--> Abstract: Controls on Bitumen Heterogeneity in the Athabasca Oil Sands Deposit - Evidence from Cores and Outcrops, by M. Fustic, B. Bennett, H. Huang, R. Spencer, S. Hubbard, and S. Larter; #90075 (2008)

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Controls on Bitumen Heterogeneity in the Athabasca Oil Sands Deposit - Evidence from Cores and Outcrops

M. Fustic 1,2, B. Bennett1, H. Huang1, R. Spencer1, S. Hubbard1, and S. Larter1
1Alberta Ingenuity Centre for InSitu Energy, University of Calgary, Alberta
2NEXEN Inc., Calgary, Alberta

The Athabasca Oil Sands Deposit (AOSD), the world’s largest petroleum accumulation, contains an estimated 1.7 trillion barrels of heavily biodegraded oil with API gravities ranging from 6 to 11. Current exploitation technologies involve surface mining combined with bitumen recovery by warm water extraction and also by using in-situ extraction methods such as Steam Assisted Gravity Drainage (SAGD). The recovered bitumen is upgraded by thermal or hydro cracking treatments to produce a synthetic crude oil. Both processes require a large amount of energy and water to recover the bitumen.

Conventional approaches that are used for evaluating the bitumen resource are biased towards a description of the reservoir quality using classical methods that describe the variation in rock properties, however, very little attention is given towards measuring the variation in bitumen composition and ultimately mapping how these variations may extend laterally and vertically throughout the bitumen resource.

In this study, we have measured the bitumen physical and chemical property variation on a suite of samples obtained from cores and outcrops. The variation in bitumen viscosities and changes in the hydrocarbon composition due to varying levels of biodegradation (interpreted using molecular markers) were integrated into the depositional facies framework and correlated with the various reservoir descriptions including:

  • presence or absence of a water leg in contact with the bitumen
  • continuous (Fig. 1) or compartmentalized (Fig. 2) reservoir columns
  • lithologies
  • porosity and permeability

Results demonstrate that the bitumen residing in the AOSD is highly variable in terms of hydrocarbon composition and physical properties on both vertical and lateral scales. In general, the viscosity of the bitumen residing at the base of an oil column may be an order of magnitude higher than the bitumen located higher up in the reservoir (i.e. at the reservoir temperature of 4 °C the viscosity may be 5 million cP at the base and 0.3 million cP at the top). While this is a general rule, detailed analysis of the composition of a number of petroleum columns sampled at high resolution have shown that physical and chemical property variation in various areas may show anomalous inverse gradients, and steps in compositional trends coinciding with geological features or due to other factors that may not be readily apparent. For example, our results obtained so far indicate that even very closely spaced compartments (<5 m) may contain not only bitumen with very different properties, but also that the bitumen composition may be used to define the presence and how effectively the barriers have influenced fluid communication between the compartments.

Molecular evidence strongly supports the notion that biodegradation is the dominant alteration process responsible for present day bitumen properties and composition. Shallow post-depositional burial history of petroleum hosting sediments (McMurray Formation) and associated low reservoir temperature history evidenced from vitrinite reflectance supports favourable conditions for the establishment of petroleum degrading microbial communities over the life span of the reservoir.

Consequently, the measured chemical and physical properties of the bitumen are a function of the geological features and reservoir factors controlling the intensity of the biodegradation. Due to the high degree of reservoir complexity encountered in the Athabasca oil sands deposits, studying those factors alone has inherent difficulties. Thus, sample sets from each well and/or outcrops were treated as a unique case study and were carefully interpreted considering many sedimentological, reservoir conditions and petroleum system factors. A detailed study of both rock and fluid properties of the AOSD has now led to an appreciation that many different components may be considered in an integrative way to ascertain the controls where biodegradation may be increased while other factors are considered to mitigate degradation. The level of biodegradation commonly increased:

  • downhole as a function of “deepening” paleo-oil water contact (Fig. 1)
  • along the present day water-bitumen interfaces as a function of active biodegradation evidenced from neo-formation of 25-norhopanes
  • within so called “lean zones” where recent water charges have partly flushed less biodegraded but still mobile oils or ancient gas caps
  • below vertical compartments when these isolated the upper compartment and protected it from more intense biodegradation occurring in the lower one along the present day water-oil contact
  • with increased porosity and permeability, perhaps due to increased fluid mobility and associated increased nutrient supply. (this infers that the best reservoirs in terms of reservoir quality are not the best in terms of bitumen quality)

The intensity of the level of the biodegradation was interpreted to decrease because of:

  • salty brines along the present day water-bitumen interface (these brines are common in AOSD subsurface and are associated with dissolution of salts from the Prairie Evaporate Formation).
  • possible late petroleum charge of more mature oils or possibly of oils from different source rocks
  • vertical compartments when they did not allow better (lighter?) oil (possibly emplaced as a late charge) from the lower compartment migrating to the upper compartment (Fig. 2).

