This paper compares estimates of reserves, resources and future production scenarios of conventional petroleum liquids for five peaked countries and the World as determined by various analytical techniques. It starts by illustrating Hubbert’s Model using historical production from offshore Norway and the United Kingdom (UK), and onshore Oman, Syria and Yemen, to estimate the resource, peak rate and year. For all five countries the estimated resources were found to significantly differ from known reserves (cumulative production plus proved reserves) and ultimate recoverable resources estimated by geologic studies; accordingly the model’s estimate is here referred to as the producing resource. Importantly, the producing resource – not the known reserves or ultimate recoverable resources – represents the quantity that most closely predicted the peak (rate and year) and early decline for these countries. The model’s production trajectory became accurate after the producing resource was between 10–30% depleted for four countries; the exception was for the UK at 44% depletion and due to non-geological circumstances. In the five countries, the peak occurred when the producing resource was approximately 50% depleted, and within a production plateau – here defined as exceeding 91% of the peak rate.
The Hubbert Model cannot be applied to all basins and/or countries. Its World predictions are controversial and therefore presented as a Production Base Case and compared to those from other studies. The Base Case for conventional petroleum liquids predicted: (1) average producing resource of c. 2,860 billion barrels (Gb), (2) peak rate of c. 85.7 Mb/d (31.3 Gb/year), and (3) peak year in ca. 2016. The data used for this analysis is oil production as reported by BP (2008) from 1991 to 2007, consisting mostly of crude oil, lease condensates and natural gas liquids. The producing resource is just 3% greater than the 95%-confidence estimate for ultimate recoverable resources of 2,770 Gb effective in 2025 by the United States Geological Survey (with 152 Gb added for Canadian oil sands, BP, 2008). It is 351 Gb greater than the end-2007 known reserves of 2,509 Gb, consisting of 1,119 Gb produced, 1,238 Gb proved, and 152 Gb in Canadian oil sands (BP, 2008). The unproven resource of 351 Gb is achievable if the 20 Gb/year rate of new liquids reserves (undiscovered and reserves growth), added in 2005, is maintained on average between 2008–2025. The convergence of these three independent techniques on a resource of c. 2,860 Gb makes no assumption about the price of oil.
The predicted peak rate (85.7 Mb/d in 2016) is 4.2 Mb/d greater than the 2007 average oil production of 81.5 Mb/d (BP, 2008). It compares closely to the peak rate of 86.2 Mb/d in 2012 obtained by balancing new megaprojects (more than 40 Kb/d) coming onstream in 2005–2014, against existing 2004 production declined at 4.5%/y. The Base Case predicts that production in 2030 will be 78.0 Mb/d, as consistent with the high-price scenario for conventional petroleum liquids production by the Energy Information Agency (2008): price of oil to increase to $186/barrel by 2030 but production to fall to 80.3 Mb/d in 2030 from 81.8 Mb/d in 2004.
Over the past several decades many analysts have applied Hubbert’s Model to forecast the production of petroleum from various countries and the World (Hubbert, 1956a, b, 1969, 1982; Hubbert’s Curve – sometimes referred to as the derivative of the Logistic Curve; e.g. Campbell, 1997, 2004, 2006; Campbell and Laherrère, 1998; Laherrère, 2000; Laherrère and Wingert, 2008; Duncan, 2001; Cavallo, 2002, 2004; Deffeyes, 2005; see review inAl-Husseini, 2006). The model suggests a simple relationship between annual discoveries, annual production, peak production and year, and the ultimate recoverable resources. The predictions, however, vary considerably depending on the analyst’s confidence in the reported ultimate resources and the suitability of the model to the target region (e.g. Nehring, 2006a, b, c). Moreover, because the model does not explicitly account for the price of oil, some analysts have regarded its application to be of limited scope. In particular, for the USA and World cases, it has been convincingly argued that because the price of oil varies over time then so do supply, demand, reserves and the ultimate resource itself (see McCabe, 1998, and related Discussion in 2001 by Laherrère, Campbell and Duncan, and Reply by McCabe, 2001; Ahlbrandt, 2004, 2006; Nehring, 2006a, b, c).
One significant aspect of Hubbert’s Model is that it offers a simple technique that uses only historical production data to estimate: (1) resource; (2) maximum sustainable production (peak); and (3) peak year (Hubbert, 1982; see Duncan, 2001; Deffeyes, 2005; de Sousa, 2008). The application of this technique – here referred to as the Hubbert Line – is illustrated using production data from five countries with declining production (Table 1); two offshore (Norway and the United Kingdom - UK) and three onshore (Oman, Syria and Yemen). These five countries were specifically chosen to illustrate how the technique works when applied to suitable regions, and more importantly to quantitatively determine what is meant by the terms resource, peak, plateau and peak year as determined by the Hubbert Line. This paper shows that the resource estimated by Hubbert’s Model using production data – referred to as the producing resource – differs from known reserves (produced plus proved) and ultimate recoverable resources; importantly, in the studied countries, it is the crucial quantity that determined the peak, plateau and early decline of production.
The final part of the paper applies the Hubbert Line to the World’s production of conventional petroleum liquids to compute its producing resource and peak. The results are interpreted as the Production Base Case, and compared with those from other independent studies of ultimate recoverable resources (USGS, 2000; Ahlbrandt et al., 2005; Ahlbrandt, 2004, 2006; J. Laherrère, 2008, written communication), known reserves (produced and proved; BP, 2008), rates of reserves additions (Chew, 2006), near-future production from megaprojects and decline rates (Skrebowski, 2007; Jackson, 2008).
PRODUCTION, RESOURCES AND RESERVES OF CONVENTIONAL PETROLEUM LIQUIDS
Annual Production of Conventional Petroleum Liquids
The annual oil production data (Tables 2 and 5) used in this paper are from the BP (2008) data base, which is unique in several ways: (1) it is readily available from their website for producing countries and the World (www.bp.com), (2) it lists production and reserves back to the 1960s in spreadsheets, (3) the data most closely represents the conventional petroleum liquids extracted from crude oil reservoirs and wet-gas reservoirs locally (lease condensates) and from gas plants, and (4) it is widely quoted as a source in many other studies.
BP includes in the category of oil production commercially traded crude oil, which is a stabilized liquid of processed hydrocarbons at atmospheric temperature and pressure. BP includes condensates (lease condensates), which act as a gas in the reservoir but are liquid at surface conditions and processed in a manner similar to crude oil. Natural gas liquids (NGL) are also included in oil production, and referred to as natural gas plant liquids (NGPL) by the USA’s Energy Information Administration (EIA). NGL consist of C2 (ethane), C3 (propane), C4 (butane), C5 and C6 (pentane and hexane used to produce light naphtha or natural gasoline and fractionated into liquefied petroleum gas LPG). NGL and their derivative LPG are distinguished from condensates because they are totally volatile at atmospheric conditions, more so for the lower weight components. Other petroleum liquids included by BP are oil sands (Canada) and shale oil (USA); not included are liquid fuels recovered from coal, gas-to-liquids (GTL) and biofuels.
The BP database distinguishes between oil production and oil consumption, the latter being generally several million barrels per day (Mb/d) greater due to refinery gains, additives and discrepancies in reporting. For example, average 2007 production was reported as 81.5 Mb/d while consumption as 85.2 Mb/d – a difference of 3.7 Mb/d. Also, as noted later, some organizations quote volumes in terms of production capacity (e.g. International Energy Agency, IEA), which can be as much as 10 Mb/d greater than BP’s reported production (Cambridge Energy Research Associates - CERA).
