1. SPE 171999
Viscoelastic Surfactants Based Stimulation Fluids with Added Nanocrystals and
Self-Suspending Proppants for HPHT Applications
Avi Aggarwal, SPE, Soham Agarwal, SPE, Indian School of Mines; Shubham Sharma, SPE, Halliburton Logging
Services
Copyright 2014, Society of Petroleum Engineers
This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 10–13 November 2014.
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Abstract
With dwindling resources and mushrooming energy demands worldwide, HPHT field development has come under the
limelight of the industry. Thus for expanding the existing horizons, new frontiers in HPHT stimulation advancements are
being anticipated for economical harnessing of hydrocarbons. From more than a decade, surfactant fluids had been
extensively employed in completion and stimulation operations as the surfactants arrange anatomically to form very long
worm-like micelles, maintaining considerably low formation damage levels, and simultaneously exhibiting brilliant
rheological properties, viscosity and proppant transportability. High fluid leak off and its inability to withstand temperatures
greater than 200°F, have limited its HPHT application. Similar is the case for proppants where significant advancements have
been made to increase its strength, but with better strength it has become heavier, causing early screenout, making it unable
to reach deeper-complex fractures and requiring more viscous fluids.
This paper discusses in detail an extensive review of the application of nanoparticle and hydrogel polymer technology to
enhance fluid – proppant performance in conditions with temperatures nearing 275°F and brine density up to 14.4ppg. This
can be achieved by developing nano-sized crystals, which colligate with VES rod-like micelles to yield a virtual viscous filter
cake that significantly curbs the fluid loss rate, thus demonstrating wall building on the porous media, rather than usual
viscosity dependant leak off control. When internal breakers are applied, VES micelle structures degrade rapidly, leaking off
VES fluid and the pseudo filter cake will then split into brine and nanoparticles, thus producing formations remains intact. To
augment its performance proppants can be encapsulated with a thin hydrogel polymer layer which will hydrate on coming in
contact with water. This layer smoothens the proppant, adsorbs the fines, and makes the proppant self-suspending. This
wonder layer is resilient to high pressure high temperature conditions and exhibits excellent characteristics which are
elucidated in this paper.
When applied, nanotechnology can reduce requirement of VES fluid volume by 60% and permeability range of VES fluid
application is extended upto 2000md. While the incorporation of self-suspending proppants (SSP) can significantly bring
down the requirement of additives and enable fracturing of challenging formations with maximum retained conductivity.
Introduction
Pumping of fluid into the well, at a greater pressure than the fracture pressure, to induce fractures is known as Hydraulic
fracturing. The main objective of the operation is to increase the productivity index of a producing well and/or the injectivity
index of an injection well. It was first used in the industry in Kansas, USA in 1947 when it was found to be more cost
effective compared to acidizing jobs (Gidley et al., 1989). Below enlisted are the fundamental steps employed in a fracturing
job:
 Pad fluids are the first stage of the fracturing ‘treatment’ which break down the formation and initiate fractures.
Sufficient depth and width of the fractures is needed to allow the proppant-laden fluids to enter in the later stages.

