474255186 hydraulic-fracturing-pdf

EP 2000-5540
November 2000
Stimulation Field Guidelines
Part II (Revision)
Hydraulic Fracturing
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SEPTAR Stimulation Team
EP 2000-5540
November 2000
Stimulation Field Guidelines
Part II (Revision)
Hydraulic Fracturing
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This document is classified as Restricted to Shell Personnel Only. 'Shell Personnel' includes all staff with a personal
contract with the Shell Group of Companies, designated Associate Companies and Contractors working on Shell
projects who have signed a confidentiality agreement with a Shell Group Company. Issuance of this document is
restricted to staff employed by the Shell Group of Companies. Neither the whole nor any part of this document may
be disclosed to Non-Shell Personnel without the prior written consent of the copyright owners.
Copyright 2000 SIEP B.V.
SHELL TECHNOLOGY EP, RIJSWIJK
Further copies can be obtained from the Global EP Library, Rijswijk
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EP 2000-5540 Restricted to Shell Personnel Only
Contents
Introduction 1
Fracture geometry and propagation 3
In-situ stress 3
Near-wellbore fracture geometry 5
Fracture containment 7
Fracture propagation 9
Net pressure 9
Basics of fracture propagation 9
Tip screen-out (TSO) 10
Productivity improvement factor 11
Fracture growth analysis 12
Hydraulic fracturing models 14
Basic models used in Shell 15
Various fracture design models 15
Selection of candidates 17
Basic requirements 17
Stimulation treatment selection 18
Fracture treatment selection 18
Fracturing fluids and additives 21
Introduction 21
Features of fracturing fluids 21
Types of fracturing fluid 22
Water-based fluids 22
Oil-based fluids 25
Emulsions 26
Foams 26
Liquid CO2 26
Fracturing fluid additives 27
Fluid rheology 28
Measurement of rheological properties 30
Fluid leakoff 31
Fracture wall impairment 32
Stimulation Field Guidelines - Hydraulic Fracturing Contents • i
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Proppants 33
Introduction 33
Ideal proppant properties 33
Proppant pack conductivity 34
Fracture closure stress 34
Particle size, shape, sorting 35
Proppant embedment 36
Proppant concentration 36
Fracturing fluid residue 37
Commonly used proppants 37
Sand 38
Intermediate strength proppant 38
High strength proppant 38
Resin-coated proppants 39
Types of RCPs 39
Interaction of RCPs with fracturing fluid 40
Proppant back production 41
Description 41
Prevention methods 41
Data acquisition 45
Introduction 45
Microfrac testing 45
General 45
Short description 46
Minifrac testing 48
General 48
Procedure 48
Interpretation 49
Core testing 50
Anelastic strain recovery (ASR) 50
Differential strain analysis (DSA) 51
Acoustic transmission anisotropy (ATA) 51
Log data 52
Fracture mapping 53
Temperature log 53
Radioactive tracers 54
Tiltmeter survey 54
Microseismic monitoring 55
High-permeability fracturing 57
Introduction 57
Skinfrac design considerations 58
Skin bypass fracturing 60
Candidate selection 60
Restricted to Shell Personnel Only EP 2000-5540
ii • Contents Stimulation Field Guidelines - Hydraulic Fracturing
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Selection criteria 61
Proppant selection 62
Fluid selection 62
Skinfrac design guidelines 63
Special topics 65
Multiple zone fracturing 65
Cased holes 65
Open holes 67
Dual hydraulic fracturing 68
"Pipeline" fracturing 69
New developments 70
Fracturing through coiled tubing 70
Viscoelastic fracturing fluids 71
Waterfracs 71
Acid fracturing 72
Propped acid fracturing 72
Closed fracture acidising (CFA) 73
Hydraulic fracture treatment design guidelines 75
Introduction 75
Well condition and parameters 75
Reservoir and rock parameters 76
Determine optimum fracture length and conductivity 77
Perforation policy 77
Type of fracturing fluid 78
Type of proppant 79
Determine fluid data (fluid loss, rheology) 81
Fracturing fluid additives 81
Determine in-situ stress profile 81
Calculate a fracture treatment design using ShellFrac 82
Design steps 82
Treatment scheduling 83
Recommended procedure 84
Planning and executing the treatment 87
Pre-treatment (laboratory) studies 87
Planning and scheduling 89
Fluid preparation 90
On-site quality control 90
Test procedures 91
Programme deviation 92
Carry out the fracturing treatment 92
Job responsibilities 92
Logistics and site lay-out 93
Stimulation Field Guidelines - Hydraulic Fracturing Contents • iii
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On site execution 94
Post-job report and evaluation 94
Reporting 94
Evaluation 94
After the treatment 94
Forced closure 94
Resume production 95
Appendix I Summary of various hydraulic fracturing
programs 97
Appendix II Fluid loss calculations 101
Appendix III Rock mechanical parameters for hydraulic
fracturing design 103
Appendix IV Example calculation for a Skinfrac design 107
Appendix V Commercial fracturing fluid systems 109
Appendix VI Execution checklist 113
References 117
Index 119
iv • Contents Stimulation Field Guidelines - Hydraulic Fracturing
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Introduction
The primary goal of well stimulation is to increase the productivity of a well by
removing damage in the vicinity of the wellbore, or by increasing the connectivity
between the reservoir and the wellbore through the creation of a highly conductive
channel (propped fracture) in the formation. Commonly used stimulation
techniques include matrix stimulation (acidising), hydraulic fracturing and acid
fracturing (carbonates only).
Acidising is a good stimulation method in moderate to high permeability reservoirs,
which show substantial damage (skin) in the near-wellbore region. The damage is
removed by injecting acid below fracturing pressure (see Stimulation Field
Guidelines, Part I). The impairment may originate from drilling or completion
operations, for example due to the invasion of drilling or completion fluids, or it
may be caused by the production process (or in case of injection wells, by the
continuously injected fluids), for example by asphaltenes or moving fines.
Hydraulic fracturing is successfully applied in low to moderate permeability
reservoirs, whereby the productivity is improved from effectively increasing the
wellbore radius. It can be applied in almost any formation, although commonly in
carbonate reservoirs acid fracturing is applied.
The first hydraulic fracturing treatment was carried out in 1947 by Halliburton in a
well in the Hugoton Field, Kansas, USA. A gasoline-base napalm gel was used as
fracturing fluid and sand was used as propping agent. Although the productivity of
the well was not increased by the treatment, it had aroused interest in the method
on the part of the oil industry and of service companies. As a result, Halliburton
became the first exclusive licensee for the hydraulic fracturing technique in 1949.
In hydraulic fracturing a neat fluid, called a “pad”, is pumped to initiate the fracture
and to establish propagation. This is followed by a viscous fluid mixed with a
propping agent (“slurry”), further extending the fracture. A two-wing fracture is
created. The propping material (proppant), transported by the frac-fluid, is placed
inside the fracture to prevent it from closing completely after the treatment. The
fluid chemically breaks back to a lower viscosity and flows back out of the well,
leaving a highly conductive flow path for reservoir fluids. The propped fracture can
be from tens to several hundred meters long, and it usually has a width of some
5-35 mm, thus increasing the effective wellbore radius. As a result the production
Stimulation Field Guidelines - Hydraulic Fracturing Introduction • 1
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rate of the well will increase. Depending on the formation permeability and the
presence of damage, the productivity improvement may be tenfold or more.
At this point it is worthwhile to realise that by hydraulic fracturing, the well
productivity is increased by altering the flow pattern in the formation near the
wellbore from one that is radial, with flowlines converging to the wellbore, to one
that is linear with flow to a conductive fracture, that intersects the wellbore. For this
to be successful, however, the fracture must be much more conductive than the
formation. To obtain such a high-permeability fracture, a highly permeable prop-
pant pack is required of some 50 - 500 Darcy.
Since its inception, hydraulic fracturing has developed from a simple, low-volume,
low-rate fracture stimulation method to a highly engineered, complex procedure
that is used for many purposes. Fracturing treatments typically have varied in size
from the small (e.g. 1.9 m3) mini-hydraulic fracturing treatments, to the deeply
penetrating massive hydraulic fracturing (MHF) treatments, which now exceed
1 million gal (3.8 x 103 m3) fracturing fluid and 3 million lbs. (1.4 x 106 kg) of
propping agent. Hydraulic fracturing is currently the most widely used process for
stimulating oil and gas wells, and MHF treatments have played a significant role in
developing otherwise uneconomical tight gas reservoirs.
The application of hydraulic fracturing is generally limited to low-permeability
reservoirs (e.g. < 1 mD for gas reservoirs and < 20 mD for oil reservoirs). The
fracture conductivity corresponding to the typical fracture widths achieved is not
sufficient to effectively stimulate medium and high permeability reservoirs.
However, a technique has been developed in recent years, primarily intended to
bypass near-wellbore damage, for which an extra wide, proppant-filled, relatively
short hydraulic fracture is created. This technique, called Skinfrac, uses a limited
volume (some 600 bbl or 100 m3) of fracturing fluid, and some 10,000-100,000 lbs
(5-50 tonnes) of proppant, using an aggressive pumping schedule, in which the
proppant reaches the fracture tip at an early stage of the treatment, preventing the
fracture from growing further (tip screen-out, TSO, design). The fracture is then
further inflated and filled with proppant. In unconsolidated reservoirs, where sand
production is a potential problem, the Skinfrac technique can be a good alternative
for sand control purposes: the reservoir is fractured with a screen in place, followed
by a gravelpack operation. Such technique is also frequently called Frac&Pack, or
FracPack. These techniques will be discussed in detail later in this document.
Hydraulic fracturing a well is not without some risk. A fracture treatment may fail
because of unintended communication with neighbouring water or gas zones.
Furthermore, mechanical failures can occur, including leaking packers, casing or
tubing leaks, or communication of fracturing fluids behind poorly cemented casing.
Other causes of failure include the inability to complete the treatment due to high
treatment pressure, or poor proppant transport (screen-out). Incompatibility of the
fracturing fluid and additives with the reservoir rock or fluids can lead to severe
reservoir damage. When selecting candidates for hydraulic fracture treatment, a
careful candidate and treatment selection procedure is therefore of paramount
importance, to avoid any of the above problems.
2 • Introduction Stimulation Field Guidelines - Hydraulic Fracturing
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Fracture geometry and propagation
In-situ stress
The in-situ stress, as it affects hydraulic fracturing, is the local stress in a given rock
mass at depth. The three principal stress components of the local state of stress,
which are typically compressive, anisotropic and non-homogeneous, are the result
of the weight of the overlying rock (overburden), burial history, pore pressure,
temperature, rock properties, diagenesis, tectonics and viscoelastic relaxation. In
addition, drilling, production and fracturing can also alter some of these
parameters, thereby changing the local stress field.
For most sedimentary basins, the three principal stresses will be different, with the
vertical principal stress, σ1, which equals the weight of the overburden, being the
largest, and two unequal horizontal stresses, σ2 being the intermediate horizontal
stress, and σ3 being the minimum horizontal stress (see Fig. 1). The vertical, or
maximum stress component, can usually be obtained from the integration of a
density log. If such a log is unavailable, as a rule of thumb, a stress gradient of
1.0 psi/ft is generally a good approximation for this stress component. For the
magnitude and orientation of the in-situ horizontal stresses, actual measurements
are required to provide an accurate quantitative description, for which a number of
methods are available, which will be discussed later in this document.
Figure 1 – Fracture orientation is controlled by the in-situ stress field
The in-situ stresses control the fracture orientation (vertical or horizontal and the
azimuth of the fracture plane), vertical height growth and containment, surface
Stimulation Field Guidelines - Hydraulic Fracturing Fracture geometry and propagation • 3
σ1
σ3
σ1 > σ2 > σ3
σ2
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treating pressures, proppant crushing and embedment. Fractures are generally
planar and oriented perpendicular to the minimum in-situ stress (Fig. 1). For
horizontal wells, if drilled perpendicular to the minimum horizontal stress, the
created fracture will be longitudinal (Fig. 2). If the horizontal well is drilled parallel
to the minimum horizontal stress, the created fractures are expected to be
perpendicular to the horizontal well, and transverse fractures will be created
(Fig. 3). For horizontal wells and (highly) deviated wells drilled in an intermediate
direction relative to the direction of the in-situ horizontal stresses, non-planar
fracture geometry may be created near the wellbore. This will be discussed in the
next section.
Figure 3 – Transverse vertical fractures
4 • Fracture geometry and propagation Stimulation Field Guidelines - Hydraulic Fracturing
KOP
H,max
σ
H,min
σ
H,min
σ
Lf
KOP
H,max
σ
Hydraulic Fracture
H,max
σ
H,min
σ
Lf
D
Figure 2 – Longitudinal vertical
fracture
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Near-wellbore fracture geometry
The near-wellbore fracture geometry depends on the wellbore orientation with
respect to the minimum in-situ stress. Close to the wellbore the fracture may be
non-planar, associated with a reorientation of the initial fracture to the far-field
direction perpendicular to the minimum stress. This is illustrated for a horizontal
wellbore in Figure 4.
Figure 4 – Near-wellbore fracture geometry - influence of wellbore orientation
If the wellbore coincides with the far-field fracture plane (Figure 4a), no
reorientation will occur. The fracture is planar and provides good communication
with the reservoir. Hence, no problems are expected during the treatment; the
production improvement should be optimum.
Minimum stress
Vertical
Fracture
Wellbore
Perforation
Vertical
Minimum stress
Minimum stress
Vertical
c) Horizontal wellbore at 45° to far field
fracture plane
a) Horizontal wellbore in far field fracture
plane
b) Horizontal wellbore normal to far
field fracture plane
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Figure 4b shows a wellbore oriented normal to the far-field fracture plane. The
fracture initiates along the wellbore and then reorients perpendicular to the
wellbore. Thus, the fracture communicates with the wellbore over a limited length
only. The reorientation process causes a reduction in fracture width and increases
fracture rugosity and tortuosity. These characteristics promote treatment problems
(premature screen-out, high fracture propagation pressures) and reduce the near-
wellbore fracture conductivity. Also, multiple short fractures may be created near
the wellbore, as illustrated in Figure 4b, further aggravating treatment problems and
reducing fracture length.
The reorientation is less severe in case the horizontal wellbore is oriented in an
intermediate direction, see Figure 4c. Multiple fracturing may also be less. Still,
communication between wellbore and fracture could be reduced significantly. In
Figure 5 a summary is given of non-planar fracture geometry for different wellbore
situations relative to the direction of the in-situ stress.
Figure 5 – Near-wellbore fracture geometry
Recommendations have been established to optimise hydraulic fracturing in highly
deviated or horizontal wells. In the drilling phase, the wellbore should be oriented as
