Prior to running a BHA most oilfield service providers have software to model the BHA behaviour such as the maximum WOB achievable, the directional tendencies & capabilities and even the natural harmonics of the assembly as to avoid vibration brought about by exciting natural frequencies.
Rotary assemblies[2] are commonly used where formations are predictable and the rig economics are an issue.
In such an assembly the weight of the drill collars gives the BHA the tendency to sag or flex to the low side of the hole, collar stiffness length and stabiliser diameter and placement are engineered as a means of controlling the flex of the BHA.
The length of the section AFTER the near bit stabilizer would determine the extent of the angle build rate.
In short the longer the gap between the near bit and the drill string stabiliser the greater the angle building rate.
This hanging means that there is a force acting on the low side of the hole, which causes the deviation.
In this instance the weight may be applied by running the drill pipe in compression in the high angle section.
The high angle may help to stabilise the drill pipe allowing it to carry some compression.
They play a major part in directional drilling as it helps determine the well-bore path and angle.
Replaceable blade stabilisers can maintain full gauge stabilization, but their blades can be changed with tools no machining or welding required Sleeve type stabilisers have replaceable sleeves that can be changed in the field.
Reamers are stabilisers that have cutting elements embedded on their fins, and are used to maintain a gauged well-bore.
The underreamer utilises an increase in mud pressure or flow rate to deploy the expandable cutters.