am shocked that you are ignorant of that fact.

    I have no idea what Ghawar’s current production numbers are because it is a Saudi state secret."


  3. Dennis, suggestion on the petroleum/non-petroleum thread combos. Put the non-petroleum thread as the first thread to read on the page. The issue of the non-petroleum stuff contaminating petroleum threads is much more the issue than the opposite. If you have the top thread be non-petroleum, than that is easier for the electric car, climate change, politics, evolution, capitalism, macroecon, etc. comments to head for.

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