Iraq has begun to produce oil again, only days after hostilities ceased, giving rise to hopes of a large rise in oil production over the next few years. Is this good news for a world short of oil, or the addition of still more surplus capacity to an oversupplied market? Over the past few months, OET has been reviewing the prospects for production over the coming decade. In this issue, we bring the results together to present a world picture covering the period to 2010. The production outlook presented in Table A is based on plans already announced in the countries covered in the survey and assumes a price of at least $21 a barrel (in money of the day) for North Sea Brent crude throughout the period. As such, it may be said to be the ‘best case’ as far as production is concerned. It includes heavy oil synthetic and other non-conventional crudes but excludes gas liquids.
Our survey suggests that the world could increase crude oil production by some 14.5 mn bpd or 21.3% between 2001 and 2010. This should be seen more as an indication of potential output capacity than as an actual forecast of production in 2010, since the amount produced then will depend also on demand. The figures given above would satisfy a 1.5% growth in demand over the period, which turns out to be the annual growth rate in demand between 1991 and 2000, when Brent prices averaged just under $18 a barrel (in money of the day). There are some reasons to believe that crude oil demand will rise at a lower rate during the current decade. In the first place, the higher oil prices assumed above could dampen the growth in demand. Secondly, political instability in the Middle East may well hasten oil substitution in the main consuming countries, notably the USA, where the Bush administration has made energy security a major political issue since 2001. The National Energy Policy Development Group, which included both US vice-president, Dick Cheney, and secretary of state, Colin Powell, recommended in May 2001 “that the President make energy security a priority of our trade and foreign policy” with the aim of substituting oil wherever possible by natural gas, nuclear power, and renewable energy.
Further oil substitution is likely worldwide from natural gas liquids and liquids manufactured from gas via gas-to-liquids (GTL) processes (see Table B). At first sight, therefore, the world appears comfortably supplied with oil between now and 2010.
Table B |
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Global gas liquids and GTL outlook, 2001–10 |
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| 2001 | 2010 | Change | |
| (mn bpd) | |||
| NGL | 5.4 | 8.0 | 2.6 |
| GTL | * | 1.2 | 1.2 |
| Total | 5.4 | 9.2 | 3.8 |
| *only two plants in operation with a combined capacity of 35,000 bpd | |||
Once NGL and GTL are added to the picture, the outlook for total liquids’ production is for a rise of 18.3 mn bpd between 2001 and 2010, representing a total increase of 24.9% and an annual increase of 2.5%. This suggests even more room for manoeuvre when it comes to meeting demand over the coming decade.
The situation with regard to crude oil looks rather less rosy when we examine the reserve numbers on which it is based. Proven reserves of crude oil amount to 1,081 bn bbl: sufficient for 43 years at recent rates of production (see Table C). Some 64%, however, are located in the Middle East, which suggests a long-term shift towards dependence on that area for production. Our output projections, however, suggest a different trend over the next few years (see Table A). The Middle East’s share of world production may, if anything, fall slightly: from 30.6% in 2001 to 30.5% in 2010.
There are several reasons for this apparent paradox. Output from the main Middle Eastern producers is artificially constrained by OPEC quotas. There is also some element of underestimating reserves in Africa and parts of the former Soviet Union (FSU). Enhanced oil recovery (EOR) is generally applied more intensively outside the Middle East, where reservoirs and wells tend to be less prolific.
The use of EOR has done much to raise the amount of oil recovered from non-Middle Eastern oil fields. One country where this has been particularly successful is Russia, where a 50% decline in production between 1987 and 1996 has been reversed. Output is now more than 30% higher than in 1996 and still rising. EOR has also transformed large areas of the North Sea, allowing more oil to be recovered from reservoirs than had previously been expected. In the last 20 years, recovery factors have risen from around 30% of the oil in place in the reservoir to more than 50% in certain fields. In some cases, it is becoming worthwhile to recommission abandoned fields. Some industry experts forecast eventual recovery rates of nearly 70%.
