INTRODUCTION
Hydraulic fracturing is widely used to improve the performance of wells that
serve a wide variety of applications, from the production of oil from reservoirs to the removal of contaminants from aquifers. Techniques for fracturing oil reservoirs have been
used in the petroleum industry for more than 50 years to improve recovery; and hydraulic
fracturing is currently the most widely used process in use for stimulating oil and gas
wells (Gidley, 1989, and others). During the past 15 years, hydraulic fracturing has been
developed for use in near-surface applications for environmental remediation purposes
(Murdoch and Slack, 2002). Hydraulic fracturing is the process of pumping a fluid into
a geologic formation until a critical pressure is achieved, at which point a fracture is initiated. As more fluid is injected, the fracture will dilate and propagate away from the
borehole where it was initiated. The amount of dilation of a fracture, the distance between the upper and lower surfaces, is termed aperture. The fracture will continue to
propagate as fluid pressure is maintained. When fluid pressure is relieved after injection,
the fracture will close and the aperture will decrease until each fracture wall rests on asperities in the opposing wall.
Investigations show that the effective transmissivity of a hydraulic fracture needs
to be relatively high for the fracture to increase well productivity significantly (Howard
and Fast, 1970). One method for creating a transmissive fracture involves injecting granular solids into the crack during propagation. The walls of the fracture are inhibited from
closing after propagation as they are held open by the granules. Techniques for filling
hydraulic fractures with granular solids were developed in the oil industry, where the
granules are termed proppants because they “prop” the fracture open. Those terms are
used in this work.
Fracture form determines how well a hydraulic fracture will improve the performance of a well (Bradner, 2002). Form is the shape, orientation, and thickness of a fracture. The forms of hydraulic fractures created at shallow depths are known from studies
where the vicinity of fractures were excavated, or explored using split-spoon sampling
(Murdoch and Slack, 2002). In general, the form ranges from a roughly flat-lying, nearly
circular feature, to a steeply dipping sheet. The typical form of shallow hydraulic fractures is a flat-lying to gently dipping feature that dips back toward the initiating borehole
to create a surface shaped like a gently curved bowl. However, some fractures appear to
be asymmetric, like a bowl with flattened side.
Fracture form appears to result from interactions between the processes used to
create the feature, and the conditions at the site. In particular, the state of stress at the site
and material properties, such as the elastic modulus and the fracture toughness appear to
be particularly important. In addition, the presence of geologic layering (e.g. bedding,
foliation) may also affect form. As a result, geological conditions are known to be a major factor affecting the form of a hydraulic fracture.
Site conditions are considered to be the most dominant control on fracture form,
although their role is incompletely understood. Fracturing methods are engineered to optimize fracture performance and facilitate the fracturing process based on site conditions.
As a result, the methods are as varied as the conditions under which fractures have been
created. An overview of hydraulic fracturing in the oil-industry is provided by Howard
2
and Fast (1970). This study used methods adapted from Murdoch (1995), which were
developed for shallow fracturing activities. These basic methods have been used in more
than 19 U.S. states and 2 other countries. Because fracture form is influenced by methods used to initiate and propagate the fracture, it was desirable to use methods that could
be compared to observations from other geologic regions. It is expected that the results
of this study will provide useful tools for predicting and modeling fracture form in soils
at other sites.
Many of the previous studies on the forms of hydraulic fractures created at shallow depths were done in silty clay glacial tills in the mid-western U.S. (Murdoch, 1995;
Murdoch and Slack, 2002). Clay-rich saprolite underlies much of the Piedmont region of
the eastern U.S., and hydraulic fractures should be well suited to improving remediation
efforts in this material. The forms of hydraulic fractures in shallow saprolite have been
reported briefly by Frere and Baker (1995) and they seem to resemble forms observed in
glacial tills. Those descriptions are brief, however, so the details of the forms of hydraulic fractures in saprolitic soils remain poorly known.
Objective
The objective of this investigation is to describe the forms of hydraulic fractures
in saprolite and compare them with the forms created in other settings. In addition, important aspects of the form will be described in greater detail than in any other published
account. Another objective is to evaluate the feasibility of tracing the movement of sand
within a hydraulic fracture in order to confirm, modify, or develop new concepts for explaining sand movement in the fracture.
3
Approach
The approach to meeting the objectives of this study is to monitor the creation of
four hydraulic fractures at a depth of 5 ft in at a test site near the city of Pendleton in Anderson County, South Carolina. The fractures are designated F, G, H, and I, and the
pipes through which the fractures were created are referred to as injection casings. Three
colors of sand were injected into the fractures to trace the paths of sand migration in the
fractures. The vicinity of the fractures was excavated and the fractures will be mapped
using typical geological techniques. Details of the fracture form and patterns of sand migration were determined from the mapping results.
Background information on relevant processes and factors affecting hydraulic
fractures will be presented in Chapter 1, followed by an overview of the conditions at the
test site in Chapter 2. The methods used to create and monitor the hydraulic fractures,
and the techniques used to characterize them are described in Chapter 3. Results of the
investigation will be presented in Chapter 4, and a conceptual model of the processes inferred from the field observations is described in Chapter 5.
4
1
BACKGROUND
The forms of hydraulically induced fractures are of interest because of its importance to fracture performance. However, comprehensive descriptions of fracture form
and mechanisms of formation have not been published. Direct observation of fracture
form can be difficult, as they are subsurface features. Consequently, much of what is
known about fracture form is inferred from indirect observations.
The various methods of monitoring and evaluating form of fractures created in the
field can be divided into two main groups. One group consists of methods that are undertaken during the fracturing process, primarily at the ground surface. The other group of
methods includes subsurface sampling, monitoring, and excavation before, during or after
the fracture creation.
The methods of evaluating the forms of fractures that take place during fracturing
activities are primarily above-ground techniques. These techniques take advantage of a
surface deformation phenomenon observed during fracturing termed uplift. Uplift is produced when the opening of the fracture causes vertical displacements in the ground surface. A fracture will begin to uplift the ground surface when the fracture length is 2 to 3
times the depth (Murdoch, 1995; Pollard and Holzhausen, 1979). Both the oil and environmental industries commonly use arrays of tiltmeters to measure uplift during fracturing. These tiltmeters can be extraordinarily sensitive and detect ground displacements as
small as 2 mm over distances greater than 150 km (Lacy, 1987).
5
Surveying has proven to be a reliable and efficient means to measure uplift in
shallow environmental applications. The lateral extent of these fractures is generally
small enough that a single point level station can resolve surface elevations to the nearest
1.0 mm. The relationship between this measured uplift and fracture form has been studied by Murdoch and Slack (2002). They showed that for gently dipping fractures, the
surface area represented by the extent of uplift is a good approximation of the lateral extent of the fracture. Furthermore, they demonstrated that the sand thickness could be estimated by the uplift multiplied by the sand loading of the slurry in the fracture. Sand
loading is the ratio of the volume of sand to the total volume of a sample of slurry which
has been allowed to settle fully. The volume of slurry injected into a fracture will determine the volume of soil that a fracture will displace and which is measured as uplift.
This inflated volume of a fracture is referred to as fracture aperture. Sand thickness is
used to describe the distance between the upper and lower fracture surface filled with
sand. It is expected that sand thickness is a result of the sand loading of the slurry in that
portion of the fracture when the fluid portion of the slurry is gone.
Core samples are commonly used in both petroleum industry and environmental
applications. When cores intersect the fracture plane, the fracture properties can be
measured directly. More often in the petroleum industry, the core sample is used to test
the properties (e.g. state of stress) at the target fracture depth in order to predict the fracture form preferential to those properties. Iridium is sometimes added to the proppant,
which allows the vertical distribution of a fracture to be resolved from pre- and postfracture gamma surveys (W. Slack, personal communication). Other subsurface moni-
6
toring techniques include a wide variety of other geophysical methods and intra-well
pulse testing (Lacy, 1987).
The methods of modeling fracture form continue to evolve. Verification of models requires accurate, detailed observations of forms of fractures in the field. A 2-D axisymmetric model, which is able to predict fracture form and surface deformation, is currently under development by Qingfeng Tan at Clemson University. The model was tested with site data from this study presented herein and the model predicted fracture elevation and surface uplift profiles which closely agree with observations from this study. A
significant finding from this test was that the fracture propagated downward near the initiation point in response to an underlying material with a lower elastic modulus.
Laboratory bench tests modeling fracture form and propagation are useful, as material physical properties and stress regime can be closely controlled. In 1992, Larry
Murdoch published results from such tests on soils, simulating near-surface conditions.
Several projects are in progress at Georgia Tech under the direction of Leonid Germanovic examining fracture propagation mechanics.
Murdoch and Slack (2002) provided a summary of several aspects of fracture
form based on observations of uplift, core samples, and trench mapping activities. These
observations were from several hundred fractures created using the methods presented by
Murdoch (1994). They found that fractures were generally gently dipping, elongate features. Dip of the fractures averaged 10°, generally ranging between 0° and 20°. The
fractures were typically elliptical in plan view (Fig. 0-1). The ellipses had a mean aspect
ratio of 6:5 (1.2:1), and were offset from the injection casing. Sand thickness was greatest near the center of the fractures and tapered towards the edges. The forms of fractures
7
created under similar geologic conditions were similar. Greater variability was observed
between fractures created in differing geologic conditions.
There is a significant amount of unpublished work on hydraulic fracturing in the
Piedmont Province of the eastern U.S. More than 50 fractures have been created within a
few miles of the study site at depths less than 10 feet below ground surface (bgs). Approximately 10 fractures were initiated at depths ranging from 20 to 50 feet bgs in
Greenville, SC. Limited observations from core samples of these fractures indicate that
many of the forms of fractures in saprolite are similar to those reported in glacial tills by
Murdoch and Slack (2002).
Figure 1 Generalized form of a hydraulic fracture (Murdoch and Slack,
2002).
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1.1
Controls on Form
Previous investigations suggest that site conditions are the primary control of the
form of a hydraulic fracture, but some influence of fracture form can be achieved by engineering measures. Engineering measures include all methods used to create the fractures. Various aspects of these two controls will be described in the following sections.
1.1.1
Site Conditions Affecting Fracture Form
Site conditions that currently appear to influence fracture form are the state of
stress, mechanical properties, permeability, heterogeneities, and anthropomorphic features.
1.1.1.1 State of Stress
The state of stress is the dominant control of fracture orientation in soil and rock
(Daneshy, 1976). The state of stress is defined by the magnitudes and orientations of the
three principle stresses. At shallow depths beneath flat-lying ground, the principle stresses are typically oriented either vertically or horizontally. Vertical stress is generally assumed to be the product of depth and the average unit weight of the overburden (Davis,
1983). Horizontal stresses also increase with depth and unit weight, but other processes
related to the history of the region can also influence the magnitude of horizontal stress.
For example, the horizontal stress in recently deposited sedimentary material that has is
typically slightly less than the vertical stress. However, removal of overburden by erosion can decrease the vertical stress more than the horizontal stress to the point where the
9
vertical compressive stress is actually less than the horizontal compression. Repeated
cycles of wetting and drying can increase the horizontal stress relative to the vertical
stress, and this process appears to influence the state of stress within a few meters of the
ground surface at many locations. Tectonic processes can also increase the lateral stresses in rocks.
The ratio of horizontal to vertical stress (Ko, the coefficient of earth pressure at
rest) is an aspect of state of stress. It is well established that a fracture will propagate
normal to the least compressive stress (Abou-Sayed, 1984). Hydraulic fractures are more
likely to be vertical where the least compressive stress is horizontal, and Ko < 1.0, whereas fractures are more likely to be horizontal in regions of high lateral compression where
Ko > 1.0. Most applications of hydraulic fracture in oil and gas reservoirs are thousands
of feet below ground surface where Ko < 1.0 and fractures are typically vertical. Fractures for environmental remediation are generally initiated less than 100 feet bgs, where
the vertical stress is much less than it is in oil and gas reservoirs where Ko ranges from
0.6 to 2.0 or more (Fairhurst, 1964). The orientation of shallow fractures can range from
flat-lying to vertical as a result of variations in Ko.
1.1.1.2 Mechanical Properties
The two primary mechanical properties of soils that control factor form are elastic
modulus (E) and fracture toughness (KIC). Elastic modulus is the ratio an applied stress
and the elastic strain produced by that stress, and conceptually it resembles the stiffness
of a spring. The elastic modulus affects the aperture of a fracture by influencing how the
enveloping material deforms in response to the load applied by the fracture. The aperture
10
of a hydraulic fracture will decrease and the length will increase as the modulus of the
material containing the fracture increases (Medlin 1982).
Fracture toughness is a material property used to describe the resistance of a material to fracture propagation. The fracture toughness of a material is related to the
strength of bonds between constituent particles and the size of flaws in the material.
Fracture toughness is widely used to describe fracture propagation through rock, and it
appears to be a valid predictor of fracture propagation in cohesive soils. In rock, fracture
toughness values are typically on the order of 1 MPa m1/2, whereas the fracture toughness
of partially saturated silty clay is less than 0.05 MPa m1/2 (Murdoch, 1993 b).
1.1.1.3 Permeability
The permeability of a media can have a pronounced effect on fracture form. The
higher the permeability, the greater the leakoff will be for a given fluid pressure and viscosity. Leakoff is the process of the fracturing fluid moving out of the fracture and into
the surrounding formation. Leakoff results in a shorter and thinner fracture than would
result if all of the fracturing fluid remained in the fracture. Additionally, leakoff will affect the mobility of the slurry injected into a fracture. Proppant can be deposited in the
fracture where the fluid content decreases due to leakoff. Fracture propagation can be
arrested altogether when proppant completely packs a fracture. This process is known as
screen-out (Gidley and others, 1987). Screen-out is a primary mechanism by which fracture propagation is arrested in permeable materials (Gidley and others 1987; Smith and
others, 1989).
11
1.1.1.4 Heterogeneities
Heterogeneity in subsurface materials and conditions can markedly affect fracture
form. Fractures created in glacial tills of Ohio and have been observed to preferentially
propagate along or nearly parallel to bedding planes (Murdoch, 1995).
Discontinuous features, such as dikes, veins, pods, and cobbles have been observed to significantly effect fracture form. These features present a rapid change in the
soil conditions through which the fracture is propagating. Propagation into a sand lens,
for instance, would likely result in increased leakoff and subsequent screen-out of the
fracture (Murdoch and others, 1991; Murdoch, 1995). Existing, naturally occurring fractures can have a similar effect, and can be a dominant control on fracture form in some
conditions (Beugelsdijk, 2000). However, fractures created in glacial tills in southern
Canada were observed to be sub-horizontal and cut through pre-existing vertical fractures
indicated by quartz veins (Frac-Rite, web-site photograph).
Burrow and root structures are another heterogeneity that can affect fracture form
by serving as preferential pathways for the fracturing fluid. Animal burrow structures, in
particular, which typically reach the ground surface, could make it difficult to impossible
to maintain enough fluid pressure to propagate a fracture.
1.1.1.5 Anthropomorphic Features
Anthropomorphic features are any change to the site conditions that result from
human activity. Excavations and borings can drastically alter natural conditions. Surface
loading, in the form of buildings and heavy equipment, can alter the state of stress in the
soil. Heavy equipment (fracturing equipment, forklifts) has been used to “steer” fractures
12
by placing the equipment directly opposite the desired propagation direction from the injection casing. This effect diminishes with increasing depth of fracture initiation.
1.1.2
Engineering Controls on Fracture Form
Engineering controls on fracture form consist of the materials chosen and the
methods used to create the fracture. The selection of materials is based on site conditions
and fracture performance design.
1.1.2.1 Proppant and Fracturing Fluid
Nearly any granular material can be used as a proppant, and it is chosen to optimize fracture performance and operational feasibility. The large volume and the high
confining pressures common in petroleum reservoirs are primary factors controlling
proppant selection. An example of this consideration is the use of sintered bauxite in
conditions of very high fracture closure stress that would crush many other materials and
render them less permeable (Gidley, 1989).
Silica sand is the most commonly used proppant in hydraulic fracturing, and sand
processed specifically for hydraulic is fracturing commercially available (Gidley, 1989).
This frac sand is typically well-sorted and has highly spherical grains, in order to maximize fracture permeability. Well-sorted, spherical grains are also less likely to cause a
screen out in the slurry pump or delivery hose. Filter pack sand is often used as a proppant, as it is more widely available commercially than frac sand. Filter pack sand has
been used throughout the U.S. to increase the productivity of injection and extraction
points for many of the most common remediation designs.
13
A variety of other materials have also been implemented, tested, or considered as
proppants in the environmental field. One area of considerable interest is the use of reactive materials targeted to the contaminant(s) of concern. A bioremediation project utilizing more than 80 fractures filled with micro-porous ceramic beads is currently operating
in the Coastal Plain of South Carolina (FRx, Inc., case study, 2003). Fractures propped
with graphite were used in a process to study the effects of electroosmosis on groundwater flow rates (Chen, 1999). There is currently interest in the use of hydrophobic beads as
a proppant in fractures to be used in vadose zone applications from which the fluid to be
extracted is a gas. A fracture propped with granular hydrophobic material should have
more gas filled pore space than otherwise identical fracture filled with a hydrophilic material.
Fracturing fluids are designed for a variety of different rheological characteristics
depending on operational and fracture-design demands. One of the most important characteristics is viscosity. A high viscosity fluid has two primary advantages. First, a more
viscous fluid is less likely to leak into the formation rather than fracture it. Secondly,
transportation of proppants is aided by a more viscous fluid. A variety of fluids including
foam-, oil-, and alcohol-based fluids have been tested, but one of the early developments
of the fracturing industry in the 1960’s was the use of water-based guar gel (Gidley,
1989).
Guar gel is an ideal choice for environmental applications because the breakdown
products are non-toxic. In fact, the guar powder used in this study is near food grade, and
guar gel is widely used in manufactured food products as a thickening agent. The product used to make the gel is a naturally occurring carbohydrate polymer or polysaccharide
14
processed from the guar bean which hydrates upon contact with water (Rogers, 1981).
When the polymer hydrates it uncoils, and these long chain polymers interacting with water results in a fluid referred to as unlinked gel, or simply gel. Guar gel is a nonNewtonian fluid, and has a viscosity of 34 centipoise at 511 seconds-1, similar to that of
mineral oil (Gidley 1989). A heavy metal ion, commonly a borate, can be added to this
unlinked gel solution causing a bond to form between the borate and the hydroxyl group
of the guar polymers (Gidley 1989). This results in a fluid referred to as crosslinked gel
which is a highly viscous material sometimes referred to as a pseudoplastic fluid (Gidley
1989).
Crosslinked guar gel behaves as a non-Newtonian fluid and exhibits highly variable rheological properties (Harrington 1979). It is beyond the scope of this study to evaluate the effect of gel rheology on fracture form, though the potential significance is recognized. For example, it is well documented that the viscosity of crosslinked guar gel
decreases with increasing shear stress (Williams, 1970). It should follow that as gel is
pumped into a fracture, shear forces from contact with the lower and upper fracture surfaces would lower the viscosity. The decrease in fluid viscosity could have significant
impacts on leakoff and sand settling out of slurry.
