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Sustainable Society:  A society that balances the environment, other life forms, and human interactions over an indefinite time period.

 

 

 

 

 


 

Will the Natural Gas Supply Meet the
Demand in North America?

Jean Laherrère*
      
November 2001

Part 2 of 2

 
    Creaming curve

Figure 38: US gas discovery: creaming curve.
Figure 39: US gas fields cumulative discovery modelled with logistic curve.
    Forecast
Figure 40: MMS forecast for gas production 2001 to 2005.
Figure 41: GRI forecast for the GOM.
Figure 42: US deepwater GOM: natural gas production from known and future discoveries up to 2010 from Nehring.
Figure 43: Nehring forecast for the GOM.
Figure 44: GOM (from MMS): annual production and annual discovery shifted by 25 years.
Figure 45: GOM deepwater modelling cumulative discovery and cumulative production from Infields data.
    US all

Figure 46: US gas production and " mean " discovery shifted by 20 years.
Figure 47: US gas production modelled with ultimates 1500 Tcf and 1900 Tcf.
Figure 48: US gas production with DOE/EIA and GRI forecasts.
Figure 49: USDOE dry gas forecast up to 2020.
Table: AEO 2001,  from 1999 to 2020
    US unconventional gas
Figure 50: US gas production 1990-2020 from EIO 2000.
Figure 51: US CBM production.
Figure 52: US unconventional gas proved reserves.
Figure 53: US unconventional gas undeveloped resources.
Figure 54: US unconventional gas production 1998-2020 from USDOE EIO 2000.
    Canada
Figure 55: Canada remaining gas reserves from political sources (current proved) and technical sources (proven + probable backdated).
Figure 56: Alberta gas pool cumulative discovery and production.
Figure 57: Western Canadian sedimentary basin: creaming curve up to 1997.
Figure 58: Canada gas potential from CGPC.
Figure 59: WCSB gas field size: parabolic fractal display.
Table: Comparing old and new projections
Figure 60: Canada gas production with NEB forecasts and modelling.
Figure 61: Canada gas production and discovery shifted by 20 years.
    Mexico
Figure 62: Mexico gas remaining reserves from technical sources (current proved) and technical data (backdated proven + probable).
Figure 63: Mexico gas discovery: creaming curve.
Figure 64: Mexico gas fields: parabolic fractal distribution and ultimate.
Figure 65: Mexico gas production and discovery shifted by 20 years.
Table: Conventional gas estimates, USGS 2000 vs. 1994.
Figure 66: US + Canada+ Mexico gas mean discovery: creaming curve.
Figure 67: US + Canada + Mexico gas production and shifted mean discovery by 20 years.
    East Greenland
    US + Canada + Mexico
Conclusion on the local gas supply of North America
Potential of importing gas to North America from the rest of the world

    World
Figure 68: World remaining gas reserves from political sources and technical sources.
Figure 69: World gas annual discovery and annual production.
Figure 70: World conventional cumulative gas production and discovery.
Figure 71: World liquids and gas production 1925-2125.
Figure 72: IPCC 2000 gas consumption scenarios compared to forecast from technical data.
    Global conclusion
References


Creaming curve

US all

The creaming curve (concept from Shell) represents the cumulative discoveries versus the cumulative number of new field wildcats. It displays the classic law of diminishing returns in mineral exploration. Usually it displays one or several hyperbolas.

Up to 1998 1150 Tcf of "mean" discoveries has been found with 320 000 NFW. The modelling shows that doubling the present number of NFW will increase only the total discoveries up to 1400 Tcf.

Figure 38: US gas discovery: creaming curve.

The cumulative discoveries versus time is disturbed by the stops and gos of exploration, for an active exploration it displays a logistic curve trending toward an asymptote of 1400 Tcf.

Figure 39: US gas fields cumulative discovery modelled with logistic curve.


In this graph, the number gasfields/100 means that the number of fields is divided by 100: the number trends towards 42,000.


