jean laherrere 19 march 2018 · 6 mason inman data aeo 2013 to 2018 and ut 2017 aeo2014 was...

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Jean Laherrere 19 March 2018 This paper was written in association with Charlie Hall in view of a presentation in New Orleans on 21 March at ACS conference “M. King Hubbert: Is He Relevant?” Forecasts for US oil and gas production My assumptions for forecasting US oil and natural gas production are several: 1-Reserves estimates of LTO and shale gas, like conventional ones, are based on multiplying estimates of the volume in place (or the volume generated by the source rock) and a recovery factor. Such assessments are completely unreliable because the volume of the accumulation is fuzzy (no water plane) and the recovery factor unknown by lack of historical checks with LTO or shale gas fields produced until abandoned 2-Future production estimated by many (in particular EIA) by assuming a large number (tens of thousands) of future wells multiplied by the optimistic estimated EUR of past wells (in sweet spots) without bothering to check if there is enough room for drilling economical wells is for me very unreliable. EIA does not bother reporting the cumulative future production of their forecasts up to 2050 EIA publishes the LTO reserves at end 2016 ranked by proved reserves: Bakken is number one but in their AEO forecasts up to 2050 Permian basin is number one This EIA approach relying on number of wells and well ultimate reminds of the USGS estimate in 1962 of 590 Gb for the US oil ultimate by V.McKelvey (based on Zapp’s work https://pubs.usgs.gov/bul/1142h/report.pdf) by multiplying a large number of feet drilled (5 10E9 foot) by the recovery per foot op to 1961 (118 b/ft = 130 Gb discovered for 1.1 Gft drilled = G.Bowden 1982): Hubbert was strongly against such approach, saying that the oil recovery per foot was showing a roughly exponential decline (D.Strahan 2007) and would be lower in the future. Present estimate of the US ultimate is far below Zapp’s estimate (590 Gb), but higher than Hubbert’s estimate (150-200 Gb for conventional USL48). It is the same with LTO. The present ultimate recovery per well (EUR) will be lower in the future and the location of future wells will be limited, in particular with lateral length increase. 3-I believe it is better to estimate the ultimate production of LTO and shale gas with HL (Hubbert linearization) of past production. But many plots display several declines and the last data with rise Hubbert Linearization is the plot of the ratio of annual production to cumulative production in percentage (Y axis) versus the cumulative production (Hubbert 1980). Empirically once the field is moderately well developed, this gives one or several relatively straight lines and the last one can be extrapolated to the Y axis, giving the EUR when production will fall to zero (assumed to be the end of the production) 4-Past oil and gas data for the USLower48 displays cycles and most of the cycles display approximately symmetrical rises and declines, so the future cycle is assumed to be also symmetrical. This symmetry is explained by the fact that, in the USL48, there are thousands of producers acting in random (law of large numbers). Random behavior is described as “Brownian motion”, displaying Gaussian symmetrical curve.

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The past crude oil production 1859-2017 of the USL48, Texas, California and Gulf of Mexico displays several cycles and each decline has the same slope as the last increase.

Our main forecasts are based on EIA monthly production data (unfortunately there are several different reports as weekly, monthly).

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USL48

Jean Laherrere Feb 2018

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http://www.data.boem.gov/homepg/pubinfo/repcat/product/Region.asp

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North Dakota: Bakken oil monthly production per well

Jean Laherrere March 2018

Antelope field

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The following plots show for different plays: -left: annual & cumulative production as forecast for ultimate from HL -right: HL (Hubbert linearization) of past production extrapolated to ultimate (U) CP = cumulative production, RR = remaining reserves, CP+RR = initial reserves (discoveries) -Natural gas production -Shale gas: Bakken

Mason Inman requested the EIA to get more details on the AEO and received the forecasts for each shale play for AEO 2013 to 2018

AEO annual production forecasts are chaotic with time! -Shale gas: Barnett

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Bakken dry shale gas monthly production from EIA (FQ)

Bakken FAQ

U = 6 Tcf

U = 6 Tcf

CP FQ


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cumulative production Tcf

Bakken HL of dry shale gas production from EIA (FQ)

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Bakken shale gas production from AEO & U = 6 Tcf

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013U=6 TcfEIA FAQ


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Bakken cumulative shale gas production from AEO & U=6 Tcf

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013U=6 Tcfhist FAQ


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From TxRRC annual data

Mason Inman data AEO 2013 to 2018 and also from University of Texas UT

AEO2013 was much higher than AEO2018, missing the decline after the peak of 2012, , UT 2017 (University of Texas) is close to our forecast -Shale gas: Eagle Ford

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Barnett dry shale gas monthly production from EIA

