The only commercial development of oil sand has taken place in the Province of Alberta, Canada. There are four major oil sand deposits in Alberta: the Athabasca, Cold Lake, Wabasca, and Peace River deposits. The Athabasca deposit is by far the largest and contains the only reserves shallow enough for surface mining. These deposits were initially discovered from outcrops of the oil sand along drainages, in which the bitumen would ooze from the surface when exposed to the sun.
There are two commercial operations using surface mining techniques to extract oil sand from the Athabasca deposit north of Fort McMurray, Alberta, Canada. These are the Great Canadian Oil Sands (GCOS) operation which is located along the Athabasca River, 40 km (25 miles) north of Fort McMurray and the Syncrude mining operation, located immediately adjacent to the GCOS lease. The GCOS lease has 100 Mm3 (630 million bbl) of recoverable oil and is being exploited at the rate of approximately 7 900 m3 (50,000 bbl) of synthetic crude oil per day. The overburden on the GCOS property averages about 15 m (49 ft) in thickness and is removed with a large bucket wheel excavator in conjunction with 136-t (150-st) trucks. The oil sand which averages about 50 m (164 ft) in thickness, is removed by large bucket wheel excavators and carried to the process plant by conveyors. The oil is removed from the sand using a hot water process. The GCOS plant went onstream in 1967 and achieved its design capacity of 7 200 m3 (45,000 bbl) of synthetic crude per day by 1970.
The Syncrude mine went into operation in the late 1970s with a design capacity of 19 800 m3 (125,000 bbl) of synthetic crude oil per day. The oil sand averages approximately 11 to 12% bitumen by weight. Approximately 1.8 t (2 st) of oil sand is needed to produce one barrel of synthetic crude. Adding the handling of overburden and tailings material, 4.5 t (5 st) of material need to be moved per barrel of crude. At a designed capacity of 19 900 m3 (125,000 bbl) per day, the Syncrude operation will
handle more than 544 kt (600,000 st) of material per day.
Currently there are no commercial oil sand operations in the United States. However, studies and pilot plant testing are underway on deposits in Utah, California, and Kentucky.
GEOLOGY
Oil sand deposits consist of accumulations of heavy oil within the pore space of permeable reservoir rocks, such as sandstones or unconsolidated sands. They are essentially the same geologically as conventional oil reservoirs, except that the hydrocarbon is much heavier and cannot be recovered with conventional oil wells. These deposits are subject to the same type of geological analysis as conventional oil reservoirs, such as studies of source rocks, reservoir rocks, oil migration history, trapping mechanisms, and oil maturation and differentiation. The percent of oil in an oil sand deposit is a direct function of the porosity and permeability of the host rock. The distribution of permeable zones is controlled by the distribution of porous sand bodies and interbedded shales or other impermeable strata. Most oil sand deposits are thought to be formed when oil migrates from a source rock into a permeable reservoir rock and is exposed to water washing and a lessening of pressure with the consequential loss of the light hydrocarbons, leaving a heavy residue—the bitumen in the oil sands deposit. However, there are two schools of thought regarding the origin of the oil in these deposits. One theory is that the parent petroleum was a thermally mature crude similar to conventional crude oil that has migrated from some geographically remote source rock into the sand deposits and been subjected to biodegration and water washing to produce the oil sand deposit. The other theory postulates that the parent petroleum was an immature crude and has a source within the same formation or very close to the oil sand deposit. Whatever the source, it is clear that the oil was much less viscous at the time it entered the reservoir as it occupies all the porous and permeable zones within the reservoir.
One characteristic of oil sands that is important to the selection of processing techniques is whether the sand is water wet or oil wet. In the case of water wet oil sand, as in the Athabasca deposits, there is a thin film of water separating the bitumen from the sand grain (Fig. 2.8.2), which allows the bitumen to be removed by a hot extraction process. In the case of oil wet sands, the oil is in direct contact with the sand grains and is more difficult to remove, usually necessitating a solvent extraction process.
Most oil sand deposits are located in alluvial or deltaic sandstones near the edge of a large basin (Fig. 2.8.3).
Figure 2.8.3.
These alluvial and deltaic environments usually contain a variety of sedimentary units with differing amounts of porosity and permeability. This variety results in a nonhomogeneus oil sand deposit. The oil content is directly proportional to the porosity of the host rock and its deposition was controlled by the permeability. A study of the depositional environments can lead to an understanding of the variability in the deposit. Any exploration or development effort should include a thorough study of the sedimentology and a reconstruction of the depositional history of the deposit area.
EXPLORATION TECHNIQUES
Oil sand deposits are essentially the same as conventional oil reserves except that they are more viscous because of the loss of light hydrocarbons. Exploration techniques used to locate these deposits are consequently the same as those used for conventional oil reservoirs. Regional or grass-root methods include identification of source-rocks, location of reservoir rocks with high porosity and permeability, and identification of traps in the reservoir rocks.
