CLASS I FRACTURE SLURRY INJECTION
A Summary of the Technology
and Recommendation for Implementation
USEPA National Underground Injection Control
Technical Work Group
Report No. 1
by
Joe Kordzi
USEPA Region 6
February 26, 1998

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I. BACKGROUND
For many years, the petroleum industry has successfully disposed
of drill cuttings through a process known as fracture slurry
injection (FSI). In its basic form, this process consists of
grinding the drill cuttings to a relatively fine consistency,
mixing the cuttings with water and/or other liquids to form a
slurry, and disposing of the slurry by pumping it down a well at
a high enough pressure that fractures are created within the
target formation. The injected slurry is then emplaced in the
fractures created by the force of injection. Recent work in this
area has focused on extending this technology to the disposal of
contaminated soils and other solid material associated with
Superfund sites. If the injected waste is classified as a
hazardous waste, an FSI well may be categorized as a Class I
hazardous waste However, regarding Class I hazardous waste
wells, 40 CFR §146.67(a)states:
"Except during stimulation, the owner or operator shall
assure that injection pressure at the wellhead does not
exceed a maximum which shall be calculated so as to
assure that the pressure in the injection zone during
injection does not initiate new fractures or propagate
existing fractures in the injection zone. The owner or
operator shall assure that the injection pressure does
not initiate fractures or propagate existing fractures
in the confining zone, nor cause the movement of
injection or formation fluids into a USDW."
Here, well stimulation is defined according to 40 CFR §146.3 as
"... several processes used to clean the well bore, enlarge
channels, and increase pore space in the interval to be injected
thus making it possible for wastewater to move more readily into
the formation, and includes (1) surging, (2) jetting, (3)
blasting, (4) acidizing, (5) hydraulic fracturing."
A similar restriction also applies to Class I non-hazardous waste
injection wells under 40 CFR 146.13 (a) (1). Consequently, the
FSI of waste would require that either the well be categorized as
other than a Class I well, or that 40 CFR Part 146 be revised.
This issue paper contemplates the latter case.
II. TECHNICAL CONSIDERATIONS
A. Summary of Basic Theory
An understanding of fracture mechanics can be facilitated by
first defining a coordinate system, consisting of x, y, and
z axes, which are mutually orthogonal, with the z-axis

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oriented in the vertical direction. At depths over
approximately 3,000 feet, due to the weight of the
overburden, the maximum principal stress is usually oriented
along the z-axis, and the intermediate and least principal
stresses are oriented along the x and y axes. Due to the
fact that fractures propagate perpendicular to the least
principal stress direction, a vertical fracture will
propagate in the above described environment. Figures 1 and
2 depict this situation, with the fracture idealized as a
single-planar fracture. As the depth to the target
formation decreases, the stress due to the weight of the
overburden also decreases, and the principal stress
direction will deviate from the vertical direction.
Eventually with continued decreasing depth, the principal
stress direction will re-align itself in the horizontal x-y
plane. Consequently, as the depth to the target formation
decreases, induced fractures will change from being vertical
to horizontal in orientation.
B. Concept of Disposal Domain
There is a great deal of information that leads to the
conclusion that, except for short term single-event
injection episodes, long term FSI does not result in the
propagation of classical single-planar fractures. Rather,
due to the repeated injection episodes, and the relatively
high volumes often injected, a "disposal zone", which can be
visualized as consisting of an array of branched fractures
with possibly some rock disaggregation, evolves from the
single-planar fracture. This situation, depicted in Figure
3, develops due to the tip of the fracture becoming clogged
with injected solids to the point where it becomes easier
for the fracture to continue as a branch off of the main
fracture. Initially in the formation of this disposal zone,
the branched fractures will tend to re-align themselves
parallel to the main fracture. However, repeated injection
episodes can alter the stress field within the disposal
domain to the point at which the direction of the least
principal stress re-equilibrates. Consequently, in the case
of vertical fractures, this will cause the azimuth of newly
propagating fractures to change. In theory, with continued
injection, it is possible that the least principal stress
field can even become vertical, which would cause fractures
to propagate horizontally. This would be desirable, due to
the elimination of vertical containment concerns.
