Challenges to the Heavy Oil and Tar Sand Industry – A Comparative Analysis of the Petroleum Systems for Two Super-Giant Foreland Basin Accumulations: The Canadian Athabasca Oil Sands and the Faja Petrolifera Del Orinoco (Venezuelan Heavy Oil Belt) and the Impact of Reservoir and Fluid Heterogeneities on Sustainable Recovery of Energy from Bitumen Reservoirs

John R. Suter¹, Dale A. Leckie², and Steve Larter^3
1ConocoPhilips, Houston, TX, USA
²Nexen, Inc., Calgary, Canada
³AICISE, University of Calgary, Calgary, Canada

Recoverable global non-conventional hydrocarbon resources are dominated by foreland-basin associated heavy oil and bitumen accumulations produced by biodegradation of conventional crude oils over geological time scales. Variations in oil charge, long charge histories, oil mixing and local controls on biodegradation result in the defining characteristics of such accumulations being large spatial variations in oil viscosity and other physical properties. These fluid variations impact all existing recovery processes and the high-energy inputs required to recover the bitumen present large economic and environmental challenges. The primary mechanism of biodegradation producing these deposits involves methanogenesis and dry gas commonly associated with heavy oils and bitumen.

The enormous accumulations of the Athabasca and Peace River Oil Sands of Canada and the Faja Petrolifera del Orinoco, or Orinoco Heavy Oil Belt, of Venezuela dominate global resources of bitumen and heavy oil. The Canadian resource contains some 1.7 trillion barrels of bitumen, with about 935 billion barrels in the lower Cretaceous McMurray Formation. Around 1.4 trillion barrels of heavy and ultra-heavy oil occur in the Early Miocene Oficina Formation of Venezuela. Despite significant differences, these huge accumulations are remarkably similar petroleum systems. Each occurs on the flexural margin of a complex foreland basin, superimposed onto pre-existing passive margins. Sediments were principally sourced from granitic shield terrains. The petroleum of the respective deposits was generated from passive-margin, marine source rocks, and emplaced by long-distance migration as conventional oils into broad, low-amplitude traps with significant stratigraphic components. Both deposits have unconsolidated, dominantly quartz sand reservoirs with exceptional reservoir quality. The shallow, relatively cool reservoirs had ideal conditions for biologic activity, resulting in severe biodegradation to produce heavy oils and tar sands. Sedimentologic, ichnologic, and biostratigraphic data from cores and outcrops, coupled with interpretations of extensive well log and 3D seismic datasets, reveal that both formations comprise non-marine to marginal marine sediments, mainly channelized fluvial, tidal-fluvial, and estuarine deposits. The oils have a wide range of properties with API gravities ranging from 5-11 and dead oil viscosities ranging from as low as a few 1000cP to over 20McP at reservoir temperatures.

The complex reservoir geology and variations in fluid properties combine to make very large variations in bitumen mobility under native or thermal recovery conditions. This impacts all existing recovery processes from cold recovery through to SAGD and CSS. We review the impact of these heterogeneities on current processes and look at the next generation of recovery methods including acceleration of biological activity in reservoirs to recover oil as methane or hydrogen; in-situ upgrading of oils in reservoir and the Nexen-Opti process.

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