Geomechanical Factors Affecting the Hydraulic Fracturing Performance in a Geomechanically Complex,...

7/27/2019 Geomechanical Factors Affecting the Hydraulic Fracturing Performance in a Geomechanically Complex, Tectonically

1/13

SPE 122315

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


2/13

2 SPE 122315

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


3/13

SPE 122315 3

=

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.


4/13

4 SPE 122315

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


5/13

SPE 122315 5

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.


6/13

6 SPE 122315

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


7/13

SPE 122315 7

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


8/13

8 SPE 122315

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]

Reference

Aadnoy, B.S.

Agu H.; B tion Experience on a Naturally Fractured Gas Condesate Reservoir, - Field

stillo, D.A.; Moos, D.; Peska, P. and Zoback M.D. 1998. Characterising the Full Stress Tensor Based on Observations of

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


9/13

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


10/13

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


11/13

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


S

0

1000

2000

3000

4000

5000

6000

7000

8000

-5000 -3000 -1000 1000 3000 5000 7000 9000 11000 13000' (psi)

psi

To


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



12/13

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



si/ft)



00,10,20,30,40,50,60,70,80,9

11,11,21,3

1,41,5



si/ft)



00,10,20,30,40,50,60,70,80,9

11,11,21,3

1,41,5



si/ft)



(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


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


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



13/13

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

Geomechanical Factors Affecting the Hydraulic Fracturing Performance in a Geomechanically Complex,...

Documents

Transcript of Geomechanical Factors Affecting the Hydraulic Fracturing Performance in a Geomechanically Complex,...