-
EXTRACTION OF NATURAL GAS BY
HYDRAULIC FRACTURING
MICHAEL JOSEPH KNUDSEN
SUPERVISORY COMMITTEE:
DR. LOC VU-QUOC, MECHANICAL & AEROSPACE ENGINEERING
DR. WILLIAM E. LEAR, MECHANICAL & AEROSPACE ENGINEERING
DR. R. KEITH STANFILL, INDUSTRIAL & SYSTEMS ENGINEERING
A THESIS PRESENTED TO THE UNIVERSITY OF FLORIDA COLLEGE OF
ENGINEERING IN
PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF
BACHELOR OF SCIENCE
MECHANICAL ENGINEERING
SUMMA CUM LAUDE
UNIVERSITY OF FLORIDA
2012
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Extraction of Natural Gas by Hydraulic Fracturing Knudsen,
Michael J. (2012)
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2012 Michael Knudsen
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Extraction of Natural Gas by Hydraulic Fracturing Knudsen,
Michael J. (2012)
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Dedicated to
my parents for their undying love and support throughout my
academic career and
my beautiful fianc for her patience and compassion
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Michael J. (2012)
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Acknowledgments
I would like to express my sincerest gratitude to Dr. Loc
Vu-Quoc for his continuous guidance
throughout this year; his passion and excitement for engineering
is inspiring, and I hope to have
that same fervor throughout my career.
I wish to thank Dr. R. Keith Stanfill for teaching me how to
break down any given process in a
useful and informative way. The knowledge I have gained as one
of his pupils will carry
forward into almost every aspect of my career as an
engineer.
I would like to thank Dr. William E. Lear for his uncanny
ability to explain many of the difficult
processes that engineers face every day. With influential
mentors like Dr. Lear still in the
discipline, I am confident that I will be able to conquer
anything with my engineering degrees.
Finally, I would like to thank the entire faculty and staff of
the University of Floridas College of
Engineering for the education I have received. Without a doubt,
I would not be the same person
today if I had never been a part of the Gator Nation.
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Table of Contents
Acknowledgments...........................................................................................................................
4
Table of Figures
..............................................................................................................................
6
List of Tables
..............................................................................................................................
6
Abstract
...........................................................................................................................................
7
Introduction
.....................................................................................................................................
8
Horizontal Drilling
..........................................................................................................................
9
Hydraulic Fracture Theory
............................................................................................................
11
Fracture Simulation and Discussion
.............................................................................................
23
Fracturing Fluids and
Additives....................................................................................................
26
Gas Locations and Environmental Concerns
................................................................................
28
Future Presence of Hydraulic Fracturing
......................................................................................
31
Conclusion
....................................................................................................................................
32
Works Cited
..................................................................................................................................
33
Appendix
.......................................................................................................................................
37
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Table of Figures
Figure 1: Horizontal Drilling
.........................................................................................................
9 Figure 2: Geosteering tool
...........................................................................................................
10 Figure 3: Crack propagation in an isotropic, linear elastic,
impermeable body. ......................... 11 Figure 4: Fracture
Modes I, II, and III
.........................................................................................
12
Figure 5: Tensile stress produced in a poroelastic material
......................................................... 13 Figure
6: PKN Model of Crack
....................................................................................................
16 Figure 7: KGD Model of a Crack
................................................................................................
16
Figure 8: Radial Model of a Crack
..............................................................................................
16 Figure 9: In-Situ Stress vs. Depth
................................................................................................
24 Figure 10: Minimum fracture extension pressure and maximum crack
width as a function of
radius of fracture
...........................................................................................................................
25
Figure 10: US Shale Gas Resources
.............................................................................................
28 Figure 11: U.S. Natural Gas Production Projections, 1990-2035
................................................ 31
List of Tables Table 1: Constant Propagation Parameters
..................................................................................
23
Table 2: Components in Fracturing Fluids
..................................................................................
