Final version 14 March 2007 for Petroleum Africa
What’s Wrong with Reserves?
by Jean Laherrere jean.laherrere@wanadoo.fr
The publishing of data is a political act, one depending largely upon the image the author
would like to portray i.e. rich in front of the banker, the shareholder, or alongside quotas;
poor in face of taxes. Most debates argue over words that are not clearly defined (as oil or
reserves) and which are distinct from their authors, resulting in often useless discussions.
Wording ambiguities
Gas means gasoline for some, but natural gas for others. M means thousand for the US
industry (outside computers) but million (= mega) in metric countries. Billion is thousand
millions in the US, but million millions (square million) in Europe. Webster’s definition for
billion is a very large number, which is not very precise!
Reserves Definitions
There are currently several reserve definitions in use:
 US: all energy companies listed on the US stock market are obliged by the SEC to
report only proved reserves (1P), assumed to be the minimum; these reserves are
audited.
 OPEC: because quotas depend upon reserves, OPEC members report proved reserves
(1P), which is their wish being non-audited.
 FSU classification: ABC1 (1979) reports maximum theoretical recovery, being equal
to proven plus probable plus possible (3P).
 Rest of the world: SPE/WPC (1997) regulations (I was a member of the task force)
report reserves as proven plus probable (2P), close to the expected value.
Proved reserves (1P) tell bankers that the company will not be bankrupt, but development
decisions are taken on mean reserves (2P). The aggregation of proved reserves is incorrect, as
it underestimates the total. Thus, national proved reserves are more than the addition of field
proved reserves, and therefore world proved reserves are more than the addition of all
national proved estimates.
SPE 2007 definitions show how misleading simple addition can be as only mean (proven plus
probable) data should be added. Perceived reserve growth occurs when reserves are initially
reported at the minimum (proved) and then simply added, which does not happen statistically
when reported as proven plus probable, which is already the mean (expected) value.
Proven plus probable reserves estimates are confidential in all countries except the UK (DTI),
Norway (NPD), and federal US (MMS). In Russia, divulging oil ( but not gas) reserves can be
punished by 7 years jail!
Scout companies sell reserve databases but they are very expensive, dealing with huge
quantities of data (about 24 000 fields outside the US and Canada non-frontier provinces).
My main graph displays the technical (backdated mean) and the political (current proved)
remaining reserves at the end of 2005.
Figure 1: World oil remaining reserves from political and technical sources
1400
remaining reserves Gb
1200
World oil remaining reserves from political and
technical sources
including tarsands
+175 Gb
omission of probable
incorrect aggregation
1000
800
OPEC fight for
quotas +300 Gb
600
400
technical = 2P = proven+probable:
backdated mean excluding extra-heavy
political = 1P = current proved
200
0
1940
1950
1960
1970
1980
1990
2000
2010
year
Jean Laherrere 2006
The same graph was presented eight years earlier in the Scientific American, March 1998,
Campbell and Laherrere, “The end of cheap oil.”
Figure 2: same graph presented in 1998 in Scientific American
The 2006 graph is identical to the 1998 one, showing that ASPO (The Association for the
Study of Peak Oil) does not change as often as some say.
Proven reserves are only financial data and should never been used for forecasting
future production.
Unfortunately technical (2P) data are not usually published (except in the UK (DTI), Norway
(NPD), and US federal (MMS)), but they can be bought by scout companies such as IHS or
Wood Mackenzie, so it is wrong to say that they are confidential; they are only expensive and
anyone can buy them.
US DOE/EIA proved reserves as end of 2005; posted October 5, 2006:
US federal agencies are obliged since 1993 to use the International System (SI) of units, and
under SI, thousands have to be indicated by a space and not a comma (which is used in some
countries to indicate the decimal point).
Oil (Billion
OGJ
BP
WO
Cedigaz
barrels = Gb)
World
1 292.935 5
1 201.331 538 509 4
1 119.615 3
Canada
178.792 4
16.500
12.025
Africa
102.580
114.268
109.759
Gas (Tcf)
World
6 124.016
6 359.172
6 226.554 6
6 380.625
Norway
84.26
84.896 5
83.272 1
109.759 02
Africa
485.841
507.826
490.882
508.819
This inventory is misleading because it is incorrectly aggregated, yet is repeated every year.
