SPE 151128

Hydraulic Fracture Optimization in Unconventional Reservoirs

Pedro Saldungaray, SPE, Terry T. Palisch, SPE, CARBO Ceramics Inc.

Copyright 2012, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Middle East Unconventional Gas Conference and Exhibition held in Abu Dhabi, UAE, 23–25 January 2012.

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 of the paper have not been
reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to
reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract
Hydraulic fracturing has become a critical component in the successful development of unconventional reservoirs. From tight
gas, to oil and gas-producing shales and coal bed methane, resource plays rely on hydraulic fracturing for commercial
viability.
A primary goal in unconventional reservoirs is to contact as much rock as possible with a fracture or a fracture network of
appropriate conductivity. This objective is typically accomplished by drilling horizontal wells and placing multiple transverse
fracs along the lateral. Reservoir contact is optimized by defining the lateral length, the number of stages to be placed in the
lateral, the fracture isolation technique and job size. Fracture conductivity is determined by the proppant type and size,
fracturing fluid system as well as the placement technique.
While most parameters are considered in great detail in the completion design, the fracture geometry and conductivity
receives lesser attention. Some mistakenly anticipate that in extremely low permeability formations, hydraulic fractures act as
“infinitely conductive” features. However, many factors that affect the realistic conductivity of the fracture are poorly
understood or overlooked. This often leads to a less than optimal outcome with wells producing below the reservoir potential.
This paper presents an approach to assess the realistic fracture conductivity at in-situ conditions and the economic
implications on proppant selection. The effects of transverse fractures, low areal proppant concentration and flow dynamics,
are considered among other variables. The theory behind this concept is presented and supported with case studies where it has
been applied in the field to various unconventional reservoirs.

Introduction
Unconventional reservoir fracturing is unique in several aspects when compared to fracturing conventional wells. Very low to
extremely low permeability, horizontal well geometries, multiple transverse fracs placed along a horizontal drain, and complex
frac geometry - particularly in shales - all add to the complexity of designing and implementing fracture treatments. For the
remainder of the paper we are assuming that horizontal wells with multiple fracs are utilized in unconventional reservoir
developments. In order to optimize the stimulation treatment, the design process must attend to multiple parameters which can
be grouped into four broad categories:

• Wellbore placement and lateral length

• Completion hardware and isolation techniques
• Fracture spacing or number of fracs
• Fracture geometry and conductivity

Wellbore Placement and Lateral Length. These parameters are driven by geology, in situ stress regime, reserves to be
developed per well, production rates to be handled by each individual well, future well intervention requirements, surface
logistics and environmental impact. The trend within most unconventional plays through the years has seen an increase in the
lateral length to maximize the reservoir contacted and reserves developed by each well (Figure 1). In most cases the main
restriction to lateral length is the capability of both current and future intervention in the wellbore. This may include
limitations on frac isolation equipment and perforating, as well as coiled tubing reach concerns. This trend of increasing the
lateral length has favorably impacted the economics of field developments and leaseholds, and reduced the environmental
impact of development. Lateral lengths ranging from 1,000 to in excess of 10,000 ft are common today [Rankin 2010]
2 SPE 151128

4500 "Lateral Length" and IP vs Time 18
Completion Hardware and Isolation Techniques. The
industry has developed a wide variety of completion
4000 16 hardware and isolation techniques for Horizontal Multi-
Distance between top and bottom perf, ft

3500 14 Fractured wells (HMF). From barefoot openhole wells to

Initial Production Rate, MMCFD
<= Lateral  uncemented or cemented liners, ball-activated sliding
3000 Length, ft 12
sleeves to pump-down plugs and perf guns, as well as
2500 10 hybrid systems, each technique strives to maximize
2000
IP =>
8
operational efficiency by placing the maximum amount
of stages in the minimum possible time. Current
1500 6
multistage sleeve systems are capable of placing dozens
1000 4 of stages in a continuous pumping operation, with the
maximum limits being continually pushed. Plug and perf
500 2
Louisiana Wells  ONLY techniques are only limited by the ability to pump the
0 0 plugs and guns down the lateral. In the Bakken, for
Aug‐07 Nov‐07 Feb‐08 Jun‐08 Sep‐08 Dec‐08 Mar‐09 Jul‐09 Oct‐09 Jan‐10
example, operators are now routinely placing as many as
Figure 1 – Average horizontal lateral length in the Louisiana 40 stages per lateral using combinations of sliding sleeve
Haynesville Shale has shown a steady increase since development and plug and perf methodology [Rankin, 2010]. In fact,
began in 2007, and a corresponding increase in average IP [Pope, it is rumored that some are contemplating as many as 50
2010]. stages in the future.

Fracture Spacing and Number of Fracs. This subject

is largely dependent on the rock fabric and permeability 10
#4 #6

of the formation. As spacing is reduced adjacent fracs 9

#7

start to interfere with each other affecting production 8 #3 #5

while costs continue to increase due to the larger number

#1
#2
7
of treatments. An economic evaluation dictates the
Reported IP, MMCFD

6
optimal spacing where the benefit of adding fracs is
5
balanced with the cost of the increased number of
fracture stages [Rankin 2010, Norris, 1998]. Two 4