Reserves and Resources of Conventional Petroleum Liquids
Petroleum reserves and resources are categorized and defined, mainly in terms of their probability of occurrence and commerciality, by several organizations including a team of geologists and engineers from the Society of Petroleum Engineers (SPE, 2008; see www.spe.org), the American Association of Petroleum Geologists (AAPG; www.aapg.org), the World Petroleum Council (WPC; www.world-petroleum.org) and the Society of Petroleum Evaluation Engineers (SPEE; www.spee.org). This paper is primarily concerned with comparing the producing resource estimated from historical production data by the Hubbert Line to those from other studies, particularly by the United States Geological Survey (USGS). For this reason the paper follows the USGS (2000; Ahlbrandt, 2004, 2006; Ahlbrandt et al., 2005) and casts the estimated ultimate recoverable resources (EURR; ultimate resources for short) in terms of four categories (Figure 1):
(1) Cumulative Production (produced) obtained by adding annual production (BP, 2008) to start-up.
(2) Remaining Proved Reserves (proved) are reported in various publications (e.g. Table 4, BP, 2008; Oil & Gas Journal, annual issue) but their definitions may vary by country or source. For example, the Canadian National Energy Board (CNEB) reports Canada’s proved oil reserves at c. 180 billion barrels (Gb) of which oil sands account for 174 Gb. In contrast, BP (2008) divides the same quantity into proved developed reserves of 27.7 Gb, and 152.2 Gb for undeveloped oil sands. Moreover, the CNEB estimates the ultimate recoverable resources in oil sands at 315 Gb and the oil-originally-in-place at 1,701 Gb. The definitions for proved reserves also vary by region, organization and certainty (e.g. United States of America - USA, Organization of Petroleum Exporting Countries - OPEC, Former Soviet Union - FSU, etc.). The USGS uses the IHS database, which essentially includes proved plus probable (P50 or 2P), as consistent with the view of J. Laherrère (2008, written communication). In this paper all proved reserves are quoted from BP (2008) without any attempt to qualify their certainty. The term Known Reserves is the sum of cumulative production and remaining proved reserves.
(3) Undiscovered Resources (undiscovered or yet-to-find) are uncertain, and typically estimated by geological studies involving quantitative modeling of petroleum systems in different regions (i.e. basin modeling), sometimes qualified with probabilities of occurrence (e.g. USGS, 2000; Ahlbrandt et al., 2005; Ahlbrandt and Klett, 2005).
(4) Reserves Growth (growth) are unproven resources in developed or undeveloped reservoirs, and attributed to new technology, improved reservoir management, changes in commerciality and other considerations, and believed to increase along historical trends established in producing fields (e.g. McCabe, 1998, 2001; Klett and Tennyson, 2008; Klett and Gautier, 2005). Nehring (2006a, b, c) showed the importance of reserves growth in two USA mature provinces and how the application of Hubbert’s Model resulted in incorrect predictions of production.
Whereas the produced is fairly accurately known, the quantities attributed to the other three categories are successively less well defined and uncertain, and greatly debated (Caruso, 2005;Skrebowski, 2006a, b, c, 2007; Jackson, 2006; see reviews in Edwards, 1997; Kerr, 2005; Al-Husseini, 2006; Ahlbrandt, 2004, 2006; National Petroleum Council, 2007).
For the five countries studied here the comparisons show significant differences between producing resource, known reserves (BP, 2008) and ultimate recoverable resources (Table 1). The ultimate resources in Table 1 were determined by J. Laherrère (2008, written communication) and are between 12.5–22.5% greater than the producing resource. His estimates are based on applying the Hubbert Model to historical reserves data (creaming curve) rather than production data, and are therefore more likely to represent the ultimate recoverable resources (EURR). Another discrepancy occurs because the historical production data do not necessarily account for booked reserves from future projects that have not yet started producing (enhanced oil-recovery projects - EOR, liquids from undeveloped wet-gas reservoirs, sulfurous and/or heavy-oil reservoirs, etc.).
Conventional and Unconventional Petroleum Liquids
Some confusion occurs when comparing production, reserves and resources across studies because certain analysts exclude, for example, NGL, very deep water, Arctic resources, etc. Water depth has been considered as one criterion for distinguishing between conventional and unconventional petroleum liquids; but the cut-off depth has changed as E&P technology has advanced into increasingly deeper waters. For example T. Ahlbrandt (2008, written communication) noted that Campbell set the cut-off at 200 m in 1989 but extended it to 500 m in 2008. In contrast, the USGS (2000) initially set it at 2,000 m but later increased it to 4,000 m when Brazilian wells were drilled in water depths of 3,000 m.
Extra-heavy oil (e.g. Venezuela’s Orinoco oil with an API of c. 10–12°) is considered unconventional and not included by BP (2008) with reserves (Figure 1); however the cut-off API for extra-heavy oil can vary according to analyst (e.g. 15° API by the USGS, Ahlbrandt et al., 2005; or 17.5° API, Campbell, 2006). BP does not include oil shale in proved reserves, and the quantities attributed to shale oil production are mainly from the USA and relatively small.
ILLUSTRATION OF HUBBERT MODEL FOR FIVE COUNTRIES WITH DECLINING PRODUCTION
Consider a simple relationship between a finite producing resource (R) and maximum production (PM) – both assumed to be constants, and the variables annual production (PA) and cumulative production (PC):
The variables PA and PC are known year-by-year and are published for most producing countries and the World (e.g. BP, 2008). By setting Y = PA/PC and X = PC, Equation 1 is recognized as a straight line – here referred to as the Hubbert Line (Hubbert, 1982; Duncan, 2001; Deffeyes, 2005; de Sousa, 2008), with the form shown in Equations (2) to (4):
The constants A and B respectively correspond to the intercept with the Y-axis and the slope of the line. The straight line can be drawn visually or determined by least-square regression. Once A and B are estimated, then from equations (3) and (4):
Norway’s Hubbert Line
Norway production history (Figure 2 and Table 2, BP, 2008) provides a good case study to test how well these equations work in a particularly suitable region. Norway’s production peaked in 2001 at a rate of 1.25 billion barrels per year (Gb/y), and by end-2007 22.5 Gb was produced and 8.2 Gb proved (BP, 2008) totaling 30.7 Gb in known reserves (Table 1).
In Figure 3 the ratio of Norway’s annual-to-cumulative production (Y = PA/PC) is plotted against produced (X = PC). Three Hubbert Lines were determined using least-square regression for different time intervals. When the data from 1982–2007 was used the producing resource R was 29.8 Gb and peak rate PM was 1.25 Gb/y. When the pre-peak 1989–1997 data was separately used, R was 30.4 Gb and PM = 1.30 Gb/y. The most recent straight-line trend from 1998–2007 in Figure 3 predicted R as 31.1 Gb and PM = 1.21 Gb/y. Essentially all three lines predicted R and PM to within a few percentages of the peak level and known reserves.
Significantly, the pre-peak 1989–1997 Hubbert Line carried sufficient information to predict the peak year and known reserves. The most recent straight-line trend between 1998–2007 estimates R as 31.1 Gb, which is only 0.4 Gb greater than the known reserves (30.7 Gb). This would at first suggest that the unknown resource (undiscovered and growth, Figure 1) is c. 1.3% (100 x 0.4/30.7; see Table 1). In contrast, the creaming curve based on historical reserves data predicted Norway’s ultimate recoverable resource at 36.0 Gb (J. Laherrère, 2008, written communication) such that the unknown resource is c. 4.9 Gb (13.6%, Table 1). The differences between the producing resource, known reserves and ultimate recoverable resources emphasize the importance of distinguishing between these terms.