Reporting any data with more than two significant digits is statistically incorrect
because the accuracy of the different estimates varies over 10%.
US proved reserves are assumed to be conservative (reasonable certainty to exist) and for
some represent a 90% probability (= P90), but in fact the US DOE’s annual report gives the
positive revisions as the negative revisions, allowing to compute the probability of these
estimates, being the percentage of positive revisions over positive plus negative revisions. The
probability varies for oil from 75% to 55% (even below 50% in 2001 where negative
revisions were higher than positive revisions). For gas and NGL the probability is worse.
Figure 3: US probability of the estimate of proved reserves from revisions of USDOE
annual reports
US probability of proved reserves from revisions
of EIA US 2005 annual report
probability of estimate = %
positive revisions versus posotive +
negative revisions
75
70
65
60
55
50
oil
45
dry gas
40
NGL+condensate
write off Prudhoe Bay gas
35
1975
Jean Laherrere 2007
1980
1985
1990
1995
year
2000
2005
2010
source EIA US AR 2005
This graph shows that US operators do not precisely follow SEC rules, leading them to report
a value closer to 2P than to 1P. SEC rules were written in 1977, compared to SPE rules which
have been changed several times, and disregard probabilistic approaches. SPE/WPC/AAPG
(1997) reserves definitions are used internally now by most operators. In fact IOCs use
several different reserves figures; internal ones used by geologists or reservoir engineers and
external ones for the SEC or DTI. The rest of the world (Canada dropped SEC rules in 2003)
reports proved plus probable. As long as only proved reserves will be used, all forecasts based
on such data are flawed.
Plotting current proved reserves and backdated mean remaining reserves for Africa at the end
of 2006 reveals a huge difference, as in the first graph for the world.
Figure 4: Africa remaining oil reserves from political and technical sources
Africa: remaining oil reserves from political and technical data
120
110
remaining oil reserves Gb
100
90
80
70
60
50
remaining mean 2P discovery
40
proved reserves BP
30
proved reserves EIA=OGJ
20
proved reserves WO
10
0
1950
1960
Jean Laherrere 2007
1970
1980
1990
2000
2010
year
The Cause for Confusion
Ambiguity is often favored by purpose but many confusions show imperfect knowledge as
shown by the following:
 Oil and liquids: oil can vary from regular (former conventional) oil of Campbell (66 million
bpd,) to crude oil (73 million bpd) and finally to all liquids including NGLs, synthetic oils
from coal (CTL), biomass (BTL), and refinery gains (85 million bpd in 2005).
 The term “liquids” may be restricted to hydrocarbons (Campbell) or to all liquids including
everything that burns (olive oil).
 Oil production in the US includes condensate produced at the wellhead, but excludes NGL
production totals. OPEC oil production excludes condensate. The UK reports only condensate
while Norway reports condensate in cubic meters and NGL in tonnes (metric tons).
 Conventional versus unconventional: there is no consensus. In the past, conventional was
primary and secondary recovery, with the rest being unconventional. Some exclude heavy oil
such as arctic and deepwater. USGS and SPE define conventional as having water-contact
with dynamic aquifer.
 Peak oil is often discussed without defining the product, and oil peak dates (as ultimate
reserves) are compared when they are not dealing with the same “oil.”
Recovery Factor (RF)
Volume-in-place is estimated only from seismic and well data, while reserves are estimated at
the end from production data. RF is often reported as a round value and is usually an educated
guess. However the RF from IHS at the end of 2006 shows clearly that for gas the FSU
classification ABC1 (3P) is quite higher than that of the other continents using 2P definitions.
Figure 5: Natural gas recovery factor by continent
Reserves Production Ratio (R/P)
R/P is often used to describe the future as 40 years for oil, but it is a very poor ratio as it
assumes that oil production will stay constant for 40 years and will decline to zero the
following year. US (current proved) R/P for oil has been 10 years for the last 80 years, showing
clearly that it is not a good indicator and also that proved reserves are an obsolete tool. Even
using 2P reserves, R/P is curved and tends towards an asymptote (20 years).
