geomechanical factors affecting the hydraulic fracturing performance in a geomechanically complex,...
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Geomechanical Factors Affecting the Hydraulic Fracturing Performance ina Geomechanically Complex, Tectonically Active Area in ColombiaJ.G. Osorio, SPE, C.F. Lopez, BP Exploration
Copyright 2009, Society of Petroleum Engineers
This paper was prepared for presentation at the 2009 SPE Latin American and Caribbean Petroleum Engineering Conference held in Cartagena, Colombia, 31 May3 June 2009.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract
The Cusiana and Cupiagua fields are located in a tectonically active, geologically complex and highly faulted region in theColombia foothills. These features lead to unusual complex hydraulic fracturing performances which can not be taken into
account by conventional models and practices. To reduce risks and associated costs related to unsuccessful hydraulic
fractures, it is imperative to identify the primary factors and mechanisms affecting the hydraulic fracturing performance in
this geomechanically complex environment.In this study, the main factors affecting the hydraulic fracturing performance in geomechanically complex oil and gas
fields have been investigated. To achieve this objective, it was necessary to compile, interpret and process of a wide set of
data relevant to hydraulic fracturing performance from previous successful and unsuccessful hydraulic fractures from severalfields and formations. Geomechanics models were constructed for each well and the actual performance for each hydraulic
fracture was simulated to study the effect of the following factors: initial failure type (shear or tensile), wellbore orientation,
stress anisotropy, stress continuity with depth, near-well faults, natural fractures, rock strength, geomechanical properties,
pore pressure and stress path. This paper refers to the first four factors (initial failure type, wellbore orientation, stress
anisotropy and stress continuity with depth). The remaining factors will be subject of a future publication.
Results show that the factors having the strongest effect on fracturing performance are initial failure type and wellorientation, which are highly correlated. In past successful hydraulic fracturing operations, tensile failure occurred prior to
shear failure. Conversely, unsuccessful hydraulic fracturing operations are associated with shear failure having occurred priorto tensile failure. Thus, it is imperative to select well orientation and fractured interval such that tensile failure is guaranteed
to occur prior to shear failure to assure a successful fracture. Additional observations show that stress continuity with depth
and stress anisotropy favors fracture performance.
Application of the new findings and best practices obtained from this study has led to improve the hydraulic fractures
geomechanics performance in Cusiana and Cupiagua fields.
IntroductionThe Cusiana and Cupiagua fields, discovered in late 80s, are located 140 kilometres north East of Bogot, in Colombia. The
fields lie in the foothills trend on the edge of the Eastern Cordillera. They are among the largest fields in Colombia. Bothfields have a large aerial extent of approximately 160 km2 and have three productive horizons, the Mirador, Barco and
Guadalupe sandstones, characterized for exhibiting low porosity and relatively high permeability. Further description of thegeology, petrophysics and fluids of these reservoirs has been presented elsewhere (Lee and Chaverra 1998; Giraldo et. al.
2000; Prada et. al. 2001; Jaramillo and Barrufet 2001; Markley et. al. 2002; Torres et. al. 2003; Aguirre et. al. 2004).
In Cusiana and Cupiagua the tectonic forces govern. The maximum horizontal stress is the largest of the three principal
stresses, equivalent to approximately 1.2 psi/ft, and its direction is northwest-southeast. The minimum stress is about 0.6psi/ft and horizontal. Hence, the vertical stress is the intermediate stress and is equivalent to approximately 1.05 psi/ft. These
in-situ stresses indicate that the actual stress regime in Cusiana and Cupiagua is strike-slip faulting. However, there is
evidence of local variability in the stress magnitudes with formation type, structural position, and near-by faults. Stress
directions also changes with depth in some parts of the field. Table 1 presents typical geomechanical properties ranges forMirador, Barco and Guadalupe formations.
The tectonics features, the complex geology and the faulted characteristics of the region lead to complex hydraulic
fracturing performances. In this complex environment, the geomechanics performance of a hydraulic fracture is the result of
the interplay of several factors such as initial failure type, wellbore orientation, stress anisotropy and stress continuity with
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depth, among others. This paper discusses the effects of these factors on the hydraulic fracture performance in Cusiana and
Cupiagua fields. To study these effects, a data base was constructed with information of wells subjected to hydraulic
fracturing in the past. Not only wells that could be fractured, but also wells where the fracture gradient could not be reachedwere considered. For each well, a geomechanics model including elastic properties, rock strength, pore pressure, and
magnitudes and orientations of principal stresses was constructed. To investigate the effects of initial failure type and well
orientation on the hydraulic fracturing performance, the geomechanics model was linked with the stresses generated in the
wellbore neighborhood and with fracturing failure criteria.
Results can be summarized as follows:1. In favorable cases tensile failure occurs prior to shear failure. Therefore, it is imperative to select wellbore
conditions, such as well orientation and a geomechanically favorable interval, such that tensile failure occurs prior to
shear failure to ensure satisfactory fracture initiation.2. For high angle wells, the probability of attaining reasonable fracture initiation pressures increases as the angle
between wellbore azimuth and preferred fracture plane azimuth decreases.