Barnett Gcf/m

U = 25 Tcf

CP+RR

CP Tcf

U = 25 Tcf


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Barnett HL of dry shale gas production from EIA

aP/CP%

jan2010-dec2017


CP+RR2016 = 33.8 Tcf2015 = 32.8 Tcf2014 = 38.8 Tcf

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Barnett gas & liquids production from RRC

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gas Gcf/d RRC


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Barnett HL gas production RRC 1993-2017

gas aP/CP %

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2010-2017 RRC


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Barnett gas decline 2000-2017 from RRC

gas Gcf/d RRC

2014-2017


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Barnett shale gas production

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UT 2014, AEO2014 $

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hist (EIA)

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Barnett cumulative gas production from AEO & U= 25 Tcf

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013TxRRCU=25 Tcfhist AEO


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From TxRRC annual data

Mason Inman data AEO 2013 to 2018

-Shale gas: Fayetteville

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Eagle Ford dry shale gas monthly production from EIA

Eagle Ford Gcf/m

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CP+RR

CP Tcf

U = 15 Tcf


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Eagle Ford HL of dry shale gas production from EIA

aP/CP%dec2013-feb2017mar2017-dec2017


CP+RR2016 = 30.1 Tcf2015 = 25.4 TCF2014 = 27.8 Tcf

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Eagle Ford NG production & forecast for U = 15 Tcf

gas TcfU = 15 Tcf

Jean Laherrere Feb 2018 http://www.rrc.state.tx.us/eagleford/index.php

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Eagle Ford HL natural gas production from RRC

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2013-2017


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Eagle Ford shale gas annual production from AEO & U=15 Tcf

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013histU = 15 Tcf

Jean Laherrere March 2018 source: Mason Inman EIA

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Eagle Ford shale gas cumulative production from AEO & U=15 Tcf

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013histU = 15 Tcf


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Mason Inman data AEO 2013 to 2018 and UT 2017

AEO2014 was completely unconnected with reality, when University of Texas UT2017 cumulative production up to 2050 is 18 Tcf against 42 Tcf for AEO2018 or 10 Tcf for my forecast: UT is closer to my estimate than to AEO2018! -Shale gas: Haynesville

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Fayetteville

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Fayetteville HL of dry shale gas production from EIA

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feb2013-dec2017


CP+RR EIAend 2016 = 13.5 Tcfend 2015 = 13.6 Tcfend 2014 = 17.3 Tcf

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Fayetteville shale gas cumulative production from AEO & U = 10 Tcf

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013UT 2017 $3/McfU = 10 Tcfhist (EIA)


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Haynesville dry shale gas monthly production from EIA

U = 27 Tcf

Haynesville

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CP Tcf


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Haynesville HL of dry shale gas production from EIA

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Mason Inman data AEO 2013 to 2018 and UT 2017

-Shale gas: Marcellus My estimate for Marcellus gas is within the range 80-100 Tcf, when the cumulative production up to 2050 is forecasted by AEO 2018 to be over 360 Tcf

Marcellus basin is huge, but the sweet spots are concentrated in two areas and no drilling in between: its potential is likely to be poor! MCOR David Hughes 2018

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Haynesville shale gas cumulative production from AEO 2013-2018 & UT2017

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013UT 2017 $3/McfU = 27 Tcfhist (EIA)


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Marcellus Gcf/mU = 80 Tcfprod (res)U = 100 TcfU = 80 TcfCP+RRCP TcfU = 100 Tcf


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Marcellus HL of dry shale gas production from EIA

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Mason Inman data AEO 2013 to 2018 & UT 2017

The AEO2018 forecast for Marcellus in 2045 is more than 5 times the UT2017 forecast -Shale gas: Utica

-Shale gas: Woodford

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Marcellus cumulative gas production from AEO & U= 80 & 100 Tcf

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013U = 100 TcfU = 80 Tcfhist AEO


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Utica HL of dry shale gas production from EIA

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CP+RR EIAend 2016 = 18 Tcfend 2015 = 13.9 Tcfend 2014 = 7.0 Tcf

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-Shale gas: all US

-Natural gas: US

Summary for US shale gas plays

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Woodford HL of dry shale gas production from EIA

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CP+RR EIAend 2016 = 25.7 Tcfend 2015 = 23 Tcfend 2014 = 20 Tcf

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US shale gas Gcf/d

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EIA wet reserves


https://www.eia.gov/naturalgas/weekly/archivenew_ngwu/2017/12_1/

EIA does not report any reserves for Permian and for Bakken

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US HL of dry shale gas production from EIA jan2000-dec2017

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https://www.eia.gov/naturalgas/weekly/archivenew_ngwu/2017/06_29/

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US natural gas production & forecasts

U = 2400 TcfmarketeddryAEO2018AEO2017AEO2016AEO2013AEO2010U = 2400 Tcfcum prod markEIA reserves

