I use the term non-conventional as a basket for oil that does not qualify as being conventional oil for any one of a variety of reasons. It is perhaps a better term than unconventional which is also used. It is a broader usage than, for example, that employed by the USGS, which restricts it to deposits having no clear water contact, being termed continuous-type resources. As discussed earlier, the boundary between conventional and non-conventional oil is fuzzy, although the general distinction is valid enough, and indeed critical.

Included in the non-conventional category are:

- oil from oil shale

- oil from tar sands

- heavy oil

- oil from enhanced recovery

- oil from infill drilling

- oil in very hostile environments

- oil in very small accumulations.

Together they comprise a substantial resource, and have two essential characteristics: they generally become viable only in a high price environment; and they have a different depletion pattern, rising only slowly to a long, low plateau before eventually declining. The production of some categories are closely linked to the production of the conventional oil with which they are associated. They will not make much of a contribution to world production until long after Convention Oil production has peaked.

Whereas conventional oil is primarily resource constrained, non-conventional oil depends more on economic factors, and its production is more analogous to mining. The distinction between reserves and resources has more meaning when applied to non-conventional oil than is the case with conventional oil. The sheer scale of the operations needed to extract significant amounts of nonconventional oil is a major constraint.

Oil can be distilled from certain shales rich in organic material, in the same way as oil can be distilled from coal, as was done in Germany during the War. The organic material consists of kerogen that has not been converted to oil. Accordingly, the liquid so produced is strictly speaking not a natural oil at all. Shale oil should in fact better be classed as part of the coal domain rather as a hydrocarbon source, but it is mentioned here because it is often considered in colmection with oil.

The most advanced exploitation of shale oil is in the Piceance Basin of Colorado. It is reported that deposits yielding more than 10 gallons per ton are potentially commercially exploitable. The process carries a high environmental cost in terms of the disposal of waste, some toxic, and the large amount of water consumed. The waste material has a very fine particle size and occupies more space than it did before it was processed. It is unstable when heaped up in tips.

Although considerable investments were made in US shale oil projects in the aftermath of the Oil Shocks of the 1970s, most projects have now withered away. There are similar deposits in many other countries, including Australia, Brazil, FSU, Zaire, and China. The resources are very large, but actual world production is unlikely to exceed 500 000 b/d for a long time to come.

Australia, which has limited oil resources, has recently started exploiting shale oil near Gladstone on the coast of Queensland. The project has been encouraged by government tax relief. Production is expected to start two years from commencement, rising to 14 800 b/d in the eighth year. If all goes well, further developments may be undertaken, eventually yielding 250 000 b/d. Production costs are anticipated to be about $11.50/b, possibly falling to US$6.50 when the facility is in full operation. While it is evidently a very promising and valuable project, doubling Australia's present Bass Strait production, the long timeframe of such operations is well demonstrated. The slow rise in production to a long low plateau is very characteristic of non-conventional oil.

When oil migrates to shallow depths on the margins of basins, it is attacked by bacteria, which remove the light ends, leaving behind sticky viscous materials known variously as bitumen, asphalt and tar. These substances grade into heavy oils, and there have been difficulties in knowing how to classify them precisely. Their characteristics vary, depending on the composition of the oil from which they were derived and the subsequent alteration processes. The boundary between bitumen and Heavy Oil is drawn at 10°API gravity and a viscosity of 10 mPa-s. Asphalt is a type of bitumen with a gravity around zero degrees API.

The two largest deposits are the tar-sand deposits of Athabasca in Canada and the heavy oil deposits of the Orinoco area of eastern Venezuela, which are each estimated to have over one trillion barrels in place.

Of the two, the Canadian deposit is at the more advanced stage of exploitation. The deposit is mined in mammoth open pits, as well as being exploited by in-situ steam stimulation. A new development has been the use of horizontal wells for steam injection as well as production. The mining operation involves stripping off the overburden; separating the bitumen with steam, hot water and caustic soda, and then diluting it with naphtha. After centrifuging, liquid bitumen at 80°C is produced, which is then upgraded in a coking process and subjected to other treatments, eventually yielding a light gravity, low sulphur, synthetic oil. The process is economically viable, and it is estimated that costs can optimally be reduced from $12-13/b to about $9/b by 1998, depending on the cost of capital etc. About 400 000 b/d are being produced to-day, and there is clearly scope for expansion. A huge work force is engaged in the operation.

In Venezuela, the heavy oil, which has an average gravity of 9.5°API, is extracted with steam stimulation and chemical dilutants from reservoirs at depths of 150 to 1200 m. It is estimated that about 270 Gb could be recoverable. Typically, patterns of five wells are drilled on a regular grid. Steam is injected through the peripheral wells. It drives the oil to the central well, which can produce initially at up to 600 b/d, for a period of a few months until the catchment is drained. There are new proposals to extract it directly with the help of horizontal wells and submersible pumps, expanding the catchment area to increase flow rates to 1400 b/d, even without steam injection. In the 1980s, Venezuela commenced marketing a product made from bitumen, known as Orimulsion, which is used as a commercial boiler fuel for electricity generation. It consists of an emulsion of 70% bitumen, processed to a particle size of 20 microns, mixed with water and 2000 ppm surfactant. It has a relatively high sulphur content, which can, however, be largely removed by conventional scrubbers in power stations. Production is expected to rise to about 400,000 b/d by 2000 and 600,000 b/d by 2005. Almost half the investment is in precessing facilities. Exports to Europe have dwindled, however, partly because of the emissions, but new markets may be found.

It is obvious that the resources of tar-sand oil are enormous. The largest are the Canadian and Venezuelan deposits, but there are many others around the world, including two large ones, known as Aldan and Siliger in the Former Soviet Union. Although they may be economic to produce, at least to a certain scale, they use a large amount of oil in steam generation and are very environmentally unfriendly both for producer and consumer. Undoubtedly, production will rise in the future, but probably to a low ceiling, constrained by the sheer scale of the operation, and only when conventional oil is much scarcer than now.

The classification of what constitutes heavy oil is somewhat arbitrary, the boundary being variously drawn at 10, 15 or 20° APl - here we prefer the upper number. There is a very large number of heavy oil fields, which are found in virtually all producing basins, generally at shallow depth. Heavy oil generally has a high viscosity, and production rates are low, commonly requiring the pump. The production profile consequently rises slowly to a long low plateau before declining gradually. Many heavy oil deposits have been neglected, or produced slowly, in the past, because their economics compared unfavourably. A larger proportion of what will be produced in the future will be heavier oil: one estimate suggests as much as 37% of the undiscovered will be heavy. Deepwater finds tend to hold heavy oil because of low geothermal gradients from the thick water cover. [pp. 121,122]