3. Stress anisotropy also has a significant effect on fracture initiation: the larger the stress anisotropy, the higher theprobability of reaching a reasonable fracture gradient.
4. Variability in the direction of principal stresses yield to high fracture gradients, if reachable.
Geomechanics Model ConstructionThe geomechanics model is the core of any geomechanics study and, therefore, drives the accuracy of all subsequent results.As the minimum, a geomechanics model comprises the determination of elastic properties, rock strength, pore pressure, and
magnitudes and orientations of principal stresses. In this study, a geomechanics model was built for each well included in the
study. The following paragraphs present the methodology used to construct the geomechanics model. The selection of
correlations and techniques for assessment of geomechanical properties, rock strength and in-situ stresses is based on those
that have proved to work the best for Colombia foothills.
Characterization of Elastic Properties and Rock Strength
Conventionally, rock mechanical properties are obtained by performing a series of triaxial compression tests on coresamples. However, laboratory tests only provide properties at discrete core depths along the wellbore and therefore best used
as calibration points for log-derived properties. Additionally, due to high costs associated with core retrievals, handling and
preservation, core materials are often not readily available.
Using logs to predict formation mechanical properties provides an economical technique to generate continuous profiles.
The most commonly used method for deriving mechanical properties is based on relations expressing properties in terms of
sonic velocities. These acoustically derived profiles, referred to as dynamic mechanical properties, differ from lab-derivedproperties, referred to as static properties. The main cause for such a difference is due to different deformation mechanisms
between dynamic loading (low magnitude of applied stresses, short duration of pressure or sonic waves) and static loading(high magnitude of applies stresses, long duration of applied pressure). Since the parameters needed for a hydraulic fracturing
job should be valid for a wide variation in stress magnitudes, log-derived properties must be calibrated by using empirical
correlations between static and dynamic properties or by using lab-derived values for a specific rock type. In this study,
calibration is performed by using lab-derived mechanical properties from core samples.
Poisson s Ratio
Poissons ratio, , is the ratio of lateral strain to longitudinal strain when a longitudinal stress is applied. It represents the
amount that the sides of a core plug bulge out when the top is compressed. Poissons ratio is given as (Montmayour and
Graves 1986):
= 2
2
12
2
p
s
p
s
Dt
Dt
Dt
Dt
v ................................................................................................................................. (1)
In Eq. 1, and are the shear (S) and compressional (P) waves travel times, respectively, obtained from sonic
logs.
sDt pDt
Shear Modulus
Shear modulus, , is the ratio of the shear strain to the applied shear stress. It is a measure of the samples resistance
against deformation. The shear modulus is given as (Nielsen et al. 1979):
G
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=
2
101034.1
sDtG
.............................................................................................................................. (2)
In Eq. 2, is rock density and can be obtained from in-situ density logs.
Young Modulus
Youngs modulus, E, is the ratio of longitudinal stress to longitudinal strain. It can be interpreted as the rock stiffness
(the resistance of the rock to deform under a given loading condition). The equation relating the Youngs modulus toPoisson;s ratio and the shear modulus is given as (Fjaer et al. 1996):
( vGE += 12 ) ....................................................................................................................................... (3)Uniaxial Compressive Strength
Uniaxial compressive strength, UCS , is the normal (uniaxial) stress required to cause failure by crushing an unconfined
sample of rock. The UCS is given as (Zoback 2008):
78.304509.2532 = VpUCS ............................................................................................................. (4)
In Eq. 4, is the compressional (P) wave velocity.pV
Tensile Strength
Tensile strength, , is the tensile stress required to cause failure by splitting an unconfined sample of rock. Therelationship between and UCS is given as (Fjaer et al. 1996):
0T
0T
.......................................................................................................................................... (5)UCST = 1.00
Cohesion
Cohesion, , is the force that holds grains together in a rock. The relationship between and UCS is given as (Fjaer et
al. 1996):
0S 0S
tan2 =
UCSSo .......................................................................................................................................... (6)
In Eq. 6, is given by:
24
+= ............................................................................................................................................... (7)
In Eq. 7, is the angle of internal friction given as (Chang and Zoback 2003):
( 5148.0532.18 Vp= )
............................................................................................................................... (8)
Calibration of L og-Deri ved Properti es
Fig. 1 shows some log-derived properties profiles for a typical well in Cusiana (Mirador formation) computed by
application of the preceding correlations. Table 1 presents typical ranges of static mechanical properties obtained from
laboratory tests on cores obtained from Mirador, Barco and Guadalupe. Fig. 1 illustrates the calibration performed on theacoustically derived dynamic profiles to convert them into static mechanical property profiles using static data as calibration
points (red dots). As pointed out earlier, core materials are often not readily available for the well under study. In this lattercase, lithology-based extrapolations from offset wells are performed to shift dynamic to static mechanical properties.
