LA CONVIVENCIA ENTRE PRÁCTICAS TRADICIONALES Y MODERNAS EN LOS FAXINAIS

A new discovery is not put into production unless there is a profitable market for the hydro-carbons produced. This self-evident statement illustrates the extent to which the concept of reserves is economic in nature.

However the circumstances for gas are rather different from those of oil. At present and allowing for existing rates of consumption the reserves of gas will outlast those of oil (about 65 years, against 40 years for oil). Furthermore it is generally agreed that gas production will peak (point at which production begins to decline) later than oil production. The demand for gas, although real and considerable, is therefore less sustained than that for oil products, or to put it another way, in consuming energy we tend to give priority to the most economic option (at present oil), with their wide variation in energy content. It should be remembered in this connection that gas is 5 times as costly to transport as oil. The oil market is rather more demand-driven than that of gas, where supply is often waiting for demand.

This phenomenon is well known because it also applied (and still applies) to the coal market. In practice there are very many extremely large known gasfields which will probably never be put into production.

At the present rate of production, coal reserves will last more than 160 years. This statistic is difficult to interpret, however, because it seems very likely that two centuries from now coal will have all but disappeared as a source of energy. This means that some of these reserves will deliberately not be exploited. This being the case, these latter should be clas-sified as resources rather than reserves. The same applies, on a smaller scale, to natural gas.

In the past, large quantities of gas have been flared because there was effectively no market for it.

In the two succeeding sections we will consider how reserves are estimated, and production is forecast, using production profiles at the level of the field, basin or province.

3.3.2 Production profiles

The production profile of a field is a graph in which production (usually annual) is plotted against time. A production profile can be prepared in the same way for a well, a field or a complete geographical zone by the same process as that applying to a petroleum system, a basin or a country. The profile can be descriptive (i.e. historical data) or predictive. Predictive profiles are usually constructed for a well or a field once the production tests have been completed. Two theoretical examples are given below which are typical of production profiles for an oil —or gasfield. The field reserves are represented by the area under the curve

Chapter 3Hydrocarbon reserves

which defines the production profile. The preparation of a predictive production profile therefore also involves estimating reserves (equal to the area under the curve).

At the level of the field, there are broadly two types of profile, corresponding to small and large fields. Small fields (Fig. 3.4) exhibit a very steep rise in production and are rapidly exhausted, so as to reduce the production costs by concentrating them over as short a period as possible. Conversely, the production profile of a large field (Fig. 3.5) tends to be more spread out in time. After an initial testing period it climbs steeply to reach a production plateau which is maintained for a number of years, depending on the size of the field. The decline in production as the field becomes depleted is generally slow.

It can be seen that production profiles tend to be very asymmetric around their production peak (or maximum). When, however, production profiles are summed to give estimates for an entire basin or country, the aggregated curve is often symmetrical about its peak, with a rather bell-like shape. This fact was first applied by King Hubbert at the end of the 1950s to forecast the peak and decline of oil production in the U.S. But is this forecasting method of universal applicability?

3.3.3 Hubbert theory of decline

Chapter 3Hydrocarbon reserves

Figure 3.4 Characteristic production profile for a very small oilfield (20 Mbbl).

Figure 3.5 Characteristic production profile for a large oilfield (500 Mbbl).

1850 1900 1950 2000 2050 Years

Annual production of US (48 states)

Fitted norma curve

Around 1960, King Hubbert, then an engineer at Shell, forecast, by fitting a normal curve to the production profile of 48 American states, that production would reach its peak in 1969.

Production would then decline in a manner symmetrical to the growth phase. His forecast of the peak proved correct to within a year. This success won its author great acclaim and recognition from his peers. There are various Internet sites which promote the work of Hubbert and his disciples. However the fact that his theory was vindicated for one particular example does not mean that his model has been validated generally. An entire school of fore-casting has been erected on this solecism.

The object of this section is not to refute Hubbert’s conclusions or methodology but rather to point out that there has been no valid scientific proof of the effectiveness of this method, and still less of its universality.

The model does however have the merit of comprising a particularly simple example of a method of forecasting production (and therefore also the ultimate reserves). As we argue in Box 3.1, it is legitimate to make some criticisms of the tendency to force everything into a normal distribution; there are many regions in the world, including the U.S., where aggre-gated production profiles are not distributed normally, or even symmetrically.

A model of this kind makes time the only explanatory variable for the production of a region. This is a astonishing idea, implying an ineluctable decline mirroring the growth phase, and does not allow the possibility of reserves being created as a result of technical progress.

Chapter 3Hydrocarbon reserves

Box 3.1 Hubbert and mathematics.

Even if, in several regions of the world, production profiles are found to be distributed normally, there is no reason to believe that all production profiles will display this pattern.

However attempts have been made to explain or justify the Hubbert phenomenon “math-ematically”. One such attempt, tenacious and false, appeals to one of the most celebrated theorems of probability theory: the central limit theorem. This states that under certain regularity hypotheses the sum of a large number of independent random phenomena (even if highly asymmetric or multimodal) tends to produce a random variable with a normal distribution, that is, symmetrical with a bell-shaped distribution, like that used in the Hubbert approach: the distribution function of the sum of the processes is close to being normally distributed. But the probability density of the sum is not equal to the sum of the probability density (in this case the production profiles of the fields). Furthermore the Hubbert phenomenon does not fall within the scope of this theorem. In the first place the production profiles summed are obviously not independent of one another, particu-larly when they relate to the same geographical zone, and secondly the theorem relates to numerical distributions rather than temporal distributions, as in Hubbert’s model.

