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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 1 of 2

    Figure 1: gas import prices in Japan, Europe and US
    Table: Calorific values of gas
Current situation & forecasts
Figure 2: US gas producers: fractal distribution.
Figure 3: Number of US producing wells.
Figure 4: Number of all wells from 1860 to 2000.
Figure 5: Number of exploratory wells from 1950 to 2000.
Figure 6: US average completed well cost per footage drilled.
Figure 7: Gas well current cost in $/ft versus nominal wellhead price in $/kcf the year before.
Figure 8: US fossil fuels production.
Figure 9: US oil & gas annual production.
Figure 10: US oil & gas monthly production.
Figure 11: US gas production and withdrawals.
Figure 12: US 2000 gas flow.
Figure 13: Gas production from oil wells and petroleum production.
Figure 14: Brent oilfield production of oil and gas.
Figure 15: Parentis oilfield production of oil and gas.
Figure 16: Remaining US reserves.
Figure 17: US remaining gas reserves: current proved versus backdated mean.
    Gulf of Mexico
Figure 18: Percentage of production in federal lands.
Figure 19: GOM OCS: evolution of original reserves and production.
Figure 20: GOM percentage of gas discovery and production versus water depth from MMS.
Figure 21: GOM OCS: annual average size and number of gas discoveries from MMS.
Figure 22: GOM OCS cumulative gas discoveries detailed by water depth from MMS.
Figure 23: GOM gas field size from MMS: fractal display.
Figure 24: GOM OCS: MMS proved & industry unproved discoveries.
Figure 25: GOM deepwater: comparison of field reserves from Infield, Wood Mackenzie and MMS.
Figure 26: Cumulative gas discovery up to 1998 versus water depth from Infield and MMS.
Figure 27: Cumulative gas discovery versus time from Infield and MMS.
Figure 28: GOM oil & gas production up to 2000.
Figure 29: Decline of GOM production from gas wells from 1972 to 1998.
Table G1.  Average Production from Wells in the Federal Offshore Gulf of Mexico, 1972 to 1996.
    Reserve growth
Figure 30: GOM gas fields: evolution of original reserves with time.
Figure 31: GOM Tiger Shoal gas field: reserves evolution.
Figure 32: GOM Tiger Shoal gas field: production decline.
Figure 33: GOM Eugene Island 330 field: gas reserves evolution.
Figure 34: GOM Eugene Island 330: gas production decline.
Figure 35: NPC 1992 study: Gas reserve growth.
Figure 36: GOM gas remaining reserves proved and grown from MMS and Nehring.
Figure 37: Texas gas performance from 1971 to 1998.



The goal of this paper is to deliver to the reader a large number of graphs in order to allow him to choose the ones that he consider as important to make his own opinion. Graphs from data are more important than statements which are mainly interpretation and political. But the problem is that the data are fairly unreliable.

There is only one oil market as oil is cheap to transport around the world for about 1$/b, but gas is 6 to 10 times more expensive to transport and there are three main gas consumer markets: North America, Europe, and Asia Pacific. But the Persian Gulf will become a fourth producing centre. Gas supply in North America is only local when excluding imported LNG, which is a very small part.

The graph from IEA WEO 2001 shows clearly that the gas import price in Japan from 1987 to 1997 was about 3.5 $/MBtu when it was about 2.5 $/MBtu in Europe and only 2 $/MBtu in the US. But in 1999 & 2000 US gas was more expensive than in Europe.

Figure 1: gas import prices in Japan, Europe and US.

The calorific value of gas varies with the producing country  (from IEA/WEO 2001) and as the oil equivalent (assuming 1toe = 42 GJ and a gravity of 33°API (0.86) or 1 toe = 7.3 boe; barrels of oil equivalent).

Gross Calorific Value

MJ /m3 toe/1000 m3 boe/kcf
Netherlands 33.3 1.26 6.1
Russia 37.6 1.11 5.4
Uzbekistan 37.9 1.10 5.3
Saudi Arabia 38.0 1.10 5.3
Canada 38.1 1.10 5.3
US 38.3 1.09 5.3
UK 39.3 1.07 5.2
Indonesia 40.6 1.03 5.0
Norway 41.0 1.02 4.9
Algeria 42.0 1.00 4.8

The US and Canada gas is in the middle of the range between the low calorific gas in the Netherlands and the rich gas in Algeria.

In 1999 US supply was 85% from production and 15% net import with LNG covering only 1%.

