American Oil and Gas Reporter - September 2017 - 59

SpecialReport: Tubulars Technology
between a well drilled in 2017 and a well drilled in 2014. In this
report, well productivity is combined with drilling speed to establish a measure of the first full month of production per rig.
Figure 1 plots the first full month of production per rig for all
seven major shale regions, which collectively account for twothirds of total U.S. rig activity.
As the chart shows, each rig operating today results in nearly
twice as much crude oil and natural gas production as a rig did
in mid-2014 on a first full-month basis. One interesting aside
worth noting is that based on these data, first-month production
per rig for both oil and gas was flat during the course of the past
year, although company reports suggest otherwise.
In any event, Figure 2 is a reproduction of an EIA chart that
shows the initial production and the production decline of wells
during the past several years. While this chart is for the Permian
Basin, the other six major tight oil and shale gas regions have
similar profiles. The technologies influencing well productivity
revolve around lateral length, well spacing and the optimization
of completion practices (including the number of stages, proppant
volumes and hydraulic fracturing treating pressures, to name
only a few completion design variables).
With regard to drilling speed, a variety of data sources can
be used to identify trends and attempt to quantify changes, including several noteworthy references in recent earnings calls.
Cabot Oil & Gas, for example, included a chart of Marcellus
Shale drilling speeds from spud to total depth that showed a
decline from 18 days a well in 2014 to 12 days/well in 2017.
An EOG Resources presentation noted that its Permian Basin
drilling times decreased 45 percent between 2014 and the end
of 2016. Drilling contractor Helmrich & Payne reported that it
drilled Eclipse Resources' Outlaw C 11H "super lateral" in the
Utica Shale in only 17 days during the second quarter-a well
with a record-setting 19,500-foot lateral section and a total
drilling depth of 27,750 feet.
Meanwhile, Comstock Energy reports it is drilling Haynesville
horizontals twice as fast as six years ago. In its fourth-quarter
2016 earnings call, one of Range Resources' senior executives
FIGURE 2
Average Oil Production per Well in Permian Region

100

Niobrara

50
0

Bakken

Permian

Utica

24
36
Months of Operation

500

Bakken RC

400

Marcellus

Eagle Ford RC

300

Haynesville RC
Marcellus RC

200

Niobrara RC

100

Haynesville

Eagle Ford

600

Rigs

150

2014
2012
2010
2008
pre-2007

FIGURE 3
U.S. Rig Counts for Seven Major Resource Plays

Permian RC

Oc 4
t-1
Ja 4
n1
Ap 5
r-1
5
Ju
l-1
5
Oc
t-1
Ja 5
n1
Ap 6
r-1
6
Ju
l-1
Oc 6
t-1
Ja 6
n1
Ap 7
r-1
7

bbl/d

200

2015
2013
2011
2009
2007

The other factor determining how much OCTG a rig consumes
is the regionality of drilling, and the changes in the string
designs for each region over time. As Figure 3 illustrates, in the
commodity pricing environment that has characterized the
market since late 2014, the Permian Basin and Eagle Ford
plays together account for more than half the total rig count in
the seven major shale basins. OCTG consumption per well in
these two regions ranges from more than 700 tons for deep,

Utica RC

l-1

First full month
of production

More Pipe Per Rig

250

said the company had realized a 40 percent year-over-year
increase in lateral footage drilled each day. Another leading
Marcellus operator, Antero Resources, has revealed that it has
slashed average drilling times for 9,000-foot Marcellus horizontals
from 30 days a year ago to only 12-14 days.
The anecdotal evidence goes on and on. Overall, based on
the data we have collected, a rig today can drill 30-40 percent
more wells in a given time frame in a given region than it could
in 2014. In the context of weekly rig counts, this essentially
means that the 377 rigs drilling in the Permian Basin in early
August were as productive as 509 of the 555 rigs active in the
basin during the first week of August 2014. The technologies
that have improved drilling speed include rig design and horsepower, automation, high-pressure mud pumps, improved data,
better targeting, and a host of other improvements.
Another contribution is the lower risk associated with the
fact that drilling in unconventional plays is more developmental
than exploratory by nature, which has boosted the producing
well-to-dry hole ratio.
When the improvements in production per well (higher productivity) combine with increasing drilling speeds (higher efficiency),
it takes roughly half as many rigs today as it did in mid-2014 to
generate the same first-month production total. This quantum
shift in drilling efficiency and productivity, driven by the economic
necessity of a price slump, is completely redefining the significance
of rig counts and other conventional industry "scorecards."

SEPTEMBER 2017 59

American Oil and Gas Reporter - September 2017

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