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Unconventional resources such as shale gas are becoming increasingly important exploration, development, and production targets. The variation in well performance observed between various shale reservoirs and indeed within individual basins and on individual pads, has served to dispel the myths regarding the perceived homogeneity of shale gas targets. With increased quantities of geological and engineering data and more quantitative and deterministic analyses, it is now clear that in order to ensure the economic success of shale gas production we must understand the microscopic and mesoscale heterogeneity of the shale reservoirs. This can be advanced through interdisciplinary studies that incorporate traditional and advanced geophysical data and methods with geological understanding and engineering measurements. This understanding is critical in field development, optimizing well placement, well spacing and length of horizontal wells, and the hydraulic fracturing effort needed to maximize recovery. Some of the key parameters are total organic content and porosity that control the resource density estimation, and geomechanical properties that are related to the rock’s mechanical strength. These parameters and their lateral distributions are needed for areal and interval selection in order to optimize stimulation programs.
As the only remote sensing tool, geophysics plays a unique role in the characterization of organic-rich shales through the estimations of lateral and vertical variations of geological properties, including but not limited to porosity, clay content (Vclay), and the total organic carbon (TOC), geomechanical properties (Young’s modulus and Poisson’s ratio), and stress (and natural fractures). It can help to identify the most prospective zones for stimulation planning. It is critically important to establish a quantitative link between geological and engineering parameters that may be obtained from seismic data by incorporating rock physics modeling. We use an improved anisotropic rock-physics model that includes TOC effects in addition to the effects of mineralogy, porosity, and fluid content on seismic and electrical properties of organic-rich mudstone. The modeling results suggest that an increase in the organic content generally reduces P-impedance and Vp/Vs while increasing the velocity anisotropy and resistivity. This general trend is further modified by the mineralogical composition (see the figure). These observations form the basis for the application of seismic attributes to characterize resource density and producibility of unconventional resources. We use wireline log and seismic data from shale gas reservoirs to demonstrate a workflow that may be used to map reservoir quality for unconventional resources.
In the end, “with unconventional resources, it’s all about the fractures” as is often claimed by reservoir engineers. There are three issues we need to deal with when talking about fractures:
- Mapping natural faults/fractures – We want to know the spatial distribution, the scale (micro or macro), the density, and the relationship to the stress field.
- Identifying “fraccable” intervals that can be easily fractured – We want to know the brittleness, the fraccability in terms of geomechanical properties, such as Young’s modulus, Poisson’s ratio, and stress field.
- Monitoring of hydraulic fractures – We want to know the length, height, and shape of the fractures.
This is also true for other types of unconventional resources such as tight sand and tight oil. Geophysics plays the key role in addressing all these “fracture” issues. So there are abundant opportunities to apply geophysical tools to characterize unconventional resources.