  1999 Production Net Imports Total Supply Canada Imports LNG
Gcf/d 52.1 9 61.5 10.3 0.4
Tcf/a 19.0 3.3 22.4 3.8 0.1
% supply  85 15 100 17 1.0

The last gas crisis in North America was due to a shortage of local supply as most of the gas comes from the US and Canada, Mexico being and will be more and more a net importer. The low price for oil and gas at end of 1998 led to a shortage of investment in drilling. Technology has enabled huge progress in producing gas cheaper and faster, and the decline rates of gas wells have increased sharply over the last 30 years and are now about 50%/a. Most new gas wells are needed not to fulfill the demand increase, but to prevent the supply to decrease because of the drastic decline of present producers. The sharp increase in gas prices at the end of 2000 leads to a decrease in gas demand in 2001, which then resulted in a drop in price.

Future production (in fact the remaining reserves) has to be studied from the past discoveries, the past production and from the estimate of the undiscovered.

We are going to analyse the reliability of the data (political versus technical) for the three countries (US, Canada and Mexico), the pattern of discovery (creaming curve), the field size distribution (parabolic fractal), the correlation between annual discovery and annual production after a certain time shift, and last the modelling of future production from ultimate.

Current situation & forecasts

We will study first the present situation and second the forecast for future production.


Present situation, data and reliability, number of producers and wells.

Oil & Gas Journal (OGJ -Oct 1, 2001) lists the 200 US companies (OGJ200) which produced in 2000 11.5 Tcf (58% out of 19.7 Tcf total production) from 119 Tcf of proved reserves (71% out of 167 Tcf). It means that there is a very large number of gas producers (in thousands as the difference of 8.2 Tcf is produced by companies producing less than 0.01 Tcf/a), quite different from countries outside North America where the number of gas producers is limited to a few tens. The distribution of annual production and reserves listed by rank of decreasing size) displays a fractal distribution in figure 2:

Figure 2: US gas producers: fractal distribution.

Gathering the data from so many companies is quite difficult and inaccurate.

The USDOE provides a large set of data (it is the best available source of data on the world’s oil and gas industry) on US production and for the rest of the world. Unfortunately the quality of these data is questionable.

If the number of gas companies is by thousands, the number of producing gas wells is by hundreds of thousands as shown in figure 3.

Figure 3: Number of US producing wells.

From 1985 to 1998, the number of producing oil wells decreased from 650 000 down to 550 000 in 1998 when the number of gas wells increased from 250 000 to 315 000.

But the number of wells drilled in US up to 2000 is about 3.5 million with 48% being oil wells and 18% being gas wells. But these wells are either development wells or exploratory wells which can be in part New Field Wildcats (NFW) and these wells can result either in oil wells, gas wells or dry wells.

The number of all wells drilled in the US peaked in 1920 (with 30 000), 1940 (30 000), 1955 (55 000) and 1980 (90 000 with 40 000 oil wells and 20 000 gas wells), but the number went down with the price of oil and gas between 1986 and 1996. The number of gas rigs went from 400 in 1996 to a peak of 600 in 1998 down to 350 mid-1999 and now at 1000 mid 2001.

Figure 4: Number of all wells from 1860 to 2000.

The success ratio in gas development, which was 85% in 1880, decreased to 55% in 1970 and rises again up to 80% in 2000.

The success ratio in gas exploration, which was around 20% in 1950, has increased to 35% in the second half of the 90s. More and more exploratory drilling is closer to development drilling.

Figure 5: Number of exploratory wells from 1950 to 2000.

Reporting the number of wells is unreliable as in 1998 USDOE corrected the reported number of gas wells for 1996 being 560 and not 943. The 1996 success ratio was corrected from 45% down to 32%.

The number of New Field Wildcats (roughly half of the exploratory wells), which was about 9000 in 1956, went down to 5000 in 1970, up to 9000 again in 1981 and down to 1000 in 1995. But the NFW success ratio (from USDOE) has increased from 10% during the 50s and 60s to over 20% in the 90s. The maturity of the exploration is up, more data and better seismic exploration leads to higher success ratio, but finding smaller field size for both oil and gas.

The last DOE/EIA annual report in 1999 is more up to date and slightly different. The success ratio for the second half of the 90s is about 30%.