2. 2 SPE 171999
 The Pad fluid is pumped to create enough fracture width to accept proppant particles. Proppant is typically
comprised of size-graded, rounded and nearly spherical white sand, but may also be man-made particles.
 Proppant particles are mixed into additional fracturing fluid and the resulting slurry is pumped into the reservoir,
propping open the created fracture(s) so that they will remain open and permeable after pump pressure is relieved.
 At the end of placing the slurry, a tubular volume of clean “Flush” fluid is pumped to clear tubulars of proppant and
the pumps are shut down.
 Well pressure is then bled off to allow the fracture(s) to close on the proppant.
 The final step in a fracturing treatment is to recover the injected fluid by flowing or lifting the well.
Hydraulic fracturing consists of initially injecting a pad fluid to induce fractures in the formation, followed with a propping
agent to keep the induced fractures open once the operation ceases. Varying fluids are employed in fracture initiation and
later for proppant/sand transport. The fluids used have undergone a series of developments with better understanding of the
downhole environment and also the advancements in the field of chemical engineering. Initially, fluids based on a
hydrocarbon phase (kerosene, crude oil or gasoline) were employed. Fatty acids were later used to improve the viscosity of
the oil-based fluids for fracture initiation. The use of water-based fluids such as guar-based polymers emerged as a result of
increasing understanding of the rock-oil interactions. To facilitate the transport of proppant, guar is used as an agent to
increase viscosity. In order to generate more viscosity and minimize leakoff, crosslinked guar-based fluids were introduced.
(Dysart et al., 1969). Breakers are generally used alongside polymer-based fluids to improve retained fracture conductivity
and minimize left-over residue associated damage. (Small et al., 1991).
Synthetic polyacrylamide polymers have been reportedly used in recent years as hydraulic fracturing fluids for high
temperature applications upto 232℃. (Holtsclaw and Funkhouser, 2010).To reduce damage caused by polymer based fluids,
viscoelastic surfactants were introduced. (Small et al., 1991) but were susceptible to high temperature degradation at more
than 115℃.unless used in extremely high concentration, other associated problems being leak-off control and formation
damage. Polymer -based fluids are still the most commonly used type of fracturing fluids. This is due to their versatile
properties and the extensive industry experience associated with their use.
Most of the promising recent discoveries are Tight Oil reservoirs located in deepwater/ultra deepwater High Pressure High
Temperature (HPHT) conditions, so to transform these prospects into projects this paper elucidates a stimulation solution by
integration of two contemporary technologies, namely nanocrystal added viscoelastic surfactants and hydrogel based self-
suspending proppants (SSP).
Nanoparticle Based Viscoelastic Surfactants
Nanoparticle technology has a great potential for a broad range of applications in the oil industry in general and stimulation
fluids in particular. It has been envisaged upon great investigation that nano-fluids have attractive properties for applications
where high temperature-high temperature conditions are encountered. This has led to concentrated research work by
companies to design new-age stimulation fluids which can be used in HPHT conditions, possessing a satisfactory viscous
nature for proppant transportation and causing minimum formation damage as a result of fluid leaf-offs. These nanoparticle
empowered stimulation fluids will hence be useful in those conditions where both cross-linked VES based fluids and polymer
based fluids were found to be having a few shortcomings.
VES based fluids were primarily used to overcome the short comings of the polymer based fluids which left a residue in the
fractures resulting in reduced permeability of the fractures (Crews et al., 2006). This was overcome by usage of VES fluids
which formed micelles. These micelles are stable upto 200℉ providing far superior rheological properties and are compatible
with a vast variety of completion fluids including𝐶𝑎𝐶𝑙1, 𝐶𝑎𝐵𝑟1, 𝐾𝐶𝑙 and crude oils causing no damage to the formation
(McElfresh et al., 2003). The problems associated with these fluids are that they are expensive and are unstable at
temperatures greater than 200℉. Also, these fluids do not form a filter cake on the formation, because the VES fluids are
based on the arrangement of low molecular weight surfactants instead of the high molecular weight polymers like guar,
resulting in greater leak offs (Crews et al., 2006). Hence, VES based fluids can be used for those formations which have low
to moderately low permeability to offset the negative impact of the high fluid loss which may get compounded in case of a
highly porous/permeable formation.
To overcome the drawbacks as presented by VES, (Crews and Huang, 2008) proposed the integration of nanoparticle
technology with VES fluids viz loading of nanoparticles to VES micelles. Huang et al., 2010 showed that the addition of the
above mentioned particles significantly improve the rheological properties. The mechanism behind the working is that with
the usage of cationic worm-like micelles with like charged nanoparticles, a micelle-nanoparticle junction gets formed which
act as physical crosslinks between micelles enhancing the viscosity and elasticity of the dilute and semi-dilute wormlike
micelles (Figure 1). The result showed increase of the surfactant micellar fluid’s zero shear rate viscosity by more than 100
times. Also, 20 to 100% lesser usage of VES was reported at higher temperature by Crews et al., 2006.

