Journal of Petroleum Science and Engineering 184 (2020) 106523
Contents lists available at ScienceDirect
Journal of Petroleum Science and Engineering
journal homepage: http://www.elsevier.com/locate/petrol
Comprehensive experimental study of proppant transport in an
inclined fracture
Troy Chun a, Yanchao Li b, Kan Wu a, *
a
b
Department of Petroleum Engineering, Texas A&M University, College Station, TX, USA
CNPC Chuanqing Drilling Engineering Co. Ltd, Chengdu, China
A R T I C L E I N F O
A B S T R A C T
Keywords:
Proppant transport
Slickwater
Inclined fracture
Hydraulic fracture
The application of slickwater fracturing technology along with horizontal drilling has revolutionized oil and gas
energy industry. Solid particles, i.e. proppant, are mixed with slickwater and injected into the formation to keep
fractures opened after fracturing. Many researchers have studied the proppant transport and distribution in
vertical fractures. However, in unconventional reservoirs with multiple bedding layers and preexisting natural
fractures, hydraulically induced fractures with inclined angles are often generated. Thus, proppant transport in
various angles of fracture geometry is necessary to study further. In this study, multiple case studies including
fracture inclination angle, proppant size, and injection point location were performed to experimentally quantify
proppant delivery mechanism in an inclined fracture. Laboratory parameters were scaled down from field
conditions to successfully capture proppant transport mechanism without any significant boundary effect. Sand
slurry was pumped into a fracture channel and proppant placement was recorded at various conditions. The
effect of individual parameter was scientifically analyzed at predetermined condition to quantify the proppant
transport trend within an inclined fracture.
Friction due to wall roughness and different effective vertical gravitational forces completely change proppant
transport behaviors in inclined plane. Frictional force acts stronger, as the fracture plane angle becomes closer to
the horizontal plane. Strong wall friction effect creates a thin suspension area rather than settling and forming
compact dune. Some proppants are invested for the suspension zone instead of dune area. This leads to greater
proppant coverage area, yet smaller dune area. Suspended zone is the most differentiating feature compared to
vertical fractures. There is almost no suspended zone observed in the vertical fractures, yet suspended zone is
well observed and prevalent in inclined fractures. Fine mesh sized proppants travel farther due to low settling
velocity. It therefore forms a well distributed sand pack. Fine particles are heavily influenced by the flow,
therefore it follows the streamline of the incoming flow. They also experience strong wall friction. Thus sus­
pension zone and total coverage area increase with smaller proppant size. In addition, the difference between
having a single inlet point at various depth compared to having several opened inlet points provides an insight
while operating in field environment. The inlet location determines the shape of the sandpack, especially near
the wellbore. Lower injection point pushes the sandpack farther, yet this poses a potential wellbore closure or
collapse.
1. Introduction
Hydraulic fracturing (HF) technology has become a dominant
mechanism to extract oil and gas from unconventional resources.
Coupling with horizontal drilling allowed reaching hydrocarbons trap­
ped in the unconventional shale reservoirs, previously uneconomical
ones. During hydraulic fracturing, highly pressurized water is injected
into the wellbore. Then complex fracture geometry, often connecting
with natural fractures, is generated. Once fractures are opened, prop­
pants are injected to keep the fractures open by withstanding high
closure stress around the fractures. Proppant transport within these
fractures plays a key role to maintain fractures open and enhance
reservoir conductivity (Zhang et al., 2013; Huang et al., 2018a,b; Wang
et al., 2018; Barree et al., 2019).
The hydraulic fracturing propagates in a direction where it has the
least resisting stress acting on it. Therefore, it often propagates in a
* Corresponding author.
E-mail address: kan.wu@tamu.edu (K. Wu).
https://doi.org/10.1016/j.petrol.2019.106523
Received 26 March 2019; Received in revised form 27 August 2019; Accepted 23 September 2019
Available online 26 September 2019
0920-4105/© 2019 Elsevier B.V. All rights reserved.
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
vertical direction and forms vertical fractures (Daneshy, 2019; Weijers
et al., 2019). Yet once it reaches to a bedding plane, it changes propa­
gating directions and continue to propagate to existing bedding layers
(Yushi et al., 2016; Tang et al., 2018; Agrawal et al., 2019). This bedding
plane tends to be in horizontal direction close to perpendicular to
propagating direction. In addition, Gale et al. (2014) presented a
comprehensive natural fractures study and they found the common
occurrence of bed-parallel and low angle natural fractures in shale.
Connection with these natural fractures creates additional flow paths
after hydraulic fracturing. Hydraulic fractures propagating at an angle
often occur in multiple fracture propagation in horizontal wells (Kumar
and Ghassemi, 2015). Fracture propagation angle becomes steeper as an
effective fracture length propagates farther. Thus, it is essential to
investigate proppant transport mechanisms in inclined planes.
