Hydraulic-Fracture-Height Growth

Student name

Hassan Shakir Aziz

Student Number

Supervisor:

Lecture. Ahmed Ali

Petroleum Engineering Department

Engineering College

University of Basrah

Final Exam Report

Iraq

2019-2020

1|P a g e
Table of Contents
ABSTRACT ............................................................................................................................................................4
1. INTRODUCTION ...............................................................................................................................................5
2. FRACTURE MAPPING TECHNOLOGIES .............................................................................................................7
2.1 Microseismic ............................................................................................................................................. 7
2.2 Microdeformation ..................................................................................................................................... 8
3. FRACTURE-MAPPING DATA .............................................................................................................................9
4. FRACTURE-CONTAINMENT MECHANISMS ....................................................................................................15
4.1 In-Situ Stress............................................................................................................................................ 18
4.2 Material-Property Contrasts ................................................................................................................... 21
4.3 Weak Interfaces ...................................................................................................................................... 22
4.4 Layered Interfaces ................................................................................................................................... 25
4.5 Fluid-Pressure Gradient .......................................................................................................................... 26
4.6 Faults ....................................................................................................................................................... 28
4.7 High-Permeability Layers ........................................................................................................................ 29
5. IMPLICATIONS ...............................................................................................................................................29
6. CONCLUSIONS ...............................................................................................................................................30
7. NOMENCLATURE ...........................................................................................................................................32
8. REFERENCES...................................................................................................................................................32

Table of Figures
Figure 1: Stress orientation. ............................................................................................................................... 7
Figure 2: Barnett shale measured fracture heights sorted by depth and compared to aquifers. ................... 10
Figure 3: Woodford shale measured fracture heights sorted by depth and compared to aquifers. .............. 11
Figure 4: Marcellus shale measured fracture heights sorted by depth and compared to aquifers. ............... 12
Figure 5: Eagle Ford shale measured fracture heights sorted by depth and compared to aquifers. .............. 13
Figure 6: Microdeformation (tiltmeter) measurements of horizontal vs. vertical fracture components with
depth. ............................................................................................................................................................... 14
Figure 7: Example mineback fracture showing multiple fracture strands and horizontal components. ........ 15
Figure 8: Example mineback fracture near borehole showing offsets at natural fractures and two parallel
fractures. .......................................................................................................................................................... 16

2|P a g e
Figure 9: Example mineback fractures initiating from perforations in a horizontal wellbore; multiple
fractures have initiated from multiple perforations below the wellbore. ...................................................... 17
Figure 10: Schematics of levels of complexity observed in hydraulic fractures. ............................................. 17
Figure 11: Geometry for fracture-height calculations. .................................................................................... 19
Figure 12: Stress data from the Piceance basin. .............................................................................................. 20
Figure 13: Mineback photograph of dyed-water fracture propagating across interface. ............................... 21
Figure 14: Mineback photograph of fracture terminating at a weak interface. .............................................. 23
Figure 15: Mineback photograph of fracture terminating at a weak interface. .............................................. 24
Figure 16: Mineback photograph (and line drawing) of fracture kinking, offsetting, and turning as interface
is crossed. ......................................................................................................................................................... 25
Figure 17: Schematic of pathologies for fracture behavior in a layered sequence. ........................................ 26
Figure 18: Example calculation of fracture size for tall fracture. ..................................................................... 27

3|P a g e
ABSTRACT

Much public discourse has taken place regarding hydraulic fracture growth and whether
fractures could potentially grow up to the surface and create communication pathways for frac
fluids or produced hydrocarbons to pollute groundwater supplies. Real fracture growth data
mapped during thousands of fracturing treatments are presented along with the reported aquifer
depths in the vicinity of the fractured wells. These data are supplemented with an in-depth
discussion of fracture-growth limiting mechanisms augmented by mine back tests and other
studies performed to visually examine hydraulic fractures. These height-growth limiting
mechanisms, which are supported by the mapping data, provide insight into why hydraulic
fractures are longer laterally and more constrained vertically. This information can be used to
improve models, optimize fracturing, and provide definitive data for engineers, regulators, and
interest groups.

4|P a g e
1. INTRODUCTION

Hydraulic fracturing is a technology that has been in practice since the late 1940s to improve
production from reservoirs. This technology has been refined through the decades, and
fracturing design, execution, quality control, and evaluation have been the source of hundreds
of articles in previous literature.

Hydraulic fractures are manufactured flow paths by which hydrocarbons are efficiently
extracted from low-permeability rocks. The fracture is constructed by a planned injection of
high pressure fluid that penetrates a sufficient volume of reservoir rock to result in economic
production. Because fracturing materials (fluids, proppant, and chemicals) and pumping
hydraulic horsepower are expensive, the industry has been motivated since the inception of
fracturing to understand and control fracture growth. The least desirable occurrence is generally
excessive height growth, and many studies and journal articles have addressed this topic.

The science and engineering of hydraulic fracturing is well understood, and it is clear that there
are numerous mechanisms that contribute to fracture containment. These mechanisms deal
particularly with the layered Earth structure and are discussed later in some detail. In addition,
there is a volumetric argument.

