American Oil and Gas Reporter - January 2019 - 82

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Tech Trends
To accomplish this step change in
well design, the Range Resources' Appalachian drilling team evaluated the
processes that had been in place for
7,000-9,000 foot laterals to determine
what operational practices would need
to be revised to drill and case 12,000 to
18,000-plus foot laterals (Figure 1). The
team focused on rig upgrades, directional
tools, drilling fluids, casing flotation
and other best practices, and then implemented field trials to evaluate extended
lateral practices. Over the 12-month period of revising processes and making
upgrades, Range drilled 34 horizontal
wells with laterals longer than 12,000
feet (Figure 2).
Consistent use of best practices and
systematic equipment upgrades has led
to improved performance year after year
in Range's Marcellus operations, with
wells progressively drilled in less time
and at a lower cost. The focus has been
on the key performance indicator of cost
per lateral foot. One of the keys to successfully implementing extended-lateral
drilling was drilling longer horizontals
while continuing to achieve the goals of
safe, environmentally compliant, sustainable and cost-efficient Marcellus development over time, including maintaining
the KPI trend shown in Figure 3.
From 2006 to 2015, Range had drilled
only five wells with lateral lengths ex-

ceeding 10,000 feet. The challenges faced
on those wells and the time required to
reach total depth raised concerns that
multiple changes would be needed to
successfully drill extended laterals in a
continuous program. Consequently, in
early 2016, the drilling team began planning a well pad with laterals exceeding
12,000 feet (including one longer than
14,000 feet) with drilling scheduled for
the fourth quarter of that year. Comprehensive studies, followed by field tests,
were implemented in preparation for the
extended-length lateral drilling. The focus
was on:
· Rig selection;
· Directional tools;
· Drilling fluids;
· Casing flotation; and
· Best practices.
Rig Selection
Range has utilized various types of
rigs with different capabilities throughout
the evolution of its Marcellus development
program, including super singles with
the capacity to drill laterals to ~6,000
feet, high-performance walking rigs capable of drilling laterals to ~10,000 feet,
and walking triples rigs with a maximum
lateral length capability of ~20,000 feet.
The progression of rig capability has
been instrumental in achieving longer
laterals.

FIGURE 1
Average Lateral Length (January 2007-July 2018)

FIGURE 2
Longest Laterals Drilled (January 2016-July 2018)

11,000

19,000'

10,000

18,000'

9,000

17,000'

7,000

16,000'

6,000

15,000'

Lateral Length (ft)

Lateral Length (ft)

8,000

5,000
4,000

14,000'
13,000'

3,000
2,000

12,000'

1,000

11,000'

0

2007

2008

2009

2010

2011

2012

2013

2014

82 THE AMERICAN OIL & GAS REPORTER

2015

2016

2017

2018

Because of their versatility and efficient
design, Range had vast success with super
singles with 650-horsepower drawworks,
1,000-horsepower mud pumps, 150-ton
top drives, 450-kilowatt generators, 4½inch range III drill pipe, and 300,000
pound capacity masts. However, as drilling
shifted toward laterals longer than 5,000
feet, it became evident that rig selection
needed to be re-evaluated along with the
number of wells drilled per pad, location
size and wellhead spacing.
The second fleet iteration came in the
form of a high-performance design with
enhanced horizontal drilling capabilities.
These rigs had 1,000-hp drawworks, 1,600hp mud pumps, 500-ton top drives, 1,365kW generators, 5.0-inch drill pipe, and a
750,000-pound capacity masts. The rigs
used range II drill pipe to build stands
(triples) with a rack-back capacity of
~15,000 feet, and had the ability to walk
~20 feet an hour with a rack full of pipe.
These second-generation rigs have
met the challenges associated with drilling
10,000-foot laterals with great success,
drilling 805 Marcellus horizontals (one
of the rigs drilled an 11,146-foot lateral).
However, with the first 14,000-foot lateral
planned, permitted and placed on the
drilling schedule, the capabilities of the
rig fleet once again came into focus in
2016 and the team determined another
upgrade was necessary.

10,000'
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