Much experimental work of proppant transport has been done. Kern
et al. (1959) was one of the earliest experiments to understand proppant
transport mechanisms in slurry mixture. Barree and Conway (1994)
studied settling during transport and its distribution trend. Liu and
Sharma (2005) investigated the impact of fracture width and fluid
rheology including viscosity in a narrow channel. Palisch et al. (2010)
focused on slickwater treatment system, whose typical viscosity is less
than 10 cp.
In recent years, Sahai et al. (2014) showed development of sand bed
and equilibrium height as well as proppant distribution in the secondary
fractures. Alotaibi and Miskimins (2015) and Alotaibi and Miskimins
(2019) conducted numerous experiments for proppant transport into the
secondary and tertiary fractures. They successfully demonstrated suc­
cessive steps of sand dune development. Wen et al. (2016) investigated
proppant transferability at various fracture geometry and fluid condi­
tions. Tong and Mohanty (2016) built a unit in which various angles of
secondary fracture can be attached. They performed a sensitivity anal­
ysis having several parameters such as bypass angle, shear rate, and sand
size. After that, they employed various rheological properties with
different foam percentage in the fluid, thus delivered proppant farther
and more into the secondary fractures (Tong and Mohanty, 2017; Tong
et al., 2017; Tong et al., 2018a; b). Kadhim et al. (2017) tested the
impact of fracture width ratio, wall roughness, and leak off to proppant
distribution by adopting Equilibrium Dune Level (EDL), Equilibrium
Dune Length (EDX) and Fracture Pore Volume (FPV). Huang et al.
(2018a,b) tested polymer concentration, injection rate, and proppant
�ndez et al. (2019) investigated
type in rough fracture conditions. Ferna
the effect of vorticity and turbulence in proppant dune placement and
formation.
Most proppant transport mechanism work focuses on vertical frac­
tures and its secondary vertical fractures. To our best knowledge, macro
scale inclined and horizontal fracture geometry has not been studied
experimentally. Shrivastava and Sharma (2018) worked on proppant
transport simulation in multiple fracture networks including horizontal
bedding plane. Kou et al. (2018) and Kou et al. (2019) simulated the
effect of inclined plane using computational fluid dynamics (CFD) and
Discrete Element Method (DEM). They conducted proppant delivery
mechanism in several primary and secondary fractures in field scale.
The effect of inclined fracture plane was conducted in small scale.
Roy et al. (2016) tested proppant settling on Marcelleus shale sample
inside the fracture cell. They investigated the effect of concentration and
fracture inclination angle. Xu and Pyrak-Nolte (2018) performed
experimental work to investigate the effect of fluid properties in terms of
precipitation and deposition within the inclined fracture. They studied
with miscible fluids to visually compare the buoyancy in inclined frac­
ture conditions. However, they analyzed fluid properties without having
proppant particles in the experiments. Ba Geri et al. (2018) and Ba Geri
et al. (2019) conducted multiple case studies on proppant transport
behaviors. They compared the inclined angle, aperture size, the number
of openings, shear rate and proppant size to measure proppant delivery
efficiency. They analyzed EDL and fracture propped area (FPA) values to
perform their sensitivity analysis in various cases. Yet the length of the
fracture channel was too short to avoid boundary effect in some cases.
This paper presents slickwater proppant transport mechanism in
inclined and horizontal planes. Several factors, such as fracture incli­
nation angle, proppant size, and inlet locations, have been tested
experimentally. Various combinations of parameters were conducted in
order to study the normalized coverage area within the fracture channel.
The detail experimental apparatus is described in the following section.
2. Laboratory experiments
The experimental setup in this paper was designed to safely deliver
sand slurry to clear fracture channel. It is designed to accommodate
various fracture angles and operating conditions in slickwater treat­
ment. Regular tap water was used for slickwater fluid. Northern white
sand, most commonly used sand proppant type for slickwater fracturing,
was introduced for proppant materials.
2.1. Fracture assembly and experiment setup
The slot channel was made of transparent plexiglass panels. Its di­
mensions were 4 feet long, 1 foot high, and 0.3 inches wide, shown in
Fig. 1. It was tapped and glued with epoxy to ensure robust assembly.
The screws were bolted every 6 inches to instantly visualize proppant
deliverability. The channel accounts for half wing of one of four perfo­
ration clusters. Therefore injection rate here is one eighth of a total in­
jection rate. In other words, the overall injection rate would be eight
times that of injection rate tested during the experiment. Compared with
the field scale, we scaled down the experiment setup by 50, yet the width
stayed at 0.3 inches to study proppant mixture movement within a
narrow fracture condition. Since injection velocity determines the
proppant placement and the shape of a proppant dune, the injection rate
was designed to have the same field surface velocity along the fracture
surface. The length and height ratio was kept at 4 to 1 and this mini­
mized the boundary effect. Proppant concentration for slickwater
treatment often stays in between 1 and 2 ppg. The most popular con­
centration was approximately 1.5 ppg (Schein, 2005; Alotaibi and
Miskimins, 2019; Vidma et al., 2019). Other operating parameters are
also presented in Table 1.
