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Forecasting World Natural Gas Supply

Copyright 2000, Society of Petroleum Engineers Inc.
This paper was prepared for presentation at the 2000 SPE/CERI Gas Technology Symposium
held in Calgary, Canada, 3-5 April 2000.
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World gas supply forecasting has proved difficult because its
exploration, transportation, and customer bases are so heavily
dependent on fluctuating economic factors. Our recent study
showed that the conventional Hubbert model with one
complete production cycle is not appropriate for use in
forecasting gas production trends for most gas producing
This paper presents our forecast for the world’s supply of
conventional natural gas to the year 2050. We used a
multicyclic Hubbert approach to develop 53 country-specific
gas supply models that enable production forecasts for
virtually all of the world’s gas. The multicyclic modeling
approach is presented in a convenient form that makes
production data exhibiting two or more cycles easier to model.
These models were aggregated to the regional level and to the
world level. Supply models for some organizations (e.g.
OPEC, non-OPEC, OECD) were also developed and analyzed.
Our results indicate that the world’s supply of natural gas
will peak in 2014, followed by an annual depletion rate of
1%/yr. A regional analysis indicates that gas production of
some regions will peak soon. North American gas production
is currently (1999) at its peak. West European gas production
is expected to peak in 2002. The countries of the former
Soviet Union and Middle East, which comprise about 60% of
world’s ultimate recovery of natural gas, will be the main
sources of world gas supply in the future.
Natural gas is becoming an increasingly important source of
the world's energy. In recent years, natural gas has become the
fastest growing fossil fuel, and it will continue to grow rapidly
for several decades. The US Energy Information
Administration (EIA)1 reported that the world’s gas
consumption grows by 3.3%/yr compared to 2.2%/yr for oil
and 2.1%/yr for coal. This higher growth rate can be attributed
to several factors. First, natural gas, including unconventional
gas, is available in abundant quantities in many parts of the
world. Second, natural gas is environmentally cleaner than
coal and crude oil. Third, the lower price of gas relative to
other fuels makes it attractive to many gas operators and
Fig. 1 shows the U.S. wellhead prices of gas and crude oil
since 1949. These data are wellhead inflation-adjusted prices
based on 1992 U.S. dollars on an equivalent energy basis. The
figure shows that there is a somewhat direct relationship
between oil and gas prices, with a time lag of 3 to 4 years. In
1949, the gas/oil price ratio was 0.12, indicating that gas was
12% as valuable as oil on an energy basis. Since that time the
trend of this ratio has been increasing generally upward,
reaching the value of 0.94 in 1998. This indicates that gas has
now reached a close price parity with oil.
The gas industry is influenced by political events,
economic factors, and its relationship with the oil industry.
Fig. 2 shows the U.S. marketed gas production rate since
1918. The gas production trend from 1918 until 1970 shows
an exponential growth. From 1970 to 1973, gas production
continued to increase, but at a slower rate of growth. Oil
production peaked in 1970. Contributing factors to the slow-
down in gas rate increases might have been the oil production
decline, which resulted in a decline of associated gas
production, and lower gas prices. However, there were gas
supply shortages in the very cold winter of 1972-1973. Actual
gas production peaked in 1973, the time OPEC cut production
of crude oil. Then gas production rates dropped, paralleling
the decline in oil production. This drop in gas rate extended to
1975 since the gas market was based on long-term gas sales
contracts with stable prices. During the 1975-1979 period, gas
production showed slow growth and gas prices became more
extensively regulated. In 1979, the Iranian revolution caused
oil prices to increase sharply reaching the peak in 1981. This
corresponded to an increase of gas prices, which peaked in
1984 (Fig. 1.) The oil/gas price time lag of three to four years
possibly resulted from the moderating effect of long-term gas
contracts. In 1981, with low gas demand, the “gas bubble” and
gas production decreased rapidly until 1986 despite the fact
that gas reserves and production capacities were high.
SPE 59798
Forecasting World Natural Gas Supply
S.M. Al-Fattah, SPE, and R.A. Startzman, SPE, Texas A&M University
Since 1986, gas production has been increasing steadily
for a variety of reasons. Among those are government policy
and tax incentives, increased gas demand caused by fuel
switching and low gas prices, and increases in unconventional
gas production.2
Of considerable interest to both producers and consumers
is the future direction of US gas production. Our recent study3
indicated that Hubbert’s model,4-7 which proved useful for oil
production forecasting, does not account for fluctuations in
gas producing rates. Thus, it may not be appropriate for use in
forecasting gas production for the US and a number of other
countries. This paper presents new forecasting models for the
future gas supply. Our supply models are based on production
analyses of a country-by-country basis. Natural gas supply
analysis by region and by organization or group will be
Several authors4-12 have shown that Hubbert’s model with one
complete production cycle is adequate for predicting crude oil
production. However, our recent study3 showed that, in the
case of natural gas production, most countries exhibit two or
more Hubbert-type production cycles. These additional cycles
apparently result from new exploration areas and technology,
regulations, economic factors and/or political events. Using a
Hubbert model with a single production cycle did not allow
for these factors. To account for additional production cycles
we used the “multicyclic Hubbert” model we presented
earlier3. Based on the number of cycles suggested by the
production data, we can add a number of Hubbert-type
production cycles. The production rate of the multicyclic
model can be computed using the following equation:
( )
[ ]
+== k
maxmax 14)()( (1)
where k is the total number of production cycles, qmax the
maximum or peak production, tmax the time at peak production,
and a constant. This equation has fewer parameters (three)
than the Hubbert’s equation (Eq. 2) that has four, making
production data easier to model. Eq. 1 also provides a better fit
for multicyclic production data than the Hubbert model with
its single production cycle.