Jean Laherrere 20 Feb 2018

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HL of US marketed natural gas production 1900-2017

mark aP/CP%1983-2006

Jean Laherrere 16 %arch2018

AEO 2018 extrapolated towards 2100 = 4000 Tcf

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-Other forecasts EIA/AEO forecasts from 1979 to 2018 display a huge range of uncertainty or poor practice (often change of the person doing the estimate): it means that the last forecast is likely to be poor too!

gas play Tcf ultimate cum prod 2017 remaining 2017Barnett 25 18 7Eagle Ford 15 9 6Fayetteville 10 8 2Haynesville 27 15 12Marcellus 80 31 49Utica 10 4,5 5,5Woodford 18 6 12shale gas 250 110 140natural gas 2400 1400 1000

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US cumulative dry gas production forecasts from USDOE/EIA/AEO AEO 1979AEO 1982AEO 1983AEO1985AEO1990AEO1993AEO1994AEO1995AEO1996AEO1997AEO1998AEO1999AEO2000AEO2001AEO2002AEO2003AEO2004AEO2005AEO2006AEO2007AEO2008AEO2009AEO2010AEO2011AEO2012AEO2013AEO2014AEO2015AEO2016AEO2017AEO2018cum actualcum + 1PJean Laherrere March 2018

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My own estimates for the ultimates of total US NG marketed has increased from 1600 Tcf in 2008 to 2400 Tcf in 2018 In contrast, the official EIA/AEO forecast is for dry gas production, which is about 7% less than marketed gas. Our forecast U=2400 Tcf is for marketed gas. The difference of forecasts between AEO 2108 dry gas and U=2400 Tcf/1,07 is 13 Tcf for 2030, 20 Tcf in 2040 and 30 Tcf in 2050; But AEO2018 NG consumption is well below AEO production by about 7 Tcf, but exceeds my forecast after 2023 and in 2050 20 Tcf is missing. The plot of AEO 2018 US NG consumption shows that US in 2050, instead of exporting 8 Tcf, will be forced to import 20 Tcf: quite a change compared to the official statements

Europe counts on the US shale gas to import LNG, but for that to occur the US must be able to produce more than they consume, which is unlikely All other analysts beside the US EIA give results that disagree with the EIA estimates, specifically: David Hughes 2018 displays US NG production 2012-2050 from EIA/AEO 2017 (but not his own forecast) and Art Berman displays US NG monthly production 2000-2017 (production starts at 20 Gcf/d)

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for 2010for 2020for 2030for 2040for 2050ultimates JL mark


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cum actual


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US natural gas production, consumption & forecasts AEO2018 & U=2400 Tcf

U = 2400 TcfmarketedAEO2018dryconsumption AEO 2018AEO2018-U=2400 Tcf/1,07


12

DNV GL (Det Norske Veritas Germanischer Lloyd in Norway is assumed to tell the truth!) report “Oil and gas forecast to 2050- Energy Transition outlook 2017” displays a peak of unconventional onshore gas production in 2016 for North America at 880 G.m3 = 31 Tcf

DNV forecasts that North America unconventional onshore gas in 2050 will be 70% of 2016 value (going down), against 160 % (going up) for AEO2018 forecasts for the US unconventional gas (only onshore) as shown in the above graph. It means that DNV disagrees with the EIA forecasts for US unconventional gas. However DNV adds: unconventional gas will be the primary source for North American LNG exports. ExxonMobil 2018 outlook forecasts that the North America unconventional gas should be in 2040 150% of its 2016 value, in agreement with AEO 2018 -Gas price, oil/gas price and flaring Gas price has sharply peaked in 2005 and 2008 and today back to pre2000 price despite that the heat content has increased.

13

If in Europe some gas contracts are indexed to oil price. The US ratio of oil to gas price per Joule (MBtu) varies largely being over 6 in 1950 decreasing slowly to 1 in 2004, increasing to 6 in 2013 and is presently around 3. EIA forecast that it will increase but stay below 4 in 2050. The problem is that the cost of transporting gas internationally is much higher than transporting oil and when gas is cheap and in excess associated to oil it is flared. The oil over gas price correlates with flared over marketed percentage in the US and since 2004 in North Dakota. I am surprised that the 1950-2005 trend for equality between oil and gas price is not the goal of EIA. I doubt that the future increase of this ratio will occur.