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C. Vertical Containment of the Injected Waste
Regarding vertical fractures, propagation will initially
occur almost equally in the vertical and lateral directions.
This process will continue until either (1) a stress barrier
is encountered, a (2) "bleed-off" zone is encountered, (3)
hydraulic horsepower limitations prevent continuance, or (4)
the fracture "rolls over" due to re-equilibrium of the
stress field. Because horizontal fractures propagate
parallel to the ground surface, the issue of their vertical
containment, except possibly in the instance of steeply
dipping beds, is moot.
A typical stress barrier, mentioned in (1) above, consists
of a relatively thick shale with a minimum horizontal stress
significantly greater than that of the injection interval.
Employing the coordinate system defined above, the fracture
would, upon reaching a stress barrier, begin to expend most
of its energy by propagating laterally. As wellbore
pressure is increased to compensate for the increasing
frictional pressure losses in the system, or due to the
fracture tip becoming clogged, the fracture will extend
itself farther and farther, on the order of a few feet, into
the stress barrier.
The bleed-off zone mentioned in (2), above, is defined here
as an interval with horizontal permeabilities significantly
greater than those of the injection interval. Upon reaching
such a higher permeability interval, the vertical and
possibly lateral progress of the fracture may be suspended
due to pressure bleed-off into the more permeable zone.
With continued injection, filter cake buildup at the edge of
the fracture that intersects the bleed-off zone may
effectively shut off flow into that zone and allow
additional lateral propagation of the fracture. This cycle
may be continually repeated if the fracture continues to
propagate laterally and the fracture continues to cut into
fresh portions of the overlying bleed-off zone.
Regarding (3) above, in order to continue to extend a
fracture, the pump engines must possess sufficient power to
maintain a fracture tip pressure above the fracture
propagation pressure. Consequently, the pump engines must
have enough horsepower to overcome the energy losses of the
system through frictional pressure drops in the tubulars and
in the fracture, pressure losses due to leakoff into the
surrounding formation matrix, and still supply the required
energy to the system. This can impose a practical
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limitation on the vertical and lateral extension of
hydraulic fractures.
Regarding (4) above, if neither barriers nor pump power
requirements limit the vertical propagation of the fracture,
at some point it will begin to roll over to the horizontal.
This is because, due to the decreasing weight of the
overburden experienced by the fracture as it propagates
vertically, the maximum principal stress will at some point
begin to deviate from acting downward along the z-axis. It
will then become easier for the fracture to begin lifting
the layers of rock than parting those layers.
Lastly, it should be noted that properly configured
monitoring systems, as discussed in the next section, are
capable of monitoring the height of the induced fracture.
This provides the operator with an important control,
allowing, in the case of real time monitoring, the shutdown
of the system if the fracture begins to grow into an
undesirable area.
D. Determination of the Height, Length, and Azimuth of Induced
Fractures
The primary reason for the fracture prohibition clause in
the Class I regulations was the uncertainty associated with
the height of induced fractures, and the resulting concern
of contaminating a USDW, or the land surface. Recently,
technology has been developed that is capable of real time
monitoring of the height, length, and azimuth of an induced
fracture during injection operations. This technology was
not available when the Class I regulations were promulgated.
In addition, there is a great deal of information available
(i.e., modeling studies, field data, etc.) that demonstrates
that the height of the fracture can be confidently
predicted, as well as controlled, based on the geological
and mechanical properties of the receiving and overlying
formations, the injection rate, and the hydraulic properties
of the injectate.
There are currently two main methods through which the
height, length and the azimuth (in the case of a vertical
fracture) , of an induced fracture may be monitored. These
involve the use of tiltmeters and/or subsurface
microseismic monitoring equipment.
