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Oilfield Technology
January
2016
characteristics, the polymer’s shear-resistance enables an operator to
select the desired proppant mesh for efficient placement in the fracture
network.
Polymerbreak
Breaker testingwas conductedwith ammoniumpersulfate and
magnesiumperoxide, among others, under various conditions, including
temperature, breaker loading rates, proppant loading rates, and time.
The teamverified complete polymer breaking by testing the fluid viscosity
and settledbed volume; only the rawproppant substrate remains in the
fractures. Conventional viscosified fluids are consideredbrokenwhen
the viscosity is near that of water. R&Ddata confirmgeneral trends that
with increasing downhole temperature andbreaker loading, break
time decreases. As proppant loading increases, additional break time is
required.
After breaking the polymer systemand upon fluid flowback, there
is no residue on the proppant pack or in the formation. This is a very
important factor, as mentioned above, considering traditional fluids can
leave residue that damages the proppant pack or bonds to water and
the rockmatrix deep in the formation, limiting hydrocarbon flow out of
the fractures. When the well is cleaned up satisfactorily, an operator can
be confident of an optimised hydrocarbon flow. Better cleanup equals
better production.
Following fluid cleanup from the well, laboratory testing determines
the frack fluid’s effect on proppant pack regained conductivity. This
is ameasure of howmuch of the original proppant pack/fracture
conductivity remains. According to Stim-Lab tests, because the
technology does not damage the proppant pack with fluid additives,
regained conductivity is maximised compared with only 50% regained
conductivity typical for guar-based fluids.
In additional laboratory testing, the proppant transport technology
demonstrated 100% retained oil permeability in the Ohio sandstone core
while the conventional fluids exhibited some level of damage. Overall,
compared with slickwater, the technology minimises formation damage
because after breaking the polymer does not adhere to water and rock
deep in the formation as does a friction reducer. Operators are improving
formation permeability and fracture and proppant pack conductivity
froma residue-free fluid.
Greater fracturehalf-length
The hydrogel polymer will create a separation between proppant
grains after they have settled. When proppant concentration is
ramped up to or above full saturation, the fluid traversing the
fracture is completely filledwith proppant. In this case, proppant
is distributed throughout the fracturewith aminimal amount of
fluid, maximising the effective fracture half-length unlike slickwater
(Figure 2).
Even when final proppant concentration does not achieve full
saturation, the height of the settled Propel SSP proppant in the
fracture will be higher than the equivalent proppant quantity that
settles in a slickwater or linear gel-based fluid. Although proppant
that settles in traditional fluid systems forms a conductive
proppant pack, the effective half-length is shorter because
of insufficient propped frack height. Despite the frack being
in-zone, excess fluid and proppant are required with alternative
low-viscosity fluid systems to achieve a comparable effective
half-length.
With highly viscosified gel based fluids, frack height can
grow vertically out of the net pay interval, resulting in out-of-zone
proppant placement. Maximumproppant concentration is often
kept between 4 and 6 ppg for this reason to limit the amount of
proppant placed in a nonproductive zone.
Fracks with Propel SSP technology remain in-zone like
slickwater, but with the important difference of less leakoff and
superior transport at high loading rates – often 6 ppg or higher
– that allow operators to maximise conductivity using the least
fluid volume. Fracks with Propel SSP technology compared with
crosslinked gel maintain increased efficiency by keeping the
proppant and fluid in-zone (Figures 3 and 4).
Reducedcostperboe
Propel SSP technology’s low-viscosity frack fluid is yielding
improved production results in hydrocarbon basins throughout
the US and Canada. Oilfield services companies have completed
more than 60 wells for 16 operators in initial field trials.
Operators are applying a significantlymore efficient hydraulic
fracturing systemthat eliminates fluid sweeps, decreases fluid
additives, and reduces pumping time, all of which enhance
production success at lower cost per boe. This proppant
technology enables greater reservoir drainage by travelling farther
in a thin fluid for a substantially improved propped fracture surface
area and conductivity.
Figure 3.
In the frackmodel above andbelow, the pay zone ismarkedby the black
lines, ranging from9450 to 9550 fton the y axis. In this Figure 3 crosslinked-gel frack
model, nearly all of the proppant is inefficiently placed out of the pay zone.
Figure 4.
In the Propel SSP technology frackmodel, nearly all of the proppant
is placed efficientlywithin the pay zone and two times farther into the fracture
comparedwith the crosslinked-gel frackmodel above. Although the Propel SSP
technology frackwidth is narrower, the greater amount of proppant in-zone
increases the propped fracture surface areawith the least fluid volume.