In order to compare Norway’s Hubbert Line to those from other regions it is helpful to use a normalized graph. Equation 1 can be rewritten in a normalized form as:
Norway’s Hubbert Parabola
Clearly Norway’s Hubbert Line carries important information about this country’s production history, and in hindsight its predictions were important well before the plateau occurred and subsequent decline started. But what does Hubbert’s Line physically mean? To clarify its significance, Equation 1 is rewritten as follows:
Equation 8 has the same information as the previous ones but it now shows how the percentage ratio of annual-to-maximum production (100 x PA/PM) follows a parabolic trajectory as a function of percent depletion (D = 100 x PC/R) (Hubbert, 1982; Duncan, 2001). In Figure 5, Norway’s production trajectory is plotted along Hubbert’s Parabola using the producing resource R of 31.1 Gb. The following model-data comparisons standout:
Annual and cumulative production are zero at start-up in 1977; PC = PA = 0.
Annual production should reach 36% of the peak (PM) at 10% depletion – Norway closely attained these two levels in 1988.
At 15% depletion, production should attain half the peak – this occurred in 1990.
At quarter-depletion, production should reach 75% of peak – Norway reached a slightly higher rate of 80% of peak in 1994 at quarter-depletion.
Annual production should reach a peak (PA = PM) when half of the resource has been produced, or mid-depletion (D = 50%, PC = 15.5 Gb) in 2001 – this occurred in 2001.
The plateau (defined here as greater than 91% of peak) should be symmetrical and correspond to depletion between 35% and 65%, or the mid-30% depletion interval – Norway’s plateau occurred between 1996–2005 when depletion increased from 30% to 65%.
After mid-depletion, the decline is predicted to be symmetrical to the build-up, as approximately the case since the 2001 peak.
Annual production returns to zero (PA = 0) when all the resource has been depleted (D = 100%, PC = R = 31.1 Gb). This is predicted to occur well past 2020.
In summary it is evident that the closer the data adhere to Hubbert’s Line (Figures 3 and 4), the closer the production trajectory follows Hubbert’s Parabola (Figure 5). Importantly, it demonstrates that the producing resource (31.1 Gb) – not the ultimate resources (36.0 Gb) – best calibrates the Hubbert Parabola from 1977 to 2007. Indeed this distinction argues that all the ultimate resources may not contribute to production in the critical plateau and early decline phases, but moreso in the advanced decline phase. So far the Norwegian illustration has not shown time explicitly in the equations – a matter that is accounted for below.
Norway’s Maximum Depletion and Annual Decline Rates
Time can be factored in the model by considering small time increments (dT) required to produce small amounts of oil (dP). Returning to Equation 8, substitute depletion D = PC/R and a small production rate dP/dT instead of PA:
inverting both sides of the equation yields:
The time interval (T) from the mid-depletion is calculated by adding the time increments dT (integrate or sum over time; de Sousa, 2008). Two commonly cited yearly rates (percentages) are introduced here to describe how time stretches and contracts the Hubbert Model.
The first is the maximum depletion rate (DM in percent per year), here defined as the peak rate (PM multiplied by 100) divided by the producing resource (R). During Norway’s peak year in 2001, DM was 3.89%/y (DM = 100 x 1.21/31.1 Gb; Table 1). As seen in Figure 5, over the 1996–2005 plateau, one-year time steps approximately depleted the maximum rate (i.e. annual PA and peak PM production are nearly equal in the plateau).
The second commonly cited rate is the irreversible annual decline (DA sometimes referred to as year-to-year decline or natural decline; e.g. Skrebowski, 2006a, b, c; 2007; Jackson, 2008); it is the percentage fall of annual production relative to the previous year. In Table 3, the time interval from peak year (T) and annual decline are shown for DM = 1.0%/y. For other maximum depletion rates, the time interval (T) changes in inverse proportion (for example for DM = 2.0%/y, divide time by 2.0) and annual decline in direct proportion (for DM = 2.0%/y, multiply decline by 2.0).
For Norway (Figure 5), the post-peak years from mid-depletion in 2001 to 95% depletion in ca. 2020 are calculated from Equation 10. Also shown are the average annual decline rates (DA) for every 5% depletion increment. The actual decline trajectory between 2001 and 2007 is comparable to the model’s prediction. The Norwegian model predicts that the annual decline rate increases from 0.8%/y shortly after the peak, to c. 6.6%/y in 2007 reaching c. 10%/y in the next decade. The model’s decline trajectory is predicted to be time-symmetrical to the build-up when reflected by the peak year 2001. This is approximately the case so far; for example 2007 (six years post-peak) is mirrored with 1994 (seven years pre-peak).
Having noted these model predictions for annual decline (DA), it is emphasized that the decline rate for mature basins may not necessarily follow the model’s prediction (Nehring, 2006a, b, c). As noted earlier, Norway’s producing resource (31.1 Gb) may be as much as 13.6% less than the ultimate resources (36.0 Gb, J. Laherrère, 2008, written communication). This difference implies that additional and yet-unproved resources may go into production in the future rendering the decline rate less steep and causing the parabola to become less symmetrical over longer time intervals. This pattern may be true in general, and particularly when oil prices increase and/or advanced recovery technology is applied.
Hubbert Model for the United Kingdom (UK)
Whereas Norway’s production history closely matches the Hubbert Model, the UK’s does not. Although both countries started producing from the North Sea at about the same time (Figure 2 and Table 2, BP, 2008), the UK’s production history has a much steeper build-up, an early 1985 peak, followed by a sharp valley between 1989–1993. The production valley after 1985 was in part a consequence of the tragic Piper Alpha accident and the subsequent safety measures, which took the industry several years to implement before returning to full production (Zittel and Schindler, 2003). It also resulted from reduced production in the Brent field when gas-producing facilities were installed (J. Laherrère, 2008, written communication). Production returned to the plateau level in 1993, peaked in 1999, after which it started to decline.
The UK’s end-2007 produced and proved were respectively 24.9 and 3.6 Gb totaling 28.5 Gb in known reserves, compared to Norway’s 30.7 Gb (Table 1, BP, 2008). In Figures 6 and 7, the UK’s normalized production, Hubbert Line and Parabola are plotted. The UK’s producing resource (R), based on the 1994–2007 straight line, was found to be 30.6 Gb, which is 2.1 Gb greater than the known reserves (28.5 Gb) (Table 1). The maximum production is predicted at 1.02 Gb/y in 1996 and compares better with the second peak in 1999 at 1.06 Gb/y.
As in the case of Norway, the UK’s producing resource is again substantially less (12.5%) than the ultimate recoverable resources (EURR) of 35.0 Gb obtained by J. Laherrère (2008, written communication). The UK’s Hubbert Parabola predicts production to fall to c. 700 Kb/d by 2015 and c. 100 Kb/d by 2030. These predictions are unlikely to be true because by 2015–2030 currently marginal resources may become commercially viable to produce. The likelihood of a less steep decline is reinforced in the IEA’s draft of the World Energy Outlook 2008 obtained by London’s Financial Times (C. Hoyos and J. Blas, October 29, 2008): the report predicts that the UK’s North Sea oil production by 2030 will be about 500 Kb/d – not 100 Kb/d.
