Vibrations generated in a drill string while drilling generally lead to a reduction in drilling efficiency and often cause premature failure of drill string components and bit damage. It is also known that lateral vibrations, in particular, are responsible for most measurement-while-drilling (MWD) tool failures while drilling. One way to increase drilling efficiency and avoid tool damage is to monitor and analyze drilling vibrations so that drilling parameters can be adjusted while drilling to reduce such vibrations. An alternative method is to analyze and determine the natural frequencies of the bottom-hole assembly (BHA) so that resonant conditions caused by various excitation mechanisms in the drill string can be avoided. Even though models have been developed in the past in the drilling industry to determine the natural frequencies of a BHA, few attempts have been made to demonstrate that such models do actually help reduce vibrations or failures. This paper deals with the process of field validation of model-derived frequencies for axial, torsional and lateral vibrations. The results presented in this paper are based on the analysis of drilling data from a field test using downhole vibration measurement sensors. The downhole measurements included X and Y bending moments, axial acceleration, dynamic weight-on-bit, dynamic torque, and X and Y-axis magnetometers mounted in an MWD sub. The data analysis demonstrates that the natural frequencies predicted by the models match well with actual field (measured) values at the locations of interest, particularly for lateral vibrations. This analysis therefore shows that model derived results can be used with a degree of confidence to help avoid resonant conditions in a BHA while drilling and to help reduce failures.
Rig downtime due to MWD tool failure is expensive, particularly on offshore rigs with extremely high operating costs. There are different reasons for tool failures, one being the high vibration loads on MWD tools under extreme drilling conditions. MWD and LWD tools are usually equipped with sensors to measure and record vibrations for drilling efficiency and optimization. The goal of the study described in this paper is to establish the link between MWD or LWD tool failure, and drilling dynamics. With this knowledge, it is possible to reduce failure rates and costs with real-time monitoring of downhole drilling dynamics. To analyze the effect of drilling dynamics on MWD tool failures, a unique database of MWD runs in challenging environments was created. This database includes vibration data recorded at 5-second intervals from more than 12,000 drilling and reaming hours, over a total footage of 425,000 feet. In addition to unique dynamics data such as weight, torque, bending moments and axial, lateral and tangential RMS and peak accelerations, the database included detailed run and failure reports, and environmental information such as well profiles and drilling operations. A statistical study using the logistic regression indicates the types of dynamic behavior most statistically significant in MWD/LWD tool failures. These are cumulative lateral vibrations and backward whirl. Cumulative axial or tangential acceleration appears not to be significant in current MWD/LWD tool failures. A study on the correlation between recorded MWD tool dynamics and tool failure rates established the link between time spent operating above a level of vibration and the probability of tool failure. This paper contains charts describing this relationship between dynamics, operating hours, and MWD/LWD tool failure rates. These charts are valuable in operational risk management and in developing procedures for optimal drilling practices that reduce the dynamic loads on the MWD system, resulting in prolonged tool life and reduced cost.
Electromagnetic (EM) systems are used for MWD telemetry during drilling. The deployment of EM telemetry systems is only successful when the signal does not vanish in noise. Knowing the attenuation profile with depth of an EM signal is a helpful guide for predicting successful deployment. This paper details several case studies on the different attenuation profiles in North America.In the case studies the actual signal strength was measured by an EM surface system at the wellsite, with a field operator logging the measurement against depth. EM signal amplitude generally attenuates exponentially against depth, although this is highly dependent on mud and formation resistivities. While modeling provides information about the expected signal tendencies (for example, the effect of casing on signal amplitudes), EM transmission is heavily influenced by many factors, among them the presence of extremely resistive thin beds in the formation and the distribution of surface resistivity. These factors are hard to include in the simulations. The case studies included here illustrate the different relationships between actual measurements and depth.By understanding the EM signal attenuation within a region it is possible to validate and calibrate EM transmission models, so that the successful deployment of EM telemetry systems can be predicted.
BSTRACTDrillstring vibrations while drilling cause premature drillstring co~ponent and bit failure, and represent a waste of drilling energy. To Increase drilling efficienc¥, drillstring vibrations are monitored and analyzed and the optimum drilling parameters and practices are determined as a well is drilled. This results in a reduction in the frequenc¥ of drillstring failures and the amount of time spent tJ1Jping and/or fishing, ard an increase in both bit IWe ard drilling rate. This paper presents vibration signatures and analyses selected from over 15,000 hours of vibration data obtained using a surface vibration measurement sub. The case histories demonstrate the surface detection of drillstring resonance, BHA (Bottom Hole Assembly) lateral vibrations, PDC (fixed cutter) bit whirl, shock sub closure, torsional string oscillations, premature bit bearing failure and impending stuck pipe. INTRODUCTIONDuring drilling, various sources excite the drillstring. The amplitude of the resultant drillstring vibrations will depend on the level (severity) of the excitation, the system damping, and the proximity of the excitation freque"C¥ to a natural freque"C¥ of the drillstring. When the freque"C¥ of any of the excitation sources is a natural frequenc¥ of the drillstring (axial, torsional or lateral) then the string resonates. Vibration levels are generally highest at resonance, but high level vibrations may exist in the drillstring, independent of drillstring resonance, whenever a high level of excitation is present.Drilling with large amplitude vibrations will result in accelerated drillstring fatigue. A recent study! of drillstring failures indicated that fatigue was the primary cause of the examined failures. Most current efforts aimed at understanding and controlling drillstring vibrations focus on the failure of drillstring components. However, during drilling the drillstring transfers power from the surface to the bit and high amplitude drillstring vibrations may represent a loss, or waste, of drilling energy. Therefore, high levels of vibration not only result in drillstring component failures but can also result in suboptimum drill rates.References and illustrations located at end of paper The avoidance of high vibration levels can be attempted in two ways: (a) the BHA can be modeled and a harmonic analysis performed to predict the operating conditions, weight-on-bit (WOB) and rotary speed (RPM), which avoid resonant conditions, or (b) the vibrations can be directly monitored while drilling to determine the optimum operating conditions (WOB, RPM and pump rate).The use of modelling analysis is limited by the number of unknowns that occur in real-time drilling operations. In addition, most models focus on drillstring resonance frequencies, and estimate bit rotary speeds which will avoid exciting these frequencies ("critical speed" analysis). Therefore, they do not take into account high level excitations independent of this resonance analysis. Dynamic models do offer the ability to understand drillstring dynam...
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