Petroleum Review's Oil & Gas Fields Megaprojects - October Update In Full

Prices set firm, despite massive new capacity

Over the last two years Petroleum Review has regularly updated its listing of the upcoming so-called "megaprojects". The aim of the listing is to attempt to answer the question as to whether sufficient oil is being developed to meet likely requirements going forward, writes Chris Skrebowski.

This latest update "based on public sources of information" identifies a total of 16.65mn b/d of new capacity due onstream by 2010. This, in turn, is made up of 6.34mn b/d of incremental Opec capacity and 10.31mn b/d of non-Opec capacity additions (see p2 for basis of tabulation). This is directly comparable with the 16.5mn b/d identified by the consultant CERA in its recent report. However, CERA's happy conclusion that potentially price depressing excess supply was about to emerge does not appear to take project slippage and depletion fully into account and, therefore, appears highly optimistic.

Experience shows that between 10% and 20% of projects slip from one year to the next. As no company intends this to happen and there is no way it can be anticipated, the only way to deal with it is to continuously update the database. A recent example of this phenomenon is the BP-operated Thunder Horse project, where, following storm damage to the platform, startup has moved from late 2005 to 1H2006. Project slippage does not mean that the capacity is lost, but merely postponed. This, however, will reduce the actual capacity increments each year going forward. The exact magnitude cannot be determined in advance - although 10% to 20% would be a reasonable rule of thumb.

Depletion modelling

Depletion is relatively difficult to model, but must be taken into account when determining future capacity additions. It is possible, and useful, to identify three sub-categories, or types, of depletion.

Type I depletion - is the normal loss of capacity in an oil field as production from wells in one field run down and are offset by new wells or increased production from other existing wells in the field. There is only limited public data available, apart from the North Sea, where decline rates of between 5% and 15% are reported and are typical of the main decline phase. The North Sea also shows that a proportion of the region's fields are able to finally stabilise production at about 10% of peak flows. There have also been reports (not fully corroborated) of 7% declines in Iranian fields and 6% declines in Saudi fields. Offshore fields, which, because of their economics require high flow rates and much more rapid and intensive development, tend to have the most rapid decline rates - often as much as 15%/y. Companies really only suffer the impact of Type 1 depletion when a field is fully drilled up and there is no possibility of offsetting the declines.

However, with the consultant IHS Energy now reporting to various conferences that 90% of known reserves are in production, more and more fields around the world are moving into their decline phase. One estimate is that as much as 70% of the world's producing oil fields are now in decline.

Type II depletion - is when a company, or country, can offset field declines in one part of the country with expansion in another part. Because public data is collected on a national basis, there is only limited data available on Type II depletion - although its magnitude is likely to be the same as for Type I.

Type III depletion - is when a country produces less oil in a year than it did in the previous year. This can be identified quite readily from public production databases (see Petroleum Review, August 2004 and August 2005). Type III depletion will increase as additional countries move into decline, but will reduce as the volumes produced by the countries in decline decreases. In 2003, Type III depletion was running at around 1.1mn b/d, but in 2004 it fell back to around 900,000 b/d (significant revisions to production data tend to confuse the picture). Over the next few years a number of countries are likely to move into decline - Denmark, China, Malaysia, Mexico, Brunei and India are the obvious candidates and account for over 12% of global production - so a reasonable working assumption is that Type III depletion will increase, although with something of a saw-tooth profile. Recent statements by oil companies (Petroleum Review, August 2005) have tended to indicate that overall depletion (Types I, II and III) is running at between 4% and 6%. Analysis of recent company production (see p24) tends to confirm that using a 5% figure is a reasonable approximation. Demand growth is subject to quite rapid swings, but appears to average around 2%/y. By combining these various pieces of information, it is possible to determine whether the market will tighten or weaken and whether "peak oil" is a likely outcome in the period to 2010 (see Table 2).

In 2004, effectively all the world's spare capacity was used up in meeting unexpectedly rapid demand growth. It is not at all clear if the world's oil companies can provide an incremental 3mn-plus b/d from all the small, untabulated projects and infill drilling going forward year after year. The world has now reached the point where the volumes lost to depletion are much larger than the levels of likely new demand. This means total increments requred (new demand plus depletion) are running at around 7%/y, while the largest supply increments in 2006 and 2007 are contributing 3.6% and 3.5%.
It would seem most unlikely that small projects and infill drilling could account for the remaining required 3.5%. The inescapable conclusion is that oil prices will have to remain high enough to destroy demand, bringing supply and demand back into balance.

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