Forecast

GOM

MMS forecasts for 2000 to 2005 that gas production in shallow water will continue in average to decline and in deepwater to start to decline in 2003.

Figure 40: MMS forecast for gas production 2001 to 2005.


A 2000 report from Gas Research Institute (GRI, now GTI = Gas Technology Institute) "The long term trends in US gas supply and prices" (Cocheter 2001) illustrates with the following graph that Gulf of Mexico gas production shows a continuous decline from the shelf since its peak of 1970, and the rise of the deepwater since 1990. GRI adds in its forecast the arrival of a sharply rising ultra-deep production. The GRI deepwater gas production peaking around 2005 is in line with Nehring’s assessment, but not this new concept of ultra-deep gas production, which is contrary to the finding that the deeper the water, the less gas there is.

Figure 41: GRI forecast for the GOM.


Cocheter gives the breakdown by areas for 2015: figure 7

Production Tcf 1998 2015
Lower 48 19 27.8

West

 0.3 0.4

Rocky Mountains

2.9 4.9

Permian

4.3 4.8

S.Texas/Louisiana

5.1 5.7

GOM

4.9 8.1

East

1.5 4
Alaska 0.5 0.7
Canada 5.6 7.7

BC

0.6 1.1

Alta Sask Manitoba

5 6

Eastern Canada

0 0.6


The USDOE/EIA AEO 2001 and GRI forecasts for US gas production show a drastic break from the trend of the past 10 years production.

Nehring’s forecast (Jan. 2001) for deepwater GOM gas production from his estimated resource of 56 Tcf (current discoveries = 27 Tcf) is a peak in 2008 at 3 Tcf/a. Unfortunately Nehring did not define what he calls deepwater. For the MMS deepwater is more than 1000 ft but from the next graph it seems that Nehring’s definition is less than 1000 ft, it is close to EIA values which take deepwater at 200 m. MMS federal agency is obliged (?) to use the SI unit and the deepwater royalties are defined with water depth in meter and the leases are classified as: 0-200 m, 201-400 m, 401-800 m, 801-1000 m and >1000 m. For some, with the progress of the drilling, deepwater starts at 500 m or even 1000 m.

Nehring describes the difference between the continental shelf where about 65% of the oil and gas reserves are gas, and the deepwater where gas represents only 30% of the oil and gas reserves. There is less gas in the deepwater because of the low thermal gradient, which creates low temperatures in the gas generation zone. For the GOM deepwater Nehring sees a peak in 2008 at 3 Tcf/a.

Figure 42: US deepwater GOM: natural gas production from known
and future discoveries up to 2010 from Nehring.


Nehring (March 2001) in "Gulf of Mexico Rising Star; then over the Hill" said that the anticipated US supply in 2010 would be short by 3-4 Tcf. For the global GOM, he sees a peak (average high and low) around 2007 about 6.5 Tcf/a.

Figure 43: Nehring forecast for the GOM.


The MMS " mean " discovery is plotted on graph 44 as annual discovery and shifted in order to get the best fit with annual production. The fit is best for 25 years and this shift allows forecasting the future production using the last 25 years of discovery. The fit looks good despite the unreliable data (not so much for old data) and it is obvious that the annual gas production has been steady (new data more unreliable) for the last 20 years and production will soon decline sharply.

Figure 44: GOM (from MMS): annual production and annual discovery shifted by 25 years.


For the GOM deepwater (>300 m), the most complete file from Infields is used to model with the same logistic curve the cumulative discovery and cumulative production. The model is not very good for discovery because of the ups and downs of deepwater exploration. An ultimate of 30 Tcf is used to model it as deepwater holds only one third of gas compared to oil when it is the contrary on the shelf where gas represents two thirds compared with oil. This change is well explained by Nehring (Jan. 2001) because the low thermal gradient below deepwater.

Figure 45: GOM deepwater modelling cumulative discovery and cumulative production from Infields data.


The cumulative number of fields is divided by 10.


From this graph discovery seems to have passed the midpoint and gas production will do so around 2005.