Multimodal Production Curve
The two peaks seen in the UK’s production history characterize it as bimodal, whereas Norway’s is monomodal (Figure 2). Using only the UK’s Production Line before 1994 would have substantially under-estimated the producing resource at c. 10 Gb (Figure 6). This demonstrates an important pitfall that occurs when it is assumed that all the resources are in production. Similar multimodal production curves occur in many countries due to disruptions caused by wars, disasters, sabotage, strikes, sanctions, quotas, embargoes, price variations and other non-geological factors. It may also occur in politically stable regions, such as the USA’s San Joaquin Valley and Permian Basin, due to variations in the price of oil, advanced recovery (e.g. impact of waterflooding) and other technological advances (Nehring, 2006a, b, c).
Nevertheless an important observation to note here is that the UK’s 1993–2007 production still tracked the Hubbert Model quite faithfully over the most critical second plateau and early decline phase (Figure 7). This observation is relevant to the later discussion of the World’s production curve, which is multi-modal (see Figures 15 and 17).
Comparison of Hubbert Models for Norway and UK
The UK’s maximum annual depletion rate (DM) was 3.56%/y compared to Norway’s 3.89%/y. Norway’s plateau (> 91% of Peak) lasted ca. 10 years (1996–2005); in contrast the UK attained two plateaus (1984–1987 and 1994–2001) for ca. 12 years in total (Figure 2, Table 1). At end-2007, the UK is at 81.3% depletion and Norway at 72.3% of the producing resource. Post-peak, both countries are tracking the model’s decline trajectory; at end-2007, the UK was at 56.2% and Norway at 74.8% of peak production. The close tracking of the model’s decline-depletion curve is an important result – it appears to be independent of the country’s build-up profile, or whether production is monomodal or bimodal.
For the North Sea, reserve growth has contributed significantly for oil and moreso for natural gas reserves, with for example the giant Ekosfisk field surpassing its original estimated recoverable reserves (Klett and Gautier, 2005; T. Ahlbrandt, 2008, written communication). Nevertheless, taken together the production of the two countries has declined from 2.21 Gb/y in 1999 to 1.53 Gb/y in 2007, and is predicted by the model to reach c. 0.70 Gb/y by 2015 (Table 2). The predicted 1999–2015 decline amounts to 1.5 Gb/y (4.1 Mb/d); if true this loss would require new production that nearly equals the annual crude oil production of Iran, OPEC’s second largest producer in 2007.
Hubbert Model for Three Onshore Middle East Countries
To illustrate the Hubbert Model for onshore countries that have different reserves, resources and production histories, three peaked Middle Eastern countries (Oman, Syria and Yemen) are considered (Figure 8 and Table 2, BP, 2008). In Figures 9 to 14 and Table 1, their productions are compared to the model’s graphs. The Hubbert Line became straight after c. 20% depletion for Oman, and 30% for Syria and Yemen. At end-2007, the ratio of annual-to-peak production (PA/PM) for Oman was 74.7%, Syria 66.1%, and Yemen 73.5%. In all three cases the model matches the plateau and early decline phases closely.
A notable difference between the three countries can be observed for the maximum depletion rate at the peak (DM). Yemen with the highest at 4.82%/y has the briefest plateau (six years from 2000 to 2005) and highest annual decline rate (DA predicted to reach 9.8%/y in 2008, Figure 14). Syria’s DM = 3.72%/y corresponds to an 8.5-year plateau (mid-1993 to end-2002) and a maximum decline rate of 8.7%/y in 2008 (Figure 12). Oman’s DM is the least at 2.62%/y, and so the plateau was more long-lived (12 years from 1994 to end-2005) and the maximum decline rate less steep and predicted to reach 4.5%/y in 2008 (Figure 10).
The above comparisons illustrate that the model’s annual decline rate (DA) varies by country (Table 1, Figures 5, 7, 10, 12 and 14) and over time (see Table 3 and its footnote). The higher the maximum depletion rate (DM = PM/R) over the plateau, the shorter its duration and the steeper the annual decline rate. Significantly, the time history of production after the build-up phase is predicted to only depend on the peak production level (PM) and the producing resource (R), or equivalently their ratio, the maximum depletion rate (DM) (see Table 3). This prediction is probably more true for the two North Sea countries than for the onshore Middle Eastern countries.
Unlike most offshore production, onshore production generally includes opportunities for additional and more expensive projects (enhanced oil recovery - EOR, NGL from undeveloped wet-gas reservoirs, heavy and/or sulfurous oil reservoirs). These future projects are booked as proved reserves but are not yet apparent in the historical data; therefore the producing resource R is consistently less than the known reserves (Table 1): for Oman 12.1% (12.4 versus 14.1 Gb), Syria 18.1% (5.9 versus 7.2 Gb), and Yemen 35.4% (3.4 versus 5.26 Gb). It is also consistently less than the ultimate recoverable resources (EURR) as estimated by the creaming curve (J. Laherrère, 2008, written communication): for Oman 22.5% (12.4 versus 16.0 Gb), Syria 21.3% (5.9 versus 7.5 Gb), and Yemen 15.0% (3.4 versus 4.0 Gb).
These comparisons illustrate another pitfall in the Hubbert Line technique – namely that historical production data may not account for significant undeveloped but proved and/or probable reserves. In such cases, the annual decline should again become less steep as the new projects go onstream. Indeed the predictions made by Syria’s Minister of Petroleum and Mineral Resources S. ‘Alaw (MEES, 2008) in September 2008 highlight this pitfall. He stated that Syria had recoverable oil reserves of 7.0 Gb, or 5.0 Gb greater than reported in BP (2008). Adding the produced (4.7 Gb) and proved (7.0 Gb) raises the known reserves to 11.7 Gb, or c. 4.0 Gb greater than the estimated ultimate resources of 7.5 Gb (J. Laherrère, 2008, written communication). Moreover, the Minister stated that oil production in 2008 would increase by 5 Kb/d relative to 2007 thus reversing decline, and would remain above 320 Kb/d until 2020. His 2020 prediction for production is more than three times greater than the one predicted in Figure 12.
HUBBERT MODEL FOR OTHER COUNTRIES AND BASINS
The Hubbert Model for the five countries considered so far offered useful insights regarding their reserves, resources and production. In all cases their E&P activities are driven by production-sharing agreements (PSA), which result in production rapidly converging on the Hubbert Model. In general, the model works well for regions that have undergone major early development, have a geographically limited resource base and are in an early phase of reserves growth efforts (T. Ahlbrandt, 2008, written communication). It will not generally apply to countries that do not meet some of these preconditions; some examples are Algeria’s Ghadames Basin, Neuquen Basin in South America, Brazilian and US offshore where large deepwater discoveries have recently been made (Ahlbrandt and Klett, 2005), or the USA’s San Joaquin Valley heavy oils and Permian Basin (Nehring 2006a, b, c).
Another important example where Hubbert’s Model does not apply is represented by the Gulf-5 countries (Iran, Iraq, Kuwait, Saudi Arabia and the United Arab Emirates), which together account for 58% of the reported World proved reserves (c. 720 Gb; Table 4, BP, 2008). Their production is multimodal and mainly been determined by non-geological factors – described as an undulating plateau (T. Ahlbrandt, 2008, written communication). Their known reserves are currently at c. 30% depletion – some more, some less. For these countries, the historical production data do not plot as a straight Hubbert Line and cannot be used to predict future production profiles or estimate the producing resources.