1.1.2.2 Fracturing Methods
When evaluating fracturing methods, it is important to note again that the development of the methods has been primarily for stimulation of petroleum reservoirs. In
many ways, decreasing the depth at which a fracture is initiated simplifies the methods
required to create it. Because of the comparatively more extreme site conditions, the
methods developed by the petroleum industry represent a variety of choices when design15
ing a fracture for environmental remediation applications. However, the petroleum industry commonly uses materials that are not practicable in environmental remediation
scenarios; for example, some fractures in the petroleum industry have been created using
napalm as a fracturing fluid. Nevertheless, the basic methods for creating a hydraulic
fracture in an oil and gas well and the environmental field are the same: isolate a target
zone, initiate (or nucleate) a fracture, and propagate the fracture with fluid pressure while
filling it with granular material.
An excellent overview of hydraulic fracturing methods used in the petroleum industry is presented by Howard and Fast (1970). For the purpose of this study, these
methods have been identified with the following headings: installation of injection well
casing, creation of a starter notch, preparation of injectates, slurry injection, and data collection.
The isolation of the target zone is the first step in any subsurface fracturing process.
The isolation must be such that fracturing fluid can be delivered to, and contained within
the target zone. Petroleum industry fracturing operations are generally conducted in
cased wells. In fact, one of the primary functions of “hydrofrac” stimulation of oil and
gas wells is to overcome formational damage caused by drilling activities (Howard and
Fast, 1970). High-pressure water and explosives are commonly used methods of perforating casing to expose the formation (Gidley and others, 1989). Inflatable packers can
then be used, typically in a straddle configuration, to seal the casing as the fluid is
pumped under pressure between them.
Injection casings installed for environmental purposes have a special set of design
considerations. Depth again plays a major role in these design considerations. As drill16
ing costs are a significant portion of any subsurface fracturing technique, shallow target
zones are much less expensive to isolate and are more easily modified as site conditions
demand. In order to maximize the lateral extent of a fracture, it is important to ensure
that the well bore is not a preferential pathway for fluid flow. Preferential pathways are
often created in “conventionally” completed environmental wells, such as those created
with hollow stem augers. Poor completion techniques and materials often result in annular voids and channels that fail under fracture injection pressures. It is certainly possible
to create horizontal fractures using drilled wells, but careful attention to detail and materials such as swelling grouts are necessary for reliable results.
Direct push techniques have proven a reliable means in injection casing installation at
the shallow depths and soft soil conditions often encountered in environmental remediation projects. With direct push, a single casing can be installed which serves as the
means of isolation in addition to the well casing for planned remediation extractions or
injections. Because the wells are installed into undisturbed soil, as the drive point and
casing are advanced, the surrounding material is compressed. This creates a tight seal
between the injection casing and the formation. In a vertical well installation, this compression locally increases the horizontal state of stress, which favors formation of horizontal fractures. No artificial void space is created because no material is removed.
The creation of the starter notch has two distinct functions. The first is to lower
the pressure required to initiate (nucleate) the fracture. The pressure required to initiate a
fracture is many times that which is necessary to propagate it. The notch lowers the initiation pressure by nucleating fracture propagation. A simple analogy for this is the “starter notch” provided on plastic food wrappers that allow the package to be easily ripped
17
open. The other function of the starter notch in fracturing applications is to preferentially
orient the fracture. Laboratory experiments have shown that fractures will begin to propagate in the plane of the notch and gradually change orientation to that expected by the
imposed stress field (Murdoch, 1993). A notch that is oriented horizontally will initiate a
horizontal fracture in the vicinity of the borehole.
Many methods of notching have been used in various fracturing processes.
Workers in the petroleum industry, for example, often use shaped explosive charges to
create oriented holes in the injection casing and enveloping formation to nucleate hydraulic fractures. Because deep fractures are all essentially vertical, the compass bearing of
the fracture plane is one of the few methodological controls of fracture form available to
oil-field engineers. Diminished stress intensities and comparatively easy working conditions (e.g. depth) provide the opportunity for notches cut at shallow depths to be more
easily modified in response to site conditions.
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2
SITE CONDITIONS
The field site for this study is on the Simpson Agricultural Experimental Station,
owned and operated by Clemson University. The site is located approximately 5 miles
east of the city of Clemson, in Anderson County, South Carolina (Fig. 2-1). This is within the Western Piedmont Province of South Carolina.
123
Clemson
76
88
178
Pendleton
2 km
1 mi
Figure 1.1-1
2-1 Road
map to and
aerial photo
(from terraservice.net)
of study area
600 feet
N
Study site
Peach Rd
Bishop Branch Rd.
2.1
Geologic Setting
The Piedmont Province is one of the five physiographic regions of the eastern
United States. The Piedmont trends northeast-southwest, bounded on the northwest by
the Blue Ridge province and on the southeast by the Atlantic Coastal Plain (2.1-1). It extends from New Jersey and Pennsylvania southeast to Alabama, and includes significant
portions of Georgia, South Carolina, North Carolina, Virginia, and Maryland. A residual
soil covers the Piedmont region with depths of more than 50m in places and feathering
out to zero in others (Miller, 1990). These are frequently clay-rich, low conductivity
soils well suited to hydraulic fracturing enhancement.
Study Area
Coastal Plain
Piedmont
Blue Ridge
Appalachian Mtn.
Valley and Ridge
Figure 2.1-1 Map of Physiographic provinces in North Carolina, South
Carolina, and Georgia.
20
The Western Piedmont physiographic region of South Carolina is bounded locally
on the northwest by the Brevard Fault, separating it from the Blue Ridge geologic province, and on the southeast by the Lowndesville shear zone (Horton, 1991) (Fig. 2.1-2).
The rocks that compose the Western Piedmont are accreted masses making up a stack of
thrust sheets and intrusive bodies, which have experienced varying degrees of faulting
and metamorphism representing over 1.1 billion years of tectonic activity (King, 1977).
The major principal stresses trend northwest to southeast, which are residual tectonic
stress from these thrust sheets (Sowers and Richardson, 1982).
21
N
50 km
Study Area
Figure 2.1-2 Map of Piedmont physiographic province, from Horton (1991).
22
2.2
Bedrock at Site
The bedrock which underlies the site is implied from the geologic map (Fig. 2.1-
2) to be the Caesar’s Head Granite, a light gray, inequigranular, medium grained, discontinuously banded to nonbanded biotite granitoid gneiss or gneissic granitoid (Nelson, et al
1990). At the site, kaolin rich bands and quartz veins are present. The granite was emplaced as part of the Table Rock Plutonic Suite begun during the Taconic orogeny, and
continued in the early Silurian period (Horton, 1991). Nelson identifies the Caesar’s
Head Granite as Early Silurian to Ordovician, and zircon 207Pb/206Pb dating yielding an
age of 435Ma (Nelson, et al. 1990).
2.2.1
Piedmont Soils
The soils of the Piedmont are characterized by an up-section sequence of bedrock-transition zone--saprolite soil--massive soil--topsoil (Sowers and Richardson, 1982).
The transitional and unevenly distributed nature of the weathering process makes delineation of these boundaries somewhat subjective. Bedrock is the solid, unweathered rock,
referred to as the parent rock. The transition zone is defined by variably weathered and
solid rock. Above the transition zone is saprolite, which is characterized by its retention
of the structure of the parent rock. A massive soil (B-horizon) composed generally of
sands and clays overlies the saprolite (Sowers and Richardson, 1982). This soil is more
thoroughly weathered than the underlying saprolite and none of the parent rock structure
is visible. Variability in this horizon includes minerals resistant to the weathering process
23
as well as root and burrowing structures. Above the massive soil, there is a layer of organic rich topsoil (A horizon).
2.2.2 Stresses in Piedmont Soils
The soils of the Piedmont are residuum derived from in-situ chemical weathering.
An understanding of the stress-strain history of the parent rock is thereby potentially important when considering stresses in modern soils. Sowers and Richardson (1982) have
suggested that high lateral stresses in bedrock may be inherited by the residual soils. It
seems likely that under some conditions the weathering process would alter the stress
state of the parent rock significantly as minerals are leached out of the soil. Volumetric
changes in the soil are highly dependent on mineral constituents and degree of weathering and are hence difficult to generalize for the highly variable soils of the Piedmont. As
a result, it seems possible that high lateral compression could be inherited from parent
rocks in some cases, as suggested by Sowers and Richardson (1982), but that lateral
compression could be relieved and relatively low in other cases.
Wetting-drying cycles offer another possible mechanism for the development of
lateral stress that exceeds vertical stress. Soils in the vadose zone are alternately wetted
during precipitation and dried during subsequent evapotranspiration. In the drying cycle,
the overall volume of the soil is reduced. This process results in the formation of desiccation cracks, which can become filled with loose material caving into the cracks. When
the soil is wetted, its volume will increase. With the desiccation cracks filled, this volumetric increase results in increased lateral stress.
24
2.3
Site History
The study site was used previously for pasture, cattle grazing and hay growing.
The area was likely originally a forest that was cleared up to 200 years ago for agricultural purposes. Little impact on soil properties from these activities is expected below plow
depth (~18 in). No evidence of large roots was observed more than 1 ft bgs, and no traces of burrows were observed. There is a corrugated metal barn (200 ft x 50 ft) on a ~6in-thick concrete pad on the site 100 ft east of the study area. It appears that minimal excavation was required for the building.
The site has been used for previous investigations related to hydraulic fracturing.
Fractures were created and used for vapor extraction (Bradner, 2002), and borings were
made to characterize the site and evaluate the state of stress. The area selected for this
study is adjacent to the locations of those previous activities.
The history of the site offers no evidence of activities that would have disturbed
the soil below plow depth. Borings were made recently in the area, but they are located
outside of the study area. As a result, it is expected that the soil was pristine at the time
the hydraulic fractures were created for this study.
2.4
Soil Characterization
Information on the characteristics of soils at the site was derived from investiga-
tions for this study, as well two other studies at the site and limited published data. The
soil is part of the Cecil sandy loam, as mapped by the Soil Survey of Anderson SC
(1975). The site soil investigation was conducted after fracturing and trenching activities
were completed. This timing allowed the locations of samples and test holes to be chosen
25
to represent both site variability and conditions near the fractures. The soil profile is reported from the ground surface to 10 ft bgs (table 1). This interval is expected to contain
all of the vertically distributed variability at the site that influenced fracture form. This
interval also includes each of the three uppermost soil horizons developed at the site,
which have markedly different characteristics.
There are three primary units at the site: topsoil underlain by a massive silty clay,
which is underlain by saprolite. The uppermost unit is organic-rich silty sand that extends to a depth of approximately 1 ft. It will be referred to as the A-horizon (table 1),
based on the soil classification terminology (Herren, 1979). The underlying unit is massive, red to dark red, silty clay loam, with a lower contact roughly 8 ft bgs. This unit will
be referred to as the B-horizon in the following pages (table 1). Saprolite underlies the
B-horizon, and is identified by the presence of relic structure inherited from the metamorphic rock from which it has weathered. Saprolite is recognized as a C-horizon by
some soil scientists (Sowers and Richardson, 1982), but the term saprolite is used in the
following pages (table 1) rather than the term used for soil classification.
The contact between the saprolite and B-horizon is uneven, ranging in depth from
5 to 9 ft. The contact surface is gradational over more than 1 ft in some places, and sharp
(within 1 in) in other places. The contact is particularly sharp where saprolite contains
quartz fragment and pods of mica and kaolinite, which are weathered pegmatite material.
Hydraulic fractures were created in massive silty clay of the B soil horizon, slightly above the lower contact with saprolite.
26
Table 1 Soil profile at the study site
114.7 0.41
79
82
3.0
0.48 4.1
0.52
72.4
0.30 4.0
65.1
0.27 3.6
90.3 0.20 3.5
83.92 0.36 3.64
17.34 0.13 0.44
Munsell color of wet fines (hue value/chroma)
0.20
0.23
0.31
0.31
0.39
0.44
0.40
0.47
0.34
0.43
0.35
0.09
Unified Soil classification system
moisture content
0.70
0.41
0.77
0.70
0.92
0.99
0.96
0.98
0.70
0.82
0.80
0.18
Pocekt Penetrometer (tsf)
degree of saturation
0.41
0.56
0.40
0.44
0.43
0.45
0.42
0.48
0.48
0.52
0.46
0.05
fines content (by mass less than 0.075mm)
porosity
93.64
69.30
95.51
88.65
91.14
88.02
93.02
83.03
82.40
75.54
86.03
8.47
dry unit weight (lb/ft3)
bulk density (lb/ft3)
depth below ground surface (ft)
1
2
3
4
5
6
7
8
9
10
average
std. dev.
Silty sand (SM)
Dark reddish brown (5 YR 3/4)
Silty sand to sandy silt (SM to MH)
Red to dark red (2.5 YR 3/6 to 4/8)
Silty sand (SM)
Yellowish red (5 YR 4/6)
A-horizon
B-horizon
Saprolite
Saprolite
Geotechnical testing was conducted by Mr. Cedric Fairbanks and Dr. Ron Andrus
of the Civil Engineering Department at Clemson University. Two block samples were
taken from the B-horizon 20 ft north of injection casing F at 1.5-2.5 ft and 3.6-4.6 ft bgs.
Sand cone samples were taken at several depths in the B-horizon and saprolite layers 25
ft north of Injection Casing F and 10 feet south of Injection Casing I. ASTM methods
were used for collection and analysis of the sand cone samples.
2.4.1
State of Stress
Horizontal stress exceeds vertical stress in the B-horizon at the site (Ko>1.0). Insitu stress tests were performed 200 feet south of the study site by Shaun Malin as part of
his MS thesis (in preparation). He created hydraulic fractures by injecting tens of ml into
the B-horizon and analyzing the resulting pressure histories to estimate state of stress. He
conducted 15 tests at 3, 4, and 5 ft bgs within 200 ft of the hydraulic fractures created for
this study. His preliminary interpretations indicate that Ko ranges from 3 to 10. In addition, flat blade dilatometer tests were conducted at the site by a commercial company
(Soil Materials Engineers Inc.). Results from those tests indicate that Ko values range
from 3.0 to 3.5 in the depth range of 3 to 5 ft bgs. It appears that the horizontal stress is
several times greater than the vertical stress in the B-horizon.
Measurements with the dilatometer suggest that Ko in the saprolite is less than 1.0.
Sowers and Richardson (1983) summarized results from geotechnical tests at many locations underlain by saprolite, and they indicate that Ko can be greater than 1.0. Results
from the method used by Malin are unavailable in saprolite. As a result, the state of
stress in the saprolite is unclear, but the tentative interpretation is that Ko<1.0. This indicates that the vertical compressive stress exceeds the horizontal compressive stress in the
saprolite, which is the opposite of the relative magnitudes of stresses in the B-horizon.
2.4.1.1 Failure envelope
Unconsolidated-undrained triaxial tests were conducted on four cylindrical subsamples were taken from the block samples. Mohr circle diagrams were constructed
from the magnitudes of applied stresses at material failure to determine the failure envelope of the samples.
The total shear stress at failure, cuu, is 5 psi , and the undrained angle of friction,
Φuu, is 32o, at normal stresses less than 25 psi. At greater normal stress, in the range of
25 to 40 psi, the total shear stress at failure increases to 16 psi and Φuu decreases to 10o
(Fairbanks, personal communication).
2.4.2 Young’s modulus of elasticity
Young’s modulus of elasticity was determined as the ratio of applied normal
stress to normal strain during triaxial load tests. Stress increased roughly linearly with
strain at relatively small strains (less than 0.005) for a given confining stress. However,
the slope of plots of stress and strain decrease with increasing applied stress (Fig. 2.3-2),
presumably because failure occurred within the sample. As a result, the modulus of elasticity was estimated as the slope of the linear part of the stress-strain curve, when strain is
less than 0.005 and the material is behaving elastically.
The elastic modulus ranges from 3500 to 7000 psi (table 2), and values increase
as confining stress increases from 2 psi to 20 psi. Saprolite was too friable to obtain
29
block samples used to prepare specimens for triaxial load testing. As a result, the elastic
modulus of the saprolite is unknown.
Table 2 Elastic modulus as a function of confining stress determined from triaxial tests
(Fairbanks, 2002)
Confining
Stress
(psi)
20
10
5
2
E
(psi)
5500
5000
3700
3200
30
60
Principal stress difference (s1-s2) (lb/in2)
confining pressures
50
20 psi
10 psi
40
5 psi
30
20
2 psi
10
0
0
0.01
0.02
0.03
0.04
0.05
Axial Strain, ea
Figure 2.4-1 Principal stress differential as a function of strain
and confining stress for samples from the field site, from
Fairbanks (2002)
31
2.4.3
Permeability
A Guelph permeameter was used to conduct constant head infiltration tests in the
B-horizon and saprolite. Tests were performed in 1.6-inch diameter hand-augured holes.
Constant head was maintained in the boreholes and the flow rate measured as a function
of time. The results were analyzing using standard methods developed for the permeameter (Soil Moisture instruction manual) to give values of in-situ hydraulic conductivity.
The average hydraulic conductivity of three tests in saprolite at 8 feet bgs is 2.4 x
10-3 cm/s, and the range is 0.8 x 10-3 cm/s to 3.5 x 10-3 cm/s. Five tests were conducted
50 feet south of Injection Casing I at depths ranging from 2 to 6 feet bgs. Flow rates during these tests were slower than the resolution of the permeameter, approximately 0.1 cm
in 24 hours. These results suggests that the hydraulic conductivity of the B-horizon is 107
cm/s or less.
The results of the permeameter testing suggest that there is a contrast between the
in-situ hydraulic conductivity of the B-horizon and the saprolite of 3 to 4 orders of magnitude. It is certainly possible that natural fractures exist in the B-horizon that would increase the effective hydraulic conductivity of larger regions than those affected by the insitu permeameter. Sowers and Richardson (1983) summarized results of many permeability tests in B- horizon material, and their results indicate hydraulic conductivities are
typically in the range of 10-5 cm/s to 10-6 cm/s.
32
2.4.4 Ambient Pore Pressure
Five Soil Moisture™ model 2725 tensiometers were installed at different depths
in a cluster approximately 60 ft east of Injection casing H. Tests were conducted at 1 ft
intervals from 1 to 5 ft bgs.
The pore pressure decreases with depth within the B-
horizon from –10 to –210 cm of total head. A previous study at this site measured soil
moisture tension over a period of one month in the fall of 2001 (Bradner, 2002). In that
period, the same vertical profile was consistently observed, while the magnitude of soil
moisture tension increased throughout the test. It is expected that soil moisture tension
continues to decrease in the upper unsaturated saprolite horizon at the site.
2.4.5
Grain-Size Distribution
Grain-size distribution curves were constructed for samples taken from the Bhorizon and saprolite layers. Sieve analyses and hydrometer tests were conducted to determine the grain-size distributions.