US all

The correlation of annual production with shifted annual " mean " discovery shows a fair fit for a shift of 20 years. The problem is that it is not known if the reserves are estimated as raw or dry gas.

Figure 46: US gas production and " mean " discovery shifted by 20 years.


This shift of 20 years allows forecasting that for the next 20 years US gas production will decline.

Using ultimates is another way. The creaming curve of figure 36 suggests an ultimate less than 1500 Tcf for conventional gas. As the unconventional gas ultimate is less than 400 Tcf (see below) the maximum ultimate is less than 2000 Tcf.

The modelling with ultimates shows either a decline around 2000 for U = 1500 Tcf or 2000 - 2100 = 570 Tcf and a coming peak in 2010 for U = 1900 Tcf or 2000 - 2100 = 970 Tcf.

Figure 47: US gas production modelled with ultimates 1500 Tcf and 1900 Tcf.


Our forecast is far from the one by the official agencies.

Figure 48: US gas production with DOE/EIA and GRI forecasts.


The detail of the gas production is given.

Figure 49: USDOE dry gas forecast up to 2020.


The bulk of the 10 Tcf increase in US production from 1999 to 2020 is from the lower 48 onshore non-associated (8 .8 Tcf) and half of it from unconventional.

AEO 2001,  from 1999 to 2020

Lower 48 wellhead price

+1 $1999/kcf

Dry production

Tcf
U.S. total +10.4
Lower 48 onshore +8.4
Associated-Dissolved -0.4
Non-Associated 8.8
Conventional 4.7
Unconventional 4.1
Lower 48 offshore +1.8
Associated-Dissolved 0.1
Non-Associated 1.7
Alaska +0.1


US unconventional gas

US unconventional gas production comes presently mainly from tight sands and one fourth from coalbed methane (CBM), but the increase from 1999 to 2020 is slightly less than in EIO 2001.

Figure 50: US gas production 1990-2020 from EIO 2000.


The forecast on unconventional gas production is found at EIO 2000:
< http://www.eia.doe.gov/oiaf/analysispaper/images/uncon_fig1.jpg >.


The amount of proved unconventional gas is about 50 Tcf with two thirds in tight sands and the rest mostly coalbed methane (CBM). CBM has been in the beginning mainly from the San Juan basin (New Mexico) which is now peaking, and the rising basin is in Colorado.

Figure 51: US CBM production.


The proved reserves of unconventional gas are about 34 Tcf in tight sands, 13 Tcf in CBM and 4 Tcf others.

Figure 52: US unconventional gas proved reserves.


The amount of unconventional gas in undeveloped resources is about 370 Tcf with 70% in tight sands and the location is shown in the next graph.

Figure 53: US unconventional gas undeveloped resources.


The production of unconventional gas is now at 4.5 Tcf/a with USDOE EIO 2000 forecast in 2020 between 4.5 and 7 Tcf/a depending on the degree of technology. It is far from the 4.7 Tcf of increase from 1998 to 2020 from EIO 2001. These reports lack continuity and homogeneity.

Figure 54: US unconventional gas production 1998-2020 from USDOE EIO 2000.


Unconventional gas will not be the alternative to the declining conventional present fields.

Future discoveries will only compensate for the decline of the present fields.

In conclusion, the US gas production is forecast by official agencies to increase by around 10 Tcf in the next 20 years but it is more to satisfy the forecasted demand, which is now with the present recession, very questionable. There are many plans for new electric plants requiring a large amount of new gas, but many projects will fail and the demand will be much less than actually forecasted.

More likely, US gas production will stay stable for a while before declining.

Any growth of the US demand has to be filled from imports from Canada or by LNG.


Canada

The Canadian remaining gas reserves are reported (current proved) to be around 60 Tcf while they were close to 100 Tcf 8 years ago, with a drastic drop in 1993. This drop seems to be mainly a reporting problem as the technical reserves ("mean" backdated) shows a peak around 120 Tcf in 1986 declining slowly to 90 Tcf in 1997.

