Geomechanical Modelling of Stress

Geomechanical modelling of stress
magnitude and orientation across fault and

its relation to hydraulic fracturing
Ehtesham Karatela, B.S. (University of Karachi)
This thesis is submitted in partial fulfilment of the requirements for the
Master of Science (Petroleum Geoscience)
Australian School of Petroleum,

The University of Adelaide
October, 2012
Contents
Contents........................................................................................................................................I
ABSTRACT .............................................................................................................................. III
ACKNOWLEDGEMENTS......................................................................................................... IV
Chapter 1 ..................................................................................................................................... 1
Introduction ................................................................................................................................. 1
1.1 Hydraulic fracturing ....................................................................................................... 1
1.2 Influence of stress.......................................................................................................... 1
1.3 Methodology ................................................................................................................. 2
1.4 Aims and Objective ............................................................................................................. 3
Chapter 2 ..................................................................................................................................... 4
The in situ Stress tensors............................................................................................................... 4
2.1 Introduction ........................................................................................................................ 4
2.2 Anderson’s Classification .................................................................................................... 4
2.3 Stress around a borehole ...................................................................................................... 5
2.4 Stress at the fault tips ........................................................................................................... 6
Chapter 3 ..................................................................................................................................... 8
Measurement of stress magnitude and orientation ........................................................................... 8
3.1 Introduction ........................................................................................................................ 8
3.2 Borehole breakouts.............................................................................................................. 8
3.2.1 Theory.......................................................................................................................... 8
3.2.2 Interpretation ................................................................................................................ 9
3.3 Drilling Induced Tensile Fractures...................................................................................... 11
3.3.1 Theory........................................................................................................................ 11
3.3.2 Interpretation .............................................................................................................. 12
3.4 Hydraulic Fracturing.......................................................................................................... 12
3.4.1 Theory........................................................................................................................ 12
σhmin = minimum horizontal stress......................................................................................... 12
3.4.2 Operational procedure ................................................................................................. 13
3.4.3 Interpretation .............................................................................................................. 14
3.4.4 Impact of stress on fracture stimulation......................................................................... 15
3.5 Overcoring measurements.................................................................................................. 16
3.5.1 Theory........................................................................................................................ 16
3.5.2 Interpretation .............................................................................................................. 16
I
3.6 Earthquake focal mechanism.............................................................................................. 16
3.7 Seismic (AVO) ................................................................................................................. 17
Chapter 4 ................................................................................................................................... 19
In situ stress of the Cooper Basin ................................................................................................. 19
4.1 Introduction ...................................................................................................................... 19
4.2 Tectonic evolution ............................................................................................................. 20
4.3 In situ stress field of Cooper basin ...................................................................................... 21
4.3.1 Overview.................................................................................................................... 21
4.3.2 Stress Orientation ........................................................................................................... 22
4.3.3 Stress Magnitudes ....................................................................................................... 23
Chapter 5 ................................................................................................................................... 26
Geomechanical modelling ........................................................................................................... 26
5.1 Introduction ...................................................................................................................... 26
5.2 Modelling Approach.......................................................................................................... 27
5.2.1 Boundary element method (BEM) ................................................................................ 27
5.2.2 Poly 3D ...................................................................................................................... 27
5.2.3 Model information ...................................................................................................... 28
5.3 Modelling Results ............................................................................................................. 30
5.3.1 Lithology.................................................................................................................... 30
5.3.2 σH azimuth.................................................................................................................. 33
5.3.3 Fault size .................................................................................................................... 35
5.4 Discussion ........................................................................................................................ 37
Chapter 6 ................................................................................................................................... 41
Concluding statement and recommendation.................................................................................. 41
6.1 Concluding Statement........................................................................................................ 41
6.2 Recommendations ............................................................................................................. 41
References ................................................................................................................................. 42
Appendix A................................................................................................................................ 48
Raw data ................................................................................................................................ 48
Appendix B .............................................................................................................................. 105
Lithology ............................................................................................................................. 105
σH azimuth ........................................................................................................................... 109
II
ABSTRACT
With intense exploration around the world, easily extractable hydrocarbons are getting more and more
difficult to find. Major conventional hydrocarbon accumulations have been targeted and are being
produced; but increased world’s consumption has led petroleum exploration and production industry
to consider exploiting targets that were not believed to be economical. Tight reservoirs include shale
gas, shale oil, coal seam gas (CSG) and tight sands. This concept has changed the conventional view
of shales from being source and seal rock to unconventional perception –as reservoir. These reservoirs
have minimal porosity and permeability which is not sufficient to produce at economic rates.
Developing these reserves may require hydraulic fracturing to create a predictable network of
fractures with height of several hundred feet through which hydrocarbons can easily flow towards
borehole. Even if these reservoirs are fracture stimulated at best of the knowledge and skills;
production from two wells in the same field is never the same.
For a successful fracturing treatment, it is necessary to understand impact of existing fractures, faults
and stress regimes in the subsurface. Geologic structures influence the stress field locally and show
deviation from the regional trend of stress pattern. This study utilizes geomechanical modeling with
static elastic moduli to depict stress magnitude and orientation around faults. For the purpose, stress
magnitudes estimated by Reynolds et al., (2006) are used. Strike-slip stress regime prevails in at the
depth interval selected. A thorough study using different lithologies, σH azimuth and fault size is
carried out. Stress concentrate at the fault tips on opposite quadrants of the fault tips. Fluctuation in
stress magnitude increases with increase in fault size. However, the variation diminishes after fault
size of 1500 meters. These models help in understanding the orientation of fractures during hydraulic
fracturing and help to recognize stress barriers that may affect production from an unconventional
reservoir.
III
ACKNOWLEDGEMENTS
First and foremost, I would like to thank God for helping me throughout the year specially in the time
period when I struggled. My sincere thanks to my principal supervisor Dr. Dennis Cooke and co-
supervisor Dr. Hani Abul Khair. Their excellent supervision and regular discussion sessions has
helped me in finishing this project in the required time. I was lucky to have such friendly and
technically strong supervisors.
This project provided me with an opportunity to understand the role of stress in subsurface and helped
to understand the factors affecting the process of hydraulic fracturing. It was a pleasant experience
working with Geofrac research consortium at Australian School of Petroleum (ASP).
My deepest thanks to all the staff at ASP for all of the knowledge they shared to me. I would like to
thank all the teachers who provided with a new insight in petroleum geosciences. In particular
Kathryn Amos, Bruce Ainsworth, Andy Mitchell, Guillaume Backe and John Kaldi whose attention
provided significant knowledge and influenced me to get involve with structure and geomechanics.
A special thanks to Ian West who has always been there to help regarding technical issues particularly
with the software. I would like to thanks my classmates and my friends in Masters Petroleum
engineering for the fun moments we shared.
I would like to thank my parents, brothers and cousin in Adelaide; whose moral support soothed me
throughout the year. I hope this thesis brings something positive to the industry and helps others doing
research relating geomechanics.
IV
Chapter 1- Introduction
Chapter 1
Introduction
1.1 Hydraulic fracturing
Production of oil and gas has a history of more than a century. In the early days oil from seepages was
utilized where the seal integrity has been compromised. The increasing demand of oil resulted in
drilling the first well of exploration history in Pennsylvania in the year 1859. The need of energy is
more intensified and the major reservoirs of the world are at the verge of depletion. To cope up with
the energy need, oil and gas industry is considering various ways to exploit tight reservoirs such as
shale gas, shale oil, tight sands and coal seam gas (CSG). These reservoirs do not flow at economic
rates until they are hydraulically fractured.
A hydraulic fracturing treatment is carried out by pumping specially engineered fluids at high
pressure into the reservoir interval to be treated, causing a fracture to prop open. Usually a single
˚ and theoretically assumed to
fracture is created in two directions at 180 be similar in shape and
dimension. The fracture created needs to be remained open after the pressure is reduced, a propant
such as sand is used to prop open the fracture after the pumping operation is stopped (Holditch, 2007).
To hydraulically fracture a reservoir, particularly shale gas, various criterions need to be considered
before selecting an appropriate candidate. To produce commercial quantities of gas, shale should have
appropriate amount of absorbed and adsorbed gas content, thermally mature, thick enough to contain
the fracture treatment within itself and accurate information of stress conditions around borehole, high
young’s modulus and low Poisson’s ratio (King, 2010). All fracture simulation treatments are not
always successful (Reynolds et al., 2006), potentially due to number of reasons explained by King
(2010). Across North America a number of shale gas plays show production variability (Baihly et al.,
2010). One of the possible reasons in the variation of production from wells is the stress along well
bore which can control the initiation and development of fracture (King, 2010).
1.2 Influence of stress
A total of 3400 dependable measurements of tectonic stress are available defining global stress
patterns (Zoback et al., 1990). The world stress map project has provided important stress data using
a number of conventional methods such as borehole breakouts and minifrac test (Tingay et al., 2005).
The notable development in determining global stress magnitude and orientation has led to use this
1
vital information in exploration and production process. However, variation in stress magnitude due to
local geologic structures in sedimentary basins is poorly understood (Tingay et al., 2005).
Cooper basin is one the most prolific onshore basin of Australia with most prominent shale gas
prospects in Australia (World gas resources, 2011). Since 1963, 129˟ 10 9 m3 (4.6 tcf) of gas and 4.6 ˟
106 kL (29.1 mmstb) of oil have been produced (GSA, 2011). Due to intense exploration ample
amount of stress data sets in the form of borehole breakouts, drilling induced tensile fractures (DITF),
overcoring measurements and earthquake focal mechanism is available. Most of the stress data is
from borehole breakouts and drilling induced tensile fractures, east-west orientation of maximum
horizontal stress (σHmax) is mostly constant throughout the basin (Reynolds et al., 2005). Assessment
of surrounding areas determines clockwise rotation of σH ma x, from north-south in Amadeus basin to
east-west in cooper basin (Reynolds et al., 2005). In the Cooper basin, stress regimes vary with depth.
Reynolds et al. (2004) and Reynolds et al. (2006) produced stress-depth plots determining change in
stress regime with depth. Fractures initiated in strike-slip stress regime will open in direction of
minimum horizontal stress but will change its orientation as soon as it enters in thrust fault stress
regime. Such fractures are called T- fractures and cause a significant problem in acquiring desirable
results from hydraulic fracturing. The in situ stress field plays an important part in not only
determining the orientation of new fracture but also define the fractures that may be more vulnerable
to flow in a naturally fractured reservoir (Reynols et al., 2004). Apart from tectonic stresses, less
consideration has been given to the local change of stress.
1.3 Methodology
This thesis includes a number of stress simulations with variable fault sizes and stress magnitude of
strike slip stress regime to understand the variation in stress magnitude with change in size of the fault
and rapid change in stress magnitude at the fault tips. The simulations are made using Schlumberger’s
stress simulation package Poly 3D which is based on Boundary element method (BEM). The software
use average values of Young’s modulus (YM) and Poisson’s ratio (PR). Simulation results imply that
stress perturbation is a function of size of the fault, lithology and σHmax azimuth. This approach allows
evaluation of a very large number of models and quantitative assessment of stress disturbance around
the fault tips. Stress magnitudes utilized for geomechanical modelling were used from Reynolds et al.,
(2006). Selected data points represent strike-slip stress regime in Cooper basin (Fig 1.1).
2
Figure 1.1, S tres vs depth plot; showing magnitude for stresses. Modified
from Reynolds (2006)
1.4 Aims and Objective
The prime aim of this project is to determine the change of stress magnitude particularly at the fault
tips with change in size of the fault and impact of lithology on this variation. Plane view of
simulations can be used to predict magnitude of minimum horizontal stress and direction of fractures
that may be created during hydraulic fracturing. Using geomechanical modelling can be fruitful to
recognize stress trends in sub surface especially at the locations where stress amplitude fluctuates
rapidly
3
Chapter 2- The in situ stress tensors
Chapter 2
The in situ Stress tensors
2.1 Introduction
This chapter concisely defines the in situ stress tensors and stress regimes which form the basics of
this thesis. In simplest terms, stress can be defined as the force (F) acting on a specified area (A).
𝐹
𝜎=
𝐴
The S.I. unit for stress is Pascal (Pa). Due to large amount of stress involved in geological processes,
stress is defined as Mega pascals (106 ). In rock mechanics, stress acting on a homogenous and
isotropic body can be resolved into nine components oriented in three dimensions. This description of
three normal (S11 , S22 , s33 ) and six shear stress (S12 , S13 , S21 , S23 , S31 , S32) is expressed as stress tensor.
σ=
The normal stresses on the principal planes are termed as principal stresses, typically defined with
conventional methodology as S1 > S2 > S3 . The stress within the earth at depths is conventionally
compressive, therefore positive. Tensile stress does not occur at greater depths (Zoback, 2007).
2.2 Anderson’s Classification
E.M. Anederson (1951) proposed a classification applying the concept of stress tensor to the earth
crust. He assumed that stress magnitudes of principal stresses (S1 , S2 and S3 ) correspond to the SV ,
SHma x and Sh min depending on the geological setting of the area and fault style (Fig 2.1). Each fault
type is associated with a particular stress regime that determines the relative stress magnitude
4
(Zoback, 2007). The stress regimes are normal fault stress regime (SV > SH ma x>Sh min ), strike-slip stress
regime (SHmax >SV >Sh min ) and reverse fault regime (SH max>Sh min >SV).
Figure 2.1 Pictorial representation of Anderson's Classification from Zoback (2007)
2.3 Stress around a borehole
When a well is drilled, the stress from the rocks is removed and shifted to well bore. Mud density,
weight on the surface of rocks being drilled and pressure of the fluids circulating in the borehole are
the primary factors that keep the well stable (Watterson, 1999); otherwise fluid from the formation
will enter the borehole resulting in borehole instability. Kirsch (1989) proposed various equations
determining stress components around borehole as a function of far field stress (Reynolds, 2001).
Following equation is a simpler form defining stress at the wellbore.
5
𝜎𝜃 = 2𝜎𝐻𝑚𝑎𝑥 𝐶𝑜𝑠2𝜃
Where,
σ θ = circumferential stress
θ = Angle around well bore
Figure 2.2, S chematic diagram representing stress around vertical borehole

