Fracture Characterization Workflow Using High Resolution Azimuthal Seismic for Unconventional Jurassic Formation in Greater Burgan Field, Kuwait

In many unconventional resources, including shale gas, tight gas, and tight oil reservoirs, recognizing fracture clusters, co rridors, and their typical directions can have a significant impact on exploration and field development plans, as well as the placement of individual wells. Natural fractures are challenging to characterize and can only be achieved by integrating various aspects of geoscience, such as borehole data, stress regimes, seismic data, and regional tectonics. Other measurements, including outcrops, core samples, FMI, cross-dipole, and other fracture information, are determined solely at well locations, while geophysical methods can identify the a real distributions of fractures and fracture corridors between wells. This study introduces the f undamental concepts of seismic fracture characterization through the introduction of seismic anisotropy, equivalent-medium representation theories of fractured rock, and methods for obtaining fracture parameters from seismic data. The Greater Burgan area in South-East Kuwait contains tight, naturally fractured Jurassic reservoirs such as Najmah-Sargelu formation. Well performance in these unconventional reservoirs is dominated by this secondary, fracture related porosity and permeabilit y. An incomplete understanding of reservoir stress and fracturing can be a major source of NPT while drilling the wells. For these reasons there is significant business advantage to reducing the uncertainties related to precise mapping of the azimuths and intensities of formation stress and fracturing. This uncertainty reduction allows better sampling of the sub-surface during imaging and improves the ability of exploration teams to identify and characterize sweet spots before well planning and drilling. These stress and fracture parameters may be readily interpreted at a well from existing borehole image logs and core analysis. However, pre-drill determination away from the well is problematic due to reservoir heterogeneity and the fact that the scale of many fractures is not visible on the stacked seismic image. This means that any attempt to interpolate well properties is inevitably compromised, and that conventional seismic volumetric workflows incorporating automatic fault delineation (e.g. ant-tracking) fail to resolve all fractures. To achieve the desired outcome, a full azimuth characterization in the local angle domain is proposed. The output of this approach maps the complete recorded wavefield at the surface to every subsurface image point so that measurements of fracture orientation and intensity can be obtained in-situ and in-depth. As a result, geologists and geophysicists can analyze and investigate the output of the seismic data without the need to go back to interpolate any missing information or data. The main objective is to provide previously unattainable levels of subsurface knowledge to help geoscientists locate reservoirs and optimize exploration and development decisions.