Table B |
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Global gas liquids and GTL outlook, 2001–10 |
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| 2001 | 2010 | Change | |
| (mn bpd) | |||
| NGL | 5.4 | 8.0 | 2.6 |
| GTL | * | 1.2 | 1.2 |
| Total | 5.4 | 9.2 | 3.8 |
| *only two plants in operation with a combined capacity of 35,000 bpd | |||
Production in the North Sea and elsewhere has been boosted by falling exploration and development costs. Horizontal drilling allows access to greater areas underground and the development of multilateral wells allows several boreholes to be drilled from a single well bore. Sub-sea wells have cut development costs by allowing reservoirs to be tapped using manifolds on the seabed rather than considerably more expensive fixed or floating production platforms. Such wells can often be tied in to existing production infrastructure, with further savings on costs. Although North Sea production has actually peaked, techniques such as those described above enable its output to be prolonged rather than entering a rapid decline.
Developments in sub-sea technology are enabling more continental-shelf areas to be opened up and allowing drilling to take place at ever-deeper levels. Amongst the areas to benefit have been offshore Brazil and West Africa. One consequence of this is that reserve estimates for these and other areas may well have to be revised upwards.
The country with perhaps the greatest potential for upward reserve revision is Russia, which has large areas both offshore and onshore still unexplored where hydrocarbons are likely to be found. Many of these areas are in Eastern Siberia, which was seen as a potentially huge new oil province in the 1980s. Several other highly prospective areas exist offshore. Most estimates of Russia’s proven oil reserves are around 49 bn bbl (see ‘Looking Ahead’, February 2003). Russia’s Yukos predicts that there are more than 50 bn bbl of undiscovered reserves. The US Geological Survey estimates proven and probable reserves around 130 bn bbl, putting it in the Middle Eastern class of oil producers. Some forecasters predict output levels of 10 mn bbd by 2010. Several political, legal, and logistical problems need to be resolved before such figures can be attained (see ‘Focus’, December 2002). There are nevertheless considerable grounds for optimism on Russian reserves and production.
The Caspian Sea is another area where reserves may have to be revised upwards (see ‘Looking Ahead’, February 2003). The former Soviet republics of Azerbaijan, Kazakhstan, Turkmenistan, and Uzbekistan have about 20 bn bbl of proven reserves between them. Several geologists believe further exploration could double this total.
Hydrocarbons are fairly widely distributed in the earth’s crust but output gains over the coming decades are likely to be concentrated in a small number of countries (see Table D). On the other hand, the gains themselves are likely to be spread across a large number of fields. Field sizes are becoming smaller. New finds in many places tend to be almost an order of magnitude below the size of earlier finds.
In the North Sea, for example, new fields like BP’s Clair field are estimated to contain recoverable reserves of about 250 mn bbl. BP’s Forties field, which began production in 1975, was estimated then to contain about 2.5 bn bbl. BP recently sold its 96% shareholding in Forties to concentrate on other areas, including Russia. Tax changes have made the UK sector less attractive to some companies, and other asset sales are likely.
Of the 14 countries liable to raise oil production by 0.5 mn bpd or more, 8 are members of OPEC, which also accounts for four of the top five places in the list (see Table D). Canada’s increase depends largely on a sharp rise in heavy oil production and in synthetic crude produced from tar sands. A period of low oil prices could set back many of these developments leaving Canada with much smaller gains over the period. Venezuela also depends to a lesser extent on being able to offset the decline of some of its older fields from heavy and other non-conventional crudes. Most of the rest of the gains shown in Table D, however, are expected to come from conventional crude sources.
Nigeria is developing a number of large new discoveries, including the Yoho field, which is expected to be producing 150,000 bpd by next year, when its first deepwater field, Bonga, will also be commissioned. Deepwater fields could provide around 1 mn bpd by 2010. Nigeria, however, has problems in financing its share of many of its older fields, which are operated as joint-ventures with foreign companies. New production-sharing agreements have been drawn-up to encourage the development of deepwater fields. There is also political unrest in some onshore oil producing areas. Elsewhere in West Africa, Angola has considerable offshore potential with several fields already under development.
Mexico has high potential for new production, but a reluctance to use foreign capital could hold back any increases in output. Russia’s production could rise by more than the 1.2 mn bpd indicated in Table D, but it will first need to make its legal and investment framework more attractive to foreign companies. The Caspian also has considerable potential but output growth could be held back by a failure to develop sufficient export infrastructure in time (see ‘Focus’, July 2002). The development of oil production in Kazakhstan and Azerbaijan has been strongly promoted by the US government as an alternative to the Middle East. Washington may switch its attention to Iraq, however, if it is able to persuade the new regime there to open its upstream to US participation.
