HUBBERT REVISITED — Deepwater oil discovery rate may have peaked; production peak may follow in 10 years

July 26, 2004
Deepwater exploration and production is undoubtedly the petroleum industry's greatest achievement.

Deepwater exploration and production is undoubtedly the petroleum industry's greatest achievement.

Major oil companies often compare this activity to that of putting a man on the moon, while the US Geological Survey and International Energy Agency refer to deepwater provinces as among the world's most promising sources of oil in the world, with ultimate reserves potential greater than 100 billion bbl of oil.

Since deepwater exploitation (defined in this study as E&P in water depths of 500 m or more) began in the mid-1970s, over 1,800 deepwater exploration wells have been drilled in 70 areas worldwide, resulting in the discovery of 47 billion bbl of oil (estimated as of yearend 2002). However, just four provinces, or the Big Four (Brazil, US Gulf of Mexico, Angola, and Nigeria), account for nearly all of the total exploration wells drilled and oil reserves discovered.

With the help of great technological advances, global deepwater oil production has risen almost every year since first oil was produced in more than 500 m of water in 1989 in the Gulf of Mexico. In 2003, global deepwater oil production accounted for 3.6% of world oil production, most of which also came from the Big Four provinces, but deepwater oil production is set to grow rapidly in the next 5 years as viable projects, particularly in the Big Four, are brought on stream.

However, there are good reasons to believe that the ultimate reserve potential (oil discovered plus yet-to-find, or YTF) of the Big Four provinces will not substantially exceed that which has been found to date.

A top-down assessment of 30 years of exploration efforts and recent trends suggests that the most prospective targets in the Big Four have been discovered or explored either by drilling and-or by 3D seismic. More importantly, from a supply-demand perspective, peak deepwater oil production also is estimated (Colin Campbell) to take place around the beginning of the next decade, never to rise again.

The objective of this article is to present the key conclusions of a multidisciplinary appraisal of deepwater Angola, Brazil, Gulf of Mexico, and Nigeria that integrates well, geological, and field data to provide an estimate for 1) ultimate oil reserves potential, in particular YTF, and 2) peak oil production for each of the Big Four provinces.

Methodology

The database for this study comprises official sources, industry announcements, consultant reports, and published information.

Discovered oil reserves have been estimated based on field-by-field data available to yearend 2003 and comprise proven and probable oil reserves (2P) for each oil or oil and gas discovery. YTF oil reserves have been estimated by extrapolating the hyperbola of cumulative oil reserves discovered in each province to yearend 2003 plotted against cumulative exploration wells drilled.

The underlying principle, used by exploration teams and mastered by Jean Laherrère, is that once the larger discoveries have been found (which happens early), they set the parameters of the hyperbola that may be extrapolated to the smallest discovery, using estimates for expected reserves per well, expected success rates, etc., based on a given number of wells to be drilled in the future.

In this study, it is assumed that roughly the same amount of cumulative wells drilled to date in each province will be drilled in the future. On average, in world-class provinces such as the North Sea that have had intensive exploration, the use of this technique suggests that at the point when 60-70% of the known cumulative exploration wells have been drilled, an additional 20-30% of the discovered reserves is likely be found. However, at this point exploration activity starts to decline and despite the fact that discoveries continue to be made, these tend to be very small relative to the past and immaterial to offsetting production decline in the province.

Peak oil production has been estimated based on the production capacity of projects that are currently producing or under development, known discoveries that can be developed, and production capacity of future discoveries as a function of YTF reserves. However, in each province production growth has been constrained near the midpoint once cumulative production reaches 40-50% of total oil discovered, including YTF reserves. This approach, based on the research of M. King Hubbert, says that in any given hydrocarbon province, when approximately half of the reserves discovered, including YTF, have been produced, production will level off and begin to decline. Several important studies, including those by Campbell and Deffeyes, indicate that Hubbert's rule of thumb gives the best explanation for the decline of many oil fields and several important provinces around the world.

Big Four overview

This study estimates that discovered, or 2P, deepwater oil reserves in the Big Four amounted to 44 billion bbl (88% of the known global deepwater oil reserves discovered) at yearend 2003.

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A total of 1,568 exploration wells were drilled in these provinces from 1975 to 2003, half of these in the last 5 years. Tables 1a-1b show a summary of key data for each of the four provinces.

Of the total deepwater oil reserves discovered, Brazil dominates with 14.6 billion bbl, of which 60% is located in 5 giant (i.e., >1 billion bbl) discoveries. The Gulf of Mexico is in second place with 11.5 billion bbl of oil reserves in some 140 discoveries, of which 2 discoveries are giant and 45 discoveries are less than 50 million bbl in size.

