American Oil and Gas Reporter - January 2015 - 86

Unconventional Resource Science
Even a 1 or 2 percent increase in a well's
ultimate recovery can translate to a tremendous amount of crude oil or natural gas over
the life of the well, observes Ross Craft,
chairman and chief executive officer of Fort
Worth-based Approach Resources Inc.
"We think we have it figured out," offers the leading operator in the Wolfcamp
Shale play in West Texas' southern Midland Basin. "But our recovery is still
low. We are talking about 3.0-3.5 percent
recovery of the oil in place and 10 percent
of the natural gas.
"The Wolfcamp Shale is approximately 1,200 feet thick in the southern Midland
Basin, or roughly four times as thick as the
average shale pay zone," Craft points out.
"With roughly 125 million barrels of oil
equivalent per 640 acres of in-place reserves and a 3-4 percent recovery factor,
someone will figure a way to conduct some
type of secondary recovery. I may no longer
be around, but someone will figure it out.
This play will be here for a long, long time.
Hopefully, our younger engineers and geologists will figure out how to get the oil
recovery rate up to 10 percent."
Adds Continental's Gould, "If you
spend (as much as $9.6 million in the
Bakken) to drill a well, you want optimal
recovery."
In fact, he says optimal recovery has
been the emphasis over the past year at
Continental, which is the largest leaseholder in the Bakken, where the company has
drilled more than 1,000 wells in the past

four years.
"When you start, delineating the play
is the most important thing in order to hold
acreage," Gould reflects. "Now that most
of the acreage in the Bakken is held by production, we and others are moving into a
manufacturing mode. We really are working on two things: reducing costs while optimizing completion design."
In its third-quarter earnings report,
Continental announced it had been testing
various enhanced completion technologies
and monitoring results throughout its
Bakken leasehold in its quest for the optimum formula for future development.
More recently, the company expanded its
assessment to include industrywide enhanced completion results.
The combined results, according to
Gould, show that the early time uplift in
production can be sustained in certain areas, which translates to a higher estimated ultimate recovery per well. He says
where Continental has its most complete
dataset, it has observed an average production uplift of 45 percent over the first 90
days and an average EUR increase of approximately 30 percent.
The company announced it planned to
focus the majority of its 2015 Bakken capital expenditures in areas it anticipated improved recoveries.
Slickwater Design
As Continental began experimenting in
late 2013 and early 2014 to develop op-

Through its quest to optimize its
own completion techniques as
well as monitor industrywide results, Continental Resources reports it has realized average
production uplifts of 45 percent
over the first 90 days in Bakken
Shale wells for which it has the
most complete datasets, as well
as 30 percent better estimated
ultimate recoveries. In addition
to traditional pumpjacks, Continental is testing long-stroke
units, downhole electrical submersible pumps, and gas lift.

86 THE AMERICAN OIL & GAS REPORTER

timal economics in the Bakken, one thing
it did was devise a new completion technique using slickwater or hybrid designs.
"Slickwater fluid creates more complex
fractures, which helps stimulate the rock,"
Gould comments. "But it is hard to carry
the same sand concentration using slickwater as compared with gels. So we have
started experimenting with a hybrid design.
We start with slickwater and finish with gel
to carry more sand into the reservoir and
provide better connectivity between the
reservoir and the wellbore."
He says initial 90-day results in
Williams and northern McKenzie counties,
N.D., have shown increased production of
45 percent. "We are very encouraged,"
Gould says.
Typically, he says, Continental has
drilled two-mile laterals with 30 frac
stages in the Bakken. Now the company
is experimenting with 40 frac stages in the
same two-mile lateral to get more connectivity. "There is additional cost, but additional recovery," Gould relates. "It is too
early to know the results; it will take a couple quarters to get the 90-day rates for a
significant number of wells."
Continental also has experimented
with drilling several three-mile laterals. He
says there is not an exponential increase
in cost from drilling the longer lateral.
"You spend a certain amount just to get to
the reservoir," Gould outlines. "There is
an efficiency factor in drilling a longer lateral, but it is a challenge to drill a 15,000foot lateral."
Gould notes company engineers evaluate data constantly to come up with the
optimal density spacing.
"Is the proper spacing 660 feet, 1,320
feet, or somewhere between?" he ponders.
"It often depends on where in the field the
wellbore is located and whether we are
drilling in the Middle Bakken or one of the
Three Forks benches. We haven't seen
enough data yet to make a definitive determination. The great thing is that when
you have drilled 250-300 wells a year and
participated in several hundred more,
you have a chance to learn and test."
After completing a well, companies
have to determine what artificial lift to use,
which is another factor in determining
EUR, according to Gould.
"Larger completion designs require
larger artificial lift," he comments. "Pumpjacks have been our historical standard, but
we are testing long-stroke units that pro-

American Oil and Gas Reporter - January 2015

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