For hydraulic fractures to propagate, they must be opened by internal pressure. As a fracture
grows larger, the width of the fracture increases in proportion to the fracture height. Because
the pressure must remain high to continue feeding the fracture at its deep starting point, the
high pressures and a hypothetically large height would require enormous volumes of fluid. It
is clear that the fracture can only grow so far before it reaches a physical limit. Fracture lengths
can sometimes exceed 1,000 ft when contained within a relatively homogeneous layer, but
fracture heights, because of the layered geological environment and other physical parameters
to be discussed here, are typically much smaller, usually measured in tens or hundreds of feet.

Faults have been suggested as mechanisms for enhancing fracture growth, but this ignores the
basic understanding of faults in hydrocarbon reservoirs. If there is an open path to the near
surface through an existing fault, throughout geologic time, all of the hydrocarbons would have

5|P a g e
escaped and there would be no reason for exploiting the resource. If the fault is impermeable,
then it also must be closed. In that case, the conditions required for extending the fault are
essentially identical to those for extending a fracture in a competent rock. The reason is that
the strength of the rock is a negligible factor in fracture propagation; almost all of the work is
performed in the opening of the fracture against the rock and the in-situ stresses.

It also appears that there is some misunderstanding of the permeability conditions that occur in
these sedimentary basins. The layered structure of typical sedimentary rocks results in hundreds
or thousands of layers that have low vertical permeability. These rocks collectively form the
cap rock that prevents the hydrocarbons from escaping. This cap rock works exactly the same
with respect to the fracturing fluids. Once fracturing fluids are emplaced in the reservoir or
rocks adjacent to the reservoir, they are there to stay unless they get produced back to the
wellbore. If the permeability was sufficiently high that the fracturing fluids could migrate to
the surface, then the hydrocarbons would have already escaped and there would be no reservoir
to exploit.

Fractures grow perpendicular to the direction of least principal stress, or in the direction of
maximum stress (in order to open against the smallest stress). At depths deeper than
approximately 2,000 ft, the vertical stress or overburden (𝜎ov ) is generally the largest single
stress, so the principal fracture orientation is expected to be vertical on deeper wells (Figure 1).
Of the two horizontal-stress orientations, the direction of maximum stress (𝜎hmax ) will dictate
the direction the frac grows laterally (length) and the frac width will open against the smallest
stress orientation (𝜎hmin ). This paper presents data from microseismic and tiltmeter monitoring
technologies that provide definitive evidence of the amount of vertical growth exhibited by
industrial hydraulic fractures. The monitoring technologies are briefly discussed, followed by
the monitoring results that clearly show that fractures remain in relatively close proximity to
the reservoirs in which they are created. Finally, the paper presents the mechanistic arguments
that explain why containment of fractures is to be expected in these sedimentary environments.

6|P a g e
 Figure 1: Stress orientation.

2. FRACTURE MAPPING TECHNOLOGIES

The two primary methods for full field monitoring of hydraulic fractures are microseismic and
microdeformation. These two technologies monitor different aspects of the fracturing process,
so they are complementary and can be used to corroborate information about height growth.

2.1 Microseismic

Microseismic monitoring is based on detecting and locating the small reservoir movements that
take place as a result of the fracturing process. These movements are caused by changes in
stress (fracture opening) and fluid pressure (leakoff), and they occur along natural fractures,
bedding planes, and other weakness zones in the rocks with which the fracture makes contact.
Therefore, it is an excellent technology for monitoring fracture growth by tracking the
distribution of the microseismic events.

Microseismic monitoring is usually performed by placing long arrays of sensitive receivers in

offset wells at a depth that is close to the zone to be fractured. The microseisms are
7|P a g e
characterized by the emission of both compressional (P) and shear (S) waves, and these are
detected by the receivers in the monitoring well. Robust grid search and migration methods are
used to determine where the events originated on the basis of wave arrival times and
polarizations. It is important to have an accurate velocity model; therefore, significant effort is
placed on characterizing and calibrating the model.

The distance at which microseisms can be observed depends primarily on the size of the
microseism and on noise levels. This distance can almost always be characterized from the
observed data, so the limits of the monitoring capabilities are known. In shale reservoirs,
microseisms can often be detected at distances up to 5,000 ft, whereas many other reservoirs
have much shorter observation distances. In shales (the reservoirs possibly of most concern
because of the size of the fracture treatments), the large detection distance allows vertical height
to be monitored even if there is significant height growth.

If fractures are at relatively shallow depths, then it can also be possible to monitor microseisms
using surface arrays. This is typically performed in geothermal reservoirs where the
microseisms are much larger and can be observed at greater distances.

