Quantitatively Evaluating Far-Field Fractures by Analyzing Azimuthal Acoustic Waveforms: Case Studies in Vertical and Horizontal Wells

Abstract

To understand formation structures extending away from the wellbore, azimuthal acoustic waveforms are acquired with longer recording length compared to conventional sonic logging. Advanced acoustic waveform processing algorithms such as 3D slowness time coherence (3D STC) and ray tracing applied to the reflection waveforms allow for quantitatively determining the true dip, azimuth, and position of the reflectors in 3D space, especially for far-field reflectors that can't be detected or located by conventional logging methods. In this paper we discuss two case studies of fracture evaluation. For the first one, experiences indicated that natural fractures bring operation risk for horizontal wells in shale gas play of Middle Yangtze Basin, such as casing deformation or screenout. Therefore, it was of great importance to evaluate natural fractures before completion and fracturing design. The borehole resistivity image log provided fracture assessment at the wellbore but cannot assess far-field fractures. The surface seismic ant track depicted fracture distribution on a large scale, yet with limited resolution. Azimuthal borehole acoustic reflection imaging filled the gap in between by identifying fractures as far as tens of meters from the wellbore. In the cased-hole horizontal well, the natural fracture results from azimuthal borehole acoustic reflection imaging confirmed the mud losses encountered while drilling. The operator used the results to optimize the completion design by placing perforation cluster about 15 m away from the natural fractures, and to change the fracturing design by adjusting slurry rate and fluid volume accordingly. For the second case, azimuthal borehole acoustic waveforms were acquired twice with the first run along an interval of Longmaxi shale gas in the vertical section of a 12.25-in. hole and the second run in a deviated section of an 8.5-in. hole. The result of the first run revealed a layer boundary between shale and carbonate. For the second run, high-dip-angle fractures in carbonate formations were identified with a maximum distance of 32 m from the wellbore. The dip and azimuth agreed with the few conductive fractures identified by the borehole resistivity image, yet the former identified more fractures than the latter. The two case studies clearly illustrate that azimuthal borehole acoustic imaging can quantitatively evaluate far-field fractures away from the wellbore, e.g., the true dip and azimuth, as well as position in 3D space. This helps not only provide a better reservoir characterization, but also allows optimization of the completion and fracturing design.