1

1,02

1,04

1,06

1,08

1,1

1,12

1,14

1,16

0

1

2

3

4

5

6

7

8

9

10

1950 1960 1970 1980 1990 2000 2010 2020 2030

heat

con

tent

dry

gas

MBt

u/kc

f

NG

pri

ce $

/kcf

& $

/MBt

u

year

US natural gas price: wellhead, citygate & Henry Hub from EIA & heat content

wellhead $/MBtu

citygate $/kcf

Henry Hub spot $/Mbtu

heat content mark MBtu/kcf

heat content dry MBtu/kcf


0

8

16

24

32

40

48

56

0

1

2

3

4

5

6

7

1950 1960 1970 1980 1990 2000 2010 2020 2030 2040 2050

flare

d/so

ld %

Nor

th D

akot

a

oil/g

as r

atio

& fl

ared

/mar

kete

d %

year

US oil over gas price MBtu ratio from EIA and flared over marketed percentage

annual oil/gas ratio

oil/gas ratio AEO2018

oil/gas ratio AEO2016

flared/marketed % US

flared/sold % ND


14

Oil production -Tight oil: Bakken North Dakota & Montana

Bakken ND from ND.gov https://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf Ultimate 4 Gb

From Mason Inman: AEO 2013 to 2018, and UT2017 forecast

0

1 000

2 000

3 000

4 000

5 000

6 000

7 000

8 000

9 000

0,0

0,1

0,2

0,3

0,4

0,5

0,6

0,7

0,8

0,9

1,0

1,1

1,2

1,3

2000 2005 2010 2015 2020 2025 2030 2035

cum

ulat

ive

prod

uctio

n M

b

Mb/

d

year

US Bakken monthly production from EIA play & forecast U= 4.5 Gb

Bakken (ND & MT)U = 4.5 GbCP+RREIA 1PU = 4,5 Gbcum prod Mb


0

20

40

60

80

100

120

0

1

2

3

4

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

WTI

$/b

aP/C

P%

cumulative production Mb

US HL of Bakken LTO monthly production from EIA play 1953-Sept2017

2000-2017Jan2014-Feb2017WTI


CP 1953-1999 = 42 Mb

0

100

200

300

400

500

600

700

800

900

1000

1100

1200

2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

oil p

rodu

ctio

n kb

/d

year

North Dakota: Bakken oil monthly production

U = 4 Gb

kb/d


0

25

50

75

100

125

0

1

2

3

4

5

0 500 1000 1500 2000 2500 3000 3500 4000

WTI

$/b

aP/C

P %


Bakken North Dakota monthly oil production Hubbert linearization

1955-2008Nov2008-Dec2012Jan 2012-Feb 2017Feb2017-Dec2017WTI $/b


15

-Tight oil: Eagle Ford

From TxRRC annual production

From Mason Inman data: AEO2013 to 2018

0,0

0,5

1,0

1,5

2,0

2,5

3,0

1990 2000 2010 2020 2030 2040 2050

Mb/

dBakken oil production

AEO2013 Bakken AEO2014 Bakken



UT2017 ($40/bbl case) Bakken UT2017 ($55/bbl case) Bakken

UT2017 (AEO2017 price case) Bakken historical (EIA) Bakken

0

2

4

6

8

10

12

14

16

18

20

22

24

26

2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Gb

year

US Bakken annual cumulative production from EIA AEO & U= 4.5 Gb

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013U=4.5 Gbpast EIA/FAQ


0

1 000

2 000

3 000

4 000

5 000

6 000

7 000

0,0

0,2

0,4

0,6

0,8

1,0

1,2

1,4

1,6

1,8

2005 2010 2015 2020 2025 2030

cum

ulat

ive

prod

uctio

n M

b

Mb/

d

year

US Eagle Ford monthly production & forecast U = 3 Gb

Eagle Ford playU = 3 GbCP+RREIA 1PU = 3 GbCP Mb

Jean Laherrere Feb 2018 https://www.eia.gov/petroleum/data.php#crude

0

20

40

60

80

100

120

0

1

2

3

4

5

6

7

8

0 500 1000 1500 2000 2500 3000 3500 4000

WT

I $/b

aP/C

P%


US HL of Eagle Ford LTO monthly production from EIA play

aP/CP%

Oct2013-Nov2016

WTI


0,0

0,1

0,3

0,4

0,5

0,7

0,8

1,0

1,1

1,2

1,4

1,5

0

50

100

150

200

250

300

350

400

450

500

550

2005 2010 2015 2020 2025

Mb/

d

annu

al p

rodu

ctio

n M

boe

year

Eagle Ford RRC oil & condensate production & forecast for U = 3 Gb

U = 3 Gb

oil + cond Mb

oil

condensate

Jean Laherrere March 2018 http://www.rrc.state.tx.us/eagleford/index.php

0

10

20

30

40

50

60

70

80

90

100

0

10

20

30

40

50

60

70

80

90

0 500 1000 1500 2000 2500 3000 3500

WTI

$/b

aP/C

P %


Eagle Ford HL RRC crude oil +condensate production

aP/CP%2010-20132013-2017WTI $/b

Jean Laherrere Jan 2018

16

-Tight oil: Permian Basin

All Permian basin annual production displays a decline since the peak of 1974 which is constant at 3%/a until 2005 before the burst of LTO, this 3% decline is extrapolated down to 2017 and the difference with all oil production is assumed to be the LTO, in agreement with EIA values, except for the period 2005-2010 where the EIA confuses LTO and horizontal wells

