This document describes a breaker-free, non-damaging nano-composite friction reducer called FR-2 that is effective under various brine conditions. Conventional acrylamide-based friction reducers can cause formation damage and have reduced performance in high-salinity brines. FR-2 is shown to hydrate quickly, reduce friction consistently regardless of brine type, and cause essentially zero formation damage based on core permeability tests. In contrast, conventional friction reducers showed friction reduction dependence on brine composition and severe core damage of up to 99.5%. FR-2 demonstrates advantages over conventional friction reducers for hydraulic fracturing in its breaker-free nature, non-damaging properties, and brine

1. Copyright © 2017 American Scientific Publishers
All rights reserved
Printed in the United States of America
Article
Journal of
Nanoscience and Nanotechnology
Vol. 17, 1–7, 2017
www.aspbs.com/jnn
A Breaker-Free, Non-Damaging Friction Reducer
for All-Brine Field Conditions
J. Jim Wu1 2 ∗
, Weichu Yu1
, Fei Ding1
, Ying Zhang1
, and Zhiqi Liu1
1
Hubei Cooperative Innovation Center of Unconventional Oil and Gas, Yangtze University, Wuhan, 430100, PRC
1
Phoenix C&W, Inc., P.O. Box 481, Bellaire, Texas, 77402, USA
Acrylamide polymers are frequently used as friction reducers (FRs) in slick water fracturing.
Although these FRs are effective at curtailing turbulent flow, the resultant formation damage is a
major concern. This issue becomes worse when high-salinity water is encountered. Attempts are
made to utilize breakers to reduce the extent of damage. However, the results are mostly sub-
par in nature. In this paper, we describe a breaker-free, non-damaging nano-composited friction
reducer, namely FR-2, that is applicable under essentially all-brine situations. The extents of friction
reduction and rates of hydration are characterized with flow loop. Formation damages are assessed
with using synthetic quartz cores. Various conventional friction reducers are compared with FR-2
regarding core damage, friction reduction under various brines and rate of hydration. The results
show that whereas these conventional FRs led to a core damage as high as 99.5%, that by FR-2
was essentially zero. On the other hand, although these conventional FRs perform well in terms of
friction reduction in fresh water or even in KCl, their performances deteriorate substantially in the
presence CaCl2. Most strikingly, when FeCl3 is present, the FRs in comparison lost their effects
entirely. In contrast, FR-2 remains consistently robust in reducing friction regardless of the brines.
FR-2 hydrates in 10–20 sec, whereas some of the tested FRs require longer than 2 min to achieve
the same results. Field trials corroborate the effectiveness of using FR-2 for well clean out and
hydraulic fracturing. To our best knowledge, this is the first report on a breaker-free, non-damaging
friction reducer for slick water fracturing. The novelty also lies on the fact that the performance of
this FR demonstrates independency upon brine variation. These aspects are expected to enhance
oil and gas production and to render peace of mind during fracking operations.
Keywords: Friction Reducer, Hydraulic Fracturing, Non-Damaging, Breaker-Free, Brine
Resistance.
1. INTRODUCTION
The exploration and production of shale gas and oil is
drawing great attention worldwide, where the key chal-
lenge is to enhance the permeability/conductivity of the
reservoir. Various fluids are utilized to stimulate the wells
so that the production becomes realistic and economic.
Often, these systems include linear gels and crosslinked
guar gum. The crosslinking could be realized via the use
of either borate or transition metal ions such as zirco-
nium and chromium. Viscoelastic surfactants (VES) is
also utilized due to its tunable viscosity under applica-
tion conditions.1
The most recent developments over shale
∗
Author to whom correspondence should be addressed.
oil and gas include multi-stage horizontal fracturing and
slick water.2–4
Slick water is a fracturing fluid where cer-
tain amounts of friction reducer (FR), surfactants and clay
stabilizer are added to aqueous medium. Among various
additives, friction reducer is undoubtedly the most critical.