2.2 Microdeformation

Microdeformation fracture monitoring is the measurement of small displacements either at the

surface of the Earth or in boreholes using sensitive tiltmeters. For surface monitoring of deep
fractures, these tiltmeters are used to measure minute deformation induced by the fracture, but
can also be used in offset wellbores to monitor fracture dimensions particularly height. A
tiltmeter works on the same principle as a carpenter’s level, but the sensitivities are orders of
magnitude greater (on the order of nanoradians). When a fracture is created, it deforms the rock
surrounding it and this deformation radiates outward, reaching the surface or an observation
well. An array of tiltmeters on the surface can be used to measure the deformation pattern and
determine some details of the fracture orientation. Dipping and horizontal fractures induce
distinct patterns, which are easy to separate from vertical fractures, and it is straightforward to

8|P a g e
resolve the azimuth and dip of the fractures with a surface array. The amplitude of the tilt signal
and the width of the deformed zone can be used to determine the depth to the fracture’s center
and the fracture volume. If significant height growth were to occur, it would be observable in
the surface tiltmeter data. In addition, the mode of fracturing can be closely monitored, such as
multiplanar fractures or the case where a vertical fracture turns horizontal, or vice versa.

Downhole tiltmeters, when installed in a wellbore near the treatment well with an array
sufficiently long to span the fractured interval’s thickness, can directly measure the height of a
hydraulic fracture.

3. FRACTURE-MAPPING DATA

Figures 2 through 5 present plots of data collected on thousands of hydraulic fracturing

treatments in some of the most active shale plays in North America: the Barnett shale of Texas,
the Woodford shale of Oklahoma, the Marcellus shale in the northeastern US, and the Eagle
Ford shale in south Texas, respectively. More fracture treatments have been mapped in the
Barnett than in any other reservoir. The methodology for the following graphs is consistent.

Each of the graphs illustrates the fracture top and bottom for all mapped fracture treatments
performed in each reservoir from early 2001 through the end of 2010. All depths are in true
vertical depth. Perforation depths are illustrated by the red band for each stage, with the mapped
fracture top and bottom illustrated by colored curves corresponding to the counties where they
took place. The deepest reported drinking water levels in each of the counties where these
fractures have been mapped are illustrated by the dark blue bars at the top of the individual
charts. Note that the depth scale in the vertical axis differs from reservoir to reservoir because
of large differences in the depths of the pay zones. As presented, the largest directly measured
upward growth of all of these mapped fractures still places the fracture tops several thousand
feet below the deepest known water well level in each of the reservoirs presented.

9|P a g e
 Figure 2: Barnett shale measured fracture heights sorted by depth and compared to aquifers.

Figure 2 illustrates that faults do not provide a mechanism whereby hydraulic fractures can
propagate to the surface. Most of the larger spikes (both downward and upward) are a result of
hydraulic fractures intercepting faults. This is because fault related microseisms can usually be
resolved from fracturing induced microseisms because of their different characteristics.
Hydraulic fracture vertical growth in faults is restricted because of limited volumetrics, and the
microseismic data clearly present that even the fault intersections do not result in unbounded
fracture-height growth.

The Woodford shale data, illustrated in Figure 3, are interesting because of the exceedingly
complex geology. As presented, these Woodford completions span a large vertical interval
from wells as deep as 14,000 ft to shallow wells at approximately 4,500 ft. The Woodford’s
geologic structure can include substantial faulting, highly dipping bedding planes, overturned
beds where a vertical wellbore could intersect the same series twice, and all manner of geologic
complexity. The fracture-height results would be expected to be influenced by this complexity,
but the general interpretation is the same as for the Barnett: hydraulic fracture heights are

10 | P a g e
relatively well contained, there is some fault interaction, and the fractures remain separated
from the local aquifers by large distances.

Figure 3: Woodford shale measured fracture heights sorted by depth and compared to aquifers.

The Marcellus data in Figure 4 present a similarly large distance between the top of the tallest
fracture and the location of the deepest drinking water levels. Because it is a newer play (fewer
mapped fracture stages at this point) and encompasses several states, the data set is not as
comprehensive as that from the Barnett, but it is no less compelling in providing evidence of
good physical separation between hydraulic fracture tops and aquifers. Hundreds of fracture
stages are presented in Figure 4 and are color coded by state. The fractures grow upward much
taller than was seen in the Barnett (some fractures grew nearly 1,500 ft), but the shallowest
fracture tops are still around 4,800 ft, almost a mile below the surface and thousands of feet
below the aquifers in those counties. Only the two shallow tests at the far right in Figure 4
come within 2,000 ft of the water-well levels, and this occurs only because the wells are very
shallow.

11 | P a g e
 Figure 4: Marcellus shale measured fracture heights sorted by depth and compared to aquifers.

The Eagle Ford shale data presented in Figure 5, much like those of the Woodford shale, exhibit
very little out-of-zone height growth. Very little growth is observed into the overlying Austin
chalk or the underlying Buda limestone. Another important feature of the fractures mapped in
all of these shale reservoirs is that the tallest fractures (those with most significant fracture-
height growth) occur in the deepest wells in a given reservoir and, in general, the shallowest
wells in a given reservoir have the least measured fracture height.

12 | P a g e
 Figure 5: Eagle Ford shale measured fracture heights sorted by depth and compared to aquifers.

