American Oil and Gas Reporter - January 2019 - 83

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Tech Trends
While larger hook load, power generation, flow rate, rotational speed, pipe
handling and other capabilities were needed, the size of the rig was a critical consideration, especially with it becoming
routine to return to sites with producing
wells to conduct infill drilling. The upgraded rigs would have to be able to
seamlessly fit within existing operations
on pad locations and also be efficient to
mobilize given the challenging Appalachian terrain.
Ultimately, Range decided to add a
rig in late 2016 that features 1,500-hp
drawworks, two 2,000-hp mud pumps
(7,500 psi maximum rated working pressure with 4.5-inch liners), a 500-ton top
drive (37,500 foot-pounds maximum continuous drilling torque capability), three
1,365-kW generators, 5.0-inch drill pipe,
and a 750,000 pound capacity mast, capable of racking back 21,500 feet of drill
pipe made up into stands. A second rig
was added in March 2017.
Since upgrading the fleet with these
rigs, Range has been able to meet the
rigorous demands of continuous improvement by focusing on stability of personnel
and monitoring KPIs to achieve program
goals. Range successfully drilled 16
laterals longer than 10,000 feet in 2016,
47 wells in 2017, and 16 through the
first seven months of 2018. In total, the
rigs drilled 83 Marcellus laterals in excess
of 10,000 feet through the first half of
2018, including the 18,129-foot well in
Washington County. The team also has
noted a 171 percent improvement in the
amount of lateral footage drilled per rig
in 2017 versus 2013.

friction between the wellbore and drillstring, and help transfer energy to the
bit. However, using rocking and agitator
oscillating tools had practical limitations
and heightened risk in laterals greater
than 7,000 and 10,000 feet, respectively.
Eliminating the need to slide drill was
mandatory to overcome frictional concerns
in long laterals. Another driving force
behind the move to rotary steerable tools
was the decision to reduce geosteering
target windows by 50-100 percent in an
effort to improve well productivity. The
team concluded that rotary steerable tools
would be required to meet the new goals
of the Marcellus program.
Rotary steerable tools provide precise
directional steering for tight-target windows, and the ability to fully rotate the
drill string throughout the drilling process
reduces friction between the drill pipe
and wellbore to minimize tortuosity,
torque and drag in extended-lateral wells.
Rotary steerables also enhance hole
cleaning while drilling, improving ROP
and stability. By combining rotary steerable tools with the right rig design and
drilling fluid, Range has kept wellbores
in the target zone for 99 percent of
lateral footage drilled in 14,000-plus
foot horizontals.
Adopting rotary steerable tools to drill
extended laterals contributed to another
critical design: switching from the highFIGURE 3

Drilling Cost per Lateral Foot (January 2012-November 2018)
$2,000

2012
2013
2014
2015
2016
2017
2018

$1,800
$1,600
Drilling Cost/Lateral Feet

Directional Tools And Fluids
With shorter laterals, the Marcellus
horizontal program used a PDC bit, positive-displacement drilling motor, bent
housing for directional control, and a
mud pulse measurement-while-drilling
tool. As average lateral lengths grew, it
became increasingly challenging to slide
drill effectively and hold consistent tool
face. At that point, both rocking and agitator-type oscillating tools began to be
deployed to assist in breaking static

chloride, water-based fluid that had been
used with positive-displacement motors
to a diesel-based mud. Modeling indicated
a significant reduction in friction and
torque by replacing the saltwater polymer-based mud with the OBM system
with better shale inhibition and lubricity
characteristics.
Both fluids were tested on a fourwell pad in which the same rotary steerable tools were run, changing only the
mud type. The wells in the study that
were most comparable had 10,042 and
10,150-foot laterals and similar trajectories. The well that used the WBM
recorded 9,000 foot-pounds more torque
than the well drilled with the OBM.
Over the past two years, the dieselbased fluid has proven crucial to successfully drilling laterals longer than
10,000 feet utilizing rigs with higherhorsepower and rotary steerable tools.
Wellbore stability has improved drastically and the team has observed numerous performance improvements.
Those improvements include a dramatic increase in daily footage rates
since switching to rotary steerables and
OBM. On average, lateral footage averaged less than 2,000 a day prior to 2016.
In fact, prior to 2016, the most lateral
footage drilled in a 24-hour period was
4,344 feet. Since implementing the design
changes, daily footage rates have averaged

$1,400
$1,200
$1,000
$800
$600
$400
$200

$0
2,000

4,000

6,000

8,000

10,000
12,000
Lateral Length (feet)

14,000

16,000

18,000

20,000

JANUARY 2019 83

American Oil and Gas Reporter - January 2019

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