Subsurface microseismic monitoring involves the downhole
installation of geophones or accelerometers in offset wells,
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and/or the injection well itself, and the associated surface
equipment used to process and store the data. This system
depends on the ability of the equipment to triangulate the
location of the fracture, through the analysis of the
intercepted microseismic events. The accuracy of this
system depends on the number of geophones or accelerometers
installed, and the spatial location of this equipment
relative to the loci of the particular microseismic events
of interest. The advantage of subsurface microseismic
monitoring is the ability of the system to monitor fracture
geometry in real time. This affords a great deal of control
over the operation. Although the operator cannot "steer"
the fracture as it propagates, being able to monitor its
height, length, and azimuth enables the cessation of
operations in the event the fracture begins to propagate to
an undesirable area. The main disadvantage of microseismic
monitoring is the relatively high cost associated with the
installation of the deep monitoring wells, which must be
completed into the same interval as the injection well.
Tiltmeters are high resolution, angular displacement sensors
that are usually arranged in one or more circular or
elliptical arrays, usually within near-surface boreholes,
surrounding the injection well. They measure the surface
deformation field that results from the creation of
fractures. The fracture geometry is then inferred from a
geophysical analysis of this data, through a mathematical
inversion - in effect, an automated procedure in which a
large number of fracture geometries are successively
compared to the data to obtain a best fit. Unlike
subsurface microseismic monitoring, tiltmeter technology is
not capable of monitoring fracture geometry in real time.
However, tiltmeter data can be analyzed and interpreted very
quickly. The main advantage of the use of surface
tiltmeters is the relatively low cost of the system,
compared to deep subsurface microseismic monitoring.
Disadvantages include (1) the sensitivity of the equipment
to noise, and weather conditions such as heavy rainfall, and
(2) that surface tiltmeters are usually not accurate at
inferring geometries of fractures that propagate at depths
below approximately 5,000 feet, a limitation not applicable
to subsurface microseismic monitoring. In addition, surface
tiltmeter techniques are considered inferior to subsurface
microseismic monitoring from both an accuracy and precision
standpoint.
Recently, tiltmeters have been successfully deployed in deep
monitoring wells, installed as vertical arrays in much the
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same configuration as the deep microseismic monitoring
equipment discussed above. These "inclinometer" arrays
overcome some of the limitations of surface deployed
tiltmeters, such as sensitivity to noise, and because they
are deployed in deep monitoring wells completed in the
injection interval, they are not depth limited. In
addition, inclinometer arrays are capable of "near real
time" monitoring of the height, length, and azimuth of the
propagating fracture. This can be accomplished in an
automated mode by periodically analyzing the accumulated
data, which similar to microseismic data is acquired in real
time, in the same manner as described above for surface
tiltmeters. In addition, inclinometer arrays can be
deployed in the same monitoring wells as the microseismic
arrays, providing an independent assessment of fracture
geometry.
Following injection, the height of the fracture can be
determined from various types of logs including temperature
logging, and, if the injectate has been tagged by a
radioactive isotope, through gamma ray logging. If the
depth of the fracture is shallow enough to enable the use of
surface tiltmeters, or if downhole inclinometers have been
employed, the resultant, effectively permanent, change in
the surface displacement can be measured through the use of
precision leveling techniques, and the geometry of the
fracture inferred. Other than these techniques, there is no
known reliable non-intrusive procedure for measuring the
length and azimuth of an induced fracture following the
cessation of injection.
E. Presence of Wellbores and Subsurface Discontinuities
Knowledge of the location of wellbores, faults, natural
fracture systems, and other possible subsurface
discontinuities must be a critical part of the site
evaluation for FSI. This is perhaps best illustrated by the
March 17, 1997 incident on the Alaskan North Slope, in which
approximately 18,000 barrels of water broached to the
surface as a result of an FSI operation. The liquid phase
of the injection is theorized to have intercepted production
wellbores and utilized the pathway existing between the
outside of the casing and the formation as a means to travel
upward to the surface. The suspected intercepted wells are
production wells completed in much deeper horizons. These
wells are cemented across and immediately above the
production horizons. However, these wells are typically not
cemented at the elevation of the FSI operation. The
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operation has since been shut down and negotiations are on-
going with the UIC Primacy State Agency, as of the date of
this issue paper, for relocating the FSI operation to an
area free of wellbores.
It is also possible that a fault plane, or some other
geologic subsurface discontinuity could serve to transmit
the fluid phase of the injectate across containment strata
and to the surface. Consequently, it is recommended that
(1) a thorough geologic study of the area be completed, (2)
a thorough information search in the study area be performed
so that all wellbores can be located, and (3) a large margin
of error be included in any pre-injection prediction of the
disposal domain dimensions.