Figure 55: Canada remaining gas reserves from political sources (current proved)
and technical sources (proven + probable backdated).


The historical pattern of gas pools in Alberta from 1900 to 2000 shows a drastic increase in gas cumulative discovery starting in 1950 (Leduc reefs discovery), a slow down during the 80s, but an increase in the 90s.

Figure 56: Alberta gas pool cumulative discovery and production.


The creaming curve for the Western Canadian sedimentary Basin displays two hyperbolas, one since 1904 and a second one in 1990 (I do not see any clear reason!). Up to 1997, about 160 Tcf has been found with about 90 000 exploratory wells. But the hyperbolic model shows that only less than 30 Tcf will be added when drilling another 90 000 additional exploratory wells, and only 40 Tcf with 200 000 additional wells, far from the 88 Tcf potential for undiscovered from 200 000 new wells from the Canadian Gas Potential Committee (CGPC), needing another hyperbola. It is difficult to foresee the drilling of 200 000 new wells in the coming 30-40 years when it took 100 years to drill 90 000 exploratory wells in the past.

Figure 57: Western Canadian sedimentary basin: creaming curve up to 1997.


Cocheter for GRI gives the breakdown of their production forecast for US and Canada for 2015:

GRI 2000 fig. 7

Dry Production (Tcf)

1998 2015
Lower 48 19 27.8
Alaska 0.5 0.7
Canada 5.6 7.7

BC

0.6 1.1

Alta Sask Manitoba

5 6

Eastern Canada

0 0.6

GRI hopes that Canada gas production will grow by 2.1 Tcf from 1998 to 2015. The 1999 NEB (National Energy Board) was more optimistic with its scenario case 1 producing 9 Tcf in 2015 (3 Tcf increase) rising to 10 in 2025 and the other scenario case 2 peaks at 8 Tcf in 2015 (2 Tcf increase) and down to 7.5 Tcf in 2025.

But drastic changes have occurred after the California gas shortage.

The Canadian Gas Potential Committee (CGPC) has released their new report on Sept 11, 2001. It is a drastic change from their previous report in 1999, cutting their estimate by about half. It seems to be a reaction towards the demand from the US for Canada to fill their gas need. Canada does not want to be obliged to produce too quickly their gas supply to satisfy the US hunger for gas. (See below on the NAFTA Act).

< http://www.canadiangaspotential.com/2001report/mediarelease.html >.

Figure 58: Canada gas potential from CGPC.


Canadian Gas Potential Committee wrote:

As of end 1998 there remained 233 Tcf of nominal marketable conventional gas resources, but without economic consideration.

The Western Canada Sedimentary Basin held an estimated 54 trillion cubic feet of gas reserves plus 88 trillion cubic feet of undiscovered nominal marketable gas, a total of 142 trillion cubic feet. The Western Canada resource represents 61 percent of the remaining marketable gas in Canada.

The Committee estimated that the 150 largest undiscovered pools are high-impact exploration targets that range in size from 40 billion to 1 trillion cubic feet. This attractive group of prospects contains about one quarter of the marketable gas potential in Western Canada. Another 25 per cent of the potential is expected in 3,000 pools that range in size from 2.5 billion to 40 billion cubic feet. An additional 40 percent of the nominal marketable gas is expected from 65,000 smaller pools, the study said.

At current rates of discovery in Western Canada, as many as 200,000 exploration wells, twice as many as have already been drilled, may be required to tap the undiscovered conventional gas potential, the Committee said.

The near frontiers of Canada, namely offshore Nova Scotia, the Mackenzie Corridor and the Mackenzie Delta, hold an estimated 35 trillion cubic feet of discovered and undiscovered nominal marketable gas. This is about 15 percent of Canada’s total marketable gas.

Non-conventional gas sources, such as coalbed methane, may provide important gas supplies, but will require extensive research into production methodologies. The successful conclusion of active pilot production studies is critical before a reserve potential can be estimated.

