American Oil and Gas Reporter - February 2016 - 44

SpecialReport: Unconventional Resource Science

Technology Solves Sanding Problems
By John H. "Jay" Thompson,
Jeff Dwiggins
and Scott Muster
OKLAHOMA CITY-The industry's
concept of sand control has been redefined
by unconventional reservoir development.
A decade ago, sand management was associated with conventional, high-permeability reservoirs, where "getting the
beach out" was required to sustain hydrocarbon production in sand-producing
intervals, particularly sandstones and
other unconsolidated formations.
With the advent of multistage completions of horizontal wells in unconventional resource plays, the production of
frac sand and other proppants has become
a more widespread challenge. For the
majority of oil and gas fields, sand from
the reservoir is an inevitable byproduct
of hydrocarbon production. In unconventional wells, however, it is a consistent
challenge.
Virtually all wells completed in unconventional formations experience some
level of proppant flowback, since all
wells in these plays require hydraulic
fracturing to produce economic rates of
liquids and gas. Proppant flowback begins
immediately with fluid flowback at the
time of pressure release, but can occur to
different degrees throughout a well's productive life cycle. Depending on the particular operator's completion method,
sand flowback issues can range from
moderate to severe, and may present myriad problems.
The immediate concern is damage to
artificial lift systems and other downhole
equipment, in particular electrical submersible pumps, as well as plungers,
valves and tubular components. Sandrelated problems can be very expensive
to remediate, resulting not only in increased operational costs, but also potentially leading to equipment failures
that necessitate unscheduled repairs and
interrupting hydrocarbon flow to the
sales line (increasing costs while decreasing revenues).
Given the prevailing low commodity
price environment and the need to optimize
the economics of each asset, a single
equipment failure can impact a well's
bottom-line performance materially. Costs
vary based on the type and size of equipment installed and the well's location,
44 THE AMERICAN OIL & GAS REPORTER

but the capital expenses associated with
a well intervention to repair or replace a
damaged ESP system can exceed $150,000
for horizontal wells. The value of lost
and/or deferred production from downtime
also must be factored into the equation,
along with the possibility of decreased
reservoir performance that may never be
restored.
In some wells, downhole pumps have
to be replaced as often as three or four
times a year because of wellbore sanding,
creating an operating cost structure that
challenges profitability, especially at lower
wellhead prices. In pad developments
with multiple wells, recurring sand problems that require frequent interventions
can negatively impact the economics of
individual pads as well as entire field development areas.
Looking at well construction trends
in shale and tight reservoirs, proppant
flowback and sand control issues certainly
do not appear to be diminishing anytime
soon. In fact, given the correlation between
higher volumes of sand pumped during
hydraulic fracture treatments and better
production performance in horizontal
wells in many plays, proppant volumes
pumped per well have effectively doubled
since late 2013, according to data from
Primary Vision Inc.
Increased proppant concentrations per
stage mean that wells completed with
500-750 pounds of proppant for each lateral foot a few years ago now are being
completed with 1,000-1,500 pounds/foot
(routinely exceeding 7 million pounds
total for each lateral completed in the
Bakken, Eagle Ford and other plays).
While helping operators maximize production and recovery rates, it also obviously places twice as much frac sand in
the formation.
Sand-Related ESP Failures
Sucker rod pumping is the most widely
used artificial lift method in U.S. onshore
operations, but oil and gas companies invest more capital in electric submersible
pump equipment than any other lift
method. In fact, ESPs account for more
than 45 percent of the total annual spending
on artificial lift installations. They are
deployed routinely in shale plays to accommodate high productivities, and frequently are used in combination with
other forms of artificial lift at different

stages of a well's productive life.
For example, a horizontal well may
be equipped with an ESP to accommodate
the high-rate initial production phase, but
then converted to rod pump or some other
form of lift once IPs have dropped. But
even in these situations, proppant flowback
typically occurs most frequently in the
earliest stage of production, when an
ESP is required to accommodate the peak
initial flow volumes.
Consequently, ESPs in horizontal shale
wells commonly suffer from severe erosion
and radial wear caused by frac sand and
other residual solids. The biggest challenges for ESPs are sand and gas slugging,
which lead to excessive temperatures in
the motor, cable and pump section. Prominent failure modes are related to erosion,
sand accumulation, plugging or contamination, and loss of radial stability.
In unconventional reservoir applications, ESP shutdowns happen throughout
the life of a well, and sanding is always
a concern when restarting the pump.
When an ESP cycles off or shuts down,
the sand trapped in solution in the production stream begins to fall out and
collect on the top of the pump. By the
time the ESP cycles back on, sand can
accumulate to the point that it clogs the
pump chamber.
Restarting a sand-plugged pump can
cause catastrophic harm, including the
inability to restart because of severe plugging (thereby mandating a workover),
significant damage to the upper stages
(commonly top 20-30 percent), forcing
lower stages into down-thrust, torque
twisting and broken pump shafts, and
burned motors from starting under high
load conditions.
For this reason, fluctuations or disruptions in electric supply are a key issue
in ESP applications. Every time the power
goes out, sand starts falling back on the
pump.
Electricity reliability tends to be a localized problem, and some areas are
worse than others. In North Dakota, for
instance, ongoing improvements to stabilize the power grid in the Bakken play
area have eliminated many lingering problems. However, in areas such as the Mississippian Lime trend in Oklahoma and
the Permian Basin, power fluctuations
remain the root cause of many production
issues, including pump failures caused

American Oil and Gas Reporter - February 2016

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