SPE-196203-MS
Suat Bagci and Sergey Stolyarov, Baker Hughes, a GE Company
Copyright 2019, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Calgary, Alberta, Canada, 30 Sep - 2 October 2019.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents
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Abstract
The flowback period of the unconventional wells is very critical as it can cause determential ecomonical
effects if not properly optimized. The success of the well is as dependent of the completion program as
it is from the flowback program applied during the initial production period of the well. If ineffective
operations are performed on the flowback phase {independently on the completion technology}, the well
can underperform and become unsuitable for development.
In unconventional wells, it is necessary to develop the safe well operating envelope in safe zone to prevent
the early proppant flowback based on the reservoir parameters and the completions in place. The well can
start producing in this developed safe well operating envelope by controlling the wellhead pressure and
surface valves and optimizing the proper choke size to keep the well with free proppant production.
Proppant flowback production modeling captured decline of water production as well as the increase of
liquid production when a selected choke sizes is applied. By controlling the flowing bottomhole pressure
(FBHP) during defined flowback period, the volume of proppant production decreased with decreasing
chokes sizes and increasing long flowback periods. This study showed that the optimized choke sizes to
improve the longer production periods depended on the sensitivity of pressure drawdown, liquid rates,
wellhead pressure, and fracture geometry parameters. Numerical results showed that the critical parameters
affecting the stability of the proppant pack are fracture closure pressure, reservoir pressure, proppant type
and size, and type of fracturing fluid. Proppant flowback program developed by using optimized choke size,
wellhead pressure (WHP) and FBHP, and amount of producible proppant volume predicted for designed
flowback production periods. At the beginning of the flowback period, the wellbore is filled with fracturing
fluid and the minimum choke size should be used as small as possible (12/64"). The controlled FBHP
management over 45 days of flowback period corresponds to an average drawdown rate of 10 psi/day to 200
psi/day. Finally, the developed workflow applied to design flowback periods and selection of choke sizes
to prevent excessive proppant production and proppant crushing in hydraulically fractured unconventional
wells.
This paper presents the methodology and workflow for selecting the required choke sizes and flowback
periods to minimize the risk of production of high volume proppant during the flowback period after
fracturing. The case study presented here in will present the benefits of optimizing choke sizes and flowback
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Flowback Production Optimization for Choke Size Management Strategies in
Unconventional Wells
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SPE-196203-MS
programs for reducing the damage to fracture conductivity and to increase the cumulative production. The
optimized choke sizes, flowback strategies and workflow established with this case study have proven to
increase the performance of fractured unconventional wells.
Introduction
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Unconventional shale oil and gas reservoirs are developed using multi-stage hydraulically fractured
horizontal wells to create large surface areas connected to the wellbore and easier access to the low
permeability matrix pores and induced natural fractures. After drilling a horizontal well, fracturing fluids
and proppants are injected into a pre-selected perforation stage in the well to create a hydraulic fracture and
keep it open. After completing all fracture stages, the fracturing fluids and formation fluids are produced
from the well as flowback. Because flowback data provides important information, the quality and frequency
of flowback data measurements improved by deploying a uniform choke management procedure, which
has prompted researchers to develop improved empirical, analytical, and numerical models to analyze the
flowback data (Kurtoglu, et. al, 2015).
Flowback production at high rates and unmanaged flowing bottomhole pressure can result in near
wellbore damage and an overall decrease in productivity due to higher proppant production with higherpressure drawdown in the fractured reservoir. By applying aggressive flowback, programs and using
improper choke sizes can also result in proppant washout, crushing, embedment, fines migration and
spalling. Large amounts of proppant can flow out of the well due to higher-pressure drawdowns. In order
to prevent this situation, the choke sizes should be optimized to mitigate the proppant flowback that could
result in substantial damage near the wellbore. In fact, the amount of proppant collected during flowback
period caused the operator to question how much proppant was actually left in the fracture. This loss of
proppant near the wellbore was potentially restricting the fluid flow into the wellbore. This damage to the
proppant pack could result in diminished production.