These lab and field parameters resemble slickwater fracturing
operating conditions. There were three 0.500 I.D. injection holes on one
side and they were three inches apart from one another. Having multiple
inlet points permitted even distribution along the injection plane and
Fig. 1. Schematic of the dimensions of a fracture cell used in the experimental
study. The dimensions are 4 ft long, 1 ft high, and 0.3 in wide and have three
inlet points and two outlet points.
2
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
flow meter and a valve on the pump outlet side together controlled the
injection rate. The additional pressure built by closing the valve enabled
controlling the injection rate. Having outlets on top of the channel
helped releasing the air pressure present in the assembly without dis­
rupting streamline in the fracture. Small amount of proppants escaped
on the outlet side and they were collected in the retention tank. The
work lights provided more vivid and obvious observation while
recording the experiment. Everything was recorded with a camera for
post image analysis. Figs. 3 and 4 display the layout of the laboratory
and its operating steps.
Base case was established for the sensitivity analysis. Then other test
were followed depending on the variables of interest. The injection rate
of 6 gpm and proppant concentration of 1.5 ppg were constantly used for
all the case studies, since they are most commonly used values respec­
tively. Then several inclination angles, proppant sizes, and inlet loca­
tions were conducted to observe their impact on the proppant placement
in the fracture.
ImageJ, an image analysis software was used to accurately measure
the dune area and suspended zone. The image was converted into grey
scale and its pixel density was used to analyze the volume fraction at a
given space. Threshold function successfully calculated the area of dune
and suspended zone.
Table 1
Laboratory and field operating conditions scaling.
Lab
Field
5–10 bpm
1 ft
1.363 m /
hour
0.3048 m
10–100 ft
0.795–1.59 m3/
min
3.05–30.48 m
0.3 in
0.00762 m
0.1–0.5 in
0.00254–0.0127 m
4 ft
1.219 m
100–1000 ft
30.48–304.8 m
1.5 ppa
1.5 ppa
0.5–3 ppa
0.5–3 ppa
1 cp
2.55 g/
cm3
20/40
Mesh
size
30/50
Mesh
size
40/70
Mesh
size
0.001 pa�s
2.55 g/cm3
1 -100 cp
1–2.65 g/
cm3
20/40–200
0.001–0.1 pa�s
1–2.65 g/cm3
Injection rate, Q
6 gpm
Fracture height,
H
Fracture width,
H
Fracture length,
L
Proppant
concentration,
C
Fluid viscosity, μf
Proppant
density, ρp
Proppant
Diameter, D
3
0.630 mm
0.415 mm
0.315 mm
Mesh size
3. Results and discussion
also allowed single injection point testing availability. On the outlet
side, one hole was placed on the side and the other one was placed on the
top face. The side hole let water escape from the system, leaving prop­
pant behind in the system. The other hole on the top acted as a pressure
relief point. The channel required an escape point where entrapped air
could exit the slot channel, otherwise creating extensive amount of
pressure built up within the system. This could lead to a potential safety
hazard including crack and explosion. Additional wood frame was built
to provide sufficient support to tilt the channel at predetermined angle
at every 30� increments, starting from 0� (a horizontal fracture case) to
90� (a vertical fracture case). Fig. 2 shows the different inclined fracture
angles applied for the experiment.
In this section, the proppant transport experimental results were
presented and discussed. Base case was chosen where its condition most
resembled the field conditions. Fracture incline angles, proppant parti­
cle sizes, and inlet locations were scientifically analyzed in order to
investigate the effects on proppant placement. As proppants entered into
the fracture channel, they formed a densely populated and immobile
dune area. Then incoming proppants created loosely packed and thin
layer of suspended zone. Suspended zone followed the streamline
initially and settled slowly. The development of dune area, suspended
zone, and total coverage area was investigated, since they directly relate
to conductivity within the fracture. An image analysis software was used
to identify and calculate sizes of dune and suspension areas.
2.2. Operating procedure
3.1. Base case
The channel was water-filled environment prior to sand slurry in­
jection. Once the channel was filled with water, the outlet valves were
closed to prevent water from escaping. Predetermined mass of sand and
water was introduced and mixed together in a bucket. A tank mixer was
used to agitate the sand slurry homogeneously in the bucket. This
allowed homogeneous sand/water concentration in the bucket and
provided constant concentration into the fracture channel throughout
the flow test. The progressive cavity pump was used to deliver sand
slurry to the fracture channel. The progressive cavity pump was chosen
because it successfully delivered the sand slurry with no pulsation. The
The base case was established first in order to accurately compare
subsequent parameters in the later experiments. The operating param­
eters for the base case were shown in Table 2. The bold numbers in the
table indicate the variables of interest. These numbers were tested
individually to study its effect with respect to the base case. 30� from the
ground was designated for the base case in order to investigate the effect
of other parameters in a tilted environment. 30/50 mesh size was chosen
for the proppant size because they are commonly used in slickwater
treatment. This sand size exhibited enough buoyancy to show sus­
pending trend during the experiment. In addition, base case has three
inlet points as discussed above. They provided uniform distribution
along the inlet wall.