Grain sizes range from clay to sand in both saprolite and B-horizon materials (Fig.
2.3-3). Both materials are poorly sorted, with uniformity coefficients (Cu=D60/ D10) of
400 or larger in the B-horizon, and from 27 to more than 2000 in the Saprolite. Uniformity coefficient could not be determined for 3 of the samples from the B-horizon because D10 is finer than 0.001 m, the smallest grain size that was determined.
The B-horizon material contains mostly fine sand to silt-sized material, with lesser amounts of clay and sand. Between 0.25 and 0.75 of the material is finer than silt. It is
a sandy, clayey, silt. In contrast, saprolite contains mostly fine sand with lesser amounts
of silt-sized grains. Approximately 0.2 of the saprolite is finer than silt. It is a silty sand.
33
34
SC 5 at 9.25 ft
SC 6 at 7.95 ft
Well F at 5 ft
80
60
(a)
40
20
0
10
1
0.1
0.01
0.001
Grain Size, mm
Well F at 4 ft
Well I at 5 ft
SC 4 at 5.65 ft
Well G at 5ft
SC 2 at 3.35 ft
Well H at 5 ft
SC 3 at 7.65 ft
100
Percent finer by weight
.
Percent finer by weight
100
(b)
80
60
40
20
0
10
1
0.1
Grain size, mm
0.01
0.001
Figure 2.4-2 Grain size distributions of soil samples from Saprolite (a) and
B-horizon (b), from Fairbanks (2002).
35
3
METHODS
The methods used in this study involve techniques for creating hydraulic fractures, collecting data, describing their form, and analyzing the resulting information. Accordingly, this chapter includes subsections describing fracturing activities, collecting
data during field monitoring and mapping, and data manipulation.
3.1
Fracturing Activities
The fracturing activities for this study were conducted in February and March of
2002. The injection casings were all installed in one day in early February, and each of
the notches was cut within 1 hour of the slurry injection. Fresh liquid batches of gel and
crosslinker were prepared for each fracturing event, using water supplied by an on- or
near-site well.
The notching, liquids preparation, and slurry injection methods are the same as
methods currently in use for commercially installed fractures, with one notable exception.
In this study, there was a focus to maintain consistent methodology, rather than basing
methods on observations made while work was in progress. For example, each of the
notches was cut with 8 gal water rather than examining the cuttings while notching and
adjusting the duration of the notching event on the volume of cuttings removed.
3.1.1
Injection Casing Installation
The casing used for the injections is 2 in schedule-40 black iron pipe, threaded on
one end. The well casing and a retractable drive point attached to an inner rod were ad-
vanced by direct push with a CME 45 drill rig. Each of the well casings is 4.92 ft and
was installed flush to the ground surface. The drive point was advanced an additional 3
in, then removed from the well casing to create a cavity in the soil below the casing, (Fig.
3.1-1: steps 1-3).
1
4
2
5
3
6
P
Figure 3.1-1 Well installation, notching, notch measurement, and fracture initiation.
37
38
3.1.2
Solids (Proppant) Preparation
The proppant used during this study is #2 filter pack sand obtained from Driller’s
Service, Inc. in West Columbia, SC. The sand is rated as 10/30 material, which means
that it will nominally pass through a 10-mesh screen but not through a 30-mesh. According to the grain-size distribution, 99.4% of the sand is finer than a #8 sieve and only 3.0%
is finer than a #25 sieve. The uniformity coefficient (Cu) (D60/D10) is 1.5. Grain-size distribution was determined by Law Engineering, Inc, and provided by Driller’s Service Inc.
Dry bulk unit weight was determined by filling a 1 L volumetric flask with the dry sand
and then shaking the flask to promote settling. The sand was then weighed, yielding a
bulk unit weight of 95 lb/ft3 (1.53 g/cc).
Several methods of marking the sand proppant for visual detection were investigated. The goal was to find a marker for the sand that could be produced and implemented in the field at a minimal cost, and that facilitated the use of sand that was similar to the
material used for typical hydraulic fracturing operations. Towards this end, different
methods to color the sand were pursued. A variety of colored sands are commercially
available, but all the material that could be located was either prohibitively expensive, or
available in grain-sizes that are significantly different from those used for typical field
operations. The grain-size distribution of sand will affect the rheology and the ability to
pump slurry containing the material. Therefore, various alternatives were considered for
coloring the sand that was available for fracturing operations.
Two methods of coloring
sand were evaluated, both in the laboratory and in the field. One method of coloring used
a dye, and the other used paint. The dye that was used is a water-based compound mar39
keted to dye clothes by Bestfoods Specialty Products under the trade name of Rit-Dye.
The sand was soaked in dye mixed at two times the recommended concentration. The
batches were allowed to soak for 12 to 18 hours, then drained, rinsed with clean water,
and air-dried. Batches of dry sand were stained different and distinct colors, but it was
observed that continued rinsing diminished the intensity of the color. Some colors produced more vividly marked sand, and the blue and red were the most striking so they
were selected for field-testing. The first two fractures (G and H) completed for this study
were filled with dyed sand. It was apparent when those fractures were created that the
coloring of the dyed sand may be too faint to detect easily in the field, so an alternative
method of marking the sand was evaluated.
The alternative method involved the use of Rust-Oleum® marking paint, which is
widely available in a variety of bright, distinct colors to color the sand. This paint dries
quickly after application from an aerosol can, and will coat individual grains distinctly
without causing the grains to cluster or clump together. Visual inspection of the painted
grains using a hand lens suggests that the paint coats the grains as a thin film. The bulk
density was lowered to as little as 91% of the unpainted sand in samples prepared for lab
testing with more than 20 applications of paint. It was only necessary to perform 5 to 10
applications of paint to the sand which was injected.
The sand was colored in the field by loading it into a shallow trough, spraying
with the paint, raking the material, and spraying another coat. The sand was sprayed until
the color appeared to be uniform based on visual inspection.
For each of the four fractures, 500 lb of sand was prepared in the following ratio:
50 lb red, 350 lb uncolored “white”, 150 lb blue. The colors were injected sequentially,
40
with no interruption of flow to the fracture. Operational efforts were made to make the
color changes as abrupt as possible while maintaining a uniform sand loading.
3.1.3
Notching
To create the notches for this study, a piece of pipe and a T-fitting were first attached to the well casing (Fig. 3.1-1; 4). Water was injected to create the notch, and the
return flow is routed through the T-fitting and collected in a bucket. A jetting tool, which
consists of a rigid rod and a head that holds a nozzle perpendicular to rod, is lowered to
the bottom of the casing at a depth of 5 ft bgs. Water was injected through the nozzle at
4 gpm at a pressure of 3000 psi. This flow created a high-energy water jet oriented horizontally at the bottom of the hole. The jet was rotated by turning the rod at the ground
surface. The rod was rotated approximately several revolutions per minute to cut a
roughly circular notch at the bottom of the casing. Each of the notches used in this study
were cut by injecting 8 gal water.
A notch is created by disrupting and eroding soil material in the path of the jet.
The material is cut by the jet and carried to the ground surface by water flowing up the
casing. The cuttings and water were collected in buckets held under the T-fitting. The
buckets were allowed to sit undisturbed for several days while the solid cuttings settled
out. The water was then decanted and the solid material saved for analysis.
The lateral extent of the notches was measured using a specially designed tool
(Fig. 3.1-1). The tool consists of an 8-ft long piece of 1-in PVC pipe with a cap on one
end. A thin circular disk forms a cap on the end of the pipe. A narrow slot, roughly 0.1in wide and 0.5-in long, was cut normal to, and at the end of the pipe. A roller bearing is
41
installed above the slot. The tape from a retractable tape measure is installed into the
pipe. The slot is wide enough so that it will pass the tape from a retractable tape measure.
The tape extends along the inside of the pipe, curves around the bearing, and goes out
through the slot. The tape can be pushed or pulled along the axis of the pipe and this
causes it to extend or retract in a radial direction from the slot.
Figure 3.1-2 Schematic of notch-measuring tool. Vertical displacement
of the tape (black line) at the top results in equal horizontal displacement at the bottom.
To use this tool, it is advanced downhole to the depth of the notch and secured
with a pair of vise-grips. A measurement is taken at the top end of the tool when the tape
is fully retracted. The tape is then pushed down, forcing the tip of the tape out into the
notch. The tape is advanced until it meets resistance and the displacement is recorded as
the radial dimension of the notch. The tape can be extended with minimal effort, so it is
fairly easy to tell when the end of the tape encounters the back of the notch. The radius
42
measurements were made every 45 degrees of arc, so the notches are characterized by 8
measurements of radial distance.
The tool is only able to measure the apparent lateral extent of the notch. Irregularities in the notch may cause the radial distance to be underestimated, or the tape can
fold over and cause the radial distance to be over-estimated. The process sometimes required repeatedly probing and retracting the tape to determine the full extent of the notch.
3.1.4
Liquids Preparation
The liquid component of the slurry typically injected into hydraulic fractures consists of guar gum gel, cross-linker, and an enzyme breaker. The guar gum solution is
formed from a powder dissolved in water. Molecules in the solution are linked together
to form a gel using a chemical crosslinker. The enzyme breaker is designed to break
apart the linked molecules a few hours to days after the gel is crosslinked.
3.1.4.1 Gel
The guar powder used in this study was manufactured by Aqualon under the
product name Galactasol®. It was mixed with water at a ratio of 4.5 lb dry powder to
100 gal water. The mixing of the dry powder and the water is accomplished by the use of
an eductor. The eductor is part of a recirculation loop that takes fluid from the bottom of
a 500 gal water tank, through a centrifugal pump, through the eductor and back into the
top the tank. The powder is aspirated into the circulating fluid, and then the pump is allowed to run until the guar gel has adequately hydrated. The centrifugal pump moves
fluid at approximately 50 gpm, so the circulation loop mixes the guar and the water in the
tank.
43
The hydration process generally takes 5 to 30 minutes. Hydration is complete
when the guar solution will crosslink to a gel when the crosslinker is added. Adequate
hydration is determined by taking a sample of approximately 100 ml of gel solution, adding about 1 ml of crosslinker and observing the consistency of the mixture. The proper
consistency resembles a thin jelly. The crosslinked gel has strength so it can be lifted up
out of a cup, or a few tens of ml can be poured out and suspended from the lip of a cup.
3.1.4.2 Cross-linker
Guar molecules are crosslinked by borate ions to form a gel. The borate donating
crosslinker used in this study is 20 Mule Team Borax®. The borax is mixed with water to
form a saturated solution, approximately 10 ounces borax powder per 10 gal water. This
solution is added to the unlinked gel with a metering pump at a ratio of approximately
1:40; that is 0.4 gal crosslinker solution to 10 gal unlinked gel.
Lab tests indicate that under ideal conditions the guar gel becomes crosslinked
when mixed with a saturated solution of borax at a ratio of 1:100, so the ratio used in the
field is nearly twice as much borax as required for most applications. However, factors
such as low temperatures or compounds dissolved in the water may inhibit crosslinking
and reduce the amount of sand that can be carried by the gel. Increasing the concentration of crosslinker mixed with the slurry will improve crosslinking in some situations,
which is why the concentration of crosslinker used in the field is greater than that required for most applications.
The rheology of gel created in the lab using crosslinker at a ratio of 1:40 is similar
that of gel created with a concentration of 1:100, so there appears to be minimal negative
effect of using that concentration of crosslinker.
44
Some applications of hydraulic fractures require strict documentation of the concentrations of injected compounds that could adversely affect water quality. The concentration of borate ion in the injected slurry can be of concern during some applications.
Borate ion occurs in a saturated solution of borax at a concentration of 1080 ppm, and it
is diluted to a concentration of 27 ppm when crosslinker is mixed with gel at a ratio of
1:40.
3.1.4.3 Breaker
An enzyme is commonly added to guar gel to break the bonds in the gel. This allows the guar to be recovered, which opens the pore space in the proppant to facilitate
fluid flow. Because there was no intention of using the fractures created during this study
for applications involving fluid flow. As a result, no enzyme breaker was used during
this study.
3.1.5
Slurry injection
Specialized equipment is used mix and pump the slurry used in the fracturing process (Fig. 3.1-3). The equipment consists of a system to convey and blend the components of the gel, another system to convey the sand and mix it with the gel to form slurry,
and another system to inject the slurry into the ground.
The gel is circulated through a loop that extends from the bottom of a tank,
through a centrifugal pump, past a T-fitting and a valve, and back to the tank. A hose
extends from the T-fitting through a flow meter and past two other T-fittings before ending at the intake of an auger mixer. Closing the valve in the circulation loop forces gel
that has been pressurized by the centrifugal pump to flow through the flow meter and into
45
the mixer. Two metering pumps are used to inject crosslinker and breaker into the two Tfittings on the hose that carries gel to the mixer. As a result, the gel contains crosslinker
and breaker when it arrives at the auger mixer.
The proppant is stored in a hopper with an auger feeder that transports the sand
into the mixer. The rate of rotation of the auger feeder can be controlled to regulate the
rate at which sand is added to the mixer. The mixer contains a dissected auger, which
disrupts and blends material as it translates it from one end of the mixer to the other.
Flowing streams of sand and gel enter one end of the mixer, and are blended to produce a
continuous stream of slurry from the other end.
Slurry is injected using a positive displacement, progressive cavity pump. The
pump contains a metal rotor shaped like a rounded helix, and a rubber stator containing a
helical cavity. The match between the rotor and the stator creates a series of small cavities that progress along the axis of the pump when the rotor is rotated. The progressing
cavities can contain a wide range of materials, making this design well suited to pumping
slurries of gel and sand.
The pump will inject slurry at a rate that is determined by the rotation speed of the
rotor. The pressure required to accomplish the injection depends on the resistance induced by hoses, fittings and the propagating fracture. Pressure transients created by a
progressive cavity pump are negligible, so the pressure signal produced during injection
is a result only of the resistance to pumping at a constant rate. The “clean” pressure signal is one reason why a progressive cavity is preferred over a positive displacement piston pump, which creates sharp pressure transients with each stroke of a piston.
46
A hydraulic fracture can be influenced by vertical stresses at the ground surface,
so the fracturing equipment, which weighs more than 10,000 lbs, was staged at least 80 ft
from the injection point. Surface loading from heavy equipment has been both inadvertently and intentionally been used to produce fractures oriented preferentially away from
the increased load (Murdoch, 1994; 1995; Murdoch and Slack, 2002).
Positive
Displacement Pump
Screw
Conveyor
Sand Hopper
To Injection
Well
Mixer
P
P
P
Gel Storage
Breaker
Storage
Linker
Storage
Figure 3.1-3 Schematic of fracturing equipment.
47
3.1.5.1 Steps
To begin the fracturing process, a short piece of pipe with fittings for the injection
hose and a pressure transducer is screwed onto the well casing (Fig. 3.1-2; drawing 6 of
series). For each of the fractures in this study, 50 ft of 1.5 in (inner diameter) hose was
used to connect the injection pump to the injection casing. The hose was then filled with
cross-linked gel. The gel in the hose (approximately 4 gal) served as the pad for the fracture. The pad is the material used to initiate the fracture and dilate it enough to allow
sand to be pumped in.
After the injection hose was primed with crosslinked gel, the mixer auger was engaged and the 50 lb of red sand were blended with crosslinked gel to create slurry. The
unpainted, “white” sand was loaded into the solids hopper. The blue sand was staged
near the solids hopper and loaded as soon as the white sand was clear of flights of the
conveyor auger in the bottom of the solids hopper.
The progressive cavity injection pump was then engaged and held at a constant
rate of 10 gpm for the duration of the fracturing process. Once the last of the blue sand
slurry entered the injection pump, approximately 3 gal of crosslinked gel were run
through to “chase” the blue sand into the well.
3.1.5.2 Sample collection and analysis
Samples of the slurry were taken at regular intervals during the injection to determine the relative volumes of sand and gel. The volume ratio of sand in the slurry, or
the sand loading is defined as ratio of the total bulk volume of the sand to the total volume of slurry (Murdoch and Slack, 2002). These samples were allowed to settle, then
48
thoroughly washed, dried, and weighed. The weight of the sample was then multiplied
by the unit weight of the sand (95 lb/ft3) to determine the bulk volume of the sample.
This volume was divided by the total volume of the slurry (each sample was 0.75 quarts,
0.71 L).
In order to determine the distribution of the different colors of sand in each sample, a smaller sample of approximately ten grams (many hundreds of grains) was taken
from each of the samples, and the individual grains of each of those sub-samples were
then hand sorted by color. Each of the colors was then weighed individually and weight
percentages of the overall sub-samples were calculated. These values are similar to color
percentage estimates done by visual estimates of the samples.
During the slurry injection events for this study, accurate records of the sand loading were maintained. However, slurry samples can take up to 2 days to fully settle, depending on environmental conditions and slurry compositions. For this reason, determination of sand loading as described above (or simply allowing the slurry sample to settle
in a graduated cylinder) is impracticable, and a method was sought that could be used
during the injection event to maintain consistent sand loading. This method was developed by relating the unit weight of the sand-laden slurry, slurry, to the volumetric sand
loading, SL, using
 slurry   gel  SL(1  n)( sand   gel )
(1)
where n is porosity of the sand and sand and gel are the unit weights of the sand grains
and the gel, respectively. Alternatively, the volumetric sand loading can be related to the
weight of sand per unit volume of gel, P, according to
49
SL 
P
 s  P (1  n)
(2)
The unit weight of the sand used for this study is 95 lb/ft3. The unit weight of the gel was
assumed to equal that of water (8.33 lb/gal), as fracturing fluids are primarily water by
volume. The additives to the water (guar flour and crosslinker) used in this study account
for only 0.004 (4%) of the mass of a volume of gel. The porosity of the proppant is more
difficult to estimate in the field, so the solution for sand loading was calculated for porosities ranging from 0.30 to 0.50 (Fig. 3.1-2). The porosity of the sand used in this study is
approximately 0.40. It was measured by adding a known volume of water to a known
volume of sand in a graduated cylinder, shaking vigorously, allowing the sand to settle
and noting the total volume.
The unit weight of the slurry can be readily determined during the fracturing process by weighing a sample of known volume. The volumetric sand loading and the
weight of sand per volume of gel in the slurry can be calculated using equations (1) or
(2). In the field, it is more convenient to determine the sand loading graphically using
Figure 3.1-2. As a result, the sand loading of the injected slurry can be monitored by obtaining the weight of samples of known volume.
50
20
16
n= 0.3 0.4 0.5
15
16
14
14
12
13
10
12
8
11
6
10
4
9
2
0
0.0
unit weight (lb/gal slurry)
pounds of sand per gallon of gel
18
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
8
0.9
(volumetric) sand loading
Figure 3.1-4 Volumetric sand loading related to slurry content (thick line)
and unit weight (thin line), n = sand porosity.
51
3.2
Field Monitoring and Mapping
Field monitoring and mapping activities were conducted during and in the months
following fracturing activities.