27
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Abstract
Recent advancements in the controversial natural gas extraction
method known as hydraulic
fracturing, or fracking, has been accompanied with an
unparalleled wave of scrutiny over the
oil and gas industry. With the American energy industry shifting
toward green initiatives,
environmental safety questions regarding fracking need to be
answered quickly. Due to the
unconventional nature of this methodology, a sizeable amount of
existing literature has
conflicting, overly technical views on the theory and dangers of
hydraulic fracturing. The
purpose of this study is to familiarize scientists and engineers
with the topic of hydraulic
fracturing at an introductory level by using a basic theoretical
fracture model. For a Perkins-
Kern-Nordgren (PKN) fracture model, it was found that pressure
drop controlled fracture width
and thus higher injection rates and more viscous fluids
increased the maximum width of the
crack. Additionally, it was found that even with precautionary
measures in place, ground water
pollution is not likely but possible if faulting of the rock
formation occurs; this is a more
probable occurrence during horizontal rather than vertical
drilling. Minor seismic activity was
discovered to be a consequence of fracking but the order of
magnitude on the Richter scale made
this finding relatively insignificant.
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Michael J. (2012)
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Introduction
Nowhere is the promise of innovation greater than in
American-made energyBut with only 2% of the worlds oil reserves,
oil isnt enough. This country needs an all-out, all-of-the-above
strategy that develops every
available source of American energy a strategy thats cleaner,
cheaper, and full of new jobs. We have a supply of natural gas that
can last America
nearly 100 yearsAmerica will develop this resource without
putting the
health and safety of our citizens at risk.
President Barack Obama, 2012 State of the Union Address
With the American energy crisis rapidly growing, it is critical
that the energy industry
turns to cleaner and cheaper domestic fuel resources to stop
dependence on foreign oil. In 2009,
87% of natural gas consumed in the U.S. was produced in the
United States. By 2035, the U.S.
Energy Information Administration (EIA) projects that 46% of
domestically produced natural
gas will be obtained from shale rock formations, a 32% growth
rate from shale gas produced in
2010. If the U.S. energy industry is able to harvest the
domestic natural gas resources of
approximately 2,543 trillion cubic feet, American energy
companies could supply up to 100
years of natural gas at the 2010 U.S. consumption rate (U.S.
Department of Energy, 2012).
Hydraulic fracturing, colloquially referred to as fracking, has
become a controversial
method of extracting natural gas reserves due to environmental
concerns of groundwater
contamination. Fracking involves pumping high pressure fluids
underground in order to crack
rock formations that contain natural gas. The high pressure
fluids expand into pre-existing
fractures and forces crack growth underneath the surface. As the
cracks continue to expand,
natural gas is released into the pipeline and is transported to
the surface (Timmer, 2011).
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Horizontal Drilling
A new type of oil and gas drilling technique is known as
horizontal or directional drilling.
The well bore reaches depths of up to 10,000 feet in the rock
formation before gradually turning
horizontal and through the porous rock reservoir where the
natural gas is trapped. Figure 1
depicts the process of hydraulic fracturing and horizontal well
drilling at such depths (U.S.
Department of Energy, 2012). The corner at which this gradual
turn begins to take place in the
well is known as the kickoff point. Horizontal wells can extend
up to five miles away from the
initial drill rig on the ground which makes this new technique
extremely advantageous. As
hydraulic fracturing continues along the horizontal well,
several pockets of natural gas are able
to be extracted that would have previously required new wells to
be drilled. This has become
advantageous for natural gas wells with lower porosity because
of the ability to obtain gas in
lateral shale rock (Union Town Energy).
Figure 1: Horizontal Drilling
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In horizontal drilling, the reservoirs length works to the
drilling companys advantage, as
the well provides the ability to produce more natural gas from
one well. However, horizontal
wells are nearly 300% more costly than a standard vertical well.
Therefore, horizontal drilling is
only employed when it becomes economically feasible; this could
include higher production
rates, or lower permeability in the horizontal direction (Helms,
2008).