It is interesting to note that the US cost of drilling varies sharply up and down. The cost for gas wells is slightly higher than for oil wells. The cost of drilling in $/ft has increased sharply since 1992 from 80 $/ft to more than 120 $/ft in 1998.

Figure 6: US average completed well cost per footage drilled.

The cost varies with the wellhead price as shown in the next graph.

Figure 7: Gas well current cost in $/ft versus nominal wellhead price in $/kcf the year before.

It seems that there is a good linear relationship between drilling cost and wellhead price and that the technological progress does not show up too much!


The US fossil fuels production is almost flat since 1970, as shown in figure 8 (given in PBtu (10E15 Btu) close to EJ (exajoule, close to Tcf or Gb/6)).

Figure 8: US fossil fuels production.

The decline of oil is compensated mainly by the increase of coal and partly of gas since 1985 (after the peak of 1972).

The detail of oil and gas production in Gb and Tcf is given in figure 9 and figure 10.

Figure 9: US oil & gas annual production.

The monthly production (Mb/d and Tcf/month) in figure 10 shows that the NGL in Mb/d was equal to the gas in Tcf/month from 1973 to 1982 but increases since 1982 as gas plants stripped of more liquids which was more valuable than staying into gas.

Figure 10: US oil & gas monthly production.

The big problem with gas production statistics is that very often it is not indicated if the production is gross withdrawal, marketed wet or marketed dry. Most of the times when not indicated it is assumed to be dry production. The difference is quite large as shown in figure 11 between gross withdrawal and dry production:

Figure 11: US gas production and withdrawals.

USDOE/EIA gives the 2000 gas flow as below in http://www.eia.doe.gov/emeu/aer/diagrams/diagram3.html:

Figure 12: US 2000 gas flow.

The gross withdrawal is 24.7 Tcf/a and dry production only 19.2 Tcf/a (78%).

3.7 Tcf (15%) is repressured, but 3.4 Tcf is drawn from storage. It is not specified where the gas is repressured (field or storage). If it is in storage it should be compensated by the withdrawal from the storage. The reference data should be raw (gross) and not dry production.

Gas production from gas wells and gas production from oil wells are shown in figure 11 and to study in detail the evolution of the associated gas production from oil wells is compared to oil production in figure 13.

Figure 13: Gas production from oil wells and petroleum production.

It is striking that associated gas production was in line with oil production from 1950 to 1979 but from 1979, oil declines when gas increases.

In his book "Alternative energy resources" in 1976, James Hartnett gave on page 35 his forecasts on oil & gas US production until 2020. He forecasted for oil a continuous decline of the Lower 48, a new cycle with Alaska Prudhoe Bay since 1975 and another cycle due to EOR (Enhanced Oil Recovery), expecting 2.1 Gb/a in 2000 for conventional oil and another 1 Gb/a for EOR. In fact oil US production was at 2.1 Gb/a, but the dreams of EOR did not come true. But for natural gas he forecasted also Alaskan production in addition to declining Lower 48 with a total of 15 Tcf/a in 2000 and an additional 12 Tcf/a for new techniques (27 Tcf/a in 2000), but all declining since 1985. In fact North Slope gas is not there, total production for 2000 was about 18 Tcf (dry), but rising since 1985. Hartnett was all wrong.

Why has gas production been increasing since the trough of 1985? It comes in part from gas wells but also surprising in part from oil wells, despite the decline of oil. As shown in figure 13, gas production from oil wells rises from 1985 when oil declines sharply: Why?

It is well known that at the end of an oilfield associated gas production rises. The increase of gas production from oil wells seems to indicate the near end of most US oilfields. This behaviour was not forecast by most of the experts.

One good example of increasing associated gas with declining oil is shown with Brent oilfield in UK and Parentis oilfield in France.

Figure 14: Brent oilfield production of oil and gas.

From 1996 oil declines and gas rises sharply. GOR (gas oil ratio) jumps from 2,5 to 8 Gcf/Mb.

Figure 15: Parentis oilfield production of oil and gas.

From 1993 GOR jumps from 0,05 Gcf/Mb to 0.25, when the oil production keeps declining.


The remaining reserves (which are future production) vary by author. USDOE data shows a change in value in 1979 when they took over the duty of reporting from API (American Petroleum Institute) and AGA (American Gas Association).

Figure 16: Remaining US reserves.

