American Oil and Gas Reporter - April 2018 - 70

VISION2020
power of data analytics to enhance deliverability and drive
down costs. We also believe that management teams and private
equity funds will need to be increasingly flexible as they
approach monetizations. The desired cash sale to a public
company looking to build inventory may become less frequent
in the new cash flow-neutral world, so management teams and
their private equity partners will need to consider a variety of
other monetization options, including an IPO, selling to a public
company and taking back a considerable amount of stock, and
selling to other private equity-backed companies.

OIL HITTING NEW HEIGHTS

The U.S. Energy Information Administration reQ: ported
in early February that U.S. oil production
had exceeded 10 million bbl/d for the first time, easily
surpassing the historic peak set in the early 1970s. By
EIA's count, production in the first week of March was
up year-over-year by 1.2 million bbl/d, and up 3.3
million bbl/d compared to five years earlier. What do
your forecasting models indicate about U.S. oil production
trends through 2020? What do the models project
longer term? How high can daily oil output climb?

QUINNELL: U.S. production is currently growing at a very
rapid pace and we expect this to continue over the next several
years given the current price environment. Genscape is forecasting
that production will reach nearly 12.6 MMbbl/d by year's end
2020, which is nearly a 2.4 MMbbl/d increase from current
levels. As we move further out, we do expect the pace of
growth to slow, but do still foresee growth over the next
decade. By the end of 2022, we see U.S. production at around
13.8 MMbbl/d, or nearly 3.6 MMbbl/d higher than current
levels.
The Permian Basin will lead the growth, climbing from
around 3 MMbbl/d to 5.3 MMbbl/d by the end of 2020 and then
reaching nearly 6.1 MMbbl/d by year's end 2022. The South
Texas and Mid-Continent also will contribute to the growth
with the Eagle Ford adding 400,000 bbl/d by 2020 and the
SCOOP/STACK play growing by 200,000 bbl/d. On the other
hand, Genscape expects the Gulf of Mexico to decrease by
300,000 bbl/d as investment in large offshore projects has
declined and infill drilling is not keeping pace with overall
decline from existing wells.
In terms of daily output, we saw some weakness in production
volumes in December and January because of cold weather impacts, freeze-offs and some production off line in the Gulf of
Mexico as a result of maintenance and a fire at Shell's Enchilada
platform in November. However, in February, production started
to trend higher and likely surpassed the new peak set in
November. Permian production averaged just under 3.0 MMbbl/d
for the month of February, and climbed to 3.1 MMbbl/d by the
middle of March. Gulf of Mexico production shut-in due to the
70 THE AMERICAN OIL & GAS REPORTER

fire at the Enchilada platform should come back this summer
and Bakken production tends to trend higher in the summer
months as warmer temperatures allow for increased activity
and well completions.

Looking forward to 2020, which specific basins
Q: and
plays do you project will provide the majority
of production additions? What are the data showing in
regard to continued improvements in well productivities?
In more established horizontal tight oil plays such as
the Bakken and Eagle Ford, is there anything to suggest
that well productivities are declining as operators drill
up "tier-one" acreage in the sweetest spots? What are
we learning about decline curves and EURs?

QUINNELL: As mentioned, the Permian Basin will lead
much of the growth in U.S. production over the next several
years. However, other plays such as the Eagle Ford,
SCOOP/STACK, Niobrara and Bakken all are anticipated to
add to the U.S production growth story through 2020. Even in a
lower-price environment, a main reason for the growth is
continued well productivity and efficiency gains.
A common phrase among operators has been that wells
are "exceeding the type curve" as enhanced completions
rapidly are becoming the standard. With completion density,
well spacing, cluster spacing and increased proppant per foot
increasing, we are seeing improved economics as well productivity and estimated ultimate recoveries continue to improve.
However, some first cracks have appeared in the "higher intensity" leg of the shale revolution as Statoil Eagle Ford
reversed course from 200- to 250-foot well spacing as being
not as good as "hoped for," back to 500-foot spacing. In the
Bakken, as Oasis Petroleum began to probe the downspacing
capabilities of that play, 11-13 wells per spacing unit were
okay, but 16 wells was too tight. In other words, echoing the
400- to 500-foot well spacing as the current limit. In general,
we feel well productivities will continue to improve into
2018, but that some limits to these gains are starting to
become evident.
With higher prices, operators likely are starting to move
outside defined core areas in the tight oil plays, and therefore,
there is the potential to see well performance decrease. There
also has been talk about the parent/child well relationship in the
Permian and the potential for well degradation as we move into
development mode and drill out more child wells. However,
with higher-intensity fracs and enhanced completions, the move
to outside the core and the development drilling of more child
wells could be mitigated as a result of the technological improvements in completion techniques and designs.
I think the Bakken is a good example of an area that is more
mature in its lifecycle, and we have seen a slowdown in well
productivity growth with initial production rates flattening out.
However, at this point, even with movement to outside the tierone acreage, we have yet to see declines in productivities and
American Oil and Gas Reporter - April 2018

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