[ ]
= . (2)
The parameters of the multicyclic model can be
determined using a nonlinear least-squares method. Every
complete production cycle has its own value of ultimate
recovery, Q, computed by use of Eq. 3, and the total ultimate
recovery is then determined by adding the ultimate recoveries
for each production cycle.
4 . (3)
The “logistic” curve of the cumulative production of the
multicyclic model can be calculated as
( )
[ ]
+= k
max max
14 . (4)
Peak Production. Peak production can be estimated from the
following analytical tools and information:
(1) correlating backdated discovery data with production
data with shifted time lag,
(2) using the method of inflection points,
(3) using known ultimate recovery, and/or
(4) estimating ultimate recovery, if unknown, by adding
the cumulative production and proved reserves.
We recommend the use of more than one tool at a time to
improve the certainty of prediction. Here is the method for
predicting the peak production of the Hubbert or bell-shaped
curve using the inflection points of the curve:
The two inflection points on the Hubbert, or bell-shaped,
curve are determined by taking the first derivative of the
Hubbert rate/time equation, Eq. 2. Then, taking the second
derivative of Eq. 2, setting it to zero, and solving for the time
will give the time at the two inflection points. The solution
gives the points tifl1 and tifl2, which are
1ooifl Natt += (5)
2ooifl Natt ++= . (6)
The corresponding production rate of these inflection
points can then be obtained by substituting either tifl1 or tifl2
into Eq. 2. Thus, the production rate at the inflection points is
=aQqifl . (7)
From Eq. 3 and Eq. 7, a relationship can be established
between the maximum production rate and production at
inflection points, given by
qq 2
max =. (8)
We also found another relationship relating the time at
peak production and the time at the inflection point on the
bell-shaped curve.
1max a
tt ifl += . (9)
These relations state that the maximum production rate is
1.5 times the production rate at the inflection points at a
distance of (1.317/a) from the time of inflection points on
either side of the symmetrical bell-shaped curve.
Therefore, knowing the rate at the inflection point on the
curve, we can predict the peak or maximum production rate.
Rather than solving analytically, we can also estimate the
production rate at the inflection points as given in Eq. 7 from
production data by using a spreadsheet.3
The time at maximum production can also be expressed in
terms of maximum production or of production rate at the
inflection point. Thus, the time at peak production can be
determined using
ifl q
+= 219.0
1max (10)
1max qQ
tt ifl
+= . (11)
If we choose to use the inflection point on the right side of
the curve in the calculations, then the positive sign of the
second terms in Eqs. 9, 10, and 12 must be changed to a
negative and tifl1 be changed to tifl2.
The multicyclic model proved to be an effective approach
for modeling cyclic production data. Some of its
characteristics include that:
(1) It is derived from physical and mathematical concepts.
(2) It can history match with good accuracy data
fluctuations influenced by economic factors and/or
political events.
(3) The results are reproducible.
(4) It uses historical data that are obtainable.
(5) These procedures are simple and can be readily
implemented using a computer spreadsheet program.
(6) The predictions can be easily updated with new data.
However, like Hubbert’s original model, the results from
the multicyclic model are not strictly unique because the
model is data-sensitive, especially when using few data from
small fields. Therefore, we recommend performing sensitivity
analysis of the model parameters. The use of many data points
from large fields helps reduce the sensitivity of the model.
Sources of Data
We used historical natural gas production data acquired from
Oil and Gas Journal (OGJ) database,13-14 Twentieth Century
Petroleum Statistics,15-16 and the Energy Information Admin.
(EIA).17 We used discovery data of the U.S. (1900-1997) from
Refs. 17 and 18, and obtained U.S. marketed gas production
(1918-1997) from the Twentieth Century Petroleum Statistics.
Annual production of natural gas for all other countries was
obtained from OGJ databases for the period 1971-1997.
Proved reserves of natural gas for all countries (1967-1998)
were obtained from OGJ.
The following sections present analysis of the world’s natural
gas by region. The forecasting model of each region was
constructed by aggregating the corresponding countries’
models to their respective region level. A summary of the
results is given in Table 1. The results of ultimate recovery,
future recoverable gas, and cumulative production for each
region are depicted in Fig. 3.
North America
This region includes gas production from Canada, Mexico,
and the U.S. Historically, most of this region’s production is
from the U.S. In 1971, the U.S. production of 22.5 Tcf/yr
contributed about 88% of this region’s production compared
to 72% in 1997. A 27-year (1971-1997) average production
share of U.S. in North America is about 81%. On the other
hand, Canada increased its share of production from around
10% (2.5 Tcf/yr) in 1971 to 24% (6.6 Tcf/yr) in 1997. Mexico
has a fairly stable share of production ranging from 3% to 4%
of the total regional production during the period 1971-1997.
Fig. 4 shows the region’s actual and predicted gas
production from the multicyclic Hubbert approach. The 1997
predicted production (28.1 Tcf/yr) is higher than the actual
(27.7 Tcf/yr) by 0.5 Tcf/yr. The model indicates that the
conventional gas production of this region will peak in 1999 at
about 28.6 Tcf/yr. Production then will decline at an average
annual decline rate of 0.7 Tcf/yr from 2001-2027; thereafter,
production will have a slower decline with 0.4 Tcf/yr. Most
production is predicted to come from the U.S. until 2010 when
Canada and the U.S. will have the same production of 10.5
Tcf/yr. The production share of Canada will reach about 55%
by 2025 and decrease to 41% in 2040.
Our studies indicated that the estimated ultimate recovery
of conventional gas for this region is approximately 1900 Tcf,
and about 840 Tcf would remain to be produced (future
recoverable gas) as of 1997 year-end. This quantity has an
annual depletion rate of 3.3%/yr, the highest depletion rate of
recoverable gas of any region worldwide. In particular, the
U.S. has an annual depletion rate of 6.4%/yr, thus ranking
U.S. the highest country worldwide in gas reserves depletion.
