American Oil and Gas Reporter - April 2017 - 58

SpecialReport: Drilling Technology

Planning Key In Extended-Reach Wells
By Neil McRobbie,
Vakkeyil Naveen Nair
and Paul Bitzan
DENVER-Operators are drilling to
the technical limits in resource plays to
deliver high-performing wells and reduce
overall reservoir development costs. However, well planning and design are more
critical than ever in extended-reach projects,
underscoring the need to apply the most
effective technologies to achieve both operational and economic objectives.
To optimize extended-reach operations
using conventional drilling tools, Enerplus
Resources (USA) Corp. adopted a "stepped
approach" to drill Bakken and Three
Forks wells with lateral lengths of more
than 14,500 feet and total measured depths
exceeding 25,000 feet. Extensive analysis
was conducted to evaluate the risks associated with using conventional motors
and bottom-hole assemblies to drill ultralong-laterals in the deeper parts of the
Williston Basin, where downhole temperatures exceed 250 degrees Fahrenheit.
The project drilled five Bakken/Three
Forks horizontals on a pad in North Dakota: two initial "study wells" with more
conventional lateral lengths, and three
wells with 50 percent longer laterals and
three miles of total drilling footage. The
goal was to apply the lessons learned on
the first two wells to optimize drilling
the three extended-reach wells using conventional motors and BHAs. Accordingly,
downhole optimization tools and surface
sensor data were applied in the first two
wells to calibrate and model critical parameters such as torque and drag, hydraulics, downhole vibrations, and weight
on bit (WOB).
A drilling optimization tool placed
above the motor measured weight, torque
and bending moment across the sub. A
pressure-while-drilling (PWD) tool monitored downhole pressures, and tri-axial
vibration sensors measured and transmitted drill string dynamics data in real
time to optimize the drilling system and
identify ways to overcome friction effects.
The data validated the effectiveness of
friction-breaking tools and proposed
areas for improvement to orient drilling
with conventional motors farther into
the lateral.
Continuous improvements were made
to the system to drill to the limit with
58 THE AMERICAN OIL & GAS REPORTER

conventional motors before picking up
rotary steerable tools to drill the final
1,300-1,800 feet of the laterals in the
long-lateral wells. This approach proved
more cost-effective to optimize within
the constraints of the drilling system
before using the RSS tools.
Drilling Optimization
The trajectory design and actual wellbore tortuosity in the 8.75-inch intermediate section (including a vertical\deviated
section drilled to ±10,500 feet before
kicking off into the build section to land
at a 90-degree inclination in the target
formation) is critical for minimizing
weight transfer and torque. Initiatives deployed to achieve a better understanding
of downhole dynamics and limitations
while drilling the two study wells included:
* Drill pipe specified to high torque
with friction-reducing wear banding;
* Downhole WOB, torque and bending moment with a direction sub;
* Friction-breaking tools;
* The PWD tool; and
* The tri-axial vibration sensor with
rpm.
The operator's geosteering approach
in the horizontal section placed importance
on utilizing information obtained while
drilling to accurately map the structures
of the Bakken and Three Forks. The first
lateral targeted the middle of the Bakken
C zone. It was geosteered by periodically
bringing the bit up to contact the Bakken
B. The gamma ray signature identifying
the B/C contact was used to determine
bed dip and formation structure. The
structure data obtained from this first
Bakken well then was used to establish
the paths of the subsequent parallel Three
Forks wells.
"Bumping" the wellbore up to the
Bakken B/C contact required increased
sliding to point the bit up and then bring
it back down to the target line. In some
areas, a hard streak exists at the B/C
contact that can be tough to penetrate.
This has been shown to cause increased
stresses on downhole tools and even
motor failures. While this geosteering
approach adds time to drilling the lateral,
it ensures the wellbore remains in the
target formation.
The lessons learned from downhole
WOB, torque-on-bit (TOB), bending mo-

ment sub, vibration sensors, and pressure
while drilling, along with advanced modeling for torque and drag, hydraulics,
BHA design, and vibration analysis enabled the team to use a stepped "modelmeasure-optimize" approach to effectively
plan for downhole scenarios and develop
contingencies to drill the three extendedreach wells.
Study Wells
Figures 1A and 1B show the trajectories
for the first (blue) and second (pink)
study wells. Well 1 targeted the Bakken
at a total measured depth at 19,935 feet.
The last 4,000 feet of the 8.75-inch intermediate vertical/nudge section from
2,200 to 10,418 feet was drilled at a 20degree inclination. The build section from
10,418 to 11,279 feet was drilled at an
inclination of 12 degrees per 100 feet.
The 6.0-inch lateral was turned 25 degrees
at 5 degrees/100 feet.
The well trajectory was designed to
optimize weight transfer closer to well
TD with reduced string buckling in the
vertical/nudge section. The 20-degree
nudge in the wellbore until kickoff related
to an increased off-bottom torque profile
with increased drill pipe-to-wall contact
in the intermediate section. The lateral
was drilled with 6.0-inch PDC bits and
an 0.81 revolution/gallon motor with an
integral blade stabilizer (IBS) above the
motor. The weight, torque and bending
moment sub was placed above the IBS
on the motor to record lateral, torsional
and longitudinal drill string dynamics
and vibrations.
The recorded data revealed the torque
and drag effects of drilling through B-C
contact markers. The geosteering approach
to calculate formation dip by seeing the
gamma signature required the BHA to
drill through the hard streaks in the formation. Every time the markers were
penetrated, there was more seepage of
gas into the well, increasing background
gas units.
This also required the drilling engineer
to increase backpressure while bringing up
the mud weight from 10 pounds/gallon of
water-based mud to 13.8 pounds/gallon of
oil-based mud to stay overbalanced through
the lateral. Increasing the mud weight decreased the flow rate by 100 gallons/minute
and led to a reduction in motor/bit horsepower, contributing to a lower rate of pen-



American Oil and Gas Reporter - April 2017

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