The consequence of inappropriate friction reducer selec-
tion may lend substantial loss of kinetic energy to the
fracturing fluid when reaching thousands of meters down
hole, leaving inadequate energy for effectively fracking
the reservoir. Moreover, the wrongly formulated fluid may
result long-term or permanent formation damage, greatly
reducing daily production or even quickly evolving into a
“dry well.”
J. Nanosci. Nanotechnol. 2017, Vol. 17, No. xx 1533-4880/2017/17/001/007 doi:10.1166/jnn.2017.14500 1

2. A Breaker-Free, Non-Damaging Friction Reducer for All-Brine Field Conditions Wu et al.
Although various options are available from multiple
commercial sources, almost all these friction reducers are
ultra-high molar mass acrylamide polymers in its dry or
inverse emulsion (water-in-oil) form. The research over
matching a friction reducer with field specifics from pro-
cess and production optimization perspective is still on its
infant stage, as majority of the efforts was directed toward
finding chemicals that maximize merely the extent of fric-
tion reduction, i.e., turbulent flow suppression in fresh
water under ambient conditions. Issues such as slow acti-
vation (time to reach 90% of the max. friction reduction)
under low temperatures, incompatibility with brines, for-
mation damage, are far from being adequately addressed.
It was observed that in the fields such as Barnett, Fayet-
teville and Woodford in the United States, gas production
reached a maximum within a month then diminished at
a rate much faster than expected.5
A most recent publi-
cation from Journal of Petroleum Technology reports an
extremely low shale gas and oil recovery rate of only 7%.6
These findings should suggest the presence of far-reaching
formation damage once a shale well is completed via
hydraulic fracturing. It should be stressed that the ultimate
goal of slick water fracturing is to enhance reservoir per-
meability as it is directly linked to how much oil/gas is to
be produced. Therefore, formation damage by slick water
i.e., friction reducer (FR is the most likely damaging in
a slick water formulation) should be the frontier concern.
Surprisingly, very few reports are available from the pub-
lic domain addressing this particular issue. Quite recently,
a “double-component” system, where an oxidizing breaker
such as ammonium persulfate is teamed up with a friction
reducer that is incorporated with a breakable bond, became
available.7
Concurrently, breakers are also utilized along
with conventional friction reducers to break FR to mitigate
formation damage. Unfortunately, few reports could be
retrieved pertaining the detailed protocols and end results.
In this report, we describe a breaker-free non-damaging
friction reducer, namely FR-2 for all-brine field condi-
tions. Instead of going in-depth theoretically, the content of
this report is attempted to be fact-centric and application-
driven based on comparative assessment. The goal is to
present an overview of key issues facing the fracking
industry so that the readers are to become more aware
of how present commercial friction reducers and how
FR-2 behave in terms of compatibility, activation, brine-
tolerance and formation damage, all of which are crucial
for effectively fracturing a shale well. The accounts of
these aspects are expected to benefit not only the engi-
neers who are designing fracturing jobs, but also the scien-
tists who are tackling the fundamental issues during shale
exploration and production.
2. EXPERIMENTAL DETAILS
Unless otherwise noted, all the chemicals used for this
article are reagent grade. Tens of commercialized dry
power and inverse emulsion friction reducers (some may
be duplicates, although from differed sources) are evalu-
ated for performance comparison. Based on the informa-
tion from either suppliers or manufactures, these FRs are
acrylamide-based polymers, but with no further details.
It should be noted that this is a common practice in
the industry to protect proprietary information. Since this
reports involves comparative assessment of products that
encompass commercial interests, the identity of the sup-
pliers and manufacturers are intentionally skipped in order
to avoid any potential conflicts. To achieve simplicity and
objectivity, two representative friction reducer samples,
namely, FR-A (a dry powder) and FR-B (an inverse emul-
sion) were carefully chosen from the pool to compare with
the subject non-damaging friction reducer FR-2.