Canada and Mexico have annual depletion rates of 2.0%/yr
and 0.6%/yr, respectively.
South and Central America
This region includes gas production from Argentina, Bolivia,
Brazil, Chile, Columbia, Ecuador, Peru, Trinidad and Tobago,
and Venezuela. These countries produced about 3.4% (2.8
Tcf/yr) of world gas production during 1997, and hold around
4.4% (222 Tcf) of world proved reserves of natural gas as of
1997 year-end. The largest gas producer of this region is
Venezuela, followed second by Argentina, and Trinidad and
Tobago comes far third. The same ranking holds for the
proved reserves.
The actual and predicted gas production for this region is
shown in Fig. 5. Our forecast model indicates that production
of this region will peak in 2018 at 4.7 Tcf/yr. This peak
production will maintain its level from 2015 until 2021.
Production will then start declining steadily at an average 0.03
Tcf/yr through 2050, representing an annual average decline
rate of 0.7%/yr. Production of this region is predicted to be 3.8
Tcf/yr in 2050, and 285 Tcf of cumulative gas will have been
produced by that time. Gas supply will be mainly from
Venezuela and Argentina until the peak production of the
region is reached, after which Venezuela will take the leading
role. In 2025,Venezuelan production is predicted to contribute
54%, and 78% in 2050 of the total region production.
Our estimated ultimate recovery for this region is 419 Tcf
of which 68% (285 Tcf cumulative gas) is predicted to be
produced by 2050. The future recoverable gas of this region is
364 Tcf, which will last approximately for 130 years assuming
a constant 1997 rate of production. The region’s annual
depletion rate is 0.76%/yr, with the highest being Argentina
(2%/yr) followed by Trinidad and Tobago (1.8%/yr).
Western Europe
The major producing countries from this region will continue
to be the Netherlands, the U.K., and Norway. These countries
contributed 80% of 1997 west European production. Norway’s
share of the region’s production is predicted to increase from
15.4% in 1997 to 51% in 2015, after which it will dominate
the region’s production, reaching 85% in 2035 and 90% in
Fig. 6 shows this region’s actual and predicted production.
Our model shows that the peak production will occur in 2002
at 12 Tcf/yr. Production then will have an annual average
decline rate of 3.6%/yr until 2015. After that, production gets
flatter, mainly due to Norway’s production, then having a
more relaxed annual decline rate of 2%/yr until 2050. Some
countries in this region have already passed their peak of
production. Austria peaked in 1975, followed by a smaller
second peak predicted to have occurred in 1998 and now in
decline. France also peaked in 1983 and has experienced a
general decline trend since then.
We estimated the ultimate recoverable gas for this region
to be 560 Tcf. Of this amount, around 66% (367 Tcf)
remained to be produced as of 1997 year-end, and 535 Tcf of
cumulative gas is predicted to be produced by 2050. Our
analysis indicates that the western European region stands
second highest, after North America, with an annual depletion
rate of 2.8%/yr. Countries with high depletion rates are
Denmark (6.3%/yr), France (5.9%/yr), Austria (5.5%/yr), and
the Netherlands (5.5%/yr). With the 1997 production given as
constant, the future recoverable gas will continue for 36 years.
This is in close competition with that of North America.
Eastern Europe and FSU
This region includes the countries of Albania, Hungary,
Romania, and other low producing countries of eastern Europe
and the former Soviet Union (FSU). As of 1997, FSU alone
accounted for 29% (23.8 Tcf/yr) of the world’s gas production
and held about 39% (1977 Tcf) of the world’s proved gas
reserves. In contrast, gas production from eastern European
nations contribute less than 2% of world production with less
than 1% of the world’s proved reserves.
The actual and predicted production of this region is
shown in Fig. 7. The 1997 predicted production is slightly
higher than the reported production by 0.6 Tcf/yr. The
production of this region has been declining since 1990, the
time when the countries of FSU separated and became
independent; it is predicted to hold at about the same 1997
level of production until 1999. Production is predicted then to
start increasing by 2000, reaching a peak in 2032 at about 36
Tcf/yr. Our prediction indicates that a plateau production at
the same peak level will extend from 2030 to 2035. With the
exception of FSU, all eastern European countries passed their
peak of production in the 1980’s. The increased gas
production is expected to come mainly from FSU and mostly
from western Siberia. The FSU low depletion rate of gas
(0.9%/yr) surpassed eastern Europe’s high depletion rate,
which averages approximately 5%/yr. The estimated ultimate
recovery of this region is 3411 Tcf, and about 81% of this
amount (2776 Tcf) remained to be produced as of 1997 year-
end. By 2050, around 72% of the ultimate recovery is
predicted to be produced, and gas production is predicted to be
30.6 Tcf/yr, about the same level as it was in 1990.
Middle East
This region includes production from Bahrain, Iran, Iraq,
Kuwait, Oman, Qatar, Saudi Arabia, Syria, UAE, and others.
This region contains 34% of the world’s proved gas reserves.
The major gas-producing countries in this region are Saudi
Arabia and Iran followed by the UAE and Qatar. Political
events in the region and oil-related OPEC policies affected gas
production of the region. These events include Iran’s cutback
production of oil in 1979, the UN sanction on Libya, and the
UN sanction on Iraq following its invasion of Kuwait in 1990.
Fig. 8 shows the region’s actual and predicted production,
indicating how effective the multicyclic approach is for
accounting for such unpredictable events. Production is
predicted to increase at an average annual increase of 0.6
Tcf/yr until 2040, when it will peak at 29.3 Tcf/yr. Production
then will decline at a low rate of about 0.2 Tcf/yr. By 2050
production is predicted to be 27.2 Tcf/yr, most of which will
come from Iran, Saudi Arabia, Qatar, and the UAE.