Flowback production optimization can enable the operator to achieve optimum flowback production
by using proper choke size and mitigate proppant production after the completing of frac job and reduce
formation damage commonly because by applying aggressive flowback practices. After fracturing jobs,
the production rates are very high due to higher near-wellbore pressures in the stimulated volume of
the reservoir, which resulted rapid pressure drawdowns of flowing bottomhole pressure. High-pressure
gradients may develop near wellbore regions, which can lead to increased stress and fracture damage
(Jacobs, 2015).
Fu et. al (2018) proposed a method to estimate initial fracture volume and investigate the loss in
fracture volume during flowback period after frac job. They indicated that the loss in fracture volume
mainly happened during early flowback period. The effect of fracture closure is expected to reduce during
late flowback when fluid influx from matrix into fractures provides increasing pressure support. They
also indicated that fastback strategy (enlarging the choke size) might cause more fracture-volume loss in
wells compared with slowback strategy (decreasing choke size). Consequently, the fracture closure is the
dominant drive mechanism compared to fluid expansion during early flowback period.
Tompkins et. al (2016) studied on prediction of damage that can be created by aggressive flowback
practices and how this damage can be mitigated by effectively monitoring and controlling initial rates and
pressures. The benefits of optimizing choke schedules were demonstrated to effectively manage drawdown
pressure and to reduce damage to fracture conductivity and to increase cumulative production. They
evaluated flowback production periods of two wells in the Delaware basin completed in Second Bone
Springs sand. One of the well was produced using the operator’s conventional approach and the second
well was flowed back using a drawdown strategy and operational decisions for choke management. In
conventional approach, the well was flowed back for 26 days with an initial pressure decline of 140 psi/
day with choke size increased from 12/64 to 15/64 in. After hydrocarbon breakthrough and declining of
SPE-196203-MS
3
Flowback Production Optimization
Figure 1 presents the flowback production optimization workflow for choke size optimization after
fracturing job. In this workflow, using fracture fluid type, proppant type, fracture closure pressure and
flowing bottomhole pressure for each usable choke sizes and wellhead pressures in developed well model,
the flowing bottomhole pressures can be predicted. The predicted flowing bottomhole pressures, the water
production rate and oil rate at the flowback period can be used to estimate the producible amount of proppant
volumes for each choke size and flowback production period based on changing the fracture permeability
due to fracture closure pressure, proppant type, fracture fluid type. At the beginning of the flowback period,
the wellbore filled with fracturing fluid and the minimum choke size should be as small as possible. The
controlled FBHP management over the flowback period use an average pressure drawdown rate of 10 to
150 psi/day that is similar to conservative flowback production operations in the field after fracturing job.
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water production, the choke size was increased to 23/64 in. and was used until to end of flowback period.
The total fluid production from this well was 35,264 bbls before the beginning of oil production. In second
well, the production was started with small choke size (11/64 in.) and an average initial pressure decline
of 100 psi/day. The choke size was changed with 1/64 in. increments every 24 hours up to 34/64 in. At the
end of flowback period, the total fluid production was 34474 bbls. After analysis of the production data, the
fracture half-lengths of first well and second well were 279 ft. and 761 ft., respectively. They concluded that
a decrease in fracture half-length caused the decrease in well performance due to application of conventional
flowback production approach.
Wilson et. al (2016) studied the stress impact of various drawdown strategies in unconventional wells after
completing the fracture jobs. They estimated damage of proppant pack and near-wellbore region resulted
from an aggressive drawdown strategy. The geomechanical modeling approach was used to calculate the
effective stress in the near-wellbore region created by different drawdown scenarios. They concluded that
a drawdown of 1 to 5 psi/hr. helps significantly reduce the peak stress imposed on the proppant pack. This
resulted in the decrease of fracture conductivity over time in the shale zones.
Kumar et. al (2018) analyzed the impact of drawdown strategy on the production from a well producing
from a reservoir with a complex fracture network. The estimated ultimate recovery from complex fracture
networks depends upon the connected fracture conductivity and the applied drawdown. As the drawdown
is increased, the unpropped fractures close and can cause a large portion of the fracture network to get
disconnected from the wellbore. This reduces the available fracture area for production. Although an
aggressive drawdown strategy results in higher initial production rates, it can cause faster fracture closure,
in turn resulting in a lower Estimated Ultimate Recovery (EUR). They showed that choke management
strategy depends on the sensitivity of the fracture conductivity to stress. They observed that drawdown
dependent closure of a fracture segment could lead to a decrease in the conductivity of the fracture system
to the wellbore.