In the US to comply with the SEC (Securities & Exchange Commission) listed companies have to report only proved reserves (estimated with reasonable certainty to be commercially recoverable,), omitting probable reserves. In the rest of the world reserves are reported as proven + probable. Under the SPE/WPC/AAPG rules, proved reserves are defined as "a high degree of confidence" under the deterministic approach or with a "90% probability to be equalled or exceeded" under the probabilistic approach. "Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves". There is a contradiction in the deterministic approach where probable being as likely or unlikely i.e. 50%, when in the probabilistic approach it is proved + probable being 50%.

The poor US practice on proved reserves leads to a very strong revision and the concept of reserve growth, whereas using the mean (or expected value) reserves for proven + probable results statistically in no growth.

The experts are clear:

Ross 1998 wrote: "The term "reserves" often is treated as if it were synonymous with "proved reserves". This practice completely ignores the fact that any prudent operator will have, at least internally, estimates of probable and possible reserves."

DeSorcy 1993 for the Canadian Standing Committee on Reserve Definition wrote: "There are currently almost as many definitions for reserves as there are evaluators, oil and gas companies, securities commissions and government departments. Each one uses its own version of the definitions for its own purposes."

Capen, one of the best US experts in reserve definition, wrote in 1996: "An industry that prides itself on its use of science, technology and frontier risk assessment finds itself in the 1990s with a reserve definition more reminiscent of the 1890s" "illegal addition of proved reserves."

It is amazing to find in the oil and gas industry so much advanced technology such as the deepwater and so much obsolete practice such as using the old term of bbl (being the blue barrel: why blue?) or refusing to use the system of international units (SI) (it was the cause of the lost of the Mars Climate Orbitor which crashed when NASA sent instructions of thrust in newtons when Lockheed has built it in pounds), still using M for thousand when the layman uses Y2K and not Y2M. Most of US gas producers refuse the probabilistic approach in estimating the reserves, as they use only area (spacing) in acre, net pay in foot and recovery as cubic foot per acre-foot from the closer field, or often ten times the annual production!

One of the biggest mistakes in dealing with proved reserves is that aggregation of the proved field reserves does not give the proved reserves of the country or a basin, it underestimates it. But every official agency or media does it. Only the addition of "mean" field reserves corresponds to the "mean" reserves of the country.

The comparison between the current proved remaining reserves and the backdated mean (proven + probable) reserves (corrected using MMS reserve growth model) shows a large difference in volume and in decline rate. The "mean" reserves have declined since 1965 and the slope is constant since 1980 at 2.5%/a, whereas the current proved stays flat since 1988.

Figure 17: US remaining gas reserves: current proved versus backdated mean.

The biggest problem in forecasting US production is the poor quality of the reserves data because of the SEC rules and the conservatism of the gas industry in reporting data.

Gulf of Mexico

Data is difficult to gather onshore US because of the number of producers and confidentiality of the data - gas is owned by the landowners. It seems that the situation should be better in the federal waters of the Gulf of Mexico = GOM OCS (Outer Continental Shelf) where oil and gas is owned by the Federal Administration (selling leases to private companies) and productions are managed by the USDOI MMS (Minerals Management Services).

It is surprising to see the increase of the federal lands in the production of fossil fuels from 3% in 1950 to more than 30% in 1998 and it is likely to continue in the future and to increase more if the access to federal lands is more open to exploration and production.

Figure 18: Percentage of production in federal lands.

Reserves have been changed in the 80s because of the change in definition from API (American Petroleum Institute) to SPE (Society of Petroleum Engineers) rules.

Figure 19: GOM OCS: evolution of original reserves and production.

The incomplete MMS data gives a distribution of gas reserves and production versus water depth, which shows that gas is mainly in the shallow waters.

Figure 20: GOM percentage of gas discovery and production versus water depth from MMS.

The MMS data displays a peak in the annual number of discoveries (in the graph the number is multiplied by 10) around 1984 (70) and that the average size of the original reserves which was around 0.6 Tcf in the 50s has sharply declined since 1973. The average water depth of the discoveries, which was around 200 ft in the 70s, is around 150 ft in the 80s and the first half of the 90s.

Figure 21: GOM OCS: annual average size and number of gas discoveries from MMS.

The cumulative gas discoveries (from MMS) shows that the main part comes from water depth less than 1000 ft, but this part decreases since 1980.

Figure 22: GOM OCS cumulative gas discoveries detailed by water depth from MMS.

