THE  ROLE  OF  NATURAL  FRACTURES  IN  THE  PROCESS  OF  HYDRAULIC  

FRACTURING  

 

 

 

 

A  research  paper    

Presented  to    

Dr.  Herman  Rieke  of  

The  University  of  Louisiana  at  Lafayette  

In  Partial  Fulfillment  of  the    

Requirements  for  the  class  of  

Shale  Reservoirs  

 

 

 

 

 

 

 

 

Shanna  Mason  

Fall  2014  

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TABLE  OF  CONTENTS  

LIST  OF  FIGURES……………………………………………………………………………………………....3  

ABSTRACT………………………………………………………………………………………………………..4  

INTRODUCTION………………………………………………………………………………………………..5  

  Stress  in  the  subsurface  and  mechanical  behavior  of  rocks………………………5  

NATURAL  FRACTURE  SYSTEMS………………………………………………………………………..6  

  Deformation  fractures……………………………………………………………………………7  

  Induced  fractures…………………………………………………………………………………..8  

  Material  failure………………………………………………………………………………………8  

  Propagation  of  a  crack…………………………………………………………………………….9  

  Natural  fracture  network  characterization………………………………………………9  

HYDRAULIC  FRACTURING………………………………………………………………………………..10  

  Production  theory………………………………………………………………………………….10  

  Produced  fracture  orientation………………………………………………………………...11  

  Hydraulic  fracture  interaction  with  open  natural  fractures………………………11  

  Hydraulic  fracture  interaction  with  closed  natural  fractures…………………….12  

  Fault  reactivation  during  hydraulic  fracturing………………………………………….13  

CONCLUSION………………………………………………………………………………………………….....14  

FIGURES…….………………………………………………………………………………………………...14-­‐18  

REFERENCES…………………………………………………………………………………………………….19  

 

 

 

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LIST  OF  FIGURES  

Figure  1:  Fracture  modes  (Gale,  2008)……………………………………………………………..15  

Figure  2:  Stress  orientations  according  to  tectonic  region  (Nacht  et  al.,  2010)……15  

Figure  3:  Failure  envelope  for  brittle  deformation  (Cosgrove,  2001)………………….16  

Figure  4:  Four  stress  states  causing  extensional  failure  (Cosgrove,  1998)…………..16  

Figure  5:  Three  stable  states  of  pore  pressure  (Cosgrove,  1998)………………………..17  

Figure  6:  Hydraulic  fracture  and  natural  fracture  interaction  scenarios    

                                   (Huang  et  al.,  2014)……………………………………………………………………………17  

Figure  7:  Stress  states  during  depletion  and  injection  (Nacht  et  al.,  2010)………….18  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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ABSTRACT

Unconventional reservoirs have become viable economic producers of hydrocarbons with

the advancement in techniques of hydraulic fracturing. The production from these

reservoirs, using the hydraulic fracturing techniques, depends on natural and induced

fractures to flow hydrocarbons into the wellbore (Ferrill et al., 2014). The following

paper is a review of natural and induced fractures, and their effects in hydraulic fracturing

techniques. First natural fractures will be reviewed, going through deformation fractures

to induced fractures. Touching on material failure and crack propagation, both important

aspects of hydraulic fracturing. Then hydraulic fracturing will be looked at in terms of the

production theory. Following this theory will be produced fracture orientation and

interaction with both closed and open natural fractures. After which fault reactivation will

be described, along with the damages it can have on production and ways to mitigate the

damage incurred.

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INTRODUCTION

For over the past ten years shale-gas formations have dramatically increased in economic

importance. Encouraged mostly by the development of hydraulic fracturing techniques,

shale formations have continued as an important developing topic in the oil and gas

industry due to their new economic viability and the amount of reserves present in the

United States. Within the industry, “shale” is a term used to classify plays including both

mudstones and shales. This is in contrast with the geologic differentiation between the

two based on fissility (Gale, 2007). Herein, the term “shale” is used in conjunction with

the industry trend.