Characterization of In-Situ Stresses
The three principal stresses required for any geomechanical analysis are vertical, maximum horizontal and minimum
horizontal stresses. For horizontal stresses, magnitudes and directions are required. In addition to this stresses, pore pressure
is also needed. The pore pressure in the drainage area of the wells considered in this study was obtained from transient testingor from calibrated reservoir simulators.
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Vert ical Stress
rtical) stress, , was determined from the integration of formation density logs supplemented with
val m
.................................................................................................................................... (9)
Eq. 9,
Overburden (ve vS
ues obtained from core measure ents. Thus, the vertical stress is given by the following equation:
dzgzS
z
v = 0
)(
)(z is density log value, z is vertical depth, and gIn is the acceleration of gravity. The vertical stress in
Cu upia
profile, , was determined from acoustic logs by application of the following
rela
siana and C gua is about 1.05 psi/ft.
Minimum H orizontal Stress
The minimum horizontal stress hS
tionship (Zoback 2008) :
( )( ) PPS
v
vS vh +
=
1....................................................................................................................... (10)
Eq. 10, P, iIn s pore pressure. The minimum horizontal stress profile obtained from Eq. 10 can be calibrated by usingclo e
of the maximum stress, , can be determined utilizing borehole image data from a finite
num
sure pressur values obtained from hydraulic fracturing performed in the well under study or its offset wells. Typical
values for minimum stress in Cusiana and Cupiagua range between 0.58 and 0.78 psi/ft.Maximum Horizontal Stress
The orientation and magnitude HS
nber of observations of wellbore failure in conjunctio with drilling data (essentially mud weights). Strong stress
anisotropy has been observed in Cusiana and Cupiagua fields by examining breakouts and shear anisotropy from sonic logs
(Fig. 2). Barton et al. (1988) proposed a methodology for determination of HS when utilizing observations of breakout
width. They derived the following equation:
( )
b
bhH
SPPUCSS
2cos21
cos212
+
++= ............................................................................................ (11)
Eq. 11, P iIn s the difference between wellbore pressure (mud weight) and pore pressure and b is the half-width ofwel
rength theory in conjunction with the stress polygon technique, using image logs, was also applied the
con
Stress Distribution Around Wellbore and Failure Criteriaon the hydraulic fracturing performance, it is necessary to
tress Distribution Around Inclined Wells
sotropic rocks, the stresses on the wall of an inclined well, as shown in Fig. 3,
can
lbore breakout.
The frictional st
strain the magnitude of HS . Explanation of this method is beyond the scope of this paper and is explained elsewhere
(Wiprut and Zoback 2000). The regional value of HS in the Colombia foothills region is from 1.1 to 1.25 psi/ft .
To investigate the effects of initial failure type and well orientation
link elastic properties, rock strength, pore pressure, and in-situ stresses (i.e., the geomechanics model) with the stressesgenerated in the wellbore neighborhood and fracturing failure criteria.
S
Assuming homogeneous, linearly elastic, i
be derived from solutions presented by several researchers (Deily and Owens 1969; Aadnoy et al. 1987; Hossain et. al.1999) as follows:
wr P= ................................................................................................................................................... (12)
wxyyxyx P+= 2sin4)(2cos2 ................................................................... (13)( ) 2sin42cos2 += xyyxzz v ................................................................................ (14)
0== rzr ............................................................................................................................................. (15)
( ) cos+ yzsen ............................................................................................................. (16) 2 = xzz
Eq. 12 trough 16, is radial stress on the wellbore wall, In r is tangential stress on the wellbore wall at an angular
position, (see Fig. 3), z is axial stress on the wellbore wall position,at an angular ; r , z and rz are shear stresses
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on the wellbore wall in cylindrical coordinate system; x , y and z are normal stresses on the wellbore wall along
subscript letters in rectangular coordinate system (x, y orthogonal andzparallel to wellb re is xyo ax ); , yz and zx are shear
stresses on the wellbore wall in rectangular coordinate sys , w is wellbore pressure,tem P anticlockwise angular position on
the wellbore wall with respect to x .
x , y , z , xy , yz and zx can be estimated from in-situ principal stresses and wellbore orientation as follows:
) 2v222h S sincossins ++= ............................................................................... (17) Hx SS co
sin
2
cosin += Hhy SS2
s .................................................................................................................. 8)(1
( ) 2222 cossincos ++= vHhz SSS ................................................................................ (19)( ) s
sin2
2sin5.0 = hHyz SS in .......................................................................................................... (20)
( 2sincos5.0 2 += vHhzx SSS .) ................................................................................... (21)( ) 2sin5.0 = hHyz SS ........................................................................................................... (22)cos
In Eq. 17 through 22 ehole deviation with respect HS and is the borehole inclination from vertic, is the rbo al.
or inclined wells, the three principal stresses at the e wall are oback 2008):F borehol (Z
22max )(
2
1
2zz
z
++= ...............................................................
