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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  10. Dennis: Neither purity product propane or any other plant NGLs are part of lease condensate.

    An oil or gas well has something called a 3 phase separator that operates at ambient temperature. It separates the fluids coming out of the well into two liquid streams and one gaseous one. The bottom liquid is water, the middle one is oil, and the highest one is rich gas.

    The middle stream may be called crude if it comes from a well that mostly makes oil. It may be called lease condensate if it comes from a well that makes mostly gas. (The state of Texas makes this differentiation and has exact numerical criteria for how to call a well a gas well or oil well. These are not physical criteria but just numeric, legal criteria.) MANY states have ZERO differentiation between lease condensate and crude. Anything that comes out of the middle stream is called oil and taxed as oil. Note also that all Federal laws treat lease condensate and crude identically. Really the difference is relatively arbitrary.

    Also, although lease condensate tends to be higher API gravity than crude, borderline wells in TX may actually have heavier condensate versus others with oil. It just comes down to the reservoir characteristics (oil is a natural product with variation) and how the wells meet the arbitrary definition of gas well versus oil well (which is mostly a Texas distinction).

    After the rich gas comes out of the well, it is sent to a processing plant. There refrigeration is used to extract and purify the different components of the rich gas. NOTE: this is different from the wellsite 3 phase separator, which is really a fancy knockout drum and does not have refrigeration. The NGLs are separated into dry gas (C1, methane), ethane (c2), propane (C3), isobutane and normal butane (C4 and i-C4), and "pentanes plus" (also called natural gasoline or PLANT condensate).

    Everything below pentane is a gas at room temperature. Yes, even though called natural gas liquids. None of this stuff is EVER a part of the crude and (lease) condensate numbers. You can see if you look at the EIA tables for total liquids (it is added on top of C&C to move towards total liquids).

    The plant condensate is a VERY high API liquid at room temperature. Mostly pentane but some c6, 7 or traces higher. It is usually 70 gravity or so. This is versus lease condensate that is typically 50+ or 45+ (depending on your source). Natural gasoline is NOT counted as part of "crude and lease condensate"--you can see if you look at EIA spreadsheets that differentiate all the total liquids. The reason why there is some liquid hydrocarbon in the rich gas is because there is some vapor pressure of these chemicals at room temp (or even higher for fluid as i exits the well). Think of water which boils at 212F but still has some vapor pressure at lower temps, thus is in the air.

  11. Note: There is some residual propane, and other "light ends" in the crude and condensate. There is even C1 still in there. But this is just because there is a solubility of these gases into organic fluids. (Similar but greater in extent to how oxygen has some solubility in water.) Nothing sneaky here: even very heavy crudes will have all the molecules from C1 to C100. During distillation these are separated. This is called refinery propane (most of the natgas and ethane is burned on site). It is not part of the NGLs and is not double counted. It's just a refinery product. A lot of the butane is actually converted into heavier molecules, although some refineries sell normal butane. Again, this is not an NGL but a refinery product like gasoline, jet, etc.

    In any case refinery propane is very small in quantity. No it is not classified with NGLs (is a downstream product of the C&C). If it makes you feel bad, realize we also don't count the plant condensate (a fluid hydrocarbon often mixed into gasoline) either. This is because they are both downstream of processing plants. The NGL plant or the refinery.

    P.s. It hurts me to see you not knowing this stuff after literally years of writing and commenting and reading about oil production. And making silly comments like 'maybe they are counting the propane in the condensate'. All it takes is a look at the EIA site (won't link because of spam control) to see how purity propane is NOT part of C&C, but is a part of plant NGLs and "total liquids".

  12. "The confusion is that there is some pentanes plus collected in the field “lease condensate” and there is an identical product extracted from natural gas in the Natural Gas Processing plant where NGL is stripped from the natural gas to produce “dry gas” shipped to natural gas consumers by pipeline. The NGL has several components, ethane, propane, butane, and pentanes plus (also called natural gasoline).

    The pentanes plus from the natural gas processing plant is part of NGPL (Natural Gas Plant Liquids) and is not considered part of C+C, even though it is essentially the same chemically as “lease condensate”."

    Typical API for plant condensate (pentanes plus, natural gasoline) is 80+ API. Lease condensate is usually 50-60 API. So they are not identical. Lease condensate is much closer to WTI than plant.

    Furthermore there is pentanes plus in the WTI, in the Maya, in the Kern River. All crudes have a range of hydrocarbons from C1 (yes, methane) to C100+. You have obviously never learned even the most basics of distilling crude oil.

    The reason the methane within the crude is not called gas production and why the plant condensate in the wet gas is not called oil production is because it would be double counting. Since you already accounted for oil and gas at the lease (3 phase seperator). Further separation in either a refinery (oil) or a gas processing plant (wet gas) is downstream processing.

  13. Your comments about dumbbell blend are too confident. Get a source and some numbers behind your comments.

    P.s. See this image: (You should be able to see that blending heavy with 55 condensate is actually pretty close to one of the intermediate grades. I suspect you hasve a very exaggerated mental image of how different 55 and 20 API hydrocarbons are to start with. Then you don't do the math, to look at how the fractions come out when blending.

  14. "Not sure if those EUR estimates are realistic, they are far higher than the industry average. According to shaleprofile EOG wells are about 24% more productive than the industry average in the Permian for 2017 and 2018 wells, that suggests an EUR of about 480 kb for the average EOG Permian basin well, while EOG claims about a 700 kb EUR for a typical Permian basin well or about 46% too high."

    1. Please give the slide number when making comments like this. Hard to tell what you are addressing.

    2. Need to adjust EOG BOE into BO (remove gas and NGLs) to do apples to apples comparison with Enno's site. (The info is there in the appendix to do this.) Unclear if you did this.

    3. Enno's site does not give an EUR. So important to say what you are doing to get an EUR from his site (E.g. straight line extrapolation of log rate v cum plot, to WHAT endpoint...or whatever you did.)


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