Rojas and Lerza (2018) presented the results of choke size management in horizontal wells located in
Vaca Muerta shale play and evaluated their potential impact on estimated ultimate recovery (EUR) and net
present value (NPV). They stated that an aggressive choke management caused a reduction in EUR of up
to 20%. By changing choke size, too early in a well’s life or developing higher drawdown have yielded
a decrease in productivity. Higher drawdown showed an evidence of lower completion effectiveness and
damage on the fracture network could be the reason for this behavior. Because of excessive and spontaneous
pressure drop, mechanisms such as fines migration, proppant embedment and crushing, pressure dependent
properties, proppant flowback and its resistant to cyclic stress are becoming the most critical behaviors
during choke size management. The conservative choke size management probably minimized these effects
and increased long-term production rates. They defined the pressure drawdown path and the choke size
should be increased by following this optimum path.
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SPE-196203-MS
Prediction of Fracture Geometry Parameters
Post-fracture job analysis was used to identify the fracture geometry parameters (fracture half-length, height,
width, conductivity, dimensionless conductivity, and fracture permeability) for each stages along the lateral
section of the well using digital recorded fracture treatment data. As a first step, pressure history matching
analysis was performed by matching the recorded surface treatment pressure recorded during fracturing job.
These estimated parameters would provide upper limits of the fracture geometry parameters that would be
used to constrain subsequent initial production analysis after frac job with matching the production rates
during flowback period. The pressure matching analysis for selected stages located at toe (Stage-1), middle
(Stage-11) and heel (Stage-21) sections of the well are given in Table 1.
Table 1—Selected stages for post-fracture job analysis to identify fracture geometry dimensions.
Stage
Perforated Interval (ft)
Stage Length (ft)
Number
of Clusters
Perforation
Density (SPF)
Cluster
Interval (ft)
# of Perfs
1
14,518 – 14,740
222
4
4
8
32
11
11,548 – 11,772
224
4
4
8
32
21
8,503 – 8,800
297
4
4
8
32
In Stage-1 at toe section of the well, pressure matching was verified for fracture treatment as shown in
Figure 2. As shown in this figure, Confined fracture growth and long fracture lengths having very good
conductivity contributing the production were observed for Clusters-2, -3 and -4. In cluster-1, no fracture
conductivity was observed due to no proppant settling after fracture closing.
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Figure 1—Flowback Production Optimization Workflow.
SPE-196203-MS
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In Stage-11 at middle of the well, the pressure matching was verified for fracture treatment as shown in
Figure 3. In Clusters -1 and -2, goof fracture growth and fracture conductivity were observed. In Clusters-3
and -4, high fracture conductivity was created, while the fracture show large height and short fracture length.
In all clusters, good proppant settling was observed during the job and post-job prior to fracture closing.
Figure 3—Pressure matching of Stage-11 using fracture treatment job data.
In Stage-21 at heel of the well, the pressure matching was verified for fracture treatment as shown in
Figure 4. In all clusters, the upward fracture growth was observed. Higher fracture conductivities were
created by good proppant settling. Overall fracture geometry parameters for all stages are given in Table 2 for
predicting the initial production rates and matching the recorded production rates during flowback period.
Figure 4—Pressure Matching of Stage-21 using fracture treatment job data.
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Figure 2—Pressure matching of Stage-1 using fracture treatment job data.
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Table 2—Fracture Geometry Parameters.