from Zoback (2007).
The removal of rock due to drilling cause the concentration of stress around the well bore. In a
vertical well stress path is compressive in the direction of Shmin as compare to the stress pattern in
SHma x orientation (Zoback, 2007). Stress concentration is a function of position and distance from the
well which would affect the fracture development away from the bore hole.
2.4 Stress at the fault tips
The magnitude and orientation of the stress field can change locally due to any discontinuity such as
faults and fractures (Homberg et al., 1997; Gudmudsson, 2000; Bourne and Willemse, 2001;
Kattenhorn and Marshall, 2006; Cooke, 2011). High magnitude stress concentrates at the tips causing
deviation of stress pattern from the regional stress field. Fractures propagate on a plane parallel to
SHma x locally (Bourne and Willemse, 2001); therefore the knowledge of stress confined at fault tips is
necessary to understand the mode of fracture deviation during fracture treatment. The studies of
previous authors determine that stress concentrates in two quadrants, with size of stress accumulation
depending on far field azimuth. Fig 2.3 shows the concentration of stress on a strike slip fault.
6
Figure 2.3 Concentration of stress (both compression and tension)on opposite quardants of fault tips. From
Bourne and Willemse (2001)
7
Chapter 3-Measurement of stress magnitude and orientation
Chapter 3
Measurement of stress magnitude and orientation
3.1 Introduction
This chapter summarize conventional methods used to determine stress magnitude and direction
described by Zoback and Haimson (2001) and world stress map project (public domain project since
1989). These methods include borehole breakouts, drill induced tensile fractures (DITF), earthquake
focal mechanism, hydraulic fracturing, overcorring and seismic. However, an eccentric method,
prediction of stress, strain and displacement using computer simulations is being used as well
(Thomas, 1993; Swyer and Davatzes, 2012). A brief introduction of the usual methods is presented in
this chapter to help the reader understand and compare between conventional methods and computer
based geomechanical modelling of stress analysis used in this thesis. In section 3.4, a review of
hydraulic fracture treatment procedure is presented that shall explain the importance of stress during
the process.
3.2 Borehole breakouts

3.2.1 Theory
Borehole breakouts are dark continuous elongated features which can be observed on image logs. Bell
and Gough (1979) explained these features as stress related that are formed due to concentration of
stress around borehole. They form when circumferential stress surpasses the compressive strength of
the rock (Reynolds et al., 2005). Maximum and minimum horizontal stress act perpendicular to each
other in a vertical well, borehole breakouts enlarge in minimum horizontal stress direction (Tingay et
al., 2005).
Borehole breakouts are reliable indicators of orientation of maximum horizontal stress (S1 ) (Zoback et
al., 1985; Brudy et al., 1997). However conflict exists to the extent at which breakouts can be used to
determine stress magnitude (Engelder, 1993). Stress orientations defined from borehole breakouts are
consistent with other stress indicators such as hydraulic fracturing, overcoring and earthquake focal
mechanism and contributes up to 22% of the stress data in world stress map project (Reynolds, 2001).
Fig 3.1 represent borehole breakout in a vertical well.
8
Figure 3.1 From Reynolds (2005), Orientation of minimum and horizontal stress
resulting in borehole breakout.
Borehole breakouts are distinct, beginning and ending suddenly (Bell and Gough, 1979; Tingay et al.,
2005). The length of a borehole breakout is independent of the depth in a well, lithology and dip of
the bed (Bell and Cough, 1979).
3.2.2 Interpretation
Dipmeter and image logs are the most appropriate tools to measure borehole breakouts. In older wells
dipmeter is a commonly used tool and has now been replaced by imaging tools. The four arm
dipmeter tool has four pad electrodes arranged in a coplanar orthogonal pattern (Plumb and Hickman,
1985). The pads are pressed against the wellbore wall and measure formation resistivity from opposite
sides of the wall. The reference pad (pad 1) is magnetically oriented while two independent callipers
measure well bore diameter between pads 1-3 and 2-4 (Plumb and Hickman, 1985). The limitation on
calliper measurements is that it may only measures those breakouts which are larger than the length
and width of pad and diameter of well bore (Plumb and Hickman, 1985).
9
There are a number of borehole enlargements that are not related to stress around well bore (Fig 3.2).
These enlargements in a well are possibly influenced by lithology, natural fracture, consolidation and
drilling history (Rider, 2002). Plumb and Hickman (1985) has set criteria to foil misidentification of
breakouts, according to which breakouts are symmetric with the axis and are in the direction of
minimum horizontal stress; while other elongations in the well may have been formed by drill pipe
wear. Therefore, identification of breakouts calls for measure of symmetrical electrical conductivity
anomalies by dipmeter.
Figure 3.2 Modified from Ri der (2002),

S chematic representation of borehole
shapes and caliper log profile. Fig 3.2a,
in gauge. Fig 3.2b, Key seat. Fig 3.2c,
washout caused by drilling wear. Fig
3.2d, Breakout showing symmetrical
elongation.
Image logs provide a more confident interpretation of breakouts than the dipmeter tool. They are
being used more frequently in new wells. The tool consists of 4 or 6 pads with different number of
“buttons” depending on the tool. These buttons measure the electrical conductivity of the formation.
Breakouts are poorly imaged (reduced pad-wall contact) in the zones of low resistivity where drilling
mud has invaded the formation (Reynolds, 2001). Breakout intervals which are not associated to the
spalling of wellbore wall are identified using image logs. Fig 3.3 shows borehole breakouts
recognised by image logs.
10
Figure 3.3, Interpretation of borehole breakouts and drilling induced tensile fractures.
From Tingay et al., 2005
3.3 Drilling Induced Tensile Fractures