CGPC uses a forecasting method called Petromines where they introduce the undiscovered fields in the holes of their distribution size-rank distribution. Theoretically it is justified when the accuracy of the discovered size is good, but it is not the case.

We prefer to combine the parabolic fractal with creaming curve (figure 57) to forecast undiscovered. CGPC forecasts 150 pools yet to discover over 40 Gcf in the WCSB. Our forecast is about less than this number.

Figure 59: WCSB gas field size: parabolic fractal display.


The comparison between the 1999 study (NEB with two estimates) and the new estimate CGPC is striking.

(Tcf)

NEB 1999 ultimate 1 NEB 1999 ultimate 2 CGPC 2001
WCSB Conventional 335 265 249
WCSB Unconventional 75 75 0
Other Conventional 20 20 32
Frontier 303 303 61
    Total Canada 733 662 342


CPGC is pessimistic on the frontier areas and on unconventional gas.

But the USGS 2000 report, which is very optimistic, adding for the world during the next 30 years 8536 Tcf of conventional gas (4976 undiscovered and 3560 reserve growth), is very pessimistic on Canada, giving less than 25 Tcf of undiscovered. USGS did not give for Canada any reserve growth (which should be on the same ratio as the US), as Canada uses also proved reserves, when the rest of the world uses proven + probable. Using the US ratio of reserve growth over known discovery, Canada could have a reserve growth of 60 Tcf, as US has 355 Tcf of reserve growth for 854 Tcf produced as of 1996 and 172 Tcf remaining, when Canada has produced 67 Tcf produced as of 1996 with 118 Tcf remaining proved.

But USGS forecasts 81 Tcf undiscovered in East Greenland!

The modelling of future production with the different ultimates is shown on next graph.

Figure 60: Canada gas production with NEB forecasts and modelling.


In fact the NEB case 1 peaking at 10 Tcf/a in 2025 corresponds to an ultimate of 670 Tcf and not 733 Tcf. Case 2 peaking at 8 Tcf/a in 2017 corresponds to an ultimate of 500 Tcf and not 662 Tcf. The new ultimate of 340 Tcf corresponds to a peak at 7.3 Tcf/a in 2007 and a peak at 6.2 Tcf/a in 2003 corresponds to an ultimate of 280 Tcf.

The comparison of annual production and shifted mean discovery gives a fair fit for a shift of 20 years. This shift allows guessing that the present production will peak soon and decline sharply.

Figure 61: Canada gas production and discovery shifted by 20 years.


Stark 2001 in the IHS mid 2001 Review is pessimistic on the gas production because of the fast decline in productivity. He wrote:

Similarly, deterioration in Alberta gas well productivity is evident in Figure 6 by significant increases in decline rates and decrease in peak production volume between 1990 and 1999. Correspondingly, the USGS in its World Petroleum Assessment 2000 dropped its estimate of Western Canada gas resources to 19 Tcf. This compares to an estimate of about 170 Tcf by a Canadian source.

In conclusion the Canadian gas production is likely to peak soon and will not fulfill the forecasted demand from the US. Further more Nikiforuk (2001) in "The next gas crisis" is pessimistic about the supply and mentions that "the oil sands, the source of Canada’s future oil supply, by 2020, will be hogging nearly 25% of Alberta’s gas production in order to fire the boilers to heat the water that melts the tarry sands into usable oil."


Mexico

Mexico was for a long time in dispute with the USGS on their reporting of reserves, these being over-estimated in order to have good loans from the IMF and World Bank. The remaining gas reserves from political sources dropped in the last few years from 65 Tcf down to 30 Tcf (after signing the NAFTA Agreement). The technical data (mean backdated) shows a decline from a peak of 45 Tcf in 1083 down to 30 Tcf in 2000.

Figure 62: Mexico gas remaining reserves from technical sources (current proved) and technical data (backdated proven + probable).


The cumulative discovery versus cumulative number of New Field Wildcats displays two cycle hyperbolas (second cycle starting in 1975) trending towards an ultimate of 100 Tcf when more than doubling the number of wildcats.