With the development of hydraulic fracturing techniques, shale formations are now a

viable resource for oil and gas. Fractures in the rock are integral to the producibility of a

shale formation. During the process of considering these unconventional reservoirs as a

successful play, production companies must characterize the natural fracture system of

the formation. According to Sunjay (2012), four questions must be answered: Will the

fractures open? What is the direction of fracture propagation? What are the types and

dimensions of the fractures? Will they stay in the pay zone during stimulation? To fully

understand how to answer these questions the fundamentals of stress in the subsurface

and the mechanical behavior of rocks must be understood.

Stress in the subsurface and mechanical behavior of rocks

At any point in the subsurface, there is a definable stress field determined by the

orientation of three mutually perpendicular principal stress axes. Planes perpendicular to

these have shear stresses equal to zero. Because shear stress parallel to the ground surface

must be zero, one of these axes must vertically terminate perpendicular to the ground

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surface. This characteristic causes most underground surfaces to be composed of one

vertical axis, and two horizontal ones. When rocks are subjected to a load, and the

stresses in the subsurface are unequal, fracture and slippage occur in a matter determined

by the stress combinations (Hubbert and Willis, 1957).

The total stress in the subsurface is determined by the sum of the effective stress (or the

rock matrix and overburden stress) and the pore pressure. Under hydrostatic pore

pressure conditions, any change in the stress on a formation is due to the effective stress.

In some situations the pore pressure might increase or decrease, which changes the

effective stress and increases or decreases the three principal stress axes by the same

amount (Gretener, 1981).

NATURAL FRACTURE SYSTEMS

Rocks are elastic, or they deform in a non-permanent manner, until a certain point. At this

point, the yield point, rocks behave plastically (Han et al., 2013). This point marks the

transition into permanent deformation and is determined by the rock’s mechanical

characteristics. The manner in which a rock deforms plastically classifies it as brittle or

ductile. A brittle material fails with small permanent strain and a ductile material fails

with a large permanent strain. For a shale formation to be important in production, it must

be brittle (Aydin, 2014). This is due to the importance of joint formations, which are

brittle deformation structures and are a necessary element in hydraulic fracturing

techniques (Gale, 2007).

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Deformation fractures

At the yield point, a material will fracture in a degree determined by the mechanical

characteristics of the rock. There are three basic physical characteristics to a fracture.

One, there are two parallel surfaces that meet at the fracture front. Two, both of these

surfaces are planar. Three, change in displacement is small compared to the fracture

length (Pollard and Aydin, 1988). Both joints and faults are characterized as fractures,

however, the two occur in different ways. Fractures generally occur in three modes, as

outlined in Figure 1. Generally, Mode I fractures are characterized by joints and faults are

associated with the other two modes (Pollard and Aydin, 1988). Joints viewed in outcrop

tend to occur in a sequence of joints with similar strike and dips. These sets can occur in

a region with other sets that usually have a perpendicular strike and dip. Joints are usually

perpendicular to the fracture surface, orientated at right angles to the bedding plane

(Russell, 1955). In the subsurface joints can be sealed with an infilling material or pushed

together by overburden pressure. This determination is important because even though

there is no open space between the planes of the joint, the meeting surface can act as a

plane of weakness (Gale, 2007).

Ductile deformation, which is denoted by large-scale strain, occurs at faults in both

extensive and compressive tectonic regions. Each tectonic region can be classified

according to the orientation of the principal stresses (fig. 2). In regions of normal faulting

(extensive tectonic regions), the greatest principal stress is vertical and equal to the

pressure of the overburden. The least stress is horizontal and should be between 1 2 − 1 3

the pressure of the overburden (Hubbert and Willis, 1957). In compressive tectonic

regions, where reverse faulting occurs, the least stress is vertical and equal to overburden

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pressure. The greatest stress is horizontal, but equal to 2-3 times the pressure of the

overburden (Hubbert and Willis, 1957).