3.3.1 Theory
Drilling induced tensile fractures (DITF) are frequently identified on image logs. They form when
circumferential stress around borehole is smaller than the tensile strength of the rock (Reynolds,
2001). When formation is penetrated by drill bit, stress in the formation is disturbed. However DITF
is not formed until the pressure of fluid in borehole exceed the minimum principal stress causing lost
circulation. In a vertical borehole DITF form in the orientation of maximum principal stress while in a
deviated well DITF can occur in an en echelon pattern (Barton and Zoback, 2002).
Fig 3.3 shows a number of DITF. As mentioned in section 3.2, breakouts are in the direction of
minimum principal horizontal stress (σhmin ). Brudy and Zoback (1999) imply that it provides direct
11
evidence that DITF are oriented in the direction of maximum principal stress (σHmax). DITF are
abundant and it is unlikely to encounter a number of fractures parallel to wellbore axis.
DITF can be easily interpreted from image logs acquired through borehole televiewer, Formation
microscanner and formation microimager. DITF can determine the orientation of maximum horizontal
stress accurately. Fig 3.3shows an image log illustrating DITF in dark colours. During drilling mud
penetrated into the fractures which show high electrical conductivity as compare to the surrounding
rock matrix.
3.4 Hydraulic Fracturing

3.4.1 Theory
Hydraulic fracturing is considered to be a successful treatment to produce economically from low

permeability reservoirs by connecting natural fractures and cleats within a reservoir. Since 1957, after
first hydraulic fracturing treatment, it has become a regular practice for stimulating reservoirs to
produce at best possible rates (Holditch, 2007). Minifrac test is a type of hydraulic fracture treatment
carried out at smaller scale utilized to determine the magnitude of minimum horizontal stress. It has
subsequently become a reliable method to determine in situ stress at depths in a sedimentary basin.
The process involves injection of high pressure fluids in a test interval creating a fracture that is in the
direction of maximum horizontal stress (σHmax) and opens in orientation of minimum horizontal stress
(σhmin ). Natural fracture impact the propagation of fractures but it is mainly controlled by stress field
(Zoback, 2007). Therefore, knowledge of localised stress field is vital to effective fracture treatment.
Poroelastic model is usually used to estimate magnitude of minimum horizontal stress.
Equation 3.1, Mathematical form of poroelastic model. Minimum

horizontal stress is correlative to closure pressure.
σhmin = minimum horizontal stress

ѵ = poisson’s ratio
P p = Pore pressure
σext = tectonic stress
12
3.4.2 Operational procedure
Hydraulic fracturing is a process in which fluids are injected into reservoir at high rate that is
impossible for formation to accept in a radial pattern (Holditch, 2007). This leads the pressure to
increase in the borehole until the tensile strength of rock is overcome resulting a fracture through the
rock. As soon as fracture is formed, fluids injected begin to move into the fracture. Theoretically, the
fracture in the formation is vertical that propagate in two opposite directions away from the well bore;
the fracture wings being 180̊ apart and identical in shape, size and length (Holditch, 2007). Fluids
injected during the treatment contain “propping agent” that prop open the facture after injection is
ceased. Normally sand grains or ceramic beads are used as propping agent.
The basic equipment used for fracture treatment is shown in Fig 3.4. The interval that is to be
fractured is sealed off using packers. If any natural fracture already exists in the interval, it will open
when pressure in well bore rises and avoid the formation of induced fracture. This will invalidate the
in situ stress assessment; therefore care should be taken while selecting a candidate interval.
Figure 3.4 Equipment for Hydraulic fracturing from Bell (1996)
A fracture is created when circumferential stress exceeds tensile strength of the rock. The basic
difference between hydraulic fracture and drilling induced tensile fractures is that during hydraulic
fracturing the magnitude of fluid pressure in borehole is greater than minimum principal stress so the
fracture can propagate away from the borehole (Zoback, 2007).
13
Rock mechanics
Besides in situ stress field, mechanical rock properties also affect a successful hydraulic fracture
treatment. “Ratio of lateral expansion to longitudinal contraction” is defined as Poisson’s ratio. The
amount of Poisson’s ratio is used in determining the closure pressure (Cooke, 2011). Similarly
Young’s modulus controls the fracturing ability. Therefore, data regarding the elastic moduli of the
rock to be fractured should be determined.
Injection test
Minifrac test is a reliable technique to measure insitu stress field. A time-pressure plot is used to
estimate the closure pressure. The term closure pressure corresponds to minimum horizontal stress
(Holditch, 2007). The test is carried out by injecting small volumes of same fluids used in the main
treatment. The purpose of the test is to create similar fracture but of small height. As soon as fracture
is created pumping is stopped leading to a decrease in pressure. The decline curve is used to estimate
minimum horizontal stress.
The stresses are calculated using pressure-time plot (Fig 3.5). Fracture breakdown, shut in and
reopening pressures are used for computation. A sharp peak followed by quick decline determines the
pressure at which fracture is created and fluids enter into fracture (Bell, 1996). After the fracture is
created pumping is stoped (shut in), but the fracture growth continues until fracture fluid pressure is
equal to stress intensity factor (Hayashi and Haimson, 1991). This phenomenon causes the pressure to
decline leading the fracture to close. This pressure is termed as fracture closure pressure. Rapid
decline in pressure gradient changes to relatively stable decline because of closing of pressure (Bell,
1996). Facture closure pressure can be used in determining measurement of minimum horizontal
stress (Shmin ).
Figure 3.5 Pressure -Time plot representing closure pressure

estimated to determine magnitude of minimum horizontal
stress.
14
The instantaneous shut in pressure (ISIP) is always higher than the closure pressure and is considered
to be upper bound for closure pressure. Rocks with low permeability have sharp shut in curve due to
minimal fluid leak-off, while rocks with higher permeability have large curvature of shut-in pressure
that make identification of closure pressure vague (Reynolds, 2001).
3.4.4 Impact of stress on fracture stimulation
The magnitude and direction of stress around borehole and well trajectory may affect the way in
which the fractures may initiate and propagate away from the borehole (Hossain et al., 2000). Some
fracture stimulation treatments don’t undergo ideally. A number of fractures convert into torturous
pathways (Fig 3.6b) as they grow away from the wellbore, this result in limited fracture growth
(Nelson et al., 2007; Reynolds et al., 2004). Restricted connectivity limits the possible drainage area
for production. Fig 3.6 shows difference between torturous and ideal fractures created during a
fracture treatment.
Figure 3.6 S chematic representation of variation in fracture propagation in a well against

theoretical approach. From Nelson et al. (2007)
Fracture development is mainly controlled by stress field around well bore; however it is also
regulated by natural fractures in reservoir which determine failure planes in the rock body. (Zoback,
2007).
15
3.5 Overcoring measurements

3.5.1 Theory
Overcoring is a term used to describe a number of measurement techniques that involves cutting core
with stress measuring instruments attached, for example doorstopper, USBM guage. This technique
involves measuring three-dimensionl stress tensor by estimating strain relief when a rock sample is
isolated from surrounding rocks (Ljunggren et al., 2003). When rock is isolated, amount of expansion
is directly proportional to the stress within the rock (Engelder, 1993). The in situ stress can be
estimated using elastic modulus.
Each overcoring technique has its own methodology and is applied at various stages (Ljunggren et al.,
2003; McGarr and Gay, 1978).
Each technique is interpreted in a separate fashion. Reynolds (2001) has summarized generalized
assumptions considered for the analysis of overcoring measurements in a borehole.
• Stresses that are relieved are equal to the stresses when rock was in situ.
• Diameter of overcoring has no influence on stress measurements.
• Rock response in a linear elastic manner when unloaded during overcoring.
• Rock is assumed to be isotropic.
• Borehole is circular with no rugosity.
• In situ field is three dimensional.
• Rock deforms in plane stress or strain.
3.6 Earthquake focal mechanism
Earthquake focal mechanism (fault plane solution) involves measurement of deformation stimulated
by large volume of rocks at great depths (Zoback and Zobak, 1991; Zoback, 2007). If sufficient
seismic acquisition seismographs are available, it can help to continuous change as earthquake occurs
(Ljunggren et al., 2003). The beach balls in Fig 3.7 denote normal, strike slip and reverse fault
regimes. Earthquake focal mechanism contains two orthogonal nodal planes one of which is termed as
fault plane and other is referred as auxiliary plane which bound the compressional and extensional
quadrants of focal mechanism. These planes define the orientation of P (compressional), B
(intermediate) and T (extensional) planes and are sometimes misinterpreted as orientation of S1 , S2
and S3 . (Zoback and Zoback, 2002).
16
Figure 3.7 Representation of Anderson's classification in the form of earthquake focal mechanism
on right. From Zoback (2007)
P and T axes are at 45˚ from the fault plane and B-axis. In a frictionless fault, seismic propagation is
not controlled by insitu stress but by the orientation of fault (Zobak and Zoback, 2002). Therefore,
plate boundary strike-slip faults do not allow determination of principal stress orientation. Stress field
can be determined from earthquake focal mechanism using inversion techniques (Reynolds, 2001;
Zobzck and Zoback, 2002). Seismic waves radiating as a result of an earthquake can be used to
estimate the relative magnitude of stress.
3.7 Seismic (AVO)