Figure 6: World oil (crude less extra-heavy) R(mean)/P with logistic models for
U=2000 Gb
World crude oil (less extra-heavy) R(mean)/P with logistic models
for U = 2000 Gb
220
200
180
R/P
R/P model
160
R/P years
140
120
100
80
60
40
20
0
1910
1930
Jean Laherrere 2007
1950
1970
1990
2010
2030
2050
year
Ultimate Assessment
The best way to assess oil and gas reserves ultimately is to plot the cumulative backdated mean
discovery versus the cumulative number of pure exploratory wells (New Field Wildcats=
NFW).
Figure 7: Africa creaming curve 1886-2006
250
4000
225
3600
200
3200
175
2800
150
2400
125
2000
100
1600
1956-1992
1992-2006
75
oil+condensate
oil Gb
gas Tcf/6
50
25
1200
800
cumulative number of fields
cumulative discovery Gb, Tcf/6
Africa creaming curve 1886-2006
400
field
0
0
2000
4000
6000
0
8000 10000 12000 14000 16000 18000 20000
cumulative number of New Field Wildcats
Jean Laherrere 2007
It is easy to model the creaming curve with two cycles (hyperbolas); the first from 1956-1992,
and the second from 1992-2006 which includes mainly deepwater wildcats and shows an
increase in discovery volume but not in the number of fields (where the break was around 4000
NFW in the 1956 with the discovery of Hassi Messaoud). The discovery of gas in Tcf/6 (=
billion barrels of oil equivalent as 1 boe = 6 kcf) displays a similar pattern being roughly half.
The ultimate is about 250 Gb for oil and condensate and about 750 Tcf for gas.
Plotting the same cumulative discovery versus time displays the same two cycles. Offshore
cumulative discovery is 75 billion barrels out of 200 billion barrels.
Figure 8: Africa cumulative oil and gas discovery versus time
Africa cumulative discoveries 1886-2006
225
cumulative discovery Gb, Tcf/6
4000
oil+condensate
oil Gb
O+C offshore
U=250 Gb
gas Tcf/6
gas offshore Tcf/6
field
field offshore
200
175
150
3600
3200
2800
2400
125
2000
100
1600
75
1200
50
800
25
400
0
1940
1950
1960
1970
1980
1990
2000
2010
2020
2030
cumulative number of fields
250
0
2040
year
Jean Laherrere 2007
Cumulative discovery versus water depth or onshore elevation indicates that the most
productive fields are offshore below 1000 meters of water and onshore less than 500 meters.
Figure 9: Africa cumulative discovery versus water depth and elevation
Africa: cumulative discovery versus elevation
200
180
cumulative discovery Gb, Gboe
160
oil offshore Gb
oil onshore Gb
gas offshore Gboe
gas onshore Gboe
140
Hassi Messaoud
120
100
Hassi R'Mel
80
60
40
20
0
-2500
-2000
Jean Laherrere 2007
-1500
-1000
-500
0
500
1000
1500
2000
elevation in meter
If discoveries have increased significantly since 1955, but from 1968 remaining reserves are
constant at about 90 billion barrels, then R/P is decreasing towards 20 years.
Figure 10: Africa cumulative discovery & production, remaining reserves and R/P
Africa: cumulative oil discovery & production, and R/P
200
oil discovery
crude production
remaining discovery
R/P
180
160
Gb, R/P years
140
120
100
80
60
40
20
0
1950
1960
1970
1980
1990
2000
2010
year
Jean Laherrere 2007
NFW water depth ( blue curve) increases in as deepwater goes deeper, NFW number peaked in
1981, but average (smoothed by 3 years) field size (green curve) has peaked in 1959 and 1999.
Figure 11: Africa offshore discovery: NFW water depth & number, average field size &
number
Africa offshore annual discovery
Mboe, water depth meter NFW
1000
900
132
average water m
smooth average field Mboe
NFW
field
120
108
800
96
700
84
600
72
500
60
400
48
300
36
200
24
100
12
0
1950
1960
Jean Laherrere 2007
1970
1980
year
1990
2000
0
2010
number of fields and NFW
1100
Technology is often presented as increasing reserves. In fact, for conventional fields
technology allows operators to produce faster and cheaper, but no more at the end. Many
examples of technology use in giant fields show that in the end the production collapses: East
Texas (US), Brent (UK), Yibal (Oman). For one, the Rabi-Kounga, Gabon’s largest oil field,
was produced quickly with horizontal drilling and infill wells, but the decline was sharper
than expected tending towards lower reserves.