parameters can affect this interference. First is the rock 3

fabric, or the tendency of the hydraulic fracture treatment 2

to generate complex fractures. The higher the tendency 1

to generate a complex network of fractures, the greater 0
the optimal spacing will be between fractures. In this 0 10 20 30 40 50
Lateral Length x # Stages / 1000
60 70 80
case one will tend to measure the effectiveness of the
Figure 2– Initial Production as a function of Lateral Length and Total
fracture in terms of Stimulated Reservoir Volume (SRV). Number of Frac Stages for one operator in the Haynesville Shale
In some shales it has been demonstrated that increased [Pope 2009].
SRV will yield higher production and EUR [Mayerhofer
2008]. The flow capacity or conductivity of the fracture
network combined with the SRV provide an assessment
method to predict well performance and hydrocarbon
recovery.
As the tendency of the formation to generate complex
fractures decreases, the optimal spacing between
fractures becomes more tightly correlated with reservoir
permeability and resulting fluid mobility in the
formation. In reservoirs more prone to conventional bi-
wing planar fractures, a greater number of closely spaced
stages are required to recover reserves in lower
permeability reservoirs [Cipolla 2009]. In general where
reservoir permeability is the determining factor, it is not
Figure 3– Increasing lateral length as well as decreasing the spacing
uncommon to see long horizontal drains with dozens of between fracture stages has yielded positive impacts on production,
fracs spaced 10s to 100s ft apart. In the Haynesville EUR and well economics [Rankin 2010].
Shale (Figure 2) and Bakken (Figure 3), for example,
increasing the number of stages has led to increased production.
SPE 151128 3

Fracture Geometry and Conductivity. The fracture geometry optimization involves defining the desired fracture half-length,
width and conductivity for maximized production. While there are several optimization methods, all involve a relative
comparison of the flow potential of the fracture to that of the reservoir, as described by the Dimensionless Fracture
Conductivity (FCD) parameter below:

FCD = [kfrac*wfrac ]/ [kform*Xfrac] ………………………………………………………………………………(1)

For steady or pseudosteady state flow in oil wells, several authors [Prats 1961, Cinco-Ley 1981and McGuire & Sikora 1960]
have developed correlations that allow the engineer to use FCD to predict the benefits of the fracture stimulation, yielding a
method that balances fracture half length and drainage area with fracture conductivity for stimulation design. FCD is also used
to optimize the design of the fracture in such methods as the Unified Fracture Design [Economides 2002].
While the FCD concept and various related fracture optimization methods are well understood, many in the industry fail to
identify the correct fracture permeability to plug into the equation correctly estimated at realistic (downhole) flow conditions
[Palisch 2007]. Given the critical nature as well as generally overlooked impact of fracture conductivity, the following sections
will be devoted to describing the deficiencies of the laboratory procedures, as well as provide references to adjust reported
conductivities to reflect more realistic conditions within an actual fracture in order to guide the proppant selection process.

Fracture Conductivity
The concept of fracture conductivity is often overlooked as an important stimulation design variable in unconventional
reservoirs. For some, the presence of nano-Darcy rock does not intuitively lead to the need for high fracture conductivity.
However, while the fracture conductivity required to economically produce a horizontal well in an unconventional play and to
improve hydrocarbon recovery will vary in different reservoirs, many engineers fail to recognize the conductivity requirements
to accommodate high velocity hydrocarbon flow in transverse fractures. The pack conductivity for a given proppant is a
function of the proppant particle size, strength, proppant grain shape (roundness and sphericity), embedment into the frac
faces, fracturing fluid residue, fines migration, effective stress on proppant and fluid flow effects (non-Darcy and multi-phase
flow) which can be very pronounced in the limited intersection between a wellbore and a transverse fracture. When accounting
for these effects, it is not uncommon for proppant pack reference conductivity to be reduced by two orders of magnitude
[Palisch 2007 and Miskimins 2005]. In the following sections the authors will review the standard testing methodology and
deficiencies in more detail.

Conductivity Testing and its Limitations. In order to understand realistic conductivity, one must first understand how
conductivity is measured and reported. The conductivity of the fracture represents the product of the permeability of the
fracture and the fracture width, and can be represented by the following equation:

Conductivity = kfrac*wfrac …..…………………………………………………………………………………(2)

In 1989 the American Petroleum Institute (API) issued the first standardized procedures under API-RP-61 for measuring the
conductivity of proppants in the lab using the Cooke Conductivity Cell [API 1989]. The procedure was modified through the
years to include longer flowing times, replacement of steel shims with sandstone cores and testing at elevated temperatures. In
2006 the International Organization for Standardization (ISO) set the current standard under number ISO-13503-5 [ISO 2006].
In 2008 the API adopted ISO-13503-5 under API-RP-19D, effectively replacing API-RP-61 [API 2008].
These standards set testing procedures for evaluating sand, ceramic media, resin coated proppants, gravel packing media,
and other materials used for hydraulic fracturing and gravel-packing operations. The objective was to provide a consistent
methodology for proppant conductivity testing and comparing proppant materials under comparable laboratory conditions.
Recognizing the standard’s limitation given the differing conditions between lab and realistic downhole conditions, API-RP-
19D specifically states it “is not intended for use in obtaining absolute values of proppant pack conductivities under downhole
reservoir conditions” [API 2008].
The current procedure consists of placing a representative sample of proppant at 2 lb/ft2 in the test cell between two Ohio
sandstone wafers with a Young’s Modulus (YM) of 5 million psi. The cell is heated to 150°F or 250°F (depending on
proppant type) and stress is ramped at a prescribed rate to the first test point. After 50 hours a set of measurements is made and
the process can then be repeated at each desired stress, holding for an additional 50 hours at each stress. Conductivity is
calculated by applying Darcy’s Law from the pressure drop produced by a 2 ml/min 2% KCl flow stream through the proppant
pack. Conductivities measured using this test are normally reported in service and proppant company published literature and
may be denoted as “reference”, “laminar”, “baseline” or “long term” conductivities. The key testing conditions are
summarized below:

• 2% KCl fluid pumped at 2 ml/min

• 2 lb/ft2 proppant loading
• Sample placed between Ohio Sandstone wafers with YM = 5.0 Mpsi
4 SPE 151128

• Single stress maintained for 50 hr

• Temperature 150° F (for sand) or 250° F (for ceramics)

Although these standard conditions allow for comparable testing between proppants, they rarely represent the realistic
conditions in which proppant is placed in hydraulic fractures [Vincent 2009]. As such, these procedures ignore many
parameters that affect the actual conductivity of the frac. Further complicating matters, different proppant types may be
affected differentially by each parameter. A brief description of the key effects is given below. The interested reader can refer
to SPE 106301 for a full description [Palisch 2007].

