16.- DIRECTIONAL

VIBRATION IN BOTTOM HOLE ASSEMBLY

When drilling a well there is a risk of serious damage caused by drillstring vibrations. Shock and vibration are identified as a cause of premature failure on drill bit and components in the bottom hole assembly (BHA), resulting in lost time for operators and costing service companies several millions in repair each year. The expenditures incurred by drillstring vibrations include reduced rate of penetration (ROP), tripping and poor drilling performance. Currently, several tools and techniques are used in the attempt to minimize shock and vibration. For vibration mitigation to be more effective in the future, the most effective tools and techniques must be designated, implemented and improved.

Predicting bottom hole assembly (BHA) vibrations is a complicated problem. Axial, lateral, and torsional vibrations can be coupled and effects such as stick-slip and whirl can magnify the loads. Fatigue, pipe bouncing, and tool joint washouts demon e the complexity of the problem. One type of vibration that can be isolated and analyzed is the rapid destruction of the BHA caused by operating at or close to resonance. At rotating speeds that reinforce the natural vibration of the BHA, the destructive harmonics generate high stresses resulting in very short fatigue life. While other factors may cause BHA failure, a significant percentage of field failures appear to be associated with harmonic vibration, particularly lateral vibration. A simplified model based on harmonic analysis using finite elements has been found to agree well with field experience. The influence of stabilizer placement, drill string forces, and mass of the drilling mud are included in the finite element vibration model. (SPE-16675-MS)

AXIAL VIBRATION : Can cause bit bounce , which may damage bit cutter and bearing.

TORSIONAL VIBRATION : Can cause irregular down - hole rotation. Stick/Slip is often seen while drilling and is a severe form of drillstring torsional oscillation in which the bit becomes stationary for a period. Torsional fluctuations fatigue Drill collars connections and can damage bits. The use of the mud motor may help to address if the main source of excitation is from the bit but the presences of a motor does not prevent stick/slip . The drillstring and BHA  above the motor can enter into a stick/Slip motion even when the motor is turning the bit a steady rate.  

LATERAL VIBRATION : are most destructive type of vibration and an create large shocks as the BHA impacts the wellbore wall. The interaction between BHA and drillstring contact points may, in certain circumstances , drive the system into backward whirl. Backward whirl is the most severe form of vibration, creating high - frequency and large - magnitude bending moment fluctuations that result in high rates of components and connections fatigue. Imbalance in an assembly will cause centrifugally induced bowing of the drillstring , which may produce forward whirl and result in one - side wear of components.  

   

1.- Schlumberger

2.- Halliburton 

SUMMARY

Stick-slip and whirl are vibrational problems that limit drilling performance in hard formations and extended reach wells. When these vibrations are present, adding roller reamers to the drillstring can significantly reduce their severity and improve performance. Whirl is characterized by lateral vibration at the bit and in the BHA. When whirl becomes severe, lateral vibrations cause significant side forces in stabilizers. Frictional drag then causes high torque levels at the stabilizers, which can result in stick-slip (fluctuations in BHA rotational speed). This is referred to as “coupled stick-slip.” When these conditions exist, the replacement of stabilizers with roller reamers reduces torque generation at the contact points. Consequently, more torque becomes available to the bit and the driller may raise WOB. This results in reduced bit whirl and improved ROP. The reduction of bit whirl and elimination of stick-slip prevent damage to bit and BHA components

Figure5 shows diagram for each of the three BHA configurations. Note that there are two stabilizers configured in BHA-2. The stabilizer is located at the far left to the bit in BHA-3 compare with BHA-2. There is one stabilizer used in BHA-1 near the bit. The detail descriptions are as following:

 

Figure6 provides state vectors display comparison for three of BHA surrogates operation at 100RPM and 80000N of bit weight. The lateral vibration potential simulation for BHA-1 is significantly lower than BHA 2 and BHA-3. Especially for the lateral displacement, the effect is most remarkably, which means that the contacts for BHA-1 with wellbore may be less than other BHA surrogates during drilling process. However, the yellow color curve shows the larger amplitudes of the states for BHA-2 than others, which represents the most severe vibration potential.

Prepared by : O.Bohorquez
Update:24.07.19