`
Principal stresses (SHmax , Sh min and Sv ) and elastic properties of rock can be estimated from
investigation of azimuthal velocity and AVO analysis of conventional 3D seismic data (Schmid and
Gray, 2011; Gray et al., 2012). Borehole derived measurements provide information of stress change
in the vicinity of well and does not propose the lateral and temporal changes. Therefore it is necessary
to develop techniques to assess and predict stress regimes with non destructive qualities.
17
As seismic waves propagate through the rock volume, they cause some strain within elastic limits.
Young’s modulus and poisson’s ratio can be calculated using assumptions described by Gray et al.,
(2012). These moduli are illustrated as dynamic because they are estimated by high frequency
measurement of velocities of elastic waves (Gray et al., 2012). AVO inversion can be used to
calculate vertical stress (Sv ), through integration which can lead in estimating minimum and
maximum horizontal stress. However these calculations should be calibrated with log data,
microseismic and regional knowledge (Schmid and Gray, 2011). The combination of these estimates
allows for evaluation for hydraulic fractures and geomechanical issues before drilling any well.
18
Chapter 4- In situ stress of the Cooper basin
Chapter 4
In situ stress of the Cooper Basin
4.1 Introduction
The Cooper Basin is Australia’s most proficient onshore basin Fig (4.1). It is northeast-southwest
trending basin located in the central Australia, with major part lying in Queensland and other portion
lying in South Australia. Since 1963, 229 x 109 m3 (8.2 tcf) of recoverable gas and 6.9*106 kL (43.9
mmstb) of recoverable oil have been found in the Cooper basin (Laws and Gravestock, 1998). Largest
reserves of Cooper basin are accumulated in the Moomba and Big lake fields. Cooper basin lie
beneath the Eromanga basin (Great Artesian Basin) which is Jurasssic to cretaceous in age. Fig 4.1
outlines the boundaries of Cooper and Eromanga basin.
Figure 4.1, Regional map showing location of Cooper basin from Laws
and Gravestock (1998).
19
Exploration history of Cooper basin is more than 40 years, therefore, extensive database is available
from Queensland and South Australian sectors of the basin. A significant number of image logs and
dipmeter data can be used to interpret stresses in the basin (Reynolds, 2004). The study of in situ
stress in Cooper basin is very important as many of the hydrocarbon bearing formations are of low
permeability therefore need to fracture stimulate to produce at economic rates. The author has used
stress magnitude measured by Reynolds et al., (2006) for the well Dullingari North-8 for
geomechanical modelling. Hence, this chapter will provide an overview of the stress orientation and
magnitude to help the reader understand the change in fracture pattern during hydraulic fracturing.
4.2 Tectonic evolution
Apak et al., (1997) explains tectonic development involves varying amount of uplift and erosion,
resulting in major depocenters and ridges. The northwest oriented Karmona-Naccowlah feature
divides the cooper basin into southern and northern portions. Prominent northeast trending structures
exist in South Australian part of the basin. These structures include two intrabasins highs, the
Gidealpa-Merrimelia Innamincka (GMI) and the Nappacoongee Murteree (NM) trends, additionally
three main depocenters, the patchwarra, Nappamerri and Tenappera troughs (Fig 4.2).
Figure 4.2, prominent structures of Cooper Basin. From Apak et al.

(1997)
20
Prior to the formation of Cooper basin, a number of orogenies resulted in intense deformation in the
region causing crustal shortening over south-eastern Australia and eastern central Australia,
Moreover, stresses were transmitted to the basin area (Apak et al., 1997). The Cooper basin was
developed under gentle compressional regime evident from the compressional folds thrust faults,
strike-slip movements and inversions within the Permian-Triassic sequences (Apak et al., 1997).
Major structural trends are underlain by features initiated by basement related compresssional regime.
Orientation of a number of faults and folds in cooper basin suggest that northeast trending structures
were developed in Permian sequence as a result of northwest-southeast or an east-west oriented stress
regime (Apak et al., 1997). According to Apak et al., 1997 reactivation of structural lineaments in pre
Cambrian had strong influence on basin configuration. Gravestock and Jensen-Schmidt (1998) has
divided structural evolution of cooper basin into Pre Permian and late Permian-Triassic with a long
period of non deposition after deposition of Daralingie formation.
Apak et al., 1997 propose that Cooper basin is described by high geothermal gradient while basement
structures partially controlling the evolution of the basin. Same authors suggest two episodes of
tectonic uplift headed by ‘gentle down wrapping’ followed by tectonic stability.
4.3 In situ stress field of Cooper basin
4.3.1 Overview
Extensive drilling in the Cooper basin has provided substantial amount of stress data. Orientation of
maximum horizontal stress is approximately east-west in direction with azimuth of ˚.101
Stress
magnitudes have been calculated by Reynolds et al., (2006). Vertical stress magnitude (σv ) is
equivalent to the overburden of the rock at a particular depth; it is truer for rocks at greater depths
(Zoback, 2007). σv has been calculated using density and checkshot velocity survey. Minifrac test
provide for the magnitude of minimum horizontal stress (σhmin ) indicating magnitude approximately
equal to the magnitude of σv . Due to variability of σhmin and σv estimates, maimum horizontal stress
magnitude can be loosely confined regionally (Reynolds et al., 2006). However it is important to
determine stress magnitudes locally (Reynolds et al., 2006). Stress magnitudes in Cooper basin are
very complex which vary with depth in subsurface and location in the basin. Reynolds et al. (2006)
constrains magnitude of principal stresses in Bulyeroo-1 and Dullingari North-8 that illustrate a
predominant strike slip-stress regime (σHmax>σv >σh min ) at depth ranghing from 1 to 3 km. At greater
depths strike slip stress regime change into reverse fault stress regime (σHma x> σh min > σv ) with
minimum horizontal stress magnitude reaching equal to the magnitude of vertical stress magnitude.
Lateral variation in stress regime is illustrated by Reynolds et al. (2004) which depict reverse fault
stress regime at shallower depths and strike slip stress regime at greater depths (Fig 4.3).
21
Figure 4.3, Depth S tress plot explaining change in stress regime. From
Reynolds et al. (2004)
Variation in stress regime can be a serious problem to produce from tight reservoirs of Cooper basin,
where a number of hydraulic fractures treatments have failed to provide significant results. The
fracture propagation is controlled by stress regime and the perturbation in stress field due to fractures
and faults.
4.3.2 Stress Orientation
Reynolds et al., (2005) used datasets from 61 wells to interpret the orientation of maximum horizontal
stress. It uses wells ranked A to C quality determined by World Stress Map (WSM) project ranking
scheme. The average σHmax orientation from all wells determined by borehole breakouts and Drilling
induced tensile fractures (DITF) is 101̊. Geologic and geomorphologic features also affect trend of
σHma x. Stress data from Patchawarra trough indicate southeast-northwest orientation. σHmax direction at
GMI rigde is west-northwest which changes to east-west at Nappamerri trough (Fig 4.2).
22
Figure 4.4, Map representing orientation of maximum horizontal stress in th Cooper

basin.
The systematic clockwise rotation of σH ma x orientation is part of regional rotation across the Australian
continent (Reynolds et al., 2005; Hills et al., 1998). North-south oriented maximum horizontal stress
in the Amadeus basin corresponds to the Tennant Creek earthquake. In the north-east of Cooper basin,
σHma x is north-northwest to south-southeast in Bowen basin which is consistent for 500 km (Reynolds
et al., 2005). Therefore, Cooper basin appears to be at the apex of the regional σH ma x rotation which
provides an evidence for regional rotation of stress field across the continent.
4.3.3 Stress Magnitudes
Vertical stress magnitude
A stress from the weight of overlying rock is directed in a vertical direction due to gravity. It is known
as overburden stress or vertical stress. Density log can be used to determine vertical stress (σv ). Fig
4.3 shows vertical stress magnitude calculated by Reynolds et al.(2004). This data gives an average
23
approximate of vertical stress across the basin and show no unusual deviation from the trend
(Reynolds et al., 2004; Reynolds et al., 2006).
Vertical stress gradient in Cooper-Eromanga basin is around 20MPa/Km (Hills et al., 1998). As
shown in Fig 4.3, vertical stress is intermediate stress at greater depth but at shallow depth minimum
horizontal stress approach the magnitude of vertical stress causing the stress regime to change from
strike slip to reverse fault stress regime.
Minimum horizontal stress magnitude
The minimum horizontal stress in a basin can be determined by minifrac and leak-off tests. Minifrac,
which is a type of hydraulic fracture, is more authentic method to determine minimum horizontal
stress in a basin. A fracture is created pumping fluids at high pressure, causing the fracture to
propagate in the direction of minimum horizontal stress. Details of the process are provided in section
3.4.
Reynolds et al. (2006) illustrates two minifrac tests conducted in Daralingie formation and one each
in Toolachee formation and Nappameri Group. The minimum horizontal stress magnitude is estimated
by a linear relationship, 20.5 MPa/Km. Similar authors propose that the magnitude of minimum
horizontal stress is controlled by lithology and the mechanical stratigraphy of the basin effects stress
magnitudes.
In Dullingari North-8 and Bulyeroo-1, minifrac tests elucidate that minimum horizontal stress is less
than the vertical stress defining stike slip stress regime (σH ma x>σv >σh min ) at a depth of 1 to 3 km.
Minifrac tests also indicate that minimum horizontal stress may be as high as vertical stress such that
stress regime is at the border of strike slip and reverse fault stress regime (σHma x> σh min= σv ).
Differential stress (σHmax - σh min ) in Cooper basin is high (50 MPa at 2.8 km).
Maximum horizontal Stress
Reynolds et al., (2004 and 2006), estimate magnitude of maximum horizontal stress using frictional
limit to stress with hydrostatic pressure being constant. Variation in the amount of minimum
horizontal stress (σHmax) and vertical stress limits the calculation of maximum horizontal stress on the
basin scale (Reynolds et al., 2006). σHma x is the highest principal stress throughout the basin and is not
affected by either stress regimes (strike-slip and reverse fault).
24
As vertical stress does not have a linear relationship with depth, estimation of maximum horizontal
stress is also not linear (Reynolds et al., 2006). The upper bound magnitude of σH max in Dullingari
North-8 is 41.1 MPa/Km and 38.6 Mpa/Km in Bulyeroo-1 using friction limit Reynolds et al. (2006).
The insitu stress field of Cooper basin is considered to be as a result of complex interaction of tectonic
elements surrounding the Australian plate transmitted to the Cooper basin through high strength upper
crust (Reynolds et al., 2006). However, stress field is disturbed by local geologic features (Reynolds
et al., 2006) which can change the magnitude and orientation of principal stresses locally and affect
the final result.
25
Chapter 5- Geomechanical modelling
Chapter 5
Geomechanical modelling
5.1 Introduction
Unlike Indo-Australian plate, most continental areas such as Western Europe, South America and
North America exhibit σH ma x orientation parallel to the absolute plate velocity (Zoback et al., 1989;
Reynolds; 2001; Reynolds, 2005). Most researchers believe that plate boundary forces are the primary
control on the character of the first order intra plate stress field (Zoback et al., 1989). A brief
explanation of insitu stress field in Cooper basin in the previous chapter suggest that plate boundary
forces put forth first order control on the intraplate stress field, however; local geologic structures
such as faults, fractures and salt domes highly perturb the stress patterns around (Luo et al., 2012).
Knowledge of disturbance in stress field around these structures is vital for stability of the well and
economic production from reservoir.
Tight reservoirs need to be hydraulically fractured to flow at economic rate. For a successful fracture
treatment, fractures may grow tens of meters and perhaps encounter a natural fracture. The fracture
stimulation treatment may cause shear movement on the natural fracture if the natural fracture is
critically stressed. Shear movement on natural fractures can be associated with an increase in
production. Therefore, understanding these stress perturbations is very important. Geomechanical
modelling of such geologic structures can reveal important information helpful to develop an oil and
gas field more competitively. Finite element modelling (FEM) and boundary element modelling
(BEM) are two approaches used for the purpose.
This thesis uses Poly 3D software which is based on the boundary element method. This chapter
provides an introduction to BEM and includes stress modelling results in the form of plane view and
line plots. The modelling results represent that the local stress perturbation can be a function of fault
size, lithology and σH ma x azimuth. This approach allows evaluation of a very large number of models
and quantitative assessment of stress disturbance around the fault tips. It is worth emphasizing that the
primary aim of the project is to predict and quantify abnormal stress change at the fault tips using the
limited knowledge of stress. The study also presents extent of fault size after which stress perturbation
is negligible. The conclusions from the study are limited to the average rock properties of rocks such
as Poisson’s ratio and young’s modulus. Poisson’s ratio and young’s modulus vary laterally and
vertically which will affect the ability of a fracture to propagate during hydraulic fracturing.
26
Geomechanical modelling helps to understand fluctuation in magnitude at the fault tips and facilitate
predicting the orientation of possible shear fractures in the zone of concentration of stress.
5.2 Modelling Approach