Induced fractures

Fractures created by an increase in pore fluid pressure can occur naturally, or stimulated

with hydraulic fracturing techniques. For each case, the mechanics of the rock failure is

basically the same. Any dramatic increase or decrease in pore fluid pressure can drive the

mechanical state of a formation to fail. At this point of failure, a hydraulic fracture is

induced. Once a fracture forms, the way that it propagates depends on the mechanical

properties of the rock and the orientation of the fracture. Only certain environmental

conditions naturally incrementally increase or decrease pore fluid pressure.

Material failure

The Mohr Circle is a way to show the relationship between stresses and the magnitudes

of normal and shear stress at the point of material failure (Means, 1976). Figure 3

indicates a Mohr diagram showing the failure envelope for brittle deformation. Beside the

Mohr diagram are the stress orientations resulting from both Mode I fractures (fig. 3b)

and Mode II and III fractures (fig. 3c). Mode II and III failure occurs when the diameter

of the circle is four times the tensile strength, at point A along the envelope. Mode I

failure occurs at point B, when the differential stress is less than four times the tensile

strength of the rock. Figure 4 indicates the four stress states that can cause extensional

failure, and the stress orientation present in each state. In all states, extensional fractures

form parallel to the maximum principal stress and open against the least principal stress

(Cosgrove, 2001).

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The subsurface is governed by compressional stresses, even though tensile stresses occur.

These tensile stresses cause extensional fractures because of hydraulic fracturing.

Indicating that stress in the subsurface can be modified with a change in pore pressure. In

Figure 5, the three stable pore pressure states are indicated. If any of these states

experiences an increase or decrease in pore pressure it could cause the circle to reach the

failure envelope, at which point a hydraulic fracture is initiated. Each stress state causes

certain types of deformation upon failure, state i will cause shear failure, ii will cause

aligned extensional failure and iii will cause unaligned extensional failure (Cosgrove,

2001).

Propagation of a crack

The propagation of a fracture occurs in increments. Within the joint, during an increase in

fluid pressure, stress builds up at the tip of the fracture. Once this stress reaches a certain

point, or the stress intensity factor exceeds the fracture toughness, the fluid pressure

causes the tip of the fracture to extend or propagate a certain distance. The distance the

fracture propagates depends on the calculated stress intensity factor and the critical stress

intensity factor of the formation. This incremental process occurs over and over again

during the life of the joint (Yew, 1997).

Natural fracture network characterization

To assess the economic viability of a shale play, multiple characteristics of the formation

must be examined. Size, size variation, joint intensity and relation to bedding are obvious

characteristics seen in outcrop. Other key characteristics of the natural fracture system

are; orientation, length and height, spacing, space between parallel planes and whether

there is an infilling material, composition of the host rock and cement fill, and strength of

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the rock and fracture plane (Hubbert and Willis, 1957). It is also necessary to consider

fractures in the subsurface to determine whether they are sealed or not. Determining the

present orientation of the maximum principal stress is also important, because it controls

the direction of hydraulic fractures (Gale, 2007). A full characterization of the natural

fracture network of a formation should include geological, geochemical, petrographical,

petrophysical and geo-mechanical parameters. All of which should be incorporated

together to develop working models (Nagarajan and Arasteh, 2013).

HYDRAULIC FRACTURING

Production theory

The hydraulic fracturing technique used in gas or water well stimulation is based on a

theory first postulated by Kirsch in 1898 and expanded on by Hubbert and Willis (1957).

This theory states that a fracture will begin in a borehole wall when the acting fluid

pressure exceeds the minimum tangential stress and the tensile strength of the material

(Rummel, 1987). The plane along which the fracture will open will be the one whose

compressive stress is first reduced to zero as the pressure in the borehole is increased. In

the case of a smooth cylinder, such as the borehole, this plane will be vertical and

perpendicular to the least principal stress axis. Because of this, at depths the pressure

needed to start a vertical fracture with a non-penetrating fluid ranges between twice the

least horizontal stress and zero. The exact value out of this range depends on the degree

of triaxial stress between the principal stresses (Hubbert and Willis, 1957).