Off Angola and Nigeria, 9.5 billion bbl and 8.3 billion bbl of oil reserves in 41 and 25 fields have been discovered, respectively. In contrast to conventional wisdom, the average discovery size in Angola is 230 million bbl of oil, and there are only two discoveries that are close to but do not exceed 1 billion bbl. On average, the largest discoveries have been made off Brazil and Nigeria and the smallest in the Gulf of Mexico.

In terms of exploration wells, as of yearend 2003, 990 deepwater wells had been drilled in the Gulf of Mexico, 383 in Brazil, 111 in Angola, and 84 in Nigeria. The average success rate for all of these wells is 24%, but industry achieved the highest success rate in Angola (37%) and the lowest in Brazil (9%).

To yearend 2003, cumulative deepwater oil production from the Big Four is estimated at 4.4 billion bbl. Of this total Brazil accounts for 57%, the Gulf of Mexico 39%, Angola 3%, and Nigeria less than 1%. Brazil is the largest oil producer from deepwater sources, with average 2003 production of 1.2 million b/d of oil. The Gulf of Mexico is second, with average 2003 output of 1.1 million b/d; oil production in 500 m of water commenced in 1989, 6 years after the first discovery. At yearend 2003, Angola and Nigeria produced 210,000 b/d and 40,000 b/d from deepwater sources, respectively.

In Angola deepwater production commenced in 2001, 5 years after the first deepwater discovery, while deepwater oil production in Nigeria started at yearend 2003, 8 years after the first discovery was made.

In terms of crude quality, it is estimated that the API gravity of 70% of the discoveries in the Big Four is 19-27° (heavy to medium); Nigeria appears to have the highest quality oil, and Brazil the lowest quality.

Big Four reserves potential

An observation that is not necessarily revealing—but important for context—is that deepwater oil discoveries in the Big Four peaked at 5.8 billion bbl in 1996.

However, regional data show a more compelling story. In Brazil, oil discoveries peaked in 1987 and in the Gulf of Mexico in 1999. If Thunder Horse had not been discovered in 1999, the peak year for the Gulf of Mexico would have been 1989. In Angola and Nigeria deepwater discoveries peaked in 1998 and 1996, respectively, 3 years after the first acreage became available.

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In the 5 year period to yearend 2003, key exploration parameters—especially success rate, discovery size, and reserves per well—showed a deteriorating trend despite an increase in drilling in all provinces except for the Gulf of Mexico (Fig. 1a). In the Gulf of Mexico the number of deepwater exploration wells drilled almost halved from a high of 109 in 2001 to 56 wells in 2003.

It is relevant to note here that drilling technology for water depths as great as 1,000 m has been around for a decade, and for 1,000 m or more, for at least 5 years; the latter period coincides with record industry profits, suggesting that success has not been constrained by technology or lack of cash.

The first conclusion is that total YTF oil reserves in the Big Four could be 10-12 billion bbl, a volume roughly equal to 25% of the discovered reserves at yearend 2003 despite that over 1,000 deepwater exploration wells are likely to be drilled (Table 1b). Importantly, the large acreage already covered by drilling and-or 3D seismic relative to the total acreage available and the high concentration of deepwater prospectivity in a single geological formation and basin justifies a high level of certainty for the YTF results obtained for Brazil, Angola, and Nigeria. In the case of the Gulf of Mexico, given the size of the province, thickness of the hydrocarbon-rich rock formations, and the high number of blocks relinquished relative to those that are drilled, it is possible that some areas have not been thoroughly explored. This may suggest that more than the 4 billion bbl YTF estimated in this study could be found in the Gulf of Mexico. However, this estimate for YTF is well short of the latest US Energy Information Administration prediction that shows a YTF of 57 billion boe of oil and gas, most of which is expected to be oil.

Importantly, the bulk of future discoveries in the Gulf of Mexico is likely to continue to be smaller than in the other provinces, posing great challenges for development. And in ultradeep water, commercial success is constrained by geology and in part by water depth.

A key issue in Angola that constrains future exploration upside, and to a lesser extent an issue in Nigeria, is that most of the total acreage with prospectivity has been offered. As a result exploration has focused inside the most prolific blocks—limited to four blocks in Angola and a similar number in Nigeria.

In Brazil, deepwater oil prospectivity has proven to be concentrated in the mature Campos basin. Future discoveries in Brazil (especially outside the Campos basin) should be expected to continue to be heavier crude compared with those in the other provinces, requiring better technology than what we have today.

Peak deepwater oil production

The second conclusion is that total deepwater oil production from the Big Four could peak at 6.2-6.4 million b/d sometime during 2011-13 (Fig. 1b).

Perhaps production could peak before cumulative production reaches 50% of the total oil remaining at yearend 2003, including YTF reserves. This would be mainly the result of production maximization (i.e., simultaneous development of the largest fields) and limited number of large-scale developments, particularly in the Gulf of Mexico and Angola.

In addition, there is no doubt that deepwater fields will be drained as fast as technically possible for engineering and commercial reasons regardless of oil prices.