5.2.1 Boundary element method (BEM)
The possible magnitude of minimum horizontal stress was predicted using Schlumberger’s stress
simulation package Poly 3D based on boundary element method (BEM). BEM is a numerical method
used by engineers for modelling purposes. It is prominent that BEM offers distinctive advantages in
simulation. For example it lessens the spatial dimension of the problem, preserving high accuracy
(Pecher and Stanislav, 1996; Fu, 2006). It provides much better results compared to other numerical
modelling methods (Pecher and Stanislav, 1996). Furthermore, it represents a quasi-infnite domain in
terms of internal surface geometry and boundary conditions; hence, we can model rock volume as an
infinite or semi-infinite elastic mass (Lorig and Brady; Thomas, 1993).
The boundary element method has been part of mathematical literature for a long time but had never
applied to computer geomechanical simulation until research efforts at Stanford University (Pecher
and Stanislav, 1996). The study was formulated in form of a computer program namely Poly 3D by
Thomas (993) which helps to get precise solution of stress and strain estimated at observation points
in the surrounding volume using linear elastic properties (Swyer and Davatzes, 2012).
It efficiently computes 3D loading conditions representing any tectonic regime.
5.2.2 Poly 3D
Thomas (1993) states, “Poly3D is a C language computer program that calculates the displacements,
strains and stresses induced in an elastic whole- or half-space by planar, polygonal-shaped elements
of displacement discontinuity.” A geological surface is divided into small polygonal elements across
which the discontinuity is in displacement is assumed constant (Thomas, 1993). Polygonal elements
may have minimum of 3 sides as used in this thesis (Fig 5.1). The user can select the number of
elements to divide a fault or fracture. These polygonal elements can be used to model complex
geologic structures with bending surfaces (Thomas, 1993). Faults having different strike and slip can
be modelled without gaps. The surface of the fracture as a result of hydraulic fracturing can also be
meshed using Poly 3D (Thomas, 1993). The sensitivity to results is achieved due to individual role of
the polygonal elements.
In Poly 3D, traction on an element is defined through determining any remote stress in addition to the
total stress field induced by all polygonal planes on the element plane (Thomas, 1993). The element
27
plane collectively forms an observation grid, which is defined as a series of equally spaced
observation points and instructs Poly 3D to estimate stress, strain and displacement at individual
points.
Figure 5.1 Modified from S wyer and Davatzes (2012). A geological

. surface divided into triangular polygonal elements
5.2.3 Model information
A significant number of simulations were created using Poly 3D with varying fault size ranging from
100 to 2000 meters. Each model consists of constant volume and rock properties with varying length
of faults. To prevent any perturbation of stress due to model edges, the edge of the model was kept
200 meters from the fault top. Therefore, models with fault length 1900 and 2000 meters have model
length of 2100 and 2200 meters.
The simulation grid is divided into small triangular segments, each segment acting as individual
element when running the simulation. Each model consists of a near vertical strike-slip fault and two
observation grids (Fig 5.3a). One encompassing the fault; displays stress change across the entire fault
length while second observation grid depicts stress variation at the fault tips (Fig 5.3a). The former
observation grid consists of 400 nodes and later is composed of 40 nodes, while both having similar
number of nodes (20) on X axis. Change of fault size does not affect the model as the number of
nodes on horizon is always constant.
The far field stress magnitude used for the simulation purpose was extracted from Reynolds et al.
(2006). In the Cooper basin a strike-slip stress regime prevails from 1 to 3 km. Therefore, the
magnitude of stresses used in simulations represent strike-slip stress regime. Three depth points
models magnitude of σH max , σhmin , σv and pore pressure (Pp) taken from Reynolds et al. (2006) as per
28
table 5.1. Separate models using similar amount of stress data were created for Sandstone, Shale and
Coal.
Each model with different lithology was further with the azimuth between fault and σH ma x of 0˚, 5˚,
15˚, 30˚, 45˚, 60˚ and 90˚. All models were assigned an average Young’s modulus and Poisson’s ratio
as per lithology assuming no change in elastic properties of rocks throughout the model. Simulation
results vary not only with lithology but also as we change the angle between the fault and σH ma x. A
comprehensive tree explaining the structure of model formulation is described in Fig 5.2.
Strike- slip
stress regime
2.25 km 2.5 km 2.6 km
Sandstone Shale Coal Sandstone Shale Coal Sandstone Shale Coal
Fig 5.2, Tree representation of modelling paradigm. N.B each lithology is further divided into seven different models
with 0, 5, 15, 30, 45, 60 and 90 as σ H azimuth.
Stress magnitude for each depth is compiled in table 5.1. The stress magnitude in the Cooper basin
has high differential stress, around 50 MPa (Reynolds et al., 2006). Data represented in table 5.1 is
evident of elevated stress in the upper crust responsible for the transfer of stress intraplate (Reynolds,
2001; Reynolds et al., 2006). Poisson’s ratio for Sandstone, Shale and Coal is 0.24, 0.14 and 0.35
respectively while Young’s modulus used in these simulations for Sandstone, Shale and Coal is 2.2*
106,, 2.8*106 and 5*109 Pascals respectively.
Depth (Km) Stress Magnitude (MPa)
Maximum Minimum Vertical stress Pore pressure

horizontal stress Horizontal stress
2.25 62 32 47 20
2.5 100 50 55 22
2.6 110 52 58 24
Table 5.1, Tabulation of stress magnitudes utilized in the simulations.
29
It should be noted that the faults in these simulations are hypothetical, but certainly realizable. Use of
fault is intended is to understand the abrupt change of stress across the fault. Therefore, these models
are not only applicable in the Cooper basin but may also serve as analogue to understand stress
behaviour across faults worldwide.
5.3 Modelling Results
Examination of results from the model runs indicated that stress variation is the function of lithology,
σH azimuth and fault size. Each of the factors has its impacts on stress perturbation. Therefore, the
impact of each of these properties is presented in a separate section.
According to Gudmundsson (2000), stress concentrates in two quadrants on the opposite ends of fault
tips. Simulation results presented in this thesis align with the hypothesis of Gudmundsson (2000). The
Poly 3D results are displayed in two forms. One, map view of minimum horizontal stress magnitude
(Shmin ) depicted in colour with vectors determining the orientation of S1 . Second, a graphical
representation in the form of line plot explaining abrupt change in stress magnitude across fault tips.
The dark line passing through fault tip is the smaller observation grid. Following sub sections
represent outcomes of the model run on the basis of above give criteria.
5.3.1 Lithology
Each Lithology used in modelling has average elastic modului. Therefore, no lateral variation due to
change in rock properties is expected. Fig 5.3a, 5.4a and 5.5a represent model run with Sandstone,
Shale and Coal as the candidate for hydraulic fracture treatment. Each model is composed of an
absolute scale representing minimum horizontal stress (Shmin).For the sake of demonstrating the
variation due to litholgy; fault size and stress magnitude is kept constant. Models 5.3a, 5.4a and 5.5a
represent minimum horizontal stress at 2.5 km depth and fault size 600 meters.
30
Fig 5.3 Plane view near of

vertical fault representing
minimum horizontal stress (S 3)
in colour contours, with
vectors depicting orientation of
S 1 shale at 2.5 km azimuth 30˚
fault 600.
200 meters
17 37 MPa

S 1 for Coal at 2.5 km σ H
azimuth of 30˚ and fault length
of 600 meters.
200 meters
15 43 MPa
31

S 1 for S andstone at 2.5 km σ H
of 600 meters.
200 meters
15 39 MPa
σ3
4.50E+01
4.00E+01
3.50E+01
3.00E+01
Stress (MPa)
2.50E+01
Shale
2.00E+01
Coal
1.50E+01
1.00E+01 Sandstone
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
Distance from fault tip
Fig 5.6, graphical representation of rapid change in stress magnitude of minimum

horizontal stress (S 3) at the fault tip for S hale, Coal and S andstone at 2.5 km σ H azimuth
of 30˚ and fault length of 600 meters.
32
These results indicate prominent change in stress across the model with change in lithology.
Difference in distribution of stress field is observed clearly, sandstone being able to distribute stress
far away from the fault compare to Coal and Shale. Similar simulations with different lithology and
stress magnitudes are compiled in Appendix A.
Fig 5.6 is line plot for Shale, Coal and Sandstone that correspond to smaller observation grid (black
line in simulation model crossing through the fault tip).
5.3.2 σH azimuth
Tectonic stresses influence the orientation of geologic structures, therefore effect of direction of
maximum horizontal stress is analysed by changing σH azimuth. Fig 5.7, 5.8 and 5.9 represent
simulations with orientation of maximum horizontal stress (σHma x) of 5̊, 45˚and 90˚. To purely
explain the effect of angle change, presented simulations utilize magnitude to stresses at 2.5 km depth
within shale with fault size 1000 m.