0,0

0,2

0,4

0,6

0,8

1,0

1,2

1,4

1,6

1,8

1990 2000 2010 2020 2030 2040 2050

Mb/

dEagle Ford oil production

AEO2013 Eagle Ford AEO2014 Eagle Ford AEO2015 Eagle Ford

AEO2016 Eagle Ford AEO2017 Eagle Ford AEO2018 Eagle Ford

0

2

4

6

8

10

12

14

16

18

20

2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Gb

year

US Eagle Ford cumulative production fromAEO & forecast U = 3 Gb

AEO2018AEO2017AEO2016AEO2015AEO2014AEO2013U = 3 Gbpast

Jean Laherrere March2018 source Mason Inman

0

1 000

2 000

3 000

4 000

5 000

6 000

7 000

8 000

9 000

10 000

0,0

0,2

0,4

0,6

0,8

1,0

1,2

1,4

1,6

1,8

2,0

2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

cum

ulat

ive

prod

uctio

n M

b

Mb/

d

year

US LTO Permian monthly oil production for U = 10 Gb

Permian playreal LTO ?U = 10 GbCP+RREIA 1PU = 10 GbCP Mb


source: EIA/FAQ

0

12

24

36

48

60

72

84

96

108

120

0

1

2

3

0 2 000 4 000 6 000 8 000 10 000 12 000

WTI

$/b

kb/d


HL of Permian LTO monthly oil production 2000- sept 2017

aP/CP%

March2015-Feb2017

WTI


source: EIA/FAQ

0,0

0,3

0,5

0,8

1,1

1,4

1,6

1,9

2,2

2,5

0

100

200

300

400

500

600

700

800

900

1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020 2030 2040 2050 2060

Mb/

d

annu

al p

rodu

ctio

n M

b

year

Permian Basin oil production & forecasts from ultimatesdecline3% + U=10 GbU = 50 GbTx+NM = conv

decline 3%U LTO = 10 GbLTO =all-decline3%LTO EIA/FAQall PB EIA

Jean Laherrere Feb 2018 source TxRRC & NMemnrd0

5

10

15

20

25

30

35

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14

aP/C

P%

cumulative oil production Gb

Permian Basin LTO oil production Hubbert linearization 2004-2017

aP/CP%

2012-2016


17

From Mason Inman data: AEO 2013 to 2018

-Tight oil: all less Permian, Bakken & Eagle Ford

- Tight oil: all US

0,0

0,5

1,0

1,5

2,0

2,5

3,0

3,5

4,0

4,5

1990 2000 2010 2020 2030 2040 2050

Mb/

d

Permian oil production

AEO2013 Permian Basin

AEO2014 Permian? [Austin Chalk + Avalon/Bone Springs + Spraberry + Wolfcamp]





0

5

10

15

20

25

30

35

40

45

50

2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Gb

year

Permian cumulative oil production from AEO & U = 10 Gb



0

500

1 000

1 500

2 000

2 500

3 000

3 500

0,0

0,1

0,2

0,3

0,4

0,5

0,6

0,7

2000 2005 2010 2015 2020 2025 2030

cum

ulat

ive

prod

uctio

n M

b

Mb/

d

year

all LTO-Permian-Bakken-Eagle Ford monthly production

LTO-Permian-Bakken-EagleU = 3 Gbreal LTO?CP+RREIA 1PU = 3 GbCP Mb


0

20

40

60

80

100

120

0

1

2

0 500 1000 1500 2000 2500 3000 3500 4000

aP/C

P%


US HL of all LTO-Permian-Bakken-Eagle Ford monthly production

aP/CP%Aug2015-Jul2017WTI


0

5 000

10 000

15 000

20 000

25 000

0

1

2

3

4

5

2000 2005 2010 2015 2020 2025 2030 2035

cum

ulat

ive

prod

uctio

n M

b

Mb/

d

year

US LTO monthly production from EIA play & forecast U= 20 Gb

all playsU = 20 GbCP MbEIA 1PCP+RRU = 20 Gb


0

20

40

60

80

100

120

0

1

2

3

4

0 2 000 4 000 6 000 8 000 10 000 12 000 14 000 16 000 18 000 20 000 22 000 24 000

