American Oil and Gas Reporter - September 2015 - 102

SpecialReport: Tubulars Technology

Real-Time Data Improves Performance
By Richard Taylor

HOUSTON-The emergence of multiple unconventional targets in the
Delaware Basin in West Texas has led to
the growth of horizontal drilling techniques
throughout the basin over the past few
years. To enhance the learning curve in
drilling horizontal wells, optimize performance and mitigate downhole problems
such as poor penetration rates and accelerated wear on drill string components
during all stages of drilling, operators
are applying real-time downhole dynamics
and mechanics sensor technology.
The first evolution of this technology
consisted of recording downhole dynamics
data in memory mode. The memorymode approach confirmed that strong dynamic events were in fact occurring, but
it meant a delayed improvement cycle,
since operators were able only to apply
the knowledge acquired from the data to
make adjustments to drill string components and operational parameters on subsequent wells.
Transitioning to real-time downhole
drilling dynamics informed by drilling
optimization expertise has delivered immediate performance improvements by
enabling on-the-fly adjustments to drilling
parameters while a well is drilling, in addition to helping operators optimize bit
and bottom-hole assembly designs on
subsequent wells. The continuous performance improvement loop highlights
best drilling practices, permitting the de-

velopment and implementation of refined
drilling procedures and further enhancing
performance, safety and economics.
A group of six BHP Billiton-operated
horizontal wells in the Wolfcamp Shale
play provides a case in point. This article
addresses drilling dynamics challenges
encountered while drilling the vertical
intermediate sections of the Wolfcamp
wells. The results illustrate the benefits
of managing drilling parameters in real
time as an integral component to best
drilling practices. Managing real-time
downhole drilling dynamics reduced overall operator costs by an average of 24
percent on each of these wells.
Moreover, real-time downhole weight
on bit functionality provides increased
safety, while close-to-bit rotational inclination data enable enhanced vertical
control, compared with the standard survey
systems on conventional straight-hole
drilling assemblies.

Primary Objective
The primary objective was to maximize
bit life and penetration rates while drilling
the 121⁄4- or 105⁄8-inch) vertical intermediate
sections, where wells historically experienced heavy bit wear and twist-offs,
and often required multiple runs to drill
the section to planned depth. The solution
consisted of employing drilling performance solutions in conjunction with a
downhole dynamics tool to transmit data
to surface in real time. The downhole information was displayed on the rig and

FIGURE 1
Managing Whirl and Lateral Vibration with High Bending Moments

102 THE AMERICAN OIL & GAS REPORTER

also relayed to the operator's regional
office. A team of well site experts gave
24-hour coverage to interpret the data,
provide support and advise the drillers
on parameter management.
The plan called for using downhole
drilling dynamics tools on the intermediate
vertical sections of the six wells (drilled
by four rigs), and on the first hole drilled
by every new rig added to the operator's
Delaware Basin focus area. For the first
wells, the intermediate vertical hole was
121⁄4 inches, which was the typical hole
size on previous wells. The 121⁄4- and
105⁄8-inch drilling systems incorporate a
PDC bit and an 8-inch, straight positive
displacement motor with a pendulum
arrangement of stabilizers to help keep
the well path vertical. An 83⁄4-inch system
incorporates a 63⁄4-inch, straight positive
displacement motor with a pendulum
arrangement of stabilizers.
The dynamics tool's data suite consisted of optimization information, dynamics information, and wellbore quality
with steering information. The optimization information consisted of downhole
WOB, downhole torque, downhole differential pressure, equivalent circulating
density (ECD), downhole motor rpm,
downhole drill string rpm, downhole mechanical specific energy (MSE), and highfrequency strain. The dynamics and motion
information consisted of lateral, axial,
and tangential vibration with motions
consisting of stick-slip, whirl and bit
bounce. The wellbore quality and steering
information entailed data from bending
moment, bending tool face and rotary inclination.
The acquired data are transmitted in
real time to the surface by mud-pulse
telemetry while drilling. The data displays
on the rig allow experienced well site
personnel to make informed real-time
decisions. The average real-time update
rate was every 90-120 seconds while
transmitting data from the dynamics sub.
The dynamics tool typically is placed
immediately above the first stabilizer and
just above the motor in the BHA. Placing
the tool as close to the bit as possible is
important for steering control from rotary
inclination. The drilling dynamics tool
replaced the usual measurement-whiledrilling system. Data from the rotary inclination detected deviation from vertical
in real time while drilling without the

American Oil and Gas Reporter - September 2015

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