The non-damaging FR-2 is a nano-composited friction
reducer that was developed through molecular design and
process optimization. A complex reaction medium was
chosen to render colloidal dispersion of particles rang-
ing from nano to submicron scale. The contours of the
macromolecules are tailored in such a manner that they
incur minimized retention by the surrounding matrix and
are insensitive to salinity variation. The dispersed phase
was such customized that the resultant entity not only pos-
sesses the function of taming turbulent flow, but also con-
tributes to water flow back and clay stabilization (not to
be accounted in details in this report).
The typical physical properties of FR-2 are summarized
in Table I. FR-2 is a slightly viscous milky white disper-
sion and has a fairly robust colloidal stability that was
manifested by the fact that no sediment was observed after
storage at room temperature for over 6 months.
2.1. Percentage Friction Reduction Measurements
The basic principle for the determination of friction reduc-
tion is via measuring the fluid pressure drop within a fixed
distance of the interior of a flow loop in the presence and
absence of a friction reducer. The regular testing specs
are: interior diameter = 10 mm, flow rate = 30 L/min, FR
dosage: 1000 ppm. Friction reducer is added to the flow
loop on-the-fly to mimic the field scenario. In the case
of dry powder, aliquots were pre-hydrated before pouring
into a tank mounted on the top of the flow loop.
The FR% is then calculated through Eq. (1):
FR% =
P0 − P
P0
×100 (1)
Where FR% is the percentage friction reduction, P0 is the
differential pressure in the absence of an FR at a specific
Table I. Physical properties of nano-composited FR-2.
Odor pH Solubility Solids Molar mass Density (g/cm3
)
None 6∼8
(1.0%)
Fresh/salt
water
Ca. 50% >5,000,000 1 10∼1 30
2 J. Nanosci. Nanotechnol. 17, 1–7, 2017

3. Wu et al. A Breaker-Free, Non-Damaging Friction Reducer for All-Brine Field Conditions
flow rate, and P is the pressure drop at the same velocity
after adding FR.
2.1.1. Core Permeability
Synthetic quartz cores with a diameter of ca. 2.5 cm and
a length of ca. 8 cm were utilized for core damage assess-
ment. A typical core has a porosity of ca. 20% and a
permeability ranging from 40 mD to 200 mD. The perme-
ability before damage (K1) is measured by letting N2 flow
in the inlet of the core holder at a flow rate below the crit-
ical flow rate to assure the applicability of Darcy’s Law.
After the flow rate and the N2 pressure has been stabilized
for at least 1 hour, record the flow rate and the pressure.
The FR-containing fracturing fluid is then allowed to flow
in the outlet of the core holder (i.e., the reverse direction).
When the fracturing fluid begins to flow out, start record-
ing the amount of flow. The damaging process is deemed
over once the flow is two times of the pore volume (PV).
Close the inlet and outlet of the core holder, and keep the
fracturing fluid in the core for 2 h. The permeability after
damage (K2) is measured by letting N2 flow in the inlet of
the core holder and repeat the test as that described above.
The inlet pressure was kept essentially the same, which
leads to differed flow rate correlating to various extents of
core damage.
The permeability (K) is calculated via the Eq. (2) below:
K = 10−1 2Q LP0
P2
1 −P2
0 A
(2)
where Q: N2 flow rate, cm3
/s, : N2 viscosity, mPa · s,
L: core length, cm, P1: inlet pressure reading plus atmo-
spheric pressure; MPa, P0: atmospheric pressure, MPa,
A: core cross-section area, cm2
.
When water is used to mimic shale oil and functions as
the mobile phase, the permeability before and after damage
is calculated by the Eq. (3):
K = 10−1 Q L
PA
(3)
where Q: water flow rate, cm3
/s, : water viscosity, mPa·s,
L: core length, cm, P: pressure difference at the inlet
and the outlet, MPa, A: core cross-section area, cm2
.
In both of the cases, the regained permeability ( ) is
calculated with the equation = K2/K1.