Iran’s Production, Reserves and Resources
Iran’s production illustrates to some degree some of the uncertainties and errors that occur when applying the Hubbert Model to countries with undulating plateaus (see review of Iran inAl-Husseini, 2007). Iran’s production ramped-up quickly in the 1960s and early 1970s reaching an early peak of 6.02 Mb/d in 1974. It plateaud in the range of c. 5–6 Mb/d until 1979, after which it dropped to 1.56 Mb/d in 1981 during the Iran-Iraq War. Since the end of the War, Iran’s production has risen steadily reaching 4.4 Mb/d in 2007 (crude oil and condensates). Iran’s E&P strategy is not driven by PSA contracts; nevertheless, the country seeks to continuously maximize production and reserves. By 2007, c. 65 Gb was produced and remaining proved reserves were 138.4 Gb, totaling 203.4 Gb in known reserves (BP, 2008). The reserves are reported as primary and secondary, the latter mostly involving gas-injection EOR projects in mature reservoirs.
Contrary to the Hubbert Model prediction, the 1974 peak was attained when cumulative production was only c. 10% (c. 20 Gb), compared to 50% depletion in the model. When the Hubbert Line was tentatively applied to Iran’s 1991–2007 data, the producing resource (R) was found to range between 156–177 Gb, some 13–23% less than the known reserves (203.4 Gb). The peak rate at mid-depletion was found to vary from 4.5–4.7 Mb/d and to occur in ca. 2020. These results suggest that it is unlikely that Iran’s production will reach the 5–6 Mb/d 1970s level. This prediction is supported by reports that Iran’s annual natural decline in the main mature reservoirs ranges between 250–500 Kb/d– between 5.8–11.6%/year (see references inAl-Husseini, 2007). This range of decline is large enough to nearly offset new production.
Maximum Past to Current Production Ratio
In Table 4, oil-producing countries are ranked in terms of the maximum level of past production compared to their production in 2007 (2007/Past Ratio); for example, Iran’s 2007-to-1974 ratio is 72.6% (100 x 4.40/6.06). Also shown are reserves and production statistics (BP, 2008), which provide an approximate overview regarding which countries may have production still rising, on-a-plateau or in decline. Countries with year 2007 marking maximum production (2007/Past Ratio = 100%) are clearly in the rising mode. Those with 2007 production at better than 90% of their past maximum level are probably on their plateau and may be capable of raising production. Countries with ratios of 80–90% are probably on the plateau, but unlikely to increase production. Those with ratios of less than 80% may be either in the late plateau or in decline.
Iraq with proved reserves of 115 Gb is specifically noted for having an exceptionally low ratio of 61.5%; little doubt exists that the past peak level of c. 3.5 Mb/d can be significantly surpassed. Table 4 shows that nearly 62% of total 2007 World production is from countries that have a potential to increase production (2007/Past > 80%) and these hold a 54% share of World reserves (excluding Canadian oil sands). Another 38% of 2007 production is from countries with ratios of less than 80% corresponding to 46% of reported reserves; these countries are unlikely to increase their production (except for Iraq, which accounted for a production share of 2.7% in 2007).
PRODUCTION BASE CASE FOR WORLD CONVENTIONAL PETROLEUM LIQUIDS
The historical productions of many countries do not plot along a straight Hubbert Line, and therefore the World’s producing resource cannot be determined by adding up estimates for individual countries. Instead this section starts out by applying the Hubbert Line to total World production in order to estimate the producing resource (R), peak and plateau production levels and peak year (at mid-depletion); these results are referred to as the Production Base Case – and compared to those obtained by other analysis.
Annual and Cumulative Production Data Base
The World’s annual production data (PA) are listed in Table 5 and plotted in Figure 15, along with the price of oil in 2007-adjusted US dollars (BP, 2008). The World’s cumulative production (PC) was calibrated at end-1997 at 838 Gb (Ivanhoe, 2000) and BP’s annual production data were used to calculate PC for other years. The resulting PC compare closely with published ones for other years; for example within 1–4 Gb to the estimates by Hubbert (1969) and the EIA (1985, 1987), by c. 2% (17 Gb) for 1993 (Shell data inRomm and Curtis, 1996; Edwards, 1997) and 1% (10 Gb) for end-2004 (de Sousa, 2008) and end-2005 (R. Nehring, 2006, AAPG Hedberg Research Conference, November 2006).
Base Case Estimate for Producing Resource (R)
The World’s production profile is multimodal (Figure 15) and somewhat comparable to that of the UK (compare Figures 2 and 15). The main build-up phase occurred between 1950–1974 when many giant fields were brought into production; between 1960–1974 production grew c. 2.3 Mb/d annually while oil prices remained between $10–15/barrel (in 2007 dollars). This phase ended with a 3.0 Mb/d drop in 1975, due mainly to the Arab oil embargo. Following the 1975 valley, the years 1976–1979 saw the oil price quadruple and the production trajectory turning upwards. A second valley occurred between 1979–1985 due to several factors including the Iran-Iraq War (1980–1986), as well as peaks or plateaus in many countries. These included the USA’s Lower-48 States 1970 peak, total USA (with Alaska) peak in 1985, the 1974–1979 Gulf-5 plateau (Iran, Iraq, Kuwait, Saudi Arabia and the United Arab Emirates). In the 1970s the USA and Gulf-5 alone accounted for 50% of World production.
In Figure 15, a new build-up trend is evident between 1985–2007; it shows that production growth was halved relative to the 1960–1970s (from 2.3 to 1.1 Mb/d) even though prices doubled on average (from $10–15 to $25–35/barrel). When the data is plotted along the normalized Hubbert Line, the 1990s–2007 interval forms the most current straight-line trend, and in particular the 1995–2007 data was used to estimate the World’s producing resource as 2,860 Gb (Table 1, Figure 16). This estimate varied by only ± 50 Gb when the regression was started from 1993 through 1997 and ended in 2007. Estimates for the producing resource started from 1998 and later years varied by as much as 2,860 ± 300 Gb. The Production Base Case estimate of c. 2,860 Gb was chosen as the average for the overall interval 1990s–2007. It is 351 Gb (14%) greater than the end-2007 known reserves of 2,509 Gb, consisting of 1,119 Gb produced, 1,238 Gb proved and 152 Gb for undeveloped Canadian oil sands (BP, 2008; Table 1 and Figure 1).
Comparison of World Resource Using Hubbert’s Model
The Base Case estimate for the producing resource is substantially greater than those obtained with the same Hubbert Line technique by Deffeyes (2005) at 2,013 Gb, and de Sousa (2008) at 2,165 Gb. This discrepancy is apparently due to their lines being applied to a much longer time interval, which included years that reflected constrained production. The time interval 1983–2003 used by Deffeyes (2005) was here found to predict a resource of 2,046 Gb (Figure 16). This interval included the later part of the 1980–1986 Iran-Iraq War, which reduced supplies by some 5–6 Mb/d for several years. It also included the period of reduced global demand, which in turn caused OPEC to cut production by more than 10 Mb/d from about 1981 until 1993. Moreover, due to low oil prices and demand, the non-OPEC countries also substantially reduced their E&P activities during most of the late 1980s and 1990s.
Clearly the production data is time-dependent and in particular the 1980s were unrepresentative of the Hubbert Line; especially when the 1990s–2007 data clearly form a distinct new straight-line trend (Figure 16). The 1990s-2007 average straight line suggests that the World’s production is following a Hubbert Parabola with an estimated producing resource of c. 2,860 Gb (Figure 17), a quantity that is more consistent with geological studies noted below.