WTI

$/b

aP/C

P%


US HL of LTO production from EIA play 1953-Dec2017

2000-Sept2017Dec2012-Feb2017WTI


CP 1953-1999 = 42 Mb

ultimate in GbPermian = 10 Bakken = 4.5Eagle Ford = 3 rest = 3total = 20.5

18

From Mason Inman data: AEO 2013 to 2018

-Crude oil: USL48 without Alaska

-Crude oil: US

0,0

1,0

2,0

3,0

4,0

5,0

6,0

7,0

8,0

9,0

1990 2000 2010 2020 2030 2040 2050

Total LTO production

AEO2013 Total AEO2014 Total AEO2015 Total

AEO2016 Total AEO2017 Total AEO2018 Total

0

10

20

30

40

50

60

70

80

90

100

110

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Gb

year

US LTO cumulative production from AEO & U=20 Gb



0

40

80

120

160

200

240

280

0,0

0,5

1,0

1,5

2,0

2,5

3,0

3,5

1860 1880 1900 1920 1940 1960 1980 2000 2020 2040 2060 2080

cum

ulat

ive

prod

uctio

n G

b

annu

al p

rodu

ctio

n G

b

year

USL48 crude oil (incl condensate) oil production

USL48USL48 less LTOU = 235 GbU = 215 GbU = 235 GbU less LTO = 215 Gbcum prod + reservescum prodcum USL48 less LTO


0

1

2

3

4

5

6

7

8

9

0 20 40 60 80 100 120 140 160 180 200 220 240 260

annu

al/c

umul

ativ

e %

cumulative production Gb

US Lower 48 HL of oil production 1859-2017

1859-2017

1978-2008 before LTO

1930-1972 at Hubbert's 1980 paper time


0

30

60

90

120

150

180

210

240

270

300

0,0

0,5

1,0

1,5

2,0

2,5

3,0

3,5

4,0

4,5

5,0

1860 1880 1900 1920 1940 1960 1980 2000 2020 2040 2060

cum

ulat

ive

prod

uctio

n &

rese

rves

Gb

annu

al p

rodu

ctio

n cr

ude

+con

dens

ate

Gb

year

US crude oil + condensate production from EIA & forecasts from U=280 Gb & AEO

AEO2018AEO2017AEO2016AEO2015AEO2014U=280 Gbpastcum + 1PU = 280 Gbcum prod


0

1

2

3

4

5

6

7

8

9

0 50 100 150 200 250 300 350 400 450 500

annu

al/c

umul

ativ

e %

cumulative production Gb

US HL of crude oil production 1859-2017

aP/CP%1931-2007


AEO2018 extrapolated towards 2100 = 500 Gb

19

The difference between AEO 2018 and my forecast for U = 280 Gb is over 2 Gb in 2030 and 3.8 Gb in 2050. AEO 2018 crude oil consumption is forecasted flat around 6.2 Gb/a from 2016 to 2050; But in percentage of AEO 2018 my forecast is 50% in 2030 but only 6.5 % in 2050

Summary for the oil plays

-EIA/AEO forecasts evolution EIA/AEO forecasts from 1979 to 2018 display a huge and chaotic range of uncertainty: it means that the last forecast is likely to be poor too! For example AEO 2011 forecasted 6 Mb/d for the US in 2020 when over 9 Mb/d was reached in 2015!

0

10

20

30

40

50

60

70

80

90

100

0,0

0,5

1,0

1,5

2,0

2,5

3,0

3,5

4,0

4,5

5,0

5,5

6,0

6,5

2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

% U

280G

b/A

EO20

18

annu

al p

rodu

ctio

n cr

ude

+con

dens

ate

Gb

year

US crude oil production & consumption AEO2018 & U=280 Gb

AEO2018 consAEO2018 prodU=280 GbAEO2018-U280Gbpast% U280Gb/AEO2018


oil play Gb ultimate cum prod 2017 remaining 2017Bakken 4,5 2,5 2,0Eagle Ford 3 2,5 0,5Permian 10 3,5 6,5LTO 20 10,4 9,6USL48 235 204 31US 280 222 58

0

1

2

3

4

5

6

7

8

9

10

11

12

1960 1970 1980 1990 2000 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100

crud

e oi

l pro

duct

ion

Mb/

d

year

US crude oil production forecasts from USDOE/EIA/AEO AEO 1979AEO 1982AEO 1983AEO 1985AEO 1990AEO 1994AEO 1995AEO 1996AEO 1997AEO 1998AEO 1999AEO 2000AEO 2001AEO 2002AEO 2003AEO 2004AEO 2005AEO 2006AEO 2007AEO 2008AEO 2009AEO 2010AEO 2011AEO 2012AEO 2013AEO 2014AEO 2015AEO 2016AEO 2017AEO 2018actualJean Laherrere March 2018

?