The MMS proved gas field (984 fields) reserves grown to 2P (or mean) with MMS reserve growth factor (the first year estimate is multiplied 50 years later by 4.5) are plotted with a fractal display (rank of increasing size versus field size in a log-log graph) for each decade. This graph shows that the largest fields are found first and that an ultimate curve can be drawn.

Figure 23: GOM gas field size from MMS: fractal display.

MMS provides on the web the data up to1998 giving the detail of the evolution of every field since 1975 in the GOM OCS, totalling 984 fields. Unfortunately the huge database (197 pages) on reserve history shows on the first page for the first field cumulative oil declining at the fifth line (for 1979), meaning that the annual oil production was negative (which is impossible!). It is obvious that operators sent flawed data (change in grouping?) to MMS, which did not bother to check if it is correct.

Figure 24: GOM OCS: MMS proved & industry unproved discoveries.

We have compared for the deepwater of the GOM the data given as oil equivalent (initial) reserves from MMS, Infields and Wood Mackenzie (WM). The comparison for the same field between two files X and Y is given in percentage of change ((X-Y)/Y*100) and the percentage is ranked by increasing percentage. The plot shows that the change varies from —80% to +150%. The total of the reserves for about 50 fields is 7.5 Gboe for Wood Mackenzie and 7.4 Gboe for Infields, being close, but the difference was larger when compared with MMS. For 20 fields MMS total is 2.3 Gboe when WM is 3 Gboe. For 27 fields MMS total is 3.3 Gboe when Infields is 3.6 Gboe.

Figure 25: GOM deepwater: comparison of field reserves from Infield, Wood Mackenzie and MMS.

When these databases are plotted as cumulative discovery versus time, the discrepancy is huge. For deepwater (>1000 ft) the cumulative discovery up to 1998 is 15 Tcf for Infield, but 8 Tcf for MMS.

Figure 26: Cumulative gas discovery up to 1998 versus water depth from Infield and MMS.

It is obvious that MMS database is incomplete having only 39 fields against 132 fields for Infields. The plot versus time shows that the discrepancy starts in number since 1985 and in discovery since 1988.

Figure 27: Cumulative gas discovery versus time from Infield and MMS.

MMS is incomplete and late to report, now only up to 1998.

To get updated data, it is necessary to rely on published papers such as Dodson in Offshore January 2001. Gas production is flattened since 1990 with less than 5 Tcf/a and oil has risen since 1990 because of the deepwater.

Figure 28: GOM oil & gas production up to 2000.

Figure 29: Decline of GOM production from gas wells from 1972 to 1998.

< http://www.eia.doe.gov/oiaf/servicerpt/depletion/table_g1.html >.


Table G1.  Average Production from Wells in the Federal Offshore Gulf of Mexico, 1972 to 1996

Year Peak Production kcf/d Percentage of Peak Production
23 Months Later
1972 4198 0.633
1976 5591 0.648
1980 5533 0.502
1984 4477 0.591
1988 4915 0.497
1992 5294 0.417
1996 6070 0.314

Source: Energy Information Administration, Office of Oil and Gas, Reserves and Production Division (Dallas, TX).

Reserve growth

In 1981, faced with the unreliability of the so-called proved reserves, the USGS (in an assessment of undiscovered conventional oil and gas as of end 1979), called them measured reserves, and called inferred reserves the expected additions on these measured reserves, which is now called reserve growth by the new team.

Reserve growth is the most important problem in assessing the US oil & gas potential, as a proper approach needs to deal with "mean" values, called "proven + probable" in most of the countries outside the US and Canada.

Technology allows cheaper and faster production, seldom to increase the conventional reserves (but in contrast to unconventional oil and gas). The best proof is that the depletion rate of gas wells has increased drastically over the last 20 years, being now over 50%/a in the GOM.

What is wrong is the US practice of estimating reserves because the SEC rules prohibit reporting probable reserves as is done in the rest of the world. It is why from 1988 to 1999 new gas field discoveries represent only an average of 5% of the total reserves additions, and the revisions of the past discoveries represents 95%, meaning that the past estimates are pretty lousy. US practice for reporting reserves is very poor (as obsolete as the punched cards of the last presidential elections!). This poor practice leads to a strong reserve growth wrongly attributed to new technology when in fact it is due to poor methodology. But such practice allows oil & gas companies to report growth even without any discovery and they love it.