The estimated ultimate recovery of the Middle East is 2508
Tcf, with future recoverable gas of 2433 Tcf remaining as of
1997 year-end. Our work indicates that about 43% of the
future recoverable gas of this region will be produced by 2050.
The 1997 production of this region was 3.3 Tcf/yr from which
Algeria produced about 74%. Algeria is expected to continue
to be the major producer of Africa until 2043, when Nigeria
and Libya production take over the role. By 2050, the
production share of Nigeria, Libya, and Algeria is predicted to
reach 41%, 29%, and 17%, respectively. The actual and
predicted production of this region is given in Fig. 9. The
figure indicates that production will peak in 2014 at 7.2
Tcf/yr, with an average annual increase of 0.24 Tcf/yr.
Production will then decline at an average annual 0.17 Tcf/yr
until 2043 and get flatter thereafter with less than 0.05 Tcf/yr
average annual decline. The model shows that the 1997
production level will be repeated in 2035.
The estimated ultimate recovery of this region is 476 Tcf,
and the future recoverable gas is 426 Tcf, Table 1. At 1997
production levels, remaining recoverable gas is expected to
last more than ten decades. This region model gives an annual
depletion rate of 0.78%/yr, close to that of the South and
Central America region.
Asia Pacific
Production from this region has continued to increase steadily
since 1971, except in 1982 and 1983 when Indonesia reduced
their production to 44% and 20%, respectively. This had an
impact despite the addition of Malaysia’s and Thailand’s
production as first reported in 1981 and 1982, respectively.
Fig. 10 shows the region’s actual and predicted production,
indicating the peak predicted production to occur in 2012 with
16.7 Tcf/yr. Production decline will then take place at about
0.4 Tcf/yr (2.4%/yr) average annual.
We estimated the ultimate recovery of gas for this region
to be about 800 Tcf, of which 86% remained to be produced
(i.e. 686 Tcf future recoverable gas) as of 1997 year-end. This
follows an annual depletion rate of 1.2%/yr.
We combined the country models according to their affiliated
organization or group. The following presents analysis of
natural gas production and outlook of gas supply for OPEC,
OECD, IEA, and EU organizations. Fig. 11 displays the
results of each organization or group. Table 2 provides a
summary of the results.
OPEC and non-OPEC
The OPEC countries hold approximately 43% (2175 Tcf) of
world’s proved reserves of natural gas as of January 1998. The
countries of Iran, Qatar, UAE, and Saudi Arabia contribute
69% of OPEC gas proved reserves, and about 30% worldwide.
Although gas production from OPEC countries account for
only 13% of 1997 world produced gas, its production has been
increasing steadily since the 1970’s. Gas production increased
from 2 Tcf/yr in 1971 to 10.5 Tcf/yr in 1997, an increase of
81%. Exceptions to continual production increase occurred in
1974 and in 1979-1980, when gas production decreased as
OPEC cut back production of crude oil in 1973 and Iran
experienced its revolution in 1979.
Fig. 12 shows actual and predicted gas production of
OPEC and non-OPEC countries. This figure indicates that gas
production from OPEC countries will peak in 2038 at 34.9
Tcf/yr. Most production will come from Iran, Saudi Arabia,
Qatar, and the UAE through the forecast period. On the other
hand, conventional gas production from non-OPEC countries
is expected to peak by 2004 at 78.8 Tcf/yr. Production then
will decrease at an average decline of 1.1%/yr of the peak to
the year 2050.
The future recoverable gas of OPEC is estimated to be
3055 Tcf as of 1997 year-end, with an annual depletion rate of
less than 0.5%/yr. These future reserves accounts for about
39% of the world’s future recoverable gas.
OECD and non-OECD
Fig. 13 shows the actual and predicted gas productions of the
Organization for Economic Cooperation and Development
(OECD) and non-OECD. The model indicates that the OECD
conventional gas production will peak in 2001 at 42.2 Tcf/yr.
Most production of this organization is coming from the North
American countries: the U.S. and Canada. The annual gas
depletion rate of OECD is about 3%/yr. The ultimate
recoverable gas is 2564 Tcf with 1300 Tcf remaining
recoverable gas to be produced as of 1997 year-end.
The non-OECD production is tightly controlled by the
high production of FSU. The peak production is expected to
occur in 2031 at 77.4 Tcf/yr, with a relatively low gas
depletion rate of 0.65%/yr. The ultimate recoverable gas of
this group is 7480 Tcf, representing about 83.5% of the
world’s future recoverable gas. Most of the future gas
production from this group will come from FSU and the
Middle East gulf countries including Iran.
EU and IEA
The European Union (EU) production of gas accounted for
only 10% of the world’s produced gas in 1997, and the area
holds about 2% of the world’s proved reserves. The actual and
predicted gas production of the EU is shown in Fig. 14,
indicating that the gas production will peak as soon as 2001 at
10 Tcf/yr. Production will then decline to an insignificant
amount by 2050. Among organizations and groups considered
in this study, EU has the highest annual depletion rate of gas
with 4.4%/yr. The ultimate gas recovery obtained from the EU
model is 366 Tcf, with 193 Tcf future recoverable gas as of
1997 year-end.
The International Energy Agency (IEA) gas production
and the forecast model are shown in Fig. 15. The 1997
production will increase until 2001 when gas production
reaches a peak with 40 Tcf/yr. Production then will decline
steadily with an annual depletion rate of 3.4%/yr. The ultimate
recoverable gas obtained from the IEA model is 2310 Tcf. Of
this amount, about 1,100 Tcf future gas remained to be
produced as of 1997 year-end.