Stage
Dimensionless
Fracture
Conductivity
0.0232
53
20
26
0.243
1181
364
152
25
0.185
844
367
4
100
27
0.213
1093
697
5
143
72
0.245
490
331
6
169
60
0.280
1319
390
7
59
51
0.265
1658
1402
8
166
52
0.242
1077
325
9
131
69
0.168
914
415
10
63
125
0.226
1194
969
11
77
104
0.193
592
437
12
104
85
0.245
1281
675
13
90
84
0.273
1587
956
14
140
51
0.274
1336
570
15
162
39
0.311
1605
497
16
133
49
0.338
1745
676
17
101
85
0.197
488
253
18
48
146
0.199
1084
1414
19
48
137
0.239
864
981
20
55
105
0.124
667
603
21
52
137
0.131
709
702
Propped
Height (ft)
1
106
90
2
162
3
Width (in)
Average fracture half-length (108 ft.), average fracture height (77 ft.), average fracture conductivity (1037
mD-ft) and average dimensionless fracture conductivity (621) values were used in well modeling to predict
the potential maximum production rate from the well after fracturing job. All created fractures as shown in
Figure 5 and their dimensions were used in well model to match the all production rates and to predict the
corresponding flowing bottomhole pressures.
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Fracture
Conductivity (mD-ft)
Fracture HalfLength (ft)
SPE-196203-MS
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Well Modeling
In well modeling, reservoir (IPR), well conduit, completion and choke flow models were combined in order
to design flowback operation and choke size optimization. The reservoir and wellbore properties for the
hydraulically fractured well are given in Table 3. The well modeling consist of the surface equipment, the
selected choke size, the well deviation, fracture geometry dimensions (fracture half-length, dimensionless
frac conductivity, height and width) and completion type for calculating flowing bottomhole pressure along
the perforations and created fractures. Inflow Performance relationship (IPR)-Vertical Lift Performance
(VLP) matching were used to predict the flowing bottomhole pressure (FBHP) to sustain the liquid
production at a given wellhead pressure and a given choke size as shown in Figure 6. In well modeling,
horizontal well with transverse vertical fractures reservoir model was also used in order to construct the IPR
curve using length of horizontal lateral having 21 fractures. Dimensionless fracture conductivity is a key
design parameter in hydraulic fracturing that compares the capacity of the created fractures to transmit fluids
down the fracture and into the wellbore with the ability of the formation to deliver fluid into the fracture.
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Figure 5—Actual created fracture geometries for all stages in the well
after fracture job used in well modeling for production optimization.
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Table 3—Reservoir and wellbore properties for hydraulically fractured wells.
Formation Properties
Initial reservoir pressure (psi)
5340
Thickness (ft)
50
Permeability (mD)
0.02
Porosity (%)
8.0
Temperature (°F)
208
GOR (scf/STB)
100
Fracture Geometry Dimensions
Propped fracture half-length (ft)
108
Propped fracture height (ft)
77
Fracture width (in.)
0.220
Fracture conductivity (mD-ft)
1037
Dimensionless fracture conductivity
621
Fracture closure pressure (psi)
5860
Young’s Modulus (psi)
1,580,000
Proppant Concentration (lb/sqft)
2.40
Well Completion Equipment
Depth (ft, MD)
14840
Depth (ft, TVD)
7809
Casing OD (in.)
4.5 (3.92 in. ID)
Tubing OD (in.)
2-3/8 (1.995 in. ID)
Reservoir Fluid Properties
Oil density (°API)
38
Specific gravity of gas
0.70
Oil viscosity (cp)
0.405
Flowing bottomhole pressures were predicted for each used choke size, wellhead pressure and liquid rate
during flowback production period of the fractured well and are presented in Figure 7.
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Figure 6—IPR-VLP matched production test data.
SPE-196203-MS
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Choke Size Optimization
Optimized choke size management strategy maximizes well productivity and minimizes the risk of typical
wellbore and completion failures. In hydraulically fractured wells, proppant crushing and proppant flowback
are the expected behaviors during a ramp-up and flowback production periods due to completely open
choke and selection of the undesirable choke sizes. Karantinos and Sharma (2017) developed methodology
and combined reservoir, wellbore, completion and choke flow models to properly design a flowback
operation or a choke management strategy. In addition to development of the reservoir simulation model,
the pore pressure at the completion/reservoir interface as a function of the production rates predicted by
using wellbore model for a given choke sizes. After completing the frac job, during clean-up operation or
production ramp-up in an unconventional well, they evaluated a choke sequence that maximizes production
and mitigates the risk of excessive proppant flowback. They performed grain-scale Discrete Element
Modeling (DEM) simulations to assess the combined effect of effective closure stress, pore pressure gradient
and particle size on the amount of proppant to be produced from a single planar fracture. They recommended
that the minimum choke diameter is 14/64 in. at the beginning of the clean-up operation when the wellbore
is filled with frac fluid. By controlling the BHP with an average drawdown rate of 6 psi/hr., in 250 hrs. of
production life of the well, the proppant flowback was controlled successfully.