A horizontal well is drilled by adding a hydraulic motor or
geosteering tool above the
drill bit as shown in Figure 2. This allows the drilling
engineer to have steering control over the
well without having to explicitly alter the orientation of the
main drill. Sensors on the
geosteering tool allow the user to find current position, as
well as calculate the probable drill
path. These sensors also give the drilling engineer
environmental information such as pressures,
temperatures, and forces that the bit is seeing. These readings
are what drive the drilling fluid
and ultimately controls the hydraulic motor.
Figure 2: Geosteering tool (Helms, 2008)
Several improvements have been and will continue to be seen in
the methodology used in
horizontal fracturing. Distances achieved in horizontal drilling
have grown from 400 to 8,000
feet over the last 50 years. Further improvements continue to be
made by casing the well into
the rock formation which allows the operators to use a lower
density drilling mud. Once the
desired horizontal displacement is reached, fracking is
completed in intervals from the end of the
well back toward the vertical borehole to extract natural gas
from the reservoir (Helms, 2008).
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Hydraulic Fracture Theory
The theory behind fracking is simply that natural gas can be
extracted through porous
rock mass by creating enough pressure to stimulate crack growth.
This crack growth is created
by sending pressurized pumping fluid through the well to average
depths of 3000 meters at high
flow rates to expand into existing fractures (J. Daniel Arthur,
2008). When the drilling fluid
pressure is greater than the in-situ stress of the rock mass,
fracture occurs which allows the fluid
to continue expanding further into the material.
Some simplifying assumptions are necessary in order to create a
solvable model of the
hydraulic fracturing theory. As exemplified in Figure 3, the
material in which the steady-state
crack growth is assumed to occur in an isotropic, homogeneous,
linear elastic, impermeable
body. The pressurized fluid is assumed to be an incompressible
fluid acting with power-law
shear thinning flow.
Figure 3: Crack propagation in an isotropic, linear elastic,
impermeable body.
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As the pressure from the fluid rises above the combination of
the lowest principal stress
and the tensile strength of the soil material, tensile failure
occurs. While this can happen
naturally, human-controlled fractures are caused by continual
pumping of the fluid into the
borehole of the well. As the fluid is pumped, the pressure
increases and will first fracture normal
to the location and direction of smallest resistance.
In general, a fracture typically comprises of some form of
mechanical discontinuity in or
on a material. In crack growth, materials can experience three
different modes of fracture during
failure which can occur on an individual or combined basis as
shown in Figure 4. Mode I
fracture occurs when the walls of a crack propagate in a normal
direction away from one another.
Mode II fracture occurs in shear where the crack walls propagate
in a sliding away from one
another. Mode III fracture occurs in shear where the crack walls
propagate in a tearing direction
away from one another (Lacazette, 2000). Any of these three
modes of fracture may occur
during hydraulic fracturing depending on the orientation of
existing cracks in relation to the well
borehole that has been drilled. Mode I fracture is the most
common type of fracture mode that
occurs in hydraulic fracturing and will be assumed through the
remainder of this investigation.
Figure 4: Fracture Modes I, II, and III
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Figure 5: Tensile stress produced in a poroelastic material
(Fjar, Holt, Horsrud, Raaen, & Risnes, 2008)
The pressure required to propagate the fracture is the result of
three different
components: the pressure that maintains the crack opening in the
direction of the smallest
principal stress, the pressure seen while pumping fracking fluid
into the wellbore, and the
pressure required to overcome the tensile strength at the actual
fracture tip (Fjar, Holt, Horsrud,
Raaen, & Risnes, 2008). Figure 5 represents a poroelastic
structure in which pressure that occurs
between the pores is controlled at the valve, and the overall
effective stress is the difference
between the in-situ stress and the pore pressure as in (1).
(1)
The in-situ vertical stress will change with depth due in large
part to changes in density of
the rock formations along with the effects of the gravitational
force. Assuming a constant
gravitational acceleration and a depth, h, the vertical stress
can be found in (2) where the z is
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along the zenith axis which points radially inward to the center
of the earth and z = 0 lies at the
start of the well.
( )
(2)
Assuming a constant density gradient, this reduces to (3). Note
that this is an
oversimplification, as rock layers are bound to have varying
rock densities. For the purpose of
roughly estimating the vertical in-situ stress, , the constant
density gradient approximation is
appropriate.
