Geological Controls on the Origin of Heavy Oil and Tar Sands and Their Impacts on In Situ Recovery

Abstract Biodegradation of crude oil in subsurface petroleum reservoirs is an important alteration process affecting most of the world's oil deposits. The process preferentially removes light components from conventional oil to form heavy oil and tar sands, which are more difficult to produce and are more costly to refine. Although reservoir temperature is a key control on biodegradation, large variations in oil properties have been documented in accumulations from similar depths within a play area. Data from the Liaohe Basin, NE China and other basins in China and elsewhere, indicate that biodegradation is most active in a narrow zone at or near the base of the oil column in contact with the water leg. The availability of nutrients from mineral dissolution within the water leg is also thought to have a significant impact upon the degree of biodegradation. Thus the level of biodegradation increases with water leg thickness. Charge history and in-reservoir mixing, of continuously charged oil with residual biodegraded oil also have a significant impact on oil physical properties. The conceptual biodegradation model proposed combines geochemical and geological factors to provide a coherent approach to estimate the impact of degradation on petroleum and to help reliably predict biodegradation risk at the prospect level. Our geochemical approach can be used to locate sweet-spots (areas of less degraded oil), optimize the placement of new wells and completion intervals and help with production allocation from long production wells. Introduction Biodegradation has a large influence on oil physical properties, which typically reduces oil producibility by increasing oil viscosity. Viscosity and density are key properties for the evaluation, simulation, and development of petroleum reservoirs. In order to develop and manage heavy oil fields cost effectively, it is essential to understand the variation in petroleum fluid properties, especially viscosity throughout each reservoir within a field. A variety of studies demonstrated how oil properties in biodegraded oil accumulations can be predicted from core and cutting extracts prior to well testing using geochemical parameters sensitive to biodegradation1–5. McCaffrey et al. 2 identified geochemical parameters that are sensitive to the degree of oil biodegradation and to the quantity of the secondary charge and then developed transforms that related those geochemical parameters to oil quality. Those transforms were used to predict oil quality from geochemical analysis of sidewall cores. Smalley et al. 3 used a similar approach to predict oil viscosity in a biodegraded heavy oil accumulation. Guthrie et al. 4 developed a predictive model of oil quality based on a sample set of produced oils from Venezuela for predicting viscosity, API gravity, and sulphur content in oil-stained sidewall cores where these properties cannot be measured directly. Koopmans et al. 5 analyzed oils from a single oilfield in the Liaohe basin, NE China. They found the large variations in viscosity across the field can be explained by mixing, to various extents, of heavy biodegraded oils with less degraded oils. They established a simple binary mixing model, which may assist in predicting the viscosity of reservoired oils before production.

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