Tiltmeter data in Figure 6 illustrate the vertical and horizontal components from more than
10,000 fractures mapped throughout the past decade with surface tiltmeters in numerous types
of reservoirs at all depths across North America. Each point on the map is a separate fracture
treatment, and the hydraulic-fracture volume from that particular fracture job is correlated to
the horizontal vs. vertical fracture volume percentage scale at the top. The scale is the
percentage of fracture fluid in a single treatment distributed in the given fracture dip so that a
0% fracture component would be a fracture that is vertical and 100% would be a fracture that
was 100% horizontal. The larger the horizontal component, the less fracture-height growth one
would expect (i.e., a 100% horizontal fracture would have a small height equal only to the
fracture’s width). As illustrated from the blue curve, which is the average of all fracture dips,
fractures are largely vertical until the wells get shallower than approximately 4,000 ft, at which
point the fracture complexity (ratio of horizontal-to-vertical fracture-volume distribution)
begins to increase steadily. Above 2,000 ft, fracture components are largely horizontal, which
leads one to expect minimal fracture-height growth in these shallower reservoirs. Although a
totally separate methodology (deformation) from microseismic mapping, tiltmeters confirm

13 | P a g e
one of the mechanisms responsible for limited fracture-height growth in shallower wells. As
well depth decreases, the overburden (weight of rock above the wellbore) lessens. At some
point in shallow wells, the overburden stress will decrease to a point where it is less than the
maximum horizontal stress and, at this point, one would expect the fracture growth to be
horizontal and not vertical. As wells get shallower, and the overburden stress lessens, mapped
fractures are typically observed exhibiting increasingly larger horizontal components. All of
the fractures do not necessarily turn horizontal; they might have significant vertical and
horizontal components with more of a T-shaped geometry, but the horizontal components can
become significant and could thieve away enough fluid to cause a blunting effect, limiting
upward fracture-height growth. Even in areas with the largest measured vertical fracture growth
(such as the Marcellus), the tops of the hydraulic fractures are still thousands of feet below the
deepest aquifers suitable for drinking water. As can be observed from the data in these
reservoirs, the huge distance separating the fractures from the nearest aquifers at their closest
point of approach demonstrates that hydraulic fractures are not growing into groundwater
aquifers and that fracture treatments themselves are unlikely to contaminate them.

Figure 6: Microdeformation (tiltmeter) measurements of horizontal vs. vertical fracture

components with depth.
14 | P a g e
The results from this extensive fracture mapping database showed that hydraulic fractures are
often better confined vertically (and are also longer and probably narrower) than conventional
wisdom or models predict. Examination of data from other studies might help explain why
fracture-height confinement is generally better than that predicted by fracture models.

4. FRACTURE-CONTAINMENT MECHANISMS

On the basis of mineback work performed in the 1970s and 1980s at the Nevada test site, it is
clear that hydraulic fractures are much more complex than envisioned by conventional models
of the process. Figures 7 through 9 illustrate three examples of how complexity is induced by
geologic factors and the wellbore itself. A multistranded vertical fracture is presented in Figure
7 in which the number of fracture strands increases where layering becomes more frequent, as
represented by the horizontal banding near the bottom of the photograph, but also where a
horizontal component has propagated to the left. This propped fracture was created with a
crosslinked fluid carrying three stages of colored sand (red, black, blue). The apparent
curvature of the fracture is actually the curvature of the mineback face; the main fracture is
vertical at this location.

Figure 7: Example mineback fracture showing multiple fracture strands and horizontal
components.

15 | P a g e
Figure 8 presents a fracture initiating from a wellbore (the white circular area near the bottom;
the wellbore was filled with cement) and having its path offset at a series of natural fractures.
The viewpoint in this photograph is looking up at the fracture, which starts out as a single
fracture, but becomes two fractures after intersecting and filling one of the natural fractures
that is oblique to the hydraulic-fracture trajectory.

Figure 8: Example mineback fracture near borehole showing offsets at natural fractures and two
parallel fractures.

Figure 9 presents a dyed-water fracture that has been initiated from a horizontal, cased, and
cemented wellbore through six perforations on both the top and bottom. Those fractures that
initiated from the bottom perforations are visible, and there are at least five separate strands
that can be identified in the photograph. It appears that each perforation was the initiation point
for a separate fracture and these all propagated independently for some distance (for scale, the
wellbore diameter is approximately 5 in.). The mineback did not go farther down, so it is not
known if the fractures ever coalesced into fewer strands.

16 | P a g e
 Figure 9: Example mineback fractures initiating from perforations in a horizontal wellbore;
multiple fractures have initiated from multiple perforations below the wellbore.

It is clear from the mineback examples in Figures 7 through 9 that fractures are much more
complex than envisioned by early modelers and practitioners. Figure 10 is a commonly used
schematic showing a hierarchy of complexity.

Figure 10: Schematics of levels of complexity observed in hydraulic fractures.

17 | P a g e
Instead of the simple planar fracture presented in the upper left, fractures in common geologic
environments show varying degrees of complexity, from the simple complex fracture that is
relatively planar in the upper right, to the complex fracture network in the lower right. As a
result of this complexity, fractures tend to grow shorter than they would if they were simple
planar features. The multiple strands provide additional walls that increase friction and thus
raise the fluid pressure, causing wider cracks, and the additional walls also provide a large
amount of added surface area for leakoff of the injected fluid. As a result, complex fractures
are shorter and wider than simple fractures and both their height growth and length growth are
reduced.