S 1 for Shale at 2.5 km σ H
of 1000 meters.
200 meters
18 35 Mpa
33

of 1000 meters.
200 meters
10 40 MPa

of 1000 meters.
200 meters
16 37 MPa
34
σ3
4.00E+01
3.50E+01
3.00E+01
Stress (MPa)
2.50E+01
2.00E+01 5
1.50E+01 45
1.00E+01 60
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
Fig 5.10, graphical representation of rapid change in stress magnitude of minimum

horizontal stress (S3) at the fault tip for σ H azimuth of 5˚, 45˚ and 60˚ at 2.5 km in Shale
and fault length of 600 meters.
Fig 5.10 correspond to simulations anticipating stress varaition at the fault tips. It was observed that
maximum stress perturbation exist when σH angle is 45˚. Similar reseults were observed at different
depths within Sandstone and Coal. Graphical representation of these results is compiled in Appendix.
5.3.3 Fault size
Fault size with fault poulation in a reservoir control the orientation of fracture development (Zoback,
2007). Therefore, a detailed analysis is carried out estimating stress perturbation due to change in fault
size. As demonstrated in the previous sub sections, litholgy and σH azimuth influence the stress
disturbance around fault tips; both parameters are reserved stable. Fig 5.11, 5.12 and 5.13 represent
change in stress magnitude at 2.25 km depth within shale at σH angle of 0˚, 30˚ and 60˚.
35
σ3
1.65E+01
100
1.45E+01 200
300
1.25E+01
500
1.05E+01 600
Stress (MPa)
800
8.50E+00
1000
6.50E+00 1200
1400
4.50E+00
1500
2.50E+00 1600
1800
5.00E-01
1900
-1500 -1000 -500 0 500 1000 1500
Distance from fault tip 2000
Fig 5.11, S tress concentration at fault tips in Shale at 2.25 km depth, σ H azimuth 5˚
σ3
3.40E+01
100
3.20E+01 200
300
3.00E+01
400
Stress (MPa)
2.80E+01 500
600
2.60E+01 800
1000
2.40E+01
1200
2.20E+01 1400
1500
2.00E+01
1600
-1500 -1000 -500 0 500 1000 1500
Distance from fault tip 1800
36
σ3
3.70E+01
100
3.20E+01 200
300
2.70E+01 400
500
600
Stress (MPa)
2.20E+01
800
1.70E+01 1000
1200
1.20E+01 1400
1500
7.00E+00 1600
1800
2.00E+00 1900
-1500 -1000 -500 0 500 1000 1500
2000
5.4 Discussion
Results presented in this thesis are broadly similar to previous studies (Nicol et al., 1996; Homberg et
al., 1997; Gudmundsson, 2000; Bourne and Willemse, 2001; Kattenhorn and Marshall, 2005).
However significant differences also exist, that are discussed in this section. Orientation of principal
stresses can be affected by local geologic structures and rock properties (Reynolds et al., 2005;
Zoback, 2007). If no shear stress exists at the boundary, principal stress may align themselves parallel
or perpendicular to the orientation weak planes (Zoback, 2007). Re-orientation of maximum
horizontal stress vectors (S1 ) near the fault can be observed from the simulation results (Fig 5.14).
Therefore, fractures as a result of hydraulic fracturing treatment will change their orientation affecting
production from the well bore.
37
50 meters
6 39 MPa
Fig 5.14, S tress concentration at fault tips in Shale at 2.5 km depth, σ H azimuth 45˚ with
horizon length of 500 meters fault size 300 meters
A general observation in all models is the concentration of stress at the fault tips in opposite quadrants
of the fault. Therefore, fault tips can be divided into four quadrants; two compressional and two
extensional (Fig 5.3). Near the fault tips, stress vectors appear to align in a different orientation
compare to the far field stress direction. According to Kattenhorn and Marshall (2005) stress field at
the fault tip is greater than the magnitude and different in orientation than regional stress and may lead
to fractures if tensile strength of rock is reached. . Vectors in Fig 5.3 do not appear to diverge from the
trend because spacing between two observation points is 200 meter. However, in fig 5.14 spacing in
observation points is 25 meter, therefore; S1 vectors show a prominent change in orientation.
Deviation of stress orientation is consistent in every model and is influenced by the orientation of far
field stress. Failure planes indicated in the simulations represent points where faults may initiate.
However, the orientation of fractures is a function of σH azimuth and elastic properties of rock matrix.
Each lithology has different elastic moduli that affect the magnitude of closure pressure. Cooke
(2011) explains the importance of Poisson’s ratio in measuring the magnitude for closure pressure.
Change in magnitude of σh min can affect the propagation of fractures. Hence, elastic moduli affect the
ability of rock to transfer stress, thus orientation of fractures. Moreover, more brittle lithologies tend
38
to fracture easily compare to relatively ductile formations (Lorenz et al., 1991). Poly 3D models
possible orientation of shear fractures. Sandstone being most brittle of the presented lithologies,
fractures more easily with high number of fractures compare to shale and Coal. Coal usually have
weak planes (cleats) and has some influence on the fractures during fracture stimulation treatment.
Though the orientation of fracture created during the treatment is mainly controlled by insitu stress.
Coloured contours in figures represent minimum horizontal stress while the vectors determine the
orientation of maximum horizontal stress. S1 vectors indicate propagation in the direction of σHma x
while the fractures open in the direction of S3 . Elastic moduli used in these models are static but this is
not the case in actual practice. Rock properties vary laterally and vertically (King, 2010). However,
for the purpose of developing understanding of the behaviour of stress static properties can be used. A
number of authors (Reynolds, 2001; Cooke, 2011; Swyer and Davastez, 2012) have utilized
averagerock properties for geomechanical modelling.
Homberg et al. (1997) explains the relation of σH azimuth and strike of geologic structure. As the
orientation of maximum horizontal stress is changed, it influences the concentration of stresses at the
fault tips. Stress distribution illustrated in Figures 5.7, 5.8, 5.9 and 5.10 are in good agreement with
those predicted by Homberg et al. (1997). For the sake of argument σH azimuth of 15˚, 45˚ and 60˚ are
presented in the figures. It should be noted that stress perturbation is symmetrical relative to the centre
of fault. The vectors for maximum horizontal stress appear to align themselves according to the
orientation of the fault. Largest perturbation is encountered at the angle of 45˚. If a faulted reservoir is
hydraulically fractured, σH azimuth shall change locally with pre existing faults and fractures which
will serve as barrier for economical production. Thus, fracture stimulation will not be considered to be
successful.
The third criteria used for simulation purpose the fault size (5.11, 5.12 and 5.13). Detailed analysis of
faults depicts rapid change in stress magnitude at fault tips as proposed by previous authors. However,
author has made an attempt to predict the fault size in a given geologic condition after stress
perturbation is constant and is not the function of fault size. Figure represents line plots for stress
perturbation with fault sizes ranging from 100 meters to 2000 meters. It was observed; increase in size
of fault results in increase in perturbation of stress at the fault tips. The fluctuation is prominent in the
models with smaller size of faults (100-1000 meters). Line plots start to come close after 1000 meters
and the amplitude of stress change is not very significant after fault size of 1500 meters (Fig 5.15
Fault vs stress).
39
Fault Vs Stress
36
34
32
30
Stress (MPa)
28
Fault Vs Stress
26
24
22
20
0 500 1000 1500 2000 2500
Fault size
Fig 5.15, An analysis of Fault size with S tress.
Similar trend was observed in all models. However, the magnitude of stress perturbation is function
of lithology and orientation of maximum horizontal stress. Fault size can be predicted from the
seismic survey and using that fault size in such models can help to determine critically stressed areas
around the fault. This practice may help fracking engineer to develop a good understanding of local
stress disturbance in subsurface leading to a successful fracture treatment. It is obvious that fractures
created due to fracture stimulation will intersect such faults in a reservoir. Critically stressed faults
may aid to the production, therefore, such models allow.
40
Chapter 6- Concluding Statement and recommendation
Chapter 6
Concluding statement and recommendation
6.1 Concluding Statement
A number of studies have been carried out to understand the variation in production resulting from not
so successful hydraulic fracturing treatments. Production from unconventional reservoirs particularly
shale gas from world’s known reservoirs is unpredictable due to various factors explained by (King,
2010; Cooke, 2011). Shale gas targets in Cooper basin are also subjected to similar problems like
Barnett Shale and Haynsville Shale.
The detailed analysis of models has led to greater understanding of distribution and abrupt change in
stress field at the fault tips. The simulation uses real stress magnitudes estimated by Reynolds et al.
(2006). This study represents few of the geomechanical factors responsible that can affect the
variation in production from a faulted reservoir. Fractures resulting from hydraulic fracture treatment
have height of several hundred feet; therefore, it is obvious to encounter faults.
Stress is concentrated in two opposite quadrants of the fault at the fault tips. Abrupt change in
magnitude can influence the orientation of fracture during fracture treatment. Fault size play an
important role in determining change in magnitude. Stress perturbation increases with increase in fault
size. However, line plots depict that stress magnitude is not large when fault size reaches around 1500
meters.
6.2 Recommendations
This study of stress distribution leads to following recommendations
• Actual subsurface rocks have varying elastic properties. An analysis using dynamic rock
properties should be carried out to mimic the subsurface more accurately.
• Layered models with different combination of lithologies need to be modelled.
41
References
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47
Appendix A
Appendix A
Raw data
This appendix presents models with fault length of 600meters with σH azimuth of 0˚, 5˚, 15˚, 30˚, 45˚,
60˚ and 90˚. Sandstone, Shale and Coal are included in the section. A number of models are included
in the DVD attached with the thesis.
200 meters
12.1 12.1 MPa
48
Appendix A
S3
1.21E+01
1.21E+01
1.20E+01
Stress (MPa)
1.20E+01
1.20E+01
1.20E+01 S3
1.20E+01
1.20E+01
1.20E+01
-1500 -1000 -500 0 500 1000 1500
Distance fom fault tip to model
Fault 600 meter, Shale 0˚ at 2.25 km