3. SPE 171999 3
Self-Suspending Proppants
They are recently introduced modified proppants by Mahoney et al. in 2014, encapsulated with a polymer coating which is
water swellable. This special layer enables proppant to resist settling thus making possible effective transportation into
fracture without the usage of high viscosity fluids. This coating is highly continuous and forms an entangled film. When it
comes in contact with water, the coating impulsively absorbs water leading to the formation of a hydrogel sphere. This
swelling process causes an increase in the volume of particle while reducing the particle density. The anchored coating not
only swells upon interaction with water but this unique activity is restricted to the surface and it doesn’t alter internal
chemistry of the proppant. This special layer turns the proppant into a suspending agent, thus decreasing the fracturing fluid
make-up intricacies.
For a hydrated SSP, the hydrogel layer extends several hundred microns as shown in the picture clicked by Mahoney et al.
his light microscope images of 50/70 SSP (Figure 2). The glowing body in the low brightness image is the sand particle
while the arrows in the high brightness image show the extent of hydration layer around the sand. Moreover to validate the
fact that the thickness of the dry coating layer is very small compared to the hydrated layer, Mahoney et al. took a Scanning
Electron Microscope (SEM) image (Figure 3) of unchanged sand particle and a dry coated sand of the same size. This SEM
image shows that the layer is only around 1 – 3 microns thick sand particle is more rounded-smoothened and there is
significant reduction is fines. Reduction in fines is due to adsorption by polymer coating, thus improves handling and reduces
abrasion.
The dynamic nature of SSP technology encompasses its application to a wide variety of proppants viz. ceramic, sand, or resin
coated sand. Due to the self-suspending nature it when enters the fractures proppants push eacth other to travels deep into
horizontal and vertical fractures creating longer propped fractures. The polymer coating can be modelled to automatically
desorb and degrade when it interacts with formation fluids at reservoir temperature.
Advantages of Proposed Stimulation Solution
The most important components of a successful stimulation job are fluid and proppant. As elucidated earlier it is a complex
process and the HPHT conditions (Figure 4) even make it more difficult to design and place the frac. Thus, to facilitate
economic recovery of hydrocarbons from these challenging scenarios use of nanocrystal added viscoelastic surfactant as
fracturing fluid and hydrogel layer for proppant is recommended. Following discussed are the salient features of the proposed
solution:
1) Fluid Viscosity: Due to the self-suspending nature of SSP, viscosity requirements of fracturing fluids are minimal.
Moreover in an experiment conducted by Gurluk et al. in 2013, where amidoamine oxide surfactant in a 14.2 ppg
brine solution of CaCl2 and CaBr2 with approximately 30nm MgO, 30nm ZnO and without nanocrystals, effectively
reflects the increased stability of nanocrystals added viscoelastic fluids in maintaining viscosity over time at 275°F
and 10 s-1
shear rate. (Figure 5)
2) Friction Reduction: In normal operation friction reducing agents are added to the fluid, but the polymer which gets
desorbed from SSP provides friction reduction benefits. The results of an experiment conducted by Mahoney et al.
shows 65% friction reduction when 1 ppg of SSP was added to 2% KCl (Figure 6), similarly 69% reduction in
friction for 1 ppg SSP in tap water while for 1 gpt friction reducer added to tap water 68.8% reduction was observed.
3) Proppant Suspension: The unique ability of nanoparticles to associate elongated surfactant micelles together to
form a reinforced network which enhances the suspension capability of VES as shown in Figure 1 by Huang and
Crews in 2008. Also the presence of hydrated layer of SSP will augment the suspension capacity by reducing the
overall density of particle and increasing the drag force acting on the proppant (Figure 7).
4) Brine Tolerance: In an experiment by Gurluk et al. when at 275°F concentration CaBr2 (brine) is reduced from
14.2 ppg to 13 ppg, the nanoparticle added VES maintains its viscosity at 200 cp, while the viscosity of VES without
nanoparticle drops to 100 cp. SSP also reflects good brine handling characteristics as the swollen layer acts as an
inert layer.
5) Fluid Loss Control: Due to formation of a pseudo filter cake on the face of fractures by nanoparticle cross-linked
VES micelles, fluid loss is controlled. Huang and Crews in their experiment (Figure 8) showed how with increasing
ppg of nanoparticles at high temperatures fluid loss can be controlled.
6) Regained Conductivity: Due to the small size of nanoparticles during flow-back they cause no damage to the
permeability of formation while the presence of internal breakers inside the VES micelles causes complete
dissolution of pseudo filter cake, leaving no residue after the stimulation job (Figure 9). Similarly is the case for