)( +............ 3)............ (2
22min )(
2
1
2
)(zz
z
+
+= ....................................................................................... (24)
wr P= .............................................................................................................................. 5)
In Eq. 2
...................... (2
3 through 25, max , min are the maximum and minimum stresses in the plane tangential to orehole,
respectively (Fig. 4), an
the b
d r is the radial stress.
tudy: sh n sile re. The mode of failure t
tly large stresses will de e stress state, the geom
et. al. 1996):
Eq. 25
Failure Criteria
Two modes of failure are considered in this s ear a
pend on t
d ten
h
failu hat
echanical properties and the rock
will occur when the
rock is subject to sufficienstrength.
Shear Fail ure
Shear failure occurs when the shear stress along a plane is too large. Based on Mohr-Coulomb criterion, shear failure will
occur when (Fjaer
231 tan'tan2' + So .................................................................................................................. (26)
In is the maximum effective principal stress defined as:, '1
P= 11 ' .............................................................................................................................. 7)
Eq. 27,
................ (2
In is the maximum principal stress (i.e., the maximum value among max , min and r ). Fig1 5 illustrates astress state in which shear failure occurs prior to tensile fai
i lu
f a te e st
alure.
Tensi le Fa r e
Tensile failure occurs when the rock grains are pulled apart in the direction o ns ress. T e criterion for tensile
failure is given by:
il h
03 ' T ..................................................................................................................................................... (28)
In Eq. 27, '3 is the minimum principal stress (i.e., the minimum value among max , min and r ). Fig 5 illustrates a
stress state in which tensile failure rs prior to shea
b
occu r failure.
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Pre of lic fracturing performance in Cusiana and Cupiagua fields
bore orientation, stress anisotropy, stress continuity
with depth, and presence of natural fractures. To achieve this objective, a data base was constructed with information of wells
ing in the past. Not only wells that could be fractured, but also wells where the fracture gradient
(mud weights, mud logs, losses, cavings and stuck pipe
usiana and Cupiagua, two
concentrations around, occurs massively in the wellbore neighborhood (Fig. 6a). Tensile failure occurs in the direction
b). To study the effect of initial failure type (shear or tensile) on fracture gradient, the
o performed (fractured gradient not achieved). As
(Eq. 26 and 28, respectively) are evaluated. The
Fig. 7 indicatesmo
viouss to wells where field data indicate that the fracture gradient was not reached.
azimuth and preferred fracture plane azimuth decreases. Results from Cusiana and Cupiagua indicate that for high angle
sentation ResultsThe impact of the following geomechanical factors on the hydrau
are considered in this section: initial failure type (shear or tensile), well
subjected to hydraulic fractur
could not be reached were considered. This data set consists of:1. Original reservoir pressure.
2. Reservoir pressure in the well drainage area at the hydraulic fracturing time.3. Well azimuth and deviation within fractured formation.4. Iimage, sonic, density, and gamma ray logs.
ate the geomechanics models5. Drilling data useful to calibrevents).
azilian, tri-axial and UCS tests.6. Core data (stress-strain curves, strength evelopes, and Br7. Fracturing data.
Effect of Initial Failure Type
Where the horizontal in-situ stresses are unequal to a large degree, such as the case of C
ailure may occur: shear or tensile failure. Shear failure originates from stressdifferent modes of initial fthe wellbore and, therefore
of the maximum stress (Fig. 6
following steps were followed for each well under study:1. Construction of the well geomechanics model (Eq. 1 through 11).2. Simulation of stresses on the wall of the well (Eq. 12 through 22).3. Estimation of the principal stresses magnitudes at the borehole wall (Eq. 23 through 25).4. Determination of the initial mode of failure (shear or tensile) for the specific conditions under which the hydraulic
fracture was performed (fracture gradient achieved) or intended t
injection pressure increases, the shear and tensile failure criteria
criterion that is firstly fulfilled will determine which type of failure occurs earlier.
5. Correlation between the initial mode of failure and the actual well fracture gradient (if reached).Fig. 7 shows the fracture initiation pressure as function of wellbore inclination for two wells in Cusiana. In Fig 7a, tensile
failure (blue curve) is reached prior to shear failure (red curve); in this well, fracture gradient was relatively low. In Fig 7b,
shear failure (red curve) is reached prior to tensile failure (blue curve); in this well, it was not possible to reach fracture
gradient. Fig. 8a presents the results obtained for 13 wells in Cusiana and Cupiagua. The vertical axis inde of failure: shear (red line) or tensile (blue line) failure and the horizontal axis is fracture gradient. Wells in which
tensile failure occurs prior to shear failure, as predicted by models, are positioned on the blue line. Similarly, wells in whichshear failure occurs prior to tensile failure are positioned on the red line. The pink zone corresponds to wells in whichfracture gradient could not be reached as evidenced from field data.