Comparison of Base Case Producing Resource to Geological Studies of
Estimated Ultimate Recoverable Resources (EURR)
USGS 95% Confidence EURR
The most recent study of conventional petroleum resources (crude oil, lease condensates and NGL) was completed in 2000 by the United States Geological Survey (USGS) and summarized by Ahlbrandt et al. (2005). The USGS does not predict future production, peaks or plateaus. They estimated unknown resources (undiscovered and reserves growth) for the period 1996 to 2025, and used IHS data for end-1995 known reserves (produced 710 Gb, proved 959 Gb) but did not include Canadian oil sands. By adding 152 Gb for the latter, the known reserves for end-1995 are 1,821 Gb. In Table 6, the USGS unknown resources for their three cited probabilities are added to BP’s (2008) quantities for end-1995 known reserves. The Base Case producing resource (2,860 Gb) is just 3% greater than the 95%-confidence ultimate recoverable resources (EURR = 2,770 Gb; USGS-95% for short), involving an unknown resource of 805 Gb.
The USGS-95% unknown resource (805 Gb) may prove to be approximately correct by 2025, the ending year for their projection (Klett et al., 2005). Consider that between end-1995, when the USGS study was closed, to end-2007, known reserves (produced plus proved, excluding Canadian oil sands for consistency with USGS criteria) increased by 544 Gb from 1,813 to 2,357 Gb (BP, 2008). Therefore, of the unknown resource of 805 Gb, 544 Gb was accounted for by end-2007, and the difference of 261 Gb remains to be added between 2008–2025 as undiscovered and growth. This translates to adding c. 14.5 Gb annually for the subsequent 18 years, which is achievable if the reserves additions of c. 20 Gb in 2005 are maintained to 2025 (Chew, 2006, based on the IHS data base). Noteworthy is that of the 20 Gb in added reserves in 2005, 12 Gb was discovered whereas the remainder was attributed to reserves growth.
The Base Case producing resource is 21% less than the USGS Mean EURR (2000; Ahlbrandt et al., 2005) of 3,634 Gb (Table 6) by end-2025. It is 13% less than the estimated resources of crude oil, lease condensates and NGL reported in Edwards (1997; 3,298 Gb, Table 7) for the end of this century. The Base Case falls in the middle range of the 136 estimates compiled by Ahlbrandt (2004, 2006; see also National Petroleum Council, 2007) and below estimates for crude oil only by two oil companies (reported at the meeting of the National Academy of Science, Washington D.C., USA, October 20–21, 2005): 3,200 Gb (S. Nauman, ExxonMobil) and 3,000 Gb (D. Paul, ChevronTexaco). Jackson (2006, Table 8) estimated the ultimate resources for conventional petroleum liquids at 3,673 Gb, essentially the Mean USGS EURR. Taken together with unconventional petroleum liquid resources of 1,148 Gb, he estimated total oil resources at 4,820 Gb.
In contrast to the above noted higher estimates of resources, C. Campbell (2008, written communication) considered regular conventional oil as being the primary category of petroleum liquids that is relevant to consider in the prediction of peak oil. He defines this category to exclude (1) oil from coal and shale, (2) bitumen (oil sands), (3) extra-heavy and heavy oil (less than 17.5° API), (4) deepwater oil (> 500 m), (5) polar (Arctic) oil, and (6) NGL from gas plants. He estimates the World’s ultimate reserves of regular conventional oil is about 1,900 Gb.
J. Laherrère (2008, written communication) estimated the petroleum liquids resources at between 2,700 and 3,000 Gb as follows: (1) crude oil at 2,000 Gb, (2) NGL and gas-to-liquids at 250 Gb, (3) refinery gains, oil sands and coal-to-liquids between 150–250 Gb, and (4) extra-heavy oil between 300–500 Gb. His estimate for crude oil and NGL (2,250 Gb) added to BP’s oil sands (152 Gb) amounts to about 2,400 Gb compared to 2,860 Gb for the Base Case. Moreover, he considered estimates as high as 3,000–4,000 Gb to be very unlikely.
The focus by Campbell and Laherrère on regular conventional oil and/or liquids is intended by these authors to emphasize the much greater costs and lead times involved in producing the other categories. They argue that expensive resources may only reduce the decline rate following the peak, and these realities are typified by statements made by France’s Total oil company Chief Executive C. de Margerie. He reported that in 2004 a 12.5% return on investment could be achieved at a price of $20/barrel; however in 2008 the marginal cost for one barrel reached $70 (e.g. offshore Angola) and c. $90 for heavy oil (The Times, London, September 12, 2008). These higher costs reflect high inflation in the industry – at 20% in 2008.
Higher costs also affect the major producers of regular oil. Washington consultancy PFC Energy reported that Saudi Arabia required average oil prices at c. $55/barrel in 2008 to balance external accounts. According to PFC and the International Monetary Fund (IMF), the costs were higher for Iran, Nigeria, Russia and Venezuela – at between $68 to $94/barrel (B. Lewis and S. Webb, Reuters, September 7, 2008; N. King Jr. and S. Swartz, Wall Street Journal, October 10, 2008).
Early Production Plateau at 39% Depletion
The Base Case implies the producing resource is 39% depleted at end-2007 (produced/resource = 100 x 1,119/2,860) and within the early part of the plateau (Figure 17). This level falls halfway between the 32–46% depletion range for conventional petroleum liquids estimated by Chew (2006). It is 10% less than the depletion estimate by Zittel and Schindler (2007). The 39%-depletion of the producing resource is well beyond the level at which the Hubbert Line became an accurate predictive tool for four peaked countries studied here: generally past the 20–30% range (Figures 4, 9, 11 and 13). In Figure 16, the 1995–2007 straight-line segment corresponds to World depletion increasing from 27% and 39%, well within the range of prediction established in all but the UK’s 44% exceptional case.
Peak Year and Maximum Sustainable Production
According to the Base Case, the maximum production at mid-depletion is predicted at 31.3 Gb/y (85.7 Mb/d, relative to 81.5 Mb/d at end-2007; BP, 2008) and to occur in 2016 (Equation 10). When different upwards-trending line segments were separately considered they pointed to between 27.5 and 31.3 Gb/y (75.3–85.7 Mb/d), regardless of price ranges (2007 dollars): 1975–1979 at $40, 1986–2003 at $25–35 and 2004–2007 at $50–70. The predicted peak differs somewhat from predictions by several analysts:
Edwards (1997): crude oil at 88 Mb/d in 2020, and with NGL at 96 Mb/y in 2025.
Association for Study of Peak Oil (www.peakoil.net): at 90 Mb/y in 2020 for conventional petroleum liquids.
R. Nehring (Chairman of the AAPG Hedberg Research Conference, held in November, 2006): 90–100 Mb/d plateau extending from 2020–2040 for the Low Resource case of conventional petroleum liquids (from R. Nehring, 2007, reported in Kerr, 2007, and Petzet, 2007). For 2020, Nehring stated: “I have a hard time seeing us get to 90 Mb/d … seeing us ever reaching 100 Mb/d requires a major stretch on my part” (inAndrews, 2007).
Jackson (2006): 95 Mb/d plateau between 2030–2045 for conventional petroleum liquids production and for all liquids at 130 Mb/d between 2030–2050.
Total’s CEO C. de Margerie stated (The Times, London, September 12, 2008): “We [Total] still keep our target that peak production will be below 100 Mb/d. The figure we are using is much more 95 Mb/d.” This estimate is relative to 87.0 Mb/d in 2007 compared to 81.5 Mb/d (BP, 2008) and implies a net gain of 8.0 Mb/d.
The 2016 peak year is qualitatively consistent with the statement by Shell’s CEO J. van der Veer: “Shell estimates that after 2015 supplies of easy-to-access oil and gas will no longer keep up with demand” (The Times, London, January 25, 2008).