close as possible to the expected fracture plane (for example, in vertical direction or
with azimuth perpendicular to minimum in-situ stress). This recommendation is not
σv = σ1
σHmin = σ3
σHmax = σ2
θ
Single fracture
Single fracture Multiple fractures
Reoriented multiple fractures
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generally applicable, however, since in many cases the wellbore direction is
controlled by other factors. In the completion phase, the perforation policy should be
such as to optimise communication between fracture and wellbore and minimise
multiple fracturing. This is accomplished by dense, multiphase (60° or 120°)
perforating over a short interval (~ 1 m). During the treatment, the fracture should be
initiated at as high a flow rate as possible. Fracture reorientation becomes smoother
as the flow rate increases. During the initial stages of fracturing, a low concentration
of proppant should be used to further reduce the near-wellbore resistance.
Fracture containment
A hydraulic fracture grows primarily in the vertical and horizontal direction, having
a width which is much smaller than these dimensions. Given a single uniform
formation, a fracture would develop radially, i.e. equally in both directions (penny-
shape). However, vertical lithology contrasts are the rule and at some stage the top
or bottom part of the fracture will sense a change in environment. Usually, the
growth in the vertical direction decreases compared to the horizontal growth. This
process is called (vertical) containment. A fracture with a (horizontal) length much
larger than its (vertical) height is called rectangular. Figure 6 shows an example of
a fracture developing from radial to rectangular, illustrating fracture containment.
Figure 6 – Fracture containment
Predicting the fracture geometry in terms of fracture length and height is crucial,
given the height constraints applicable in most cases. Often, the fracture length
required from a production improvement point of view, can only be attained in the
presence of containment.
Fracture length
Fracture
height
Rectangular
Radial
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There are several parameters that can lead to containment. The most important is (a
contrast in) the in-situ stress. The containment depends on the magnitude of the in-
situ stresses relative to the fracturing pressure, as illustrated in Figure 7. In case the
in-situ stress of a neighbouring top or bottom formation exceeds the pressure
necessary to fracture the target formation, the hydraulic fracture can hardly extend
into that top or bottom formation (Figure 7a). If the stress contrast is smaller
(Figure 7b), some degree of vertical growth is expected.
Figure 7 – Fracture containment - influence of in-situ stress
Apart from variations in in-situ stress, fracture containment is influenced by other
formation parameters as well:
• Young’s modulus (stiffness), E. A larger E value in adjoining layers,
helps containment and gives a narrower fracture width.
• Poisson’s ratio, ν, which is directly related to the horizontal confining
stress generated by vertical loading. A high value of ν helps
containment.
• Permeability contrast. When a fracture runs into a zone of high leakoff,
it may become impossible for the fracture to penetrate that zone.
Often, contrasts in in-situ stresses and elastic properties are interrelated and occur
simultaneously. A simple rule of thumb is that a stress contrast of more than 1000
psi (7 MPa) acts as a stress barrier and causes the fracture to be contained.
The fracture geometry can be influenced in the completion stage by selective
perforating. For instance, by specifying that the fracture should not break through
the cap rock, the fracture length can be maximised by positioning the perforations
in the bottom of the pay zone.
Fracture
Wellbore
Perforations
Fracturing
pressure
Minimum stress
a Large stress contrast b Small stress contrast
Minimum stress
Fracturing
pressure
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Fracture propagation
Net pressure
The fracturing fluid pressure must exceed the minimum in-situ stress in order to
generate fracture width. Indeed, the fracture width is proportional to the pressure in
excess of the minimum in-situ stress. This excess pressure is called net pressure.
Two main processes contribute to net pressure. The first one is fluid friction:
pressure is required to squeeze the fracturing fluid through the fracture. The second
one is fracture propagation: energy, i.e. pressure, is required to generate new
fracture area.
In field applications, the net pressure tends to be quite independent of fracture
length. This indicates that it is dominated in many cases by fracture propagation
rather than by fluid friction. Net pressures typically range between 1 and 10 MPa
(145 and 1450 psi). The fracture propagation component of the net pressure can be
estimated from analysis of the pressure behaviour during a minifrac test, to be
discussed later.
Basics of fracture propagation
Fracture propagation is governed by four physical processes:
a) fracture fluid flow, giving rise to a viscous pressure drop within the fracture.
b) fracture fluid leakoff. Balancing volumes of fracturing fluid implies that
the frac fluid pumped, equals the fluid in the fracture plus the volume
leaked off. Fluid efficiency is defined as the fracture volume at the end of
pumping, divided by the total injected volume (i.e. pad plus proppant
laden fluid).
c) elastic opening of the fracture in response to an internal pressure distribu-
tion. Driving force is the net pressure. The displacements in the formation,
due to the creation of a hydraulically induced fracture, are relatively small
and inversely proportional to the rock Young’s modulus. As a result, the
formation can be assumed to deform in a linear elastic manner, independent
of the pressure level. Also, in high Young’s modulus formations, fluid
pressure gradients can be high during the initial stages of fracture growth.
d) breaking of the rock at the fracture tip. A fracture generates resistance to
propagation at the fracture tip, which is expressed in the stress intensity
factor KI. Linear Elastic Fracture Mechanics (LEFM), states that a fracture
will not advance until the stress intensity factor reaches a critical value, KIC,
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called fracture toughness, which is a material property. Values of KIC can be
measured in the laboratory on rock samples. Typical values, measured using
small samples, and without confining stress, are given in Table 1:
Rock KIC(psi.in1/2)
Siltstone 950 - 1650
Sandstone 400 - 1600
Carbonate 400 - 950
Shale 300 - 1200
Table 1 – Fracture toughness values for various rock types
KIC values can also be derived in the field from analysis of information
obtained from a minifrac test. This is done by determining the net fracture
pressure shortly after shut-in following a period of fluid injection. This
pressure is called overpressure, defined as the difference between the
instantaneous shut-in pressure and the minimum in-situ stress. The KIC
values thus obtained from field observations can be one or two orders of
magnitude larger than those measured in the laboratory, using small
samples. Such field-calibrated KIC values are called apparent toughness
values. These high KIC values are attributed to the field and scale
dependent process zone at the fracture tip. This field-calibrated KIC or
overpressure is then used as an input to a hydraulic fracture simulator (e.g.
ENERFRAC) to design the hydraulic fracture stimulation volume and
proppant injection schedule.
The value of KIC is related to the overpressure and fracture extent by:
KIC = A x Overpressure x RF
1/2
where A is a constant (1.128 for radial fracture extension and 0.767 for a
rectilinear fracture) and RF is the created fracture extent (equal to the
radius of a circular fracture, and equal to the height of a long contained
fracture).
Tip screen-out (TSO)
A normal hydraulic fracturing treatment in low permeability reservoirs, is designed
such that the pad (the initial proppant-free fracturing fluid) is depleted through
leakoff, when the proppant reaches the fracture tip. In MHF treatments, which
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require a large fracture length to achieve sufficient fracture conductivity, a
premature tip screen-out is to be avoided, by specifying sufficient pad.
In reservoirs of moderate to high permeability, where fracturing treatments are
intended to breach near-wellbore damage, relatively short, highly conductive
fractures are required. Fracture length does not affect the outcome of the treatment
as dramatically as in low-permeability reservoirs. Thus, the objective of a
fracturing treatment here is to maximise the fracture conductivity (propped fracture
width). This can be achieved with a so-called tip screen-out design, in which the
proppant reaches the fracture tip at an early stage of the treatment (by using a
relatively small pad volume), preventing the fracture from growing further. This
induces ballooning of the fracture – the fracture width increases, together with the
net pressure. The technique, Skinfrac for bypassing near-wellbore damage, or
Frac&Pack for sand control purposes, is discussed later in more detail.
Productivity improvement factor
For a given wellbore and drainage radius, the productivity improvement factor
(which is the productivity index of the fractured well divided by the productivity
index of the unfractured well) depends exclusively on the dimensionless fracture
length and the dimensionless fracture conductivity. Dimensionless fracture length
is defined as:
LD = L / re ,
and dimensionless fracture conductivity is defined as:
kf w
FCD = ______
k L
with: re = drainage radius (m),
kf = fracture permeability (mD),
w = fracture width (m),
L = fracture length (m),
k = formation permeability (mD).
The productivity improvement from a vertical hydraulically fractured well can be
predicted by a relation, developed by Prats for steady-state conditions, see Figure 8.
From this figure, the following conclusions can be drawn:
1) the productivity improvement factor increases with increasing fracture
length,
2) the productivity improvement factor increases with increasing fracture
conductivity. However, the maximum improvement is already obtained at
a dimensionless fracture conductivity of about 15. Thereafter no further
improvement is possible.
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Figure 8 – Productivity improvement factors resulting from hydraulic
fracturing treatments
These two conclusions are valid for all ratios of wellbore and drainage radius. They
have an important bearing on the design of hydraulic facturing treatments. In most
practical cases the fracture length is selected, guided by economic criteria (e.g.
fracturing costs vs accelerated production) and the dimensionless fracture
conductivity is selected to be at least fifteen (FCD ≥ 15 ). In practice, this leads to
the recommendation of deeply penetrating fractures in low-permeability reservoirs,
but since the incremental improvement or well productivity diminishes with length
(because the dimensionless fracture conductivity decreases with increasing length),
a balance between fracture characteristics and reservoir properties must be
achieved, to optimise the well deliverability. For high-permeability formations a
long fracture is not recommended. Here, short but wide fractures are required to
achieve the necessary fracture conductivity.
Fracture growth analysis
Much information can be derived from analysis of fracturing treating pressures
during the treatment, as developed by Nolte and Smith. The method can be applied
directly during the treatment, to adjust pump rate and/or fluid viscosity to obtain
optimum treatment results. It involves plotting the log of the net treating pressure
versus log of pumping time. On such a plot, four characteristic slope regimes can
be distinguished:
1
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
2
3
4
5
6
7
8
0
10
-3
10
-2
1.0
10
-1
Dimensionless fracture conductivity
Productivity
improvment
factor,
PIF
Dimensionless
fracture
length
10
2
10
1
re / rw = 2500
hf / h0 = 1.00
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- a small positive slope,
- a zero slope,
- a positive unit slope,
- a negative slope.
This is shown schematically in Figure 9.
Figure 9 – Log-log diagnostic plot for fracturing
A small positive slope of 1/8 to 1/4 indicates unrestricted lateral extension of a
fracture with a fixed height. This is the ideal situation of confined fracture growth.
A zero slope period is diagnostically very important. It indicates stable height
growth with continued propagation of length.
A positive unit slope indicates a restriction to horizontal penetration, typically
caused by proppant bridging or a tip screen-out. A higher positive slope indicates a
restriction nearer to the wellbore.
A reduction in pressure (negative slope) indicates unstable height growth from
fracturing through a barrier. This is generally undesirable and leads to inefficient
fracture extension.
The interpretation of the fracturing pressure responses shown in Figure 9, is
dependent on the assumptions of the particular model it was derived from. It also
requires knowledge of variations in bottomhole fracturing pressure during the job.
The analysis is made substantially more complex and uncertain when, as in the
typical case, only surface pressure is recorded. Nevertheless, the technique is
widely used by many service companies to interpret fracture behaviour during
pumping.
0
1000
100
1 10
Pumping Time, min
m=1/8 to 1/4
contained height
m=0
stable height
growth
m=1
restricted
height and
length
m<0
rapid or unstable
height growth
m>1
near well
restriction
Net
Pressure,
psi
100
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Hydraulic fracturing models
A number of hydraulic fracturing models have been developed over the years to
compute fracture dimensions in simple, to more complex, layered formations.
Basically, there are four types of fracturing models, either being used or being
developed in the Industry today:
• Two dimensional (2D)
• Pseudo three dimensional (P3D)
• Planar three dimensional (PL3D)
• Fully three dimensional (F3D)
Most 2D models require that a value for fracture height be input, so the length and
width can be calculated from the fluid volume and flow characteristics, via the
material balance equations. A common simplifying assumption is that the lateral
effects of a fracture are small compared to the vertical effects, and therefore can be
neglected. This condition is called plane strain, and implies that each cross section
acts independently of any other section, so that the mechanical analysis needs only
be performed in two dimensions. Plane strain can be assumed in a horizontal
geometry (Khristianovich, Geertsma and De Klerk model, KGD), and in a vertical
geometry (Perkins, Kern and Nordgren model, PKN).
P3D models were developed from the PKN model by removing the requirement of
constant fracture height. They use equations based on simple geometries (radial,
two-dimensional, elliptical) to calculate fracture width as a function of position and
pressure, and apply a fracture propagation criterion to both length and height.
Furthermore, they assume one dimensional flow along the length of the fracture.
PL3D models assume planar fractures of arbitrary shape in a linearly elastic
formation, two dimensional flow in the fracture, power law fluids, and linear
fracture mechanics for fracture propagation. The advantage of any PL3D
simulation is the ability to model the pressure drop laterally within the fracture.
F3D models for general 3D fracture propagation (including out-of-plane) have been
presented by several authors. A model that is truly a fully 3D model is needed to
simulate special conditions that cannot be handled by other models. However, the
numerous problems and the system of equations needed, have not yet been
developed to the point of realistic working models, that can be run in an operational
environment.
Hydraulic fracturing models are used in hydraulic fracture designs by the engineer
to choose the optimum pumping schedule (amount of pad and proppant) for a
fracture designed to achieve a certain productivity improvement. With such a
design tool, the role of the propagation model is to calculate as realistically as
possible the dimensions of the induced fracture for a certain pump schedule. Also
P02832_inside14.xpr 05-12-2000 15:40 Page 14