Natural fractures beneath the surface can enhance production in two ways. Either the

fractures were already open and they connect with induced fractures to enhance flow, or

they were closed at the time of stimulation and re-open to form a path for fluid to flow

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(Doe et. al, 2013). Certain circumstances must be present in both cases. Hydraulic

fractures interact with natural fractures in various ways, changing propagation. For the

reactivation of fault and joint surfaces to occur, certain pressures and stress must be

present.

Produced fracture orientation

Hydraulic fractures tend to orient themselves parallel with the maximum and

intermediate principal stresses, and perpendicular to the least principal stress (Hubbert

and Willis, 1957). In various tectonic conditions, the orientation of the hydraulic fracture

created can be determined considering injection pressures. In normal faulting regions

vertical fractures should be produced with injection pressures than are less than the

overburden pressure. In regions of reverse faulting, horizontal fractures should be formed

with injection pressures equal or greater than the overburden pressure. In both tectonic

areas the fractures induced are dependent upon the stress field of the rocks being

fractured (Hubbert and Willis, 1957).

Hydraulic fracture interaction with open natural fractures

The characteristics and geometry of the hydraulic fracture network created during

stimulation techniques is a function of natural fracture network characteristics, state of

stress, wellbore orientation, rock mechanical properties, and stimulation technique

design. The way that a hydraulic fracture interacts with a natural fracture is a function of

the stress, mechanical properties, layer thickness, stage spacing and pumping schedule

(Huang et. al, 2014). A propagating hydraulic fracture can: (i) cross a natural fracture

without any change in direction, (ii) terminate against a natural fracture and then continue

along the natural fracture, and (iii) terminate against and then open a natural fracture, as

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new fractures initiate from the natural fracture (fig. 6, Huang et al., 2014). At the

intersection point between a hydraulic and natural fracture, the path that the fracture

continues to take is the one that has the maximum energy release rate (Sanz et al., 2012).

After a hydraulic fracture intersects a natural fracture, the propagation and geometry of

the fracture depend on the angle of intersection, length of natural fracture, differential

stress, net injection pressure, and the stress shadow of the hydraulic fracture (Wu and

Olson, 2014). The manner of diversion after intersection is controlled by the horizontal

differential stress, natural fracture orientation, and hydraulic fracture net pressure (Sanz

et al., 2012). Depending on the angle of approach, either fracture opening or opening and

crossing occurs. When the angle of approach is low, with significant differential stress,

the induced fracture can open a natural fracture. At a high angle approach, the fracture

can both open a new fracture and cross an existing fracture, depending on differential

stress (Keshavarzi and Mohammed, 2012).

Hydraulic fracture interaction with closed natural fractures

Natural fractures can be sealed by either joint surfaces that are no longer separated, or by

a mineral cement. In both situations, even though the joint is closed it operates as a plane

of weakness that can be reactivated during hydraulic stimulation (Gale, 2007). A joint

can actually re-activate before intersection. This is due to the tensile stress that is exerted

ahead of the fracture during propagation (Keshavarzi and Mohammed, 2012). The way

that rocks break in the subsurface is dependent on the burial and structural history of the

formation as well as the stress history. Thus, to understand reactivation in the hydraulic

fracturing process of a formation, knowing the orientations of mechanical discontinuities

and the orientation of the present day stress field is very important (Enderlin et al., 2013).

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Fault reactivation during hydraulic fracturing

Hydraulic fracturing treatments alter the state of stress in the subsurface. This can lead to

the reactivation of faults, causing slip along the plane of weakness. As the pore pressure

increases with injection in the reservoir the normal stresses on the fault planes decrease.