Non-Darcy and Multiphase Flow effects. The ISO/API test flow rate of 2 ml/min is not representative of actual flow rates in
a proppant pack. This rate would equate to ~6 BPD in a fully perforated vertical oil well with a 50 ft tall bi-wing frac
achieving 2 lb/ft2 concentration, or ~15 MSCFD flowing at 1,500 psi and 250°F in a similar dry gas well. The fluid velocities
resulting from more prolific wells will cause tremendous amounts of energy to be lost, which translate into additional pressure
losses not described by Darcy’s Law. Forchheimer’s equation (below) includes the non-Darcy pressure drop (βρν2) component
for a single phase fluid and is dominated by the velocity-squared term [Forchheimer 1901]. Interpreting this extra pressure
drop as a conductivity reduction typically shows a fracture conductivity impairment of 50 to 85% [Palisch 2007].

……………………………………………………………...…(3)

Additionally, the fluid circulated in the ISO/API tests is a

solution of silica-saturated, oxygen free 2% KCl water. In Increased Pressure Drop due to Mobile
reality oil and gas wells rarely produce 100% water, or Liquid in Proppant Packs
even a single phase fluid for that matter. Instead, two or 60
three phases are typically present (oil, water and gas),
Multiplier of Total

yielding a much more complex flow regime than tested in 50

Pressure Drop

the lab. Multiphase effects have been described in many 40

ways by various researchers. Lab data consistently
30
demonstrate that pressure losses in the fracture may
increase significantly when both liquid and gas phases are 20 0.75 MMCFD
mobile within the fracture. This is typically attributed to 0.25 MMCFD
10
the highly inefficient flow regime that occurs when gas, oil Trend
and water molecules move through the proppant pack, -
each moving at different velocity. In fact, some tend to 0% 5% 10% 15%
consider multiphase flow impacts as a multiplier to non- Fractional Flow of Liquid
Darcy effects since the impacts are most pronounced at Figure 4– The impact of Multi-phase flow can be dramatic at very
high velocity flow. Unfortunately, significant pressure low fractional flow rates of liquid [Palisch 2007].
losses are documented even when only small percentages
of a second phase are mobile within the fracture (Figure 4).

Proppant loading at 2 lb/ft2. It is generally accepted that in most slickwater or hybrid frac stimulations, the effective
proppant loading achieved in the fracture is less than 1 lb/ft2. This means that the fracture is narrower than in the ISO/API test.
In addition to directly impacting conductivity via the conductivity equation (fracture perm x fracture width), the much
narrower width produced by the reduced concentration also increases the fluid velocity through the pack for a given flow rate.
This in turn exacerbates the non-Darcy and multiphase flow effects in the fracture. If the fracture width is halved, and
hydrocarbon velocity is doubled, then non-Darcy pressure losses are increased by a factor of 400% (2 squared). .

Embedment and Spalling. The ISO/API test uses a sandstone core with a YM of 5 million psi. Many shale and
unconventional reservoirs are significantly softer than these sandstone cores (e.g. the Eagle Ford Shale has a YM of 1-3
million psi). Softer rock leads to a loss of width and conductivity due to both proppant embedment and formation spalling.
The reduced width has the double effect of diminishing conductivity (directly proportional), and increasing fluid flow velocity
due to the smaller cross section of the resulting proppant pack. As a consequence non-Darcy pressure losses will also be
increased.

Temperature Effects. As noted earlier, the ISO/API conductivity test is performed at 150°F for sand proppant and 250°F for
ceramic proppant. The reason for this difference is primarily due to the known detrimental impact of higher temperature on
sand and sand-based proppants (i.e. Resin Coated Sand). Specifically, as temperatures exceed 200°F, sand based products can
SPE 151128 5

experience a significant decrease in conductivity (Figure 5). For example, an uncoated sand, when exposed to 250°F at 6,000
psi stress will lose 40% of its conductivity when compared to 150°F, and this loss jumps to nearly 80% at 300°F and 8,000 psi.
Coating the sand with a resin lessens the damage because the resin can encapsulate the crushed fines. However, even resin
coated sand loses 30% of its conductivity at 8,000 psi and 300° F. Ceramic proppants are tested at 250° F due to their thermal
stability. These proppants are sintered at ~2,700°F and are engineered for improved sphericity, strength and thermal
resistance. Therefore, no correction is required when placing a ceramic proppant into higher temperature formations.

20/40 Premium RC Sand

20/40 Premium White Sand

Conductivity Correction from 150 deg F, factor

1
1
Conductivity Correction from 150 deg F, factor

0.8
0.8

0.6 0.6

0.4 0.4
150 deg F 150 deg F
200 degF 200 degF
0.2 250 deg F 0.2 250 deg F
300 deg F 300 deg F
350 deg F 350 deg F
0
0
0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000
0 2000 4000 6000 8000 10000 12000 14000
Closure Stress, psi Closure Stress, psi

Figure 5 – The effects of temperature on conductivity for Sand-based proppants [Pope 2009].