the propagation model can be used to aid in the determination of essential fracture
parameters ( such as leakoff coefficient, design overpressure and minimum in-situ
stress) by matching an observed shut-in pressure versus time plot from a microfrac
and/or minifrac test.
Basic models used in Shell
The earliest hydraulic fracturing models have a two dimensional character (2D), i.e.
the fracture was assumed to be either totally uncontained (radial or penny-shaped)
or totally contained. In the contained case, the fracture is either assumed to be very
short compared to its height (KGD) or very long (PKN). The KGD model
conditions could occur in treatments at shallow depths, or when the fracture is
allowed to slip along the interfaces between the pay zone and the barriers of
containment. The PKN model conditions usually occur in deep well treatments,
where slippage between the pay and barriers is not expected. For very long
contained fractures and using the same input data, KGD usually predicts a shorter
and wider fracture than PKN. However, the net pressure predicted by KGD is
usually smaller than by PKN. Both models are not based on overpressure-calibrated
design theories and both are single layer models. Therefore, these models are no
longer recommended for general use.
A more recent 2D model, ENERFRAC, was developed by Shell Oil, which is a
single layer model and which can take into account an arbitrary length to height
ratio, but it assumes the fracture to be totally contained (constant height) or totally
uncontained (radial). The model is overpressure-calibrated and it has been used
widely in Shell operations.
While the ENERFRAC model is still available in the ShellFrac (see next section)
package, a more recent multi-layer pseudo 3D model developed in Shell by Van den
Hoek (VdH model), is nowadays more often being used for design in Shell
operations. This model, which is overpressure-calibrated, includes the effects of
variations in the stress and fluid loss profiles and fluid friction in the fracture. The
pseudo 3D model determines the relative vertical and horizontal fracture
propagation, based on stress and leakoff profiles. These property profiles are given
in the form of a table, which allows a stress gradient or average properties to be
input for a given interval. The main difference between 3D and P3D models is that
the latter are only appropriate for long fractures (L ≥ 3H) since they essentially
employ a 2D fracture description.
Various fracture design programs
ShellFrac is a system that conforms to Windows standard commands, and which
can be used to perform the complete process of on-site optimisation of a fracture
treatment schedule. To this end, ShellFrac contains the applications FracDim, for
P02832_inside14.xpr 05-12-2000 15:40 Page 15