These results clearly reveal that fracture gradient could only be reached in those wells in which tensile failure occurs prior
to shear failure as injection pressure increases. Conversely, fracture gradient was not reached in wells in which shear failure
occurs prior to tensile fracture. Physical explanation of this behavior is that if shear failure occurs earlier than tensile failure,the energy provided by the injection pressure is dissipated to the creation of multiple near-wellbore shear fractures with no
single direction. On the other hand, when tensile failure occurs prior to shear failure, the energy associated to the injection
pressure is concentrated in the direction the fracture propagation plane (i.e., the maximum stress direction). In some very few
cases, not published in this paper, it was observed that fracture gradient can be achieved even if shear failure occurs prior totensile failure as long as shear and tensile failure pressures are very close to each other. In this latter case, however, the
fracture gradient is usually very high.
The above results indicate that it is crucial to select wellbore conditions (well orientation, fractured interval, etc.) such
that tensile failure occurs prior to shear failure as a best practice to assure that the fracture gradient can be achieved.
Effect of Well Orientation
A similar methodology was followed to study the effect of well orientation on fracture gradient. In this case, the angle
between the wellbore azimuth and preferred fractured plane azimuth was estimated as an additional step. Fig. 8b shows the
angle between wellbore azimuth and preferred fracture plane azimuth as function of fracture gradient. As in the precase, the pink zone correspond
Fig, 8b shows that for near vertical wells, the angle between wellbore azimuth and preferred fracture plane azimuth has a
minimum effect of whether or not the fracture gradient is reachable. This is valid given the orientation of the principalstresses. Since the maximum and minimum stresses are horizontal, the preferred fracture plane is vertical and, therefore, any
near vertical well will be contained on the preferred fracture plane for any wellbore azimuth.
For high angle wells, the probability of attaining reasonable fracture gradients increases as the angle between wellbore
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we
, the fracture initiation pressure
inc
very small movement of particles relative to undisturbedmaterial: compressional waves have particle motion parallel to the direction of wave propagation, and shear waves have
par ndicular to the direction of wave propagation. In anisotropic formation, shear waves split
into
al time difference between the fast and slow shearwa
zero). Evaluation of a number
of
racture
gradients are related to high variability in principal stress orientation. Physical explanation of this performance is that if theergy from injection pressure is canalized into a single fracture plane.
Ho
e as injection pressure increases. Hence, it is essential to select wellboreconditions, such as well orientation and a geomechanically favorable interval, which guarantee that tensile failure
rior to shear failure to ensure that the fracture gradient can be reached.
re initiation
interval for fracturing, the higher the
rs in Colombia (Ecopetrol and Tepma) for allowing publication of this
, Yeigmy, for her encouragement.
lls, the angle between wellbore azimuth and preferred fracture plane azimuth ought to be less than 8 to 10 degrees toachieve reachable fracture gradients. As an example, Fig. 9 shows, for a well in Cupiagua, the fracture initiation pressure as
function of wellbore azimuth and inclination. In this well, the in-situ maximum horizontal stress (i.e., preferred fracture plane
azimuth) is approximately 135 degrees. Fig. 9 indicates that in wells with high inclinations
reases as the angle between wellbore azimuth and maximum in-situ horizontal stress increases. Experience in Cusiana and
Cupiagua shows that the probability of reaching the fracture gradient in high angle wells with large difference between wellazimuth and preferred fracture plane azimuth is really very low.
Effect of Stress Anisotropy
Rock anisotropy may arise from intrinsic effects such as natural fractures or from unequal stresses within the formation.Thus, acoustic anisotropy can be divided into two categories: intrinsic and stress-induced anisotropy. The sonic wave
propagation can be used to detect and quantify the formation anisotropy.
Sonic waves come into three modes, all of which involve
ticle movement in planes perpe
two separate components: the fast and slow waves. When formation anisotropy comes from stress-induced anisotropy,
the fast and slow shear components are aligned with maximum and minimum horizontal stress directions. The greater thedifference between the maximum and minimum stress, the larger the arriv
ves. This difference is measured through the energy anisotropy which is an indicator of both the slowness and amplitude
of the fast and slow shear waves (Brie et al. 1998, Plona et al 2000, Fogal and Kessler 2002).Fig 2 presents the ultrasonic image (UBI) and anisotropy evaluation logs of a well in Cupiagua. The UBI log, Fig 2a,
clearly shows induced fractures and breakouts indicating stress anisotropy. Fig. 2b is an anisotropy evaluation log. The
difference between the minimum and maximum shear energy (energy anisotropy) is shown as the green shaded zone. The
absolute fast shear azimuthal direction (red curve) with its uncertainty (gray shaded) is shown in right track.Fig. 2 is a good example of a well with good stress anisotropy. Conversely, Fig, 10 shows the anisotropy evaluation log
of a well in Cupiagua with very low stress anisotropy (the green shaded area reduces almost to
anisotropy logs in Cupiagua leads to the conclusion that the larger the stress anisotropy in the perforated interval for
fracturing (green shaded areas in Figs. 2 and 9), the higher the probability of reaching a reasonable fracture gradient.