Given this complexity in a relatively simple fracturing environment, it becomes clear that the
height-growth mechanisms in a complex sedimentary basin that is perturbed by structure and
natural fractures will likely be dominated by the layering and heterogeneities of both properties
and stress. A brief discussion of each of the important mechanisms follows.

4.1 In-Situ Stress

The in-situ stress contrasts clearly have the most significant effect on fracture-height growth.
The importance of stress was recognized early on and has been extensively studied in modeling,
mineback tests, and numerous laboratory experiments.

Fracture-height growth can be easily restricted if the layers above and below have higher stress
than the reservoir rock, and this is a common occurrence in sedimentary basins. An equilibrium
(static) analysis of the linear elastic fracture mechanics behavior of a fracture surrounded by
rocks with higher stress, as illustrated in Figure 11, was given by Simonson et al. (1978) for a
symmetric case (stresses above and below are equal). They obtained the following equation:

…………………………………………………. (Eq.1)

18 | P a g e
 Figure 11: Geometry for fracture-height calculations.

Where P is the net pressure in the fracture, 𝜎1 is the stress in the pay zone, 𝜎2 is the stress in
the bounding layers, h is the thickness of the pay zone, H is the total fracture height, and 𝐾𝑙𝑐 is
the fracture toughness of the bounding layers. In this equation, the first term on the right side
is a result of the stress contrasts, while the second term is a result of fracture toughness. For
standard laboratory values of fracture toughness, the second term is generally small. In general,
this equation is conservative because there are other dynamic factors that affect the amount of
height growth that will occur. For example, if P > 𝜎2 , the equation would predict unlimited
growth, but the flow resistance through the narrower width of the high-stress region would
restrict growth vertically compared to laterally. Similar equations can be developed for
nonsymmetric stress contrasts, but more complete dynamic analyses are usually performed in
fracture models.

This mechanism is only effective if there are sufficiently high stresses in the sedimentary
layers. The most complete record of stress in a basin is probably that from the multi well and
multisite experiments in the Piceance basin of Colorado. The stress data are illustrated in Figure

19 | P a g e
12 and represent the stresses measured by small volume hydraulic fractures in both reservoir
(blue symbols) and nonreservoir (red symbols) rocks. As would be expected, the general trend
is one of increasing stress with depth, but there are large variations across layers that act to
“trap” fractures in low stress zones because it requires less energy to grow against a low stress.
Because the layered depositional environment in sedimentary basins has such variability in
stress, it is highly unlikely that fractures could propagate very far vertically. Also illustrated
for reference is the lithostatic stress in these tight rocks. Many of the nonreservoir lithologies
that are clay rich or organics rich have stresses that are near or at the lithostatic stress.

Figure 12: Stress data from the Piceance basin.

20 | P a g e
4.2 Material-Property Contrasts

There are three issues of concern with material-property contrasts between layers. The first one
deals with the effect of a fracture approaching an interface with modulus contrasts. The second
one deals with the effect of modulus on the width of the fracture and the increased or
diminished flow resistance caused by a width change. The third one is caused by differences
in the fracture toughness in the various layers. While Simonson et al. (1978) showed that a
material-property interface in an ideal situation could blunt fracture growth, years of fracturing
experience, fracture-diagnostic monitoring, mineback testing, and other research have
demonstrated that this is not the case. Figure 13 illustrates an example of a dyed-water fracture
that has propagated through an interface from a low-modulus material into a high-modulus
material. A more complete discussion of the role of the interface has been given by Cleary
(1978), where the complexities of the interface, the micromechanics of the fracturing process,
the potential for blunting and twisting (no longer only Mode I fracture growth), and various
other factors make any systematic conclusions from the interface mechanics quite problematic.

Figure 13: Mineback photograph of dyed-water fracture propagating across interface.

21 | P a g e
Modulus contrasts clearly have an effect on the width of the fracture and can be expected to
enhance or restrict fluid flow appropriately.

Fracture toughness can have a significant impact on fracture growth if the stress contrasts are
small, as can be seen by setting 𝜎2 = 𝜎1 in Eq. 1. A large value of 𝐾𝑙𝑐 will either induce a high
pressure or restrict the height or both. For a homogeneous formation, the stress-intensity factor
at the top of the fracture can be computed if the net stress distribution is known by

…………………………………….………………. (Eq.2)

where p(y) is the net stress distribution vertically. If the stress-intensity factor exceeds the
fracture toughness of the material, the fracture will propagate. Obviously, the situation becomes
more complex (and not analytic) for layered materials with different elastic properties, but Eq.
2 provides a rough estimate of the fracture stability.

Laboratory experiments have generally proven that fracture toughness varies over only a
limited range, which suggests that fracture-toughness effects will be rather limited. However,
the scale dependence of fracture toughness (or potentially other types of tip effects) is not well
understood for large-scale fractures, so there may be potential for fracture containment because
of this mechanism.