For base case with 30� inclined angle, two phases of proppant
transport were observed. As shown in Fig. 5, the first 10, 20 s is depo­
sition process. Proppant mostly piled up instantly instead of travelling in
the lateral direction. Proppants continued to deposit vertically until the
dune reached an equilibrium height, where it cannot accumulate
anymore. The equilibrium height determined after this phase continued
to be consistent until the end of the experiment. This left a narrow washout zone at the top where the incoming flow carved the nearby dune and
delivered the proppant to the other side of the dune. A key point here
was that the apparent slurry velocity at this point was noticeably faster
than injecting velocity. The dune area was nearly impermeable, there­
fore it allowed a very small flow pathway in the channel. Since the
available flow path is restricted for the same amount of fluid compared
to having three inlet holes together, apparent slurry velocity increased
Fig. 2. Geometry of inclined fracture planes (30� increment) – brown (90� ,
vertical), blue (60� ), green (30� ), white (0� , horizontal). (For interpretation of
the references to colour in this figure legend, the reader is referred to the Web
version of this article.)
3
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
Fig. 3. Schematic design for experimental setup in the laboratory.
Fig. 4. Experimental setup in the laboratory.
rolling until 75% of equilibrium dune level (EDL). As opposed to pre­
vious studies in a vertical fracture, proppant transport in an inclined
fracture exhibits much greater suspension capability, especially in the
later stage of pumping.
Strong wall friction dominated and completely changed transport
and deposition trend. Since wall friction heavily dictated transport and
deposition mechanisms especially at 30� fracture plane, the slurry
started to have more suspended area than direct settling dune area. This
is due to greater frictional force exerted when the fracture is flatter. At
this stage, gravitational force is not strong enough to overcome wall
friction. Then proppants were practically attached to the wall and
became stagnant. They covered widespread and thin areas within the
fracture. Yet the settling process was much slower than vertical fracture
case due to greater friction along the wall. This provided greater sus­
pended area shown in Fig. 6. Fig. 6 displays the difference between the
dune area and suspended zone. The dune area is where proppants are so
densely populated that the proppant pack becomes immobile and no
apparent seepage is occurred. The suspended zone is where proppants
are loosely occupied and they continue to settle. In inclined fracture
Table 2
Experimental parameters used for different scenarios.
Parameters
Base
case
Inclined angle
(cases 1, 2, 3)
Proppant size
(cases 4,5)
Inlet position
(cases 6, 7, 8)
Inclined
angle,
ϴ (� )
Proppant
Diameter,
D (mesh
size)
Number of
inlets
30
90, 60, 0
30
30
30/50
30/50
20/40, 40/70
30/50
3
3
3
1
substantially.
Alotaibi and Miskimins (2015) performed a comprehensive study on
proppant transport in complex fracture geometry and described multiple
stages of dune development in vertical fractures. They found that dune
development in vertical fracture was mostly driven by settling and
4
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
Fig. 5. Proppant distribution and settling profile of base case with 30� inclined fracture angle, 30/50 mesh, and three inlets at every 10 s.
Fig. 6. Suspended zone and dune area in fracture slot (base case with 30� inclined fracture angle and 30/50 mesh at 30 s).
environment, small amount of proppants was invested to occupy a large
area and this allowed a much larger effective coverage area.
demonstrates forces acting on a particle in an inclined plane condition.
The frictional force equation shown in Equation (1) confirms that the
frictional force dictates more as the fracture plane becomes closure to
horizontal plane (0� ). Also proppant could not travel as far as they did at
60� and 90� .
3.2. Effect of inclined plane angles
Ff ¼ μN ¼ μ�mgcosθ
Hydraulic fractures connect with preexisting natural fractures when
they are propped. Those fractures often exist in non-vertical angles.
Proppant transport at a non-vertical plane behaved differently since the
gravity acts in another direction at a different degree. Fig. 7
(1)
where Ff is the frictional force, μ is the coefficient of friction in between
the two surfaces, N is the normal force, m is the mass of a particle, g is the
5
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
cases. Also the normalized suspended zone is larger in 60� than 90� and
the normalized dune area is smaller in 60� than 90� . This corresponds
with the frictional force along the wall presented above in Equation (1).
Fig. 14 shows that the significant difference in normalized total area
occupied by proppants is driven by the difference in suspended zone.