Effect of Stress Orientation Continuity with Depth
Another factor that has a strong effect on fracture gradient is stress continuity with depth. Fig. 2 shows a case in Cupiagua
where the stress orientation remains approximately constant with depth (red curve). Fig. 9 shows a case where stress
orientation with depth. Observations in Cusiana and Cupiagua wells indicate that reasonable fracture gradients are associatedwith constant stress orientation within the fractured interval. Conversely, high fracture gradients or unreachable f
principal stress direction is constant with depth, the enwever, if the principal stress direction varies with depth fractures in multiple directions tend to be generated, increasing
the energy required to reach the fracture gradient.
ConclusionsThis paper presents the results obtained from a study on the main factors affecting the hydraulic fracturing performance inCusiana and Cupiagua fields, considered as geomechanically complex fields. Several highlights are noted here:
1. From the initial failure type (shear or tensile) standpoint, fracture gradient can only be reached in wells in whichtensile failure occurs prior to shear failur
occurs p
2. For non-vertical wells, the number-one favorable condition to reach a reasonable fracture gradient is to minimize the
angle between wellbore azimuth and preferred fracture plane azimuth. For high angle wells, the fractupressure increases as the angle between wellbore azimuth and maximum in-situ horizontal stress increases. The
probability of achieving a reasonable fracture gradient in high angle wells with large difference between well azimuth
and preferred fracture plane azimuth is low.
3. Concerning stress anisotropy, the larger the stress anisotropy in the perforatedprobability of reaching a reasonable fracture gradient.
4. Reasonable fracture gradients are associated with constant stress orientation within the fractured interval.
AcknowledgmentsThe authors would like to thank to BP and its partne
paper. Gildardo Osorio would like to thank his wife, Tania, for her continuous support while performing this investigation
and writing this paper. Cesar Lopez appreciates his companion
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Nomenclature
:Dt P-wave inp terval transit time [s/ft]
:sDt S-wave interval transit time [s/ft]:E Static Young Modulus [psi]
G : Shear Modulus [psi]
imum in-situ horizontal stress [psi]
psi]
:hS Min
:HS Maximum in-situ horizontal stress [
:vS Vertical Stress [psi]
oS : Cohesion [psi]
:oT Tensile Strength [psi]
: Unconfined Compressive Strength [psi]
Poisson Ratio [Dimensionless]
UCS
:v
pV : P-wave Velocity [Km/s]
: Borehole Azimuth [degs]
: Angle around borehole [degs]
Rock Density [gr/cm3]:
:1 Maximum principal stress on the wellbore wall [psi]
Intermediate principal stress on the wellbore wall [psi]:2
:3 Minimum principal stress on the wellbore wall [psi]
:r Radial stress on the wellbore wall [psi]
Normal stresses in rectangular coordinate system (x,y,z) [psi]:;; zyx
:max Maximum principal tangential stress on the wellbore wall [psi]
:min Minimum principal tangential stress on the wellbore wall [psi]
: Tangential stress on the wellbore wall at an angular position, [psi]
:z Axial stress on the wellbore wall at an angular position, [psi]
:;; rzzr Shear stresses on the wellbore wall in cylindrical coordinate system. [psi]
Shear stresses in rectangular coordinate system (x,y,z) [psi]:;; yzxzxy
: Angle of internal friction [degs]
: Borehole inclination from vertical [degs]
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Stability and Permeability
Around a Wellbore. SPE 2557.
ics, Chap. 2. Amsterdam: Elsevier Science
y from a New Generation Crossed Dipole Acoustic Tool. SPE 77792.
al Impact of Pressure Depletion in the Low-Permeability Cupiagua Gas-Condensate Reservoir. SPE 60297.
s
and Chenevert, M.E. 1987. Stability of Highly Inclined Borehole. SPEDE: 364-374. SPE 16052.
ir onilla, R. and Leal, J. 2004. Chemical Stimula
9.
re,
Case. SPE 8878
Barton, C.A.; Ca
Drilling-Induced Wellbore Failures in Vertical and Inclined Boreholes Leading to Improved Wellborerediction.APPEA Journal 1998: 29-53.P
Brie, A et al. 1998. New Directions in Sonic Logging. Oilfield ReviewSpring 1998: 40-55.
Chang, C. and Zoback, M. 2003. Unconfined Compressive Strength and Physical Property Measurements in Sedimentary Rock.Report toStanford Rock and Borehole Geophysics Consortium.
eily, F. H. and Owens, T. C. 1969. StressD
Fjaer, E.; Holt, R.; Horsrus P.; Raaen, A. and Risnes R. 1996.Petroleum Related Rock MechanB.V.
Fogal, J. and Kessler, C. 2002. Application of Shear Anisotrop
Giraldo, L.A.; Chen, H.Y. and Teufel, L.W. 2000. Field Case Study of Geomechanic
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SPE 122315 9
Hossain, M.M.; Rahman, M.K. and Rahman, S.S. 1999. A Comprehensive Monograph for Hydraulic Fracture Initiation From DeviatedWellbores Under Arbitrary Stress Regimes. SPE 54360.
nts inear-Critical Reservoirs. SPE 71726.
king for the Near Critical Cupiagua Field. SPE 49265.