The evolution of the percentage of the original reserves versus the reported value in 1998 for 12 largest gas fields discovered from 1948 to 1969 (average year of discovery 1955 and average water depth 60 ft) shows a large range of variation but the average rises sharply from 1975 (first year of data) to 1985, then the estimate went down following the counter shock of 1986 to return in 1998 to the 1985 value.

It means that the evolution is stabilised and no significant reserve growth should be expected statistically, but despite that some fields can still vary up or down.

Figure 30: GOM gas fields: evolution of original reserves with time.

The deepwater production has really only started since 1990 as shown in figure 28 and the behaviour in these new conditions is still immature. Some deepwater development have shown some disappointment as the Shell Macaroni field (developed with subsea equipments peaking at 15 000 b/d instead of the 35 000 b/d expected).

The study of the production of individual mature fields shows a different story from what is reported as reserves. The three largest GOM gasfields (all found before 1958) are TS000 (Tiger Shoal), VR014 (Vermilion) and VR039 with about 3 Tcf each.

The evolution of original reserves given by MMS since 1975 shows that for TS000 (found in 1958) by 13 ft of water) the ultimate was about 3.7 Tcf around 1985 to go down to 3.2 Tcf in 1998. The evolution of the ultimate with up and downs is not smooth, likely coming from goals varying with years.

Figure 31: GOM Tiger Shoal gas field: reserves evolution.

The analysis of the annual production versus cumulative production shows a decline from 1975 to 1990 giving an ultimate around 3.5 Tcf (explaining the 3.7 Tcf in 1985) but since 1991 the depletion has been accelerated and the present ultimate is around 3.3 Tcf against MMS estimate of 3.18 Tcf.

Figure 32: GOM Tiger Shoal gas field: production decline.

The fourth largest gas reserves Eugene Island 330 oilfield (found in 1971 in 246 ft of water and in 1998 the largest oil and gas original reserves with 760 Mboe) is interesting as this field was taken by the Wall Street Journal (Cooper 1999) as the example of refilling of reserves and to wonder about a deeper origin for oil, and to explain the huge increase in the Middle East reserves in the second half of the 80s. In fact, because of the large depletion of pressure, this field seems to have been charged again from the source-rock, by one of the largest (the Red Fault) and best faults in the GOM studied by many university seismic surveys in 4D (
http://www.ldeo.columbia.edu/4d4/talks/expl/index.html). But again the first oil estimates reported to MMS seem odd and different from OGJ estimates and the increase in1995 due to an increase in annual production is minor compared to the decrease of 1988. An analysis of the pressure should explain the recharge of the reservoir.

The difference between MMS and OGJ on the cumulative production seems to be mainly discrepancies between 1977 and 1979.

Figure 33: GOM Eugene Island 330 field: gas reserves evolution.

The new increase in annual oil production starting in 1993 peaked in 1996 and declined again. The last value plotted for 2000 is only an estimate from the month of May in MMS last report. The pre 1993 ultimate estimate from the decline was about 350 Mb, after the recharge the estimate is now about 400 Mb (416 MMS & 389 OGJ).

As for oil production, the EI 330 associated gas production declined since 1977 to 1993 to rise until 1996 and declined again. Before 1993 the ultimate could have been estimated at about 1.75 Tcf, after the recharge the present decline rate suggests (questionable value for 2000 as only for one month) the ultimate is about 2 Tcf (1.93 Tcf MMS).

Figure 34: GOM Eugene Island 330: gas production decline.

In the DOE/EIA annual report 1997 the reserve growth on federal offshore is given as 33 Tcf.

Annual report DOE/EIA 1997

Crude Oil Natural Gas (Dry) Natural Gas Liquids
    Gb Tcf Gb
Lower 48 States        
Proved Reserves (EIA, 1997) 17 157 7
Reserve Growth - conventional, onshore + State offshore (USGS 1991) 47 290 13
Reserve Growth - conventional, Federal Offshore (MMS, 1995) 2 33 NE
Unproved Reserves, Federal Offshore (MMS, 1996) 2 4 NE

Undiscovered, Technically Recoverable

Conventional, onshore + State off (USGS, 1993) 22 190 6
Continuous-type - sandstone, shale, chalk 2 308 >2
Continuous-type - coalbeds NA 50 NA
Federal Offshore - conventional (MMS, 1994) 21 142 >2


  113 1174 NA

We believe that it is completely wrong to measure the reserve growth as a ratio of the estimate of proved reserves at discovery year. The estimate is only reliable after a few appraisal wells. Furthermore the proved reserves depend on the number of wells drilled and it is better to wait for the complete development of the field to assess the real value of the proved reserves. In the past when API was in charge of reporting the reserves, the first six years after discovery were considered as unreliable. Offshore the development is decided only after appraisal wells and the only reliable estimate should be the first one at the decision of development which in fact is decided not on "proved" reserves but on "mean" reserves, if not the size of the development is underestimated costing money later.