4.3 Weak Interfaces

It is well known that weak interfaces can blunt fracture growth, and such a mechanism is often
cited for the use of the Khristianovich, Geertsma, and De Klerk models (Nierode 1985).
Examples of blunting have been noted in mineback experiments (Warpinski et al 1982a, b;
Warpinski and Teufel 1987; Jeffrey et al. 1992; Zhang et al. 2007) and laboratory experiments

(Anderson 1981; Teufel and Clark 1984). Figure 14 illustrates an example of a mineback
fracture terminating at a weak interface. The fracture was created with a crosslinked gel having

22 | P a g e
three stages of colored proppant (sand) in order of black, red, and blue. Dense sand is observed
right up to the interface, which suggests that it was wide, as would be expected with a blunted
fracture. The fracture was approximately 30 ft tall and 50 ft long, and Figure 14 shows only a
small segment that was left after mining to show the interfacial effects.

Figure 14: Mineback photograph of fracture terminating at a weak interface.

While it is generally expected that weak interfaces will be most important in stopping fracture-
height growth at shallow depths where friction caused by the overburden stress is at a
minimum, other factors such as over pressuring or embedded particulates (equivalent to a fault
gouge) can clearly minimize frictional effects even at great depths. Weak interfaces have the
potential of totally stopping vertical fracture growth, initiating interface fractures, or causing
offsets in the fracture. Figure 15 presents an example of a fracture that is crossing unhealed
natural fractures, which is equivalent to the case of a weak interface with some permeability
along the interface. This example illustrates offsets at the fractures at a location close to the
wellbore. Cement was used as the fracturing fluid for this test to preserve the width of the
23 | P a g e
fracture. Such offsets would clearly restrict fracture growth because of the narrower width of
the fracture in the offset and the possibility of proppant bridging.

Figure 15: Mineback photograph of fracture terminating at a weak interface.

In addition to restricted-growth effects, weak interfaces above and below the reservoir can
decouple the fracture walls, which results in poor coupling of the fracture pressure in the
reservoir to the fracture outside of the weak interfaces. This reduced coupling creates narrower
fractures in the layers across the interface and much wider fractures within the reservoir rock.

24 | P a g e
4.4 Layered Interfaces

All of the mechanisms previously discussed can be bundled together to describe fracturing
across a succession of interfaces. The possibility that such layered media could contain
hydraulic fractures has been derived from fracture diagnostic information. It is easy to conceive
of multiple mechanisms serving to blunt, kink, offset, bifurcate, and restrict growth in various
layers, much as a composite material hinders fracture growth across it. Various methods are
now being used to model such behavior. Several of the mechanisms are presented in Figure 16,
which is a mineback photograph of a fracture propagating upward across several interfaces.
The left side is the unaltered photograph, while the right side has the fracture accentuated with
a line drawn over it. Kinking, offsetting, and bending occurred as the fracture made its way
through the layers. In other cases, additional fractures are initiated or some fractures are
terminated.

Figure 16: Mineback photograph (and line drawing) of fracture kinking, offsetting,
and turning as interface is crossed.

25 | P a g e
Figure 17 presents a schematic of several types of behavior that have been observed in
minebacks or laboratory tests. The result of these behaviors could be any combination of
complexity, restriction, or termination of the fracture as it propagates across the layered
medium, often collectively termed the “composite layer effect.” Restrictions should be
common if kinking or offsets occur because the width in the kink or offset will necessarily be
less than in the vertical part of the fracture from both geometric and stress considerations. These
kinks, offsets, and restrictions lead to less fracture-height growth than one would expect from
a single, simple fracture.

Figure 17: Schematic of pathologies for fracture behavior in a layered sequence.

4.5 Fluid-Pressure Gradient

Simonson et al. (1978) described the relative effects of fluid-pressure gradient compared with
the rock stress gradient. This is one mechanism that is conducive to height growth, but for
normal fracture heights of a few hundred feet, it is a small effect. However, it is possible to
evaluate what would happen if there were tall fractures in a medium without all of the stress
variations that typically are found in sedimentary basins. Figure 18 illustrates that the lower
fluid-pressure gradient would cause a large overpressure at the top of a tall fracture. This case
26 | P a g e
has a linearly varying stress profile (no stress contrasts in layers), a normal fluid-pressure
gradient, and a tall fracture that is growing upward so that the entry point is at the bottom.
England and Green (1963) provide a solution for a 2D crack that can be used to determine the
fracture width for a similar distribution.

Figure 18: Example calculation of fracture size for tall fracture.

The net pressure distribution is derived as the difference between the fluid-pressure gradient
and stress-pressure gradient, assuming that the net pressure at the bottom is essentially zero.
The fracture height is H, and the vertical coordinate is y. The average pressure in the fracture
(at the centerline) is p and the gradient is given by k, so that the net pressure anywhere in the
fracture is given by p + ky. The equations for fracture width and area, respectively, in this case
are

………………..…………………….………………. (Eq.3)

27 | P a g e
And

………………..………………………………...….………………. (Eq.4)

where v is Poisson’s ratio and E is Young’s modulus. The minimum p needed to keep the
fracture open is kH/4.