3.2.1
Monitoring
Injection pressure was measured with a transducer connected to a T-fitting on the
injection casing. The transducer was wired to a datalogger and a laptop computer, which
allowed real-time viewing of pressure.
Surface deformation, or uplift, was measured by surveying the scales on an array
of fixed stakes using a leveling telescope. An initial, baseline survey is taken before the
pumping event is initiated. Another survey was taken immediately after the pumping
event. The uplift is difference between the level prior to and after the pumping event and
it is recorded for each survey point. The uplift stakes are constructed of 5 ft lengths of
0.5 in diameter aluminum conduit. A 0.05-inch scale is affixed to each stake with clear
tape. The surveying level was placed 50 to 75 ft away from the injection wells, outside
of the expected area of surface movement. Three other stakes were installed yet further
from the injection wells which served as reference points to check for movement of the
surveying level.
The array is installed by hammering the uplift stakes 6 to 8 in vertically into the
ground in a pattern designed to both delineate the lateral extent of uplift and optimize
near-well resolution. The array is laid out with one axis north-south, and the other two
axes 60° each way from north-south. The arrays for wells G and H were installed with an
52
axial stake spacing of 3 ft. Because fractures G and H displayed uplift at the outermost
edges of the survey, the spacing for wells F and I was increased to 4 ft.
3.2.2
Excavation and Mapping
Excavation of the fractures was conducted several weeks after the conclusion of
fracturing activities using a backhoe with a 24-in wide bucket. The trenches were excavated during five consecutive days to minimize equipment rental costs. The trenches and
fracture exposures were then mapped and then backfilled several weeks later. During
excavation, it was important to create a straight and vertical trench that presented a planar
cross section through the fracture. The trenches were located to maximize the amount of
exposed fracture and to define their lateral extent and overall size.
Two patterns of trenches were used to expose the fractures (Fig. 3.2-1). One pattern consists of an axial trench cutting the major axis of the fracture within 1 ft of the injection casing. Another trench was located perpendicular to the axial trench. Large piles
of excavated material restricted the second trench to one side of the fracture. This exposes the fracture along two perpendicular sections forming a “T” pattern. Two of the fractures were exposed using several parallel trenches, instead of two perpendicular ones.
This excavation pattern exposed the fractures as a series of serial cross sections.
Safety was a primary concern in the creation of the trenches, and care was taken
to bench all trenches and keep spoil piles at a safe distance from trench faces. All trench
walls were manually scraped with spatulas and knives in the vicinity of the fracture traces.
53
1000
900
N
800
10
F
9
700
13
600
14
0
500
5 10 15 20 feet
400
11
12
300
8
200
7
G
6
4
100
I
2
H
5
3
1
0
-100
-100
0
100
200
300
400
500
600
Figure 3.2-1 Map of study area showing excavations. Cross hatched areas
are trenches, with trench faces numbered 1-14. Benched areas are
shown in diagonal stripe and spoil piles are shaded gray.
54
3.2.2.1 Transparency Maps
Several attempts were made at mapping the fracture exposures with scaled drawings. It proved difficult to map features occurring at very different scales on a single
map. A method of recording the fracture exposures on the trench faces was developed
for this study to directly map the fractures on transparency sheets in the field, then extract
data from those sheets back in the lab.
A grid that encompassed the trenched area was established. The origin of the grid
system is located southwest of the trenched area. String was strung from posts to delineate the primary axes of the grid. A measuring tape and permanent marker pen were used
to index all of the string used in the grid layout. Several gridlines (e.g. 12 ft E) were then
strung at ground surface level. These lines were secured at ground surface outside of the
trench area and extended over the trenched area, crossing several trenches. A line level
was used to check these lines. String level lines were set up on each of the trench walls at
5 ft bgs. When this map orientation is overlain on a Cartesian xyz coordinate system, increasing x values increase in a westerly direction, y values increase in a northerly direction, and z values increase (to zero) at the ground surface. The trenches were mapped in
reference to this grid using compass and measuring tape.
The system developed for this study utilized transparency sheets sold for use with
overhead projectors. (It is important to use the sheets specifically designed for use with
permanent markers, which create an indelible image and don’t smudge/smear.) The
transparency sheets are first punched with a hole punch in two corners of one the long
sides. Once the trench walls have been carefully scraped, a sheet is placed holes-side up
on the trench wall and pinned in place with a nail placed through one of the holes and in55
to the trench face. The next sheet is then placed with a pin passing through its corner and
then the unpinned corner of the former sheet. Each time a pin is placed, the last pin
serves as a pivot point that allows the sheet receiving its second pin to orient the long axis
of the sheet to the fracture trace. This process of overlapping and share-pinning consecutive sheets is repeated to the other end of the fracture trace along the trench wall (Fig.
3.2-2). This relative poisoning of the sheets is secured with several pieces of tape where
sheets overlap.
pin
s
1
2
3
4
E
W
fracture
index marks
Figure 3.2-2 Transparency overlay mapping system.
Fine point Sharpie® permanent marker pens were then used to consecutively
number the sheets. The first and last sheets of the series were prominently marked with
their respective compass directions relative to one another. At least two index marks
were then placed perpendicular to all exposed edges where sheets overlapped. This allowed the sheets to be properly realigned after the series has been disassembled and re-
56
moved from the trench face. The vertical distance from the bottom surface of the fracture
to 5 ft bgs was recorded on the map every ft along the length of the cross-section. A carpenter’s level was used to draw a horizontal line on at least every other sheet for additional control on orientation and attitude of the maps. The map was then referenced to
the grid system established for the trenches. Plumb lines were dropped from ground surface gridline strings in several locations and the maps were marked and labeled where
these plumb lines crossed the maps.
The upper and lower surfaces of the fracture are then traced through the transparency sheet. Because the width of the mark left by the pen varied over the life of the pen
and from pen to pen, care was taken to trace the middle of the pen line over the exposed
fracture surface. This is important because the pen line could be as wide as 0.10 in, and
aperture measurements were later to be taken with a resolution of 0.05 in. Care must also
be taken to maintain a consistent line of sight to the fracture as one works his way down
the length of it. This can be difficult at times when the fracture is low in the trenches,
which are only 24 in wide. Colored pens were used for the maps of fractures F and I.
The color of the sand visible in the fracture was represented by using that color pen (used
black for “white”, uncolored sand) either by dots representing individual grains of one
color in a matrix of another or by sketching crosshatched areas to indicate sand in that
portion was 100% one color. Notes on soil composition and structure above and below
the fracture were also made directly on the maps. The maps were then removed from the
trench face, disassembled, and stored until measurements were taken in the lab.
After completion of the transparency-mapping phase, several additional excavations were conducted. The results of these excavations were mapped onto the trench
57
map. The primary purpose of these excavations was to define the maximum lateral extent of the fractures in directions that were perpendicular to and not exposed by the
trenches. This was completed for the northern and southern limits of Fracture I and for
the northern limit of Fracture H. Additionally, overburden was removed from the fracture where possible to expose the fracture plane. This process was conducted in the vicinity of each of the injection casings, exposing the starter notch. Sections between
trench faces 4-5 (~15ft2) and 6-7 (~6ft2) were also removed and Fracture I was mapped in
detail in those areas (Fig. 4.1-1 and 4.1-18).
3.3
Data Manipulation
The data manipulation methods are divided into the extraction of the data from
the transparencies and the manipulation of the resulting database.
3.3.1
Data extraction from transparencies
The individual sheets of the transparency maps were reassembled in order to collect data from them. These maps were laid over a sheet of graph paper 4 ft by 25 ft long
that was secured to a large table. The graph paper has major gridlines of 1.0 in and minor
gridlines of 0.10 in, both of which are clearly visible through the transparency maps. It
proved helpful to further index the graph by drawing a set of bolder lines at 12 in intervals. The maps were then positioned over the graph paper such that the horizontal indicator lines on the map coincided with the long axis of the graph paper. Thus, the long (x)
axis of the paper represented the long axis of the trench, either N-S or E-W and the short
(y) axis of the paper represented elevation (later to be designated the z-axis). The map
58
was the secured in this position over the graph paper with tape. Measurements of the
fracture trace could now be made directly through the map.
After visual inspection of each of the maps, it was decided that an interval of 1.0
in would adequately describe the occurrence and distribution of the features of interest.
A two-person team was used to collect and record the data. One person read the data
aloud, the other verbally confirmed then entered the data directly into an Excel© spreadsheet. The orientation of the map, either N-S, S-N, W-E, or E-W was first established.
The labels where the plumb lines used to reference the maps to the grid where then used
to set up the spreadsheet coordinates. For example, a label that said “12ftW” indicated
that the trench crossed the N-S line that is 12 ft west of the origin of the coordinate system. In that case, the x position of that point would be represented in the spreadsheet as
“144” (144 in). The x data series would then be “…142, 143, 144, 145, 146, 147…” as
far in either direction as is necessary for the map. Moving from 144 to 147 represents 3
in of movement in a westerly direction, while decreasing values represent easterly
movement.
The y positions (or x positions for N-S trending trench faces) of each of the data
points was determined subsequent to data collection by projecting the line of the x data
series onto the trench map. A line extending the traces of each of the trench faces were
first drawn to cross the grid axes. Principal axis intercepts were determined from those
lines. The declination angle of each of the trench faces was then measured. These data
were then used a linear transform to determine the y position corresponding to each x location.
The error in this method is recognized, that it stretches the x scale as it moves
away from the origin. This error however is minimal. Trench faces 1-4 have a declina59
tion angle of 7.4°N and a maximum x-axis extent of 287 in; faces 6-8 are at 3.2°N and
extend to 371”. The distances that these should represent are 289 in and 372 in and are
responsible for less than 0.01% error in both cases. N-S trending trench faces were even
less affected by the transform.
The data collected at each of these x, y locations were color, aperture and elevation of the bottom surface of the fracture. Measurements were taken every inch along the
x-axis of the fracture. Color measurements were done by visual inspection and reported
as percentages of each color present in that inch-long segment of the fracture. Notes concerning interesting features or structures in the sand distribution were entered in a separate column.
Sand thickness was measured from the middle of the pen line representing the
fracture bottom surface vertically upward to the middle of the top surface line. This
measurement differs from the aperture of the fracture normal to the fracture surface,
which is the typical way that aperture is defined. The vertical distance was used to define
sand thickness for this work because it could be determined unambiguously. The difference between the vertical distance and the aperture measured normal to the walls of the
fracture will increase with the dip of the fracture. The dip of the fractures created for this
work was relatively shallow, so the difference between the vertical distance and the aperture measured normal to the axis of the fracture is less than 10 percent.
Sand thickness measurements were rounded to the nearest 0.05 in. Measurement
of the elevation of the bottom surface of the fracture was done to the nearest 0.1 in. The
elevation of the top surface of the fracture was calculated as the elevation of the bottom
surface plus the sand thickness and added to the database. Elevation data are reported in
60
units of depth below ground surface. Because all of the data were below the surface,
each of these values is negative numbers and the higher the absolute value of the number,
the further below the surface it is. A total of 2685 points along 220 ft of exposure were
measured to characterize the fractures using the methods outlined above.
3.3.2
Analyzing field data
The first step in process of analyzing the field measurements was to create a map
posting each of the xyz locations on a map overlain onto the trench map. This was to
confirm that the x, y locations assigned to each of the points represented a location along
one of the trench walls. The next step was to plot the elevation data (z) against the major
axis (x or y) of each map. The plots were visually inspected to confirm that the elevation
data represented the continuous data series shown on the map. Once the data were validated, new coordinate systems were established for each well and its associated maps.
The orientation and scale of the original coordinate system were preserved, and the injection well was plotted as the origin of the four independent coordinate systems.
3.3.2.1 Data interpolation and rendering in SURFER© (3-D maps)
All of the interpolation of data presented in the results section was done by
Kriging using SURFER©. The maps produced from this interpolation method are similar
to those produced by hand-contouring the data. Other methods of interpolation, including
minimum curvature and inverse distance, were routinely applied to the data as a check on
the interpolation performed by Kriging. The other methods always produced a map that
was either similar to the map produced by Kriging, or a map that was strikingly different
from the map produced by Kriging and hand-contouring. Anisotropic bias was applied to
61
data, such as sand thickness and color distribution, because it appears to have anisotropic
distributions and because the data distribution is much denser along the section lines than
between the lines. The maps produced from anisotropically interpolated data were, in
some cases, able to accentuate elongate features within the fracture. However, the features are sufficiently distinct with isotropic interpolation and isotropic interpolation was
used in all of the maps used in the results section. This confirmed that none of the features was an artifact of the use of anisotropy in the interpolation.
The contour maps of uplift generated by SURFER© (Fig. 4.1-11, 4.2-3, 4.3-1 and
4.4-1) (interpolated by Kriging) are similar to the results of a computer program written
by FRx specifically for contouring uplift data. This program uses bi-linear interpolation
in radial reference frame to correspond with the geometry of the uplift measurements.
The results from SURFER© also resembles hand-contoured maps of the data.
The lateral extent of one of the fractures (Fracture I) was used to manipulate grid
files interpolated by SURFER©. These grids contain data, such as sand thickness, that are
extrapolated to the edge of a rectangular region and beyond the lateral extent of the fracture. The grid files were trimmed by using a blanking file, or mask, which preserves
some grid values and sets others to zero. A mask file was created by digitizing the lateral
extent of Fracture I with a total of 236 points. The mask file contains values of 1.0 in
grid cells within the digitized line (Fig. 4.1-1, bold dashed line), whereas it contains values of zero in cells outside of the line. The mask is applied by multiplying each cell in a
grid file by either the 1.0 or zero in the corresponding cell of the grid file. Masking is
particularly important when calculating areas or volumes from SURFER© files because it
excludes (sets to zero) the areas outside of the fracture from the calculations.
62
3.3.2.2 SIGMAPLOT© and MS EXCEL© for 2-D graphs
Both MS EXCEL© and SIGMAPLOT© were used to manipulate the data and prepare 2-D graphs. Most of the handling and manipulation of the database was performed
with MS EXCEL©. Data was plotted and trendlines were determined using SIGMAPLOT©.
63
4
RESULTS
The following section presents data to characterize the forms of shallow hydraulic
fractures and present evidence for possible processes that occur as the fractures fill with
sand. The data used in the results section are derived from cross-sections, combined with
uplift measurements, pre-fracture notch measurements, and additional observations made
of the excavated fractures. The data from the transparent overlay maps produced a detailed data set showing sand thickness and location of the fractures in a 3-D Cartesian coordinate system. The data for fractures I and F also includes sand color percentages.
The amount and distribution of data for each fracture depends on the configuration of the trenches that exposed the fracture. The fewest trenches cut Fractures F and G
(Fig. 4-1). They are both exposed by one trench adjacent to the injection casing and
trending north-south, and another shorter trench on the east side of, and perpendicular to,
the longer trench. In contrast, Fractures H and I are exposed by roughly parallel eastwest trending trenches. These trenches exposed eight mappable cross-sections of Fracture I. Only four of the six cross-sections of Fracture H could be mapped onto transparent film because two of the cross-sections were irregular and disturbed during excavation.
Nearly 100 ft of cross-section yielding 1161 data points are available for Fracture I, and
this is more than twice as much as any of the other fractures. Fractures F, G, and H have
approximately 40 ft of mapped cross-section each yielding 547, 475, and 502 data points,
respectively (table 3).
950
850
10
F
750
9
650
13
14
550
N
450
11
12
0
5
10
20 ft
15
350
8
250
7
G
H
6
150
4
3
I
50
5
2
1
-50
-100
0
100
200
300
400
500
Figure 3.3-1
4-1 Map showing interpreted lateral extent of fractures
(F,G,H,I) with dashed line. Trace of trench faces (1-14) in bold
lines.
65
Table 3 Trench faces mapped with transparency overlays.
E-W
E-W
E-W
E-W
E-W
E-W
E-W
E-W
mean sand thickness (in)
E-W
E-W
E-W
E-W
no. of fracture edges cut
E-W
E-W
N-S
N-S
no. of observation pts
E-W
E-W
N-S
N-S
length (ft)
(basic) trend
Fracture - Trench Face
F-9
F-10
F-13
F-14
total
G-7
G-8
G-11
G-12
total
H-3
H-6
H-7
H-8
total
I-1
I-2
I-3
I-4
I-5
I-6
I-7
I-8
total
grand total
7.9
8.3
14.1
14.9
45.2
4.3
4.7
15.9
14.4
39.3
4.8
14.3
12.3
10.2
41.6
9.2
11.6
14.4
16.2
15.9
15.0
8.8
5.1
96.2
222.3
96
101
170
180
547
52
57
192
174
475
59
172
148
123
502
111
140
174
195
192
180
107
62
1161
2685
1
1
2
2
6
1
1
2
2
6
2
2
2
2
8
2
2
2
2
1
1
1
2
13
33
0.27
0.30
0.32
0.33
0.18
0.23
0.33
0.27
0.10
0.22
0.24
0.12
0.11
0.15
0.21
0.23
0.27
0.28
0.13
0.08
66
The form of Fracture I is known more completely because it was exposed by more
trenches than the other fractures. As a result, the accuracy of the maps describing Fracture I is greater than that of the other fractures. The lateral extent of sand in Fracture I
overlaps the extent of sand in Fractures G and H in plan view (Fig. 4-1). In cross-section,
none of the fractures intersected or crossed. No evidence was observed that suggests the
presence of an existing fracture has an effect on fractures created later. The four fractures
were therefore treated as features that could be analyzed and described independently.
The following section begins with a description of Fracture I because it is known in the
most detail. Descriptions of Fractures H, G, and F follow.
Injection pressures were monitored for each of the fractures. However, difficulties with the datalogging equipment resulted in the loss of all but one of the files. The
file for Fracture H was retained (Fig. 4-2). The pressure signal from the other three fractures was similar to that of Fracture H. The injection pressure for Fracture H increases
abruptly at the onset of injection and fracture propagation is inferred to start at the maximum pressure, 50 psi. Pressure decreases and is in the range of 15 to 30 psi during injection. The injection pressure generally decreases with time during injection, but the log is
marked by several slow and a few fast fluctuations. There are three, short but rapid fluctuations when the pressure decreases and increases abruptly (Fig. 4-2). These events occur when a valve was opened to obtain a sample of the injected slurry. The cause of the
other pressure fluctuations is unclear, but fluctuations similar to those in Figure 4-2 are
common during shallow hydraulic fracturing.
67
60
Pressure (psi)
50
Breakdown pressure
40
Pump off
30
20
10
pump on
sampling events
0
0
1
2
3
4
5
6
7
8
Time (minutes)
4-2 Pressure log from Fracture H
Figure 3.3-2
68
4.1
Fracture I
The form of Fracture I is described in five sections in the following order: Geom-
etry, Sand Thickness, Uplift, Color Distribution, and Notch. The geometry of the fracture
is subdivided into lateral extent and depth below ground of the fracture surface. The sand
thickness section describes the distribution of sand on the fracture surface. The uplift
section analyzes the surficial uplift data and compares them to the geometry and sand
thickness. The distribution of the three colors of sand injected is then described. Other
data such as notch measurements are discussed last.