4. 4 SPE 171999
SSP where almost same conductivity was recorded in the proppant pack after the hydrogel layer breaks off fully in
presence of oxidative internal breakers (magnesium oxide) at reservoir temperature (250°F) and flows back with the
fluid.
Conclusion
The use of self-suspending proppants (SSP) and nanocrystals in viscoelastic surfactants (VES) will offer definite benefits for
inducing propped fractures in high pressure high temperature (HPHT) conditions in comparison to conventional fracturing
practices.
 The chemistry of the hydrogel polymer layer and nanocrystals in VES were found to complement each other, thus
enhancing the applicability to challenging environments and increased performance of the combination.
 The self-suspending nature of SSP reduces the viscosity requirement in fracturing fluid and the nanocrystals were
able to increase the viscosity of VES by ten times, maintaining the same at HPHT conditions.
 The friction reducing characteristic of SSP together with reduced requirement of fluid viscosity will drastically curb
the required pumping power.
 Due to the close organization of internal breaker in nanocrystal-VES pseudo filter cake and mangnesium oxide
(nanocrystal in VES) acting as internal breaker for SSP, the system delivers great post-fracture conductivity.
 Both the components have exhibit improved brine tolerance thus increasing their capability to induce deeper
propped fractures without getting contaminated with formation fluids.
 Better fines handling, smoother proppants, low fluid leak off due to pseudo filter cake formation were some of the
other notable features of the combination.
 Due to high level of integration between both the proposed technologies the amount of additives and pumping
capacity required are significantly reduced.
References
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Hydraulic Fracturing, 12. Chap. 1, 1-38. Richardson, Texas: Monograph Series, SPE
2. Dysart, G.R., Spencer, A.L., and Anderson, A.L. 1969. Blast-fracturing. Paper API 60-068 Drilling and Production
Practice, 1969; Harris, P.C. 1993. Chemistry and Rheology of Borate-Crosslinked Fluids at Temperatures to 300°F.
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for Fluid-Loss Control with Internal Breaking. Paper presented at the SPE International Symposium and Exhibiton
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SPE 107728. European Formation Damage Conference, 30 May-1 June.

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11. DeBruijn, G. Skeates, C. Greenaway, R. Harrison, D. Parris, M. James, S. Muller, F. Ray, S. Riding, M. Temple, L.
and Wutherich, K. 2008. High-Pressure, High-Temperature Technologies, Schlumberger Oilfield Review.
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Figure 1: Illustration of a strong network built by nanoparticles associating with VES micelles. (Huang and Crews, 2018)
Figure 2: Light microscope images of 40/70 SSP grain at low and high brightness. (Mahoney et al., 2013)

6. 6 SPE 171999
Figure 3: SEM images of 30/50 proppant sand (left) and 30/50 coated SSP (right) (Mahoney et al., 2013)
Figure 4: HPHT Classification System (DeBruijn et al., 2008)
Figure 5: When the surfactant concentration increases from 2 to 4 vol% VES, the viscosity of the fluid increases. (Gurluk et al., 2013)

7. SPE 171999 7
Figure 6: Friction reducing characteristics of SSP. (Mahoney et al., 2013)
Figure 7: A) Vials of 1.5 ppg 30/50 white sand (left) and two samples of 1.5 ppg 30/50 SSP (middle and right). (Mahoney et al., 2013)
B) Proppant-suspension-test samples after 90 minutes at 80°F. The sample on the left is VES fluid with 0.077% bw nanoparticles,
and sample on the right is VES fluid without nanoparticles. (Huang and Crews, 2008)

8. 8 SPE 171999
Figure 8: Fluid-loss tests to compare VES fluids with and without nanoparticles. Tests with nanoparticles developed a pseudofilter
cake that reduced rate of VES-fluid leakoff substantially. (Huang and Crews, 2008)
Figure 9: Internal breaker dramatically reduces VES fluid viscosity at 250°F. (Huang and Crews, 2008)