DRILLING
Core drilling is the most widely accepted method for sampling oil sand deposits, although rotary drilling with electric logging and bulk sampling are also used.
The most common core size is 63.5 to 76.2 mm (2.5 to 3 in.) in diameter. The core should be described by a geologist and the intervals containing significant bitumen should be sampled by geologic unit or in 3 m (10 ft), intervals or less. Drill spacing varies from 1.6 km to 76 m (1 mile to 250 ft) depending on the deposit and the purpose of the drilling.
Reconnaissance drilling is often done on approximately 1.6 km (1 mile) centers with fill-in drilling at 0.8 km (0.5 mile) and 0.4 km (0.25 mile) centers as more detailed exploration proceeds. Final drilling for areas to be mined in the first five years is usually carried out on a spacing of 76 to 152 m (250 to 500 ft), depending on the variability of the deposit.
Rotary drilling with sampling of cuttings every 0.6 to 1.5 m (2 to 5 ft) followed by electric logging is also used extensively on some deposits with good results. Rotary drilling and logging must always be supplemented with core drilling and it is advisable to have some twinned core and rotary holes for comparison of results.
Whether rotary or core drilling is used, geophysical logging of the holes is usually performed.
The typical suite of logs run on an oil sand drill hole include caliper, natural gamma, gamma-gamma density, neutron, and resistivity. The interpretation of these logs with respect to bitumen content will vary from deposit to deposit and from place to place within a deposit depending on the characteristics of the host rock. In general, the natural gamma and the gamma-gamma density are most useful for determining lithology and the resistivity and neutron logs are useful in determining the amount of hydrocarbon in a unit. The resistivity of a unit is inversely proportional to the amount of water present. As the water decreases in an oil sand unit, the bitumen increases. Therefore the resistivity increases as the percent of bitumen increases. The neutron log responds to the hydrogen and to a lesser extent to the amount of carbon in a formation. It can therefore be a useful direct measure of the bitumen (hydrocarbon) present. The neutron log is also useful in detecting zones of gas.
The natural gamma and density logs can also be correlated to the percent of bitumen in an oil sand unit. There is usually a decrease in bitumen content with increased natural gamma count. This is due to the fact that the natural gamma responds to radioactive elements such as potassium isotopes present in clays, and as the clay content increases, the porosity and permeability decrease, resulting in a lower bitumen content. The bitumen saturation tends to increase as the density of an oil sands unit decreases. The decrease in density is often due to an increase in porosity in the formation resulting in an increase in the amount of bitumen in the pore space.
These relationships are generalizations that will have exception in some deposits. The response of geophysical logs must be correlated with drill cores for each deposit and for various areas within a single deposit to insure reliable interpretation of the logs.
ASSAYING
One of the most important aspects of oil sands exploration is the determination of the amount of oil present in the rock.
There are three methods in common use for determining the amount of bitumen in an oil sand sample: the Dean-Stark method, the Soxlet method, and the modified Fisher assay. In some cases, a modification of these standard procedures is used for a particular deposit but the vast majority of samples are assayed using one of these standard techniques.
The Dean-Stark method is the most widely used analytical technique for determining the weight percent of oil in an oil sand sample. The technique consists of weighing the sample, then removing the bitumen and water with a hot solvent, such as toluene. The water evaporates and is trapped and weighed. The bitumen is lost in the solvent. The remaining sample is weighed and the weight percent of bitumen is determined by difference.
The Soxlet technique is similar to the Dean-Stark method except that the water is lost and the bitumen is recovered and measured directly. More specifically, the sample is weighed and hot solvent is percolated through the sample to remove the hydrocarbon. The solvent is then boiled off leaving the oil or bitumen which is then weighed directly. The method allows the oil to be tested for viscosity and other properties. It is advisable
to run both the Dean-Stark and Soxlet on splits of the same sample so that both the water content and the properties of the oil can be measured on at least a few samples. A third and less costly method for determining the amount of oil in a sample is to heat it in a retort and measure the amount of oil that comes out. This method is the modified Fisher assay used for oil shale. With this method there may be some small losses of the hydrocarbons or some hydrocarbon may remain in the sample. Therefore, duplicate samples should be tested using the Dean-Stark or Soxlet methods. Results from retorting have been quite successful on some deposits resulting in considerable savings in analytical costs.
Another indirect method of determining the amount of oil in a deposit is by inference from geophysical logs. This can only be accomplished after correlation between core analysis and geophysical logs has been established. This can be a cost effective and reliable method but must be used with caution because many geological variables can affect the geophysical response.