Cumulative Conductivity Impact. When all of these

effects are taken together, the overall impact of these Cumulative Conductivity Reductions
damage mechanisms on the conductivity at actual bottom
hole flowing conditions can be severe. In fact, it is not 6000
5720 Jordan Sand

uncommon to see the overall loss of conductivity exceeding Lightweight Ceramic

90% (Figure 6). It should also be noted that while all 5000
Effective Conductivity (md-ft)

4310
Effective conductivities can be
proppants experience these several orders of magnitude 4000
less than 2% of API test values
reduction in conductivity, the individual damage 98%
reduction
mechanisms can have different impacts on the various 3000

proppant types [Schubarth 2006]. While the above

99%
conductivity damage is already severe, there are also other 2000 1540
1410
reduction

downhole realities that can exacerbate the damage, 1000

685 547
167

including long term conductivity degradation as well as 225 25 120

85 7

gel/fluid residue damage and many other mechanisms 0

ISO 13503-5 "Inertial Multiphase Lower Gel Damage Fines
[Palisch 2007, Barree 2003, Pearson 2001]. Regardless of Test (Base Flow" with Flow Achieved Migration /

the exact magnitude of these reductions, the bottom line is Using PredictK
Case) Non-Darcy
Effects
Width (1
lb/sq ft)
Cyclic
Stress
that the realistic conductivity in all hydraulic fractures is Figure 6 – The cumulative reduction in conductivity due to several
much less than measured in standard lab testing, and damage mechanisms not accounted for in the standard ISO/API
reported in industry literature. Further, if these reductions test [Palisch 2007].
are not accounted for when designing hydraulic fractures and/or selecting the appropriate proppant, significant production may
be deferred or in some cases not recovered in the existing completion [Blackwood 2011].

Proppant Selection in Unconventional Reservoirs

The most common completion in unconventional plays consists of a horizontal wellbore with multiple proppant fracs placed
along it. Despite the very low reservoir permeability driving FCD up, high conductivity proppant is still needed given the
detrimental effects discussed in previous sections. Additional to the conductivity considerations, there are several other issues
that must be addressed when selecting the appropriate proppant for use in these multi-stage fracs in horizontal wells. These
include flow convergence in transverse fracs, proppant transport when low viscosity fluids are employed, and proppant crush
at the typical low concentrations employed.
6 SPE 151128

Flow Convergence in Transverse Fracs. Let’s reiterate

that the goal in unconventional plays is to place numerous
transverse fracs along a horizontal lateral, as opposed to
conventional plays which may exploit a single frac in a
vertical well. Production into a horizontal wellbore from
an orthogonal fracture will exhibit linear flow in the far
field as it travels down the fracture(s). However, as the
fluids converge on the relatively small diameter wellbore
(Figure 7), the fluid velocities in that near wellbore region Figure 7 – Fluids flowing within the hydraulic fracture in horizontal
increase dramatically. In fact, if one considers a single wells must converge into an extremely (relatively) small area as
planar 100 ft tall vertical fracture, and places it fully they cut transversely with the wellbore [Shah 2010].
connected in a vertical well and transversely in a horizontal 6 inch diameter wellbore, the fluid velocity in the near wellbore
would be 127 times higher in the transverse fracture as compared to the vertical well. Further, recall that velocity is a squared
term in the Forchheimer (see previous discussion) pressure drop calculation, therefore, the pressure drop in the transverse frac
could be over 16,000 times greater than in a fully connected vertical well. This leads to the conclusion that it is practically
impossible to place enough conductivity near the wellbore in a transverse/HZ well to be fully optimized. Completions in
unconventional resources will benefit from more conductivity near-wellbore in transverse fracs [Besler 2007, Rankin 2010,
Shah 2010, Vincent 2011, Economides 2000].

Proppant transport and placement via low viscosity fluids. Proppant placement is governed by a series of mechanisms
involving the interaction between the fracturing fluid and proppant. A number of issues have been investigated through time
that impact how proppant is transported into the frac and its final location in the created geometry. Proppant density and size
have a determining impact on proppant settling, which in turn impacts where proppant will be placed in the frac.
The simplest single-particle settling mechanism can be described by Stokes law, in which the velocity of a single particle
falling through a stagnant liquid medium can be described as follows:

……..…………………………………………………………………….………(4)

Where vfall is the settling rate in ft/s, dprop is the average

particle diameter in inches, μ is the fluid viscosity in cp,
and γprop and γfluid respectively are the specific gravity of
the proppant and the fluid [Economides 2000]. The
settling rate is directly proportional to the difference in
density between the fluid and proppant, and inversely
proportional to the fluid viscosity. This last condition
makes settling an important consideration when pumping
low viscosity Newtonian fluids as are typically used in
HMF treatments conducted in dry gas shales. While
Stokes Law does not fully describe the proppant transport
in hydraulic fractures due to the many additional
considerations for calculating settling rate, it shows two
components are directly controlled by the proppant:
proppant density and diameter. While much attention is
typically given to proppant density, proppant diameter can
actually be of greater importance in a fracturing treatment.
As stated in Stokes law, settling velocity is proportional to Figure 8 – Relationship between proppant density and proppant
dprop squared, thus having an exponentially larger effect on diameter on settling rate in 2% KCl [Palisch 2008].
settling rate than fluid viscosity. As an example, despite
being more dense, a smaller diameter 40/70 2.65 ASG LWC/RCS/Sand particle settles slower than a 20/40 1.75 ASG Proppant
(Figure 8). Again it should be noted that while there are significant limitations of using Stokes Law to describe setting under
dynamic conditions in a slurry situation it does serve the purpose to illustrate how smaller and lighter proppant aid easier
placement. It is therefore no surprise that the most popular slickwater proppants are currently 40/80 LWC and 40/70
Sand/RCS. Extensive research and experimentation have been carried out to better describe and assess proppant placement and
can be referenced outside this paper [Palisch 2008, Dayan 2008, Mobbs 2001].
SPE 151128 7

