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VHeadline.com oil industry commentarist Oliver Campbell writes:  When I was a young man and invited to a friend‚s party, I would put on a suit, shirt with collar and tie and polished shoes. This was conventional but if I had gone with an open-neck shirt, jeans and loafers it would have been seen as unconventional. Nowadays, the converse is true and my friend would see me as unconventional if I dressed up for the occasion. The point is that being conventional or unconventional is not a static condition but something that changes with time.

I want to argue along these same lines as regards conventional and non-conventional crude oil production and reserves. The profit motive has driven the development of new technology and resulted in cost reductions which will increasingly lead to more non conventional oil becoming economically viable. The distinction between what was non conventional and what is now conventional oil production has become blurred and this situation will, I suggest, accelerate in the future. It is also a fact the distinction means nothing to the consumer as he does not care whether the gasoline he buys comes from conventional or non conventional oil production.

Let us first look at the extra-heavy crude oil from the Orinoco Belt. Is this really non conventional oil when:

the production costs of $3 costs per barrel are “roughly the same as for conventional oil since development and production techniques are similar.‰

the oil is not much heavier than Boscan which has a 10.4° API, and Bachaquero with 12° API (which is heated to be pumped through the “hot line‰).

the oil has a temperature of some 50° C in the subsurface and flows naturally to the surface where the reservoir pressure is high enough. Where it is not, it can be pumped in the normal way. (It is not till the oil reaches the surface and cools that it becomes very viscous).

the oil can be easily mixed with naphtha for transport to Jose and upgrading there. It can also be blended with a lighter crude to make it into a saleable commodity (e.g.Merey 16).

However, this does not concur with the opinion of many who maintain the traditional position that:

1) An extra-heavy oil is defined as one that is below 10° API. This may be useful for classification, but does a difference of 4° API between the typical Orinoco Belt crude and Bachaquero Heavy really mean they are that much different physically?

2) A crude oil with a viscosity of 10,000 milliPascals/second is classified as a crude oil, but with 10,001 milliPascals/second or more it is transformed into a bitumen. This definition is not useful for classification since it does not take into account that oil below 10° API can flow freely to the surface and be, in most respects, just like any heavy crude oil.

I believe the above definition of bitumen was a maneuver, a most successful one, to exclude Orimulsion from the OPEC quota, but it has little logic to decide a substance is either a crude oil or bitumen according to some arbitrary measure of viscosity.

The situation with the Athabasca Tar Sands in Alberta, Canada is perceptibly different and there is a better case for saying the oil discovered there is non conventional oil for the following reasons:

a) the oil, which is found on the surface in fine sands and goes to a depth of a few hundred meters, has to be mined with enormous scoops or shovels. Incidentally, oil in the very south of the Orinoco Belt could possibly be mined in this way.

b) the sands containing the oil are transported in huge trucks (the tires measure 4 meters in diameter), not by pipeline, and then subjected to a process which separates the oil i.e. the oil is not in a usable form when mined.

c) It takes roughly two tons of sand to extract one barrel of oil and the process consumes a substantial amount of energy and water which can cause environmental problems. This is quite different from an oil that flows to the surface or, indeed, one that has to be pumped to the surface.

The costs of producing a barrel of crude from the sands have gone down to some US$12 a barrel and the Canadians have made the surprising statement “180 billion barrels could now be considered economically viable and so be classified as conventional oil.‰ It seems their claim arises from fact the oil can be sold like any other, and disregards its original state in the tar sands.

It was always assumed non-conventional crude oils had a much higher production cost but this is no longer the case. For instance, the costs of producing and upgrading oil from the Orinoco Belt are around $8 a barrel and still falling, the average cost of UK production in the North Sea is around $12 a barrel, and so is the average cost of production from the marginal fields in Venezuela. The crudes from the North Sea, Athabasca Tar Sands and Orinoco Belt were hardly economic when crude prices were at the $10 level at the end of 1998, but it seems that price was just an aberration and it looks safe to say oil prices will remain above the $25 mark, though currently they are much higher.

It appears to me the only significant difference with the Orinoco Belt crudes is that their API needs to be increased by an upgrading process. They have a high sulphur content which must be reduced, and nickel and vanadium which must be removed, but then so do many conventional heavy crudes.

I am not sure whether the argument over what is an extra-heavy crude and what is a bitumen is particularly fruitful. I believe it is the end result that counts: if a substance can be produced and upgraded to be saleable oil at a cost of only $8 a barrel, what does it matter if it started life with a viscosity over 10,000 milliPascals/second? To a lesser degree, the same goes for a mixture of oil with fine sand which has to be mined and separated out. Much better call them all extra-heavy oils and leave it at that.

I have the impression PDVSA also consider the extra-heavy crudes from the Orinoco Belt are not much different from so-called conventional crudes. I say this because nowhere in their Annual Report for 2001, the last one published, do PDVSA make reference to non conventional crude oil. They report their oil reserves as “Conventional and extra-heavy crude oil reserves.‰ Also in a note to the accounts, they refer to the “Development of the Orinoco Belt extra-heavy crude oil reserves.‰

The Venezuelan Oil Minister declared last year the government wish to add 235 billions of extra heavy crude oil to the nation‚s reserves. If this is done, I suggest they could be regarded as conventional oil in the same way as the Canadians have proposed. What proportion can be classified as proved reserves is something the experts will decide.