Regionally, deepwater oil production in Brazil could peak in 2014, in Nigeria in 2013, and in the Gulf of Mexico and Angola in 2011.

An important uncertainty affecting the peak year and production level in the Big Four is the potential impact of Organization of Petroleum Exporting Countries policies on developments in Nigeria.

By 2010 most of the discovered reserves in the Big Four are expected to be on stream and 40% of the reserves produced. Deepwater production in the Big Four could extend beyond 2020 despite the short life (15-20 years), compact size, and rapid decline rate characteristic of deepwater fields. Advances in deepwater production technology, especially subsea production, injection, and liquid separation, and the technologies required to produce heavy oil in deep water will help. These technologies in particular will extend field life by allowing the development of heavy oil discoveries and small-field tie-backs.

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The reserves and production data for each of the four provinces are shown in Figs. 2-5.

Brazil round

The Brazilian government is preparing to launch its sixth sale of offshore licenses next month (see related story, p. 26).

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The government will offer over 900 blocks (many offshore), with estimated reserves potential of 3 billion bbl, that it says could attract more than $20 billion in investment.

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However, after six rounds since Brazil first opened its deepwater areas to international players, only a handful of heavy oil discoveries have been made.

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Vast amounts of new geophysical data were gathered, a number of wells drilled, and new forms of interpretation have been made, but international companies have become increasingly more pessimistic about finding large, good-quality oil fields off Brazil.

And there is evidence that this "real feeling" of exploration getting harder in Brazil is not different from other areas around the world, even at $35/bbl oil.

Other deepwater basins

There are other provinces with deepwater hydrocarbon potential and in some cases world-class oil discoveries, but none represent a material long-term (oil) opportunity for the industry. Some of these include the Northwest Atlantic margin, Mediterranean basin, Northwest Africa, Baram Delta (Brunei), Tarakam basin (Indonesia), and Barents Sea (Norway-Russia).

The current hot spot is Mauritania, where several deepwater discoveries have been made. However, despite the successes, the integration of geological and well data suggests that this province is gas-prone and limited in size.

Deepwater success off Mexico could unlock the last significant deepwater oil province. The first well could be drilled there this year.

Despite that it is still early days, heavy oil production technology (not currently available) may be what is needed to commercially exploit this untested province of Mexico, as it is believed that the basin has a greater potential for heavy and extra-heavy crude than for light oil.

Big Four, peak oil

Campbell continues to make valuable contributions to the debate of ultimate recoverable reserves and peak oil production.

He suggests that since the Oil Age began, we now have produced almost half of what is there to produce from conventional sources, and as such global crude oil production soon will peak.

Campbell projects that global production of crude oil and other hydrocarbon liquids is likely to peak in 2010-15 and possibly earlier at 87 million b/d, of which deepwater production from the Big Four could provide at that time 7.2 million b/d (excluding other deepwater sources, which could provide another 1 million b/d).

However, deepwater oil production from the Big Four is now projected in this study to peak at 6.2- 6.4 million b/d sometime during 2011-13, subject to uncertainties in Nigeria.

What's next?

There is no doubt that there are fewer remaining untested areas worldwide than when the first deepwater exploration well was drilled 30 years ago.

Since then, the industry has seen or tested every geologically important corner of the world, onshore or offshore, deep or shallow reservoirs, in search for oil and gas.

Even Greenland and the mountains of Tibet have been looked at for E&P purposes.

All kinds of technologies have unlocked important unconventional hydrocarbon provinces such as the Orinoco oil belt, high-sulfur oil and condensate in the Caspian, polar oil, and enabled production in 2,500 m of water and more.

However, there is no indication to suggest that three times the amount of the oil discovered to date in the Big Four will be found again in these provinces, and outside the Big Four, there is limited potential. Global exploration potential looks now more limited than ever.

Acknowledgments

The author thanks Dr. Juan Carlos Boue from the Oxford Institute for Energy Studies and Dr. Rafael Sandrea (engineering consultant, Caracas) for reviewing the original draft and their contributions. Also special thanks to IHS Energy for providing some important historical data points for this study. The views expressed here are the author's and do not represent the official position of Merrill Lynch. F

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This is the third in a series of six—revised from four—articles revisiting the debate over peak oil and gas.

The author

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Ivan Sandrea is a global E&P strategy and financial analyst for the oil and gas team of Merrill Lynch in London. He worked as an exploration geologist and commercial analyst for British Petroleum PLC in Venezuela and Norway and as a consultant to BP Egypt. Sandrea's areas of interest include the exploration potential of Latin America, Caspian, and deepwater provinces and global E&P commercial strategy. He holds a BS from Baylor University, an MS in petroleum geology, and an MBA from Edinburgh University. Sandrea is the author of several publications and has collaborated with the geology department of Edinburgh University and the International Energy Agency for studies relating to petroleum exploration.