A modeling tool has been developed that enables drilling engineers to design vibration resistant bottom hole assemblies (BHA's), given tool placement constraints and desired directional objectives. This model can be applied to configurations with the majority of common components, including rotary steerables, bi-center bits, roller-reamers, hole openers, and eccentric mass stabilizers. Modeling results have been validated in large, intermediate, and small hole sizes. In these applications, predicted behavior and field observations have compared well. Redesign has resulted in improved drilling results, including increased on-bottom drilling time, longer tool life, higher Rate of Penetration (ROP), reduced non-productive time associated with tripping, and even better hole quality.
As use of the operator's ROP management process has spread through the company (Dupriest, 2005), downhole vibrations have been identified as one of the most significant factors limiting further ROP and footage improvements. Rig site personnel use vibrations data from downhole sensors and Mechanical Specific Energy (MSE) diagnostics to achieve the minimum vibrational levels possible with the existing assembly. The nature of the remaining vibrations is identified, and the BHA is then redesigned in a way that addresses the specific form of vibration that is limiting performance. The field assessment of the vibrational limiter and the redesign process are repeated from well to well.
Vibrations mitigation is posed more as a design problem than an analytical one. The model characterizes the lateral vibration, or whirl, tendencies of BHA's, enabling quick and easy comparison of potential BHA design candidates. A BHA can be designed to minimize vibrational tendencies for a given set of operating parameters, or the optimal operating parameters can be predicted for a given BHA configuration. The model has unique displays to support both pre-drill vibrations forecasting and post-drill hind casting. Several case studies are provided to illustrate the value of this technology.
Introduction
Vibration of drillstrings and bottom hole assemblies has contributed to operational problems since rotary drilling was first invented in 1930. Failure of drillstring components, such as Rotary Steerable (RSS) or Logging While Drilling (LWD) tools, may result in non-productive time while tripping to replace the failed equipment. Downhole components may eventually part so that fishing or sidetracking operations are required. In some situations, equipment failure may also result in well abandonment. In addition to these unplanned events, whirl or lateral vibration causes the cutting action of the bit to be inefficient and ROP may decline significantly. The operator drills approximately four million feet of hole each year, and MSE analysis suggests the performance in over 40% of this footage is adversely affected by whirl.
At various times in the past, investigators have focused on certain elements of the drillstring dynamics problem and made some progress, to be succeeded by new theories using generally more complicated models. Critical rotary speed guidelines were included in early editions of the API RP7G drillstring standard (e.g., 1984). One critical speed formula depended on the length of a drillstring, thus identifying a vibrational depth-dependency, but this section was deleted from later versions because it was considered to be insufficiently precise. Dareing (1984) found that the length of drill collars in particular is a key element in the bottom hole assembly (BHA) vibration problem. Mitchell (1987) identified harmonic resonance of the BHA as a major factor in several case studies of BHA failures. Spanos and Payne (1992) used a frequency domain eigenmode analysis to investigate the problem, primarily focusing on the identification of critical modes and corresponding rotary speeds. Critical mode analysis is still of interest in present models (e.g. Chen, 2007).