Proppant crush at low concentrations. The typical low proppant concentrations pumped in waterfracs often designed for
unconventional gas reservoirs can result in a low areal concentration being placed in the frac. Values between 0.25 and 0.50
lb/ft2 are typical and much lower than the 4.00 lb/ft2 load used in ISO 13503-2/API-RP-19-C crush test, or the 2 lb/ft2 used in
the standard ISO/API conductivity test. The impact of these low concentrations on proppant pack conductivity (due to the
narrower width) were discussed previously in this paper. However, an additional (and often overlooked) result of these
narrower fractures is the impact on proppant crush. When proppant grains are loaded into a crush cell, particles can be
considered either interior or exterior grains. Grains in the interior of the pack are “protected” due to their contact with six to
twelve neighboring grains, thus providing uniform stress distribution on the individual gains. However, exterior grains have
fewer contact points leading to greater stress at the points of contact. For this reason, exterior grains experience greater damage
in the crush and conductivity cells, and ultimately the fracture. Therefore, as proppant pack width (and proppant areal
concentration) decreases the exterior grains comprise a larger percentage of the total grains in the pack, thereby leading to
higher proppant crush [Palisch, 2009].
Some have also proposed partial monolayers as a means to boost conductivity, the idea being that voids between grains
would provide open paths with infinite conductivity [Brannon 2004, Parker 2005]. Using conventional proppants
(Sand/RCS/LWC), a partial monolayer will occur at concentrations of <0.20 lb/ft2, where less than a single layer of proppant
should occur. While there is significant debate regarding whether partial monolayers can be reliably achieved over large
portions of a created frac [Gidley 1989, Palisch 2008], even if they can be successfully placed many overlook the increased
stress concentrated on individual proppant grains. This will lead to higher crush, higher embedment, and ultimately loss of
fracture width and conductivity.
Various specialty proppants have been introduced to exploit the advantages of partial monolayers, as well as purportedly
promote their placement. Most of these new proppants are much lighter density (from 1.75 g/cc to nearly buoyant), formed
from various substrates, including resin coated porous ceramic and/or walnut hulls, thermoplastics, nanocomposites, polymers
and other resin or plastic components. In many cases these proppants do not “crush” as conventional rigid particles do, but
instead deform, which is one reason why they are typically only considered useful at low stress. Caution should be exercised
when employing these deformable proppants, however, as their usefulness is limited only to partial monolayers. Independent
testing has shown that if these deformable proppant grains are actually placed in a traditional pack whereby they come in
contact with each other, the grains tend to “squish” together and become a relatively impermeable plug [Stimlab 2009-2010].
In summary, increased crush, concentrated stress on individual proppant beads and embedment (the latter two in partial
monolayers only) occur when low areal concentrations are placed. This phenomenon takes place regardless of whether the
proppant is a Sand, Resin Coated Sand, Ceramic or specialty deformable proppant, constituting additional sources of frac
width and conductivity loss one must consider for adequate proppant selection in unconventional plays.

Proppant Selection Case Histories

When one understands the realistic conditions within the

proppant pack, and their impact on fracture conductivity, it
becomes apparent that the fracture flow capacity is not
optimized (i.e. the FCD is much lower than anticipated) in
horizontal multistage fractures in unconventional reservoirs.
Further, it means that in general, anything that can be done
to increase the conductivity of the fracture should yield a
corresponding increase in production. While there are
many ways to increase the conductivity of a fracture, and all
should be considered when designing fracture stimulations,
one of the easiest and most common is to upgrade the
proppant size and/or type. As one moves up the Proppant
Conductivity pyramid, fracture conductivity (and Figure 9 – The Economic Conductivity pyramid showing the
production) improves (Figure 9). However, moving up the three Tiers of proppant. 99% of all proppant can be placed into
pyramid typically carries with it an increase in completion one of three Tiers. As one moves up the Triangle, proppant
performance (conductivity) improves [Gallagher 2011].
(proppant) cost. Therefore, the decision to increase
conductivity must also involve an economic analysis, and ultimately will become an economic decision. So the process for
selecting proppant (as well as any design changes) must involve four steps.

1. Calculate the conductivity of the fracture at realistic conditions

2. Predict the production performance achieved with each proppant
3. Evaluate the cost vs. benefit and select the proppant that maximizes the economics of the completion
4. Review the actual field production benefits to ensure validity to the previous evaluations

The first two steps must typically be performed through the use of a fracture propagation model that is coupled to a reservoir
simulator/model. The model must be able to account for the realistic conditions of the fracture and the corresponding impact
8 SPE 151128

of fracture conductivity. Step 3 can then be performed using the economic hurdles for the given situation; some production
simulators automate this function. The last step is often the most overlooked step in the process, due to the significant activity
level required of most engineers involved with exploiting unconventional reservoirs. The authors will present in the following
sections, several case histories from unconventional reservoirs in which proppant was selected considering the realistic
conductivity at bottomhole flowing conditions and the economic impact on the completion. These cases illustrate the
robustness of the approach described above and demonstrate the production and economic benefits of placing enhanced
conductivity in ultra-low permeability formations.

