Drillstring Vibrations: Classic Ideas and Modern Approaches - Wave Propagation in Drilling, Well Logging and Reservoir Applications - page 114

at the rock-bit interface introduces a strong dynamic coupling not addressed in
the interdisciplinary literature. Third, high static torque levels, due to large
weight-on-bit, will strongly couple both lateral bending modes. Unsteady torque
reversals and stick-slip, in particular, introduce difficulties new to the
engineering literature. Thus, while each of the axial, torsional and lateral
vibration modes in itself is of academic interest, it is the combined effect that is
of practical importance. But because all of the displacement modes interact with
each other, it is essential to study each separately, at least initially, in order to
ensure physical integrity and to minimize the possibility of formulation errors.
4.1.2.6 Transient and dynamically steady oscillations.
When drillstrings rotate at constant speed, all of the above vibration modes
may be excited, leading to superpositions in axial, torsional and bending
displacements. If the resultant motion is a “standing wave pattern” that does not
change in time, the system is “dynamically steady,” which is not to say that the
drillstring is stationary. When each of the vibrations is studied separately, we
find that their standing waves contain “nodes” where motion ceases. By
contrast, deflections are maximum at “antinodes,” where vibration dampeners
might be placed. Understanding the nodal nature of vibrations is important: a
sensor for lateral vibrations detection, for example, is useless if it is mounted at
a nodal point. Good engineering skill, of course, is necessary in deciphering the
many complications that are likely downhole. For instance, a collar-mounted
strain gage will measure elongations due to axial, torsional, and lateral
vibrations, not to mention those due to thermal effects. Positioning at nodes and
antinodes will affect signal-to-noise ratio, and hence, measurement integrity.
Motions that are not dynamically steady are transient: they track irregularly
with time. This is so when drillbits bounce, when drillstrings “make hole” too
fast, and on startup of rotary drilling. Bit bounce, for example, induces surges in
drillpipe mud pressure, causing MWD signal detection problems; changes in
flow rate at the nozzles will also affect loads at poppet valve and mud siren
pulsers. Transient loads may be destructive, leading to drillpipe fatigue and
wear. When their accelerations are large and occur over extremely short time
periods, the loads are called “shocks.” Shocks are measured in g's per unit time,
e.g., “g' s per sec,” and very often, they are additionally characterized by “shock
frequency.” In qualifying MWD tools for field use, shock levels and
frequencies must be specified together with the manner in which the tool is
shock-tested, that is, its “drop axis” or axes.
4.1.2.7 Understanding the environment.
Whether our objective is designing a better BHA for directional use,
drilling with less likelihood of fatigue failure, or making hole faster, it is
important to understand what the downhole environment is and what its