(3)
The in-situ stresses and are taken to be the three principal
stresses acting in the
rock material and therefore are the eigenvalues of the stress
tensor at that location. The vertical
stress, , is represented by (3) while the horizontal stresses
and represent the maximum
and minimum horizontal stresses respectively. The maximum
horizontal stress is orthogonal to
the minimum horizontal stress and is larger due to additional
external tectonic stresses that exist
in the rock. The minimum horizontal stress can be related to the
vertical in-situ stress by (4)
(Environmental Protection Agency, 2011).
( ) (4)
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where is the Poissons ratio of the rock material, is the pore
pressure, and are
Biots parameters for the vertical and horizontal directions, and
is the external tectonic
stress. For simplification purposes, the Biots parameters are
taken to be and
Thus, the minimum horizontal in-situ stress reduces to (5).
( ) (5)
There are many models that have been employed in the study of
hydraulic fracturing
mechanics. In this study, a simplified linear elastic hydraulic
fracture (LEHF) model is
developed to determine how fracturing fluid viscosity and
injection flow rate affect the overall
growth of fractures. The Perkins-Kern-Nordgren (PKN) fracture
model is shown in Figure 6 and
is typically accepted for fractures where
where H/2 is the semi-major axis of an ellipse
and L is the length of the crack which propagates in the
direction of L. The PKN model assumes
plane strain in the vertical plane with a constant elastic
modulus. Similarly, the Khristianovic-
Geertsma-de Klerk (KGD) fracture model is represented in Figure
7 and is applicable for short
fractures. The KGD model assumes a plane-strain condition in the
horizontal plane and thus the
fracture propagation is independent of height. The radial
fracture model is shown in Figure 8
and assumes the crack propagation is radially outward from the
well borehole (Valencia, 2005).
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Figure 6: PKN Model of Crack (J. Adachi, 2007)
Figure 7: KGD Model of a Crack (J. Adachi, 2007)
Figure 8: Radial Model of a Crack (J. Adachi, 2007)
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The following analysis of a hydraulic fracture implements the
PKN fracture model for
crack widths resulting from Newtonian fluids in laminar flow for
vertical fractures (Perkins,
1961). The fluid dynamics of the fracking fluid that occurs
inside a crack is governed by
Poiseuille flow (Yuan, 1997). In general, fracture mechanics
follow three governing equations:
the elasticity equation, the lubrication equation, and the
continuity equation. For the purposes of
this study, the following assumptions were made (Perkins,
1961):
Assumptions:
2-Dimensional
Laminar flow
Vertical fracture
Elliptical crack
Brittle, elastic rock material
Isotropic
Constant rock material properties
Incompressible Newtonian fluid
No leak-off in the fracking fluid
Constant fluid injection rate, Q (implies negligible leak-off
and accumulation)
Constant fluid viscosity,
Thin film lubrication theory, h/L
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Perkins and Kern have found that the propagation of a crack is
completely driven by the fluid
pressure drop through the aperture. Beginning with the Fanning
equation yields (6):
(6)
where f is the friction factor, v is the velocity of the fluid,
is the density of the fluid, and De is
the equivalent diameter. For laminar flow, the friction factor
is defined as in (7):
(7)
According to Perry, for an ellipse with an eccentricity of
approximately zero (Perry, 1950),
(
) (8)
where RH is the hydraulic radius (which can be computed as the
area divided by the wetted
perimeter), and is a proportionality constant. The velocity of
the fluid in the fracture can be
expressed as the flow rate per unit area in the elliptical crack
as shown in (9) for laminar flow:
(9)
Using laminar flow on the same ellipse, the pressure gradient
can be written as in (10):
(10)
By equating (6) and (10) and substituting (7), (8) and (9), one
can solve for the proportionality
constant as in (11)-(16).
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Michael J. (2012)
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(
) (
)
(11)
( )
(12)
(13)
[ ( )]
(14)
(15)
As , the proportionality constant can be solved for and is
assumed to remain constant
throughout the crack propagation.