Proved values are the values reported to the outside but the technical values, which are different, are kept confidential in house. In the North Sea a study by BP and the DTI show that the proven + probable used in UK shows less reserve growth (see Laherrère 1999). A recent study by Wood Mackenzie (1999) consider the year zero as the development year and the " reserves creep " before. In fact the reserves estimates 4 years before the development were 13% higher. They increase for the first 8 years then decrease but increase again to reach a value 25% higher 13 years later.

A gas study in 1992 by the National Petroleum Council gave the following graph, which displays an erratic cloud from 0 to 30 times multiplier for the 60 years period. They draw a curve within this cloud but it could be any curve!

Figure 35: NPC 1992 study: Gas reserve growth.

From more recent data in the GOM MMS claims that the first year estimate has to be multiplied by about 4.5 to get the ultimate recovery 50 years later.

In his Jan. 2001 article in Offshore Nehring studies the Gulf of Mexico (GOM)’s reserves and, contrary to the USGS, he gives the proved as well as the proved plus probable (by growing the proved by about 30% after a few years and then stopping the growth, which is completely different from the 2000 USGS lower 48 reserve growth or the MMS reserve growth).

Figure 36: GOM gas remaining reserves proved and grown from MMS and Nehring.

Nehring increases by 20% to get grown (from 27 to 33 Tcf for deepwater) when MMS model grows OCS by about 90% (from 30 to 57 Tcf).

The claim of increasing the reserves because of technology is confused with increasing the initial production. If initial production are improved with new technology, the subsequent decline is also increased sharply as shown in figure 29 for the GOM and in fact the ultimate recovery per well decreases as in the study for gas in Texas.

Gary Swindell 1999 provides the Texas gas well performance from 1971 to 1998 with an initial rate (first month) being 52 Mcf/month in 1971 decreasing to a low of 15 Mcf/month in 1983 and increasing again through 1998 up to over 40 Mcf/month. The increase beginning in 1989 correlates with the acceleration of horizontal drilling in the Austin Chalk fields of Giddings and Pearsall Fields. Increases prior to that are likely due to improved, high volume fracturing technology and high productivity in South Texas drilling. But the first year decline has increased from 10%/a in 1971to over 55%/a in 1998. The ultimate per well decreases continuously (except 1989) from 6 Gcf/w in 1971 down to 1 Gcf/w in 1998.

Figure 37: Texas gas performance from 1971 to 1998.

It is obvious from the technical data that technology allows for conventional gas to produce faster and cheaper but hardly to increase reserves. Reserve growth is mainly due to poor reporting when using proved reserves, but the use of "mean" reserves allows statistically to avoid reserve growth.

Generally speaking, all studies assume that gas production will grow thanks to new technological developments, as if the simple extrapolation of the past production trends was missing this aspect. This is of course untrue because technology has improved over time in the past and this improvement is an integral part of the past production profile. So, the addition of a "technology improvement" should be understood as an extra improvement compared to its natural evolution with the general increase of the productivity of the factors. Given the fact that the level of prices is supposed to remain at the level of the 90s, this extra improvement cannot be attributed to prices. So, where does it come from?

In short, in all these forecasts, there is a contradiction between the evidence of a supply problem arising from past production trends and the optimistic assumption that technology will reverse these declining trends. In fact, unless the price environment changes significantly (an hypothesis that none of the NPC, GRI, DOE,…forecasts anticipates) it is difficult to admit that the trend of technology improvements (that is included in the past production, for instance with the growth of non-conventional gas or that from deep offshore), will suddenly accelerate and be the "deus ex machina".

In conclusion, if one dismisses the possibility of the opening of federal lands that are presently closed to exploration, and if one considers that, unless prices rise significantly, technology will only continue the same steady trend of progressive improvement as before (with no "silver bullet"), future production will continue to decline, possibly at an accelerating rate.

[MFS note: continued in Part 2 of 2]


-Adams T.D., Kirby M.A. 1975 "Estimate of world gas reserves" 9th WPC.
-Blair A. 2000
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* 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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