Figure 12: Rabi-Kounga oil decline 1989-2005
Rabi-Kounga oil decline 1989-2005
80
40
1989-2003
1997-1998, 2003-2005
70
35
Uscout 1
U scout 2
30
U IFP 2005
wells
50
25
Linéaire (1997-1998,
2003-2005)
40
20
15
30
in 2003 the concession
finishing in 2007 was
changed into a PSA
20
annual wells drilled
annual production Mb/a
60
10
5
10
0
0
0
100
200
300
400
500
600
700
800
900
1000
1100
cumulative production Mb
Jean Laherrere 2007
There are only a few examples of reserve growth due, not to technology, but to exceptional
geological conditions of the reservoir, such as Ekofisk (compaction of the chalk leading to an
8-meter seafloor subsidence) and Eugene Island 330 (red fault connecting reservoir and
source rock).
In contrast, technology (tertiary recovery) is a must in unconventional fields such as heavy oil
fields like Midway-Sunset or Kern River (steam and many infill wells) or extra-heavy oil as
Athabasca or Orinoco, but their growth must not be extrapolated to conventional fields.
A March 5, 2007 New York Times article refers to the Kern River heavy oil field as an
example of reserve growth to be applied to modern fields, however it uses an unscientific
approach, comparing apples to oranges, conventional fields to unconventional fields, and
outdated US practice of proved reserves to rest of the world proven plus probable reserves.
Kern River, discovered in 1893 in California, peaked in 1999 with 9000 producing wells,
more than 100 years later as production was raised little by little with the slow rate of drilling,
but then suffered a sharp decline.
Figure 13: Kern River oil decline 1900-2005
55
11000
50
10000
45
9000
40
8000
35
7000
30
6000
25
5000
15
1900-1999
1903-1933
1999-2005
10
U California
20
4000
3000
2000
number of wells
5
1000
0
0
500
Jean Laherrere 2006
number of wells
annual production Mb/a
Kern River (1899 13°API) oil decline 1900-2005
1000
1500
cumulative production Mb
2000
0
2500
In fact Kern River current reserves were inaccurately computed as 10 times current annual
production, so reserve growth had to be expected!
Figure 14: Kern River cumulatrive production, ultimate as CP +R=10P
Kern River cumulative production, ultimate
as CP + R = 10 P
2500
2000
reported Ultimates
decline Ultimate
Mb
1500
CP +aP*10
CP
proved reserves
1000
real remaining reserves
500
0
1940
1950
Jean Laherrere 2006
Conclusion
1960
1970
1980
year
1990
2000
2010
As long as SEC regulations inhibit IOCs from reporting 2P reserves, and as long as OPEC
quotas prevent members from accurately reporting reserves, reserves data will be flawed.
Proved reserves are financial (SEC) or political (OPEC) data and should not be aggregated or
used in forecasts about the future. Only proven plus probable estimates should be used and
only annual production of mature fields is required for a good estimate of reserves,
irrespective of all published estimates. Every country should release complete historical field
annual production and most disagreements on reserves will disappear for those ready to plot
the decline and to extrapolate it. Unfortunately it does not work well when field production is
constrained by OPEC quotas or investment. But now quotas are less and less followed and
investments are plenty from IOCs for countries which do not deny signed agreements as
Venezuela, Bolivia and Russia.
References:
-Laherrere, Jean. “Uncertainty on Data and Forecasts,” ASPO 5, Pisa, July 18-19, 2006
www.oilcrisis.com/laherrere
-Laherrere, Jean. “Comments on SPE Nov 2006 Revised Reserves and Resources Guidelines
Available for Industry Review,” 31 January2007, www.oilcrisis.com/laherrere
-Laherrère Jean «Shell’s reserves decline and the SEC’s obsolete rule book » Energy Politics
issue II summer 2004 p23-45, draft
http://www.hubbertpeak.com/laherrere/ShellDecline2004.pdf