III. DISCUSSION
A. Advantages of FSI over Conventional Waste Disposal Options
The deep injection of waste is the only disposal option that
effectively removes waste from the biosphere. All other
forms of disposal place the waste either into the air;
landfills which are located above the water table; or rivers
and streams that serve as recreation facilities, fish and
wildlife habitats, sources of food, drinking water sources,
or that recharge drinking water aquifers. Because injecting
solids-laden fluids into the pore spaces of most rock would
quickly plug it, without fracturing the rock to create the
necessary void spaces, the injection of waste has been
limited to fluids with a very low solids content. FSI
technology has the capability of extending the benefits of
deep well injection to any solid waste that can be crushed
or ground to a fine enough consistency and mixed with water
and/or another fluid to create a slurry. An obvious
application of this technology is the remediation of RCRA or
Superfund sites. It is projected that FSI would compare
favorably to other disposal technologies, such as
incineration, in the areas of economics, time, and public
relations. In addition, with FSI, disposal is complete.
There is no residual waste product that must be disposed,
such as blow down salts from incineration air scrubbers.
Lastly, surface reclamation can be total, in comparison with
the common Superfund remediation strategy of collecting and
capping the waste onsite, which may require perpetual
monitoring and/or maintenance.
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B. Potential Uncertainties and Limitations of FSI
Although fracturing formations for the purpose of
stimulating oil production is a mature technology, portions
of FSI, particularly the monitoring aspect, are relatively
new technologies, having benefitted from advances in the
last few years. As such, there are some risks to the Agency
in advocating, through the revision of the Class I
regulations, this technology as a waste disposal option.
Should a failure in an FSI operation occur, it would be
manifested as injected waste leaving the injection zone and
being transported toward the surface. There are only two
possible ways in which this could occur. The first case
would be if the injected waste came into contact with a
wellbore, or a subsurface discontinuity such as a fault.
The second case being if an induced fracture propagated
through the confining zone or to the surface. Prevention of
the first case depends largely on the confidence in the
geologic review of the site, and in the confidence that all
wellbores or other possible discharge points have been
located. Regarding the second case, fracture propagation
theory concludes that a vertically propagating fracture will
roll over when the fracture becomes shallow enough that the
least principal stress direction becomes vertical. Having
stated this, an account has emerged of an induced fracture
reaching the surface. However, attempts to verify this
incident have been unsuccessful as of the writing of this
document. For reasons previously discussed, it is unlikely
that a deep injection well could propagate a fracture to the
surface. In addition, properly configured real time
monitoring can prevent fracturing out of the injection zone
by instantly notifying the operator of any vertical
propagation out of the injection interval.
FSI is not suitable for all geologic environments and/or
sites. Principally in the offshore petroleum industry, FSI
has been successfully performed using relatively impermeable
injection intervals (i.e., shales), in conjunction with
relatively higher permeability barriers as bleed off zones
(i.e., sands) serving to check the vertical extent of
fracture propagation. However, considering land-based
applications of FSI for the disposal of hazardous waste,
there are a number of reasons why the injection interval
should consist of a relatively low stress, moderate to high
permeability sand, in conjunction with relatively lower
permeability, higher stress shales, to check the vertical
extent of fracture propagation. These reasons include:
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1.	Injection into relatively higher permeability zones,
such as sands, favors the production of shorter, more
compact fractures, which concentrate the waste near the
wellbore.
2.	Injection into relatively higher permeability zones,
results in lower pressure buildup in the reservoir from
the fluid portion (bleed-off) of the injectate.
3.	The lower permeability of the stress barrier shales
allows them to serve as effective confining zones,
preventing the permeation of the liquid portion of the
injectate into adjacent formations.
IV. RECOMMENDATIONS
FSI has the potential to positively impact the cleanup of many
RCRA and Superfund sites as well as other facilities needing to
dispose of non-hazardous industrial and/or domestic waste.