3. RESULTS AND DISCUSSION
3.1. Compatibility of Various FRs in Fresh Water
When designing fluid for fracking, one first assessment
is whether the friction reducer is to render a transparent
solution in water. Although transparency is desired, very
few commercial products generate clear, totally compati-
ble solution upon dissolution. For example, it takes the dry
powder FR-A approximately 20 min to dissipate into water
under agitation and the resultant solution remains cloudy.
Figure 1. Compatibility of FR-2, FR-A and FR-B with fresh water
(25 C; 1000 ppm).
The inverse emulsion FR-B appears to be difficult to dis-
solve as well. Incompatible material floats on the top of the
solution after 20 min of agitation and the resultant “solu-
tion” remains turbid even after sitting at room temperature
for two weeks (Fig. 1). In contrast, FR-2 dissolves quickly
into water under agitation. A clear, transparent solution
was formed in less than 30 secs suggesting a complete
dissolution.
3.2. Friction Reduction Under Ambient Conditions
(25 C) in Fresh Water
Besides an FR’s compatibility, one evaluates its extents
of friction reduction in fresh water for screening. As can
been seen from Figure 2, at a dosage of 1000 ppm, both
of the two commercial FR-A and FR-B, along with FR-2
were able to generate a friction reduction of ca. 80%,
with the tailing friction reduction at 5 min above 75%
as well (Fig. 2). It should be noted that during hydraulic
fracturing, it normally takes an FR (in slick water) approx.
3 min travelling from the wellhead to downhole (tubing
volume 30–40 m3
; pumping rate ca. 12 m3
/min). Thus, the
friction reduction after 3 min makes no further contribu-
tion once it hits downhole and when the turbulence ceases.
Figure 2. Friction reduction of FR-2, FR-A and FR-B (1000 ppm) at
ambient temperature (25 C) in fresh water; solid line: FR-2, dashed line:
FR-A, dotted line: FR-B.
J. Nanosci. Nanotechnol. 17, 1–7, 2017 3

4. A Breaker-Free, Non-Damaging Friction Reducer for All-Brine Field Conditions Wu et al.
Figure 3. Friction reduction of FR-2 and FR-B (1000 ppm) in fresh
water at 5 C to illustrate activation time; solid line: FR-2, dotted line:
FR-B.
The performance after 3 min should be still considered
when the pumping rate is less than 12 m3
/min, i.e., when
it takes an FR longer than 3 min to reach downhole.
In this report, activation time is defined as the time
an FR reaches 90% of its theoretical max. friction reduc-
tion. For example, the theoretical max. friction reduction
by FR-2 is 80% (Fig. 3). Under this condition, the acti-
vation time for FR-2 is the time it reaches 72% of fric-
tion reduction. This parameter is important when one deals
with inverse emulsion-based FR, as inverse emulsion needs
phase inversion to release FR molecules to water. This
process could be extremely sluggish when temperature is
below a certain threshold. As can been seen from Figure 3,
at 5 C, it took FR-B over 3 min to activate, reaching 72%
friction reduction. Since the overall time for an FR travel-
ling from the wellhead to downhole is typically 3 min, this
slow activation may greatly sacrifice the performance of
FR-B to effectively fracture the well. In contrast, it costs
FR-2 less than 20 secs to activate. In the case of the dry
powder FR-A, the concept of activation does not apply,
as it does not qualify on-the-fly injection and has to be
pre-hydrated before pumping.
3.3. Comparative Friction Reduction in
Various Brines
Brine resistance of a friction reducer is getting more
attention for fracking job design. Although fresh water is
preferably chosen, the encountering of slick water with
brines, i.e., various metal ions is unavoidable. The rea-
son lies that formation water intrinsically possesses vari-
ety of ions such as calcium and sodium. In addition, it
is currently a common practice for engineers to utilize
hydrochloric acid during the spearhead stage of hydraulic
fracturing. Although acid corrosion inhibitors are concur-
rently employed, the reaction between hydrochloric acid
and carbon steel is inevitable with the generation of fer-
ric chloride as the results. The unconsumed acid is to
Figure 4. Friction reduction of FR-A, FR-B and FR-2 (1000 ppm) in
the presence of 10% KCl (25 C); solid line: FR-2, dashed line: FR-A,
dotted line: FR-B.