200 meters
10.6 13.5 MPa
49
Appendix A
σ3
1.40E+01
1.30E+01
Stress (MPa) 1.20E+01
1.10E+01
1.00E+01 S3
9.00E+00
8.00E+00
-1500 -1000 -500 0 500 1000 1500
Fault 600, Shale 5˚at 2.25 km
200 meters
8 16.7 MPa
50
Appendix A
σ3
1.70E+01
1.60E+01
1.50E+01
1.40E+01
Stress (MPa)
1.30E+01
1.20E+01
1.10E+01 S3
1.00E+01
9.00E+00
8.00E+00
-1500 -1000 -500 0 500 1000 1500
Distance from
Fault 600 meters, Shale 15˚ at 2.25 km
200 meters
5.0 21.0 MPa
51
Appendix A
σ3
2.50E+01
2.00E+01
1.00E+01
S3
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
3.0 24.0 MPa
52
Appendix A
σ3
2.50E+01
2.00E+01
1.00E+01
S3
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
5.0 23.0 MPa
53
Appendix A
σ3
2.50E+01
2.00E+01
Stress (MPa)
1.50E+01
1.00E+01 S3
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
11.8 12.1 MPa
54
Appendix A
σ3
1.20E+01
1.20E+01
1.20E+01
1.20E+01
Stress (MPa)
1.19E+01
1.19E+01
1.19E+01
S3
1.19E+01
1.19E+01
1.18E+01
1.18E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
12.0 12.1 MPa
55
Appendix A
σ3
1.21E+01
1.21E+01
1.20E+01
1.20E+01 S3
1.20E+01
1.20E+01
-1500 -1000 -500 0 500 1000 1500
Fault 600 meters, Coal 0˚ at 2.25 km
200 meters
10.0 14.0 MPa
56
Appendix A
σ3
1.40E+01
1.20E+01
1.10E+01
S3
1.00E+01
9.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
7.0 17.0 MPa
57
Appendix A
σ3
1.70E+01
1.60E+01
1.50E+01
1.30E+01
1.20E+01
1.10E+01 S3
1.00E+01
9.00E+00
8.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
4.0 22.0 MPa
58
Appendix A
σ3
2.54E+01
1.54E+01
1.04E+01 S3
5.40E+00
4.00E-01
-1500 -1000 -500 0 500 1000 1500
200 meters
4.0 25.0 MPa
59
Appendix A
σ3
2.50E+01
2.00E+01
Stress (MPa)
1.50E+01
1.00E+01
S3
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
4.0 24.0 MPa
60
Appendix A
σ3
2.50E+01
2.00E+01
Stress (MPa)
1.50E+01
1.00E+01
S3
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
11.9 12.0 MPa
61
Appendix A
σ3
1.20E+01
1.20E+01
1.20E+01
1.19E+01
1.19E+01 S3
1.19E+01
1.19E+01
1.19E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
12.0 12.1 MPa
62
Appendix A
σ3
1.21E+01
1.21E+01
1.20E+01
1.20E+01
1.20E+01
1.20E+01 S3
1.20E+01
1.20E+01
1.20E+01
-1500 -1000 -500 0 500 1000 1500
Fault 600 meters, Sandstone 0˚ at 2.25 km
200 meters
10.5 13.5 MPa
63
Appendix A
σ3
1.40E+01
1.35E+01
1.30E+01
Stress (MPa)
1.25E+01
1.20E+01
1.15E+01 S3
1.10E+01
1.05E+01
1.00E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
8.0 17.0 MPa
64
Appendix A
σ3
1.86E+01
1.66E+01
1.46E+01
1.26E+01
Stress (MPa)
1.06E+01
8.60E+00
6.60E+00 S3
4.60E+00
2.60E+00
6.00E-01
-1500 -1000 -500 0 500 1000 1500
200 meters
5.0 22.0 MPa
65
Appendix A
σ3
2.50E+01
1.50E+01
1.00E+01
S3
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
4.0 25.0 MPa
66
Appendix A
σ3
2.50E+01
2.00E+01
Stress (MPa)
1.50E+01
1.00E+01
S3
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
4.0 24.0 MPa
67
Appendix A
σ3
2.50E+01
2.00E+01
Stress (MPa)
1.50E+01
1.00E+01
S3
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
11.8 12.0 MPa
68
Appendix A
σ3
1.20E+01
1.20E+01
1.20E+01
1.19E+01
1.19E+01
1.19E+01 S3
1.19E+01
1.19E+01
1.18E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
2.8 2.8 MPa
69
Appendix A
σ3
2.80E+01
2.80E+01
2.80E+01
2.80E+01
S3
2.80E+01
2.80E+01
2.80E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
25.0 30.5 MPa
70
Appendix A
σ3
3.05E+01
3.00E+01
2.95E+01
2.90E+01
Stress (MPa)
2.85E+01
2.80E+01
2.75E+01
S3
2.70E+01
2.65E+01
2.60E+01
2.55E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
21.0 34.5 MPa
71
Appendix A
σ3
3.70E+01
3.20E+01
2.70E+01
Stress (MPa)
2.20E+01
1.70E+01
S3
1.20E+01
7.00E+00
2.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
16 35.0 MPa
72
Appendix A
σ3
4.00E+01
3.50E+01
3.00E+01
Stress (MPa)
2.50E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
15.0 37.7 MPa
73
Appendix A
σ3
4.00E+01
3.50E+01
3.00E+01
Stress (MPa)
2.50E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
15.0 35.0 Mpa
74
Appendix A
σ3
4.00E+01
3.50E+01
3.00E+01
Stress (MPa)
2.50E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
25.0 28.0 MPa
75
Appendix A
σ3
2.85E+01
2.80E+01
2.75E+01
Stress (MPa)
2.70E+01
2.65E+01
S3
2.60E+01
2.55E+01
2.50E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
28.0 28.0 MPa
76
Appendix A
σ3
2.80E+01
2.80E+01
2.80E+01
2.80E+01
2.80E+01
2.80E+01 S3
2.80E+01
2.80E+01
2.80E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
25.5 30.5 Mpa
77
Appendix A
σ3
3.10E+01
3.00E+01
2.90E+01
Stress (MPa)
2.80E+01
2.70E+01 S3
2.60E+01
2.50E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
20.0 36.0 MPa
78
Appendix A
σ3
3.60E+01
3.40E+01
3.20E+01
Stress (MPa)
3.00E+01
2.80E+01
2.60E+01 S3
2.40E+01
2.20E+01
2.00E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
15.0 42.0 MPa
79
Appendix A
σ3
4.55E+01
4.05E+01
3.55E+01
3.05E+01
Stress (MPa)
2.55E+01
2.05E+01
1.55E+01 S3
1.05E+01
5.50E+00
5.00E-01
-1500 -1000 -500 0 500 1000 1500
200 meters
10.0 42.0 MPa
80
Appendix A
σ3
4.50E+01
4.00E+01
3.50E+01
3.00E+01
Stress (MPa)
2.50E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
10.0 42.0 MPa
81
Appendix A
S3
4.50E+01
4.00E+01
3.50E+01
3.00E+01
Stress (MPa)
2.50E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
Distance from faultt tip
200 meters
26.0 28.0 MPa
82
Appendix A
σ3
2.85E+01
2.80E+01
2.75E+01
Stress (MPa)
2.70E+01
2.65E+01 S3
2.60E+01
2.55E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
28.0 28.0 MPa
83
Appendix A
σ3
2.80E+01
2.80E+01
2.80E+01
2.80E+01
Stress (MPa)
2.80E+01
2.80E+01
2.80E+01 S3
2.80E+01
2.80E+01
2.80E+01
-1500 -1000 -500 0 500 1000 1500
Distance from faultt tip
200 meters
25.0 30.5 MPa
84
Appendix A
σ3
3.10E+01
3.00E+01
2.90E+01
Stress (MPa)
2.80E+01
2.70E+01 S3
2.60E+01
2.50E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
21 35 MPa
85
Appendix A
σ3
4.00E+01
3.50E+01
3.00E+01
2.50E+01
Stress (MPa)
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
15.0 40.0 MPa
86
Appendix A
σ3
4.00E+01
3.50E+01
2.50E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
12.0 40.0 MPa
87
Appendix A
σ3
4.10E+01
3.60E+01
3.10E+01
Stress (MPa)
2.60E+01
2.10E+01
1.60E+01 S3
1.10E+01
6.00E+00
1.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
11.7 40.0 MPa
88
Appendix A
σ3
4.00E+01
3.50E+01
3.00E+01
Stress (MPa)
2.50E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
25.0 28.0 MPa
89
Appendix A
σ3
2.85E+01
2.80E+01
2.75E+01
Stress (MPa)
2.70E+01
2.65E+01
S3
2.60E+01
2.55E+01
2.50E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
28 28 MPa
90
Appendix A
σ3
2.80E+01
2.80E+01
2.80E+01
Stress (MPa)
2.80E+01
2.80E+01
2.80E+01 S3
2.80E+01
2.80E+01
2.80E+01
-1500 -1000 -500 0 500 1000 1500
Distance from dault tip
200 meters
25.0 31.0 MPa
91
Appendix A
σ3
3.10E+01
3.00E+01
2.90E+01
Stress (MPa)
2.80E+01
2.70E+01 s3
2.60E+01
2.50E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
21.0 35.0 MPa
92
Appendix A
σ3
3.80E+01
3.60E+01
3.40E+01
3.20E+01
2.80E+01
2.60E+01 S3
2.40E+01
2.20E+01
2.00E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
15.0 36.0 MPa
93
Appendix A
σ3
4.50E+01
4.00E+01
3.50E+01
3.00E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
15.0 36.0 MPa
94
Appendix A
σ3
4.50E+01
4.00E+01
3.50E+01
2.50E+01
2.00E+01
1.50E+01 s3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
10.0 36.0 MPa
95
Appendix A
σ3
4.50E+01
4.00E+01
3.50E+01
2.50E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
25.0 28.0 MPa
96
Appendix A
σ3
2.85E+01
2.80E+01
2.75E+01
Stress (MPa)
2.70E+01
2.65E+01
S3
2.60E+01
2.55E+01
2.50E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
28.0 28.0 MPa
97
Appendix A
σ3
2.80E+01
2.80E+01
2.80E+01
2.80E+01
Stress (MPa)
2.80E+01
2.80E+01
2.80E+01 S3
2.80E+01
2.80E+01
2.80E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
25.0 31.0 MPa
98
Appendix A
σ3
3.10E+01
3.00E+01
2.90E+01
Stress (MPa)
2.80E+01
2.70E+01 S3
2.60E+01
2.50E+01
-1500 -1000 -500 0 500 1000 1500
200 meters
20.0 37.0 MPa
99
Appendix A
S3
4.15E+01
3.65E+01
3.15E+01
Stress (MPa)
2.65E+01
2.15E+01
1.65E+01 S3
1.15E+01
6.50E+00
1.50E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
14.0 45.0 MPa
100
Appendix A
S3
5.00E+01
4.00E+01
Axis Title
3.00E+01
2.00E+01
S3
1.00E+01
0.00E+00
-1500 -1000 -500 0 500 1000 1500
Axis Title
200 meters
8.0 45.0 MPa
101
Appendix A
σ3
5.00E+01
4.50E+01
4.00E+01
3.50E+01
Stress (MPa)
3.00E+01
2.50E+01
2.00E+01 S3
1.50E+01
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
10.0 45.0 MPa
102
Appendix A
σ3
4.50E+01
4.00E+01
3.50E+01
3.00E+01
Stress (MPa)
2.50E+01
2.00E+01
1.50E+01 S3
1.00E+01
5.00E+00
0.00E+00
-1500 -1000 -500 0 500 1000 1500
200 meters
25.7 28.0 MPa
103
Appendix A
S3
2.85E+01
2.80E+01
2.75E+01
Stress (MPa)
2.70E+01
2.65E+01 S3
2.60E+01
2.55E+01
-1500 -1000 -500 0 500 1000 1500
104
Appendix B
Appendix B
Lithology
Following figures explain change in Stress magnitude as a result of variation in lithology.
σ3
2.80E+00
2.80E+00
2.80E+00
2.80E+00
Stress (MPa)
2.80E+00
Shale
2.80E+00
2.80E+00 Coal
2.80E+00 Sandstone
2.80E+00
2.80E+00
-1500 -1000 -500 0 500 1000 1500
Fault size 600 meters σH azimuth 0˚ at 2.5 km
σ3
3.05E+00
3.00E+00
2.95E+00
2.90E+00
Stress (MPa)
2.85E+00
2.80E+00 Shale
2.75E+00 Coal
2.70E+00
2.65E+00 Sandstone
2.60E+00
2.55E+00
-1500 -1000 -500 0 500 1000 1500
105
Appendix B
σ3
3.60E+00
3.40E+00
3.20E+00
Stress (MPa)
3.00E+00
2.80E+00 Shale
2.60E+00 Coal
2.40E+00 Sandstone
2.20E+00
2.00E+00
-1500 -1000 -500 0 500 1000 1500
distance from fault tip
σ3
4.50E+00
4.00E+00
3.50E+00
3.00E+00
Stress (MPa)
2.50E+00
Shale
2.00E+00
Coal
1.50E+00
1.00E+00 Sandstone
5.00E-01
0.00E+00
-1500 -1000 -500 0 500 1000 1500
Disance from fault tips
106
Appendix B
σ3
4.50E+00
4.00E+00
3.50E+00
3.00E+00
Stress (MPa)
2.50E+00
Shale
2.00E+00
Coal
1.50E+00
Sandstone
1.00E+00
5.00E-01
0.00E+00
-1500 -1000 -500 0 500 1000 1500
σ3
4.50E+00
4.00E+00
3.50E+00
3.00E+00
Stress (MPa)
2.50E+00
Shale
2.00E+00
Coal
1.50E+00
Sandstone
1.00E+00
5.00E-01
0.00E+00
-1500 -1000 -500 0 500 1000 1500
107
Appendix B
σ3
2.85E+00
2.80E+00
2.75E+00
Stress (MPa)
2.70E+00
Shale
2.65E+00
Coal
2.60E+00
Sandstone
2.55E+00
2.50E+00
-1500 -1000 -500 0 500 1000 1500
108
Appendix B
σH azimuth
σ3
4.00E+00
3.50E+00
0
3.00E+00
Stress (MPa)
2.50E+00 5
2.00E+00 15
1.50E+00 30
1.00E+00 45
5.00E-01
60
0.00E+00
-1500 -1000 -500 0 500 1000 1500 90
σH azimuth combined, fault size 600 meters Shale at 2.5 km depth
σ3
4.50E+00
4.00E+00
3.50E+00
0
3.00E+00
Stress (MPa)
5
2.50E+00
15
2.00E+00
30
1.50E+00
45
1.00E+00
60
5.00E-01
90
0.00E+00
-1500 -1000 -500 0 500 1000 1500
σH azimuth combined, fault size 600 meters Coal at 2.5 km depth
109
Appendix B
σ3
4.00E+00
3.50E+00
0
3.00E+00
Stress (MPa)
2.50E+00 5
2.00E+00 15
1.50E+00 30
1.00E+00
45
5.00E-01
0.00E+00 60
-1500 -1000 -500 0 500 1000 1500 90
σH azimuth combined, fault size 600 meters Sandstone at 2.5 km depth
110

