Integration of Chemical Data into Reservoir Simulation - A Case Study from Western Canada
N. Marcano, H. Samimi, S. Larter, I. Gates, B. Mayer, H. Huang, B. Bennett, J. Adams, and R. Spencer
Alberta Ingenuity Center for In-situ Energy (AICISE), University of Calgary, AB, Canada
Alberta tar sands are unconsolidated sands saturated with heavy oil, which represent over 1.3 trillion barrels of resources in Lower Cretaceous reservoirs. The production of these reservoirs has been based on cold production (Peace River) and thermal recovery (Cold Lake, Peace River and Athabasca).
Different tectonic events in the Western Canada Sedimentary Basin have had an important role on the distribution and geochemical characteristics of the heavy oils in Alberta, and specifically the tar sands. The highly biodegraded oil (higher than 4 on the Peters and Moldowan scale) accumulated in this area is derived from conventional oil, sourced from the Exshaw and other sources during the formation of the Western Canada foreland basin, that migrated to the flanks of the basin and accumulated in a stratigraphic trap. Characteristics of the source rocks of the heavy oil produced from Lower Cretaceous reservoir are, at present, not easily identifiable because they have been overprinted by post accumulation processes, the main one being biodegradation, which shows regional and local variations (Evans et al., 1971; Deroo et al., 1977; Brooks et al., 1988, Larter et al. 2006).
Regional variations in oil composition and properties seem to be mainly caused by different maximum burial temperatures of the reservoirs (that prevents biodegradation when temperature exceeds 80ºC), mixing of oils (that refreshes biodegraded reservoirs) and possibly by maturity differences in the area (Adams et al. 2006; Larter et al. 2006). Locally, biodegradation levels that increase with depth in individual reservoirs have been observed and this has been accompanied by vertical viscosity gradients. Different gradients have been explained by proximity to the water leg, height of the water leg and charge history (Adams et al, 2006; Larter et al. 2006).
Major objective of this study was to generate chemical compositional data and incorporate it into the history matching protocol of reservoir simulation. In particular we hope to identify chemical proxies that could be used to monitor thermal recovery processes. We describe some bulk chemical, molecular and isotopic tracers suitable for this purpose.
For the geochemical investigations, a comprehensive reservoir geochemical protocol was employed. For example, in one representative well with progressively-biodegraded bitumen towards the oil-water contact transition zone, variation in bitumen content and composition are related to the position in the reservoir and biodegradation process, with levels ranging from 4 to 7 on the Peters and Moldowan scale.
The gross composition of the bitumen shows a high content of polar compounds, ranging from 42% to 52%, and greater asphaltene content toward the base of the reservoir. The inverse concentration trends of hydrocarbons and polar compounds indicate a relationship with the process of biodegradation, while the unusually high content of aromatic hydrocarbons could also indicate a direct relation with the source rock and its maturity.
Similarly, viscosity and API gravity vary significantly from top to bottom in the oil leg of the investigated well. The viscosity @ 20ºC ranges in one well from around 40,000 cP at the top to over 3,500,000 cP at the bottom, while in the same interval of depth the API gravity @ 20ºC varies from 10 to 6 degrees API and the percentage of sulphur increases from 1.2% to 2.3%.
To integrate the bitumen compositional data into a reservoir model for a thermal or a cold production recovery process, we used the approach of Larter et al. 2006, where a compositional oil model is included in the CMG Stars simulator. In addition, we developed procedures to link molecular geochemical data to the end members oils (TOIL, BOIL) used in the simulation, with a post processor that allows produced oil composition to be predicted and compared with observed produced oil composition, as part of a matching method.
Integration of compositional data into reservoir simulator protocols assists first the understanding of the development of the depleted oil zone and steam chamber and secondly improves the identification of well intervals that are not producing efficiently.
Adams, J., Riediger, C., Fowler, M., Larter, S., 2006. Thermal controls on biodegradation around the Peace River tar sands: Paleo-pasteurization to the west. Journal of Geochemical Exploration, 89, 1-4.
Brooks, P.W., Fowler, M.G., Macqueen, R.W.,1988. Biological marker and conventional organic geochemistry of oil sands/heavy oils, Western Canada Basin. Organic Geochemistry, 12 (6), 519-538.
Deroo, G., Powell, T.G., Tissot, B., McCrossan, R.G., 1977. The origin and migration of petroleum in the Western Canadian Sedimentary Basin, Alberta: a geochemical and thermal maturation study. Geological Survey of Canada, Bulletin 262, 136p.
Evans, C.R., Rogers, M.A., Bailey, N.J.L., 1971. Evolution and alteration of petroleum in western Canada. Chemical Geology, 8, 147-170.
Larter, S., Adams, J., Gates, I., Bennett, B., Huang, H., 2006. The origin, prediction and impact of oil viscosity heterogeneity on the production characteristics of tar sand and heavy oil reservoir. Petroleum Society’s 7th Canadian International Petroleum Conference. Paper 2006-134.
AAPG Search and Discovery Article #90075©2008 AAPG Hedberg Conference, Banff, Alberta, Canada