American Oil and Gas Reporter - November 2018 - 73

SpecialReport: MWD/LWD & Wellbore Optimization
The remote navigation and MWD technology were key in
keeping every foot of the lateral within the target zone, achieving
100 percent net-to-gross across the entire interval. Maximum
instantaneous on-bottom ROP exceeded 1,000 feet/hour, and
over the 24-hour period, ROP averaged more than 375 feet each
hour.
The entire 9,146-foot lateral, which extended from 7,300 to
16,446 feet measured depth, was drilled in 1.04 days. The curve
and lateral together were drilled in 3.64 days, which was 1.86
fewer days than the aggressive 5.5-day drilling plan had called
for, reducing overall drilling cost by 35 percent compared with
offset wells. In an environment where the time required to drill
from spud to total depth is critical to well economics, saving
almost two full days of rig time without compromising wellbore
quality or operational safety is consequential.
The drilling landscape in the Marcellus and Utica shale
plays has changed dramatically in recent years, with operators
realizing ever-greater efficiency gains and establishing drilling
records seemingly with each new project. By slashing drilling
times and optimizing drilling and completion designs, the
industry has forced down break-even costs even as it has ramped
well productivities by orders of magnitude in West Virginia,
Pennsylvania and Ohio.
According to the U.S. Energy Information Administration,
new-well natural gas production per rig averaged nearly 17
million cubic feet a day in the third quarter in the Appalachian
Basin, representing a five-fold increase since 2012. Even during
the 2014-16 industrywide downturn, when rig counts plummeted,
well productivities kept climbing, propelling regional gas
output to all-time highs. In October, production in the basin
topped 29 billion cubic feet a day for the first time, up 375
percent in six years.
One of the driving forces behind the incredible production
growth is integrated drilling technologies that are improving
the wellbore construction process and making it possible to efficiently extend Marcellus/Utica lateral lengths to 10,000 feet
and longer. The value proposition is simple: Longer laterals
expose more shale volume per well, which means higher perwell productivity, which in turn, generates more revenue per
well regardless of wellhead price. If those longer laterals can
stay within the highest-potential reservoir zone and reach total
depth in less time with fewer trips in and out of the hole,
operators can lower well cost meaningfully while simultaneously
enhancing production and recovery rates.

The proper drilling mud plays a key role in keeping the
wellbore stabilized, particularly when drilling a one-mile or
longer lateral in an open-hole horizontal section. Geologic variations and operational considerations from one well or pad
location to another make customized drilling fluid solutions
crucial in the Marcellus/Utica and other resource plays.
Each fluid system should be developed with careful consideration of the particular drilling environment, the characteristics
of the reservoir and the wellbore design challenges that must be
resolved. Water-based mud systems can be customized to
improve shale stability, maximize clay inhibition, minimize
pore pressure transmission and improve ROP-all while reducing
well costs and environmental impact.
Drilling high-quality wellbores at fast penetration rates would
not be possible without innovative bit technology. The newest
generation of PDC bits are designed with application-specific
profiles that improve cutting and mechanical efficiency, boost
ROP and run life, and extend durability while minimizing
vibration.
In the case of the HG Energy II well, the bottom-hole
assembly was equipped with an 81⁄2-inch high-velocity drill bit
that had been optimized and revised numerous times over the
course of several years for Marcellus/Utica operations. This
design incorporated a refined blade layout and the latest in
PDC cutter technology to maximize speed, efficiency and reliability. Hydraulics were also key for this bit and it was the
product of ongoing analysis and testing to maximize cuttings
evacuation in these high-performance well settings.
Proper gauge configuration is imperative with a HBRSS.
The bit's gauge was customized to provide the necessary lateral
responsiveness to achieve strong buildup rates in the curve,

Integrated Technologies
A number of technologies and processes support the successful
execution of record-breaking shale drilling projects, including
fit-for-purpose fluids, drill bits and cutters customized for
specific downhole conditions, and RSS and MWD/reservoir
navigation tools engineered for directional drilling applications.
Over the past four years, integrating these technological components in the Appalachian Basin has increased average lateral
footage drilled per well by 30 percent and increased daily
footage rates by 33 percent. This step-change in drilling efficiency
has allowed operators to increase the Marcellus/Utica well
count by 30 percent using 42 percent fewer rigs.

Horizontal drilling performance was redeﬁned in September when
a world-record 9,055 feet were drilled in a single day in an HG Energy II LLC-operated Marcellus well in West Virginia. The operation
achieved maximum instantaneous on-bottom ROP exceeding
1,000 feet an hour, averaging more than 375 feet/hour over the
24-hour period. The entire 9,146-foot lateral was drilled in 1.04
days while staying 100 percent in zone using an integrated
drilling solution with an advanced high-buildup rate rotary steerable system, a high-performance drilling motor, a customized
PDC bit, and remote reservoir navigation and MWD services.

NOVEMBER 2018 73

American Oil and Gas Reporter - November 2018

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