MEGAPROJECTS & DECLINE TECHNIQUE
The predictions of the Base Case (Figures 15–17) can be further assessed by comparison to those from the Megaprojects & Decline technique pioneered by Skrebowski (2006a, b, c; 2007). It involves adding-up future projects to the existing production, after the latter is discounted for natural decline. Whereas this technique bypasses assumptions regarding reserves and resources, it is more sensitive to oil prices, project delays and how to determine a global decline rate.
Future Megaprojects for Conventional Petroleum Liquids
Skrebowski (2006a, b, c; 2007) compiled new petroleum liquids projects (including gas-to-liquids) with maximum production exceeding 40 Kb/d and identified about 32.4 Mb/d coming onstream between 2005–2014 (Table 9). His early 2007 compilation did not include some giant fields discovered since then, especially in deep offshore Brazil (e.g. Tupi field with estimated reserves of 5–8 Gb in 2007, and Iara field with 3–4 Gb in 2008). He found that from discovery-to-production averaged six years for 1997–2006, and increased to about eight years for projects discovered after 1997 and coming onstream between 2007–2012. He concluded that major discoveries in 2008 would be unlikely to come onstream before the middle of the next decade.
In regards to deepwater and Arctic regions, T. Ahlbrandt (2008, written communication) noted fields in these settings may take much longer than a decade to come onstream. He stated that the latest USGS study (Gautier et al., 2008) predicted the Arctic region holds 22% of the World’s undiscovered conventional petroleum (Mean estimate of c. 90 Gb oil equivalent - includes dry gas), basically consistent with the USGS 2000 assessment. However, due to the very difficult logistics, the USGS in 2000 gave a zero probability in the 95%-confidence scenario to production from the East Greenland Province before 2025, a conclusion shared by Cavallo (2002). Ahlbrandt predicted that the Barents Sea will be one of the first significant new Arctic provinces to be developed, but set no specific date for start-up. These considerations suggest ruling out Arctic megaprojects coming onstream before 2025.
Decline Rates for Existing Production of Conventional Petroleum Liquids
Skrebowski (2006b, 2007) studied the production histories of 108 giant fields (each with more than 2.0 Gb of original reserves), and reported that 47 fields were in decline, 42 were not, 7 were undeveloped and 12 uncertain. Taken together with five additional fields, these giants account for about half of the World’s production and contained two-thirds of its reserves. He also reported that 28% of the World’s production is from countries with declining production, and concluded that the average decline rate for end-2006 production is c. 5.0%/y.
Reporting in a press release on a more comprehensive proprietary CERA-IHS study, Jackson (2008) summarized the production characteristics of 811 giant oil fields (each with more than 300 Mb of original reserves). He reported that these fields account for two-thirds of World’s production in 2007, of which 41% is from declining fields. The remaining 59% production was from fields that are still either in the build-up phase or on their plateaus, and these account for 63% of proved reserves in the 811 fields. He concluded that the aggregate decline rate for all these fields is 4.5%/y.
In 2008, the IEA assembled a team of 25 analysts to further assess the World’s top 800 producing oil fields using the IHS data base. They estimated the average rate for fields-in-decline at 9.1%/y – a rate that decreases to 6.7%/y when companies invest in more wells and techniques (IEA World Energy Outlook 2008, IEA Fact Sheet). According to the IEA’s Executive Director N. Tanaka, the global average decline in 2008 was 5.2%/y – up from 4.0% in 2007. The IEA concluded that around 7.0 Mb/d of additional capacity – over and above the 23.0 Mb/d that will come from 2008–2015 megaprojects – needs to be brought on stream just to hold global production steady. The IEA’s conclusions essentially duplicate those obtained by Skrebowski (2006a, b, c, 2007): decline rate of 5.2%/y versus 5.0%/y and total megaprojects of 30.0 Mb/d versus 32.4 Mb/d by 2015.
Decline rates of 4.5–9.1%/y are very substantial and choosing an average rate for the World’s existing production may be misleading. For the five peaked countries, considered in this paper, natural decline was found to vary according to their maximum depletion rates and with time following the plateau (Table 1). For 2008, it differed by country and predicted to range between 4.5 and 9.8%/y for all production. No attempt was made to distinguish between decline to existing production and how much was compensated for by new projects. This issue is illustrated, for example, by Iran’s production where natural decline in the mature producing reservoirs ranges between 5.8–11.6%/year. Nevertheless, the country’s production is infact increasing at a rate of c. 100 Kb/d annually as new reservoirs (crude oil and condensates) come onstream, while infill wells are being drilled and recompleted in mature ones. Moreover, many supergiant and giant fields in the Arabian Gulf countries are not in decline and it is unclear how this aspect is accounted for by various analysts. This suggests that the average decline to apply to existing World production should favor a lower estimate of perhaps 4.5%/y.
Net Production and Decline Rate
Skrebowski (2006b, 2007) concluded that based on balancing megaprojects (32.4 Mb/d) against his average 5.0%/y decline for existing 2006 production (c. 81.5 Mb/d for crude oil, condensates and NGL in his study) that only c. 4.0 Mb/d net production would be added by 2011. Because in subsequent years decline would overtake new production, he forecast World peak for conventional petroleum liquids to occur at c. 85.5 Mb/d in 2011 or so; nearly equal to – and five years earlier than – the prediction of the Base Case (85.7 Mb/d in 2016).
To illustrate the Megaprojects & Decline technique at 4.5%/y decline (Jackson, 2008), Table 9 shows the combined production increments from new projects (Skrebowski, 2007) assuming no time delays occur. The 4.5%/y was only applied to existing production, starting at end-2004 when it was 80.3 Mb/d (BP, 2008). For example, for end-2010, the total production PA(2010) is obtained by discounting 80.3 Mb/d and adding the total of new increments for six years (2005 to 2010):
This example illustrates that a decline rate of 4.5%/y over six years reduces existing production by 24% (80.3 - 60.9 = 19.4 Mb/d), which offsets nearly 81% of the new production increments (23.8 Mb/d). The application of this approach predicts a maximum production of 86.2 Mb/d in 2012 (Table 9). Assuming higher decline rates (e.g. 5.2%/y of the IEA, 2008) would reduce the maximum production and bring the peak year forward. This led the IEA to conclude: “Even if oil demand was to remain flat to 2030, 45 Mb/d of gross capacity – roughly four times the current capacity of Saudi Arabia – would need to be built worldwide by 2030 just to offset the effect of oilfield decline.”
UNCONVENTIONAL PETROLEUM LIQUIDS PRODUCTION BY 2030
In their draft World Energy Outlook 2008 report the IEA projected the global supply of unconventional petroleum liquids to increase from 1.7 Mb/d in 2007 to 8.8 Mb/d in 2030, of which Canadian oil sands accounts for 4.0 Mb/d (C. Hoyos and J. Blas, Financial Times, October 29, 2008). R. Nehring (inAndrews, 2007) predicted that by 2020, Canadian oil sands could produce 4.0 Mb/d, Venezuela’s heavy oil 0.5–1.0 Mb/d and oil shale zero. In the present paper’s Base Case, Canadian oil sands were included in the producing resource implying only some 4.8 Mb/d would be added from other unconventional petroleum liquids (extra-heavy oil, gas-to-liquids, oil from coal, etc.). This translates to about 210 Kb/d being added annually for unconventional petroleum liquids by 2030.
