American Oil and Gas Reporter - January 2019 - 84

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Tech Trends
more than 3,400 feet. From 2017 through
July 2018, Range recorded more than
30 days when lateral footage rates
eclipsed 5,000 feet in 24 hours, including
two days with more than 6,000 lateral
feet drilled.
Casing Flotation
While drilling a record-setting lateral
length is exciting, the process is all in
vain if the production casing string cannot
be run to bottom and cemented in place
for the completions team to successfully
stimulate the well. To ensure success,
Range is utilizing casing flotation technology on a vast majority of its wells.
When running a long string of casing,
increased drag considerations must be
taken into account. If the drag associated
with running casing is modeled to reach
a critical limit in which the pipe will not
be able to be slacked off to bottom, a
casing flotation sub can be utilized to
achieve a desired set depth with minimal
operational changes.
A flotation sub can be placed strategically in the casing string to aid in
running casing to bottom. With a single
fluid system, a specified length of casing
is left empty (air-filled) with the area
above the flotation sub filled with fluid
to aid in weight transfer. In the lateral, a
buoyancy effect acts on the casing because
of the difference between the drilling
fluid and air filled portion of the casing,
helping "float" the casing to bottom.
After the casing is landed at the desired
depth, depending on the type of flotation
sub used, the sub is opened or ruptured
to allow the lower portion of the casing
to fill with fluid. The air typically is allowed to swap with the fluid-filled portion
of the casing string, and carefully circulated
back to surface, where it is bled off in a
controlled manner. After, the void is fully
filled to surface, circulation begins to
condition the wellbore before cementing
the production casing string.
Hole Cleaning And Tripping
A major obstacle faced in drilling extended laterals is ensuring the hole is
cleaned appropriately before tripping and
84 THE AMERICAN OIL & GAS REPORTER

running casing. A study of wellbore cleaning was performed, focusing on the best
parameters to aid in designing an optimal
process to clean wellbores, including
pump rates, rotating speeds, high-density
mud sweeps and drill pipe reciprocation.
As lateral length grew in 2014-15,
abnormal amounts of wellbore issues
were encountered. After investigating
problems such as stuck or lost BHAs,
casing running issues, lost circulation
during cementing, etc., it was found that
the hole cleaning parameters had to be
revised. An in-depth review determined
that flow rates and RPM needed to be
increased while drilling.
After drilling to total depth, circulation
at TD and the landing point were increased
and maintained within specific parameters.
The increased parameters also included
a weighted sweep (2.0 pounds/gallon
over mud weight) at the start of the final
bottoms-up circulation at TD and pipe
reciprocation at a set speed.
Tripping procedures also were revised.
The focus on shorter laterals had been
on tripping fast to get the wellbore cased
and cemented as quickly as possible.
With extended laterals, there came a
point at which pulling the drillstring off
bottom without needing the drilling contractor's overpull approval was unachievable. In those instances, back-reaming
was the recommended method to get
off of bottom. Range's first two 15,000foot laterals used back-reaming to trip
out of the hole after reaching TD. In
both wells, the drillstring encountered
tight hole spots while tripping out that
required back-reaming to continue out
of the hole.
On the third 15,000-foot lateral, backreaming operations resulted in the drillstring getting stuck and leaving the BHA
down hole. A thorough investigation
was completed to determine the cause
of the stuck BHA. It found that the drillstring was back-reamed out of the hole
at a higher speed than recommended.
Even with back-reaming, at that speed,
the BHA was pulled into a cuttings bed
that ultimately packed it off. New backreaming standards were implemented to

limit tripping speeds and overpull in
tight spots.
When overpull/tight spots are encountered, the new procedures include
tripping back below the tight spot, pumping and rotating at set parameters, and
circulating a minimum of one bottomsup. If the shakers do not clean up, a bottoms-up continues pumping until the
shakers are clear of cuttings. At that
point, the BHA continues tripping out
of the hole on elevators.
With lateral lengths extending to 18,000
feet, additional planning and engineering
is necessary to minimize risk during
drilling and tripping procedures. The first
of Range's 17,000-foot laterals included
procedures such as increased circulating
time at TD and preset back-reaming and
circulation parameters based on insights
gained from previously drilled 15,000foot laterals. Once the drilling rig could
pull on elevators, the rig circulated for
an additional planned time before tripping
out to run casing and successfully cement
the wellbore.
A similar plan was put in place for
the 18,000-foot lateral, which was drilled
to TD without any issues. Circulating
and tripping procedures from the previous
17,000-foot well were utilized to provide
smooth tripping out of the wellbore.
The production casing was run to TD
using a flotation device, followed by
cementing operations. These procedures,
based on lessons learned from past experiences, allowed this record-setting
well to be successfully drilled, cased
and cemented.
The focus on drilling practices has
enabled faster drilling rates and less days
spent on each well, despite drilling much
longer laterals. The increased performance
results in rigs drilling more lateral feet a
year, which means fewer rigs are required
for improved capital efficiency in Range's
long-term development of the Marcellus.
The new processes and procedures the
drilling team put in place to drill record
Marcellus lateral lengths in 2018 will
continue to be utilized as Range drills
more extended laterals in the Appalachian
Basin in the future.
r

American Oil and Gas Reporter - January 2019

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