The World
World marketed gas production has increased from about 41
Tcf/yr in 1971 to about 82 Tcf/yr in 1997, an increase of 50%
over the 27-year period with production growth of about
4%/yr. Our world’s conventional natural gas prediction model
is shown in Fig. 16, indicating a very good match with the
fluctuating historical production data. The predicted world
production of gas in 1997 (83.8 Tcf/yr) is higher than the
actual production by 1.5 Tcf.
The model indicates that the world production of natural
gas will reach its peak between 2014 and 2017 at an
approximate flat rate of 99 Tcf/yr. After the peak is passed,
production will start to decline gradually and the curve will
get flatter.
The world’s proved reserves of natural gas increased
substantially from about 1,043 Tcf in 1967 to about 5,145 Tcf
in 1999, an average annual increase of 128 Tcf. About 72% of
the 1999 world’s proved reserves resides in the FSU and
Middle East region. Our results indicate that the world’s
ultimate recovery of conventional gas is 10,000 Tcf, of which
future recoverable gas (remaining to be produced) is about
7,900 Tcf as of 1997 year-end. The distributions of EUR and
FRG obtained from all country-specific models constituting
the world gas model are plotted in a semi-log plot as shown in
Fig. 17. The results of EUR and FRG appear to be log-
normally distributed with means of 190 Tcf and 149 Tcf,
Reserves/Production Ratio and
Annual Depletion Rate
The world’s R/P ratio of 96 years means that the world gas
reserves will last for 96 years if the 1997 rate of production is
constant in the future. The use of the R/P ratio as an indication
of future production is misleading and meaningless because
production rates probably cannot be constant over a long
period of time and then drop suddenly to zero when reserves
are depleted. If it is needed, an R/P curve as a function of time
(or as a function of production rate) can be constructed using
predicted production rate with a given EUR value as shown in
Fig. 18. As an example, at the year of 2030 the world’s
remaining gas reserves would last for about 50 years provided
the predicted rate of production in 2030 remained unchanged.
A better alternative is the annual depletion rate, which is
the annual production divided by the remaining reserves
expressed in percentage. It is a measure of how fast the
reserves are being depleted each year at that year’s rate of
production. The annual depletion rate of the world’s gas in
1997 is computed at 1%/yr. Fig. 18 shows the depletion rate of
the world’s gas using the predicted rate of production and the
obtained value of future recoverable gas. The world’s gas
depletion rate will be increasing throughout the forecast
period, reaching about 2.3%/yr by 2050.
We presented our analysis of the future of the world’s
conventional natural gas by region and organization/group.
Production data from several gas producing countries or
regions showed fluctuations. These data were affected by the
relationship between the gas industry and the oil industry,
economic burdens, and governmental policy implementations.
The multicyclic model was an effective approach for modeling
such production trends and developing forecasting models for
Our analysis indicates that most industrialized countries
(e.g. the U.S., Denmark, France, and the U.K.) are depleting
their gas resources much faster than are developed countries.
Fuel switching and gas dependence by industrial and
commercial sectors, and production decline of crude oil in
these countries are among the reasons for the high depletion
rate. The impact is that gas production of some regions is now
in decline or will peak soon. North American gas production is
predicted to have peaked in 1999 at a rate of about 29 Tcf/yr.
Western European gas production is expected to peak in 2002
at 12 Tcf/yr. However, the FSU and the major Middle East
Gulf countries (Iran, Saudi Arabia, Qatar, and UAE), which
hold 68.5% of world proved reserves of natural gas, will be
major sources of world gas supply with 4,880 Tcf of future
recoverable gas, representing about 62% of world future
recovery of conventional gas.
The results presented in this paper do not include
unconventional gas resulting from tight gas reservoirs, coal
bed methane, gas shales, and gas hydrates. These
unconventional resources will play an important role in the
addition of gas reserves to some countries such as the U.S. and
Canada. We recommend incorporating the analysis of these
resources with this study, but the lack of data availability
hinders that approach at this time.
a = constant, 1/t, 1/yr
EUR = estimated ultimate recovery, L3, Tcf
FRG = future recoverable gas, L3, Tcf
k = number of production cycles
n = number of observations
No = dimensionless cumulative factor
q(t) = production rate as a function of time, L3/t, Tcf/yr
qifl = production rate at inflection point, L3/t , Tcf/yr
qmax = maximum or peak production rate, L3/t , Tcf/yr
Q = cumulative production, L3, Tcf
Qmax = maximum cumulative production, L3, Tcf
Q = ultimate recovery of gas, L3, Tcf
t = time, calendar year
tifl = time corresponds to qifl, calendar year
to = arbitrary time, calendar year
tmax = time at peak production, calendar year
S.M. Al-Fattah would like to thank Saudi Aramco for
supporting his PhD study at Texas A&M University.
1. Energy Information Administration: “International Energy
Outlook 1998,” DOE/EIA-0484, Office of Integrated Analysis
and Forecasting, U.S. Dept. of Energy, Washington, DC (April
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Gas Production,” Advances in the Economics of Energy and
Resources, J.R. Moroney (ed.), J.A.I. Press, Greenwich,
Connecticut (1995) 9, 169.
3. Al-Fattah, S.M. and Startzman, R.A.: “Analysis of Worldwide
Natural Gas Production,” paper SPE 57463 presented at the 1999
SPE Eastern Regional Meeting, Charleston, WV, 20-22 October.
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Prac. (1956) 17.
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Academy of Science/Natl. Research Council (1962).
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States,” AAPG Bull. (11 November 1967) 51, 2207.
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Production of Oil and Gas,” Proc., U.S. Dept. of Commerce
Symposium, Washington, DC (June 1980) 16.
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Limit,” World Oil (October 1995) 77.
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Co. and Petroconsultants S.A., Brentwood, England (1997) 86.
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Supply and Demand,” JPT (December 1997) 1329.
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Scientific American (March 1998) 78.