4.1.1
Geometry
The geometry is divided into the lateral extent and the depth of the fracture. The
lateral extent of a fracture is defined as the edge of the area of the fracture that is filled by
sand. The depth of the fracture is defined as the vertical distance bgs at which the bottom
surface of the fracture occurs.
4.1.1.1 Lateral extent
Careful excavation revealed a parting that extended up to 6 in beyond the edge of
the sand in most exposures. Presumably, the parting was open when the hydraulic fracture was pressurized. However, evidence for an open fracture further than approximately
6 in from the edge of sand is lacking, despite careful inspection in these areas. The evidence from mapping suggests that the edge of the sand is quite close (within 6 in) to the
edge of the open fracture. The lateral extent of the sand-filled portion of the fracture is
therefore assumed to represent the overall lateral extent of the fracture. The sand-filled
region of the fracture also has the greatest effect on flow to and from the injection casing
when using the fracture in a soil or groundwater remediation operation, so the sand-filled
region of the fracture is of primary importance.
Trench faces 1 through 4 and 8 all exposed a western and eastern extent of Fracture I (Fig. 4.1-2). This provided 10 control points marking the edge of the sand from
which the lateral extent of the fracture between trenches could be interpolated. The interpolation was done using straight lines (Fig. 4.1-2).
70
200
8
7
150
N
6
100
5
50
4
3
0
2
1
-50
0
-100
-100
5
-50
15 feet
10
0
50
100
overburden
cross section exposure
trench
extent of sand
overburden removed
Figure 4.1-1 Map of exposures of Fracture I.
71
The northern and southern leading edges of Fracture I were exposed by carefully
removing the overburden above the fracture surface. The northern edge was 3 ft bgs, and
it was possible to excavate safely this region by hand. The overburden was completely
removed to reveal the leading edge, which occurred a maximum of 0.8 ft north from the
face of trench 8 (Fig. 4.1-2). The southernmost exposed edge of the fracture is much
wider and deeper than the northern edge. Complete exposure of the southern fracture
edge was infeasible and would have been unsafe without heavy equipment to remove the
large volumes (several cubic yards) of material overlying the southern fracture surface.
However, enough overburden was removed to expose some of the southern fracture face
and the edge of the fracture directly south of the injection casing (Fig. 4.1-2). The edge
of the fracture was approximately 24 in south of trench face 1 at this location.
Fracture I extended beyond the edge of the trench in trench faces 5,6, and 7.
These trench faces ended where they intersected the previously excavated north-south
trending trench 11-12 (Fig. 4-1). The fracture was observed and mapped on trench face
12, but it was absent from trench face 11. This indicates that the leading edge of Fracture
I occurs within a 24-in-wide band between the two faces and had been removed during
the excavation of the 11-12 trench (Fig. 4-1).
The shape of Fracture I in plan-view is approximately elliptical (Fig. 4.1-2). The
aspect ratio of this ellipse is 1:1.4 with a major axis of 22 ft and a minor axis of 15.5 ft.
The area of the ellipse is 267 ft2. For comparison, the area of the fracture determined by
integrating within the line representing the lateral extent is 257 ft2, which is 0.96 the area
of the ellipse. The center of the ellipse is located 5.8 ft north of the injection casing. The
72
borehole eccentricity, the ratio of the distance from the center of the ellipse to the length
of the major axis, is 0.27.
4.1.1.2 Depth
The depth of the fracture is defined as the vertical distance bgs at which the bottom surface of the fracture occurs. A horizontal datum was established at the ground surface at the injection casing. The ground surface at the study site was nearly horizontal in
the vicinity of all of the fractures, so the reference datum constructed for mapping nearly
coincides with the ground surface.
The depth of Fracture I ranges from 2.5 to 6.7 ft bgs. The shallowest portion of
the fracture (2.5 ft bgs) occurs at the northern end, whereas the deepest portion of the
fracture (6.7 ft bgs) is southeast of the injection casing (Fig. 4.1-1 and 4.1-2). In all directions except to the south, the outer edge of the fracture dips back towards the injection
casing (Fig. 4.1-1 and 4.1-2). The southern edge of the fracture is nearly flat lying.
In cross-section, the geometry can be characterized by three general shapes that
occur in different portions of the fracture. Some latitude with respect to symmetry and
completeness must be applied to the simplified forms when comparing them to the fracture traces. In the vicinity of the injection casing (within 1.7 ft), the fracture trace resembles an uneven “W” (Fig. 4.1-3; trench faces 2 and 3). A line through the center of “W”s
on opposite sides of the injection casing passes through the injection casing. From the
central points of the “W”s, the fracture traces plunge downward to the east and west away
from the injection casing at up to 18°. This trend occurs up to 5 ft from the injection casing. The plunge of the fracture trace then gradually reverses to climb upward as steeply
as 35°. In transects farther from the injection casing, the fracture trace resembles an une73
ven “V” (Fig. 4.1-4; trench faces 5 and 6). The average dip of the wings of the “V”s
ranges from nearly flat lying to a maximum of 20°. The fracture traces farthest from the
injection casing (trench faces 7 and 8, Fig. 4.1-4) are nearly flat lying.
An intermediate geometry between “W” and “V” occurs in some traces (e.g. Fig.
4.1-3; trench face 4). This intermediate geometry represents a transition between the
“W” and “V” in which the center high point flattens and the middle of the cross-section is
nearly flat. This form is closest to a “U” with the bottom flattened and sides shortened.
The same intermediate geometry is seen in trench face 1 (Fig. 4.1-3). It is inferred that
had Fracture I extended further to the south, cross-section exposures south of trench face
1 would reveal “V”-shaped traces.
74
-20
-80
-60
-40
-20
0
20
40
60
80
36 S
-40
100
120
i-1
-60
-80
-20
13 S
-40
i-2
-60
-80
-20
-40
15 N
i-3
39 N
i-4
-60
-80
-20
-40
-60
-80
-80
-60
-40
-20
0
20
40
60
80
100
120
Figure 4.1-2 Cross sections of Fracture I, trench faces 1-4. Filled pattern is
saprolite, blank region is silty clay of the B-horizon.
75
-20
-80
-60
-40
-20
0
20
40
60
80
74 N
-40
100
120
i-5
-60
-80
-20
98 N
-40
i-6
-60
-80
-20
i-7
-40
161 N
-60
-80
-20
i-8
-40
185 N
-60
-80
-80
-60
-40
-20
0
20
40
60
80
100
120
Figure 4.1-3 Cross sections of Fracture I, trench faces 5-8. Filled pattern
is saprolite, blank region is silty clay of the B-horizon.
76
An unusual aspect of the form of Fracture I is a horseshoe-shaped trough that surrounds the injection casing and is apparent when the cross-sections are interpolated and
rendered in perspective (Fig. 4.1-7 and 4.1-8). The bottom of the trough ranges from 0.8
to 1.7 ft below the initiation point of the fracture (5 ft bgs). Towards the south, the fracture extends approximately 5 ft nearly horizontally at the elevation of the bottom of the
trough. To the east, west, and north, the fracture climbs upward towards the ground surface from the axis of the trough. Because the trough is a semi-circular feature, any single
perspective hides some of the fracture surface behind the high point where the fracture
was initiated. Two perspective views of the surface of the fracture, overlain by contour
maps, are presented to avoid this problem and aid in the visualization of the trough and
overall geometry of the fracture (Fig. 4.1-7 and 4.1-8).
In examining the strike and dip of the fracture, it is most useful to focus on individual portions rather than summarizing and averaging the overall geometry. The portions of the fracture in the vicinity of the injection casing encompassing the trough, and
the area south of the injection casing were described above. More than half of the area of
the fracture occurs outside of these areas (Fig. 4.1-6). Two transects extending from the
leading edge of the fracture back towards the injection casing, but extending only as far
as the bottom of the horseshoe-shaped trench, are used to summarize the remainder of the
area of Fracture I. In one area where the fracture is roughly planar north of the injection
casing (at (0,196) of Fig. 4.1-6) of the strike of the fracture is S12°E and the dip is 16°S.
This orientation is representative of nearly one-third of the total area of Fracture I. The
other area is along the western edge of the fracture (at (-80,70) of Fig. 4.1-6), and here
the orientation of the fracture is S50°E, 20°SE.
77
The change in depth over a lateral distance appears gradual when viewed at a 1:1
scale, as in Figure xx. However, in detail the fracture is marked by step-like features
where the dip changes over small distances (< 12 in). A step is shown in detail in Figure
xx, but many steps are shown in the other cross-sections (Fig. 4.1-5), where they give the
fracture traces a rough appearance. The apparent dip of the fracture in the step features is
as steep as 80°. These steeply dipping sections result in rapid changes in depth over relatively small lateral distances. More typically, the apparent dips of these features are approximately 45°, and the depth of the fracture changes 2 to3 in. The spacing between
steps varies across each of the cross sections, from sections of nearly continuous step features to several ft of section distinct step features are absent. When the frequency and or
magnitude of depth change is high, the step features represent the major mode by which
the surface of the fracture changes depth.
78
-51
-52
-53
-54
-55
-15
-10
-5
0
5
Figure 4.1-4 Detail of Fracture I showing step from trench face
6. Scale is in inches, 5x vertical exaggeration.
79
200
N
150
100
50
0
-50
0
-100
-100
5
-50
15 feet
10
0
50
100
Figure 4.1-5 Structural contour map of Fracture I. Border scale is in
inches, contour interval is 5 inches.
80
0
ground surface
-40
-60
Figure 4.1-6 Perspective view of structural contour map of Fracture I, looking
north at ~N30°E, 30° down from horizontal.
81
surface
d
n
u
o
r
g
0
-40
-60
Figure 4.1-7 Perspective view of structural contour map of Fracture I, looking
north at N30°W, 30° down from horizontal.
82
4.1.2
Sand thickness
The sand thickness within the fracture is defined as the vertical distance between
the bottom and top surfaces of the fracture. This is slightly greater than the true thickness
measured perpendicular to fracture surfaces where the fracture is dipping. Aperture is the
inflated thickness, that is the thickness during or immediately after fracture propagation
when the fracture is filled with both sand and gel.
The sand thickness varies from a minimum of 0.08-in, primarily at the leading
edges of the fracture, to a maximum value of 0.75-in within the fracture. A thickness of
0.08 in is approximately one sand grain. The thinnest sections of the fracture occur along
trench faces 1 and 8, which are within 2.0 ft of the leading edge of the fracture (Fig. 4.1-9
and 4.1-10). The sand thickness at the leading edge of the fracture exposed in other sections is similar (0.08-0.10 in). The average sand thickness for all of the exposures in 0.18
in, however, this value is strongly dependent on the location of the exposures within the
fracture. Sections 1,2,7, and 8, which are the exposures most near the northern and
southern edges of the fracture, average only 0.12 inches thick. By comparison, sections 3
through 6 (positioned in-between sections 2 and 7) average 0.25 inches thick.
The variability of sand thickness increases with the length of the cross-section of
Fracture I. The variability also increases with distance from the northern and southern
edges, the edges to which the cross-sections are nearly perpendicular (Fig. 4-1). Maximum variability in sand thickness occurs in trench faces 5 and 6, where the standard deviations are 0.12 and 0.11 in, respectively. Trench faces 5 and 6 are the longest crosssections of Fracture I and nearly transect the center of the fracture. Trench faces 1 and 8
83
are the shortest sections and contain the least amount of variability, with standard deviation values of 0.03 and 0.01 in, respectively.
84
1.0
-80
-60
-40
-20
0
20
40
60
80
0.8
100
120
i-1
0.6
0.4
0.2
0.0
1.0
0.8
i-2
0.6
0.4
0.2
0.0
1.0
0.8
i-3
0.6
0.4
0.2
0.0
1.0
0.8
i-4
0.6
0.4
0.2
0.0
-80
-60
-40
-20
0
20
40
60
80
100
120
Figure 4.1-8 Cross sections of sand thickness (open circles) and uplift (open
diamonds) for Fracture I, trench faces 1-4. Third-order polynomial fit
for sand thickness (solid line) and uplift (dashed line).
85
1.0
-80
-60
-40
-20
0
20
40
60
80
0.8
100
120
i-5
0.6
0.4
0.2
0.0
1.0
0.8
i-6
0.6
0.4
0.2
0.0
1.0
0.8
i-7
0.6
0.4
0.2
0.0
1.0
0.8
i-8
0.6
0.4
0.2
0.0
-80
-60
-40
-20
0
20
40
60
80
100
120
Figure 4.1-9 Cross sections of sand thickness (open circles) and uplift (open
diamonds) for Fracture I, trench faces 5-8. Third-order polynomial fit
for sand thickness (solid line) and uplift (dashed line).
86
Sand thickness values from the cross-sections were interpolated and rendered as a
contour map in SURFER© (Fig. 4.1-11). Integrating the sand thickness over the area of
the fracture (using the blanking file) yields a bulk volume of 4.3 ft3. The bulk volume of
sand involved with the injection process is 5.3 ft3, however, approximately 0.1 ft3 was
removed during sampling and up to another 0.2 ft3 remained in the fracturing equipment
and injection casing. Therefore a total of 5.0 (+/- 0.3 ft3) was injected into the fracture.
The relative error between the injected and mapped volume of sand is 0.14. +/- 0.07
The error between the injected sand volume and the volume mapped in the subsurface is remarkably small and provides a general verification of the mapping methods.
The error is probably a result of methods used to trace the fracture onto the transparent
sheets. The goal was to trace directly over the top and bottom surfaces of the fracture.
The varying thickness of the marking pen lines, and confined working spaces that presented difficult perspectives sometimes made it difficult to trace the surface exactly. In
these cases, the tendency was to trace inside of the fracture surface, rather than outside of
it. This effect was further magnified when collecting data from the sections. If it is assumed that the error is distributed evenly over the area of the fracture, 0.14 relative error
translates to an average absolute error of 0.004 in of sand thickness at any given location.
This is much less than the resolution of the measurement methods. The error in the total
volume predicted by the sand thickness distribution is relatively small and suggests that
most of the injected sand can be accounted for by these methods.
When the sand thickness data is contoured, a pattern emerges (Fig. 4.1-11) that is
obscure when the data are viewed in cross-sections (Fig. 4.1-9 and 4.1-10). Elongate features are apparent that trend north-northwest and north-northeast from the injection cas87
ing. The southern portion of the map shows linear features of low (< 0.15 in) sand thickness trending towards (or away) from the injection casing. A trough structure in which
sand is unusually thin (roughly 0.2 in) trends north from the injection casing, and roughly
bisects the fracture into eastern and western halves (Fig. 4.1-11). This band of thin sand
is a prominent feature approximately 1.7 ft east of (x=0) near the middle of the cross sections of trench faces 3,4,5, and 6 (Fig. 4.1-9 and 4.1-10).
88
200
N
150
100
50
0
-50
0.0
-100
-100
0.1
-50
0.2
0.3
0
0.4
50
0.5 inches
100
Figure 4.1-10 Map of sand thickness in Fracture I. Circle with cross is injection
borehole.
89
4.1.3
Uplift
The vertical deformation at the ground surface, or uplift, measured immediately
after the pumping event of Fracture I resembles an elliptical dome. In all directions except northeast and northwest, the uplift extended beyond the area that contained survey
points, so bounding the extent of uplift is impossible using field data alone. The 0.1-in
contour was inferred as an approximation of the lateral extent of uplift by extrapolation
based on patterns of uplift at other fractures. The interpolated pattern generated by
SURFER© seems exaggerated to the northeast and northwest at the outer limits of the uplift data set (Fig. 4.1-12). The error associated with each uplift measurement is 0.05 in
and as such, the 0.1-in contour could be shifted several ft within this margin of error.
The maximum uplift measured was 0.95 inches at 8 ft north of the injection casing. This represents a displacement eccentricity, the ratio of the distance from the injection casing to the point of maximum uplift to the length of the major axis (Murdoch and
Slack, 2002), of 0.22.
The relationship between uplift and the lateral extent of sand of a fracture is a
prime interest. The uplift extended well beyond the lateral extent of sand in Fracture I
(Fig. 4.1-13). The shapes of the uplift and the lateral extent are quite similar, however.
The uplift can be characterized by an ellipse fitted to the 0.08-in contour. The aspect ratio of this ellipse is 1:1.2, compared to 1:1.4 for the fracture; both ellipses have the same
major axis orientation of north-south. The borehole eccentricity of the uplift ellipse is
0.21, compared to 0.27 for the fracture.
90
The volume under the uplifted dome within the 0.3-in contour was seems to approximate the extent and location of the fracture (Fig. 4.1-13). The volume of uplift
within the 0.3-in contour is 12 ft3. As the 0.1-in contour was intended as an estimation of
the lateral extent of uplift, the displaced volume within the 0.1-in contour is taken as an
estimation of the total volume of uplift. Integrating beneath the uplift surface within the
0.1-in contour gives a volume of 17 ft3, the same as the volume of slurry injected.
Uplift was then compared to sand thickness. Values of uplift were assigned to x-y
coordinate points along trench faces 1-9 by overlaying the uplift map onto a post map of
the trench faces (Fig. 4.1-13, note that the trace of each trench face is shown with dotted
lines within the shaded fracture area). These uplift values were added to the overlay map
database and plotted along with sand thickness (Fig. 4.1-9 and 4.1-10). The data were
fitted with a 3rd-order polynomial, which matches the profile of typical uplift patterns reasonably well. Because of the variability of the sand thickness data, direct comparison of
uplift to sand thickness is difficult. As a result, the sand thickness data were fitted with a
second 3rd-order polynomial for comparison. The ratio of these two curves was then calculated as sand thickness/uplift and plotted (Fig. 4.1-14 and 4.1-15).
The ratio of the curves characterizing sand thickness to uplift across fracture I averages approximately 0.3:1 to 0.4:1, with minimum and maximum ratios of 0.15:1 and
0.65:1 respectively. This is a similar value to the sand loading of the fracture (average
sand loading is 0.3), which suggests that the product of uplift and sand loading is a good
general indicator of sand thickness. It can be seen, however, that the value of sand thickness can vary from 0.2 to 0.5 of the average value over a cross section.
91
300
250
0.10
0.10
200
0.25
0.25
0.3
0.30
0.80
150
100
0.1
0.5
0.00
0.00
0.95
0.95
0.10
0.10
0.15
0.15
0.40
0.40
0.80
0.80
0.40
0.40
50
0.00
0.00
0.7
0.60
0.60
0.60
0.60
0.40
0.40
0
0.20
0.20
0.10
0.10
0.20
0.20
0.10
0.10
-50
0.30
0.30
0.10
0.10
0.05
0.05
0.01
0.01
0.10
0.10
0.05
0.05
-100
N
0.05
0.05
-150
0.01
0.01
feet
-200
0
-250
-200
-150
-100
-50
0
5
50
100
10
150
200
Figure 4.1-11 Map of uplift over Fracture I. Data are posted (small
numbers) for each uplift stake marked by a “+”. Contour interval is 0.2 inch, contour lines labeled with large numbers. Axes
scale in inches.