Case History 1 – Barnett Shale. The successful development

of the Barnett Shale is considered by most to be the driving
force behind the success of today’s unconventional reservoir
exploitation. Shortly after companies “cracked the code” for
Potential Target of 1
successful completion practices (multistage fracs along Bcf over 15 years
horizontal wellbores) in the early 2000’s, the Barnett Shale
became one of the hottest plays in the United States. While
depressed natural gas prices have tempered the activity in the
play for the last several years, the Barnett still enjoys
widespread activity. The Barnett Shale is a Mississippian-aged
shale located between 6,500 and 8,500 ft TVD. It currently
covers as many as 15 counties in the Fort Worth Basin of north Actual Well
Texas, and at its thickest point can be as much as 1,000 ft thick. Production
The Barnett is a thermogenic reservoir and averages 4.5% Total
Organic Content (TOC). As is the case with all shale gas plays, SPE 119366
the primary challenge in the play is the ultra-low permeability of
<0.0001 md. Numerous studies have been documented on the Figure 10 – Barnett well history match showing the potential
impact of increasing the conductivity of the fracture. The
completions practices in this shale gas play. One such study blue line represents actual well production [Cipolla 2009].
illustrated the benefits of increasing the conductivity of the
hydraulic fractures [Cipolla 2009]. An actual Barnett Shale
completion was history matched and then sensitivities were
performed to several parameters including fracture conductivity
and fracture stage spacing. The well of interest utilized a Tier 3
uncoated sand and was stimulated using a slickwater fluid
system. The history match indicated that the realistic fracture
conductivity was ~2 md-ft, and showed that if the conductivity
were increased from 2 md-ft to 20 md-ft, the well would see a 1
BCF increase in the 15 year cumulative production (Figure 10).
In addition, the study also illustrated that the optimal staging
between fractures (stage spacing) was highly dependent on the
conductivity of the fracture (Figure 11). Namely, as the
fracture conductivity was increased, the optimal spacing
increased. While all scenarios modeled would need to be
evaluated on a cost vs. benefit basis, the study illustrated the
importance of accurately estimating the realistic fracture Figure 11 – The relationship between main fracture
conductivity, as well as the overall value of increasing the conductivity and spacing [Cipolla 2009].
conductivity.
SPE 151128 9

Case History 2 – Haynesville Shale. Using the learnings

from the Barnett, the industry opened up the shale gas
frenzy when the multistage fracturing in horizontal wells
was applied to the Haynesville Shale. Its development
confirmed that this technology could be successful in other
shale plays. The Haynesville Shale is a late-Jurassic age
shale that is found between the Cotton Valley Group and the
Smackover Limestone in East Texas and North Louisiana.
It is a black, organic-rich shale with a TOC of 3-5% and 1.3-
2.4 vitronite reflectance (Ro). Although the shale is
laterally extensive and variable, most of the development
occurs at depths between 11,000-13,000 ft, and in areas
where the total thickness is 150-400 ft. While porosity is
moderate (6-12%), permeability is extremely low (5-800
nanoDarcies). The Haynesville Shale also has elevated
temperature (>300° F) and reservoir pressure (0.84-0.88
psi/ft) [Pope 2009, 2010].
Since most operators in the HV Shale initially adapted Figure 12 – Realistic Conductivity Comparison at
their frac designs from their experience in the Barnett, the Haynesville/Bossier Shale conditions for several 40/70 proppants
primary fluid system of choice was either a slickwater or show that Tier 1 ceramic proppants (red and black lines) are far
superior to Tier 2 and 3 proppants at 10,000 psi stress [Pope 2009].
“hybrid” design. Small mesh (40/70 or 40/80) proppant was
primarily utilized given transport concerns with low viscosity fluids. At realistic conditions (Figure 12), Tier 1 proppants have
two to twenty times the conductivity as Tier 2 and Tier 3
1.0
"PI" Norm to LL Cum Frequency ‐ Operator A proppants, respectively [Pope 2009]. However, despite the
high temperatures and stresses, and this conductivity
0.9
disparity, operators in the Haynesville shale have used
0.8
tremendous volumes of all three Tiers of proppants. This is
0.7
primarily due to higher cost and limited availability of the
Tier 1 proppants. However, this large diversity of proppant
Cum Frequency

0.6

0.5 usage has allowed for an opportunity to evaluate actual field

0.4 performance comparing proppant types. Once such study is
0.3
comprised of a well “Set A” containing 56 wells operated by
the same company within a 5 mile radius [Pope 2010].
0.2

Other Proppant
Twenty of these wells were known to contain Tier 1 40/80
0.1
Premium Proppant Lightweight Ceramic proppant, while 36 offset wells were
0.0 known to contain primarily a Tier 2 40/70 Premium RCS.
0.0 0.2 0.4 0.6 0.8 1.0 1.2
PI Normalized to Lateral Length, MCFD/psi/ft While there is significant debate over whether IP (initial
production) is a good indicator of completion performance in
Figure 13 – Cumulative frequency plots comparing Tier 1
(premium) proppant to Tier 2 (other) proppant, using IP data shale gas plays, the authors illustrated that increasing the
that has been normalized to both the flowing pressure and conductivity (from Tier 2 to Tier 1) of the fracture yielded
lateral length (right), show that increasing conductivity yields a nearly 50% increase in IP normalized for flowing pressure
30-40% increase in production [Pope 2010]. and lateral length (Figure 13). As stated previously, when
comparing different completions, IP data alone can present
Cumulative Incremental Value concerns. IP is just a snapshot in time and is an imperfect
6.00
measure of success. In addition, as a well is produced the
5.00
stress on the proppant typically increases, therefore it is
important to also look at the longer term performance of
Cum Incremental Value, MM$

4.00 proppants. A comparison of production for the same operator

shows the Tier 1 wells are producing, on average, 20% more
3.00
normalized production after 6 months than the Tier 2 wells.
2.00
12 Month Wells
In addition, a smaller subset of wells “Set B” (10 Tier 1 and
19 Tier 2) have at least 12 months of production. In these
6 Month Wells

1.00
wells, the Tier 1 completions had produced 30% more
0.00 normalized production than the Tier 2. The authors
0 24 48 72 96 120
Months
144 168 192 216 240
hypothesized that this increase may be indicative of the
durability advantage of the Tier 1 proppant [Pope 2010].
Figure 14 – Per well projected average cumulative In a follow up study, the above well sets were reanalyzed
incremental present value (PV10) of Tier 1 performance using an additional 12 months of data for each well set
versus Tier 2 performance, assuming $5/mcf gas price,
$60/bbl condensate and 10% discount factor. Regardless of
[Blackwood 2011]. After normalizing for lateral length, the
whether projecting from “6 month” or “12 month” wells, Tier 1 wells in “Set A” have produced over 20% more gas
there is tremendous value to upgrading the conductivity and
the incremental investment pays out in less than 2 months
[Blackwood 2011].
10 SPE 151128

than the Tier 2. This represents an additional 340 MMCF of gas, or $2 million in value, per well. Similarly, the Tier 1 wells
in “Set B” have produced an average of 39% more gas (or 500 MMCF gas) per well than Tier 2 wells. That represents nearly
$3 million in incremental present value, and a tremendous return on the investment required to upgrade to Tier 1 proppant.
The authors also performed hyperbolic decline curve analyses on the updated production, projecting recovery out to 20 years.
For the two well sets, it is estimated that the Tier 1 wells will produce an average of 1.2-1.6 Bcf additional gas over the Tier 2
wells, and generate $4 – 5 million in incremental value over 20 years, and pay out the additional investment in proppant in less
than 2 months (Figure 14).

