American Oil and Gas Reporter - September 2015 - 107

SpecialReport: Tubulars Technology
to the drilling flow rate. At this point,
surface WOB and off-bottom differential
pressure were zeroed.
As the bit was placed back on bottom,
WOB and differential pressure were increased immediately to just below the
target drilling value. There was no "feathering in" of the bit. As the bit drilled
ahead, the parameters were increased,
taking care to avoid creating strong stickslip or stalling the motor. Parameters
then were optimized to maximize penetration rates while monitoring the downhole dynamics data for problems.
In order to safely pull the bit off
bottom, rpm was decreased to 20 before
allowing up to 75 percent of WOB or
differential pressure to drill off. Optionally,
the flow rate also could be reduced to reduce motor rpm. The rotary and pumps
were stopped then and the bit was lifted
off bottom to make a connection.
In addition to following these procedures, it was vital to monitor the realtime feed from the downhole dynamics
tool to prevent motor stalls or strong
stick-slip events, and to ensure that the
procedures were having the desired effect.

This was especially important when reducing flow rate, since reducing hydraulic
lift has the effect of increasing effective
WOB, making a motor stall or bit damage
more likely. In practice, the procedures
made a major difference in the number
of observed whirl events, although the
training process required a number of interventions by the well site experts.
Using the continuous rotational inclination from the downhole dynamics tool
allowed deflections and drift from vertical
to be quickly identified and corrected. If
the inclination was building above 3.5
degrees, the driller lightened WOB and
possibly increased rpm to allow the inclination to drop back to zero. This continuous early warning allowed for a much
smoother vertical wellbore and obviated
the need for a separate MWD system, reducing cost and system complexity. Typically, this slight reduction of WOB and/or
increase in rpm did not cause a loss in
ROP, and the inclination corrected itself
within a couple stands (Figure 5).
The vertical sections of both the fifth
and sixth wells used the rotational inclination from the dynamics tool, but also

included an MWD survey tool in the
BHA placed 40-50 feet behind the rotational inclination measurement. The position of the rotational inclination continued
to provide the look-ahead value of identifying wellbore build from zero degrees
inclination, allowing drillers early parameter response to keep the wellbore
vertical.
❒
RICHARD TAYLOR is a drilling
optimization adviser for U.S. land
drilling at Baker Hughes, supporting
the implementation of drilling dynamics
technology at the well site, providing
technical analysis of data, and facilitating real-time intervention in the
drilling process. He joined the company
as a drilling fluids engineer in the
North Sea in 2001, and then from
2004 served as a drilling optimization
engineer for projects around the world.
Taylor began his career as a mud
logger and data engineer, first at
Geoservices and then at Datalog Technology Inc. He holds a B.S. in geology
from the University of Edinburgh.

What you're reading is more than just copy. It's also copyrighted. So before you head over to
the photocopier, make sure you have permission. Contact the publisher or visit www.copyright.com.

SEPTEMBER 2015 107

American Oil and Gas Reporter - September 2015

Table of Contents for the Digital Edition of American Oil and Gas Reporter - September 2015