Figure 63: Mexico gas discovery: creaming curve.


The display in fractal format (size-rank, log-log) with the distribution for each decade shows that in 1980 most of the largest gas fields (>1 Tcf) were found and that for the last 20 years most of the discoveries have been fields less than 1 Tcf. The parabola extrapolating the largest fields allows estimating the ultimate around 100 Tcf as per the creaming curve.

Figure 64: Mexico gas fields: parabolic fractal distribution and ultimate.


The correlation of the annual gas production with the shifted gas discovery is fair for a shift of 20 years as shown in the next graph. It looks again that gas production will peak soon and will decline.

Figure 65: Mexico gas production and discovery shifted by 20 years.


As our estimate of ultimate is around 100 Tcf and that the cumulative production up to 2000 is around 50 Tcf it is the mid-point and close to peak.

All the previous graphs for Mexico were for conventional gas, but there is no great potential for unconventional gas.

It is assumed by almost everybody that Mexico is unable to increase its production and will be obliged to import more gas to fill its growing demand.
 

East Greenland

As Greenland belongs to North America, it is necessary to present this country.

There are some gas discoveries in the Labrador Sea in Canadian waters, but none in the West Greenland. Because good source-rocks outcrop in East Greenland and there is some comparison with the potential of North Sea the USGS in their 2000 report on undiscovered estimates that there is 47 Gb of oil and 81 Tcf of gas. We believe (Laherrère 2000 on USGS) that this estimate is very unlikely first to occur and second to be developed, given the obstacles to bring gas to consumers from this remote area, covered with ice during 10 months each year.

It is better to forget Greenland in the North America gas supply.
 

US + Canada + Mexico

Using the dry production as the reference data is misleading as the balance of injection and withdrawal from the storage is not taken into account. It is unknown where the gas is repressured (field or storage). Raw (gross) production should be taken as the base, but it is not always available. USDOE recognises that they do not have a homogeneous database of raw and dry production for North America (Andy Dikes personal communication). As for reserves, it is unknown if they are estimated as dry or gross future production!

Nevertheless, it is interesting to obtain global graphs for the three countries.

In 1994 USGS estimated that the three countries have an ultimate for conventional gas of 2.1 Pcf. In 2000 USGS wanted to distinguish reserve growth (it was included in the 1994 study) as an important part for the US that they wanted to extrapolate to the rest of the world globally without giving the detail by country. The comparison is impossible, but it is obvious that US gas potential was greatly increased, and Canada and Mexico greatly decreased.
 

Conventional gas

USGS 2000

USGS 1994

 

disc + undisc

reserve growth 

disc + undisc

US

1553

355

1438

Canada

210

?

609

Mexico

118

?

247

North America

1881

?

2121


It is obvious that poor reporting on known reserves, and production (raw or dry), leads to a poor estimate of the ultimate discovery.

From the poor data by fields which has been corrected (with a very poor reserve growth model) to obtain the mean value for reserves, the creaming curve displays two hyperbolic cycles, the second starting in 1967. Up to 1997 1400 Tcf has been discovered with about 400 000 new field wildcats. The potential from drilling another 400 000 wildcats is less than 300 additional Tcf.

Figure 66: US + Canada+ Mexico gas mean discovery: creaming curve.


The correlation of the annual production (raw or dry) with the shifted discovery is fairly good for a shift of 20 years. This shift allows extrapolating future production towards a very soon peak and a fairly steep decline for the present decade.

Figure 67: US + Canada + Mexico gas production and shifted mean discovery by 20 years.


Conclusion on the local gas supply of North America

If official reports from governmental agencies are optimistic on the gas supply to fill the demand, it is obvious that the demand is based on very optimistic assumptions on both the price and the volume.

But technicians have a more pessimistic view on the supply estimate, such as Nehring or IHSE.