Geomechanical Modelling of Stress

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Geomechanical Modelling of Stress

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Geomechanical modelling of stress

magnitude and orientation across fault and

Ehtesham Karatela, B.S. (University of Karachi)

This thesis is submitted in partial fulfilment of the requirements for the

Master of Science (Petroleum Geoscience)

Australian School of Petroleum,

1.1 Hydraulic fracturing

1.2 Influence of stress

1.4 Aims and Objective

The in situ Stress tensors

2.2 Anderson’s Classification

Figure 2.1 Pictorial representation of Anderson's Classification from Zoback (2007)

2.3 Stress around a borehole

θ = Angle around well bore

Figure 2.2, S chematic diagram representing stress around vertical borehole

2.4 Stress at the fault tips

Measurement of stress magnitude and orientation

3.2 Borehole breakouts

Figure 3.2 Modified from Ri der (2002),

3.3 Drilling Induced Tensile Fractures

3.4 Hydraulic Fracturing

Hydraulic fracturing is considered to be a successful treatment to produce economically from low

Equation 3.1, Mathematical form of poroelastic model. Minimum

σhmin = minimum horizontal stress

σext = tectonic stress

3.4.2 Operational procedure

Figure 3.4 Equipment for Hydraulic fracturing from Bell (1996)

Figure 3.5 Pressure -Time plot representing closure pressure

3.4.4 Impact of stress on fracture stimulation

Figure 3.6 S chematic representation of variation in fracture propagation in a well against

3.5 Overcoring measurements

3.6 Earthquake focal mechanism

3.7 Seismic (AVO)

In situ stress of the Cooper Basin

4.2 Tectonic evolution

Figure 4.2, prominent structures of Cooper Basin. From Apak et al.

4.3 In situ stress field of Cooper basin

4.3.2 Stress Orientation

Figure 4.4, Map representing orientation of maximum horizontal stress in th Cooper

4.3.3 Stress Magnitudes

Vertical stress magnitude

Minimum horizontal stress magnitude

Maximum horizontal Stress

5.2 Modelling Approach

It efficiently computes 3D loading conditions representing any tectonic regime.

Figure 5.1 Modified from S wyer and Davatzes (2012). A geological

5.2.3 Model information

2.25 km 2.5 km 2.6 km

Sandstone Shale Coal Sandstone Shale Coal Sandstone Shale Coal

Depth (Km) Stress Magnitude (MPa)

Maximum Minimum Vertical stress Pore pressure

Table 5.1, Tabulation of stress magnitudes utilized in the simulations.

5.3 Modelling Results

Fig 5.3 Plane view near of

Fig 5.4 Plane view near of

Fig 5.5 Plane view near of

Fig 5.6, graphical representation of rapid change in stress magnitude of minimum

Fig 5.7 Plane view near of

Fig 5.8 Plane view near of