(16)
The Reynolds number for laminar flows (Re < 2500) is defined
in (17). By substituting (8) and
(9), and expressing the fluid density in terms of the specific
gravity, (17) can be simplified into
(20) as shown below. A condition exists for laminar flow, (
)
so that the Reynolds
number does not exceed 2500; these equations are only valid for
this criterion (Perkins, 1961).
(17)
(
) (
)
(18)
( )
(19)
( )
(20)
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Michael J. (2012)
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Substituting (7), (8) and (9) into (6), we see that:
(
( )
)( )
( )
( )
( )
(21)
This crack width is a function of the pressure, so a separation
of variables is performed in
equation (21) to solve for the effective pressure distribution
by substituting the Sneddon equation
in (23); the Sneddon equation is used to solve for the crack
width at any point along the fracture.
Assuming Qx is a constant, in other words there is no leakoff
and no accumulation that takes
place, equations (22) and (23) are combined with known initial
conditions and integrated to yield
the pressure distribution in (29).
( )
( )
(22)
( )( )
(23)
( )
( ( )( )
)
(24)
( ) ( )
( )
(25)
( )| (26)
( ) ( )
( )
( )
(27)
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21
( )
( )
(28)
( ) [
( ) ]
(29)
Plugging (29) back into (23) yields the following:
( )
[
( ) ]
(30)
[ ( )
]
(31)
Assuming a constant Poissons ratio of v = 0.15, equation (31)
becomes:
[
]
(32)
Where Q is expressed in (bbl/min), is expressed in (cP), L is
expressed in (ft), and E is
expressed in (psi). By applying the dimensional analysis in
(33), the width equation becomes
equation (34) as derived by Perkins and Kern.
(
)(
) (
) (
) (
)
(33)
[
]
[
]
(34)
R.A. Sack derived Eq. (35) by means of an energy balance. This
is the minimum pressure that is
required to overcome the pressure difference due to the in-situ
stress and extend the fracture
(Perkins, 1961).
( ) [
( ) ]
(35)
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Where is the specific surface energy of the rock and C is the
fracture radius. Equation (35)
yields that the minimum pressure required to extend the fracture
varies inversely as in the square
root of fracture radius given a constant specific surface
energy, modulus of elasticity, and
Poissons ratio (Perkins, 1961). The total crack width for a
uniform pressure acting over the
surface of the crack in a plane perpendicular to total earth
stress yields (36):
( )( )
(
)
(36)
where C is the maximum fracture radius and r is a variable along
the direction of C. The
maximum crack width occurs when r = 0 (Perkins, 1961).
( )( )
(37)
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Fracture Simulation and Discussion
In this study, a MATLAB model for hydraulic fracturing crack
growth was developed
using the Perkins-Kern-Nordgren (PKN) model geometry and the
hydraulic fracture theory
previously described. The model was meant to show how minimum
fracture pressure and
maximum aperture width varied with radius of fracture. A set of
parameters displayed in Table 1
were used as constants throughout the fracture simulation. These
values were taken from
averages found in the literature (Hydraulic Fracturing
Analysis). The simulation was performed
for up to a fracture radius of 200 ft away from the wellbore.
The MATLAB code for this
simulation can be found in the Appendix.
Table 1: Constant Propagation Parameters
Constant Propagation Parameters
Poissons Ratio
Crack Height
Youngs Modulus
Specific Surface Energy
Specific Gravity
Max Radius of Fracture
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Figure 9: In-Situ Stress vs. Depth
Figure 9 shows how the in-situ stress varies as a function of
depth in the horizontal and
vertical directions. As natural gas well depths are reached, the
vertical in-situ stress begins to
greatly out-weigh the minimum-horizontal stress. This means when
pressurized fluid is pumped
into the wellbore, the pressure will cause fracture in the
horizontal direction since the horizontal
in-situ stress will be overcome more easily. If the tectonic
stresses are high enough however, the
horizontal stress can be larger than the vertical in-situ
stress. In this scenario, the fracture would
propagate in the vertical direction.