the optimisation of the minifrac and treatment volumes, FracData, for handling the
minifrac data obtained from the contractor, FracTest, for the analysis of the
minifrac treatment data, FracDesign, for the optimisation of a conventional or a
Frac&Pack treatment pumping schedule, AcidFrac for the calculation of etched
fracture dimensions in an acidfrac or WISPER treatment, and FraPS to calculate
the expected well deliverability, given certain propped fracture dimensions. A
schematic structure of ShellFrac with its applications is shown in Figure 10. The
application FracDesign is nowadays mostly run with the VdH model option.
Figure 10 – Schematic structure of ShellFrac with its applications
Various other commercial hydraulic fracture design programs are available, some
of which are mentioned below.
GOHFER (Grid Oriented Hydraulic Fracture Extension Replicator), a planar 3D
finite difference model of Marathon Oil, marketed by STIM-LAB, Inc.
FRACPRO, a P3D fracture model. This is a development of MIT, sponsored by
GRI, and now marketed by RES, Inc. and Pinnacle.
MFRAC-II, a pseudo 3D hydraulic fracturing simulator, of Meyer and Associates.
STIMPLAN, of NSI Inc, a state of the art 3D hydraulic fracture simulator.
TerraFrac, a fully 3D hydraulic fracture simulator, developed in 1984 by TerraTek,
under Shell Research (KSEPL) sponsorship.
In Appendix I some further information is given on these models, as well as on the
main aspects in which they differ from each other.
In addition, Schlumberger uses a proprietary program, called FracCADE.
FraPS FracDim FracData
ShellFrac
FracTest
Frac-
Design
AcidFrac
P02832_inside14.xpr 05-12-2000 15:40 Page 16

Selection of candidate(s)
Basic requirements
In order to get maximum benefit from the stimulation expenditure, a proper
candidate and treatment selection procedure is of paramount importance. In this
section the procedure to arrive at a proper selection of candidates and the most
applicable type of treatment, is discussed in some detail.
The basic requirements for a successful stimulation treatment are simple:
• The reservoir must contain adequate volumes of moveable
hydrocarbons.
• The reservoir pressure should be high enough to initiate and maintain
hydrocarbon flow towards the wellbore.
• The production system (tubing, flowlines, separators, etc.) can
accommodate the extra production.
• A professional treatment design, execution and supervision is of para-
mount importance.
The well and reservoir requirements will be dictated by economical constraints, but
the minimum requirements for successful fracturing treatments, may be translated
into the following rules of thumb:
Hydrocarbon saturation : 30% or more
Water cut : 50% or less
Gross reservoir height : 10 m or more. In horizontal wells, where trans-
verse fractures are expected, this requirement is
not applicable
Permeability : Gas less than 10 mD, Oil less than 50 mD*
* Skinfraccing can also be applied at higher permeabilities.
Stimulation Field Guidelines - Hydraulic Fracturing Selection of candidate(s) • 17
P02832_inside14.xpr 05-12-2000 15:40 Page 17

Reservoir pressure : Gas: at least two times the abandonment pressure
Oil: not more than 80% depletion
Production system : Current production not more than 80% of maxi-
mum capacity of facilities
It is stressed, that the above cut-off values are not rigid criteria, but merely
guidelines for a first selection of candidate wells. In general, there should be a clear
indication of substantial production gains (into the stock tank), provided the
treatment is planned and executed in an optimum manner. After this initial
screening, a more thorough evaluation of the well performance is required, to
further assess its suitability for a stimulation treatment.
Stimulation treatment selection
Already at an early stage of the evaluation, the most suitable type of stimulation
treatment may emerge. Figure 11 shows the general scheme for the selection of a
particular stimulation treatment.
As with any well treatment, hydraulic fracturing treatments require a number of
steps to be taken. The complete process is depicted in Figure 12.
The remainder of this document describes, in some detail, the most relevant aspects
of the selection and design process for hydraulic fracturing treatments. It will
enable the engineer involved in the field, to understand and contribute to the
process of selecting and designing the best suitable treatment, in close consultation
with the involved service company. Theoretical details have been limited as much
as possible. Readers interested in such details, are referred to the short list of useful
references at the end of these guidelines.
Fracture treatment selection
After selection of candidates for a fracturing treatment, a decision has to be made
as to which type of fracturing treatment to apply. Figure 13 shows a simplified
selection scheme.
18 • Selection of candidate(s) Stimulation Field Guidelines - Hydraulic Fracturing
P02832_inside14.xpr 05-12-2000 15:40 Page 18

Stimulation Field Guidelines - Hydraulic Fracturing Selection of candidate(s) • 19
Figure 11 – Stimulation treatment selection
Well input data
(Q, S, etc.)
Depleted or high-
gas / water cut?
K < 50 mD (Oil)
K < 10 mD (Gas)
Natural fracs?
Skin > 5
Sdam > 20%
of total S?
Sand problems ?
Sandcontrol
in place?
Completion fit
for fracs?
Workover justified?
Cause of
damage known?
Not a stimulation
candidate
Slanted/horizontal
sidetrack with acid
treatment
Investigate other
measures
(e.g. reperforation)
Matrix treatment
Low chance of success
Matrix treatment
High chance of success
Major hydraulic
fracturing treatment
Skinfrac treatment
(Frac&Pack)
yes
yes
no
yes
yes
no
no
yes
no
yes
no
no
yes
yes
yes
no
yes
no
no
no
P02832_inside14.xpr 05-12-2000 15:40 Page 19

Figure 12 – Fracturing treatment design process
Sand- Soft Hard Fractured
stone carbonate carbonate carbonate
Propped frac* + + + + + -
Acid frac - - + + +
WISPER - + + + + +
Propped acid frac - + - -
CFA - + + + + + +
* Including Skinfrac
Legend: + + Preferred + Reasonable - Poor
Figure 13 – Fracturing treatment selection
20 • Selection of candidate(s) Stimulation Field Guidelines - Hydraulic Fracturing
Treatment
selection
Treatment
design
Treatment
result
prediction
Operational
stimulation
program
Scheduling
and logistics
Site
preparation
Proppant
selection
Job execution
Problem well
identification
Fluid selection
Operational
constraints
Evaluation cycle
P02832_inside14.xpr 05-12-2000 15:40 Page 20

Fracturing fluids and additives
Introduction
The purpose of fracturing fluids is basically:
• to transmit the pressure from the surface to the bottom of a well, to
initiate a fracture,
• to hydraulically extend (or propagate) the fracture into the formation,
• to transport and distribute the proppant along the fracture,
• in acid fracturing, to create unevenly etched flow channels (see
Stimulation Field Guidelines, Part III).
The fluids selected for a fracturing treatment can have a significant influence on the
resulting propped fracture length and fracture conductivity. Fluids that leak off
rapidly into the formation will not extend the fracture to the desired length, and may
result in a premature screen-out. Moreover, if a significant amount of residue of the
gelled fracturing fluid remains either in the proppant pack, and/or as a filter cake at
the fracture face, the fracture conductivity and production performance of the
fracture may be considerably less than the design value.
Features of fracturing fluids
Fracturing fluids should, in principle, have the following properties:
• the friction losses in the tubulars should be small, to keep the
horsepower requirements as low as possible.
• the fluid loss to the formation should be as low as possible, i.e. it should
be an efficient fluid (the fluid efficiency is the fraction of fluid leaked
off to the formation, compared to the total amount of fluid pumped).
Stimulation Field Guidelines - Hydraulic Fracturing Fracturing fluids and additives • 21
P02832_inside14.xpr 05-12-2000 15:40 Page 21

• they should have an optimum carrying capacity to transport the propping
agent.
• they should have an optimum viscosity to create a maximum fracture
penetration into the drainage area of the well, in relation to an adequate
width for placing the proppant.
• after breaking, they should (ideally) be residue-free, to prevent damage
of the propped fracture.
• they should be compatible with the reservoir fluids and reservoir rock at
in-situ temperature and pressure, to prevent reduction in overall per-
formance.
• they should preferably be made up from fluids which are readily
available.
• they should not create a hazard to personnel and/or the environment.
• their preparation costs should be as low as possible.
The above requirements are to some extent conflicting, since the 1st and 5th
properties would require a low viscosity, while the 2nd and 4th would imply a high
viscosity. Therefore, the fluid system for a treatment should be carefully selected
and usually a significant amount of laboratory testing is needed to quantify the
fracturing fluid behaviour under in-situ conditions.
Types of fracturing fluid
The following types of fracturing fluid are commonly used:
• water-based fluids,
• oil-based fluids,
• emulsions,
• foamed fluids,
• liquid CO2 fluids (in certain areas only).
Water-based fluids
Water-based fluids are made up using fresh water or brine as a base. Through the
22 • Fracturing fluids and additives Stimulation Field Guidelines - Hydraulic Fracturing
P02832_inside14.xpr 05-12-2000 15:40 Page 22

use of gelling agents and other additives, water-based fluids can be made to satisfy
most requirements for a suitable fracturing fluid. They are versatile, usually
cheaper than other types of fracturing fluid, give few handling problems and are
virtually hazardless to personnel and/or environment. Water-based fluids are
readily available, give low friction losses and can be used over a wide temperature
range. However, they are not always compatible with the reservoir fluids and rock.
Viscosity is one of the most important qualities associated with a fracturing fluid.
Viscosity-producing, or gelling, agents for a water-based fracturing fluid to produce
a linear gel, are:
Guar gum. Guar is a natural, branched chain, polysaccharide polymer. It provides
a very good reduction in friction pressure, degrades fairly rapidly above 80°C, but
it contains 5 - 10% insoluble residue upon breaking. The chemical structure of guar
gum is shown in Figure 14.
Figure 14 – Chemical structure of guar gum
Guar derivatives, called hydroxypropyl guar (HPG) and carboxymethyl-
hydroxypropyl guar (CMHPG), which are basically chemically purified forms of
the natural guar gum, are also used. Their properties and viscosity developments
are similar to that of guar, but they hydrate faster at lower temperatures, give less
residue (about 1%) and have a higher temperature stability. Water containing high
concentrations of methanol, will also be viscosified.
Cellulose derivatives. Most commonly used is hydroxyethylcellulose (HEC), and
carboxymethylhydroxyethyl cellulose (CMHEC), a modified, natural straight chain
polymer. They provide a good reduction in friction pressure and they do not
degrade at temperatures up to 200°C. The cellulose fluids are very clean (low
residue), and are used when fracture conductivity is important. However, their
primary use today has been in gravelpack applications, where a non-residual, high-
viscosity fluid is required.
CH2OH
CH2
HO
O
O
O
C O C
H
H
H
H
m
m = ca. 400-500
m
mannose mannose
galactose
OH
OH OH
H
H
H
acetal linkage
H
OH
H
CH2OH
O
O
H
H
OH H
HO
P02832_inside14.xpr 05-12-2000 15:40 Page 23