Temporal distributions are subject to a completely different tool of probability theory, namely time series analysis.

Great care must therefore be taken not to misuse this method which, however appealing it may seem on the basis of a few examples, has no scientific basis. If certain aggregated profiles exhibit the characteristics of the normal distribution, these are curiosities, the real reason for which it would be very interesting to explore, rather than a phenomenon of general applicability as claimed by Hubbert and his numerous followers. Hubbert himself ended up by repudiating the normal curve in favour of the logistic curve which unfortu-nately is no more justified than the normal curve.

3.3.4 The impact of technical progress on the production profile

A profile is usually constructed when production commences, once the production tests have been completed. Post mortem profiles, i.e. those which can be drawn when production comes to an end, are often very different from those initially envisaged, however. This difference is usually caused by technological progress, which may increase the reserves (Fig. 3.7) or permit their accelerated production (Fig. 3.8).

Chapter 3Hydrocarbon reserves

Figure 3.7 Effect on initial production profile (mauve) of the creation of reserves due to tech-nological progress (grey).

Figure 3.8 Effect on initial production profile (mauve then white) of the accelerated extraction of reserves due to technological progress (grey).

The two scenarios presented below show the impact of an assisted recovery technique put into operation after 16 years of production.

In the first case there is no change in the resources, but additional reserves are created (the area under the curve rises from 50 to 60 Mbbl). There is said to have been an increase in the recovery ratio (see Box 3.2). In the second case no new reserves have been created (the dark shaded area is exactly equal in size to the blank area under the curve corre-sponding to the original production profile), but simply an acceleration in the extraction of the existing reserves. Production comes to an end 10 years earlier, without any loss in the total reserves extracted. Although there is no increase in the reserves, the acceleration is defi-nitely economically advantageous for the producer as it allows him to avoid a long period of run-down and to receive the revenues earlier.

There are many examples of both cases. The Alwyn field in the North Sea is a textbook example of the first scenario. A variety of measures were taken resulting in a succession of significant increases in the reserves. A number of writers have identified numerous examples of the second scenario.

The second model of technological progress takes a pessimistic view about reserves. In relation to conventional oil, technology simply accelerates depletion and therefore hastens the onset of scarcity.

As already mentioned earlier, there are two schools of thought in relation to ultimate reserves. The object of the next section is to present both sets of arguments so that the debate can be properly understood.

Chapter 3Hydrocarbon reserves

There are many indicators commonly used in the petroleum industry, either at company level or for the entire sector. These may have a warning function, may be for general management purposes or to signal scarcity.

R/P

The first and most widely used indicates the outstanding life of the reserves at the present rate of production assuming that no further discoveries are made: it is the ratio reserves/production, often indicated by R/P. It is expressed as a number of years. The ratio has fluctuated considerably over the years, as the following table shows:

Since 1970, when it appeared that oil would be exhausted by 2000, the outstanding life of the reserves has only increased.

These indices, shown above for the global level, can also be calculated by region, company, etc. These ratios vary from 8 years (North Sea) to 80 years (Middle East), according to region and are traditionally in the range 8 to 15 years for companies, depending on their policy. These ratios have a certain strategic importance for the companies, who try to keep to the value reasonably constant at approximately 10 years.

A ratio which falls too low indicates a company in poor health. It should be noted that this ratio is very sensitive to the definition of reserves adopted. In 1986 the method used in the Middle East to evaluate reserves changed, leading to a substantial rise in the R/P ratio.

Success rate

This indicator, used by the upstream petroleum industry, is the ratio of non-dry wells to the total number of wells drilled. It is therefore, at the company level, a measure of its success in exploration. However this index must be interpreted cautiously. A non-dry well which discovers reserves of 1 million barrels is obviously not equal in value to one which discovers reserves of 1 billion barrels. The ratio should therefore reflect the size of the reserves involved; a high success rate in a region where the reservoirs are small is of no great interest to the company. The success rate nevertheless provides a measure of the effectiveness of exploration. Its value has climbed over the last 30 years, from 1/10 to 1/5 and even 1/3 nowadays.

Recovery factor

The recovery factor, defined for a field, is the ratio of the reserves to the resources in the field. It varies with time, along with the estimates of reserves and resources. Average recovery factors for conventional hydrocarbons are at the moment 30–40% for oil and 80% for gas. One of the ways of increasing reserves —the other being exploration— is to increase this percentage by taking advantage of technological advances. This is some-times referred to as field growth. The recovery factor is often used as a criterion to distin-guish between conventional and non-conventional hydrocarbons, particularly for gas. As far as heavy oils are concerned, recovery factors are of the order of 10% or less. There is obviously great scope for improving these rates, and nowadays reserves are mainly created by increasing the recovery factor from deposits of non-conventional hydrocarbons.

Box 3.2 Indicators used in the upstream petroleum industry.

50′ 70′ 80′ 90′ 00′

Oil 150 30 35 40 40

Gas 50 55 60 63