0 10 20 30 40 50 60
0
500
1000
1500
2000
2500
3000
Stress ( [MPa])
Depth
(h [
m])
In-Situ Stress vs. Depth
v
h
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Figure 10: Minimum fracture extension pressure and maximum crack
width as a function of radius of fracture
Figure 11 shows the plots of minimum fracture extension pressure
(35) and maximum
crack width at the wellbore (37) as a function of radius
fracture. It can be seen that crack widths
are controlled by the pressure drop in the fluid for static
conditions with no fluid leak-off. For
very small fracture radii, extremely high injection pressures
are necessary to fracture the walls.
The higher pressures, however, would widen the crack faster,
allowing the injection pressure
required to drop even further. The fluid pressure at the crack
tip asymptotically decreases toward
the in-situ stresses in the ground due to tectonic stress. As
seen here, the pressure drop in the
fluid drives the crack width propagation; the larger the
pressure drop, the larger the crack width.
By association, high fluid injection rates, Q, and fluids with
larger viscosities (more proppant
slurry), , tend to produce larger crack widths while low Q and
will result in slender cracks
(Perkins, 1961).
0 20 40 60 80 100 120 140 160 180 2000
20
40
60
80
100
120
140
(P-
), m
in f
ractu
re e
xte
nsio
n p
ressure
(psi)
c, radius of fracture (ft)
0 20 40 60 80 100 120 140 160 180 2000
0.005
0.01
0.015
0.02
0.025
0.03
Max C
rack W
idth
at
Well
Bore
(in
)
Min Fracture Extension Pressure
Max Crack Width
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Fracturing Fluids and Additives
Hydraulic fracturing can be performed using a multitude of
various fracking fluids.
These fracking fluids may be selected depending on the type of
rock and depths at which
fracturing is desired. A typical fracture process involves four
stages in which the following types
of fracking fluids are used: a prepad, a pad, a proppant, and a
flush. A prepad is a low-viscosity
saline solution pumped down into the borehole to prevent rock
formation damage and typically
contains some form of fluid loss prevention additives and
surfactants. Subsequently, a viscous
pad fluid is initially pumped into the borehole and pressurized
to actually produce the fractures.
Proppants are particles that are then added to lower viscosity
fracking fluids to sustain fractures
because closure can occur pretty quickly due to the high
underground pressures. Finally, flush
fluids are used to clean out the fracture fluid from underground
(Fink, 2003).
Fracking fluids are often considered to be a water-based,
oil-based, multiphase, or
surfactant-based gel that may or may not contain a proppant
pack. In the majority of cases,
water-based gels are used but are becoming more controversial
due to the residue they leave in
rock formations after fracking is completed (Hydraulic Gel
Fracturing, 2005). These water-
based solutions contain additives that precipitate proppant
delivery and stimulate crack growth.
There are certainly pros and cons to each type of fracking
fluid. Oil-based fluids tend to have a
higher risk of explosion or fire than do water-based fluids.
Multiphase fluids are fracturing
fluids that contain a second phase and are typically categorized
as foams and emulsions. These
fluids can be obtained by adding various gases or hydrocarbons
to change fluid properties such
as viscosity and temperature sensitivity. Foams tend to be lower
pressure while emulsions tend
to be higher pressure and both are low temperature fluids that
lose viscosity with increasing
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Extraction of Natural Gas by Hydraulic Fracturing Knudsen,
Michael J. (2012)
27
temperature. Due to the additional phase that is added to the
fracturing gels, multiphase fluids
are often more expensive than water-based and oil-based fluids.
Surfactant-based fluids are
newly developed fluids that significantly improve leak-off
control and proppant delivery. Other
surfactant-based fracking gels are currently being developed to
reduce the damage seen in
individual fractures which will ultimately diminish the overall
reservoir damage. Table 2,
reproduced from Oil Field Chemicals, displays various components
and functions of additives
and fracturing fluids (Fink, 2003).