3.3. Effect of proppant sizes
In slickwater treatment, it is extremely challenging to deliver parti­
cles farther into the fracture. Proppants settle instantly because of low
viscous carrying fluid. Reducing settling velocity without changing the
fracturing fluid composition is the key to effective slickwater operation.
Proppant sizes have a great influence on particle transport. Buoyancy
affects more with the smaller particles. Proppant settling velocity is
described in below equation.
Fig. 7. Forces acting on particle in inclined condition.
gravitational force, θ is the inclination angle.
The inclination angle completely changes the deposition trend and
dune development profile within the channel. Proppant travels farther
and form a long proppant dune as shown in Fig. 8. Therefore, it forms the
most widespread proppant dune than any other inclination angles. As
shown in Fig. 9, at 60� inclination angle, proppants settle much faster
and forms sand dune closer to the injection points. This eventually leads
to faster vertical buildup rate. Horizontal expansion of proppant dune
was driven by rolling rather than direct settling from the incoming flow.
Fig. 10 demonstrates the proppant transport at 0� inclination angle,
horizontal fracture. Since proppants do not have much room for gravi­
tational settling in a horizontal fracture, suspension is noticeably limited
compared to other cases. Also, the frictional force is the greatest in
horizontal plane. This promotes a piston-like dune expansion during the
transport process.
Fig. 11 displays the effect of fracture angle on the normalized dune
length. As inclination angle decreases, proppants’ longitudinal delivery
capacity becomes weaker because of greater wall friction and induced
slow settling. It is interesting to see that proppants travel 0.11 longer
with 30� increment. This Fig. 12 presents the normalized dune area
development process at different fracture inclination angle. This graph
shows that the inclination angle has little impact on the dune area. Only
the shape of a dune becomes different depending on the inclination
angle throughout the process. The normalized dune area at 30� is the
greatest at first, then becomes the smallest later. This is because prop­
pants are invested in suspension after 18s shown in Fig. 13. After 18s,
suspension takes place vibrantly in 30� than other two inclined plane
Vs ¼
gðρp
ρf Þdp 2
18μf
(2)
where Vs is the settling velocity, g is the gravitational force, ρp is the
density of a particle and ρf is the density of the fluid, dp is the diameter of
a particle, μf is the viscosity of the fluid. The squared particle diameter
term in the equation show its crucial impact. The smaller the particle
size is, the slower the settling takes place. Therefore, small particles
would tend to suspend more and travel farther. The results shown in
Figs. 15 and 16 confirm that 40/70 mesh formed the greatest suspended
area.
The effect of particle sizes in settling velocity is displayed in Table 3.
Various types of commercially used proppants were tested for settling
velocity tests. Their mean particle size and specific gravity is given in the
table. The mean diameter of 20/40 mesh proppant is greater than that of
40/70 mesh. Thus, according to Stoke’s settling velocity equation,
settling velocity for 20/40 mesh particles should be four times greater
than that of 40/70 mesh particles.
An interesting observation is that the dune area is approximately the
same regardless of the proppant size shown in Fig. 17. The smaller
particles form the dune farther away from the injection points displayed
in Figs. 15 and 16. Two mechanisms allow this to happen. Firstly, fine
proppants travel farther and settle slower than more coarse particles.
Therefore, their deposition and sand packing initiates farther from the
injection points. Secondly, fine proppants are more prone to be washed
out from incoming flow. It requires substantially less force to transport
40/70 mesh proppants than 20/40 mesh proppants due to buoyancy.
Fig. 8. Proppant distribution development of case 1 with 90� inclination angle, vertical fracture. (a) profile at 10 s (b) profile at 30 s.
6
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
Fig. 9. Proppant distribution development of case 2 with 60� inclination angle. (a) profile at 10 s (b) profile at 30 s.
Fig. 10. Proppant distribution development of case 3 with 0� inclination angle, horizontal bedding plane. (a) profile at 10 s (b) profile at 30 s.
Fig. 11. Effect of inclined plane angle for normalized dune length for 30/50
mesh and three inlets.
Fig. 12. Effect of inclined plane angle for dune area for 30/50 mesh and
three inlets.
The incoming flow pushes out existing suspending fine proppants.
Figs. 18 and 19 indicate that the difference in total area arises from the
suspended zone. Smaller particles would occupy more suspended zone
because their settling is slower than the large ones and cling to the wall
more. Common use of fine mesh proppants such as 40/70 and 100 mesh
sizes in the field should promote larger and farther proppant placement.
7
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
contact area between wellbore and a fracture, single inlet can be
assumed for each fracture. However, its relative position to the fracture
requires further studies. Each of top, middle, and bottom hole is opened
to analyze the effect of injection position on proppant placement and
dune profile in an inclined fracture. Top, middle and bottom holes are
0.25, 0.5, and 0.75 unit length away from the top, shown in Fig. 1.
The injection point location and its induced turbulent eddy deter­
mine the proppant dune profile. The eddies were created near the in­
jection point. Figs. 20–22 show proppant transport profile when the
injection point is located at the top, middle, and bottom respectively.
