To determine wellbore tortuosity, the industry uses different methods. Well trajectories can be calculated between survey stations in the wellbore with the resolution of the tortuostity dependent on the survey frequency. Friction factors within the wellbore can be back calculated from surface torque-and-drag information and used as empirical indicators of tortuosity change over the open-hole section. Neither of these previous methods however provides sufficient resolution to accurately quantify the severity and location of the wellbore macro- and micro-tortuosity. The use of downhole strain gauges to identify variations in hole condition and wellbore tortuosity, as well as how they effect the bending stresses in the bottomhole assembly (BHA), has enabled a significantly more accurate method of quantifying this tortuosity.
Downhole strain gauges are used to measure compression and tension, torque, bending moment, and bending-moment direction at specific locations within the BHA. These measurements are used in the following manner to derive the actual downhole values for the following properties: weight on bit uses downhole tension and compression; overpull uses downhole tension; the downhole torque is used to determine how much of the surface power is reaching the BHA and drillbit; and the bending moment of the BHA is used to determine the bending stresses being applied to the BHA. In addition to these accepted methods, the bending moment is used by this new approach to show details of the location and severity of wellbore tortuosity and highlights how the measurement is influenced more by changes in the wellbore trajectory than by the application of compression or tension to the BHA.
Source: SPE/IADC Drilling Conference and Exhibition, 17-19 March 2015, London, England, UK
Authors: Chris Marland (Halliburton) | Jeremy Greenwood (Halliburton)