0

1

2

3

4

5

6

7

8

9

10

11

12

1990 1995 2000 2005 2010 2015 2020

crud

e oi

l pro

duct

ion

Mb/

d

year of forecast

US crude oil production forecasts from USDOE/EIA/AEO

for 2050

for 2040

for 2030

for 2020

for 2010


20

Rystad (a Norwegian data seller) has published a paper on world reserves in 2016. Laherrere J.H. 2016 « World, US, Saudi Arabia, Russia & UK oil production & reserves -Comments on Rystad 2016 world reserves » August http://aspofrance.org/files/reservesUS_SA_%20Ru_UK-JL2016.pdf https://aspofrance.org/2016/08/11/world-us-saudi-arabia-russia-uk-oil-production-reserves-august-2016-jean-laherrere/ Bowden reported in 1982 the US crude oil resources (ultimate?) showing an evolution with time: ultimates less than 200 Gb from 1940 to 1956 (Hubbert in 1956 was using 150 & 200 Gb for USL48), between 150 and 600 Gb (with Zapp’s estimate in 1962 = 590 Gb from unrealistic recovery per feet drilled) from 1956 to 1974 and between 200 and 280 Gb from 1974 to 1980: the range was wild and it is still!

The future US crude oil (+condensate) production is modeled with the likely ultimate of 300 Gb and the unlikely Rystad 480 Gb and the EIA/AEO forecasts from 2013 to 2016. It appears that Rystad ultimate of 480 Gb is related to AEO 2016 forecast of more than 11 Mb/d in 2040. There is a wild change in LTO forecasts between AEO 2015 and AEO 2016

0

50

100

150

200

250

300

350

400

450

500

1960 1970 1980 1990 2000 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100

cum

ulat

ive

crud

e oi

l pro

duct

ion

Gb

year

US cumulative crude oil production forecasts from USDOE/EIA/AEO AEO 1979AEO 1982AEO 1983AEO 1985AEO 1990AEO 1994AEO 1995AEO 1996AEO 1997AEO 1998AEO 1999AEO 2000AEO 2001AEO 2002AEO 2003AEO 2004AEO 2005AEO 2006AEO 2007AEO 2008AEO 2009AEO 2010AEO 2011AEO 2012AEO 2013AEO 2014AEO 2015AEO 2016AEO 2017AEO 2018cum actualcum + 1PJean Laherrere March 2018

?

0

50

100

150

200

250

300

350

400

1990 1995 2000 2005 2010 2015 2020

cum

ulat

ive

crud

e oi

l pro

duct

ion

Gb

year of forecast

US cumulative crude oil production forecasts from USDOE/EIA/AEO

for 2010

for 2020

for 2030

for 2040

for 2050

Jean Laherrere Feb2018

21

-Other forecasts David Hughes 2018 displays US crude oil production from AEO2018 peaking in 2042, because of steady tight oil but not his own forecast.

As for unconventional gas, DNV forecasts unconventional onshore oil production for North America, but if for gas Canada production is small compared with the US, it is not the same for oil. CAPP forecasts the oilsands to increase by 1 Mb/d from 2015 to 2030 for Canada, when AEO2018 forecasts an increase of 2 Mb/d for the US, when DNV forecasts an increase of 4 Mb/d for North America: it means that DNV is more optimistic than EIA

ExxonMobil Outlook 2018 forecasts that tight oil in 2040 will be 3 times the value of 2016

22

-My forecasts If the performance of the EIA is not good in forecasting US crude oil production, what about my forecasting? My modeling of the future is based on the estimate of the ultimates My estimate of the US crude oil ultimate has changed from 220 to 300 Gb between 2002 and 2018, when the extrapolation of AEO 2002 cumulative production to 2100 (assumed close to ultimate) is 350 Gb and AEO2018 500 Gb. My change is less than EIA

-Oil price and dollar value Oil price influences the US oil production, it is then important to know how the oil price changes. The best correlation for the WTI is the dollar value as I presented in many papers

-US private crude oil stocks and WTI 3 months before

US all USL48site year forecast ultimate Gb site year forecast ultimate GbUppsala 2002 220 Enc Energy 2003 200Enc Energy 2003 230 ENSMP 2004 200Lisbon 2005 230 MIT 2014 225Beijing 2006 230 2018 235Luxembourg 2006 250comRystad 2016 300

2018 280

0

50

100

150

200

250

300

350

400

1990 1995 2000 2005 2010 2015 2020

cum

ulat

ive

crud

e oi

l pro

duct

ion

Gb

year of forecast

US cumulative crude oil production forecasts from USDOE/EIA/AEO

for 2010for 2020for 2030for 2040for 2050ultimates JL


0

50

100

150

200

250

300

350

400

450

500

1960 1970 1980 1990 2000 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100

cum

ulat

ive

crud

e oi

l pro

duct

ion

Gb

year

US cumulative crude oil production forecasts from USDOE/EIA/AEO 2018 & 2002 and JL ultimate

AEO 2018

AEO 2002

JL ultimate 2018

JL ultimate 2002

cum actual


?