etch calcite mineral in the formation to its soluble form,
calcium chloride, which is the intended function of the
acid in the design. Since both calcium and ferric ions are
strong chelating agent, they are expected to function as
a muster point facilitating the aggregation of acrylamide
polymer via their electronegative moiety. This aggregation
may incur two-fold damage: damping the extent of friction
reduction along the tubing and blocking flow channels in
the reservoir. Therefore, it is crucial to grasp how a friction
reducer behaves in the presence of various brines. In the
content below, we describe the comparative friction reduc-
tion performance of FR-A, FR-B and FR-2 in the presence
of a monovalent brine KCl, a bivalent brine CaCl2 and a
trivalent brine FeCl3 at 100,000 ppm (10%), respectively.
Figure 5. Friction reduction of FR-A, FR-B and FR-2 (1000 ppm) in
the presence of 10% CaCl2 (25 C); solid line: FR-2, dashed line: FR-A,
dotted line: FR-B.
4 J. Nanosci. Nanotechnol. 17, 1–7, 2017

5. Wu et al. A Breaker-Free, Non-Damaging Friction Reducer for All-Brine Field Conditions
Figure 6. Friction reduction of FR-A, FR-B and FR-2 (1000 ppm) in
the presence of 10% FeCl3 (25 C); solid line: FR-2, dashed line: FR-A,
dotted line: FR-B.
As shown in Figure 4, the presence of KCl at 10% sup-
presses the performances of both FR-A and FR-B. The
friction reduction of FR-B dropped from 81% in fresh
water to ca. 79% in KCl solution at 10%. In the case of
FR-A, its max. extent of friction reduction dropped sub-
stantially from 80% to be ca. 60%. FR-2 remained essen-
tially unaffected in the presence of 10% KCl.
It is known that monovalent brines are mild in com-
parison to bivalent and trivalent counterparts. As describe
above, the presence of both Ca2+
and Fe3+
are expected
downhole in the formation. Therefore, it is critical to
assess the behavior of an FR in the presence of these ions.
As can be seen from Figure 5, although the inverse emul-
sion friction reducer FR-B was able to maintain a maxi-
mum friction reduction at ca. 60% with the tailing at 5 min
to be ca. 40%, the dry powder friction reducer FR-A lost
almost its entire performance (<10%). Both FR-A and
FR-B rendered highly turbid solution upon dissolving in
Figure 7. Appearance of FR-2 and FR-B (1000 ppm) in the presence
of 10% FeCl3 (25 C); image (A) FR-2, image (B) FR-B.
Figure 8. Imaginary fate of conventional FR molecules in the presence
of Ca2+
/Fe3+
; these metal ions function as muster points for polymer
aggregation, which may reduce the extent of friction reduction and block
up the flow channel.
10% KCl, similar to those shown in Figure 1. In contrast,
FR-2 formed transparent solution in 10% KCl.
The most-troublesome metal ion was proven to be ferric,
as all the tested friction reducers (approx. 50 from various
sources) lost their performance entirely in the presence of
FeCl3 (100,000 ppm) (Fig. 6). FR-2 was able to sustain
its performance to be 80% friction reduction. In the pres-
ence of FeCl3, all the FRs we evaluated, but FR-2, form
“tofu”-like chunks that quickly sink to the bottom of the
container (some stick to interior surface) with the overall
volume of the chunks much larger than that of the original
FR. These chunks (Fig. 7) are expected to cause serious
formation damage, as was illustrated by Figure 8. In con-
trast, FR-2 still forms transparent solution in the presence
of 10% FeCl3.
3.4. Core Permeability Damage by Various FRs
Formation damage by slick water should have been in
the focal point but does not appear to be widely inves-
tigated. Studies have shown that after fracturing of shale
oil/gas, the daily production rate is substantially lower than
expected. Reservoir damage by fracturing fluid remains a
highly likely factor to this phenomenon, although it is sub-
ject to proven.
