American Oil and Gas Reporter - April 2018 - 80

VISION2020
has led to much better wells at much
lower costs.
Data analysis also directly factors into
one of the key contributors to resource
plays' economic success: speeding decision
making and field activities. Drilling
Bakken and Eagle Ford wells once took
45-60 days. Now, these wells are reaching
total depth in only six or seven days,
even with significantly longer laterals.
Every well drilled on a pad is a new information center, and operators are feeding
that information back into the decision
making process for the next well. It is
"real-time thinking" based on new ways
to quickly and accurately analyze data.
Tomorrow's Challenges
Most tight rock plays have a steep
growth curve for the first four-five years,
after which productivities tend to decelerate. That is because operators achieve
the most they can by increasing lateral
lengths, frac densities, proppant and fluid
volumes, etc., in the best available rock.
After the steep initial four- to five-year
ramp up, efforts to further enhance productivity begin to yield diminishing returns. With drilling and completion activity
now expanding outside core areas in tight
oil and shale gas plays, it raises major
questions about what that could ultimately
mean to productivities, decline curves,
estimated ultimate recoveries and general
well economics. It is similar to dollar
cost averaging, with overall performance
reduced to some degree by second- and
third-tier areas as operators try to figure
out the right recipes for imperfect rocks.
It stands to reason that acreage in second- and third-tier areas will not perform
as well as first-tier acreage. Therefore, it
is hard to see how moving into areas
with lesser-quality rock will not contribute
to a plateauing of overall efficiencies and
productivities. In fact, the data indicate
that many plays already have arrived at
that stage. The Permian is an exception
because it is still in the initial four-year
ramp up phase.
Moving to the next acceleration point
will require even more technology and
innovation, especially outside the fairways.
Instead of drilling 10,000-foot laterals
and pumping 30 stages, perhaps wells in
the second and third tiers would be better
with 4,500-foot laterals and 18 stages.
Operators will have to undertake a new
80 THE AMERICAN OIL & GAS REPORTER

era of experimentation to figure out the
optimal drilling and completion designs,
and getting it right may prove a struggle
in some areas.
The single biggest challenge going
forward is increasing EURs. This is an
extremely important driver on which almost every company is working. There
is a lot of room to run. The very best recovery factors in the very best tight oil
wells are in the 10-15 percent range.
That is better than five years ago, but
still not good enough. During the next
decade, it is feasible that tight oil EURs
can increase to 20 percent, and in some
fields, even approach conventional fields'
34 percent estimated global EUR average.
This will require returning the focus
to the stimulated rock volume to figure
out how to open more reservoir to allow
more hydrocarbons to escape tight rocks.
It will not be easy, particularly in second- and third-tier areas, but the productivity learning curve that operators
recently navigated when they were under
pressure to perform at low prices indicates
the type of EUR enhancement that is
possible.
Other variables that may impact the
industry's collective ability to tap resource
plays' fullest potential are aboveground
issues such as opposition to constructing
new pipelines and plants, changing public
attitudes about energy, and governmental
policies. The industry simply must operate
in environmentally responsible ways.
Good environmental stewardship is as
critical to long-term sustainability as efficiency and EUR improvements.
Tight Rock Opportunities
By 2020, IHS Markit forecasts that
U.S. oil production will stand between
11 MMbbl/d and 12 MMbbl/d, while
natural gas production will be north of
85 Bcf/d. Oil supply will revolve around
the Permian Basin while natural gas focuses on the Marcellus/Utica plus associated gas in the Permian. In fact, in 10
years, we see 70 percent of oil production
growth coming from the Permian. That
does not mean production in the Eagle
Ford, Bakken, SCOOP, STACK, Niobrara
and offshore Gulf of Mexico will not be
growing, but that growth in the Permian
will be significant enough to overshadow
other basins.

Moreover, with so much associated
gas in tight oil plays, oil activity will
start to function as a governor of gas
supply, especially in the Permian. Some
companies may find themselves "caught
in the middle" to some extent between
the Permian and Appalachian superbasins,
but again, that is not to suggest that
players in the Eagle Ford, Bakken,
SCOOP, STACK, Niobrara and other
basins outside the Permian and Appalachian will not thrive.
The big question is whether any plays
that are not yet on the map will emerge
during the next couple years. At IHS
Markit, we no longer talk about unconventional plays, but tight rock plays,
many of which are actually conventional
formations. Many of these conventional
plays have remained off the radar-hence,
we call them "sleeper plays." We are
starting to see sleeper plays pick up
steam. By and large, these are low-permeability/low-porosity formations that
were tested with vertical wells in the
past and found uneconomic. This includes
a number of intervals in basins such as
the Anadarko, Powder River, Uinta,
Greater Green River and East Texas/Upper Gulf Coast.
Independents have been scouring older
basins in search of tight rocks. Soon,
some of these plays will begin to pop up,
especially in the Powder River and Green
River basins. But even a mature province
such as the Gulf Coast will see new tight
rock plays, including perhaps some Eagle
Ford-equivalent tight formations in northern Louisiana. This is a new concept
whereby operators are thinking differently
about geology and figuring out new ways
to apply horizontal drilling and hydraulic
fracturing technologies.
With activity focusing on two U.S.
superbasins-one for oil, and one for gas-
smaller independents will find a wealth
of opportunities to use horizontal drilling
and hydraulic fracturing in secondary
plays throughout most of the country's
historic oil and gas-producing areas. We
have identified many tight conventional
reservoirs that historically have underperformed with vertical drilling, but hold
the potential to deliver economic production using shale play-like drilling and
completion methods. The production volumes will not necessarily overwhelm,
but these sleeper plays will provide ex-



American Oil and Gas Reporter - April 2018

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