92
350
300
N
250
200
150
100
0.7
50
0.5
0.3
0
0.1
-50
-100
-150
0
-200
-200 -150 -100
5
-50
10
0
15 feet
50
100
150
200
250
Figure 4.1-12 Map of uplift contours and the region containing sand
(shaded) of Fracture I and trace of trench faces (dotted lines).
93
1.0
-80
-60
-40
-20
0
20
40
60
80
0.8
100
120
i-1
0.6
0.4
0.2
0.0
1.0
0.8
i-2
0.6
0.4
0.2
0.0
1.0
0.8
i-3
0.6
0.4
0.2
0.0
1.0
0.8
i-4
0.6
0.4
0.2
0.0
-80
-60
-40
-20
0
20
40
60
80
100
120
Figure 4.1-13 Ratio of regressions (thick line) fitted to sand thickness (thin
line) and uplift (dashed line) for trench faces 1-4 of Fracture I.
94
1.0
-80
-60
-40
-20
0
20
40
60
80
0.8
100
120
i-5
0.6
0.4
0.2
0.0
1.0
0.8
i-6
0.6
0.4
0.2
0.0
1.0
0.8
i-7
0.6
0.4
0.2
0.0
1.0
0.8
i-8
0.6
0.4
0.2
0.0
-80
-60
-40
-20
0
20
40
60
80
100
120
Figure 4.1-14 Ratio of regressions (thick line) fitted to sand thickness (thin
line) and uplift (dashed line) for trench faces 5-8 of Fracture I.
95
200
0.70
150
0.65
0.60
0.55
100
0.50
0.45
0.40
0.35
50
0.30
0.25
0.20
0
0.15
0.10
0.05
0.00
-50
0
-100
-100
50
-50
100
0
150
50
200
100
Figure 4.1-15 Map of the ratio of sand thickness to uplift of Fracture I.
96
4.1.4
Color distribution
The distribution of different colors of sand in the fracture was estimated by visual
inspection in the field, but it was determined quantitatively for samples of slurry taken at
regular intervals during the fracture injection. The slurry samples were first washed and
oven dried, then shaken and mixed. Several sub-samples weighing approximately 20
grams were taken from each sample then those sub-samples were combined and mixed.
Approximately 10 grams of this sub-sample mixture was taken and sorted by hand into
red, “white”, and blue portions. The mass of each of the colors was divided by the combined mass of the three potions to express the relative content of each (table 4). The values determined by the methods are within approximately 10 percent of estimates made be
visual inspection of the bulk samples. This indicates that accuracy of the visual method
of estimating the distribution of sand in the fracture in the field should be within about 10
percent of values that would be obtained by a detailed analysis. This is sufficient accuracy for the field methods.
97
Table 4 Sand loading and color content (red, white, and blue) of 4
samples of slurry taken at regular intervals during the injection of Fracture I.
Sand Loading
Color Percentages
40%
b
30%
r
20%
w
10%
0%
1
2
3
4
1
sample sand loading (%)
1
10
2
37
3
40
4
29
average: 29
2
r
0.17
0.03
0.01
0.01
3
w
0.82
0.95
0.64
0.16
4
b
0.02
0.02
0.35
0.83
98
4.1.4.1 Cross-Sections
The sand-color distribution data were interpolated and plotted as individual contour maps (Fig. 4.1-16). The red sand, which was injected first, occurs within approximately 6 ft of the injection casing and is essentially absent beyond this distance. The majority of the red sand is south of the injection casing and is concentrated in north-south
trending ridges (Fig. 4.1-16; a). The white sand occurs throughout most of the fracture,
but is absent from the northern leading edge. The greatest percentage values of white
sand occur in the eastern and southeastern portions of the fracture. The least values are in
a north-south trending band, which contains less than 20 percent white sand, extending
from the injection casing (Fig. 4.1-16; b). All of the blue sand occurs north of the injection casing. The highest percentages of blue sand occur in a north-south trending band
approximately 2 ft wide extending north from the injection casing—the same band where
the fraction of white sand is low. This band of blue sand fans out to encompass the
northern edge of the fracture. A less prominent, discontinuous band trends roughly
N20W from the injection casing (Fig. 4.1-16; c).
99
200
200
150
100
05
0
-50
150
a.
-100
-100
-50
0
50
100
red
0% 20% 40% 60% 80% 100%
N
10 feet
100
50
white
200
c.
0
150
-50
100
-100
200
-100
-50
0
50
b.
100
50
blue
150
0
100
-50
50
-100
-100
-50
0
50
100
0
-50
-100
-100
-50
0
50
100
Figure 4.1-16 Maps of color percentage data interpolated from cross sections
of Fracture I.
100
Many cross-section exposures revealed structures of younger sand embedded in
older sand, as indicated by contrasts in sand color. The contacts between the two different colors of sand is typically fairly sharp and it is always concave toward the younger
sand. In some exposures, the contact curves downward from the upper wall of the fracture, flattens out and curves back up to the upper wall. This produces a structure that resembles a deposit of channel sand in cross-section (Fig. 4.1-17). In other exposures, the
contact curves downward from the upper wall and intersects the lower wall, and this contact is typically mirrored by another one nearby to bound the resulting structure. These
exposures resemble the channel-like features, but they are thicker and wider.
The channel structures are clearly cross-section exposures of the bands of colored
sand described above. These structures are shaped like channels in cross-section, they
are elongate features that branch in the direction of flow, and they cut sand that was deposited previously. The sand channels in hydraulic fractures seem to resemble channel
deposits formed by rivers in many ways.
Fracture
Surfaces
Younger sand
Older sand
Figure 4.1-17 Sketch of a typical channel structure observed in fracture
cross sections.
101
4.1.4.2 Surface Observations
Several areas were exposed by carefully removing the overburden to reveal the
upper surface of the sand. The distribution of sand colors in these areas was mapped in
plan view.
One area where sand colors were mapped is the vicinity of the injection well, another is to the northwest of the injection well, and a third area is south of the injection
well (Fig. 4.1-18). The best exposure where most detail could be determined is the
northwestern area, where the exposure covers approximately 10 ft2. The patterns formed
by the sand colors on the top of fracture were delineated with pins pushed into the underlying clayey material. Then the loose sand was removed with a vacuum cleaner. Sand
grains sticking to the bottom surface of the fracture remained in place and the patterns
formed by these different colors were mapped using the pins as reference points. Then
the sand was completely removed to reveal a series of steps on the fracture surface. The
locations of the steps were included on the map.
102
5
4
3
2
1 ft
1
1m
Covered
Overburden
Step on fracture surface.
Dots on downthrown side
Red Sand
Contact inferred
White Sand
Limit of red sand
Blue Sand
Trenched
Injection casing
area
Approx. extend of fracture
Strip of blue sand on frx surface
Trench
Injectionface
casing
Figure 4.1-18 Map of southwestern portion of Fracture I.
103
4.1.4.2.1 Northwestern Exposure
The upper surface of the sand in the northwestern exposure is characterized by
bands of blue sand separated by white sand (Fig. 4.1-18). Both regions actually consist
of mixtures of colors, but the regions labeled as blue sand are dominantly that color, with
subordinate amounts of white sand and a few grains of red sand. The regions labeled as
white sand also contain some blue and red sands.
The bands of blue sand trend roughly east-west and are 0.5 to 1 ft wide (Fig. 4.118). The bands are well defined, but the contact between the blue and white sand was
commonly gradational over 0.1 ft. Some of the grading between the colors resulted from
disturbances during excavation, so the contacts probably were sharper than they appeared
in the excavation.
The bands of blue sand bifurcated with increasing distance from the injection casing (Fig. 4.1-18). Two blue bands occurred on the eastern end of the exposure. The
southernmost band splits into five bands across the exposure. The northernmost band
appears to split into two bands, but the ends of these bands were removed during excavation so the full extent of the bifurcation is unknown..
The lower surface of the fracture was marked with a dendritic pattern of narrow
strips of blue sand (Fig. 4.1-18), which were revealed after the overlying sand (approximately 0.25 in thick) was removed. The strips of blue sand were 0.1 to 0.3 ft wide and
formed a branching pattern that corresponded to the axes of the wider blue bands. Several of the blue strips appear to have split within a blue band near the western edge of the
fracture (Fig. 4.1-18).
104
The orientation of the blue bands ranges from WNW in the northern part of the
exposure, to WSW and SW in the southern end. The blue strips that occur along the axes
of the bands follow similar orientations, but the blue bands that trend to the SW lack a
well-defined blue strip along their axes (Fig. 4.1-18). Orientations of both blue strips and
blue bands appear to be perpendicular to the leading edge of the fracture in the vicinity.
The leading edge of the fracture was removed during excavation directly to the west of
the exposure, but it can be located within roughly 0.5 ft based on exposures in the vicinity.
The blue strips appear to be channel structures, although none of them could be
examined in cross-section. The blue bands on the lower surface of the fracture appear to
be deposited where the thickest part of the channel spanned the entire fracture.
The lower surface of the fracture was formed from massive silty clay typical of
the B soil horizon. The surface was slightly irregular with several steps where the elevation changed abruptly by 0.5 to 0.15 ft. The steps formed linear features from 0.3 ft to
more than 1 ft long. Six steps were clearly evident on the fracture surface and they all
shared some common characteristics. All the steps occurred in areas of white sand between the bands of blue sand. They all were roughly parallel to the blue bands and strips
in their vicinity. As a result, the orientation of the steps radiates from WNW to SW, following the orientation of the bands. The downthrown sides of the steps was also consistent; the downthrown side was always to the south (Fig. 4.1-18).
Red sand occurred locally on the eastern part, but it was absent from the western
part of the exposure. Red sand occurred as patches or pods on the bottom surface of the
105
fracture, but significant concentrations of red sand were absent from the upper surface of
the sand, which was visible when the area was first exposed.
4.1.4.2.2 Southern Exposure
A region to the south of the injection casing was also exposed by excavation, and
the pattern here resembled that of the northwestern area but with some important differences. This region is approximately 2 ft2 and it reveals the leading edge of the fracture.
Sand in this region is several grains thick (1 to 2 mm), and most of the sand is red. Four
bands of white sand extend from the trench face southward and terminate slightly north
of the leading edge (Fig. 4.1-18). The bands are 0.1 to 0.2 ft wide and the exposed length
ranged from 0.3 ft to nearly 1 ft. They are rounded in plan, so the bands of white sand
resemble lobes.
The lobes of white sand that were readily apparent on the fracture surface after
excavation were much less distinct when viewed in cross-section on the trench walls.
Strips of white sand were apparent in the otherwise red sand in a few locations, but red
and white sand appeared to be mixed together without a structure that could be discerned
in cross-section. As a result, lobes of white sand probably occurred elsewhere in the red
sand to the south and east of the injection casing but they were difficult to recognize in
the cross section exposures on the trench walls.
The lower fracture surface was slightly irregular, but well-defined steps similar to
the ones that occur on the northwestern exposure were absent. The hydraulic fracture
cuts medium-grained, micaceous saprolite in the southern exposure, whereas it cuts mas-
106
sive silty clay in the northwestern exposure, so the lack of steps on the fracture surface
may be a result of the differences in material.
4.1.4.2.3 Borehole Exposure
The vicinity of the borehole was exposed and the colors of sand were mapped
there. The region was disrupted during excavation, so only the general sand distribution
could be determined; the vertical variation in the pattern of sand color that was determined in the northwestern exposure could not be evaluated near the borehole. The locations of the major colors of sand was unaffected by excavation, and that is what is shown
in Figure 4.1-18.
Significant zones of all three colors of sand occur within 1 ft of the borehole.
Patches of red sand occur over the entire exposure, and white sand fills the regions between the red. Significant amounts of blue sand occur in the vicinity of, and to the north
of the casing. The contacts between colors near the injection casing were much more distinct than was seen further out in the fracture. The contact between blue and a pod of red
sand to the north of the injection casing was particularly dramatic in that the boundary
was sharp and either side contain only one color of sand (no white sand was present).
One observation that may be significant is that the patches of red sand in the vicinity of the casing clearly span the entire thickness of the fracture. Red sand was injected first and the fracture aperture near the casing probably was roughly half of the final
aperture when the last of the red sand was injected. The red sand fills the entire fracture,
however, so it appears that the thickness of the red sand increased to fill the fracture after
is was injected.
107
4.1.5
Notch
Notch measurements of Fracture I made at ground surface before the fracture was
created are similar to observations made of the notch during excavations. The horizontal
extent of the notch as measured from the ground surface averages 8 inches in each direction, with a maximum extent of 10.5 in to the west (Fig. 4.1-19). Profiles of the notch
created during exposure of the fracture face showed the notch to be a gentle dome. The
top of the dome was approximately 2 in high and the top tapered down evenly to the outer edge. The bottom surface of the notch was essentially flat out to the edge, where it
rose sharply up to 0.5 in. When the sand was completely removed from the bottom surface, sharp trough-like features were observed radiating from the center out to the edge of
the notch. The silty clay in the vicinity of the casing was fairly uniform, so the troughlike features were interpreted as places where water jet had cut a particularly wide slot.
The edge of the notch, interpreted by the rise in the bottom surface, was circular. The
radius of the circle was approximately 10 inches, suggesting the notch measuring tool
consistently underestimated the extent of the notch by 2 inches (20 percent) but correctly
predicted the shape.
108
NW
W
N
12
8
4
0
SW
NE
E
SE
S
Figure 4.1-19 Extent of notch (inches) based on measurements made
at ground surface prior to fracture creation.
109
4.2
Fracture H
Exposures and mapping of Fracture H are similar to that of Fracture I, but there
are several important differences. The total length of exposures available to characterize
Fracture H was approximately half the mapped exposure control of Fracture I. Also,
there is no sand color data for Fracture H. Saprolite was not observed in any of the excavations of Fracture H. The trenches in the vicinity of Fracture H were no deeper than 7 ft
bgs, and it is assumed that the contact between the B-horizon and the saprolite occurs below 7 ft in this area.
4.2.1
Geometry
Fracture H has similarly distributed exposure control as Fracture I, and was transected by trench faces 3 through 8 (Fig. 4-1). However, trench faces 4 and 5 were not
able to be mapped with transparency sheets because too much overburden was removed
from this area during excavations. The remaining overburden was also accidentally hit
several times with the backhoe bucket. Consequently, it was not possible to establish
straight, vertical exposures along the two trench faces. However, the lateral extent and
bottom surface of the fracture in this area were well exposed and these observations were
used to confirm and constrain interpolations between trench faces 3 and 6.
The northern extent of Fracture H was determined with a trench not shown in figure 4-1. This trench was dug due north of injection casing H after the other trenches were
all backfilled. The trench intersected trench face 8 and extended approximately 10 ft to
110
the north. The fracture extended north 18 inches, rising gradually from 60 in bgs to 54 in
bgs along the wall of this trench.
The extent of Fracture H south of trench face 3 was completely exposed by removal of the overburden after transparency maps were completed. The extent of sand on
the bottom face of the fracture was carefully marked with push-pins. The sand extended
a maximum of 8 in south of trench face 3.
The general shape of Fracture H in plan view resembles an ellipse (Fig. 4.2-1).
The major and minor axes of the ellipse are approximately 18.5 ft and 16.5 ft, respectively. The center of the ellipse is located 2.5 ft south of the injection casing, representing a
borehole eccentricity of 0.13. The outline of the fracture deviates from the ellipse at the
north and south ends, and this is possibly a result of incorrect reference to the site grid
system during mapping activities. The outline of the fracture assumes a more ideal elliptical shape if trench face 8 data is shifted 2 ft east and trench face 3 data is shifted approximately 3 ft east. Confirming these adjustments was impossible after the trenches
were backfilled. Where leading edges of the fractures were able to be exposed, they were
often observed to be uneven, changing radial distance back to the injection casing several
inches over small lateral distances. It does seem possible, therefore, for the data to be
correctly positioned in the grid and reflect actual fracture conditions. Although a more
elliptical outline is visually appealing, the data were preserved as originally recorded.
111
100
0
10 feet
5
50
N
0
-50
-100
-150
-100
-50
0
50
100
Figure 4.2-1 Lateral extent of Fracture H shown in dashed line. Trench faces
mapped with transparency sheet shown in bold lines. Axes scale inches,
circle with cross is injection casing.
112
-80
-60
-40
-20
0
20
40
60
80
100
-20
116 S
h-3
39 S
h-6
24 N
h-7
48 N
h-8
-40
-60
-20
-40
-60
-20
-40
-60
-20
-40
-60
-80
-60
-40
-20
0
20
40
60
80
100
Figure 4.2-2 Cross sections of Fracture H. Scale is in inches.
113
4.2.1.1 Depth
The fracture surface was exposed on the northern half of the vicinity of the notch
(approximate 6 ft2) and was flat lying in this area. The traces of the cross sections resemble shapes described for Fracture I. A shallow “U” shape can be seen in trench faces
7 and 8,which are 24 and 48 in north of the injection casing, respectively (Fig. 4.2-2). To
the south of the injection casing, the trace of trench face 6 forms a broad “V” (Fig. 4.2-2).
At the southernmost end of the fracture, the trace along trench face 3 is nearly horizontal
(Fig. 4.2-2). The traces of the fracture along trench faces 4 and 5 were roughly horizontal
in the middle and curved upward along their edges to produce a trace intermediate between the “U” and “V” shapes. Traces along faces 4 and 5 could not be mapped accurately, however, so they were not included in the database.
Overall, these shapes combine to form a picture of the bottom surface of Fracture
H that resembles a spoon, with the injection casing at the lowest point and the handle of
the spoon (not part of the fracture) pointing north. This form is represented in plan view
by a contour map (Fig. 4.2-3), and in perspective on a surface map (Fig. 4.2-4). The fracture surface is either flat-lying or dips back towards the injection casing in all directions.
As in Fracture I, dips were quite steep in small step features, but the gross dip ranged
from 5° to 13°.
The form of Fracture H differed from that of Fracture I in the vicinity of the casing. Fracture I curved downward to produce a trough-like structure that wrapped around
the casing and extended below the bottom of the injection casing (Fig. 4.1-6 and 4.1-7).
In contrast, the vicinity of Fracture H was roughly flat-lying and it never occurred at
depths below the bottom of the casing (Fig. 4.2-4).
114
100
0
10 feet
5
50
N
0
-50
-100
-38
-150
-100
-50
0
50
100
Figure 4.2-3 Structural contour map of Fracture H, contour interval is 2
inches.
115
Figure 4.2-4 Perspective map of Fracture H, looking south at ~ S15°W, 30°
down from horizontal.