It is not just Venezuela and Canada that have accumulations of extra-heavy crudes. They also exist in the Middle East, but countries there have not bothered to quantify them because they have such huge reserves of light oils. At some time in the future they too will incorporate these accumulations into their reserves.

My second subject, the reporting of oil reserves, is one that is of topical interest. Calculation of oil in the reservoirs is done by geologists and reservoir engineers and this is the most important step. However, the calculation does not stop there as other factors are then superimposed.

The most notable consideration is the SEC definition which states: The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions.

This means only current technology and current prices can be taken into account. The SEC definition is super conservative because it is meant to protect lenders to the oil companies. Lenders, in the broad sense, include banks, bondholders, shareholders and suppliers. For this purpose, it is acceptable the SEC establish some stringent rules.

A good illustration comes from Shell‚s problem with the reporting of gas reserves in the Gorgon field in Australia. Shell booked reserves when its partners in the venture did not, which seems both strange and foolish. But the interesting thing is nobody disputes the reserves are there and, at some future time, will be produced and sold. An obvious customer would be China whose economy is developing at a great pace. The problem arises from the SEC “existing economic conditions‰ since, as pointed out in the press, “no reserves should be booked as proven until there is a deal to sell the gas‰ and this has not yet occurred.

However, any price hike, quite probable as oil becomes a scarcer resource, will bring greater reserves into play since crude oils with higher production costs then become viable. Also any breakthrough in technology that substantially reduces operating costs will have the same effect. The net result is that the SEC figures provide investors and analysts with only a partial account of potential oil reserves.

A most important piece of information is the extent to which production is being replaced by new reserves. However, new reserves do not mean new discoveries, a fact which is not generally appreciated. As Colin Campbell, the eminent geologist, likes to point out, most additions to reserves nowadays are reclassifications from probable to proven reserves, as further geological information on existing reservoirs is obtained. The amount of reserves classified as probable is thus another important piece of information.

I have a limited knowledge of the technical aspect of calculating oil reserves, but I do know something about financial reporting. So I suggest, in order to redress the shortcomings of the SEC definition, that more information should be provided. Companies could follow the method which the UK uses to report offshore reserves, as shown below:

Total remaining oil reserves, in millions of barrels, at December 31:

2002 2001 2000

Proven 4,665 4,715 4,930 Probable 2,555 2,750 3,000 Proven and probable 7,220 7,465 7,930 Possible 3,275 3,660 3,720 Maximum 10,495 11,125 11,650

These are arrived at on a field-by-field basis and the definitions are as follows:

Proven: are reserves that are virtually certain to be technically and economically producible.

Probable: are reserves not yet proven but with more than 50 percent chance of being technically and economically producible.

Possible: are reserves not yet regarded as probable that have a significant, but less than 50 percent chance, of being technically and economically producible. Maximum: is the sum of proven, probable and possible reserves.

The total of proven and probable reserves would give both investors and analysts a better idea of the potential to maintain oil production in the coming years. Further information on proved reserves in accordance with the SEC definition could be provided as follows (the figures are taken from PDVSA‚S accounts and are in millions of barrels):

Light, medium and heavy crude oil

2001 2000 1999 Revisions to existing reservoirs 784 1,652 1,782 New discoveries 538 286 ---   1,322 1,938 1,782 Less production (1,095) (1,103) (1,082) Net addition to reserves 227 835 700 Reserves at January 1 41,998 41,163 40,463 Reserves at December 31 42,225 41,998 41,163   Production to reserves ratio 38 years 38 years 38 years

Proved reserves of extra-heavy crude oil could be shown in the same way.

Two conferences are due to take place in the near future at which oil reserves will be discussed. The first will be held in the auditorium of the Instituto de Estudios Avanzados, next to the Simon Bolivar University, in Caracas on June 17. The second one will take place near London on June 30 and July 1. The topics for discussion at the latter will be “Oil reserves, geopolitics and the price of oil‰ and it will be chaired by Sheikh Yamani.

I regret I cannot attend the Caracas conference because I shall not be in the city, nor the London conference as the cost of £1,974 is outside my budget. However, I do hope what I have written above will be accepted as my two cents‚ contribution to both conferences. I trust my geologist friends can support some of my “unconventional opinions‰ and bring them up at the conferences since I hope thereby it will stimulate controversy so that discussion will be both frank and fruitful.

Oliver L Campbell, MBA, DipM, FCCA, ACMA, MCIM was born in El Callao in 1931 where his father worked in the gold mining industry. He spent the WWII years in England, returning to Venezuela in 1953 to work with Shell de Venezuela (CSV), later as Finance Coordinator at Petroleos de Venezuela (PDVSA). In 1982 he returned to the UK with his family and retired early in 2002. Campbell returns frequently to Venezuela and maintains an active interest in political affairs: “I am most passionate about changing the education system so that those who are not academically inclined can have the chance to learn a useful skill … the main goal, of course, is to allow many of the poor to get well paid jobs as artisans and technicians.” You may contact Oliver L Campbell at email: oliver@lbcampbell.com

www.vheadline.com/campbell More VHeadline.com commentaries by Oliver L. Campbell

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