However, because of the fracture prohibition statement in the
Class I injection well regulations, 40 CFR 146.13 (a)(1) and 40
CFR §146.67(a), this technology is effectively prevented from
being implemented. The UIC Technical Workgroup believes that the
potential environmental benefits of FSI for specific injection
sites may justify the revision of the Class I UIC regulations in
order to implement FSI practices. Sufficient operational and
monitoring controls can be placed on the use of this technology
to ensure that the injected waste remains within the injection
zone, and consequently does not contaminate a USDW. Due to the
additional siting and monitoring requirements that are believed
necessary, a simple revision to §146.67(a) is not considered
adequate. Consequently, it is recommended that a separate
subpart to 40 CFR Part 146 be created. Since Subpart H is the
next available letter in the series, it should be assigned to FSI
wells. Subpart H, although proposed to be exclusive to FSI
wells, would carry over much of Subpart G, with minor
modifications:
§146.62 Minimum criteria for siting.
§146.65 Construction requirements.
§146.66 Logging, sampling, and testing prior to new well
operation.
§146.67 Operating requirements.
§146.69 Reporting requirements.
§146.70 Information to be evaluated by the Director.
§146.71 Closure.
§146.72 Post-closure care.
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§146.73 Financial responsibility for post-closure care.
The remainder of Subpart G, would be carried over with heavy
modifications:
§146.61 Applicability
§146.63 Area of review.
§146.64 Corrective action for wells in the area of review.
§146.68 Testing and monitoring requirements.
Of these, §146.63 and §146.64, which mainly discuss the size of
the Area of Review (AOR) and the plugging of wells contained
within the AOR, would not be appropriate for FSI. In the place
of these sections, it is proposed that the AOR be defined based
on a modeled prediction of the area of the disposal domain, with
the addition of a safety factor. This prediction would be made
based on a consideration of the geology of the injection
interval, and the use of a fracture prediction model acceptable
to the Agency. §146.68 would be modified to include the addition
of microseismic and/or surface tiltmeter monitoring, with a
provision to consider new technology, should it become available.
In addition, it is proposed that the degree to which this
monitoring be required depend on the geology of the injection
interval and overlying sediments, the volume of waste injected,
and the presence of wellbores or other subsurface
discontinuities. Additional sections may need to be created in
order that additional controls may be instituted to account for
the uniqueness of FSI technology. Any regulatory changes should
allow for further development of the technology rather than
restricting it by requiring it to adhere to the current
prediction and monitoring framework. This paper does not
recommend any changes to the existing requirements under Part
148, which remain in effect due to the Land Disposal Restrictions
under the 1984 Hazardous and Solid Waste Amendments to RCRA.
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GENERAL REFERENCES
1.	Charbeneau, R. J., Ogintz, J., and Aubert, W. G., "Fate of
Waste Petroleum Sludge After Deep Well Injection." Paper SPE
28347, presented at the SPE 69th Annual Technical Conference
and Exhibition, New Orleans, September 25-28, 1994.
2.	Moschovidis, Z. A., Gardner, D. C., Sund, G. V., and Veatch
Jr., R. W., "Disposal of Oily Cuttings by Downhole Periodic
Fracturing Injections in Valhall-North Sea: A Case Study and
Modeling Concepts." Paper SPE/IADC 25757 presented at the
1993 SPE/IADC Drilling Conference, Amsterdam, February 23-
25.
3.	Soliman, M. Y., Hunt, J. L., Azari, M., "Fracturing
Horizontal Wells in Gas Reservoirs." Paper SPE 35260,
presented at the 1996 Mid-Continent Gas Symposium, Amarillo,
Texas, April 28-30.
4.	Wright, C. A. et al, "Reorientation of Propped Refracture
Treatments in the Lost Hills Field." Paper SPE 27896
presented at the Western Regional Meeting, Long Beach, CA,
March 23-25, 1994.
5.	Warpinski, N. R., "Hydraulic Fracture Diagnostics," JPT,
(October 1996) 907-910.
6.	Perkins, T. K., "Disposal of Waste Solids in Hydraulic
Fractures." Paper presented at the SPE/International Assoc.
of Computer Methods and Advance in Geomechanics, Morgantown,
WV, May 23-28, 1994.