The eddy is created at the top for the case 6 shown in Fig. 20; at the
middle for the case 7 shown in Fig. 21; at the bottom for the case 7
shown in Fig. 22.
The most differentiating observations from single inlet cases to three
inlet cases are its landing point and turbulence washout. Fig. 20 dem­
onstrates dune formation process within the fracture channel and in­
dicates the areas where various transport mechanisms occur. Unlike
three injection point cases, the landing zone (1 in Fig. 20) was formed
farther into the fracture. This is due to faster injection velocity compared
to three injection points cases. This area is where the velocity of the
incoming slurry becomes zero, so that proppants lose their moving ca­
pacity and form an immobile sand dune. The washout zone (2 in Fig. 20)
is the area where turbulent eddy forms. No settling occurs since the
turbulent flow constantly agitates sand slurry and prevent from settling.
This washout zone is more obvious and vibrant compared to three in­
jection points cases. Turbulent kinetic energy is so large that it can
�n­
overcome wall friction. This corresponds with the results from Ferna
dez et al. (2019).
An inlet position determines the dune height near the wellbore. Since
dune placement and formation is mostly driven by settling. If an inlet is
opened low end of a fracture, little proppants can deposit above the
incoming flow level. At 30 s in Figs. 20–22, there is no proppant dune is
formed above the inlet point. This is critical in hydraulic fracturing
operation because proppants keep the fracture open. Empty space near
the wellbore shown in Fig. 22 poses low permeability and potential
closure issue.
Fig. 13. Effect of inclined plane angle for suspended zone for 30/50 mesh and
three inlets.
Fig. 14. Effect of inclined plane angle for total area for 30/50 mesh and
three inlets.
40/70 mesh proppants followed the streamline and travelled longer and
also occupied larger area despite strong wall friction. Additional CFD
modeling work would provide further clarification to the experimental
work established here.
4. Conclusion
3.4. Effect of inlet position
This paper highlights the proppant transport in an inclined plane
during slickwater fracturing. Three different factors, inclined fracture
plane angles, proppant sizes, and inlet positions, were scientifically
analyzed. Proppant transport and its development process were
The horizontal drilling and slickwater fracturing create a series of
fracture planes along the horizontal wells. Fracturing fluid including
proppants would travel through the injection point. Due to the limited
Fig. 15. Proppant distribution development of case 4 with 20/40 mesh at 30� inclination angle. (a) profile at 10 s (b) profile at 30 s.
8
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
Fig. 16. Proppant distribution development of case 5 with 40/70 mesh at 30� inclination angle. (a) profile at 10 s (b) profile at 30 s.
Table 3
Settling velocity for different particle sizes (From Schein, 2005).
Proppant Type
Bauxite
White Sand
Resin Coated
Sand
ULW-125
Specific
Gravity
Settling Velocity (ft/min)
20/40 (0.0248
in.)
40/70 (0.0124
in.)
Ratio
3.65
2.65
2.55
23.2
16.6
15.9
6
4.4
4.2
3.87
3.77
3.79
1.25
4.3
1.2
3.58
Fig. 18. Effect of particle size for suspended zone for 30� inclination angle and
three inlets.
Fig. 17. Effect of particle size for dune area for 30� inclination angle and
three inlets.
successfully captured, then image analysis tool was utilized to accu­
rately measure dune, suspension, and total areas in the fracture.
Experimental work provided the following keys:
Fig. 19. Effect of particle size for total area for 30� inclination angle and
three inlets.
1. In an inclined fracture, proppants experience a greater frictional
force along the wall. Normalized dune length develops slower, yet
dune buildup in a vertical direction is faster.
2. Suspension is more dominant with an inclined fracture due to strong
adherence with the fracture wall. Thus, normalized suspended zone
and the total coverage area are greater at a flatter plane.
3. Suspension zone is greater with smaller proppant size. Smaller par­
ticles settle much slower and travel farther into the fracture because
of wash out and buoyant force acting on the particles. This leads to a
greater suspension zone and total coverage during and after pumping
frac fluid.
4. In single inlet point cases, landing zone is formed at the same spot
regardless of inlet position. This is because landing zone is where
incoming proppants lose their kinetic energy and velocity. Thus, the
initial immobile sand bed forms at that position.
5. Locations of single point injection determine the proppant distribu­
tion profile, especially near wellbore region. A wash-out zone pre­
vents proppant bed having a higher dune height than the inlet
9
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
Fig. 20. Proppant distribution development of case 6 with a single point injection (top). 30/50 mesh at 30� inclination angle. (a) profile at 10 s (b) profile at 30 s (1)
landing zone and (2) turbulence washout zone.
Fig. 21. Proppant distribution development of case 7 with a single point injection (middle). 30/50 mesh at 30� inclination angle. (a) profile at 10 s (b) profile at 30 s.
