American Oil and Gas Reporter - March 2016 - 53

SpecialReport: Gas Industry Strategies

Rig And Well Counts
To gauge the impact of LNG exports
on the six shale gas basins, a comparison
was made to demonstrate how many new
drills it would take in each basin to start
and maintain a single 4.5 MTPA LNG
train representing the production equivalent
of a constant stream of 636 MMcf/d.
The analysis assumed that all production
would be obtained from new drilling,
and that a significant number of new
drills would be required to start the train
at full capacity, with a smaller number of
wells then needed to maintain production
delivered to the train.
Gas shale basin-specific decline curves
and estimated ultimate recoveries were
utilized to determine the number of wells
needed to supply an LNG train. Both are
key variables that impact how many wells
need to be drilled initially and over time
to supply an LNG train.
The Haynesville has the highest well
EUR, followed by the Marcellus, Eagle
Ford, Barnett, Fayetteville and Woodford.
The Haynesville also has the steepest
production decline, but the Eagle Ford
has a fairly steep decline as well (Figure

FIGURE 2
Average Daily Gas Rate per Well by Basin
Based on Arps Decline Curve Forecast
10,000

Average Daily Gas Rate (MMcf/d)

prolific and the Woodford having the
lowest gas output of the six. But reaching
current output levels in each of these
plays required significant well counts
and many rigs to drill vast numbers of
laterals.
It must be noted that drilling in gas
shale plays has been declining with depressed gas prices, falling from more 900
rigs in early 2011 to an average of about
330 in 2014. However, plummeting oil
and gas drilling activity throughout 2015
in all basins left gas rig counts at their
lowest levels in decades, with only about
100 rigs active in late February.
In the Barnett, which had recorded gas
rig counts numbering in the 60s five years
ago, only one rig was drilling for gas in
late February. In the Eagle Ford, six rigs
were drilling for gas in late February compared with 95 in late 2011. Even in the
Marcellus, where rig counts topped 140
five years ago, fewer than 30 rigs were
running as February came to a close.
It remains to be seen how dramatically
the drilling slowdown will impact production in these basins, but it will have a
negative net effect. Depending on how
long the downturn lasts, it potentially
could have an impact on the level of
drilling response needed to supply U.S.
LNG terminals.

Fayetteville
Barnett
Eagle Ford

1,000

Woodford
Haynesville
Marcellus

100

10

0

5

10

2). The Barnett and Marcellus have the
most gradual decline production trends.
The assumed drilling times for all six
plays averaged 15.5 days (about two
wells per month), but ranged between
6.8 days for the Fayetteville and 30.4 for
the Haynesville. Well counts were obtained
using yearly average production rates for
each basin. The analysis focused on core
areas with the highest EURs within each
play, so the estimates for actual well
counts are likely to be conservative.
The results show that the Haynesville
requires the least number of wells to
supply a single LNG train for 30 years,
at 1,118 laterals. However, the play's relatively long drill times mean that it still
would require nine rigs for startup and
three rigs after nine years to maintain
production.
The Fayetteville requires significantly
more wells than the Haynesville (3,279),
but utilizes roughly the same rig count to
supply a single LNG train, given its considerably faster drilling times.
The Barnett and Woodford are a bit
more rig- and well-intensive, requiring
15 and 14 rigs at startup, reducing to
two and four rigs, respectively, after 12
years. The Barnett rigs would have to
drill 2,815 horizontals, while the Fayetteville would need 3,383 laterals over
30 years to supply an average LNG train.
The Eagle Ford is not quite as rig-intensive, starting up with 11 rigs and then

15
Time (Years)

20

25

30

declining to four after eight years to drill
2,294 laterals. The Marcellus may be
the second most efficient play, requiring
nine rigs at startup, three rigs after four
years, and two rigs after 14 years to drill
1,572 horizontal wells.
Substantial Volume
To attain a reasonable estimate of potential LNG export volumes, only the
five U.S. projects that had completed all
of the permitting processes and were
under construction as of mid-2015 were
considered. Furthermore, the analysis
used the permitted volumes approved by
FERC, rather than total capacity.
The four Gulf Coast facilities (Sabine
Pass, Corpus Christi, Freeport and
Cameron) have a combined FERC-approved capacity of 8.36 Bcf/d (59.17
MTPA), while Cove Point has an approved
capacity of 820 MMcf/d (5.25 MTPA).
The total U.S. FERC-permitted LNG
production of 64.42 MTPA is a little
more than 25 percent of global LNG
cargos shipped in 2014. It also represents
11 percent of current total domestic natural
gas production, which is a substantial,
but not insurmountable, volume.
To better understand how gas export
capacity may impact each shale basin,
the plays were delineated into regions,
with production from the Barnett, Eagle
Ford, Fayetteville, Haynesville and Woodford delegated to Gulf Coast facilities,
MARCH 2016 53
American Oil and Gas Reporter - March 2016

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