Karantinos et. al (2016) developed a methodology for selection of an optimum choke management
strategy to maximize the well productivity and minimize the risk of typical well failures during the early
life of the well. In unconventional wells after fracturing, back flow of excessive amounts of proppant
caused in fracture closure and possible wellbore damage and loss of production. They compared choke
management strategies for a wide range of formation and fracture properties including fluid properties,
matrix permeability, fracture conductivity and fracture length. Their results indicated that the destabilizing
effect of pore pressure was more pronounced in wide fractures and/or low effective stress. Wider fractures
produced more proppant under equivalent stress and flow conditions. A wide fractures having unstable
bridges were produced more proppant. Choke management strategy was applied by gradually increasing
the drawdown or production rate for recovering fracturing fluids or bringing a well on production after
long shut-in period. They also compared choke management strategies for various durations ranging from
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Figure 7—Predicted flowing bottomhole pressures based on measured WHP and liquid rates during flowback period.
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SPE-196203-MS
Figure 8—Effect of choke size over the flowback response (modified from Pichon, et.al, 2018).
In application of developed workflow, the predicted flowing bottomhole pressures were used to evaluate
the flowback production from hydraulically fractured well for each choke sizes. Figure 9 presents the
constructed IPR curve for reservoir performance and VLP curves for tubing performance with various
chokes sizes starting from smallest choke size of 12/64 in. In well performance analysis, the flowing
bottomhole pressures were predicted for each choke size based on applied flowback production periods.
In flowback production period, the used choke sizes and the predicted corresponding flowing bottomhole
pressures using measured liquid rates, wellhead pressure as function of production time are presented in
Figure 10. As seen in these figures, the controlled flowing bottomhole pressure management were applied
with an average drawdown rate of 0.35 psi/hr. (8-10 psi/day) up to 815 hrs. After that time, the average
drawdown rate was applied as 8.5 psi/hr. (200 psi/day) that resulted higher proppant volume production.
For long-term production periods, when sufficient oil production from the matrix into the fractures should
minimize the producible volume of proppant due to fracture closure.
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2 to 48 hours based on common clean-up operations used in unconventional wells typically last from a few
hours to 2-3 days.
Fracture closure interpretation relies on the observation of both pre- and post- closure signature during
flowback. The pressure response is controlled by the pressure differential between ISIP and atmospheric
pressure and the size of the choke. Choke selection might have to be adjusted in the first tests to check
the best setting for any given formation. It is recommended to have a variety of chokes available on the
wellsite to increase or decrease choke size according to pressure response as shown in Figure 8 (Pichon et.
al, 2018). After completion of the main propped fractures, the effect of choke management on near-wellbore
connection and fracture closure on proppant during the initial phase of flowback production give the proper
choke selection for proppant free production.
SPE-196203-MS
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Figure 10—Used choke sizes and the predicted flowing bottomhole pressures in flowback production period.
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Figure 9—IPR and VLP curves for each used choke size during flowback period (WHP = 350 psi).
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Table 4—Fracture treatment data.
Fracture fluid type
Borate Cross-Linked Fracturing Fluid w/Gel Stabilizer
Proppant type
20/40 Jordan Sand
Cumulative fracture fluid volume (bbls)
76,805
Cumulative proppant volume (lbs)
6,445,700
Slurry injection rate (bpm)
60
Fracture closure pressure (psi)
5860
Fracture permeability change with proppant embedment were calculated at fracture closure pressure,
Young’s Modulus, reservoir temperature and fracture conductivity of the created fractures in the well. The
producible proppant volumes were estimated based on changing of the fracture permeability, fracture fluid
type and volume, proppant type and volume with the changing of the flowing bottomhole pressure, water,
oil and gas production rates. The fracture closure pressure effected the amount of producible proppant from
a single planar fracture and the total proppant concentration placed after the fracturing job based on proppant
type and fracturing fluid type. At the beginning of the flowback period, the fracture closure pressure and the
created fracture permeability created a larger pressure drawdown that is required to destabilize the proppant
pack and resulted in movement of proppants with the flowing back of the fracturing fluid from the fracture.
