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World Natural Gas Shock Model

World Natural Gas Shock Model thumbnail

The views expressed in the post are those of Dennis Coyne and do not necessarily reflect the views of Ron Patterson.

The post that follows relies heavily on the work of Paul Pukite (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 about 63% of the mean.  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<x, P decreases.

If P1 is producing reserves in year 1 and P2 is producing reserves in year 2, then
P2=P1+n2-x2, where n2= new producing reserves added in year 2 and x2 is natural gas produced in year 2.

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, n 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 the 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 to match 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:



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13 Comments on "World Natural Gas Shock Model"

  1. Nony on Tue, 28th Jul 2015 7:57 pm 

    I don’t really get the point of using some “shock” model to draw the exact shape of a curve for hugely different resource amounts.

    1. Surely it is more relevant to get into the resource amount discussions (what they posit in terms of geology, technical evolution, pricing, demand, etc.) than the shape of the logistic curve.

    2. Don’t see any reason for a “shock model” or some analogy to stat mech equations to be helpful in thinking about the evolution of production which is something dependant on demand and evolution of demand and supply and evolution of supply. Getting into the segments of supply and demand, understanding current indifference prices and how the could evolve would be much more insightful. Not just to getting the right answer but to understanding the segments for use elsewhere (other problems).

    3. Missing a discussion of price assumptions.

    4. Missing a discussion of the extension (or non extension) of US shale drilling to other countries.

  2. Plantagenet on Tue, 28th Jul 2015 8:32 pm 

    Hubert linearization models clearly don’t work for shale oil and NG deposits.

    Huberts own estimate that US oil production would peak in 1970 and the decline each year after has proven to be wildly inaccurate, as US oil production has gone UP 5 my bbls/day just since 2007.


  3. Jimmy on Tue, 28th Jul 2015 9:15 pm 

    Que Marm and Quintard to join the multi personality disorder circle jerk. Start your own blog if you’re so smart you fucking losers.

  4. Boat on Tue, 28th Jul 2015 9:26 pm 

    Relax there Jimmy, peak oil will happen, just more likely because of a war, asteroid, sun flares etc. For peak oil to happen because of supply problems it will have to outlive the era of fracking. Fracking will go global when the price returns.

  5. apneaman on Tue, 28th Jul 2015 9:34 pm 

    Markets Are About to Deal With Climate — Get Ready for Ugly

  6. Westexasfanclub on Wed, 29th Jul 2015 3:44 am 

    Boat, this was discussed here many times. The conditions for fracking are unique and extraordinary in the US, from a technological and geological point of view. Even from a legal one.

    There might be some areas though in Asia, Europe and Latin America where fracking could work. But development will take a lot of time and money. Even if favorable economical circumstances return, conventional oil will be on a steep downslope then and all what fracking could do would be to slow down the general decline slightly.

  7. rockman on Wed, 29th Jul 2015 6:52 am 

    “Hubbert’s own estimate that US oil production would peak in 1970 and the decline each year after has proven to be wildly inaccurate”. Actually his projections proved to be very accurate. But if one just reads the comments of folks who don’t know what the f*ck they’re talking about instead of understand the actual analysis they keep repeating the same bullsh*t. LOL.

    Hubbert projected the peak of just those mature US oil fields that made up his model. He specifically notes his projection didn’t include yet to be developed plays like Deep Water and the shales. If one gets off their ass and studies the history of the population he was projecting it has been very accurate.

    “Fracking will go global when the price returns”. Hmm…then someone needs to explain why it didn’t “go global” when oil was $100+/bbl and the entire world watched what was going on in the US. Of course Chevron and others did give it a go spending hundreds of $millions on overseas shales but almost universally failed even with higher oil prices. Heck, Shell spent over $2 BILLION in the well-known Eagle Ford Shale in S Texas and lost their ass. Sold it to Sanchez O’Brian for about $650 million. And now SO has lost its ass on the same acreage. But hey…nothing wrong with dreaming everything will be alright. LOL.

  8. zaphod42 on Wed, 29th Jul 2015 9:40 am 

    Boat, and all who labor under the impression that prices are not rising, consider that the “law” of supply and demand might be distorted by belief that what is being measured is commodities, when it is actually dollars that are being exchanged. Or yuan, yen, euros, etc.

    When a few ‘people’ (including artificial people) hoard money, and create a shortage by refusing to spend it (purchase things, or pay to their laborers, etc.), then prices have to come down because there is more labor, iron ore, or oil/gas stock than relative dollars. So, when dollars are in short supply, prices drop. If the Fed wants to have inflation, they will have to send the dollars they create to the people who will spend them. At this particular point in time, they are spinning their proverbial wheels, shoving cash into holes where it stays.

    Notwithstanding official statistics, most of us know that real wages are dropping, and relative inflation as well as nominal inflation are increasing.

    All of which does not change the status of fracking operations. They are capital intensive and depend on cheap money (debt) and high nominal prices. Absent either, they fail, as has already been shown [thank you, Rockman]. And when they have both, they scuttle the economy, as witness the events of 2007-2009.

    Enjoy the trip down the far side of Hubbert’s Peak.


  9. Nony on Wed, 29th Jul 2015 9:41 am 

    Actually he posited coverage of all the sedimentary basins, Rock. He kept oil sands and kerogen out of the equation. But not deep water and not shale. He also discussed Indiana as an interesting example of a repeak (from seismic) but then opined that it was unlikely to happen for the US overall because of new techniques. He was wrong.

    He really screwed the pooch hard on nat gas.

  10. Nony on Wed, 29th Jul 2015 10:41 am 

    Matt Simmons in 2002 at ASPO, speculating on an immediate peak in natural gas:

    “I fear that 5 to 10 years from now, historians might look back and discover that natural gas in 2002 finally experienced the same fate as U.S. oil did 32 years earlier. If King Hubbert was still alive, he might well be publishing a new study showing that his Hubbert Peak was now occurring in North American natural gas.”

    [Since then, U.S. natural gas has increased by a third.]

  11. apneaman on Wed, 29th Jul 2015 11:46 am 

    Matt Simmons is a genuine god damn peak oil hero.

  12. Davy on Wed, 29th Jul 2015 12:31 pm 

    Ditto Ape Man and screw the NOo.

  13. Nony on Thu, 30th Jul 2015 4:47 am 

    Can’t find a relevant thread for this, but found it interesting for the PO quants out there. Discusses why the weekly US production numbers are so different from the monthlies from EIA.

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