116
4.2.2
Sand Thickness
The sand thickness of Fracture H as shown in the four cross sections (Fig. 4.2-5)
is highly variable. However, the general distribution of sand within the fracture is similar
to that of Fracture I. At the edge of the fracture (trench face 3), the sand thickness is minimal (<0.10 in). The maximum thickness of the fracture is 0.25 inch along Trench face 8,
which is within 1.5 ft of the northern edge of the fracture. The thickest sand occurs in the
center of the fracture (trench faces 6 and 7), where it reaches a maximum of 0.70 inches
and averages approximately 0.25 in. The eastern and western ends of each of the cross
sections mapped the edge of the fracture at that point, and sand thickness taper to less
than 0.10 in at each of these 8 points (Fig. 4.2-5).
The variability of sand thickness in Fracture I is also similar to that of Fracture I.
The highest variability occurs in the middle of the fracture, whereas the edges of the fracture are quite consistent in thickness.
117
1.2
1.0
0.8
0.6
0.4
0.2
0.0
1.2
1.0
0.8
0.6
0.4
0.2
0.0
1.2
1.0
0.8
0.6
0.4
0.2
0.0
1.2
1.0
0.8
0.6
0.4
0.2
0.0
-80
-60
-40
-20
0
20
40
60
80
100
-40
-20
0
20
40
60
80
100
h-3
h-6
h-7
h-8
h-8
-80
-60
Figure 4.2-5 Cross sections of sand thickness (open circles) and uplift (open
diamonds) for Fracture H. Third-order polynomial fit for sand thickness
(solid line) and uplift (dashed line).
118
4.2.3
Uplift
The uplift of Fracture H resembles an elliptical dome, with the center offset from
the injection casing to the southeast (Fig. 4.2-6). Maximum uplift of 1.20 inch was
measured at 3 ft south of the injection casing, roughly coincident with the center of an
ellipse fitted to the 0.1 in contour line. The uplift stakes were placed at 3 ft intervals for
this fracture. Uplift extended beyond the southern and southeastern limits of the stake
array, but uplift is bounded by zero measurements within the array in all other directions.
When the uplift contour map is overlain onto the lateral extent of Fracture H (Fig.
4.2-7), it can be seen that uplift extended well beyond the edge of sand in the fracture. In
plan-view, the general shape and orientation of the uplift and the fracture are similar.
The 0.3 in contour line has a similar area and location to that of the fracture. If trench
faces 3 and 8 were shifted as mentioned earlier, the shape of the outline of the fracture
and the 0.3 in contour would be similar. The center of the fracture and the overall uplift
dome are within 1 ft of one another.
119
200
150
0.0
2.5
N
0.00
0.00
feet
5.0
0.00
0.00
100
0.16
0.16
0.00
0.00
0.00
0.00
0.00
50
0.06
0.06
0.20
0.20
0.39
0.49
0.49
0.55
0.55
0.71
0.71
0.85
0.85
0
1.04
1.04
0.75
0.75
0.45
0.45
0.05
-0.10
-50
0.00
0.00
1.10
1.10
0.49
-100
0.91
0.91
1.20
1.20
1.1
0.9
0.35
0.35
0.06
0.7 0.5
0.3
0.16
0.16
0.1
-150
-200
-150
-100
-50
0
50
100
150
Figure 4.2-6 Map of uplift over Fracture H. Data are posted (small numbers) for each uplift stake marked by a “+”. Contour interval is
0.2 inch, contour lines labeled with large numbers.
120
150
feet
100
0.0
2.5
N
5.0
50
0
-50
1.1
0.7
-100
0.3
0.1
-150
-200
-100
-50
0
50
100
150
Figure 4.2-7 Map of uplift contours and the region containing sand
(shaded) of Fracture H, trace of trench faces (heavy lines), and
injection casing (filled cicle).
121
4.2.3.1 Sand Thickness to Uplift Ratios
The maximum ratio of sand thickness to uplift ranges from 0.3 to 0.6 along the
four cross sections (Fig. 4.2-8). The ratios are greater in the centers of the cross-sections
and decrease at the edges along sections that are near the center of the fracture, but they
increase as the western edge of the fracture is approached on the other two sections. The
volumetric sand loading for this fracture is approximately 0.30, so the ratio of sand thickness to uplift is approximately equal to more than twice the sand loading. The average
ratio across the two sections closest to the injection casing (trench faces 3 and 6) was
0.28, equal to that of the sand loading. Further to the north in trench faces 7 and 8, the
average ratio is higher, at 0.45.
122
1.2
1.0
0.8
0.6
0.4
0.2
0.0
1.2
1.0
0.8
0.6
0.4
0.2
0.0
1.2
1.0
0.8
0.6
0.4
0.2
0.0
1.2
1.0
0.8
0.6
0.4
0.2
0.0
-80
-60
-40
-20
0
20
40
60
80
100
-40
-20
0
20
40
60
80
100
h-3
h-6
h-7
h-8
h-8
-80
-60
Figure 4.2-8 Ratio of regressions (thick line) fitted to sand thickness (thin line)
and uplift (dashed line) of Fracture H.
123
4.3
Fracture G
The analysis of Fracture G differs from that of Fractures I and H because the
amount of data and the pattern of the exposure differs (Fig. 3.4-1, Table 1). Essentially,
only half of the fracture was exposed. The form of the unexposed half is inferred from
the exposed half and features common to all of the fractures. While these inferences are
based on data, they are not themselves compiled into a database. It was impossible to
create maps with the resolution and accuracy as those presented for Fracture I for Fracture G. Interpolation of the data, such as was done for Fractures I and H, yielded results
that differed from observed forms. A concerted effort was made to interpolate and contour these data with various interpolation methods and by adding “control points” to the
grid, but no useful results were generated. Consequently, contour maps of data interpolated between trenches (e.g. bottom surface contour and perspective, sand thickness) are
not presented Fracture G.
Fracture G was exposed in 2 trenches, yielding 4 cross-section exposures (table
1). One trench oriented roughly north-south was dug first, creating trench faces 11 and
12 (Fig. 3.4-1). During excavation, previously unknown water pipe was uncovered approximately 8 in bgs on the west side of, and running in the direction of the trench. The
pipe probably had negligible effect on the fracture, but it precluded any excavations to
the west of trench face 11. East west trending trench faces 7 and 8 exposed the eastern
extent of the fracture. It can be seen in figure 4.3-2 that the mapped portion of trench
faces 7 and 8 do not extend all the way to the west to meet the intersection with trench
face 12 approximately 2 ft east of the injection casing. The corners where trenches inter-
124
sected were not square or vertical and it was infeasible to overlay-map these small sections.
The north-south trench was intentionally dug to transect the principal axes of the
fracture. This was done because an axial trench would yield the most useful single cut
for defining fracture form. The placement and the orientation of the trench were based on
the uplift measurements made immediately after the creation of the fracture. The uplift
created by Fracture G is therefore discussed first because it was used to infer the form of
the unexposed portion of the fracture.
4.3.1
Uplift
The uplift pattern created by Fracture G is a nearly circular dome. The center of
the dome is located approximately 3 ft north to northeast of the injection casing and coincides with the maximum uplift, 0.9 inches. The circle is symmetrical from east to west
along a north-south line that intersects the injection casing. Uplift extended beyond the
survey staff area at all points north of the injection casing, but dropped to zero within extent of the uplift array 12 ft to the south. The uplift surface interpolated by SURFER©
(Fig. 4.3-2) was exaggerated to the northeast and northwest compared to a hand-drawn
interpolation. This exaggeration is an artifact of extrapolation resulting from the Kriging
algorithm and is unrealistic. As a result, artificial control points were included in the dataset to force the interpolation to be roughly consistent with the general forms of uplift
over other fractures (Fig. 4.1-11, 4.2-3, and 4.4-1).
125
200
0.10
0.10
150
0.1
0.45
0.45
N
0.3
100
0.06
0.06
0.5
0.85
0.85
0.7
0.26
0.26
50
0.65
0.65
0.06
0.06
0.26
0.26
0.55
0.55
0.91
0.91
0.71
0.71
0.91
0.91
0.71
0.71
0
0.45
0.45
0.45
0.45
0.20
0.20
0.35
0.35
0.26
0.26
0.06
0.06
-50
0.06
0.06
0.00
0.00
0.16
0.16
0.00
0.00
0.06
0.06
-100
feet
0.0
2.5
5.0
0.00
0.00
-150
-150
-100
-50
0
50
100
150
Figure 4.3-1 Map of uplift over Fracture G. Data are posted (small numbers) for each uplift stake marked by a “+”. Contour interval is 0.2
inch, contour lines labeled with large numbers.
126
4.3.2
Lateral Extent
The lateral extent of Fracture G was exposed in trench faces to the north, south,
and east. The western extent was interpreted from the exposed eastern half, the uplift
pattern, and observations made of the other fractures. The eastern half of the fracture can
be approximated by half of an ellipse; so the other half of that ellipse was used to characterize the western half of the fracture (Fig. 4.3-2). The ellipse is offset from the injection
casing in the same direction as the uplift dome, and the center of the ellipse is within 2 ft
of the maximum observed uplift. However, the ellipse characterizing the extent of sand in
the fracture has a higher aspect ratio than the very nearly circular uplift pattern. The major axis of the fracture-ellipse is 15.8 ft long and the minor axis is 14.2 ft, with an aspect
ratio of 1.1:1.
127
200
150
0.1
100
N
0.3
50
0
-50
-100
feet
0.0
-150
-150
-100
-50
0
50
2.5
100
5.0
150
Figure 4.3-2 Map of uplift contours and the region containing sand (shaded) of
Fracture G and trace of trench faces (solid lines).
128
4.3.3
Depth
The trace of the bottom surface along trench faces 11 and 12 Fracture G (Fig. 4.33) resembles the “W” shapes seen in Fracture I (Fig. 4.1-3). The trace is what would be
produced by a south to north transect of Fracture I through the injection casing. The fracture dips down in the vicinity of the injection casing, then flattens out and climbs towards
the ground surface. It can also be seen to occur deeper in one direction (to the south)
than in the other direction. The fracture propagated a greater distance in the direction of
shallower propagation. These observations are proportionally consistent with what was
seen in Fracture I. The trace of the bottom surface of Fracture G in trench faces 7 and 8
are flat lying to gently dipping (~10°) back towards the injection casing (Fig. 4.3-3). This
is the same form observed within several feet of the edges of the cross sections of Fracture I (trench faces 3,4,and 5, Fig. 4.1-3 and 4.1-4) and Fracture H (trench faces 6 and 7,
Fig. 4.2-3)
129
-30
-40
-50
-60
-70
-80
-90
-30
-40
-50
-60
-70
-80
-90
-60
-40
-20
0
20
4.3.4
40
60
80
100
120
-40
-20
0
20
40
60
80
100
120
g-11
g-12
-60
-30
-40
-50
-60
-70
-80
-90
-30
-40
-50
-60
-70
-80
-90
g-7
40
60
80
100
g-8
40
60
80
100
Figure 4.3-3 Cross sections of Fracture G. Filled pattern is saprolite, blank
region is silty clay of the B-horizon.
130
4.3.5
Sand Thickness
The sand thickness data for Fracture G are similar to that of the other fractures.
Overall, sand thickness is greatest in the center of the fracture, and tapers to the edge of
the fracture (Fig. 4.3-5). Sand thickness is highly variable over short distances, similar to
the distributions of the other fractures.
The ratio of sand thickness to uplift is 0.3 to 0.7 (Fig. 4.3-6). The average sand
loading of slurry injected into Fracture G is 0.3. These results are similar to those that
occur at the other fractures.
131
1.0
-60
-40
-20
0
20
40
60
80
100
0.8
120
g-11
0.6
0.4
0.2
0.0
1.0
0.8
g-12
0.6
0.4
0.2
0.0
-60
-40
-20
0
20
1.0
40
60
80
100
120
1.0
0.8
0.8
g-7
0.6
0.6
0.4
0.4
0.2
0.2
0.0
g-8
0.0
40
60
80
100
40
60
80
100
Figure 4.3-4 Cross sections of sand thickness (open circles) and uplift (open
diamonds) for Fracture G. Third-order polynomial fit for sand
thickness (solid line) and uplift (dashed line).
132
1.0
-60
-40
-20
0
20
40
60
80
100
0.8
120
g-11
0.6
0.4
0.2
0.0
1.0
0.8
g-12
0.6
0.4
0.2
0.0
-60
-40
-20
1.0
0.8
0
20
40
60
80
100
120
1.0
0.8
g-7
0.6
g-8
0.6
0.4
0.4
0.2
0.0
0.2
0.0
40
60
80
100
40
60
80
100
Figure 4.3-5 Ratio of regressions (thick line) fitted to sand thickness (thin line) and uplift (dashed line) of Fracture G.
133
4.4
Fracture F
Fracture F had similar exposure control to Fracture G: one long trench adjacent to
the injection casing and along the axis of the fracture, and a shorter trench perpendicular
to the first that extends beyond the edge of the fracture to the east (Fig. 3.4-1). The
placement of spoil piles and fracturing equipment made it impossible to position the
backhoe for additional excavations.
The injection casing for Fracture F was placed into the shallowest exposure of
saprolite seen at the site, at 4.7 ft bgs. Examination of notch cuttings prior to excavation
was the first indication that the casing had been installed into saprolite. Angular quartz
pebbles and kaolinitic balls made up much of the relatively small overall volume of cuttings returned when the notch was cut with the water jet. No notch was detected after
repeated efforts with the notch-measuring tool. It was assumed that whatever notch had
been cut, as represented by the notching returns, had become occluded with dislodged
material.
Although there was a concern of initiating a fracture in what was thought to be a
poor notch, no additional notching activities were performed. It was anticipated that the
breakdown pressure might be significantly higher than that of the other fractures, but it
was only slightly higher, at 60 psi. It did, however, propagate at higher pressures, and
was approximately 50 psi near the end of the injection.
134
4.4.1
Uplift
The uplift pattern produced by Fracture F was more irregular than that of the other
3 fractures, but can be roughly approximated by an ellipse. Uplift extended beyond the
surveying array in all directions except directly north. It was necessary to add control
points to the measured data for SURFER© to create a contour map that resembles what
would be drawn by hand contouring (Fig. 4.4-1, control points not posted). Maximum
uplift of 1 inch was measured in an arc at a 3 ft radial distance from the injection casing
from SE to SW. The orientation of the ellipse characterizing the uplift suggests an E-NE
orientation of the major axis of Fracture F. The magnitudes of uplift over the lateral extent are most closely matched by the 0.5 in contour line, which is approximately twice
that of the averages for the other fractures.
135
250
N
150
100
feet
0.00
0.00
200
0
5
0.10
0.10
0.20
0.20
0.20
0.20
0.06
0.06
0.10
0.10
0.30
0.30
0.16
0.16
50
10
0.55
0.55
0.45
0.45
0.75
0.75
0.39
0.39
0.59
0.59
0
1.00
1.00
1.10
1.10
0.91
0.91
0.39
0.39
-50
0.20
0.20
0.10
0.10
0.55
0.55
1.00
0.75
0.7
-100
0.20
0.20
0.39
0.39
0.5
0.20
0.20
0.3
-150
0.16
0.16
-200
-250
-200
0.1
-150
-100
-50
0
50
100
150
200
250
Figure 4.4-1 Map of uplift over Fracture F. Data are posted (small numbers)
for each uplift stake marked by a “+”. Contour interval is 0.2 inch, contour lines labeled with large numbers.
136
150
feet
100
N
0
5
10
50
0
-50
-100
0.3
-150
0.1
-200
-150
-100
-50
0
50
100
150
200
Figure 4.4-2 Map of uplift contours and the region containing sand (shaded)
of Fracture F and trace of trench faces (solid lines).
137
4.4.2
Lateral Extent
The lateral extent of Fracture F (Fig. 4.4-2) was interpreted in as an ellipse based
on the same approach as applied Fracture G. The orientation of the major axis of the ellipse is roughly east-west, as suggested by the overall pattern of uplift. The aspect ratio
of the ellipse is 1.1:1, with the major axis measuring 16.7 ft, and the minor axis 15 ft.
The portion of the fracture to the west of trench face 13 is interpreted to be much smaller
than what was observed to the east. This was based on the offset of the uplift from the
injection casing (through which trench face 13 nearly passes). The center of the ellipse is
offset approximately 3 ft to the southeast from the injection casing, and coincides with
the southeastern portion of maximum uplift. This represents a borehole eccentricity of
0.18 for Fracture F. The center of the uplift occurs over an area rather than a distinct
point, but the center of the ellipse occurs within this area.
4.4.3
Depth
Fracture F propagated downward within 2 in of the injection casing. The fracture
roughly followed the dip of the saprolite as seen in the cross section exposure (Fig. 4.43). However, the saprolite contact was an irregular surface and it is difficult to predict
the upper surface beyond the cross section.
To the north (on the right side of Fig. 4.4-3), the fracture propagated sharply
(~45°) downward within saprolite where it reached a maximum depth of 90 inches (7.5
ft). The fracture then turned abruptly and propagated upward for roughly 1 ft before ter-
138
minating (Fig. 4.4-3). This pattern occurred on both walls of the axial trench (f-13 and f14).
The fracture trace to the south also shows downward propagation, but here the
fracture curves downward for several feet and then curves back up after growing out of
the saprolite and into the massive silty clay of the B-horizon. The trace continues to
climb until it terminates 120 inches (10 ft) south of the injection casing.
The general pattern of Fracture F resembles that of Fractures I and G in that each
of curves downward in the vicinity of the casing. The shortest parts of Fractures F and I
(the northern end of Fracture F and the southern end of Fracture I) occur where the fractures grew into saprolite and terminated. The longest parts of the three fractures occur on
the side in which the fracture dips less steeply downward away from the injection casing
and “loses” the least elevation.
139
-120
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f-9
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Figure 4.4-3 Cross sections of Fracture F. Filled pattern is saprolite,
blank region is silty clay of the B-horizon.
140
4.4.4
Sand Thickness
Sand thickness reaches a maximum of 1 inch, which is the thickest observed in
any fracture created during this study. This thickness occurs at two locations within the
fracture, one location roughly 1 ft south of the injection casing and another location 3 ft
south of the casing (Fig. 4.4-4). The center of the fracture is roughly 3 ft south of the casing, so the maximum sand thickness occurs roughly at the center of the fracture (Fig. 4.44).
4.4.5
Color Distribution
Colored sand was injected into Fracture F and the distribution of sand colors was
mapped on the transparent cross-sections. The pattern of sand distribution over the entire
fracture could not be determined for Fracture F, as it was for Fracture I, because the necessary exposures were unavailable. However, local patterns of sand distribution could be
determined.
The distribution of red sand was limited to the vicinity of the injection casing.
Red sand spanned the entire thickness of the fracture at several locations near the casing.
At one location, red sand was 0.6 to 0.8 inches thick where the fracture cut coarse mica
and quartz saprolite 1 to 2 ft south of the injection casing (Fig. 4.4-3). Red sand was also
observed in the vicinity of the casing at Fracture I, but the exposure at Fracture F shows
that the red sand can extend over the entire thickness of the fracture and that the thickness
of red sand is probably significantly greater than the aperture of the fracture when the red
sand was injected.