Figure 11 presents predicted producible proppant volumes for each choke size in flowback period. For the
flowback period (45 days, 1091 hrs.), the total produced proppant volume was predicted around 554000 lbs
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With sudden changes of the choke sizes in short periods (from 24/64 in. to 46/64 in.) after 815 hrs. of
stable flowback production period, the flowing bottomhole pressures were decreased and resulted potential
increase of the producible proppant volumes due to decreasing of fracture permeability with higher pressure
drawdown. When the choke size was increased from 40/64 in. to 64/64 in. at the time of 915 hrs. of
production, the flowing bottomhole pressures were also decreased again and resulted increasing of the
producible proppant volumes. These type of flowing bottomhole pressure changes and the effect of the
fracture closure pressure prevented to keep the stable production levels and did not allow the implementation
of the choke size management strategies during the flowback period of the well.
Under the fracture closure pressure, the producible proppant volumes are highly dependent on the
total pressure drawdown in the fracture due to changing of the fracture dimensions and its permeability.
Increasing pressure drawdowns in the fracture and increasing production rates by changing the choke
size at the surface, effects the fracture stability and the remaining proppant volume in the fracture after
starting of the flowback production. The changing of the fracture permeability with flowing of the proppants
together with fracturing fluid depends on the behavior between the type of the proppant (20/40 Jordan
Sand) used at fracture treatment and the closure stress. The fracture conductivity is also a dependent of
the change of fracture closure stress that obtained from lab tests. Shor and Sharma (2014) defined three
fracture occurrences based on changing of the fracture closure stress and flow rates. These are (1) completely
collapsed fracture without any proppant placed in the fracture at high flow rates, (2) semi-collapsed fracture
having some amount of proppant still having fracture conductivity and (3) fully created fracture that has
completely full of proppant and having very good conductivity under lower flow rates and high closure
stress. At the end, they also recommended that there should be application of gradual flow rate build-ups
by changing the choke sizes and controlling the flowing bottomhole pressure to achieve proper proppant
pack formation in the fractures.
After the frac job, the producible proppant volumes were estimated using fracture closure pressure,
fracture fluid type and volume, proppant type and total amount and predicted flowing bottomhole pressure
values obtained for each production rate and selected choke sizes. Table 4 presents the fracture treatment
data used in fracturing of the 21 stages of the studied well.
SPE-196203-MS
13
which is not more than 10% of the proppant flows back into the wellbore with the used choke sizes. As a
common application in fractured wells, the total amount of the producible proppant volume should not be
higher than 30% of the cumulative proppant volume used during the fracturing job.
In choke size optimization, the flowback production periods for each usable choke sizes were evaluated
for flowback production optimization and the results are presented in Figure 12. In this evaluation, the choke
sizes are changed from the smaller size of 12/64 in to bigger size of 128/64 in with designed flowback periods
in total production time of 10 days (240 hrs). The total amount of proppant proudction were obtained as
83,000 lb with reducing of the flowing bottomhole pressure to around 3200 psi from initial reservoir pressure
of 5340 psi in total 10 days of flowback production. As an application in the hydrauilically fractured well,
choke sizes can be increased until getting the stable oil production with constant fracturing fluid production
with setting longer flowing production periods for each usable choke sizes.
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Figure 11—Producible proppant volumes for each flowback production periods at corresponding FBHPs and choke sizes.
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SPE-196203-MS
Quartz sand, ceramics and resin coated proppants account for the majority of the proppants utilized
in the hydraulic fracturing treatments. In selection of the proppant, the producible proppant volumes
were predicted for studied fractured well having 21 stages using various proppant types (Jordan Sand,
Resin-Coated Sand, Low Density Ceramic, and Resin-Coated Ceramic). Figure 13 presents the producible
proppant volumes with proppant types. Resin-coated sand prevents proppant flowback and improves
conductivity when compared to Jordan Sand. The resin-coated sands are widely recognized for its ability
to set and create a bonded network that locks into fractures, preventing proppant flowback and maintaining
high conductivity to facilitate strong production. Low-density ceramic proppant has high conductivity for
incrased production. It has a similar bulk density and specific gravity like Jordan Sand. Resin-coated ceramic
proppants are intermediate density ceramic proppant can be utilized at closure stress up to 14,000 psi. It
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Figure 12—Effect of choke size and designed flowback periods on producible
amount of proppants based on potential production rates and FBHPs.