The IHSE mid-2001 report by Stark (2001) writes:

EIA believes that supplies will be adequate to cover predicted 4.6% (1.03 Tcf) growth in demand that would accompany an economic rebound in 2002. Recent extrapolations from IHSE databases indicate that even current levels of Canadian and US gas directed drilling could be pressed to cover a 1.03 Tcf increase. If so, US gas supply and demand margins would narrow and increase the likelihood for higher prices by the end of 2002.

But it seems that the gas future demand is based on optimistic growth based on cheap price (2$/Mcf in 2020) and large resources of conventional and unconventional gas.

If the local future supply declines as technical data shows, the price will go up and the demand will immediately decrease as it did this summer after the peak on gas price of the past winter (this decrease of demand was not forecasted by any economist). Much has been written on the blackouts of California due to capping the retail electric power price under so-called industry deregulation. But most economists thought that this price cap was no problem as they have only in mind a decrease in price (GRI 2000 forecasted 1998 $1.94/Mbtu in 2015!). Increase in price is politically (as well as economically) incorrect! We are living in a culture of growth, needing lower prices!

The increased need for energy in North America is forecasted to come mainly from gas, mainly for electricity. But there are other alternatives than gas. First coal and in figure 8 showing the US fossil fuels production it is clear that coal production is rising in 2000 to a level never reached. Coal projects for electric plants were slow because of the Kyoto agreement which is now rejected by the US. Secondly there are nuclear plants and the rejection of nuclear by the US consumers seems to be less after the blackouts in California. Nuclear is safer (less deaths) than the gas consumption (numerous blow outs) outside the waste problem which can be solved.

We feel that the gas demand will be less, and the gas supply will be able to satisfy it from the local production and from increased LNG from the rest of the world. The gas potential outside North Americas is studied in the following chapter.


Potential of importing gas to North America from the rest of the world

World

The reporting of conventional gas reserves shows a rising trend from political sources and a levelling from technical sources at around 6 000 Tcf (6 Pcf) since 1980.

Figure 68: World remaining gas reserves from political sources and technical sources.


The correlation between annual conventional gas discovery and production is not very good. We plotted also the production curve by shifting it backward by 40 years to fit with the discovery curve. The fit is fair.

Up to now, 9 Pcf has been discovered and only 2.5 Pcf has been produced.

There are many stranded gas fields waiting to be developed, because the low price of gas and high cost of the transport. But the situation is improving, in Nigeria gas has been flared for decades but now LNG plants have been built.

Figure 69: World gas annual discovery and annual production.


It is better to compare cumulative production and discovery and to model them with the same logistic curve. The best fit for a logistic curve occurs with a shift of 40 years.

The fit of the logistic with the discovery curve is not too good during the 70s as a very large volume of gas have been discovered in the two most prolific places for gas: Western Siberia and Middle East. In 1971 the world’s largest gas field was discovered in Qatar as North Field with its extension in Iran being South Pars. This field is at least three times bigger than the second largest gas field being Urengoi in Western Siberia. But Urengoi is declining since 1987 and has produced now about 50% of its ultimate. North Field is just beginning to be developed. But large gas export developments need political stability and the Middle East is barrels of powder!

Figure 70: World conventional cumulative gas production and discovery.


We have modelled with a logistic curve assuming that the ultimate is 10 Pcf. This ultimate is the result of 4 large reports written with three other retired geologists during 8 years, dealing with more than 80% of the world’s individual fields and the main Petroleum Systems of the world. The fit with past production is good and forecasts that the peak (mid-point at 5 Pcf) will be reached around 2015.

In front of the coming peak for oil (in fact the second as world’s oil consumption has peaked already in 1979 and took 15 years to reach back this level), there are many articles on the potential of gas-to-liquids techniques (GTL) as an alternative for oil with gas peaking well after oil. If some gas is converted into oil, there will be less gas for electric plants. GTL is still on the pilot stage (Shell Bintulu in Malaysia) as economics were not to good up to now. GTL looks good when the price of oil is high and when the value of the gas is very little (it could be negative as in Nigeria when flared (penalties). If gas prices goes up, the economics of GTL will suffer. It is likely that GTL will be a useful addition to the declining oil but will not change much the decline of liquids.