Table 2: Components in Fracturing Fluids
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Gas Locations and Environmental Concerns
According to the United States Energy Information Administration
(EIA), shale gas
makes up 60.64 trillion cubic feet (tcf) of total natural gas
production each year which is nearly a
quarter of annual U.S. natural gas production. Figure 11 shows
the shale gas map of the U.S. as
of 2011, with the largest reservoirs, the Marcellus,
Haynesville, and Barnett shale formations
comprising of over 500 trillion cubic feet of natural gas
resources. Another notable player is the
Bakken formation in North Dakota, which is primarily a shale oil
reservoir (U.S. Energy
Information Administration, 2011).
Figure 11: US Shale Gas Resources (U.S. Energy Information
Administration, 2011)
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With the American energy industry trending toward green energy,
profitable natural gas
production is becoming a critical source of revenue for
successful oil and gas companies.
Natural gas is considered a cleaner form of energy due to its
lower levels of carbon emissions
during combustion when compared to other natural resources. With
new approaches like
hydraulic fracturing making its way into industry, catastrophic
events such as the 2010
Deepwater Horizon oil spill have caused environmental concerns
regarding oil and gas
technology to be at an all-time high. Among other concerns,
environmentalists are worried about
the effect hydraulic fracturing is having on contaminating
drinking water, causing earthquakes or
other seismic activity, and ruining the land by introducing
foreign chemicals into the soil (U.S.
Department of Energy, 2012).
With water-based fracking fluids constantly being used, some
environmentalists are not
only concerned about contaminating groundwater but also with the
amount of water used to
perform hydraulic fracturing. For a typical natural gas well,
approximately 4.5 million gallons of
water are used during the hydraulic fracturing process; this
number is only expected to increase
with the growing production of natural gas. However, many
companies currently drilling for
natural gas use resources other than fresh drinking water to
achieve these amounts including
municipal wastewater, groundwater, and reusing fracking water
(Chesapeake Energy). Another
concern is the contamination of the ground water in aquifers
surrounding gas wells. Several laws
have been implemented into industry by the Ground Water
Protection Council (GWPC) in order
to regulate the environmental consequences of hydraulic
fracturing on groundwater sustainability
and quality. According to the GWPC, the potential for hydraulic
fracturing to adversely affect
ground water aquifers is as low as one in 200 million
(Chesapeake Energy). This is because
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Extraction of Natural Gas by Hydraulic Fracturing Knudsen,
Michael J. (2012)
30
most underground aquifers are less than 1,000 feet deep, while
hydraulic fracturing occurs up to
10,000 feet deep, i.e., significantly below the water table
(Baker Hughes, 2011).
However, since most fracking fluids are water-based, other oily
chemical additives tend
to have lower densities than water and at high pressures
underground can start to separate out of
the fracking water. This separation ultimately allows for the
fracking chemicals to become
pollutants in naturally occurring groundwater formations by
making their way through the shale
rock. More often than not, pollution due to hydraulic fracturing
is caused by a failure in the well
casing or by geological faulting due to high fracking pressures.
According to a study done by
Otsego 2000, from a pressure standpoint, the horizontal
hydrofracturing of shale is effectively
the explosion of a massive pipe bomb underground (Northrup,
2010). During these effective
explosions, faulting may occur that creates a path for natural
gas or fracking fluid to escape to
the underwater aquifers. The Environmental Protection Agency has
not released an official
statement regarding the effects hydraulic fracturing has on
drinking water and is currently
investigating in a 3-year study (United States Environmental
Protection Agency, 2012).
Another growing concern of environmentalists is seismic activity
induced by hydraulic
fracturing. In multiple studies, it has been found that
hydraulic fracturing does cause an increase
in seismic activity, however, on the Richter scale, these minor
tremors typically rank somewhere
between -4.5 to -1 which are not felt above ground. According to
Oklahoma seismologist Austin
Holland, the seismic activity caused by hydraulic fracturing is
really quite inconsequential
(America's Natural Gas Alliance). In accordance with Holland,
the U.S. Department of Energy
officially stated that hydrofracturing to intentionally create
permeability rarely creates unwanted
induced seismicity large enough to be detected on the surface
even with very sensitive sensors,
let alone be a hazard or an annoyance (Colorado Oil & Gas
Association, 2012).