Water-based fracturing fluids, which are polymer-free, can be prepared using
viscoelastic surfactants (VES). When the surfactant is added to water, the
molecules associate into structures called micelles. Entanglement of the micelles
results in a network that makes the fluid viscous, and gives the fluid proppant
carrying characteristics. The micellar structure of VES fluids is permanently
disrupted by contact with liquid hydrocarbons or formation water. The principal
advantage of VES fluids is that no residue is left in the proppant pack. Their main
disadvantages are their current limited temperature application, of up to 95°C, they
cannot be used in dry gas wells, and they cannot be used with resin-coated
proppants.
Crosslinked fracturing fluids
The viscosity of linear gels can be drastically increased by crosslinking the polymer
molecules in the solution. In Figure 15 the intramolecular crosslinking of HPG is
shown schematically.
Figure 15 – Intramolecular crosslinking of hydroxypropyl guar
Crosslinking results in an increase in viscosity from 5 to 100-fold in the range of
shear rates important for fracturing. Boron (B) is often used as the crosslinking
metal, followed by zirconium (Zr), and to a smaller extent, titanium (Ti), antimony
(Sb) and alumimium (Al). To prepare these fluids, guar gum or guar derivatives are
commonly used to viscosify the low viscous fluids. Maintaining the right pH is
essential for optimal crosslinking. The friction pressures lie between those of gelled
and ungelled water, the fluid loss control is better than with low-viscosity fluids,
and proppant transport is excellent. It is worth mentioning, that HEC suffers from
extreme difficulty in crosslinking; few metals or metal-chelating techniques are
currently available to crosslink HEC.
In Table 2, commonly used crosslinked water-based fracturing fluids are
summarised.
O O
O O O
O
O
O
O O
O
O
O
O
O
O
O
O
O
O
O
O O
O
O
O O
O O
O
O
O
O O
O
O
O
O
O
O
O
O
O O
O O
Mn+
P02832_inside14.xpr 05-12-2000 15:40 Page 24

Crosslinker Gelling Agent pH range Temperature,°C
B, non-delayed guar, HPG 8-12 20 - 150
B, delayed guar, HPG 8-12 20 - 150
Zr, delayed guar 7-10 65 - 150
Zr, delayed guar 5-8 20 - 120
Zr, delayed CMHPG, HPG 9-11 95 - 190
Ti, non-delayed guar, HPG, CMHPG 7-9 40 - 165
Ti, delayed guar, HPG, CMHPG 7-9 40 - 165
Al, delayed CMHPG 4-6 20 - 80
Sb, non-delayed guar, HPG 3-6 15 - 50
Table 2 – Crosslinked water-based fluid types
However, although crosslinked HPG systems can be pumped into deep, hot
reservoirs, severe shear degradation occurs when the fluid is crosslinked at surface
and then pumped at high rates down the tubulars. Since viscosity may thus be lost
permanently downhole, delayed crosslinked frac fluid systems have been
developed. Such systems require some time for the base fluid to take on a rigid
structure. A significant advantage of delayed crosslink systems is lower pumping
friction because of the lower viscosity in the tubing. Thus, the use of delayed
crosslink fluids yields a higher ultimate viscosity downhole and a much more
efficient use of available horsepower on location.
Some gel systems show a degree of gel "rehealing", in which the viscosity after a
period of high shear, gradually returns to its prior low-shear-rate value. Boron and
chromium crosslinked gels show a good rehealing behaviour at moderate
temperatures. Ti/Zr crosslinked gels do not show good rehealing behaviour. Gel
rehealing results from reforming of broken crosslinks, rather than from reforming
of broken polymer.
Oil-based fluids
Using gelled hydrocarbons is advantageous in certain situations to avoid formation
damage in water-sensitive oil-producing formations. Crude oil is relatively cheap
and compatible with formation fluids, but usually requires fluid-loss additives and
friction reducers and it has limited proppant carrying capacity. Gelled refined oil
(diesel oil and kerosine) and condensate are more expensive and their friction,
viscosity and fluid efficiency are similar to water gels.
The application of oil-based fluids is limited, however, by the potential fire hazard,
availability of the oil, and environmental restrictions. On the other hand, in some
remote areas oil may be the only reasonable choice of fracturing fluid. Oil-based
fluids should not be used when resin-coated proppant is used, because of their
P02832_inside14.xpr 05-12-2000 15:40 Page 25

adverse chemical reaction with the coatings of the proppant. Pumping pressures are
also higher because of a lower hydrostatic head of the hydrocarbon compared with
water. Therefore, only relatively shallow formations can be fractured with these
fluids.
Emulsions
Emulsion fracturing fluids have been used for many years. While some of the first
oil-based fluids were oil-external emulsions, water-external emulsions were
introduced in the mid seventies. These are stable oil-in-water emulsions, consisting
approximately of two volumes of oil and one volume of gelled water. They show
very low fluid loss and good proppant transport characteristics. Careful handling of
the blending/mixing of the two fluids is essential, since a small change in oil
percentage can drastically change viscosity and friction of the mixture. The
emulsion is broken in the formation when the surfactant that created the emulsion,
is adsorbed by the formation. Like all oil-based fracturing fluids, emulsions have
limited application due to environmental concerns.
Foams
Foamed fluids generally contain 60-80% vol. nitrogen and 40-20% vol. water with
surfactants (to stabilise the emulsion) and sometimes with a gelling agent and a
fluid loss control agent. Their application is attractive in shallow, low-permeability
gas wells and zones containing water-sensitive clays. They give high fracturing
surface pressures but rapid well clean-up due to low hydrostatic head, and the
inherent energising capability of the fluid, caused by the entrained gas. Foam also
has the advantage in that it places the minimum amount of fluid on the formation.
However, proper foam stability during the entire treatment is operationally difficult
to achieve, and blending of proppant concentrations of over 4 lbs/gal is not
advisable.
Liquid CO2
Liquid CO2 fracturing is a patented process (by Fracmaster) that was introduced in
1981. Since then, many fracturing treatments with liquid CO2 have been performed
in Canada, the USA and in Hungary. Proppant is added directly to liquid CO2 in a
specially developed blender. Conventional fluids rely on viscosity to transport
proppant into the fracture, wheras liquid CO2 treatments utilise turbulence to
transport the proppant in the fracture. Since liquid CO2 is non-cryogenic, it can be
pumped with standard high pressure equipment, as long as the liquid CO2 is
maintained above the vapour equilibrium. Dependent on the surface pumping
pressure, it is pumped at temperatures of –25 to –15°C.
P02832_inside14.xpr 05-12-2000 15:40 Page 26

The CO2 fluid system has the advantage of eliminating formation damage and rapid
clean-up with no residue left in the proppant pack. It is particularly applicable in
low permeability, dry gas reservoirs, where leakoff is to be minimised, to avoid
relative permeability damage effects. Oil wells do not respond as favourably to CO2
fracture treatments, compared to gas wells. Oil wells require a wider proppant pack,
and fracture widths generated by liquid CO2 are narrower than those which can be
produced with conventional frac fluids.
During a CO2 frac, all personnel in the vicinity must be equipped with hearing
protection, since the phase change from liquid to gas, when pumps are cooled down
or lines are emptied, is extremely noisy.
Fracturing fluid additives
Gelling agents and crosslinkers define the specific fluid type, and they are not
considered to be additives. Fluid additives are materials used to produce a specific
effect, independent of fluid type. When using additives, however, their relative
compatibility needs to be carefully verified. And in general, the question should be
asked whether the additive, mostly advocated by the service companies, is really
required. The basic principle of using additives in fracturing fluids should be to
keep it as simple as possible.
Mostly used additives are the following:
Biocides. Most waters used to prepare fracturing gels contain bacteria, originating
from contamination of either the source water or the storage tanks on location. They
produce enzymes that destroy the viscosity of the gel in the surface tanks. Biocides
effectively control bacterial contamination, but they do not always inactivate the
enzymes the bacteria have produced. Biocides should be used when the gel is pre-
mixed, and it is common practice to add them to the fracture tanks before water is
added, to ensure that the bacterial enzyme level is kept low. Materials such as
glutaraldehyde, chlorophenates, bleach, or raising the pH to over 12, effectively
control bacteria.
Sometimes biocides are also proposed to be added to avoid growth of anaerobic
bacteria in the formation, which otherwise could turn the formation crude sour
(H2S). However, this is not considered necessary in Shell operations, when the gel
is mixed on-the-fly. Biocides are usually omitted here, also since they add to the
cost of a treatment and pose disposal problems with the backproduced fluids.
Breakers. A breaker is an additive that enables a viscous fracturing fluid to be
degraded to a thin fluid, by reducing the size of the gelling polymer, allowing faster
clean-up. Breaker systems in use include enzymes, persulfates and high-
temperature oxidisers. In encapsulated form, they can be used in higher
concentrations for delayed, but more complete breaking. Their use depends on the
prevailing pH and temperature. Laboratory tests on breakers should be carried out
P02832_inside14.xpr 05-12-2000 15:40 Page 27