Fig. 22. Proppant distribution development of case 8 with a single point injection (bottom). 30/50 mesh at 30� inclination angle. (a) profile at 10 s (b) profile at 30 s.
10
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
position level. Little proppants settle above the inlet position. Top
inlet position forms a high dune height and low inlet position forms a
low dune height. Low dune height near the wellbore may cause a
potential well collapse.
Acknowledgement
The authors would like thank Carbo for providing proppants used
during this experimental study.
Nomenclature
f
p
ρ
Ff
μ
N
m
θ
μf
dp
Vs
g
Q
C
fluid
particle
density, g/cm3
frictional force, N
coefficient of friction
normal force, N
mass, kg
inclination angle, �
viscosity of fluid, Pa∙s
proppant diameter, m
settling velocity, m/s
gravity, m/s2
Injection rate, GPM
particle concentration
Appendix A. Supplementary data
Supplementary data to this article can be found online at https://doi.org/10.1016/j.petrol.2019.106523.
References
Kou, R., Moridis, G., Blasingame, T., 2019. Bridging Criteria and Distribution Correlation
for Proppant Transport in Primary and Secondary Fracture. Society of Petroleum
Engineers. https://doi.org/10.2118/194319-MS.
Kumar, D., Ghassemi, A., 2015. 3D Simulation of Multiple Fracture Propagation from
Horizontal Wells. American Rock Mechanics Association.
Liu, Y., Sharma, M.M., 2005. Effect of Fracture Width and Fluid Rheology on Proppant
Settling and Retardation: an Experimental Study. Society of Petroleum Engineers.
https://doi.org/10.2118/96208-MS.
Palisch, T.T., Vincent, M., Handren, P.J., 2010. Slickwater Fracturing: Food for Thought.
Society of Petroleum Engineers. https://doi.org/10.2118/115766-PA.
Roy, P., Du Frane, W.L., Kanarska, Y., Walsh, S.D., 2016. Numerical and experimental
studies of particle settling in real fracture geometries. Rock Mech. Rock Eng. 49 (11),
4557–4569.
Sahai, R., Miskimins, J.L., Olson, K.E., 2014. Laboratory Results of Proppant Transport in
Complex Fracture Systems. Society of Petroleum Engineers. https://doi.org/
10.2118/168579-MS.
Schein, G., 2005. The Application and Technology of Slickwater Fracturing. Society of
Petroleum Engineers.
Shrivastava, K., Sharma, M.M., 2018. Proppant Transport in Complex Fracture Networks.
Society of Petroleum Engineers. https://doi.org/10.2118/189895-MS.
Tang, J., Wu, K., Zuo, L., Ehlig-Economides, C., 2018. A coupled three-dimensional
hydraulic fracture propagation model considering multiple bedding layers. In:
Unconventional.
Tong, S., Mohanty, K.K., 2016. Proppant transport study in fractures with intersections.
Fuel 181, 463–477.
Tong, S., Mohanty, K., 2017. Proppant placement in secondary fractures. In:
Unconventional Resources Technology Conference. https://doi.org/10.15530/
URTEC-2017-2671549.
Tong, S., Singh, R., Mohanty, K.K., 2017. Proppant transport in fractures with foambased fracturing fluids. SPE-187376-MS; 2017. In: SPE Annual Technical Conference
and Exhibition, 9 - 11 Oct. Society of Petroleum Engineers, San Antonio, Texas, USA.
https://doi.org/10.2118/187376-MS.
Tong, S., Singh, R., Mohanty, K.K., 2018. A visualization study of proppant transport in
foam fracturing fluids. J. Nat. Gas Sci. Eng. 52, 235–247. https://doi.org/10.1016/j.
jngse.2018.01.030.
Tong, S., Gu, M., Singh, R., Mohanty, K., 2018. Simulation of proppant transport in foam
fracturing fluid based on experimental results. In: Unconventional Resources
Technology Conference, Houston, Texas, 23-25 July 2018, SEG Global Meeting
Abstracts. Society of Exploration Geophysicists, American Association of Petroleum
Geologists, Society of Petroleum Engineers, pp. 4064–4080. https://doi.org/10
.15530/urtec-2018-2901054.
Vidma, K., Abivin, P., Fox, D., Reid, M., Ajisafe, F., Marquez, A., Still, J., 2019. Fracture
Geometry Control Technology Prevents Well Interference in the Bakken. Society of
Petroleum Engineers. https://doi.org/10.2118/194333-MS.
Wang, J., Elsworth, D., Ma, T., 2018. Conductivity evolution of proppant-filled hydraulic
fractures. In: 52nd US Rock Mechanics/Geomechanics Symposium.
Alotaibi, M.A., Miskimins, J.L., 2015. Slickwater Proppant Transport in Complex
Fractures: New Experimental Findings & Scalable Correlation. Society of Petroleum
Engineers. https://doi.org/10.2118/174828-MS.
