Estimation of Permeability in the McMurray Formation Using High-Resolution Data Sources
- John G. Manchuk (University of Alberta) | David L. Garner (Halliburton/Landmark) | Clayton V. Deutsch (University of Alberta)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- Publication Date
- April 2015
- Document Type
- Journal Paper
- 125 - 139
- 2015. Society of Petrophysicists & Well Log Analysts
- 3 in the last 30 days
- 287 since 2007
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Building geomodels useful for predicting the dynamic performance of in-situ recovery processes, such as SAGD in the McMurray formation, is dependent on many factors, permeability being one of the most critical. The method of characterizing and distributing permeability in a facies model is important to account for the full heterogeneity of the formation. Direct measurements of reservoir permeability are usually obtained from core-plug samples; however, this data can be problematic because it may not represent the true permeability distribution, and it can be biased due to physical limitations of obtaining plugs. Two forms of high-resolution data that can be used to supplement core-plug data and estimate permeability are core photographs and high-resolution microresistivity image (HMI) logs. Both can be used in a process called micromodeling to obtain estimates of distributions for porosity and permeability. An important feature of the process is that micromodels can be built at a variety of scales, or used in a hierarchical multiscale fashion, to obtain effective properties at the desired scale for further use in geomodeling and subsequent flow simulation. Application of the approach to an HMI log covering the full thickness of the McMurray formation indicates a trimodal distribution between porosity and horizontal and vertical permeability that is logical given the architectures observed in the McMurray formation and the percolation nature of flow in heterogeneous systems.
IntroductionOver 80% of the Athabasca oil sands are recoverable using in-situ extraction methods. The application of insitu processes for the recovery of the Athabasca oil sands continues to grow rapidly with the potential to access hundreds of millions of barrels of bitumen that was until recently economically inaccessible. Steam-assisted gravity drainage (SAGD) is considered to be a standard in-situ technology with many SAGD-based hybrid technologies under evaluation. Predicting the performance of a SAGD-based operation is important to evaluating its economic viability. SAGD history matching is sensitive to the scale of the heterogeneities and variability of properties. Practically speaking, the model grid sizes by necessity must be small to accurately simulate the recovery process length scales for heat and solvent mass transfer (Gates and Wang, 2013). The facies geomodel should be simulated for each grid scale to ensure the reservoir properties are represented fairly. The details help to match or estimate not only the ultimate recovery and steam injection but the production and injection profiles over the entire well life. This is important for realistic forecasting. Thermal flow simulators are used to emulate the steam injection and oil-drainage process. One of the most critical parameters for this is vertical permeability, since the majority of flow occurs due to the force of gravity. Bitumen that is mobilized through melting by the added energy from rising and spreading steam drains downwards to a production well positioned near the base of a recoverable interval of a reservoir pay zone.
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