| dc.description.abstract | A new mathematical model is developed for the nonlinear-static, linearized-dynamic, and fully nonlinear-dynamic behavior of drillstrings in arbitrary wellbore profiles. The formulation is based on a three-dimensional nonlinear finite beam element and accounts for the fully coupled flexibility of the drillstring, geometric nonlinearity (large displacement, small strain), automatic determination of wellbore contact points, friction acting between the drillstring and the wellbore, stabilizer clearance, three-dimensional wellbore profiles, added fluid mass and damping effects from the hydrodynamic forces generated between the drillstring and surrounding fluid, complex tool geometry (including steerable mud motors, rotary steerable systems, and eccentric stabilizers/components), shear beam deformations, lateral rotary inertias, and gyroscopic effects. The resulting model is numerically validated through comparisons with analytical formulas and previous nonlinear models, showing that it can readily be applied to a wide range of drilling engineering problems and used for practical analysis. Additionally, individual contributions of shear deformations, lateral rotary inertias, and gyroscopic effects are definitively shown to be insignificant when calculating the static and dynamic behavior of horizontal drilling assemblies within the rotational speed range of most drilling applications. An initial comparison with field data is also provided, which shows the practicality of the developed algorithms in predicting the characteristics of real drilling scenarios.
The model is then adjusted and applied to the specific case of inducing lateral vibrations in unconventional horizontal wells. It is proposed that exciting a lateral resonance in the drill pipe lying on the low side of a horizontal wellbore can induce enough movement to help overcome parasitic axial drag acting on a drillstring. This, in turn, would help to increase weight transfer to the bit while slide-drilling with a steerable mud motor in long lateral sections of a wellbore. The change in this lateral resonant behavior due to variations in weight-on-bit (WOB), inclination, well path curvature, wellbore diameter, fluid properties, and tubular dimensions are clearly shown through linearized-dynamic sensitivity studies. Nonlinear time-domain simulations are also performed to better understand the limitations of linearized-dynamic modeling and to provide a more detailed assessment of how inducing lateral vibration influences the WOB while drilling. It is shown that induced lateral vibrations provide a noticeable dynamic WOB of up to ± 250 lbf about the static value, and a slight increase in the average WOB value of up to 150 lbf. The effects on WOB are dependent on the excitation frequency of the induced lateral vibrations, with the greatest benefits being seen at resonant conditions. | en |