002. Case Studies of Casing Deformation due to Active Stresses in the Andesordillera, Colombia. IADC/SPE 74561.
986. Prediction of Static Elastic/Mechanical Properties of Consolidated and Uncosolidated Sandsrom Acoustic Measurements: Correlations. SPE 15644.
ielsen, Ramona and Kohlhaas, Charles.1979. Acoustic and Biaxial Measurement of Rock Mechanical Properties for Interpretation of
Plona, T.J.; Kane, M.R.; Sinha, J.; Walsh, J.; Vitoria, O. 2000. Using Acoustic Anisotropy. 41stSPWLA Symposium.
Osorio, A.M. 2001. Ternary Diagram to Visualize Well InterventionOpportunities for Production Improvement A Case History in Cusiana Field, Colombia. SPE 68805.
ss State Eastern Cordillera (Colombia). SPE 81074.
Fractures and Leak-ff Tests: Application to Borehole Stability and Sand Production in the Norwegian Magin. Int. J. Rock Mech. & Min. Sci. 37: 317-336.
les
PERTIES RANGES FOR COLOMBIAN FOOTHILLS
Jaramillo, J.M. and Barrufet, M.A. 2001. Effects in the Determination of Oil Reserves Due to Gravitational Compositional GradieN
Lee, S. and Chaverra, M. 1998. Modelling and Interpretation of Condensate Ban
Markley, M.E.; Last, N.; Mendoza, S. and Mujica, S. 2C
Montmayour, H. and Graves, R.M. 1F
NLogs for Design of Well-Completion Operations. SPE 8238.
Prada, A.; Lazaro, G.E.; Gonzalez, F.A.; Carrillo, L.F. and
Torres, M.E.; Gonzalez, A.J. and Last, N.C. 2003. In-Situ Stre
Wiprut, D. and Zoback, M. 2000. Constraining the Full Stress Tensor from Observations of Drilling-Induced Tensileo
Zoback, M. ed. 2008.Reservoir Geomechanics, 107-118. New York City: Cambridge University Press.
SI Metric Conversion Factors
Psi 6.894757 E + 00 = kPaFt 3.048* E - 01 = ms/ft 3.281 E + 00 = s/m
*Conversion factor is exact.
Tab
TABLE 1- TYPICAL GEOMECHANICAL PRO
Property G (psi) E(psi) UCS To Sov
Typical Value 0.18 0.30 2.5 106 - 5 106 5 106 - 1 107 15,000 - 30,000 1,500 - 3,000 2,000 - 6,000
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10 SPE 122315
Figures
Fig. 1. Log-derived properties profiles for a typical well in Cusiana (Mirador formation). The red dots represent static propertiesfrom lab tests used to calibrate dynamic to static property profiles.
(a) (b)
Fig. 2. Ultrasonic Borehole Image (UBI), part (a), and sonic, part (b), logs showing strong anisotropy in a well in Cupiagua. .
12500
12600
12700
12800
12900
13000
13100
0,15 0,25 0,35
Poisson Ratio, Adm
MD,
ft
Poisson from lab tests
12500
12600
12700
12800
12900
13000
13100
10000 20000 30000
UCS, psi
MD,
ft
UCS from lab tests
12500
12600
12700
12800
12900
13000
13100
1500 2500 3500
Tensile Strength, psi
MD,
ft
12500
12600
12700
12800
12900
13000
13100
4000 5500 7000
Cohesion, psi
MD,
ft
12500
12600
12700
12800
12900
13000
13100
0,00E+00 2,00E+07
Young Modulus, psi
MD,
ft
Young Modulus from Lab
tests
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SPE 122315 11
Pw
rw
r
r
Pw
rw
r
r
Fig. 3. Inclined wellbore with arbitrary orientation under in-situ stress system.
ig. 4. maximum and minimum stresses in the plane tangential to the borehole.F
(a) (b)
Fig. 5. Mohr circle illustrating a stress state in which shear failure occurs prior to tensile failure (a) and a stress state in whichensile failure occurs prior to shear failure.t
0
1000
2000
3000
4000
5000
6000
7000
8000
-5000 -3000 -1000 1000 3000 5000 7000 9000 11000 13000' (psi)
psi
To
TensileFailureCriterion
Shea
rFailu
reCriterio
n
0
1000
2000
3000
4000
5000
6000
7000
8000
-5000 -3000 -1000 1000 3000 5000 7000 9000 11000 13000' (psi)
psi
TensileFailureCriterion
S
0
1000
2000
3000
4000
5000
6000
7000
8000
-5000 -3000 -1000 1000 3000 5000 7000 9000 11000 13000' (psi)
psi
To
TensileFailureCriterion
Shea
rFailu
reCriterio
n
hear
Failu
reCriterio
n
Sv
Sh
SH
x
y
z
Wellbore
Sv
Sh
SH
x
y
z
Wellbore
min
max
min
max
0
1000
2000
3000
4000
5000
6000
7000
8000
-5000 -3000 -1000 1000 3000 5000 7000 9000 11000 13000' (psi)
psi
Shea
rFailu
reCriterio
n
TensileFailureCriterion
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12 SPE 122315
Sh
Sh
SH
SH
Sh
Sh
SH
SH
(a) (b)
Fig. 6. Shear failure (a) (downloaded from CSIRO web site) and tensile failure (b).