7.	Wilson, S. M., Rylance, M., and Last, N. C., "Fracture
Mechanics Issues Relating to Cuttings Re-injection at
Shallow Depth." Paper SPE/IADC 25756 presented at the 1993
SPE/IADC Drilling Conference, Amsterdam, February 23-25.
8.	Peterson, R. E. et al, "Fracture Diagnostics Research at the
GRI/DOE Multi-Site Project: Overview of the Concepts and
Results." Paper SPE 36449 presented at the 1996 SPE Annual
Technical Conference and Exhibition held in Denver, CO,
October 6-9.
9.	Vinegar, H. J. et al, "Active and Passive Seismic Imaging of
a Hydraulic Fracture in Diatomite." Paper SPE 22756
presented at the SPE 66th Annual Technical Conference and
Exhibition, Dallas, October 6-9, 1991.
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10.	Branagan, P. T., Petersen, R.E., Warpinski, N. R., and
Wright, T. B., "Characterization of a Remotely Intersected
Set of Hydraulic Fractures: Results of Intersection Well 1-
B, GRI/DOE Multi-Site Project." Paper SPE 36452 presented
at the 1996 SPE Annual Technical Conference and Exhibition
held in Denver, CO, October 6-9.
11.	Keck, R. G., and Withers, R. J., "A Field Demonstration of
Hydraulic Fracturing for Solids Waste Injection With-Real
Time Passive Seismic Monitoring." Paper SPE 28495,
presented at the SPE 69th Annual Technical Conference and
Exhibition, New Orleans, September 25-28, 1994.
12.	Brady, J. L., Withers, R. J., Fairbanks, T. D., and Dressen,
D., "Microseismic Monitoring of Hydraulic Fractures in
Prudhoe Bay." Paper SPE 28553 presented at the SPE 69th
Annual Technical Conference and Exhibition, New Orleans,
September 25-28, 1994.
13.	Bruno, M. S., Bilak, R. A., Dusseault, M. B., and
Rothenburg, L., "Economic Disposal of Solid Oil Field Wastes
Through Slurry Fracture Injection." Paper SPE 29646
presented at the SPE Western Regional Meeting, Bakersfield,
CA, March 8-10, 1995.
14.	Minton, R. C., and Secoy, B., "Annular Reinjection of
Drilling Wastes." Paper SPE 25042 presented at the 1992 SPE
European Petroleum Conference, Cannes, November 16-18.
15.	Louviere, R. J., and Reddoch, J. A., "Onsite Disposal of
Rig-Generated Waste Via Slurrification and Annular
Injection." Paper SPE/IADC 25755 presented at the 1993
SPE/IADC Drilling Conference, Amsterdam, February 23-25.
16.	Malachosky, E., Shannon, B. E., and Jackson, J. E.,
"Offshore Disposal of Oil-Based Drilling Fluid Waste: An
Environmentally Acceptable Solution." Paper SPE 23373
presented at the First International Conference on Health,
Safety, and Environment, The Hague, November 10-14, 1991.
17.	Abou-Sayed, A. S., Andrews, D. E., and Buhidma, I., M.,
"Evaluation of Oily Waste Injection Below the Permafrost in
Prudhoe Bay Field." Paper SPE 18757 presented at the SPE
California Regional Meeting, Bakersfield, CA, April 5-7,
1989.
18.	Hubbert, M. K., and Willis, D. G., "Mechanics of Hydraulic
Fracturing," Trans., AIME (1957), vol. 210, pp 153-166.
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FIGURE 1
IDEALIZED SINGLE PLANAR FRACTURE
PLAN VIEW
FRACTURE
INJECTION "WELL
PERFORATIONS
SHALE
SAND
SHALE
CROSSECTIONAL VIEW
i
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FIGURE 2
IDEALIZED SINGLE PLANAR FRACTURE
THREE DIMENSIONAL VIEW
INJECTION WELL
FRACTUKE
SAND
Y
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FIGURE 3
SINGLE PLANAR FRACTURE EVOLUTION
INTO DISPOSAL DOMAIN
PLAN VIEW
STAGE 1
STAGE 2
¦DISPOSAL DOMAIN"
STAGE 3
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