before incorporating them in a fracturing treatment.
Fluid-loss additives. The most common water-based fluid-loss additive is finely
ground silica flour, with particles ranging from 0.1 to 50 microns. Starches, diesel,
gums, resins and soaps are also being used and they tend to plug the face of the
fracture with very little penetration into the formation matrix. To achieve good
fluid-loss control, one must have not only a bridging material, but also a wall-
building material. The guar polymer eventually controls leakoff once a filter cake
is established.
Buffers. Common buffering agents are used to control the pH for specific
crosslinkers and crosslink times. Another important function is to ensure that the
fracturing fluid is within the operating range of the breakers or degrading agents.
Typical products are sodium bicarbonate, fumaric acid (a weak organic acid),
combinations of mono and disodiumphosphate, soda ash, sodium acetate and
combinations thereof.
Surfactants. A surfactant (surface-active agent) is a molecule that locates at an
interface, and has the ability to alter the prevailing conditions (wettability, surface
tension). A surfactant is always composed of two parts: a long hydrocarbon tail that
is practically insoluble in water, but soluble in oil, and a strongly water-soluble
head. Because there is partial solubility in oil and water, the surfactant will tend to
accumulate at the interface of these fluids. Surfactants provide water wetting,
prevent emulsions and lower surface tension. Reduction of surface tension allows
improved fluid recovery. Surfactants are available in cationic (positive), anionic
(negative) or nonionic forms. They are usually included in most fracturing
treatments.
Clay stabilisers. The injection of fracturing fluids, or a change in temperature,
pressure or ionic environment may mobilise clays and fines in the formation, which
can result in migrating particles to bridge in narrow pore throats, thereby seriously
reducing permeability. Clay stabilisers produce temporary compatibility of
fracturing fluid with water-swelling clays. The most commonly used clay-
stabilising agent is KCl, which prevents the dispersion of clay particles by
providing sufficient cation concentration to keep the negatively charged clay
particles in place. Almost all treatments in sandstone reservoirs are designed to
contain KCl. Other clay-stabilising agents are ammonium chloride and calcium
chloride, which act like KCl. Other chemicals that also prevent migration of fines
are certain modified polyamines, polymeric clay stabilisers and polymeric solutions
of hydroxyaluminium.
Fluid rheology
Knowledge of the flow behaviour of fracturing fluids is important in fracture
treatment design. Relations of shear stress as a function of flow are used to predict
pressure drops in tubulars and fractures. The fluid rheology also influences
P02832_inside14.xpr 05-12-2000 15:40 Page 28

proppant transport and fluid loss to the rock matrix. In fracture treatment design,
fluids are scheduled in such a manner as to provide treatment viscosities sufficient
to maintain adequate fracture widths, and to suspend proppant adequately.
Fluids are classified as Newtonian, when the ratio of applied shear stress, τ, and the
resulting shear rate, γ, is constant. The ratio τ /γ is the absolute viscosity, µ, and is
expressed in poises (1 poise = 0.1 Pa.s). Most fracturing fluids in which gelling
agents are used to generate higher viscosities, show non-Newtonian behaviour: the
ratio τ /γ is not constant. The flow behaviour of non-Newtonian fluids is commonly
described by the Power law, which relates shear stress and shear rate by:
τ = K’γ n’
in which K’ is called the consistency index and n’ the flow behaviour index. The
values of K’ and n’ describe the viscosity of the fracturing fluid as a function of
shear rate, at a certain temperature. The flow behaviour index (n’) describes the
shear-thinning behaviour of a fracturing fluid. The apparent viscosity of the fluid is
that given by:
µ a = τ/γ = K’ γ n’-1
In Table 3 some values of n’ and K’ are given for some base gels, as a function of
temperature. These were determined at a relatively low shear rates, representative
for the shear rate in a fracture. The data in Table 3 can be used for scouting
calculations.
20°C 65°C 100°C
n’ K’ n’ K’ n’ K’
FracFluid (Pa.sn
) (Pa.sn
) (Pa.sn
)
HEC 0.45 1.3 0.6 0.18 0.85 0.02
HPG 0.48 0.9 0.63 0.2 0.73 0.08
Guar 0.45 1.0 0.65 0.08 0.95 0.008
Table 3 – Power law indices for 40 lbs/1000 gal (0.5%) base gels
For Newtonian fluids, the flow behaviour index, n’, equals 1, and thus K’ represents
the viscosity. For a Newtonian fluid with a viscosity of 1 cP (e.g. water), the
corresponding K’ is 0.001 Pa.s.
Crosslinked gels cannot be adequately described by power law behaviour.
However, for engineering purposes, the value of K’ in Table 3, which is for a linear
base gel, can be increased 3 to 4 times for a titanium crosslinker, and 6 to 8 times
for a borate crosslinker. Usually, more detailed values of n’ and K’ can be provided
by the Service Companies for their fluids and fluid systems. As accurate tests for
P02832_inside14.xpr 05-12-2000 15:40 Page 29

the rheology of crosslinked fluids are difficult, which render viscosity data for these
fluids uncertain, it is usually a good idea to compare similar fluid systems from
different companies, while using field experience.
Measurement of rheological properties
The most common rheological test perfomed on fracturing fluids is testing of
apparent viscosity. Fracturing fluid viscosity is a function of shear rate,
temperature, polymer concentration, polymer molecular weight and the chemical
environment. Time is also a parameter, in that polymers can undergo degradation
from chemical reactions and physical deformation.
The rheology of gelled – but not crosslinked – fracturing fluids can be easily
determined with a Couette-type rotational viscometer. For this purpose the Fann
V-G meter model 35A is recommended. The test procedure is recommended in API
RP 39.
The rheology of crosslinked fluids cannot be easily determined. In view of the high
viscosity and sometimes viscoelastic properties of these fluids, a simple rotational
viscometer cannot be used. The only reliable data can be measured using complex
rotational viscometers or pipe viscometers. However, neither of these viscometers
are suitable for use at the wellsite.
A useful test on these fluids may be the determination of the crosslink time.
Crosslink times less than the fluid retention time in the tubulars could result in
reduced viscosity recovery after shearing in the perforations. Long crosslink times
could result in poor proppant transport. When the crosslink time has been specified
for a certain stimulation treatment, the vortex closure test may be used as quality
control prior to the treatment and during the job. This test consists of placing 250
to 300 cm3 of gel in a Waring type blender, which is then turned to a low rpm, just
sufficient to develop a vortex over the centre of the mixing blade without sucking
in air. As crosslinked viscosity develops, the vortex gets smaller and then closes
with the rolling motion characteristic of crosslinked gels. This closure time is
readily determined after observing a few tests. An alternative, qualitative test, is the
gel lipping test, which can be used to test the tendency for frac fluid to exhibit
consistency.
A novel rheological device was developed at Shell Research, the helical screw
viscometer (HSV). It is an easy-to-use rotational viscometer for determining the
rheology of both Newtonian and non-Newtonian fluids, with or without proppants,
and of crosslinked fracturing fluids with all the relevant additives, such as (delayed)
crosslinkers, encapsulated breakers and resin coated proppants. It has a built-in
temperature and pH probe and gives reliable results up to 200°C. However, the
device cannot be used at the wellsite.
P02832_inside14.xpr 05-12-2000 15:40 Page 30

Fluid leakoff
The fluid loss behaviour during a fracturing treatment has a large influence on
fracture penetration. Fluid loss depends on:
- type of fracturing fluid,
- type and quantity of gelling agent,
- type and quantity of fluid-loss additive,
- pressure differential across the fracture face,
- formation permeability and porosity (natural fractures!),
- reservoir fluid viscosity and compressibility,
- formation temperature.
The total rate and volume of the fluid loss in a fracture is described by the spurt loss
coefficient, Sp , and the overall leakoff coefficient, Ct.
Spurt loss is the volume of fracturing fluid lost instantaneously on initial exposure
to newly created fracture wall, per unit area. Spurt loss affects the rate and volume
of the fluid leakoff, and therefore the fracture growth. The value of Sp can be
obtained experimentally from laboratory testing. Values can usually be provided by
the Service Companies. Values derived from laboratory tests on small cores, may
not be directly translatable to field conditions. Typical values for Sp (in field units),
range from 0 to 0.1 gal/ft2
.
The overall fluid leakoff coefficient Ct , represents the long term, average, leakoff
behaviour over the duration of fluid exposure. Ct contains all the controlling leakoff
mechanisms of filter cake (Cw), fracturing fluid viscosity (Cv), and compressibility
of the reservoir fluid (Cc). A value of the overall leakoff coefficient is derived from
analysis of the minifrac test, to be discussed later. When no minifrac data are
available, for scouting studies, the value of Ct can also be calculated, using
reservoir and fracturing fluid data. Relevant expressions are given in Appendix II.
When the overall fluid loss is found to be high, e.g. exceeding a value of
0.005 ft/sqrt(min) for the preferred fracturing fluid, fluid loss additives could be
considered. For low-permeability reservoirs, liquid-hydrocarbon additives, such as
5% diesel, give good leakoff control. For higher-permeability formations, and for
control of leakoff to natural fractures, particulate additives, such as silica flour, may
be required. However, their use should be minimised, since they will also result in
reduced proppant conductivity, and fracture conductivity is critical for higher
permeability formations. Other measures to counteract excessive fluid loss, which
can be considered are using a higher pump rate or larger pad volume. Increasing the
polymer concentration may also help.
P02832_inside14.xpr 05-12-2000 15:40 Page 31

Fracture wall impairment
During each fracturing treatment, part of the fracturing fluid will leak off into the
formation. In some cases, this leaked-off fluid may reduce the absolute
permeability in the invaded zone of the fracture walls, by mechanisms such as clay
swelling, precipitation of solids, or mobilisation of formation fines. However, these
effects are mostly of minor importance, because of the linear flow behaviour
around the fracture, unless the depth of damage is very large, or if formation
permeability is reduced completely to zero.
More serious may be adverse relative permeability effects, which may occur in
some strongly oil-wet oil reservoirs and particularly in some tight gas reservoirs. In
such cases this may lead to a complete water block (so-called aqueous phase
trapping), which may require several months of production to clean up, before the
maximum gas flow rate is achieved. Such relative permeability effects may occur
if the initial water saturation is lower than the irreducible water saturation. Leaked-
off fluid will then reduce the relative permeability to gas in the invaded zone.
These effects may be avoided/reduced by minimising the invasive losses of
fracturing fluid. This can be achieved by the use of a low fluid loss system, the use
of bridging agents, or the use of oil-based or foamed fracturing fluids.
P02832_inside14.xpr 05-12-2000 15:40 Page 32