00,10,20,30,40,50,60,70,80,9
11,11,21,3
1,41,5
0 10 20 30 40 50 60 70 80 90Wellbore inclination (deg)
Fractureinitiationgradient(p
si/ft)
Shear Failure Tensile Failure
Wellbore inclination: 3 degs
00,10,20,30,40,50,60,70,80,9
11,11,21,3
1,41,5
0 10 20 30 40 50 60 70 80 90Wellbore inclination (deg)
Fractureinitiationgradient(p
si/ft)
Shear Failure Tensile Failure
Wellbore inclination: 3 degs
00,10,20,30,40,50,60,70,80,9
11,11,21,3
1,41,5
0 10 20 30 40 50 60 70 80 90Wellbore inclination (deg)
Fractureinitiationgradient(p
si/ft)
Shear Failure Tensile Failure
Wellbore inclination: 12 degs
00,10,20,30,40,50,60,70,80,9
11,11,21,3
1,41,5
0 10 20 30 40 50 60 70 80 90Wellbore inclination (deg)
Fractureinitiationgradient(p
si/ft)
Shear Failure Tensile Failure
Wellbore inclination: 12 degs
(a) (b)
Fig. 7. Fracture initiation pressure as function of wellbore inclination for two wells in Cusiana. In Part (a), tensile failure is reachedprior to shear failure. In Part b, shear failure is reached prior to tensile failure.
0
10
20
30
40
50
60
70
80
90
0,4 0,5 0,6 0,7 0,8 0,9 1 1,1 1,2
Fracture gradient ( psi/ft)
Anglebetween
thewellazim
uth
and
preferred
fractured
planeazim
uth
(degs)
(a) (b)
Fig. 8. Mode of failure, part (a), and angle between wellbore and preferred fracture azimuths, part (b), as function of fracturegradient for some wells in Cusiana and Cupiagua. The pink zone corresponds to wells in which fracture gradient could not be
reached as evidenced from field data.
Well 5
Incl: 3 Deg
Well 1
Incl: 3 Deg
Well 2
Incl: 3 Deg
Well 3
Incl: 3 Deg
Well 9
Incl: 19 DegWell 4
Incl: 6 Deg
Well 10
Incl: 6 Deg
Well 11
Incl: 12 Deg
Well 6
Incl: 21 Deg
Well 7
Incl: 25 Deg
Well 8
Incl: 22 Deg
Well 12
Incl: 29 Deg
Well 13
Incl: 19 Deg
Complex frac initiationComplex frac initiation
Well 5
Incl: 3 Deg
Well 1
Incl: 3 Deg
Well 2
Incl: 3 Deg
Well 3
Incl: 3 Deg
Well 9
Incl: 19 DegWell 4
Incl: 6 Deg
Well 10
Incl: 6 Deg
Well 11
Incl: 12 Deg
0
1
2
3
0,4 0,5 0,6 0,7 0,8 0,9 1 1,1 1,2
Fracture gradient (psi/ft)
Initialfailure
type
Well 6
Incl: 21 Deg
Well 7
Incl: 25 Deg
Well 8
Incl: 22 Deg
Well 12
Incl: 29 Deg
Well 13
Incl: 19 Deg
Complex frac initiationComplex frac initiation
Shear
Failure
Tensile
Failure
Well 5
Well 6
Well 1
Well 2
Well 3 Well 7
Well 8
Well 9
Well 4
Well 10
Well 11
Well 12
Well 13
Complex frac initiationComplex frac initiation
0
1
2
3
Well 11
Well 10 Well 12
Well 3 Well 7Well 5 Well 13Well 1
Well 8
Well 9Well 2
Well 6Well 4
Complex frac initiationComplex frac initiation
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SPE 122315 13
10600
10800
11000
11200
11400
11600
11800
12000
12200
12400
12600
0 50 100 150 200 250
Well azimuth (Degrees)
Fracture
initiationp
ressure
(Psi)
0
5
10
15
20
25
30
35
40
45
Well inclination
Fig. 9. Fracture initiation pressure as function of wellbore azimuth and inclination for a well in Cupiagua. Fracture initiationpressure increases as the angle between wellbore azimuth and maximum in-situ horizontal stress increases.
(a) (b)
Fig. 10. Ultrasonic Borehole Image (UBI), part (a), and sonic, part (b), logs showing weak anisotropy in a well in Cupiagua.
SH Azimuth
10600
10800
11000
11200
11400
11600
11800
12000
12200
12400
12600
0 50 100 150 200 250
Well azimuth (Degrees)
Fracture
initiationp
ressure
(Psi)
0
5
10
15
20
25
30
35
40
45
Well inclination
SH Azimuth