Agrawal, S., Shrivastava, K., Sharma, M.M., 2019. Effect of Shear Slippage on the
Interaction of Hydraulic Fractures with Natural Fractures. Society of Petroleum
Engineers. https://doi.org/10.2118/194361-MS.
Alotaibi, M., Miskimins, J., 2019. Power law correlation for slickwater proppant dune
height. In: SPE Hydraulic Fracturing Technology Conference and Exhibition. Society
of Petroleum Engineers.
Ba Geri, M., Imqam, A., Dunn-Norman, S., 2018. Proppant Transport Behavior in Inclined
versus Vertical Hydraulic Fractures: an Experimental Study. Society of Petroleum
Engineers. https://doi.org/10.2118/191813-18ERM-MS.
Ba Geri, M., Imqam, A., Suhail, M., 2019. Investigate Proppant Transport with Varying
Perforation Density and its Impact on Proppant Dune Development inside Hydraulic
Fractures. Society of Petroleum Engineers. https://doi.org/10.2118/195018-MS.
Barree, R.D., Conway, M.W., 1994. Experimental and numerical modeling of convective
proppant transport. In: SPE Annual Technical Conference and Exhibition. Society of
Petroleum Engineers.
Barree, R.D., Duenckel, R.J., Hlidek, B.T., 2019. The Limits of Fluid Flow in Propped
Fractures- the Disparity between Effective Flowing and Created Fracture Lengths.
Society of Petroleum Engineers. https://doi.org/10.2118/194355-MS.
Daneshy, A., 2019. Three-Dimensional analysis of interactions between hydraulic and
natural fractures. In: SPE Hydraulic Fracturing Technology Conference and
Exhibition. Society of Petroleum Engineers.
Fern�
andez, M.E., S�
anchez, M., Pugnaloni, L.A., 2019. Proppant transport in a scaled
vertical planar fracture: vorticity and dune placement. J. Pet. Sci. Eng. 173,
1382–1389.
Gale, J.F., Laubach, S.E., Olson, J.E., Eichhubl, P., Fall, A., 2014. Natural fractures in
shale: a review and new observations natural fractures in shale: a review and new
observations. AAPG Bull. 98 (11), 2165–2216.
Huang, H., Babadagli, T., Li, H., Develi, K., Wei, G., 2018. Experimental Study on the
Effect of Injection Parameters on Proppant Transport in Rough Vertical Hydraulic
Fractures. Society of Petroleum Engineers. https://doi.org/10.2118/190041-MS.
Huang, J., Perez, O., Huang, T., Safari, R., Fragachan, F.E., 2018. Using Engineered Low
Viscosity Fluid in Hydraulic Fracturing to Enhance Proppant Placement. Society of
Petroleum Engineers. https://doi.org/10.2118/191395-18IHFT-MS.
Kadhim, D., Imqam, A., Dunn-Norman, S., 2017. Ceramic proppant transport and
placement in heterogeneous fracture systems. In: Unconventional Resources
Technology Conference. https://doi.org/10.15530/URTEC-2017-2697613.
Kern, L.R., Perkins, T.K., Wyant, R.E., 1959. The Mechanics of Sand Movement in
Fracturing. Society of Petroleum Engineers. https://doi.org/10.2118/1108-G.
Kou, R., Moridis, G.J., Blasingame, T.A., 2018. Analysis and Modeling of Proppant
Transport in Inclined Hydraulic Fractures. Society of Petroleum Engineers. https://
doi.org/10.2118/189856-MS.
11
T. Chun et al.
Journal of Petroleum Science and Engineering 184 (2020) 106523
Weijers, L., Wright, C., Mayerhofer, M., Pearson, M., Griffin, L., Weddle, P., 2019. Trends
in the North American Frac Industry: Invention through the Shale Revolution.
Society of Petroleum Engineers. https://doi.org/10.2118/194345-MS.
Wen, Q., Wang, S., Duan, X., Li, Y., Wang, F., Jin, X., 2016. Experimental investigation of
proppant settling in complex hydraulic-natural fracture system in shale reservoirs.
J. Nat. Gas Sci. Eng. 33, 70–80.
Xu, Z., Pyrak-Nolte, L.J., 2018. Effect of Buoyancy on Fluids and Precipitation
Distribution in Inclined Fractures. American Rock Mechanics Association.
Yushi, Z., Xinfang, M., Shicheng, Z., Tong, Z., Han, L., 2016. Numerical investigation into
the influence of bedding plane on hydraulic fracture network propagation in shale
formations. Rock Mech. Rock Eng. 49 (9), 3597–3614.
Zhang, J., Kamenov, A., Zhu, D., Hill, A.D., 2013. Laboratory measurement of hydraulic
fracture conductivities in the Barnett shale. In: IPTC 2013: International Petroleum
Technology Conference.
12