The profile on the right in Figure 18 is calculated for a total fracture height of 2,000 ft in a
material with E = 4×106 psi, v = 0.2, k = 0.26 psi/ft (the difference between a 0.7 psi/ft stress
gradient and a 0.44 psi/ft fluid gradient), and p = 130 psi. The width in the upper portion of the
fracture is approximately 0.15 ft.

The important point here is that the fracture volume will become enormous as the fracture
grows upward, making it impossible for typical fracture-fluid volumes to grow to these extents.
For this case, if a typical total fracture length of 1,000 ft is assumed, the fracture volume would
be 35,000 bbl, assuming zero leakoff. If the fracture height grows to 4,000 ft, the volume
requirement is 280,000 bbl. However, it is obvious that leakoff would also be enormous
because of such large fracture areas. In short, the stress conditions that would encourage
fracture growth upward would also result in large fracture widths that require enormous
volumes of fluid to continue propagating. These volumes are an order of magnitude more than
what is typically pumped in a fracture treatment, so the volumetrics will not support unlimited
height growth.

4.6 Faults

Faults offer a potential conductive surface that can be through-going in the layered media,
minimizing many of the restrictive mechanisms discussed previously, with the exception of
remaining sensitive to stress variations. While faults can offer somewhat better conductive
paths, it is not likely that they are conductive over sizeable fractions of the depth because any
oil or gas in the reservoir would have escaped through such conduits and there would not be
any hydrocarbon exploitation success in that area. Microseismicity has proven that faults can
28 | P a g e
be activated by fluid injection and that much-larger-magnitude events can be generated,
presumably because of the large fault surface area available to move. Such faults are commonly
and easily seen in the microseismic data, and there often is some limited additional height
growth associated with fault reactivation. The additional height growth tends to range from a
few hundred to as much as 1,000 ft in isolated cases. Nevertheless, it is clear from abundant
microseismic and surface-tiltmeter data that extensive fracture growth does not occur in faults.

4.7 High-Permeability Layers

High-permeability layers have a significant effect on fracture growth because they can either
act as thief zones that accept fluid and reduce the fracture-driving forces (typical if gas
saturated) or can induce a large poroelastic back stress that clamps down on the fracture (typical
if liquid saturated). This type of containment mechanism is difficult to measure in field tests
but can be proven by means of modeling or laboratory tests.

5. IMPLICATIONS

The implications of these monitoring data sets and the review of mechanisms are
straightforward and clear. Under normal circumstances, where hydraulic fractures are
conducted at depth, there is no method by which a fracture is going to propagate through the
various rock layers and reach the surface. This fact is observed in all of the mapping data and
is expected on the basis of the application of basic rock-mechanics principles deduced from
mineback, core, laboratory, and modeling studies.

The vertical growth of fractures in sedimentary basins is hindered by the layering of the
materials. The varying material properties of the layers and the variable interface properties,
together with the large stress contrasts that are largely a result of these properties and interface
variations, create an environment where vertical fracture growth is hindered and lateral fracture
growth is favored.

29 | P a g e
Outside factors, such as faults, are regularly observed in the monitoring data. Although
intersection of a hydraulic fracture with these faults can result in some additional height growth,
the amount of growth has been found to be limited everywhere it has been observed. It is clear
that a fault can provide a path for fractures to propagate through a limited region in the vicinity
of the reservoir, but the amount of growth is restricted by the same factors that resist height
growth in nonfaulted regions, and also by the volumetrics of the process. As noted previously,
any area where there might be an open fault that extends to the surface would also be devoid
of hydrocarbons because they would have leaked out over geologic time.

Near-surface hydraulic fracturing is a situation that is primarily controlled by the stress

conditions in the reservoir. At depths of less than 1,000 to 2,000 ft, the vertical stress is the
minimum stress in all sedimentary basins where measurements have been made and hydraulic
fractures will primarily be horizontal. While a number of shallow individual layers may have
a horizontal in-situ stress that is the minimum stress so that fractures within that layer are
vertical, the bulk of a near-surface sedimentary rock mass would have horizontal fractures that
do not propagate vertically. Any mixed growth having both horizontal and vertical fractures
would significantly limit vertical growth, more so than in deeper layers. This behavior is clearly
observed in the tiltmeter data taken from many basins and depths.

6. CONCLUSIONS

Real data collected using microseismic and microdeformation fracture-mapping technologies

on many thousands of hydraulic fracturing jobs indicate that hydraulic-fracture heights are
relatively well contained. The directly measured height growth is often less than that predicted
by conventional hydraulic-fracture propagation models because of a number of containment
mechanisms. Many of those mechanisms can be best explained by careful review of several
mineback experiments, where real hydraulic fractures in the subsurface were able to be
physically viewed and studied. Some of those mechanisms include complex geologic layering,
changing material properties, the presence of higher permeability layers, the presence of natural

30 | P a g e
fractures, formation of hydraulic-fracture networks, and the effects of high fluid leakoff. The
effects of pre-existing faults are noted and observed in the mapping results, and the relatively
negligible effect of faulting on hydraulic-fracture-height growth is discussed.