Proppants
Introduction
The purpose of proppant is to keep the walls of a hydraulically created fracture
apart, to maintain a conductive path to the wellbore after pumping has stopped. The
propped fracture must have a conductivity at least high enough to eliminate most
of the radial flow path, that exists around an unfractured well, and to allow linear
flow from the reservoir into the fracture.
For the design of a hydraulic fracturing treatment, it is important to select the right
proppant. For instance, if sand is used and it crushes in the fracture, well
productivity may be lost. However, if in such a case a proppant other than sand is
used, there is an increase in cost, which should be balanced against the expected
economics of the treatment.
Ideal proppant properties
The primary requirement for an ideal proppant for hydraulic fracturing is a
sustained high permeability under reservoir conditions. This requires:
- Sufficient stength to withstand proppant particle crushing under the
increased rock stresses arising from production and depletion.
- A uniform, preferably spherical shape. Well rounded particles are less
likely to bridge in the perforations or in the fracture. At high closing
pressure, they are less likely to crush under load.
- A narrow proppant size distribution, which helps to reduce point loading
and crushing of the proppant in the fracture.
- A minimum of over- and undersized particles (including dirt).
- Resistance to fracturing fluid, formation fluids and acid.
Stimulation Field Guidelines - Hydraulic Fracturing Proppants • 33
P02832_inside14.xpr 05-12-2000 15:40 Page 33

- Availability in a range of suitable sizes. Size not only influences
permeability, but also placement, since larger grains settle faster and
bridge more easily.
- Low density, preferably equal to that of the fracturing fluid, to avoid
proppant settling during transport in the fracture.
- Availability in large quantities, at an acceptable cost.
Proppant pack conductivity
The efficiency of a hydraulic fracturing stimulation is critically dependent on the
conductivity of the propped fracture. The main factors that affect fracture
conductivity are briefly discussed below.
Fracture closure stress
The conductivity of a proppant pack is a function of the fracture closure stress. As
a result of compaction, elastic deformation and grain crushing, the conductivity of
a proppant pack decreases with increasing closure stress (deeper reservoirs).
Increased closure stress can also be the result of reservoir depletion. Cycling of
stress, as would occur with periodic shut-ins of a well, also reduces fracture
conductivity irreversibly.
Figure 16 – Strength comparison of various types of proppants
34 • Proppants Stimulation Field Guidelines - Hydraulic Fracturing
0
1000
100
2000 10,000
6000
Closure stress, psi
High-strenght
proppant
Intermediate-
strenght proppant
Permeability,
Darcy
14,000
Resin-coated sand
Sand
P02832_inside14.xpr 05-12-2000 15:40 Page 34

Figure 16 shows the proppant pack permeability as a function of load for various
types of 20-40 mesh proppant. Ottawa sand looses most of its permeability as a
result of grain crushing above a stress of 6,000 psi. Between 6,000 and 8,000 psi,
the conductivity of precured resin-coated sand is better than that of Ottawa sand.
Intermediate strength proppant, has a much better conductivity up to 10,000 psi. At
higher closure stress, sintered bauxite performs better.
Particle size, shape, sorting
Proppant particle size has a significant effect on packed fracture permeability, and,
in principle, the larger the size, the higher the permeability of the proppant pack.
However, as stress levels increase, larger sand grains will crush earlier than smaller
sand grains, which will result in a poorer sorting and thus in a lower conductivity.
Particle shape (roundness and sphericity) also plays a role in the proppant pack
conductivity with increasing stress. When compared with other sands, the better
roundness, the more uniform size and the higher percentage of the monocrystalline
grains of Ottawa sand play an important role in reducing the amount of fines
generated under increasing closure stress. As a result, Ottawa sand performs better
than any other sand at closure stresses above 4000 psi.
Another important consideration of proppant size in the design of fracturing
treatments is that the perforation diameter must be large enough to prevent
proppant bridging during the treatment, and a minimum fracture width is needed to
allow the proppant to enter the fracture. When pumping 6 lbs/gal or greater
proppant concentrations, the perforation diameter must be on the order of six times
as great as the proppant particle diameter, as shown in Figure 17. For minimum
fracture width, the generally accepted values for this so-called admittance criterion,
require fracture widths in the range of two to three times the largest grain diameter.
Additionally, proppant transport should also be considered in the selection of the
size of propping agent. Even though a 12-20 mesh proppant may be much more
conductive than a 20-40 mesh proppant, the smaller proppant is much easier to
transport deeply into a fracture than the larger proppant.
P02832_inside14.xpr 05-12-2000 15:40 Page 35

Figure 17 – Bridging of proppants as a function of proppant concentration
In general, the use of two sizes of proppant in one job is not recommended. It may
result in a zone of poorer sorting of the proppant since mixing of the proppants
cannot be excluded.
Proppant embedment
If proppant particles penetrate the walls of the fracture under closing stress, the
effective permeability can reduce significantly, since the width of the fracture is
reduced. This is not likely to be a problem in deep, tight reservoirs where the
formation is hard, but it may be a problem, particularly in soft chalk reservoirs.
With the introduction of more sophisticated fluids, allowing more aggressive
designs with higher sand concentrations (e.g. 10 to 40 particles thick pack), this
problem has been virtually resolved.
Proppant concentration
Proppant concentration refers to the amount of proppant per unit area of fracture
wall (measured on one side only). Fracture conductivity increases with increasing
concentration of proppant in the fracture. This relationship does not hold for low
concentrations (< 2.44 kg/m2
), because of wall effects. This is caused by the greater
void volume between the outside layer of the proppant and the fracture wall, than
between the proppant layers. As a result, the permeability of a proppant pack is
greatly influenced by the outside layers when there are only a few layers of
proppant. This effect becomes negligible above about five layers of proppant.
During the early days of fracturing, much attention was given to creating high
0
8
2
4
6
0 2 4 6 8 10
Max proppant conc., LBS/GAL
Diam
perf
/
Av.
Diam.
proppant
30
No Bridging
Bridging
P02832_inside14.xpr 05-12-2000 15:40 Page 36

fracture conductivities by the use of monolayers of proppant. The very high
conductivity obtained from a (partial) monolayer, however, is unrealistic, since it is
very sensitive to filter cake effects, partial embedment, fluid residue, etc. This idea
has now been abandoned, except for very low formation permeability. The
application of high to ultra high proppant concentrations, resulting in multiple
layers of proppant, the conductivity of which is less sensitive to differences in
hardness, proppant pack damage, etc., is currently the preferred approach to create
highly conductive fractures.
Fracturing fluid residue
Actual fracturing fluids will always leave some residue in the proppant pack in the
form of polymer residue, unbroken gel particles, fluid-loss material, filter cake etc.,
thus reducing the conductivity of the propped fracture. The problem is most
pronounced when the volume of residue from the polymer is high, when polymer
concentration is high, when the concentration of proppant in the closed fracture is
low and when the stress on the fracture is high, causing lower porosity.
In laboratory testing of several fluids, the reduction in fracture flow capacity was
found to be greatest for crosslinked HPG fluids and least for emulsion fluids, as
shown below in Table 4.
Fluid Type Damage (%)
Polymer Emulsion 15 - 35
Gelled Oil 30 - 55
Linear Gel 45 - 55
Crosslinked HPG – Borate 25 - 50
– Ti/Zr 50 - 80
Liquid CO2 less than 10
VES fluids less than 10
Table 4 – Proppant pack damage from fracturing fluids
The above damage percentages are dependent on temperature, and the above
numbers were determined at around 60°C. Since higher proppant concentrations
increase proppant volume, while simultaneously reducing the fluid volume, fluid
residue plugging is mitigated by higher proppant concentrations.
Commonly used proppants
The propping agents currently in use by the Industry, are sand, intermediate
strength proppant (ceramic material) and high strength proppant (e.g. sintered
P02832_inside14.xpr 05-12-2000 15:40 Page 37

bauxite). All of these proppants can be coated with a resin. Resin-coated proppants
(RCPs) will be discussed separately in a later paragraph.
Sand
Sand is the most widely used proppant. Ottawa sand, a reworked moraine sand, is
a particularly pure, rounded, monocrystalline sand, which is commonly used as a
proppant (usually 12-20 or 20-40 mesh). Ottawa sand is the best known type of
sand in the Industry, and its use is generally recommended by Service Companies.
Another type of sand, Brady-type sand, has also been used in the past. It is a
rounded, polycrystalline sand, composed of more than one quartz crystal bonded
together, leaving cleavage planes in the whole grain. Because of its tendency to
produce fines under stress, this type of sand is not widely used anymore.
When large hydraulic fracture stimulation campaigns are planned, the large
amounts of sand involved may well justify replacing the expensive Ottawa sand,
imported from the USA, by local, cheaper sand. However, the local sand should be
thoroughly tested and evaluated in the laboratory to ascertain that it can provide
sufficient fracture conductivity under downhole conditions.
Intermediate strength proppant
The development of intermediate strength proppants was encouraged by the
licence situation of high strength sintered bauxite, in order to find less expensive
alternatives. However, the strength of this type of proppant is much closer to that
of sintered bauxite, than to sand. At closure stresses up to 10,000 psi, these
intermediate strength proppants can provide fracture conductivities similar to that
of high strength sintered bauxite, at significantly lower cost. Moreover, this
material has an advantage over sintered bauxite, in that it has a lower density,
approaching that of sand. It is therefore also called intermediate density proppant
(IDP). Some trade names of intermediate strength proppant are: CarboLite, Naplite
and Interprop.
High strength proppant
Glass beads were the high strength proppants in the early seventies. However, they
were abolished based on laboratory experiments which showed that glass beads
crush in brine at a much lower stress than in the absence of brine.
High strength proppants (e.g. sintered bauxite) are a development of the technology
used to make aluminium oxide abrasives. The use of sintered bauxite as a proppant
is patented by Exxon. Sintered bauxite beads are made by grinding a naturally
P02832_inside14.xpr 05-12-2000 15:40 Page 38