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Patterns Using Hubbert-Style Curves,” Mathematical Geology
(August 1999) 11.
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PennWell Pub. Co., Tulsa, OK (1998).
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Database, PennWell Publishing Co., Tulsa, OK (1998).
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MacNaughton, Dallas, TX (1996).
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Growth,” AAPG Bulletin (March 1994) 78, 321.
SI Metric Conversion Factors
bbl x 1.589 873 E-01 = m3
ft3 x 2.831 685 E-02 = m3
Region 1997, 1997, 2050, Time Production, Proved 1/98, Future, Ultimate, R/P, Depletion,
Tcf/yr Tcf Tcf (year) Tcf/yr Tcf Tcf Tcf yr %/yr
N. America 27.7 1032 1792 1999 28.6 295 838 1871 30 3.30
E. Europe & FSU 25.0 635 2448 2032 36.2 2003 2776 3411 111 0.90
W. Europe 10.1 193 535 2002 12.0 170 367 560 36 2.75
Asia-Pacific 8.4 112 695 2012 16.7 321 686 798 81 1.23
Middle East 4.8 75 1116 2040 29.3 1726 2433 2508 >250 0.20
Africa 3.3 49 303 2014 7.2 349 426 476 128 0.78
S&C America 2.8 55 285 2018 4.7 222 364 419 131 0.76
Total World 82.1 2152 7175 2014 98.8 5086 7891 10043 96 1.04
Cumulative prod
Organization/Group 1997, 1997, 2050,
Proved 1/98,
Tcf/yr Tcf Tcf (year) Tcf/yr Tcf Tcf Tcf yr %/yr
OPEC 10.5 161 1617 2038 34.9 2175 3055 3216 >250 0.34
Non-OPEC 71.6 1991 5558 2004 78.8 2911 4836 6827 68 1.48
OECD 39.3 1264 2455 2001 42.2 499 1299 2564 33 3.02
OECD-Europe 10.5 216 568 2002 12.3 182 377 593 36 2.78
Non-OECD 42.8 888 4719 2031 77.4 4587 6592 7479 154 0.65
IEA 37.6 1212 2271 2001 40.4 421 1098 2310 29 3.43
EU 8.5 173 364 2001 10.0 118 193 366 23 4.39
Cumulative prod
1940 1950 1960 1970 1980 1990 2000
Time, year
Wellhead Price, (1992 $/MM Btu)
Gas to Oil Price Ratio, ($/Btu)/($/Btu)
Gas price
Oil price
Gas/Oil price ratio
Fig. 1-U.S. gas and oil wellhead inflation-adjusted prices and
gas/oil price ratio, 1949-1998 (all on equivalent Btu basis).
1910 1920 1930 1940 1950 1960 1970 1980 1990 2000
Time, year
Marketed Gas Production, Tcf/yr
Crude Oil Production, Billion bbl/yr
Natural gas
Crude oil
Fig. 2-U.S. natural gas and crude oil production (vertical scale on
equivalent Btu basis).
America S&C
America W. Europe E. Europe
& FSU Middle
East Africa Asia-
Trillion cubic feet
Cumulative gas 1997
Future recoverable
Ultimate recoverable
Fig. 3Distribution of world’s conventional gas by region:
cumulative produced, future recoverable, and ultimate recovery.
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 4North American region natural gas production model.
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 5South/Central American region natural gas production
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 6West European region natural gas production model.
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 7Eastern Europe/FSU region natural gas production model.
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 8Middle East region natural gas production model.
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 9Africa region natural gas production model.
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 10Asia Pacific region natural gas production model.
Europe Non-
Trillion cubic feet
Cumulative gas 1997
Future recoverable
Ultimate recoverable
Fig. 11Distribution of world’s conventional gas by
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
model non-OPEC
Fig. 12OPEC and non-OPEC natural gas production models.
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 13OECD, OECD-Europe, and non-OECD gas production
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 14European Union (EU) natural gas production model.
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Supply model
Fig. 15International Energy Agency (IEA) natural gas production
1970 1990 2010 2030 2050
Time, year
Gas Production, Tcf/yr
Fig. 16Predictions of natural gas production for different
organizations or groups and the world.
0.1 1 10 100 1000 10000
Trillion cubic feet
Cumulative Probability, %
Future Recoverable Gas
Ultimate Recoverable Gas
Fig. 17Semilog cumulative probability plots of FRG and EUR
from all country-specific models combined to yield the world
1970 1980 1990 2000 2010 2020 2030 2040 2050
Time, year
Future Recovery/Production Ratio, years
Annual Depletion Rate, %/yr
Fig. 18World historical and predicted annual depletion and R/P
ratio of conventional gas.
... In the previous related papers, forecasting of consumption of natural gas has been investigated by different forecasting techniques and tools. One of the first tools established for predicting of gas consumption is the Hubbert curve model (Al-Fattah and Startzman, 2000;Al-Jarri and Startzman, 1997;Cavallo, 2004;Cherif et al., 2013;Imam et al., 2004;Li and Zhang, 2014;Maggio and Cacciola, 2009;Reynolds and Kolodziej, 2009;Saraiva et al., 2014;Siemek et al., 2003;Valero and Valero, 2010) Since 1960s, different statistical models have been used and developed for forecasting natural gas consumption. Balestra and Nerlove (1966) used time series data and statistical techniques to estimate demand of natural gas. ...
... Other studies have examined the total (domestic and industrial) consumption of natural gas and other fuels in large geographic areas. For example, Siemek et al. [5] consolidated earlier studies by Hubbert [6] and by Al Fattah et al. [7], proposing a deterministic model based on the logistic growth curve to describe and forecast natural-gas consumption in Poland, taking into account the macroeconomic context and the economic cycles affecting the country. Stochastic logistic growth models have also been used in relation to the consumptions of various fuels, with special attention to that of electricity. ...