But consumption curves must include every component, as unconventional oil and gas and even refinery gains. Our ultimate for liquids is 2.8 Tb and for gas 12.5 Pcf (Perrodon et al 1998). The modelling of future production forecasts a peak for liquids before 2010 and for gas around 2030 about 23 Gboe/a or 140 Tcf/a.

Figure 71: World liquids and gas production 1925-2125.


It is obvious that the world has enough gas reserves for the next 20 years to help North America to solve their need for gas before finding alternatives to their declining gas production. Import of LNG from outside North America is the easiest and quickest answer to their local gas shortage.

It is amazing to find that the IPCC 2000 scenarios are based on very unlikely assumptions made by IIASA (Laherrere 2001 on IIASA gas perspectives). The 40 gas scenarios cover a very broad range but unfortunately exceed the most likely scenario based on technical data (figure 71) as shown in the next graph (consumption given in EJ = 10E18J Å Tcf/a).

Figure 72: IPCC 2000 gas consumption scenarios compared to forecast from technical data.


It means that the IPCC 2000 conclusions are as unlikely as their assumptions are based on the concept of very abundant resources and cheap price. They confuse reserves and recoverable resources with resources as volume in place. They confuse wishful thinking with reality.

It is very important that the academic agencies work on better data. IPCC has to work again on their modelling with better assumptions on future hydrocarbon production.


Global conclusion

Most of official forecasts on North America gas supply and demand are questionable. The main reason is that the scenarios are based on the concept of abundant resources and cheap oil and gas, but also on unreliable data. The 10$/b for oil in 1998 is mainly due to the "missing barrels". The IEA reported an underestimated demand and an overestimated supply, giving a wrong impression of abundance.

Before improving forecasting methods (which needs to be taken out of political pressures), it is necessary to improve the data collected by the USDOE and MMS by changing the rules of reserves reporting with the SEC.

The demand (for oil and gas) as forecasted by official agencies is unlikely to occur (high price will increase energy savings as in 1979) and the gas supply will be much less than forecasted as shown by most of the graphs, but the balance for gas can be solved with the import of LNG. Energy savings can be both by using less energy (change of behaviour such as driving less) and improving efficiency (change of equipments).

The additional demand for electricity can also be filled with coal and nuclear, if renewables cannot do it.

We hope that our goal to inform the reader with many graphs has been partly fulfilled, and has brought some light on the North America gas supply.

References

-Adams T.D., Kirby M.A. 1975 "Estimate of world gas reserves" 9th WPC.
-Blair A. 2000
"Special message" World Economic Forum Annual Meeting 2000 Davos, Switzerland. < http://www.asiamedia.ucla.edu/Davos2000/Speeches/Blair.htm >.
-Campbell C.J, Laherrere J.H. 1998 "The end of cheap oil" Scientific American March p80-85.
-Canadian Gas Potential Committee 2001 "Canada’s natural gas future to remain in Western Canada" Sept. 11, < http://www.canadiangaspotential.com/2001report/mediarelease.html >.
-Capen E.C. 1996, "A consistent probabilistic approach"; SPE Reservoir Eng. Feb. 1/1-Cochener J.C. 2001 "The long term trends in US gas supply and prices" Oil and Gas Journal, January 22 p.
-Cochener J.C. 2000 "Long-Term Trends in U.S. Gas Supply and Prices: 2000 Edition of the GRI Baseline Projection of U.S. Energy Supply and Demand to 2015" Gas Research Institute devenu Gas Technology Institute.
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[MFS note: return to Part 1 of 2]
_____
Used with permission of the author.
Originally published:
-Laherrère J.H. 2001 “Estimation des réserves de gaz en Amérique du Nord” Revue de l’Energie juillet-aout n°528 p357-375.
-Laherrère J.H. 2002 “Will the natural gas supply meet the demand in North America”, International Journal of Energy Technology and Policy.

Jean Laherrere can be reached at:< jean.laherrere@wanadoo.fr>

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