Case History 3 – Eagle Ford Shale. The Eagle Ford formation is an Upper Cretaceous deposit in the Gulf Coast region of
South and Central Texas. It has been recognized for many years and considered the source rock for several of the producing
reservoirs in South Texas. However, it wasn’t until completion practices used in the Haynesville Shale were employed in the
Eagle Ford that it became economically viable to develop. Since that time development has accelerated significantly, with
nearly 200 active rigs in late 2011. While it is typically referred to as a shale, the Eagle Ford is actually an organic rich
calcareous mudstone which is prevalent across 6 million acres spanning 20 counties. The reservoir and geologic
characteristics can vary significantly across the play, with TOC ranging from 1-7%, depths from 6,000-13,000 ft TVD and
total thickness as much as 250 ft. In addition, the reservoir fluids range from primarily oil in the northwest, to liquids-rich
condensate in the most active central portion, to dry gas in the deepest areas to the south. Since development of this play did
not begin in earnest until the latter half of 2009 and into 2010, and given the geologic and reservoir variability across the play,
completion strategies are still being developed and optimized in the Eagle Ford. However, one study was recently published
that documents the impact of fracture conductivity in Eagle Ford completions [Bazan 2010].
Two wells were modeled and history matched in this
study. They are located in the condensate and gassy
areas of LaSalle County. The depth of the “gassy” well,
Well A, is ~11,000 ft TVD, and of the condensate well,
Well B, is ~8,500 ft TVD. Both wells were drilled with
4,000 ft laterals and contained 10 (Well A) and 12 (Well
B) stages. Since these were some of the first wells
completed for this operator, additional data were
collected to assist in the history match, including
radioactive (RA) proppant tracers and microseismic
mapping. While significant work was performed and
documented, two items of note will be discussed here.
First, the fracture propagation and production match
confirmed that the realistic fracture conductivity, despite
using Tier 1 lightweight ceramic proppant, was much
lower than measured in the standard conductivity test.
In Well A, the matched conductivity was ~2 md-ft,
while in Well B it was 1.75 md-ft. Keep in mind that
these wells each produced in excess of 6 MMCFE per
day, so the stimulations and completions were
successful despite this low realistic conductivity.
However, similar to the work presented earlier in the
Case 1 Barnett study, when proppants are placed into
downhole conditions, the conductivity can be damaged
quite severely. Therefore, it is no surprise that when
sensitivities were run in these models, the impact of
conductivity was quite significant (Figure 15). A Tier 2
RCS would provide 75-100% greater cumulative
production than a Tier 3 Uncoated Sand, and the Tier 1 Figure 15 – Upgrading from a Tier 3 Sand (blue) to a Tier 2 RCS (red)
LW Ceramic provides an additional 20-50% over the yields a 3 year increase in production of 75% (Well A-top) and 100%
Tier 2, after just 3 years of production. The condensate (Well B-bottom). These increases jump an additional 20% (Well A)
well (B) enjoyed the largest increase, which is likely due and 50% (Well B) when upgrading to a Tier 1 LWC [Bazan, 2010].
to the impact of multiphase flow and the corresponding
need for additional conductivity.
SPE 151128 11

Based on this results, this operator chose to continue

the use of 40/80 LW Ceramic. After several
completions, the operator compared production of his
first fourteen Tier 1 LWC wells to several offset
operators (Figure 16). The Tier 1 wells which utilized
a 40/80 LWC appear to be producing 30-50% more
equivalent gas after 6 months production than the offset
wells containing Tier 3 Sand [Lattibeaudiere 2011].
Of course, as one moves up the Proppant
Conductivity Pyramid (Figure 9), the cost of the
proppant increases, therefore, it is important to evaluate
the increase in production and perform a cost-to-benefit
analysis. It is estimated that after 6 months, this
production increase represents ~$1.4 million in
incremental value generated by the Tier 1 conductivity,
per well, which more than offsets the investment of
upgrading from Tier 3 to Tier 1.
Additional studies have also been documented in the Figure 16 – Wells stimulated with Tier 1 LW Ceramic proppant (black
Eagle Ford which highlight the benefits of increased line) are producing 30-50% more than offset wells stimulated with
Tier 3 Sand by three different offset operators [Lattibeaudiere 2011].
conductivity, including one study which encompassed
the entire Eagle Ford well set. In this study, all wells
which were known to contain Tier 1 Ceramic from a specific manufacturer were compared to all offset wells which received
sand, RCS, or ceramic proppants from other suppliers. The results showed that in wells with at least 12 months of production,
the known Tier 1 completions had produced an average of 33-38% more BOE than completions with unknown proppant type
[Vincent 2011].