Tables II–IV summarize the comparative core perme-
ability, where K1 represents the original permeability
before damage and K2 represents the permeability after
replacement by water (mimicking flow back) for certain
periods of time. Cores were chosen to have somewhat
higher permeability, taking into account the enhancement
after fracking and in the presence of proppants. After
flowing back 84 times of the pore volume (PV), FR-
A still maintained ca. 77% permeability damage. After
504 times of the PV, FR-B held a permeability damage
of ca. 99%. By comparison, after elution of only 20 PV,
FR-2 reached a regained permeability of ca. 80%. After an
elution of 610 PV, the regained permeability was almost
Table II. Core permeability recovery to water by FR-A.
K1 = 46 mD Pore volume (PV) Regained perm%
Flow back 1 h 20 17.6
Flow back 8 h 60 21.3
Flow back 24 h 84 23.5
Notes: Dosage: 1000 ppm; mobile phase: Aqueous; 25 C.
J. Nanosci. Nanotechnol. 17, 1–7, 2017 5

6. A Breaker-Free, Non-Damaging Friction Reducer for All-Brine Field Conditions Wu et al.
Table III. Core permeability recovery to water by FR-B.
K1 = 134 mD PV Regained perm%
Flow back 1 h 28 0.5
Flow back 2 h 57 0.8
Flow back 19 h 504 1.4
Notes: Dosage: 1000 ppm; mobile phase: Aqueous; 25 C.
Table IV. Core permeability recovery to water by FR-2.
K1 = 161 mD PV Regained perm%
Flow back 1 h 20 79.5
Flow back 8 h 225 81.5
Flow back 24 h 610 99.4
Notes: Dosage: 1000 ppm; mobile phase: Aqueous; 25 C.
100%. In contrast, FR-B had a recovery of only 1.4% after
over 500 PV.
Table V summarizes the permeability recovery to gas
(nitrogen in this case) by various friction reducers. As can
be seen, with the dry powder FR-A and the liquid emul-
sion FR-B, the core permeability damage was 92.6% and
99.8%. In contrast, the permeability damage by FR-2 was
only 0.8% (almost none).
3.5. Well Clean out by FR-2 and FR-A
To illustrate the effectiveness of FR-2 and dry powder
FR-A, they were adopted for well clean out by using
2-inch I.D. coiled tubing. The flow rate of the correspond-
ing slick water was adjusted from zero to 0.55 m3
/min.
Figure 9 is a plot of pump pressure versus flow rate when
FR-A and FR-2 slick waters were injected at the same rate.
One sees that when the flow rate is low (0 2∼0 3 m3
/min),
the two FRs led to basically no difference in friction reduc-
tion. With a further increase of flow rate, FR-2 led to
a better performance (lower pump pressure) than the dry
powder FR-A. At a flow rate of ≥0.55 m3
/min, the advan-
tage of using FR-2 to curtail pump pressure over FR-A
becomes more obvious (Fig. 9). The pressure by FR-2 was
ca. 20% lower than that by FR-A (dotted line in Fig. 9).
The enhanced performance by FR-2 could be due to the
presence of ions in the coiled tubing and downhole, which
led to a decreased friction reduction by FR-A.
3.6. Horizontal Fracturing by FR-2 and FR-A
During horizontal fracturing, the main friction reducer is
FR-A. The trial of using FR-2 was not started until later
time when the pump pressure was stabilized. The use of
Table V. Core permeability recovery to GAS by FR-A, FR-B and FR-2.
Friction reducer K1 (mD) K2 (mD) Regained perm%
FR-A 172.7 12 76 7.4
FR-B 166.3 0 5 0.3
FR-2 147.7 146 5 99.2
Figure 9. Pump pressure by FR-A and FR-2 during a well clean out via
coiled tubing (2 inch I.D.); dashed line: FR-A; solid line: FR-2; dotted
line: pressure drop% by FR-2 (in comparison with FR-A).