SPE-196203-MS
15
also helps prevent proppant flowback and increases near wellbore conductivity over uncoated ceramics.
Resin-coated sand and resin-coated ceramic proppants have higher proppant strength and reduce proppant
flowback. Resin coated sand has more contact areas that help distribute the stress on proppants more
uniformly, and hold together pieces of crushed proippants to prevent the fines from migrating in the proppant
pack, entering the borehole and compromising the well productivity. Jordan Sand and lowdensity ceramic
have caused higher producible proppant volumes compared to resin-coated sand and resin-caoted ceramic
proppants during the flowback period after fracture treatment.
Conclusions
The following conclusions were obtained:
•
•
•
•
•
The flowback production optimization workflow and methodology was developed for choke size
optimization with reducing proppant production after fracturing job during flowback production
period.
The fracture closure pressure effected the amount of producible proppant from a single planar
fracture and the total proppant concentration placed after the fracturing job based on proppant type
and fracturing fluid type. At the beginning of the flowback period, the fracture closure pressure
and the fracture permeability created a larger pressure drawdown that is required to destabilize the
proppant pack and resulted the movement of proppants with the flowing back of the fracturing
fluid from the fracture.
The total produced proppant volume was predicted less than 10% of the proppant flows back into
the wellbore with the used choke sizes.
For the studied well, the flowing bottomhole pressure changes and the effect of the fracture closure
pressure prevented to keep the stable production levels and did not allow the implementation of
the choke size management strategies during the flowback period of the well.
In choke size management, the gradual flow rate build-ups should be applied by changing the choke
sizes and controlling the flowing bottomhole pressure to achieve proper proppant pack formation
in the fractures.
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Figure 13—Producible proppant volume with proppant type
16
SPE-196203-MS
•
Jordan Sand and low-density ceramic have caused higher producible proppant volumes compared
to resin-coated sand and resin-caoted ceramic proppants during the flowback period after fracture
treatment.
Acknowledgements
The authors would like to thank Baker Hughes, a GE Company for the opportunity to publish and present
this paper.
Ashish, K., Seth, P., Shrivastava, K. and Sharma, M.M., "Optimizing Drawdown Strategies in Wells Producing from
Complex Fracture Networks, SPE Paper 191419-18IHFT-MS, presented at the SPE International Hydraulic Fracturing
Technology Conference and Exhibition, Muscat, Oman, 16-18 October 2018.
Fu, Y., Dehghanpour, H., Motealleh, S., Lopez, C.M. and Hawkes, R., "Evaluating Fracture Volume Loss during Flowback
and Its Relationship to Choke Size: Fastback versus Slowback", URTeC: 2903105, presented at the Unconventional
Resources Technology Conference (URTeC), Houston, Texas, USA, 23-25 July 2018.
Jacobs, T., "Improving Shale Production through Flowback Analysis", Journal of Petroleum Technology, pp. 37–42, 2015.
Karantinos, E. and Sharma, M.M., "Choke Management Under Wellbore, Completion and Reservoir Constraints", SPE
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October 2017.
Kurtoglu, B., Salman, A. and Kazemi, H., "Production Forecasting Using Flowback Data", SPE Paper 172922, presented
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Pichon, S., Varela, R., Maniere, J., Hasbani, J. and d’Huteau, E., "Flowback-Based Minimum Stress Estimate in Low
Permeability Environment: Procedure, Interpretation, and Application in the Vaca Muerta Shale", SPE Paper 189894,
presented at the SPE Hydraulic Fracturing Technology Conference & Exhibition, The Woodlands, Texas, USA, 23-25
January 2018.
Rojas, D. and Lerza, A., "Horizontal Well Productivity Enhancement through Drawdown management Approach in
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Permian Basin Case Study", URTeC: 2461207, presented at the Unconventional Resources Technology Conference
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