Case History 4 – Bakken Shale. The Bakken formation is a Mississippian/Devonian age oil play that stretches over 200,000
square miles in North Dakota, Montana, Saskatchewan and Manitoba. Similar to the Eagle Ford, it has enjoyed a tremendous
increase of rig activity over the past several years due to the relatively high price of oil (as compared to gas). Most of the
wells are being drilled in the Middle Bakken, which lies at 9,000 to 11,000 ft depth, and can be as thick as 80 ft. Average
porosity is ~5%, and the permeability is on the order of 0.04 mD. While it is referred to as a shale, it is actually a
carbonate/clastic sequence, containing interbedded siltstones
and sandstones. While the Bakken is not as deep or hot as Well F Well G Well H Well I

either the Haynesville or the Eagle Ford, it is primarily an oil 250,000

Well J
Well N
Well K
Well O
Well L
Well P
Well M
Well Q

play and therefore requires additional conductivity to Well R

Well W
Well T
Well X
Well U
Well Y
Well V
PU Install

effectively convey the oil into the wellbore [Rankin 2010]. 200,000

Many of the operators in the Bakken are using either Tier

Cumulative Oil, Bbls

1 ceramics or Tier 2 RCS. Ceramics, similar to the 150,000

Haynesville and Eagle Ford, are in short supply, and
therefore many operators must use whatever is available,
including Tier 3 Sand. One leading Bakken operator has 100,000

published results showing the benefits of increasing the

conductivity while at the same time maximizing the number 50,000

of stages in the well, utilizing a plug and perf methodology in

uncemented liners. Initial publications were based on a 0

relatively small well count [Rankin 2010], but indicated a

0 100 200 300 400 500 600 700

Time, Days
tremendous increase in well productivity when comparing
Tier 1 ceramic completions to Tier 3 wells. However, this Figure 17 - Red wells contain Tier 1 ceramic and utilize plug
and perf staging, while Blue wells contain Tier 3 sand and
same operator revisited the well set, adding additional wells sliding sleeve staging [Vincent 2011].
and data (time) [Vincent 2011]. After nearly 2 years of
production, Tier 1 ceramic wells with more stages are producing twice the production of Tier 3 wells with fewer stages
(Figure 17). Although the authors did not provide cost or economic data, it is estimated that the Tier 1 wells are generating
~$4 million in incremental value per well after just one year, while the cost to upgrade from Tier 3 and sliding sleeves to Tier
1 and plug and perf is approximately $800,000. This represents a tremendous return on investment, which continues to grow
as the incremental production continues appears to increase over time.
12 SPE 151128

Conclusions

The pack conductivity for a given proppant is a function of the proppant particle size, strength, proppant grain shape
(roundness and sphericity), embedment into the frac faces, fracturing fluid residue, fines migration, effective stress on
proppant and fluid flow effects (non-Darcy and multi-phase flow). When accounting for these effects, proppant pack
conductivity can be reduced by more than two orders of magnitude.
When selecting proppant, one must account for these conductivity reductions so that the optimal FCD and completion can be
employed. In addition, selecting the appropriate proppant for use in multi-stage fracs in horizontal wells of unconventional
reservoirs require accounting for several additional impacts, including flow convergence in transverse fracs, proppant transport
if low viscosity fluids are employed, and proppant crush at the typical low concentrations achieved in many resource plays.
The proppant selection process must evaluate the technical merits of the available proppant options, the resulting impact on
well performance, and the fracture treatment cost. The process for selecting proppant is ultimately an economic decision based
on calculating the conductivity of the fracture at realistic conditions, predicting the production performance for each proppant
option, evaluating the cost vs. benefit of each and selecting the proppant that maximizes the economics of the completion. The
validity of the analysis must then be confirmed by the actual field results.
More than 200 field case histories have been summarized which document the benefits of conductivity [Vincent 2009] in a
wide variety of formations and well types. Four recent examples involving horizontal wells have been presented in this paper,
including studies in the Barnett, Haynesville, Eagle Ford and Bakken. These case histories support the robustness of the
proppant selection process outlined above, based on realistic conductivity and impact on stimulation economics. The benefits
of placing enhanced conductivity with high quality proppant in ultra low permeability formations is illustrated by the case
studies.
Simply put, fractures rarely can be characterized as “infinitely conductive”, even in ultralow permeability reservoirs.
Fractures must be designed to accommodate realistic conductivity reductions as presented in the paper. Unconventional
resources are sometimes called “technology plays”, because technology must be used for their development, and technology
advancements can represent tremendous opportunities in these plays.
SPE 151128 13

Nomenclature

API American Petroleum Institute

ASG Apparent Specific Gravity
BCF Billion cubic feet
Boe Barrels of Oil Equivalent
BPD Barrel Per Day
cp Centipoise
d Diameter
ΔP Pressure drop or Delta Pressure
°F, deg F degrees Fahrenheit
EUR Estimated Ultimate Recovery
F&D finding and development
FCD Dimensionless Fracture Conductivity
ft feet or foot
ft/s feet per second
g/cc grams per cubic centimeter
HMF Horizontal Multi Fractured
Hr, hr Hour
HZ Horizontal
IP Initial Production
IRR Internal Rate of Return
ISO International Organization for Standardization
K, k Permeability
kfrac Fracture Permeability
kform Formation Permeability
KCl Potassium Chloride
lb/ft2 Pounds per square foot
LWC Lightweight Ceramic
mD, md milliDarcies
MCF Thousand Standard Cubic Feet
MCFD Thousand Standard Cubic Feet per Day
ml/min milliliters per minute
MMSCF Million Standard Cubic Feet
MMSCFE Million Standard Cubic Feet Equivalent
MMSCFD Million Standard Cubic Feet per Day
Mpsi Million pounds per square inch
psi pounds per square inch
psi/ft pounds per square inch per foot
PV10 Present Value at 10% discount rate
RA Radioactive
RCS Resin Coated Sand
SRV Stimulated Reservoir Volume
TOC Total Organic Content
TVD True Vertical Depth
v Velocity
vfall Settling rate
wfrac Fracture Width
YM Young’s Modulus
Xf, Xfrac Fracture half length
ß Coefficient of Inertial Resistance
γ Specific gravity
μ Viscosity
φ Density
14 SPE 151128

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