-105

-100

-95

-90

-85

-80

-75

-70

-65

-60

-55

0

15

30

45

60

75

90

105

120

135

150

1/1/00 12/31/04 1/1/10 1/1/15 1/2/20

nom

inal

maj

or c

urre

ncie

s dol

lar

inde

x *-

1

WTI

oil

pric

e $/

b

date

US WTI crude oil daily price and dollar value * -1

WTI $/b

Dollar Index (majorcurrencies)*-1


http://www.federalreserve.gov/releases/h10/summary/indexn96_b.htmhttp://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=rwtc&f=D

-97

-96

-95

-94

-93

-92

-91

-90

-89

-88

-87

-86

-85

20

30

40

50

60

70

Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

nom

inal

maj

or c

urre

ncie

s dol

lar

inde

x *-

1 sh

ifted

30

days

WTI

oil

pric

e $/

b

date

US WTI crude oil daily price and dollar value * -1 shifted 30 days

WTI $/b

dollar shift 30 days


http://www.federalreserve.gov/releases/h10/summary/indexn96_b.htmhttps://research.stlouisfed.org/fred2/series/DCOILWTICO/downloaddata

23

Some believe that the oil price follows the private stocks of crude oil, but since 2014 it appears that the stocks follows the WTI 13 weeks before, except few months in 2017 after the OPEC Russia deal for reducing production

Conclusions The USDOE/EIA believes that the US oil and gas production will be higher in 2050 (and in every year in between) than in 2017, based on the growth of shale plays coming from the drilling of a huge number of wells. They do so without bothering to check if there is enough room in the sweet spots to do so or if the yield in the non sweet spots is enough to generate that much oil ; we believe the contrary, based on the estimate of the ultimate of shale plays from the Hubbert linearization of past production and on the assumption that in the USL48 many cycles of past production and drilling were symmetrical that the shale plays will also display symmetrical future production curves. AEO2018 forecasts US production in 2040 for oil at 12 Mb/d, my forecast is 4 times less at 3 Mb/d, for gas at 40 Tcf, my forecast is half at 20 Tcf. It is not a small difference, but a huge one. I can be wrong, but EIA has to prove that their future drilling is possible economically and geologically, but up to now I cannot find any view from EIA on this problem. The EIA has also to estimate the ultimate of each play, but, in order to do so, they have to reject the stupid rule of the SEC (to please the bankers) forbidding the reporting of 2P (proved + probable) reserves. The EIA has to recognize the fact reported by the SPE/PRMS that the aggregation of proved (1P) reserves is incorrect, only the addition of 2P is correct. (Laherrère J.H. 2008 «Advice from an old geologist-geophysicist on how to understand Nature» presentation Statoil Oslo 14 August http://aspofrance.viabloga.com/files/JL_Statoil08_long.pdf) USDOE/EIA should report the 2P US reserves like the USDOI/BOEM for the reserves of the Gulf of Mexico. Reporting 2P and backdating discovery allows to estimate ultimate using creaming curve. EIA once reported as an open file backdated established reserves with USDOE/EIA-0534 1990 "US oil and gas reserves by year of field discovery» Aug: it was supposed to be the first of a series, but in fact later it was censured and never updated. It is time to restart such good practice. Exxon and Total 10 years ago were reporting proved and non-proved reserves (2P), but today they report only 1P to follow the SEC rule. Today only Gazprom is reporting 1P and 2P, as also their queer ABC1.

-115

-105

-95

-85

-75

-65

-55

-45

-35

-25

-15

300

320

340

360

380

400

420

440

460

480

500

520

540

2014 2015 2016 2017 2018 2019

WTI

*-1

13

wee

ks b

efor

e

US

priv

ate

stoc

ks c

rude

oil

Mb

year

US weekly private stocks crude oil & WTI *-1 shifted 13 weeks

Weekly U.S. Ending Stocks excluding SPR ofCrude Oil "excluding lease stock" Mb

WTI *-1 13 weeks before

Jean Laherrere 14 March 2018

-160

-140

-120

-100

-80

-60

-40

-20

0

210

260

310

360

410

460

510

560

1980 1985 1990 1995 2000 2005 2010 2015 2020

WTI

*-1

13

wee

ks b

efor

e

US

priv

ate

stoc

ks c

rude

oil

Mb

year

US weekly private stocks crude oil & WTI *-1 shifted 13 weeks

Weekly U.S. Ending Stocks excluding SPRof Crude Oil "excluding lease stock" MbWTI *-1 13 weeks before


24

All scouting agencies report the confidential 2P reserves used internally by the operators to decide the development of their fields.

jean laherrere 19 march 2018 · 6 mason inman data aeo 2013 to 2018 and ut 2017 aeo2014 was...

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