occurring bauxite ore, primarily from South America, into particles of about 1 µm,
followed by sintering at high temperatures to form beads of the required size and
shape. The impurities in the ore (about 11% w), particularly iron, are responsible
for the capability of these particles to sinter together.
The first sintered bauxite produced as propping agent in 1976, did not perform
satisfactorily because of the high angularity of the particles, a high fines content (up
to 15% w) and a high solubility in regular mud acid. Since then, the manufacturing
process has been modified, so that well-rounded, sintered bauxite beads can be
produced, which can withstand closure stresses exceeding 10,000 psi.
Some trade names of high strength proppants are: SinterProp, Carbo HSP,
SinterBall and CarboProp.
Resin-coated proppants
Resin-coated proppant is used for the following main objectives:
• to provide, with a precured coating, increased strength to the proppant
pack,
• to prevent the back production of proppant (see later).
Types of RCPs
The following types of RCPs can be distinguished:
Precured or tempered RCPs. These RCPs are totally cured and have fully reacted.
Traditionally, the function of the resin on precured RCPs is not so much to glue the
grains together, but to improve the strength and crush resistance of the proppant,
since the plastic coating distributes point loads over a wider area on the proppant
grains. It is especially used in combination with sand as a cost-effective alternative
for intermediate strength ceramic proppants. Precured RCPs are not being used for
the prevention of proppant back production.
Curable RCPs. This RCP is coated with a curable resin that only needs an increase
in temperature in order to cure. Curable RCP can either be precoated on the
proppant, or can be coated on the fly with a resin during a fracturing treatment. It
will form strong proppant packs, but has two potential disadvantages. Firstly, the
resin will cure without confining stress and it will therefore consolidate in the
wellbore after underdisplacement or premature screen-out. Secondly, the resin
coating of these proppants has a poor fluid compatibility, and the resin will interact
with the fracturing fluid chemistry. This is discussed in the next paragraph.
P02832_inside14.xpr 05-12-2000 15:40 Page 39

Partially cured or stress bonding RCP. The stress bonding RCP needs an increase
in both temperature and pressure to form a consolidated proppant pack. It will
therefore cure in the fracture upon closure, but it is designed not to form a
consolidated pack in the wellbore. The stress bonding RCP can either be coated
with a partially cured resin, or it consists of a curable resin that has been
encapsulated with a thin, fully cured layer. These types of RCP are generally less
reactive with fracturing fluids, but compatibility should always be checked. The
fact that also stress is required for consolidation, could be a potential disadvantage,
however. If the proppant is not homogeneously distributed over the fracture, a
poorly consolidated pack could exist in low stress regions. Partially cured RCP is
the most commonly applied type resin-coated proppant at present.
Interaction of RCPs with fracturing fluid
A proppant-carrying fracturing fluid is a complex mixture of several additives.
Many of these additives can react with the resin coating of RCP, resulting in a
reduced strength and/or poor frac fluid performance.
Crosslinker – Titanate and zirconate based crosslinkers can severely reduce the
strength of the proppant pack, since the crosslinker reacts with the active sites of
the resin. Hence, less crosslinker is then available for crosslinking of the fluid,
which leads to a reduced viscosity. However, this effect is not observed with borate
crosslinkers.
pH – Although borate crosslinker does not affect the strength of the RCP, it requires
a high pH to form crosslinks. Phenolic resins tend to dissolve in high pH solutions
and, depending on the type of RCP, the strength of RCPs can rapidly decrease when
the pH approaches 12. Furthermore, the dissolved resin lowers the pH of the fluid,
which causes the gel to become less viscous, or even change it into a non-
crosslinked linear gel that has no proppant carrying capacity. The mutual
interaction between RCPs and fracturing fluid becomes very important at elevated
temperatures (above 100°C) when a high pH is required to maintain proppant-
carrying capacity of the frac fluid. Partially cured RCPs have been successfully
used in combination with borate fracturing fluids in reservoir temperatures as high
as 150°C.
Oxidising breakers – Generally phenolic coatings have a tendency to interact with
the oxidising breaker that is added to break the crosslinked fluid after the treatment.
The breaker can be consumed by the RCPs, thereby leaving less breaker to break
the gel, which results in a more viscous fluid remaining in the fracture, poor clean-
up and a lower fracture conductivity. It can therefore be required to increase the
breaker concentration. However, the strength of the RCP pack is generally not
affected by the interaction with the breaker.
In general, RCPs cannot be used with VES fluids.
P02832_inside14.xpr 05-12-2000 15:40 Page 40

Proppant back production
Description
Proppant back production from hydraulically fractured wells is a major operational
problem to the Industry. Considerable amounts of proppant (up to 25-30%) can be
produced back from a created fracture. Proppant back production is the cause of
major operational problems, especially in offshore environments. It can lead to
hazardous situations due to erosion of pipelines and surface equipment.
Furthermore, adequate and costly disposal of the produced proppant is required.
Two phases of proppant back production can be identified:
- high rate proppant production during well clean-up,
- persistent proppant back production at a lower rate, without affecting the
well productivity.
This continuous and persistent proppant production can be explained by the
formation of channels in the proppant pack. Continuous proppant production can
be (temporarily) stopped by producing the well on a restricted choke.
From field studies and laboratory experiments, it has been observed that proppant
back production tends to increase with increasing fracture widths of over 1 cm
width. Proppant packs with a maximum of 7 layers of proppant (5 mm wide
fracture, with 20-40 mesh proppant) were observed to be more or less stable, thus
reducing the chance on back production of proppant. If with such relatively narrow
fractures sufficient fracture conductivity is achieved, no further prevention methods
are required. If more fracture width is needed (majority of cases), then methods for
the prevention of proppant back production are required.
Prevention methods
Different methods have been tried and proposed to prevent proppant back
production:
- beaning back the wells in order to reduce the amount of proppant
production to an operationally acceptable level,
- installing a screen in the wellbore,
- injecting a resin solution to consolidate the proppant pack,
- use of RCPs,
P02832_inside14.xpr 05-12-2000 15:40 Page 41

- addition of mechanical additives to the proppant (fibres, plastic strips),
- on-the-fly coating of the proppant with a liquid that makes the proppant
surface sticky and increases the surface friction.
When RCPs are used to prevent proppant back production, it is strongly
recommended to use 100% coated proppant instead of tailing-in only the last 10-
25% of the treatment, as practiced by some operators. Proppant transport within a
fracture is very complicated, and due to convection it is possible that the proppant
of the earliest stages of the treatment are very close to the perforations. Field
experience has demonstrated that uncoated proppant can be back produced when
only the last 10-25% of the proppant had been coated.
Stress cycling of the proppant pack, caused by variations in offtake from a well, is
thought to lead to long-term deterioration of the cured RCP pack strength. The
phenolic resins used in conventional RCPs form hard, but brittle proppant packs.
Curable RCP tail-ins have, however, been successfully used in horizontal wells
with transverse fractures and short perforated intervals.
New techniques to control proppant back production, have been introduced to field
operations during recent years. Relatively small particulates can be added to
proppant stages of a treatment to form an in-situ network between the proppant
grains. The resulting reinforced proppant pack can withstand higher flow rates than
proppant packs without particulates. Schlumberger have developed a proppant
flowback additive, called PropNet, consisting of fibres (polymer or glass fibre).
PropNet hardly reduces the permeability of the proppant pack at relatively low
values of closure stress (Figure 18). As with resin coated proppant, it is
recommended to use the fibres throughout the treatment, and not limit their
application to a tail-in.
Figure 18 – Conductivity of PropNet fibres
0
300
250
200
150
100
50
0 6000
1000 2000 3000 4000 5000
Closure stress, psi
Permeability,
Darcy
7000
20/40 Jordan
20/40 Jordan + PropNet
P02832_inside14.xpr 05-12-2000 15:40 Page 42

BJ recently introduced FlexSand, a proppant pack enhancement additive, which
consists of deformable particles that lock proppant in place. As a result, an
increased resistance to proppant flowback without harming the conductivity of the
proppant pack is claimed.
Another new technique is the use of a so-called surface modification agent, SMA
(SandWedge of Halliburton). The SMA is a new material that can be applied as a
liquid additive to water-based fluids on-the-fly during hydraulic fracture
stimulation treatments. The agent instantaneously coats the proppant with a thin,
tacky, non-hardening coating that dramatically increases intergrain friction thereby
reducing proppant flowback, and enhances the fracture conductivity. The major
selling points for SMA have been improved fracture conductivity and reduced shut-
in time. At the time of writing this document no further test results of the
effectiveness of SMA on proppant back production are available.
P02832_inside14.xpr 05-12-2000 15:40 Page 43

P02832_inside14.xpr 05-12-2000 15:40 Page 44

Data acquisition
Introduction
Field measurements are required to obtain information on the minimum in-situ
stress, both magnitude and orientation, and of fracture heigth and direction after the
hydraulic fracturing treatment. For this purpose, injection tests are carried out, logs
can be used and core measurements can be analysed.
It is generally accepted, that the most important parameter which determines the
degree of fracture containment, is the in-situ stress difference between bounding
rock layers and the pay zone. Therefore, knowledge of the stress state in the
reservoir and in the surrounding formations is essential to simulate in-situ
conditions and to assess the potential for fracture height growth. In addition,
determination of the in-situ state of stress at depth, gives insight into the expected
treatment pressures, as well as the fracture azimuth. In the following sections, the
main test procedures and analyses involved in the design and analysis of hydraulic
fracture treatments are presented.
Microfrac testing
General
Occasionally, microfrac tests are carried out in the pay zone and adjacent layers. The
small volume, low rate microfrac test is specially designed for in-situ stress
measurement. The fracture created is small (1 - 5 m radius), which provides
adequate depth resolution, i.e. allows stress measurement in relatively thin zones of
interest. Microfraccing requires high resolution pressure monitoring. Consequently,
a downhole pressure gauge near the perforations, run on conductor cable, is a
prerequisite. Note, that the fracture created in a large volume, high-rate minifrac (to
be discussed later) is typically one order of magnitude larger (10 - 50 m radius) and
usually extends across multiple zones with possibly varying minimum stress levels.
Hence, a microfrac is preferred for determining the stress levels in individual zones.
Stimulation Field Guidelines - Hydraulic Fracturing Data acquisition • 45
P02832_inside14.xpr 05-12-2000 15:40 Page 45

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