Table D |
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Main production gains, 2001–10 |
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| Country | 2001 | 2010 | Change |
| (mn bpd) | |||
| Venezuela* | 2.8 | 4.8 | 2.0 |
| Nigeria* | 2.1 | 4.0 | 1.9 |
| Canada | 1.6 | 3.3 | 1.7 |
| Saudi Arabia* | 8.0 | 9.5 | 1.5 |
| Iraq* | 2.4 | 3.9 | 1.5 |
| Angola | 0.7 | 2.0 | 1.3 |
| Mexico | 3.2 | 4.5 | 1.3 |
| Russia | 7.0 | 8.2 | 1.2 |
| Algeria* | 0.8 | 1.7 | 0.9 |
| Kazakhstan | 0.8 | 1.6 | 0.8 |
| Azerbaijan | 0.3 | 0.9 | 0.6 |
| UAE* | 2.1 | 2.7 | 0.6 |
| Libya* | 1.4 | 1.9 | 0.5 |
| Qatar* | 0.7 | 1.2 | 0.5 |
| * OPEC member | |||
Algeria and Libya have ambitious development plans, although the Algerian government has attracted strong domestic opposition to proposals to encourage more foreign involvement in its upstream industry. Libya’s oil industry, on the other hand, could benefit from improving relations between its government and the USA following recent progress in talks over Libya’s alleged role in the bombing of Pan Am flight 103 over Lockerbie in 1988. Qatar and UAE are taking advantage of large reserves to increase their output.
The two countries with the greatest potential for output increases over the present decade are Saudi Arabia and Iraq. Saudi Arabia has the world’s largest reported proven reserves, with 262 bn bbl, while Iraq comes second with 113 bn bbl (see ‘Looking Ahead’, April 2003). Between them, they account for nearly 35% of the world’s total proven reserves. How much they actually produce in 2010, however, will depend rather more on politics than on geology. As a member of OPEC, Saudi Arabia may find its production constrained by output quotas (as may other countries in Table D). Iraq is also an OPEC member but is currently outside the quota system. Its need to raise production may conflict with its desire to return to full membership.
Saudi Arabia can already produce around 10.5 mn bpd and may even have been close to that level for a few days during April when the invasion of Iraq was taking place. A new 0.5mn-bpd field is under development at Qatif, there are plans for further drilling in the kingdom’s largest field, Ghawar, and longer term plans to produce 0.6 mn bpd (see ‘Focus’, April 2003) but these may take more than a decade to achieve.
While damage from the latest conflict in Iraq is light, there is war damage dating back to the Iran–Iraq war of the 1980s, and nearly 13 years of UN sanctions have left the oil infrastructure in poor shape. Little is likely to happen there until a new oil industry structure is in place, and there is the prospect of lengthy delays as Washington tries to agree new industry structures and methods of financing oil developments with whatever emerges as the new Iraqi government. There will also need to be agreements with the UN on ending sanctions and the oil-for-food programme governing the export of Iraqi oil.
Iraq and Saudi Arabia will nevertheless be the key marginal suppliers to the world market for the rest of the decade; and their role will be determined at least as much by politics as by geology. There are many in Washington who want to see Iraq develop as a counter-weight to Saudi Arabia, which is viewed by some there as increasingly hostile to US interests and as politically unstable. What the USA wants is a friendly and stable Iraq. How far it can achieve this will determine to a considerable degree the production outlook of the world’s two most oil-rich countries.
Even allowing for lower than expected production increases in some countries, the world should remain comfortably supplied with hydrocarbon liquids for the remainder of the decade. After 2010, though, there may be fewer grounds for optimism. Non-OPEC production will probably peak around 2010: earlier if there are problems with foreign investment in key producers like Russia and the Caspian states. OPEC, too, is having problems in financing new production. A combination of unattractive upstream terms and an unwillingness to use foreign capital may delay long term developments in Algeria, Iran, Kuwait, and Saudi Arabia, leaving production capacity in OPEC tight by 2010 or soon afterwards. With no upstream policy in place in Iraq either, the outlook for OPEC production looks even more uncertain. Some geologists are forecasting a peak in world oil output in the decade following 2010. All this suggests that the era of comfortable supplies may prove to be short-lived.
© Blackwell Publishing Ltd, 2003