The principal objective of the present study is to examine the possibilities of using a Gompertz-type innovation diffusion process as a stochastic growth model of natural-gas consumption in Spain, and to compare our results with those obtained, on the one hand, by stochastic logistic innovation modelling and, on the other, by using a stochastic lognormal growth model based on a non-innovation diffusion process. Such a comparison is carried out taking into account the macroeconomic characteristics and natural-gas consumption patterns in Spain, both of which reflect the current expansive situation characterizing the Spanish economy. From the technical standpoint a contribution is also made to the theory of the stochastic Gompertz Innovation diffusion process (SGIDP), as applied to the case in question.
Natural gas is the primary source for electricity production in Turkey. However, Turkey does not have indigenous resources and imports more than 98.0% of the natural gas it consumes. In 2011, more than 20.0% of Turkey's annual trade deficit was due to imported natural gas, estimated at US$ 20.0 billion. Turkish government has very ambitious targets for the country's energy sector in the next decade according to the Vision 2023 agenda. Previously, we have estimated that Turkey's annual electricity demand would be 530,000 GWh at the year 2023. Considering current energy market dynamics it is almost evident that a substantial amount of this demand would be supplied from natural gas. However, meticulous analysis of the Vision 2023 goals clearly showed that the information about the natural gas sector is scarce. Most importantly there is no demand forecast for natural gas in the Vision 2023 agenda. Therefore, in this study the aim was to generate accurate forecasts for Turkey's natural gas demand between 2013 and 2030. For this purpose, two semi-empirical models based on econometrics, gross domestic product (GDP) at purchasing power parity (PPP) per capita, and demographics, population change, were developed. The logistic equation, which can be used for long term natural gas demand forecasting, and the linear equation, which can be used for medium term demand forecasting, fitted to the timeline series almost seamlessly. In addition, these two models provided reasonable fits according to the mean absolute percentage error, MAPE %, criteria. Turkey's natural gas demand at the year 2030 was calculated as 76.8 billion m(3) using the linear model and 83.8 billion m(3) based on the logistic model. Consequently, found to be in better agreement with the official Turkish petroleum pipeline corporation (BOTAS) forecast, 76.4 billion m(3), than results published in the literature.
China has become a net importer of natural gas as a result of rapidly increasing consumption in recent years. A production peak would exist since natural gas is an exhaustible resource. As conventional natural gas production peak approaches, the development of unconventional natural gas is attracting increasing attention. China׳s unconventional natural gas reserves are abundant, but exploration is still in its infancy stage. Thus, with the increasing quest for low-carbon development and China׳s natural gas price reform, studying the impacts of unconventional gas development on China׳s natural gas supply and price reform under different scenarios has practical significance. In this paper we predict China׳s natural gas production trends in different scenarios and forecast natural gas demand. This paper concludes that the exploitation of unconventional natural gas will greatly improve China׳s annual natural gas production, and delay the production peak year. This is important for China׳s natural gas supply security as it can decrease dependence on imported gas. Furthermore, as the cleanest fossil fuel, it will enable more time and space for renewable energy development given the many costs and controversies surrounding its development in China.
Publishing papers in the area of forecasting natural gas consumption has begun in the middle of last century and led to a tremendous surge in research activities in the past decade. This paper presents a state-of-the-art survey of forecasting natural gas consumption. Purpose of this paper is to provide analysis and synthesis of published research in this area from beginning to the end of 2010, insights on applied area, used data, models and tools to achieve usable results, in order to be helpful base for future researchers.
In this paper, a predictive model based on a variant of the multi-cyclic Hubbert approach is applied to forecast future trend in world fossil fuel production.Starting from historical data on oil (crude and NGL), natural gas, and coal production, and taking into consideration three possible scenarios for the global Ultimate (i.e. cumulative production plus remaining reserves plus undiscovered resources), this approach allowed us to determine when these important energy sources should peak and start to decline. In particular, considering the most likely scenarios, our estimated peak values were: 30 Gb/year in 2015 for oil, 132 Tcf/year in 2035 for natural gas, and 4.5 Gtoe/year in 2052 for coal. A plateau is likely to occur in the case of natural gas, if the global Ultimate is high.A comparison of the Multi-Hubbert Variant (MHV) approach used in this paper with both the Single-cycle Hubbert (SH) and the “original” Multi-cyclic Hubbert (MH) approach has also been done.
Conference Paper
Full-text available
Modern civilization as it is known to us heavily depends on hydrocarbon fluids and their byproducts. So far, the industrialized nations have completely presumed for granted an uninterruptable supply of cheap crude oil. Petroleum liquids are exhaustible resources; thus, a good forecasting scheme of oil supply will be crucial to all parties involved in the petroleum business such as oil companies, financial institutions, public policy planners and makers, and oil exporting and importing countries. Such a model will also help bring stability and security to the crude oil market. Over the years, accurate prediction of oil production was confronted by fluctuating ecological, economical, and political factors, which imposed many restrictions on its exploration, transportation, and supply and demand. The objective of this paper is to illustrate the advantages of the multi-cyclic Hubbert model. We will demonstrate the effectiveness of the proposed model for the cases where the production rate fluctuates with time. We will also illustrate the effects of new discoveries or additional reserves due to innovative technology on peak oil rate and time and show how the multi-cyclic model accommodates these changes. Furthermore, we will demonstrate the flexibility of the proposed model to history match any future fluctuation in the production data. Historical production data of 47 countries around the world are used to predict the peak oil. The production rates of the last four years (2006-2009) are used to validate the accuracy of the model.