FR-A was then switched to FR-2. After the use of FR-2,
the friction reducer was switched back to powder FR-A
again.
The data were chosen to represent before, during and
after the test (of using FR-2). The pumping rate was
constant for these three stages at 12 m3
/min. These data
directly reflect the comparative performance of FR-2 and
dry powder FR-A.
Before FR-2 injection, where powder FR-A was
employed, the average pump pressure was ca. 57.4 MPa.
During the time when FR-2 was injected, the average
pump pressure was 52.0 MPa. After the trial, the powder
FR-A was switched back and the average pump pressure
was 54.0 MPa. Thus, the use of FR-2 led to a decrease of
pump pressure by 9.4% and 3.7% in comparison with the
use of FR-A before and after (Fig. 10).
The superb performance by FR-2 could be due to the
presence of various metal ions in the downhole, as these
ions are expected to dampen the extent of friction reduc-
tion by FR-A, but not FR-2. It could also be in part due to
an easier penetration of FR-2 slick water to the formation,
as it is non-damaging (lesser resistance). The minimized
hindrance downhole should be reflected in the wellhead
as a curtailed pump pressure. More field trials regarding
Figure 10. Pump pressures before, during and after the use of FR-2
during a horizontal fracturing (pumping rate: 12 m3
/min).
6 J. Nanosci. Nanotechnol. 17, 1–7, 2017

7. Wu et al. A Breaker-Free, Non-Damaging Friction Reducer for All-Brine Field Conditions
the pump pressure control and production enhancement are
underway and are subject to future reporting.
4. CONCLUSIONS
A breaker-free non-damaging all-brine friction reducer,
namely, FR-2 is developed. Along with an overview
of various issues facing the shale gas and oil indus-
try, comparative assessment demonstrates that the FR-2
is completely compatible with water and activates within
20 seconds upon adding to water. Mostly importantly,
the results corroborate that the use of FR-2 adequately
addresses the brine-tolerance and formation damage issues
that should be among the top of fracking design engi-
neers’ agenda. Amongst tens of friction reducers evalu-
ated thus far, FR-2 peerlessly renders untamed friction
reduction performance in the presence of KCl, CaCl2
and FeCl3 (salt concentration as high as 100,000 ppm).
More importantly, FR-2 uniquely compels essentially zero
core/formation damage, which is expected to translate to
substantially increased daily oil and gas production. Trials
of comparative well clean out and horizontal fracking
support the effectiveness of FR-2 over the representative
FR-A. More field trials are underway to further jus-
tify the recommendation of using FR-2 under all-brine
field conditions and enhancement of daily gas and oil
production.
Acknowledgment: The authors thank the National Nat-
ural Science Foundation of China (No. 51274048) for
funding.
References and Notes
1. A. A. Omeiza and A. B. Samsuri, ARPN Journal of Engineering and
Applied Sciences 9, 25 (2014).
2. G. Schein, SPE-108807 The Application and Technology of Slickwa-
ter Fracturing (2005).
3. J. D. Arthur, B. K. Bohm, B. J. Coughlin, M. A. Layne, and
D. Cornue, SPE-121038 Evaluating the Environmental Implications
of Hydraulic Fracturing in Shale Gas Reservoirs (2009).
4. G. E. King, SPE-133456 Thirty Years of Gas Shale Fracturing: What
Have We Learned? (2010).
5. J. Baihly, R. Altman, R. Malpani, and F. Luo, Study assesses shale
decline rates, The American Oil and Gas Reporter, May (2011).
6. T. Jacobs, Journal of Petroleum Technology (2016).
7. H. Sun, R. F. Stevens, J. L. Cutler, B. Wood, R. S. Wheeler,
and Q. Qu, SPE-136807, A Novel Non-Damaging Friction Reducer:
Development and Successful Slickwater Frac Applications (2010).
Received: 5 April 2016. Accepted: 1 September 2016.
J. Nanosci. Nanotechnol. 17, 1–7, 2017 7