Causing reactivation and slip (Nacht et al., 2010). This slip can also trigger microseismic

events (Gao et al., 2013). This slip is caused by friction, and can be expected to occur

when the shear stress is strong enough to overcome the resistance to sliding on a fault

plane. This is mathematically described by the Coulomb criterion: 𝜏 =  𝑆! + 𝜇(𝜎! − 𝛼𝜌).

Where S0 is the cohesion between the fault planes, τ is the shear stress along the fault

plane, σn is the normal stress, µ is the coefficient of static friction, α is Biot’s coefficient,

and ρ is the pore pressure. This equation can be used to plot failure of a rock on the Mohr

circle (Gao et al., 2013, Nacht et al., 2010). For any given stress state, we can calculate

the slip tendency and orientation of the corresponding sliding planes as functions of the

maximum and minimum principal stresses. The slip tendency obtained can be compared

to the coefficient of friction of the fault to determine the stability of the fault. We can use

the calculations to compare stress states both before and during hydraulic fracturing to

surmise how the process changes the stress field (Gao et al., 2013).

Aside from the mechanical properties of the fault itself, the sustainable pore pressure of

the formation to prevent fault reactivation must also be determined. This depends on the

stress and fluid paths of the reservoir, mainly in the horizontal direction and the

difference between vertical and horizontal stress. Figure 7 describes the Mohr-Coulomb

diagrams for: a) reactivated fault during depletion, b) a reactivated fault during injection

and c) and open fault during injection. In Figure 7(a), the horizontal stress decreases, as

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opposed to Figure 7(b) where the horizontal stress increases. In both cases the fault is

reactivated.

Fault reactivation can cause major damage to hydrocarbon production operations. This

can come in the form of instability of wellbores, collapsed casings, and fluid leakage to

the surface or shallower porous layers. It can also cause ground level subsidence (Nacht

et al., 2010). These problems can be mitigated by mapping the faults of a formation

before hydraulic fracturing, and by determining the maximum pore pressure that the

formation can take before faults are reactivated. This estimation of the maximum pore

pressure not only prevents fault reactivation, but it also preserves the integrity of the

hydrocarbon trap. Which, if the pore pressure is exceeded, can disintegrate and cause

hydrocarbons to migrate away from the area of producibility (Nacht et al., 2010).

CONCLUSION

Successful hydraulic fracturing techniques rely on the characterization of the natural

fracture network. It is imperative to determine the in-situ stress condition, mechanical

stratigraphy and geological discontinuities in the subsurface when determining the

hydraulic fracturing production plan (Ferrill et al., 2014). Natural fractures play an

integral role in the successful harvest of hydrocarbons from a shale play. Natural fracture

interaction with hydraulic fractures must be estimated, as well as fault reactivation in the

subsurface. The impact of interaction on techniques depends upon the natural fracture

and whether it is open or closed. Geological discontinuities and estimates of maximum

pore pressure must be made to prevent fault reactivation and develop a successful

hydraulic fracturing technique.

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Figure  1:  Fracture  modes  (From  Gale,  2008).    

Figure  2:  Stress  orientations  according  to  tectonic  region  (From  Nacht  et  al.,  2010).    

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Figure  3:  a)  Failure  envelope  for  brittle  deformation  b)  Mode  I  fractures  c)  Modes  II  and  III  fractures  (from  Cosgrove,  2001).    

Figure  4:  a)  four  stress  states  causing  extensional  failure  b)  stress  orientations  in  each  state  (from  Cosgrove,  1998).    

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Figure  5:  Three  states  of  stable  pore  pressure.  If  pressure  is  increased  or  decreased  enough,  the  circle  is  pushed  to  the  failure  envelope  and  deformation  occurs  (from  Cosgrove,  1998).    

Figure  6:  Hydraulic  fracture  and  natural  fracture  interaction  scenarios  (from  Huang  et  al.,  2014)  

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Figure  7:  a)  reactivated  fault  during  depletion,  b)  reactivated  fault  during  injection,  c)  open  fault  during  injection  (from  Nacht  et  al.,  2010).    

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