The above information indicates the range of chemical and physical property variations, laterally and vertically, that may be encountered in the AOSD. The results proved that placing geochemical results into the sound depositional facies framework allows for a more comprehensive interpretation of processes leading to the encountered bitumen heterogeneity in the reservoir. The latter further allows for conceptual prediction of bitumen qualities in different portions of the reservoir as well as for mapping bitumen properties in the subsurface. The information may be used to assist in prospect evaluation and exploitation, and can indicate where potential recovery problems may occur when a resource is evaluated for InSitu operations as well as for explaining discrepancies in recoveries (through history matching of production information) from different reservoir zones in existing operations. A detailed study of both rock and fluid properties of the AOSD has now led to an appreciation that many different components may be considered in an integrative way to ascertain the controls where biodegradation may be increased while other factors are considered to mitigate degradation.

Despite the extra heavy oil nature and solid phase appearance of AOSD bitumen and despite the age of the field provided, the interpretations are in the line with the findings reported from many heavy oil reservoirs worldwide, suggesting that controls on biodegradation are universal. In the case of the AOSD bitumen heterogeneity is enhanced due to extreme reservoir complexities in terms of sedimentology. However due to the close proximity of the resource to the surface and the access to core material, via the thousands of densely drilled hole it provides an excellent opportunity to perform further studies that integrate the geological interpretations with the compositional heterogeneities that have been introduced due to biodegradation.

Figure 1. Physical and chemical methods show changes in bitumen quality and molecular composition downhole along the single petroleum column in AOSD. Left: disappearance of sterane and severe attack on diasterane compound indicates increased biodegradation from level 6 to level 9 on PM scale (Peters, K.E., Moldowan, J.M., 1993. The Biomarker Guide: Interpreting Molecular Fossils in Petroleum and Ancient Sediments, Prentice Hall, Englewood Cliffs, New Jersey, p. 363). Middle: Viscosity measurements shows that viscosity increased from 2 million cP at the top of the column to as low as 7 million cP at the base of the petroleum column. Right: the image of examined core (the length of each tube is 0.75 m.; bottom of each tube is on the right and the top on the left; black colour is due to bitumen stain on sand (bitumen saturated reservoir rock), and grey at the base and the top is mudstone that confines the reservoir. The white circles are sample points presented on the viscosity chart and m/z 217 mass fragmentograms; that track sterane compounds, on the left. In summary although bitumen looks the same in the core (solid phase) its physical properties and composition show that it is in fact very heterogeneous with the worst quality at the base of the continuous petroleum column.

Figure 2. One of possible effects of reservoir compartmentalization on bitumen quality and composition in the Athabasca Oil Sands Deposit (AOSD). Sedimentological compartmentalization is evident from gamma ray (GR) log and core images (first two columns on the left). In core image black is bitumen saturated sand and grey is impermeable mud layer that separates the reservoir into two compartments. Third column shows mz 192 with peaks of 4 phenantrene isomers from 5 samples collected at depths of 7.4, 27.1, 41.9, 49.4 and 57.4 meters. Changes in ratio of abundance between 3MP and 2MP as well as 1MP and 9 MP are obvious and are typical of biodegradation, since 1MP and 3MP are more susceptible to microbial degradation than isomers 2MP and 9MP. Viscosity and API gravity measurements (last two columns on the right) show not only vertical gradients within the each of the compartments but also increased bitumen quality at the top of the lower compartment. Note, viscosity is measured at 20 oC which is significantly higher than anticipated reservoir temperature of 4 oC inferring that projected viscosities will be even greater and even more pronounce the gradient. Increased quality may be because of late charge of more mature petroleum, salty water at the base, or other factors mitigating the intensity of the biodegradation.


AAPG Search and Discovery Article #90075©2008 AAPG Hedberg Conference, Banff, Alberta, Canada