Jackson (2008) reported that CERA’s 2007 global liquids capacity model stood at around 91.0 Mb/d, which is 9.5 Mb/d greater than actual production (BP, 2008). He predicted that World production capacity of conventional and unconventional petroleum liquids could climb from 91.0 to 112.0 Mb/d by 2017, resulting in a net gain of 21.0 Mb/d. CERA’s database of new field developments expected to come on stream in the next four or five years includes some 350 projects (120 OPEC and 230 non-OPEC) with gross annual contributions of approximately 3.0 Mb/d from OPEC and 3.5 Mb/d from non-OPEC countries. For the period 2008–2017, this implies adding c. 5.5 Mb/d annually on average in order to overcome a decline rate of 4.5%/y. It would total to 55.0 Mb/d in new production capacity (compared to 32.4 Mb/d for conventional petroleum liquids obtained by Skrebowski, 2007).
The EIA, in their International Energy Outlook (June 2008), predicted two scenarios for petroleum liquids production. For their reference scenario, the price of oil was projected between $75–100 (2007 dollars) between 2007–2030 and World production of conventional petroleum liquids (crude oil, lease condensates, natural gas plant liquids and refinery gains) increases by 21.0 Mb/d from 81.8 Mb/d in 2005, to 102.8 Mb/d in 2030. This scenario projected that by 2030 an additional 9.7 Mb/d could be produced from unconventional resources (oil sands, extra-heavy oils, biofuels, coal-to-liquids and gas-to liquids) for a total of 112.5 Mb/d. In their high-price scenario the price rises from $100 to $186/barrel almost linearly to 2030, and demand is curtailed to 99.3 Mb/d in 2030. Now unconventional petroleum liquids account for nearly 20% of total supply (19.0 Mb/d) and conventional ones decrease by 1.5 Mb/d to 80.3 Mb/d in 2030.
The EIA’s high-price scenario for 2030 conventional petroleum liquids (80.3 Mb/d) is consistent with the Base Case, which predicts 2030 production at 78.0 Mb/d (Figure 15). The Base Case includes Canadian oil sands (EIA’s unconventional) but not refinery gains (not included in BP’s production or reserves); they are of comparable magnitude and approximately balance out.
Historical production data from five countries with declining production (Norway, Oman, Syria, UK and Yemen, BP, 2008) were used to illustrate Hubbert’s Model. The model can be graphically presented by the Hubbert Line, and used in a straightforward manner to calculate the producing resource (R). The producing resource does not equal known reserves (produced plus proved) or the estimated ultimate recoverable resources (EURR). For the five countries it is between 12.5–22.5% less than the EURR. Importantly, it is the producing resource that closely calibrates the production trajectory – Hubbert Parabola – particularly over the late build-up, plateau and the critical early decline phase. In all but the UK’s special case, the Hubbert Parabola predicted the production trajectory after the producing resource was only 10–30% depleted, and well before the peak occurred at approximately 50% depletion. The difference between ultimate recoverable and producing resources (EURR - R) represents more marginal and costly production in the later and more advanced decline phase. These additional resources are likely to reduce the model’s predicted decline rate, particularly in times when oil prices increase.
With oil prices having spiked at $147/barrel in mid-2008, the debate over Hubbert’s World peak has peaked in its own right (Figure 15). This paper suggests that the crucial question to consider in this debate is: Which quantity of hydrocarbon volumes in the ground calibrates the World’s rate of petroleum liquids production to about 2030? The lesson learnt from the five peaked countries is that it is the World’s producing resource, not its known reserves or ultimate recoverable resources. This is not to say that the latter two quantities are not important. Instead it suggests that although great marginal resources undoubtedly occur in the World (deepwater, Arctic, unconventional petroleum liquids, etc.), their conversion into producing reserves requires great investments and a time frame that may be well beyond the next decade, especially if the price of oil is low (Hirsch et al., 2006; Hirsch, 2006).
To test this hypothesis the World’s Hubbert Line for conventional petroleum liquids (as reported by BP, 2008) was plotted and found to be a straight line since 1991 (Figure 16). The 1995–2007 segment converges on an average producing resource of about 2,860 billion barrels (Gb), corresponding to peak production at 31.3 Gb/year in 2016 (85.7 Mb/d relative to 81.5 Mb/d in 2007, BP, 2008). This hypothesis was considered as the Production Base Case and compared to results from several independent analytical techniques, each based on unrelated types of technical databases compiled by different authoritative organizations. The producing resource (2,860 Gb) compares closely to:
The Base Case’s peak (85.7 Mb/d in 2016) is close to the 86.2 Mb/d in ca. 2012 using the future Megaprojects & Decline technique (Skrebowski, 2007, Petroleum Review data base; Table 9) and the lowest average decline rate of 4.5%/y for existing production (Jackson, 2008, CERA-IHS data base).
These close results argue that the Base Case producing resource calibrates the World’s Hubbert Parabola through ca. 2025 or later (Figure 17), and if true then this quantity is about 39% depleted. This level is past the range of depletion for the accurate prediction of the peak/plateau and early decline in the studied countries (10–30%). The Base Case implies that net new production of conventional petroleum liquids will be c. 500 Kb/d annually to 2016, on average, and then unlikely to increase beyond.
The Base Case makes no assumptions about the price of oil, which at first seems to defy the laws of supply and demand. But this is not necessarily true; instead it suggests that the high oil prices since 2003 marked the entry into the supply-constrained World plateau for conventional petroleum liquids (Figure 15). In the plateau, high prices are required to reduce demand growth, while simultaneously insuring profitable returns from more costly resources. The EIA (2008) arrived at a similar conclusion in their high-price scenario predicting production of conventional petroleum liquids decreases to 80.3 Mb/d by 2030, compared to the Base Case’s 78.0 Mb/d in 2030 (Figures 15 and 17). These results argue for accelerated E&P investments in conventional and unconventional petroleum liquids and other energy forms, greater energy efficiencies (particularly in the transportation sector, which consumes nearly 70% of petroleum liquids) and other measures aimed at meeting the World’s demand for energy.
The author thanks Thomas Ahlbrandt, Hassan I. Al-Husseini, Sadad. I. Al-Husseini, Colin Campbell, Robert Hirsch, Jean Laherrère, Joerg Mattner, Richard Nehring and Karen Wagner for their important comments and suggestions, which greatly improved the paper. The interpretations of the results presented in this paper may not reflect their views in part or completely. The author regrets that attempts to contact K. Chew and P. Jackson (CERA-IHS) and Chris Skrebowski (Petroleum Review) were not successful, and hopes that their studies have been faithfully reported in the paper. GeoArabia’s Arnold Egdane is thanked for designing the paper.
ABOUT THE AUTHOR
Moujahed Al-Husseini founded Gulf PetroLink in 1993 in Manama, Bahrain. Gulf PetroLink is a consultancy aimed at transferring technology to the Middle East petroleum industry. Moujahed received his BSc in Engineering Science from King Fahd University of Petroleum and Minerals in Dhahran (1971), MSc in Operations Research from Stanford University, California (1972), PhD in Earth Sciences from Brown University, Rhode Island (1975) and Program for Management Development from Harvard University, Boston (1987). Moujahed joined Saudi Aramco in 1976 and was the Exploration Manager from 1989 to 1992. In 1996, Gulf PetroLink launched the journal of Middle East Petroleum Geosciences, GeoArabia, for which Moujahed is Editor-in-Chief. Moujahed also represented the GEO Conference Secretariat, Gulf PetroLink-GeoArabia in Bahrain from 1999-2004. He has published about 30 papers covering seismology, exploration and the regional geology of the Middle East, and is a member of the AAPG, AGU, SEG, EAGE and the Geological Society of London.