141
Red sand occurs in the northern edge of Fracture F, where that fracture curves
downward and terminates in saprolite a few feet from the injection casing. Similarly, red
sand occurs in Fracture I where it terminates in saprolite a few ft from the injection casing. This suggests that both fractures propagated into the saprolite relatively early in
their growth, but their propagation was arrested and subsequent propagation proceeded in
other directions where the fracture curved upward into silty clay.
Fracture F is longest toward the south, and the leading edge of this part of the
fracture is filled with blue sand. White sand occurs at the leading edge of the eastern part
of the fracture. I infer that the fracture was growing in the direction of its longest dimension at the time propagation was terminated. As a result, the last sand to be injected
(blue) appears to have moved to the edge of the fracture that was propagating. This is
similar to the findings at Fracture I.
Channel-like structures of blue sand embedded in white sand were common in the
exposures of Fracture F. A few of the trench faces were excavated to show that the channel structures were elongate and their axes trended toward the borehole. Detailed mapping of the channel structures was impossible in Fracture F, but the observed patterns are
consistent with those revealed in detail in Fracture I (Fig. 4.1-18 ).
The relationship between channel structures and mechanical lobes of fractures
was evident in the map of Fracture I, where all the channel structures occur between steps
in the fracture surface. Channel structures in Fracture F were only visible in section view
where they typically occur in the wider parts of fractures between steps and cusps in the
fracture walls. It is widely recognized (e.g. Pollard and others, 1976 and 1983) that mechanical lobes of dilational fractures coalesce to produce features that resemble steps and
142
cusps in cross section. As a result, the location of channel structures viewed in cross section in Fracture F is consistent with the location of channels viewed in plan in Fracture I.
Channel structures also occur cusps where Fracture I is exposed in cross section.
The results clearly show that subtle features of hydraulic fractures that are related
to mechanical processes of fracture formation (e.g. mechanical lobes, cusps and steps)
control the location of channel structures in Fracture I. The available exposures of Fracture F support this finding.
143
-120
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0.8
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Figure 4.4-4 Cross sections of sand thickness (open circles) and uplift (open diamonds) for Fracture F. Third-order polynomial
fit for sand thickness (solid line) and uplift (dashed line).
144
-120
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0.0
1.0
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f-10
0.6
0.4
0.2
0.0
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40
60
80
100
120
Figure 4.4-5 Ratio of regressions (thick line) fitted to sand thickness (thin
line) and uplift (dashed line) of Fracture F.
145
5
DISCUSSION
This study documented several new or unexpected aspects of fracture growth and
form. This section examines these observations and offers conceptual models that can
explain them.
5.1
Downward propagation
Fractures created during this work differ significantly from other known hydraulic
fractures in that they propagate downward. The gentle troughs surrounding the injection
casing of Fractures F, G, and I have never been recognized. This form is remarkably
consistent in the three fractures where it occurred, but the form is absent from Fracture H,
which propagated horizontally and upward.
The unusual trough-like form can be explained using principles of linear elastic
fracture mechanics, which have been used to explain other features of hydraulic fractures
in cohesive materials (Murdoch, 1993 a, b, c; Murdoch, 1995; Murdoch, 2002). Two
principles appear to be important: the effect of heterogeneities on the propagation path of
a fracture, and the effect of distance from the heterogeneity. The propagation path of a
fracture will be influenced by heterogeneities in the elastic modulus in the vicinity of the
fracture tip. One type of heterogeneity is where the fracture is embedded in a relatively
stiff material characterized by Efracture, but there is a contact in the vicinity with a softer
material (Efracture >Eheterogeneity). In contrast, another type of heterogeneity is where the
fracture is embedded in soft material and there is a contact in the vicinity with a stiffer
material (Efracture <Eheterogeneity). The stress intensity increases as a fracture approaches the
first type of heterogeneity (Efracture>Eheterogeneity), whereas it decreases as the fracture approaches the other type (Efracture <Eheterogeneity), according to Hanson and Shaffer (1980).
As a result, it follows that a fracture embedded in a stiff material will tend to propagate
toward an interface with a softer material, whereas a fracture embedded in a soft material
will tend to propagate away from an interface with stiffer material. This occurs because
the contrast in modulus causes the stresses and displacements to be asymmetrically distributed about the fracture tip. A free surface, such as the ground surface, behaves like a
contact where there is a huge contrast in modulus (Efracture>>Eheterogeneity), so fractures will
tend to curve toward free surfaces (Pollard and Holzhauzen, 1979).
Hydraulic fractures created during this study were initiated near the interface between the B-horizon and the underlying saprolite. The elastic modulus of the B-horizon
is approximately 5000 psi, but the elastic modulus of the saprolite is unknown. The unit
weight and clay content of the saprolite is less than that of the B-horizon. The saprolite is
more friable and can be penetrated by a split spoon more easily than the B-horizon material. As a result, it seems reasonable to expect that the elastic modulus of the saprolite is
less than that of the B-horizon.
The distance between the fracture tip and heterogeneities plays an important role
in how strongly the heterogeneity affects the propagation path. In general, the critical
distance for the heterogeneity to affect the propagation path is roughly equal to the halflength, or radius of the fracture. Heterogeneities that are beyond this distance have little
effect. As a result, only heterogeneities in close proximity to the fracture will affect the
147
propagation path when the fracture is small, but heterogeneities at increasingly larger distances will become important as the fracture length increases.
The hydraulic fractures created during this study are inferred to have propagated
downward as they curved toward the interface between stiff B-horizon and the softer saprolite. The contact between these materials occurred from zero to a few ft below the incipient fracture, so the principles outlined above imply that downward propagation would
occur when the radial length was roughly a few feet. This is confirmed by cross sections
of Fracture I and G (Fig. 4.1-2,4.3-3). Fracture F curved downward abruptly, but the
notch was embedded in saprolite so the fracture initiated below or very near the contact
in the vicinity of the injection casing.
The ground surface behaves as an interface with an extremely large contrast in
elastic modulus. The ground surface will have little effect on a small fracture, but its effects will become increasingly important when the radial length of the fracture is roughly
equal its depth (Pollard and Holzhausen, 1979). This explains why the axis of the trough,
the lowest part of the fracture, is approximately 5 ft from the injection casing (Fig 4.1-6
and 4.1-7). The fracture started to interact with, and propagate towards the ground surface when the radial length was roughly 5 ft.
Fracture H lacked a trough. It propagated out roughly horizontally and then
curved upward approximately 5 ft from the casing. Saprolite occurred slightly lower below Fracture H than the other fractures, so it appears that the fracture was never affected
by the saprolite. It was affected by the ground surface and curved upward at roughly the
same relative location that the other fractures curved upward.
148
5.2
Effect of leakoff
Leakoff is inferred to have affected the forms of Fractures F and I. Both of those
fractures propagated downward into saprolite early in their growth. The regions of the
fractures that grew into saprolite are filled with red sand and are relatively short, so it
seems that propagation was abruptly arrested when the fracture grew into saprolite. This
affected the fracture form because it caused the fracture to grow preferentially away from
the regions cutting saprolite.
The hydraulic conductivity of saprolite is more than 3 orders of magnitude greater
than the clayey B-horizon. As a result, it seems likely that the liquid phase of the slurry
leaked out of the fracture where it cut across saprolite, but it remained in the fracture
when it cut through B-horizon. The propagation of a hydraulic fracture will cease when
the fluid content of the slurry is low enough that the slurry is no longer mobile. The process where leakoff arrests fracture propagation is called a screen-out (Gidley and others,
1989), and it appears that screen-outs occurred in the fractures created during this research. It is noteworthy, however, to recognize that the screen-out only occurred locally
and it affected the direction of propagation and fracture form, but it by no means completely arrested propagation.
5.3
Conceptual model of sand movement in a hydraulic fracture
The movement of sand within a hydraulic fracture is commonly represented using
a model of radial plug flow; that is, the first sand to be injected migrates toward the leading edge and is followed a plug of sand that is injected later (Daneshy, 1989). Observations made during this research suggest that an alternative conceptual model is required
149
to explain the distribution of sand. The conceptual model must explain these critical observations:
1. The earliest sand to be injected is deposited closest to the injection casing, and the
last sand to be injected is at the edge of the fracture that is active at the termination of pumping.
2. Sand migrates in channel-like structures that cut through relatively immobile sand
injected earlier.
3. The earliest sand to be injected occurs locally in the vicinity of the injection casing where it spans the entire aperture of the fracture. The thickness of the early
sand in these locations is greater than the aperture of the fracture when the early
sand was injected
4. Major channel structures occur near the injection casing but bifurcate into many
channels at the leading edge of the fracture where they produce delta-like structures.
5. Individual channel-delta structures are active for a while and then shut down
when others become active.
6. The locations of individual channels are related to the locations of subtle features,
such as steps and cusps on the fracture surface, that are related to the mechanical
processes of fracture propagation.
7. Leakoff can arrest the local propagation of the fracture, presumably by halting the
progress of a channel-delta structure.
150
A conceptual model that explains these observations is based on the assumption
that sand moves in a channel-like structure that is controlled by the location of features
on the fracture surface (Fig. 5-1). Thus, there is a basic interaction between the mechanical breaking of the fracture and the pattern of slurry that moves within it. Features created during the mechanical breaking of a fracture, such as mechanical lobes, or cusps,
steps, or offsets formed where mechanical lobes coalesce (Pollard, 1973; Pollard and others, 1975; Pollard and others, 1983), appear to preferentially locate channels. In general,
channels occur along the axes of mechanical lobes or in the relatively wide region between cusps (Fig. 5.1-1), which is inferred to be the axis of a lobe prior to coalescence.
Presumably, it is more efficient for the slurry to move away from the borehole
through a single channel and then split into many channels (Fig. 5-1), than it is for slurry
to flow radially away from the casing. The channels are located in positions made favorable by the mechanical fracturing process. The hydraulic head required to move sand
along a single channel-delta feature will increase as the feature lengthens, or as leakoff
increases the effective viscosity of the fluid. Eventually, the hydraulic head required to
move slurry along one of these features exceeds that required to initiate a new one, so the
old feature is abandoned. This interaction between channels is also expected to deactivate and reactivate individual channels during fracture growth.
That simple model will explain many of the observations, but several observations
require a more detailed explanation. Sand apparently can thicken after it is relatively
immobile. This is best illustrated by the red sand that spans the entire thickness of the
fracture near the injection casing where the sand thickness is 2 to 3 times more than what
would be predicted by sand loading of the red-sand slurry. Elsewhere, white sand ap151
pears to have been pushed into the lateral edges of lobes by channels of blue sand. It appears that when a channel-delta feature is abandoned, the sand it contains is still capable
of moving slightly. When a channel cuts through earlier sand, it seems reasonable to expect that the earlier sand retains some mobility and it pushed aside by the advancing
channel. There is no evidence that the channel structures are eroded into earlier material;
for example, particles of wall material were never found mixed with the injected sand,
and there is little evidence that red sand mixed with blue or white sand. This implies that
the earlier sand moves away or is pushed aside in bulk (Fig. 5.1-1). This would cause the
earlier sand to thicken adjacent to a channel. This process could account for the relatively thick deposits of red sand filling the fracture.
The observations of Fracture I can be interpreted based on the conceptual model
outlined above. The map of sand distribution (Fig. 5-1) appears to show at least 4 major
channels that bifurcate into deltas. The first one to be emplaced was filled with white
sand and it cuts red sand to the south of the injection casing (Fig. 5.1-2). The delta structure that was observed in the most detail is filled with blue sand and occurs to the northwest of the injection casing (Fig. 5.1-2). The last channel that was active extends northward from the casing and terminates at the northernmost edge (Fig. 4.1-16; c). The last
major channel is only partly shown on Figure 5.1-2, but it is well represented by the distribution of blue sand (Fig. 4.1-16; c). the four channels identified in figure 5.1-2 are
probably only a fraction of the channels that occurred in Fracture I.
The conceptual model can also be used to develop a qualitative prediction of how
sand might move into an idealized fracture (Fig. 5-3). It is certainly possible that the earliest sand moves by some other mechanism, but the channel-delta model appears to be
152
applicable relatively early. The idealized model shows sand moving through channeldelta structures arranged in roughly a trigonal or hexagonal pattern. One structure is active, becomes obsolete and another structure is formed that transports sand away from the
borehole roughly 120° from the previous one. This pattern occurs three times and then
the next channel, the fourth one, occurs between the first and second one. Additional
channels form between the ones formed previously. Sand from earlier abandoned channels is pushed laterally by new channels to completely fill the fracture (Fig. 5-3).
The result is a fracture that is completely filled with sand, just as it would be if the
sand moved by plug flow. However, the relative ages of the sand in the fracture are
much different than if the plug flow model were applied.
a.
b.
c.
Figure 5.3-1 Sequence of fracture growth. Gross fracture propagation direction perpendicular to figure. (a.) Early fracture
filled entirely with red sand. (b.) Fracture walls dilate during
growth and white sand displaces red sand toward cusp
formed by coalesced lobes. (c.) Fracture walls continue to
open and early sand fills cusp area. Thickness of red sand in
cusp is greater than fracture aperture when red sand was injected
153
5
4
3
2
1 ft
1
1m
Covered
Overburden
Step on fracture surface.
Dots on downthrown side
Red Sand
Contact inferred
White Sand
Limit of red sand
Blue Sand
Trenched
Injection casing
area
Approx. extend of fracture
Strip of blue sand on frx surface
Trench
Injectionface
casing
Figure 5.3-2 Map of the distribution of sand in Fracture I.
154
3 Conceptual model of sand transportation in a hydraulic fracture.
Figure 5.3-1
Shading shows temporal distribution (darkens with increasing age) of
sand as it travels from the injection casing, through a channel feature, and
fans out at its end
155
6
CONCLUSIONS
The observations made during this investigation show that shallow hydraulic fractures are flat-lying to gently dipping features that are elliptical in plan and slightly asymmetric with respect to the injection casing. The major axis of the ellipses characterizing
the fractures ranged from 15 to 23 ft, whereas the minor axes ranged between 12 and 17
feet. The areas of the fractures range from approximately 45 to 65 ft2.
The degree of
elongation is characterized by aspect ratios that range from 1.1:1 to 1.4:1, with an average value of 1.2:1. For comparison, the aspect ratios of nearly 100 fractures created in a
variety of settings ranges from 1.0:1 to 1.4:1 and the average value is 1.2:1 (Murdoch and
Slack, 2002). Fractures created for this research were flat-lying to wavy near the borehole, but away from the borehole they dipped between 10o and 20o. Average dips of the
fractures reported by Murdoch and Slack (2002) range from a few degrees to 22o at different sites, but they typically vary by less than 10o at any one site. These findings suggest that the gross form and dimensions of hydraulic fractures created in B-horizon and
saprolite for this investigation are similar to shallow hydraulic fractures created in other
geologic settings.
Uplift measurements at the ground surface were able to be used to predict fracture
shape, orientation, and extent in plan view, as well as the average sand thickness of the
fractures in cross section. The uplift patterns resemble elliptical domes, with the center
offset in the same direction and nearly the same distance as the center of the fracture from
the injection casing. The location of the maximum uplift relative to the injection casing
appears to be a reliable indicator of preferred fracture propagation. The shape of the uplift pattern also seems to be a good indication of general distribution of sand.
The pattern of uplift extended beyond the region containing sand. The amount of
uplift above the edges of the fractures varied from 0.1 to 0.7 inch. Commonly, the limit
of sand closely coincided with contours of uplift of between 0.3 to 0.5 inch.
The asymmetry can be characterized by the eccentricities of the maximum uplift
and injection casing with respect to the center of an ellipse fit to the uplift pattern (Murdoch and Slack, 2002). The displacement eccentricity ranges from 0.12 to 0.27and the
average value is 0.18. For comparison, the displacement eccentricity of the fractures
summarized by Murdoch and Slack range up to 0.34 and the average value is 0.14. The
borehole eccentricity ranges from 0.12 to 0.21 and the average value is 0.17 for the fractures created during this investigation, whereas it ranges up to 0.32 and the average value
is 0.14 for the fractures summarized by Murdoch and Slack. In general, the fractures created for this work are slightly more asymmetric than the ones summarized by Murdoch
and Slack, based on the average values. The differences in asymmetry are remarkably
small, however.
The magnitudes and distributions of sand thickness were remarkably similar
among the four fractures included in this study. Overall, the highest values were measured near the center of the fracture, whereas the lowest values were near the edges of the
fracture. The transition from high values in the center to low values at the edge is highly
variable, with changes in sand thickness occurring over scales of inches to ft. Sand
thickness varies by as much as +/- half of the local average over distances of only a few
inches. This is significant because it suggests that the thickness of sand in a fracture in157
tersected by a core sample could vary markedly over short distances. It is probably impossible to accurately determine the effective thickness of a hydraulic fracture from the
thickness of sand in one, or several core samples.
In some cases, local variations in sand thickness could be correlated between
trench faces. This showed that sand thickness can vary as features that span several ft or
more. Bands of anomalously thick, or anomalously thin sand were observed radiating
from the borehole.
The effective transmissivity of a hydraulic fracture will play an important role in
how the fracture affects well performance. Determining the effective transmissivity of a
heterogeneous layer requires establishing relative weightings of the different zones of
transmissivity in the layer. Continuous bands of high transmissivity will dominate calculations of effective transmissivity, particularly where the bands intersect a borehole. As a
result, it seems reasonable that the effective transmissivity of hydraulic fractures examined during this research will be preferentially weighted to values obtained from the
thicker regions of the fracture.
Plug flow models of sand transport (Daneshy, 1989) are unable to account for observations of the fractures in this study. A new model is put forth where sand moves
through a hydraulic fracture as a narrow band, or channel, that extends from the injection
casing and spreads laterally to form a delta-like feature as it approaches the leading edge.
A channel and delta fill the fracture in one direction until the hydraulic head required exceeds the head needed to initiate a new channel in another direction. The existing channel becomes dormant and a new one is activated in another direction. This process is repeated many times to fill a fracture that grows radially from a borehole.
158
There appears to be a strong interaction between the processes that form a fracture
and those by which it is filled with fluid. The growth and coalescence of fracture lobes to
form a continuous fracture whose surface is marked by steps, ridges and cusps is recognized as a common process in the development of many dilational fractures, including
hydraulic fractures. This work shows that the fluids filling hydraulic fractures preferentially follow the mechanical lobes, and the wide areas resulting from lobe coalescence.
Fluid that is temporarily immobilized when a channel is abandoned appears to be forced
laterally into the narrow edges of the crack when a new channel becomes active in the
vicinity.
The distribution of fluid pressure within the fracture is expected to play a fundamental role in the development and coalescence of lobes and other processes of propagation. Patterns of fluid pressure in a fracture are expected to be related to the patterns of
channels that are sequentially active during the life of the fracture. This implies that there
is a strong coupling between the mechanical breaking of a hydraulic fracture and the fluid
flow within it; both processes will have an important effect on the other and the details of
this interaction at the field scale are more complicated than previously recognized.
159
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