This paper describes the possible scenario of the development of the gas sector in Poland. An adaptation of the Hubbert model is implemented to the Polish situation based upon the Starzman modification. The model presented describes hypothetical natural-gas demand, based on average trend of the economy development during recent decades; the model considers natural production/demand maxima of energy carriers. The prognosis is loaded with an error resulting from the use of average data related to yearly increases of the national gross product. The adapted model expresses good compatibility with the natural-gas demand for the period 1995-2000. However, the error of prognosis may reach 20%. The simple structure of the model enables the possibility of yearly updating, and eventual correction of the natural-gas demand. In cases of untypical changes of the economy growth rate (long stagnation, extreme long and accelerated development), the prognosis error may increase.
Full-text available
This paper was prepared for presentation at the 1999 SPE Eastern Regional Meeting held in Charleston, West Virginia, 20–22 October 1999.
In this study, we undertook the risky task of predicting the world's future supply of and demand for petroleum liquids [crude oil and natural gas liquids (NGL's)] to the Year 2050. On the basis of earlier work, we choose to forecast future supply using the Hubbert model, which has advantages of simplicity and availability of data. Although this approach has several known inadequacies, it has withstood the test of time in numerous cases, and we consider it a fairly reliable supply predictor. We also used the Hubbert model to forecast demand. We found no precedence for this use and currently regard its accuracy as speculative. Nevertheless, some signs indicate that it too may develop use over time as a reasonable predictor. Our study showed that world supply (and demand) for petroleum liquids is currently at a peak and will soon decline. We examined supply and demand by region. Some regions, such as the Middle East, will produce a surplus of crude throughout the forecast period. Other regions, most notably the Far East and North America, will remain importers. Still other regions, such as Africa, that are now exporting will soon become importers.
Because gas and oil are exhaustible resources, the discovery and production history of these fuels in any particular area must be characterized by a beginning, a period of increase, a period of decline, and ultimately, an end. In this sequence, the most significant dates are neither those of the beginning nor of the end, but that of the transition between the period of increase and the period of decline. The petroleum industry in the conterminous United States is by now sufficiently advanced in its evolution that several lines of evidence are consistent in their indication of the approximate degree of that advancement. One suite of diagnostic data comprises the cumulative production, cumulative proved discoveries, and proved reserves. For more than 40 years the curve of cumulative production of crude oil has closely followed that of cumulative discoveries, with a time lag of about 10-12 years. The peak in the rate of proved discovery occurred about 1956. The peak in proved reserves, which should occur about midway between the peaks in the rates of discovery and of production, actually occurred at about 1961. The peak in production rate should occur in the late 1960's. Another suite of data is provided by successive studies made by the Petroleum Administration for War and by the National Petroleum Council, in which the oil discovered has been allocated to the years of discovery of the producing fields. These, when corrected to an estimated ultimate growth, indicate that by the end of 1966 about 136 billion bbl of producible crude oil had been discovered. The rate of discovery per year, averaged for successive 5-year periods, reached a peak of 3.57 × 109 bbl/yr during the period 1935-1940, and has declined subsequently to a present rate of less than 2 × 109 bbl/yr. Another method of analysis is that proposed by A. D. Zapp (1961, 1962), of relating discoveries per foot of exploratory drilling to cumulative footage. By the end of 1966 it is here estimated that about 1.52 × 109 ft of exploratory drilling had been done. The discoveries per foot, averaged for each successive 108 ft, reached a peak of 276 bbl/ft during the third 108-ft interval, which included the discovery of the East Texas field. Subsequently, the rate of discovery per foot has declined exponentially to a present average rate of about 35 bbl/ft. These several lines of evidence are consistent indicating that: 1. The peak in time-rate of crude-oil production will probably occur near the end of the 1960 decade, and the ultimate amount of oil production will probably be less than 200 billion bbl. 2. The peak in the rate of natural-gas production will probably occur in the late 1970's, with ultimate production between 900 and 1,200 trillion cu ft. 3. The ultimate cumulative crude-oil production from fields already discovered in the conterminous United States probably represents between 68 and 85 per cent of the total crude oil ultimately to be discovered. 4. The evidence available offers scant hope that recently postulated future discovery rates in excess of 80 bbl/ft, with attendant discoveries of additional hundreds of billions of barrels of crude oil, during the next 2 or more billion ft of exploratory drilling, will ever, in fact, be realized.
Eight papers describe innovations in economic growth analysis that account for materials and energy inputs. In contrast, earlier analyses focused on capital and labor. The authors disagree on the significance of conservation and renewable resources, but there is broad agreement on the role of coal in meeting world energy needs for several decades. Their analyses consider the effect of prices on resource choices and substitution, the resource and environmental implications of facility siting and resource development, a variety of legal complications, combinations of energy models, measurements of technological change in manufacturing, and tests of economic rents in industry. A separate abstract was prepared for each of the eight papers selected for the Energy Data Base. An introductory chapter by the editor summarizes major themes in the papers and identifies areas of agreement and disagreement.
Growth in estimates of recovery in discovered fields is an important source of annual additions to United States proven reserves. This paper examines historical field growth and presents estimates of future additions to proved reserves from fields discovered before 1992. Field-level data permitted the sample to be partitioned on the basis of recent field growth patterns into outlier and common field set, and analyzed separately. The outlier field set accounted for less than 15% of resources, yet grew proportionately six times as much as the common fields. Because the outlier field set contained large old heavy-oil fields and old low-permeability gas fields, its future growth is expected to be particularly sensitive to prices. A lower bound of a range of estimates of future growth was calculated by applying monotone growth functions computed from the common field set to all fields. Higher growth estimates were obtained by extrapolating growth of the common field set and assuming the outlier fields would maintain the same share of total growth that occurred from 1978 through 1991. By 2020, the two estimates for additions to reserves from pre-1992 fields are 23 and 32 billion bbl of oil in oil fields and 142 and 195 tcf of gas in gas fields. 20 refs., 8 figs., 3 tabs.