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Extraction of Natural Gas by Hydraulic Fracturing Knudsen,
Michael J. (2012)
31
Future Presence of Hydraulic Fracturing
According to the EIA as of 2012, the United States has
approximately 2,214 tcf of
technically recoverable gas. With lower drilling costs and a
shift toward green energy, it is
plausible that natural gas production will significantly
increase over the next twenty years.
Figure 12 shows the EIAs natural gas projections through 2035.
President Obamas 2012 State
of the Union Address statement that the U.S. has enough natural
gas to provide power over the
next 100 years is true based only on the 2010 production rate.
With the growth projections seen
in Figure 12 comes higher demand, and thus higher production
rates would be required for
natural gas drilling agencies. Although natural gas production
is still in its early stages of
economic feasibility, natural gas certainly appears to be
quickly making its way to the global
energy market.
Figure 12: U.S. Natural Gas Production Projections, 1990-2035
(U.S. Energy Information Administration, 2011)
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Extraction of Natural Gas by Hydraulic Fracturing Knudsen,
Michael J. (2012)
32
Conclusion
In conclusion, the controversial method of hydraulic fracturing
is going to be a critical
component of the oil and gas industry over the next 30 years.
There are many tools available to
engineers today that can be help model hydraulic fracturing, but
the fundamental models stem
from crack propagation governed by the elasticity, lubrication,
and continuity equations. As
outlined by Perkins and Kern, it was found that crack widths are
controlled by the pressure drop
in the fluid for static conditions in laminar flow. In general,
high fluid injection rates and highly
viscous fluids are more advantageous in expanding an aperture.
Some of these highly viscous
fluids begin to behave like a non-Newtonian fluid which changes
the analysis quite a bit.
Fracking fluids are delivered in three main stages: a prepad
(surface protection and preparation),
a frac pack (which includes a pad such as water and proppant
such as sand), and a flush which
cleans out the fracture fluid after the natural gas has been
extracted. Proppants are necessary
additives to fluids because the particles are used to prevent
closure in the fractures due to the
highly compressive stresses seen underground. Although no
official statement has been released
by the EPA regarding the safety of fracking, there have been
some observations where fracking
has caused an increase in pollutants in the groundwater around
drilling sites as well as an
increase in seismic activity. However, fracking has been
performed for well over 50 years and is
often employed in natural gas and oil wells today. With the
surge in green initiatives in the
American energy industry, the U.S. will more than likely
experience a large growth as predicted
by the EIA. This recent boom in natural gas means perfecting the
understanding of this
technology is pertinent to the future profitability of the
energy industry as well as the safety of
the environment.
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33
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37
Appendix
MATLAB CODE:
%This MATLAB simulation is based on the PKN crack model
%Perkins, T.K., Kern (1961). Widths of Hydraulic Fractures.
%Journal of Petroleum Technology, 937-949.
%Constant parameters H = 40; %ft Q = 30; %bbl/min mu = 4; %cP
SpGr = 0.9; %dimensionless parameter E = 4e6; %psi nu = 0.15; c =
0:1:200; %fracture radius, ft alpha = 0.01; %specific surface
energy Pm_sig = sqrt(pi*alpha*E./(2*(1-nu^2).*c)); %minimum
pressure difference W = 8.*(Pm_sig).*c*12/(pi*E); %max crack width
[ax,h1,h2] = plotyy(c,Pm_sig,c,W) %double plot
%figure properties axis(ax(1),[0 200 0 140])
set(ax(1),'YTick',[0 20 40 60 80 100 120 140])
set(get(ax(1),'Ylabel'),'String','(P-\sigma), min fracture
extension pressure
(psi)') axis(ax(2),[0 200 0 0.03])
set(ax(2),'YTick',0:.03/6:.03)
set(get(ax(2),'Ylabel'),'String','Max Crack Width at Well Bore
(in)') set(h1,'LineStyle','-','linewidth',1.5)
set(h2,'LineStyle','--','linewidth',1.5) xlabel('c, radius of
fracture (ft)') legend('Min Fracture Extension Pressure','Max Crack
Width')