36 |
Oilfield Technology
January
2016
Because the polymer remains wrapped around the proppant
until breaking, the fluid with polymer does not leak off deep into the
formation as with slickwater treatments, which can harm the formation.
Without guar and crosslinkers, operators can fracture and uniformly
place the optimal amount of fluid and proppant in tight pay zones
without proppant pack damage. Overall, based on industry research,
typical frack fluid additives that support proppant transport can
decrease formation permeability and proppant pack conductivity by as
much as 60%and 70% respectively.
Multifunctional polymer
The robust, micron-thick polymer – wrapped around any commonly
pumpedmesh size of ceramic proppant or sand – is the technology’s
critical element. This multifunctional polymer is designed to allow
operators and services companies to pump the desired proppant in a
low-viscosity fluid while increasing hydrocarbon production compared
with traditional hydraulic fracturing fluid systems. Additional chemicals
are not required. The polymer’s friction-reduction properties also offer
some viscosity. The company’s research and development teamalso
engineered the polymer to resist swelling in humidity while tolerating
high shear forces during hydraulic fracturing operations.
In addition, the polymer coating is ductile and absorbs impact.
These factors limit dust fromproppant throughout the supply chain all
the way to the well. The technology generates 77% less respirable dust
compared with frack-sand handling operations, based onmeasurements
at company coating plants specially designed for manufacturing this
technology. All of the research and development work has confirmed
polymer reliability fromhealth, safety, and environment (HSE) and
operational points of view.
In cold temperatures, the technology performs inwater just above
freezing unlike crosslinked gel-based frack fluids that require temperatures
as high as 80˚F and a prehydration unit to reach the desired viscosity.
Operators can spendmore thanUS$500 000 per well on heatingwater for
winter fracks. While theremay be other reasons to heat frackwater, such as
mitigatingmechanical stress in surface iron and subsurface casing, much
of the heated-water expense is for gel hydration.
Shear stability
Besides moisture resistance and dust-mitigation properties, the polymer
can withstand pressure pumping and tortuous downhole conditions.
This ‘shear stability’ is the polymer-coating’s capacity to remain attached
to the proppant during blending, pressuring pumping, and during
transport into the wellbore through the fracture. Figure 1 illustrates this
engineered, shear-stable technology.
To validate the polymer would not shear off the substrate into the
fracturing fluid, the performance parameters must remain intact upon
increasing shear rate. Performance parameters include fluid viscosity and
settled bed volume, ameasure of suspension relative to the uncoated
proppant substrate. If shearing caused a significant fluid viscosity
increase or settled bed volume decrease, the technology advantage
would be contradicted. In this case, the fluid would be similar to a
conventional gel-based frack fluid.
Stim-Lab confirmed the technology is at least shear stable up to
9600 sec-1 for more than 20minutes with nominal change in viscosity.
Themaximum shear rate was based on test limitations. Stim-Lab applied
shear by circulating the technology through a high shear pump in a
flow-loop apparatus for up to 1 hour. A high-pressure, high-temperature
viscometer further stressed the proppant-laden fluid. All tests confirm
pressure pumping and downhole conditions will not degrade the
polymer coating, allowing operators to uniformly distribute proppant
throughout the fracture.
This shear stability that ensures efficient proppant transport keeps
the hydrogel polymer attached to the substrate to facilitate plugging
areas of lower pressure where fluid leaks off while pumping. The
polymer-coated proppant, which also functions as a fluid leakoff control
agent, improves fluid efficiency. As one of the technology’s primary
Figure 1.
Thismagnified image of the technology shows the hydrated
polymer wrappedaroundandattached to aNorthernWhite sandgrain.
Figure 2.
These two Stim-Lab slot test images compare proppant transport in slickwater fluid (top), andPropel SSP technology, (bottom). In the
slickwater fluid, 20/40-meshNorthernWhite sandquickly settles, formingadune that increases the screenout potential and limits the effective propped
fracture length. At full saturation, Propel SSP technologywrappedaround 20/40-meshNorthernWhite sand is uniformly transportedanddistributed
throughout the fracture network formaximised conductivity.
