American Oil and Gas Reporter - June 2015 - 72

SpecialReport: Artificial Lift Technology
drilled with the lateral going east or west
(parallel to the maximum horizontal stress)
had longitudinal fractures that yielded
normalized EURs of 131,000 barrels of
oil and 182 million cubic feet of gas.
The 32 wells drilled with the laterals
going north or south (parallel to SHmin)
performed much better, with a normalized
EUR of 502,000 barrels of oil and 1.002
billion cubic feet of gas.
In other words, correctly orienting
the lateral tripled these wells' oil production and quintupled their natural gas
production.
Completion Design
Correctly orienting the well is critical,
but maximizing EURs also requires an effective completion. For Endurance, this
means using ceramic proppants. While such
proppants add $1 million to a well's upfront
cost, we have found they provide more
natural conductivity for the fluid than natural
sand, increasing initial flow rates.
By using ceramic proppants, Endurance
has achieved 30-day initial production
rates per 1,000 feet of lateral that exceed
400 boe, or twice those of the offset
wells in the area. In general, the proppant
pays for itself within six months.
The ceramic proppant yields such high
initial flow largely because it has a reduced
beta factor, which keeps it from flowing
back. In Endurance's experience, high
initial flow rates improve the well's longterm recoveries (Figure 2). We believe
using the initial frac energy to accelerate
production leads to higher recoveries than
choking production back to sustain lower
production rates.
In our most recent wells, we have

moved from traditional plug-and-perf
completions to a relatively new method
centered on cemented sleeves that can
be opened and isolated with a coiled tubing-deployed assembly. The assembly
contains a mechanical device that locates
the sleeves, so unlike ball drop methods,
it does not require us to narrow the casing
from sleeve to sleeve. When the device
finds a sleeve, the assembly's resettable
bridge plug activates, the sleeve opens,
and fluid is pumped through the coiled
tubing annulus to initiate the fractures.
This approach concentrates sand more
effectively than a traditional plug-andperf completion. In a plug-and-perf completion, we would pump sand into a
cluster with three entry points. In many
cases, because of differences in the strength
of the formation, most of the sand would
go into one or two of the clusters. The
other one might not get any sand at all,
leaving a third of the wellbore in that
particular stage untreated.
With the new approach, there is a
sleeve for every cluster, ensuring that
every cluster is stimulated. Furthermore,
the stimulation creates deeper fractures.
In a plug-and-perf operation, we would
have to pump 75 barrels a minute for
each cluster to receive 25 barrels, the
amount needed to create a fracture with
a propped height of 100-150 feet. Using
the cemented sleeves and coiled tubing,
we are able to get 35 barrels a minute
across each cluster, a feat that would
previously have required flow rates exceeding 115 bbl/minute. The more concentrated flow can extend fracture height
to 300 feet and increase total reservoir
contact by one-third.

FIGURE 2
Production Rates from Fast and Slow Flowback
100,000

100,000

Fast Flowback
Slow Flowback

Oil & Water

10,000

1,000

Need to make the 1,000
best use of the early
frac energy and flush
production
100

100

10
0

5
Load Water
Recovery/Frac Energy

10
Flush
Production

15
Days
Frac Energy
Fall Off

20
Transition to
Reservoir Drive

72 THE AMERICAN OIL & GAS REPORTER

Reservoir Drive

10
30

The CT-based approach has one other
advantage: During treatment, the coiled
tubing acts as a dead string that transmits
treating pressure to the surface. This
allows us to adjust pad size, sand concentration and ramp, and pumping rates
in real time.
Since Endurance adopted the new approach, our wells have flowed longer and
leveled at a higher rate. As a rough
estimate, the combination of ceramic proppants and cemented sleeve completions
increases each well's long-term production
by 40-50 bbl/d, which adds up quickly.
In some of the wells completed using
the new method, Endurance may be able
to switch from a 51⁄2-inch production liner
to one that is only 4 or 41⁄2 inches in diameter. With the cemented sleeve completion method, that gives us adequate
space to create fractures that are 200 feet
high, which is sufficient to penetrate the
productive interval on parts of our acreage.
By using a smaller liner, we free enough
capital to pay for 7 or 71⁄2-inch production
casing, which will give us the room to
run larger ESPs and optimize our longterm production.

Artificial Lift Selection
Whether we are looking at drilling,
completion or production methods, Endurance focuses on maximizing margins,
not production volumes. In a high-price
environment, the revenue from incremental
barrels can easily make up for the cost required to obtain them. But in today's environment, strategies designed to increase
production actually can decrease a company's profit margin or increase profits so
little that it is no longer worthwhile to
invest time and capital implementing them.
Focusing on margins rather than production can yield big savings. For example,
last October, Endurance needed to decide
whether to continue using ESPs or switch
to gas lift on several wells. ESPs would
produce 200 bbl/d, while gas lift only
would provide 175 bbl/d. To determine if
the 25 bbl/d gain from ESPs would be
worthwhile, we took a hard look at the operating costs associated with each option.
Because we did not have access to
electric utilities, we would need to rent
and fuel generators to power an ESP. On
average, a gas-powered generator would
have cost $22,500 a month to rent and
$10,000 to fuel, even if we were able to
use lease gas, giving it a total cost of
$32,500.
A diesel-powered generator would

American Oil and Gas Reporter - June 2015

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