Fracture physics, formation mechanical properties, the layered depositional environment, and
other factors all conspire to limit hydraulic-fracture-height growth, causing the fracture to
remain in the nearby vicinity of the targeted reservoirs. This certainly is a positive feature of
hydraulic fracturing and allows many otherwise noncommercial-quality reservoirs to produce
hydrocarbons commercially and safely.

Public discourse continues around hydraulic fracturing. The authors have shown real fracture-
growth data from thousands of treatments in several of the most active shale plays where
hydraulic fracturing is a “must-have,” where without it, there would be little to no production
or reserves growth. It might be instructive to step back from the public debate and recognize,
from real data collected starting more than a decade ago and from government sponsored
mineback studies performed as far back as the 1970s, that fracture physics, height growth, and
containment mechanisms have already been extensively studied and documented in an effort
to make hydraulic fracturing more effective. These same early studies, performed outside of
today’s highly charged climate of debate, reveal significant and relevant data to promote
informed discussions about hydraulic-fracture growth and its environmental impact.

31 | P a g e
7. NOMENCLATURE

A = fracture area, L2, ft2 [m2]

E = Young’s modulus, M/LS2, psi [MPa]
h = thickness of reservoir, L, ft [m]
H = fracture height, L, ft [m]
K = vertical net pressure gradient in fracture, M/S2, psi/ft [MPa/m]
KI = stress-intensity factor, M/S2√L, psi √in. [kPa √m]
K lc = fracture toughness, M/S2√L, psi √in. [kPa √m]
p = average pressure in fracture, M/LS2, psi [MPa]
P = pressure in fracture, M/S2√L, psi [MPa]
W = fracture width, L, ft [m]
Y = vertical distance from center of fracture, L, ft [m]
ν = Poisson’s ratio
𝜎1 = stress in reservoir, M/LS2, psi [MPa]
𝜎2 = stress in layers outside reservoir, M/LS2, psi [MPa]

8. REFERENCES

1. Albright, J.N. and Pearson, C.F. 1982. Acoustic Emissions as a Tool for Hydraulic Fracture
Location: Experience at the Fenton Hill Hot Dry Rock Site. SPE J. 22 (4): 523–530. SPE-
9509-PA. http://dx.doi. org/10.2118/9509-PA.

2. Anderson, G.D. 1981. Effects of Friction on Hydraulic Fracture Growth Near Unbonded
Interfaces in Rocks. SPE J. 21 (1): 21–29. SPE-8347-PA. http://dx.doi.org/10.2118/8347-
PA.

3. Barree, R.D. and Winterfeld, P.H. 1998. Effects of Shear Planes and Interfacial Slippage on
Fracture Growth and Treating Pressures. Paper SPE 48926 presented at the SPE Annual
Technical Conference and Exhibition, New Orleans, 27–30 September.
http://dx.doi.org/10.2118/48926-MS.
32 | P a g e
4. Branagan, P., Peterson, R., Warpinski, N., and Wright, T. 1997. Results of Multi-Site Project
Experimentation in the B-Sand Interval: Fracture Diagnostics and Hydraulic Fracture
Intersection. Topical report GRI-96/0225, DOE/MC/30070-5218, Gas Research Institute,
Chicago, Illinois (December 1997),
http://www.netl.doe.gov/publications/others/techrpts/dec1997.pdf.

5. Cleary, M.P. 1978. Primary Factors Governing Hydraulic Fractures in Hetrogeneous

Stratified Porous Formations. Paper 78-Pet-47 presented at the ASME Energy Technology
Conference, Houston, 5–9 November.

6. Cleary, M.P. 1980. Analysis of Mechanisms and Procedures for Producing Favourable
Shapes of Hydraulic Fractures. Paper SPE 9260 presented at the SPE Annual Technical
Conference and Exhibition, Dallas, 21–24 September. http://dx.doi.org/10.2118/9260-MS.

7. de Pater, C.J. and Dong, Y. 2009. Fracture Containment in Soft Sands by Permeability or
Strength Contrasts. Paper SPE 119634 presented at the SPE Hydraulic Fracturing
Technology Conference, The Woodlands, Texas, USA, 19–21 January.
http://dx.doi.org/10.2118/119634-MS.

8. Economides, M.J. and Nolte, K.G. 2000. Reservoir Stimulation, third edition. New York:
John Wiley & Sons.

9. Simonson, E.R., Abou-Sayed, A.S., and Clifton, R.J. 1978. Containment of Massive
Hydraulic Fractures. SPE J. 18 (1): 27–32. SPE-6089-PA. http://dx.doi.org/10.2118/6089-
PA.

10. Warpinski, N. 2009. Microseismic Monitoring: Inside and Out. Distinguished Author
Series, J Pet Technol 61 (11): 80–85. SPE-118537-MS. http://dx.doi.org/10.2118/118537-
MS.

11. Warpinski, N.R. and Teufel, L.W. 1987. Influence of Geologic Discontinuities on
Hydraulic Fracture Propagation. J Pet Technol 39 (2): 209–220. SPE-13224-PA.
http://dx.doi.org/10.2118/13224-PA.

12. Kevin Fisher and Norm Warpinski, SPE, Pinnacle—A Halliburton Service.
33 | P a g e