U.S. patent application number 13/152150 was filed with the patent office on 2012-01-05 for viscosity differential fracturing for enhanced application of amendments to ground and groundwater.
Invention is credited to Steven C. Chen, John J. Liskowitz, Michael J. Liskowitz.
Application Number | 20120000662 13/152150 |
Document ID | / |
Family ID | 45398819 |
Filed Date | 2012-01-05 |
United States Patent
Application |
20120000662 |
Kind Code |
A1 |
Liskowitz; Michael J. ; et
al. |
January 5, 2012 |
VISCOSITY DIFFERENTIAL FRACTURING FOR ENHANCED APPLICATION OF
AMENDMENTS TO GROUND AND GROUNDWATER
Abstract
Viscosity Differential Fracturing uses pneumatic and hydraulic
fracturing techniques and a viscosity differential to achieve
greater networking, higher amendment loading rates and more
controlled propagation. Pneumatic fracturing is applied first in
order to create a dense network of small fractures. This is
followed by a hydraulic component using a viscosity adjusted fluid.
This material can be injected into these fractures at a significant
flow rate and extend/expand these fractures while filling them with
the fluid. The significant advantage of VDF versus traditional
hydraulic fracturing is that the density of fractures created by
the initial gas process leads to an overall greater density of
fractures emplaced within the subsurface coupled with the ability
to emplace a greater mass of material (e.g. proppants, sand,
reactants).
Inventors: |
Liskowitz; Michael J.;
(Hillsborough, NJ) ; Chen; Steven C.; (Berkeley,
CA) ; Liskowitz; John J.; (Sea Girt, NJ) |
Family ID: |
45398819 |
Appl. No.: |
13/152150 |
Filed: |
June 2, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61350907 |
Jun 2, 2010 |
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Current U.S.
Class: |
166/308.1 ;
166/177.5 |
Current CPC
Class: |
E21B 43/26 20130101 |
Class at
Publication: |
166/308.1 ;
166/177.5 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A system for viscosity differential fracturing of ground
comprising: a pneumatic fracturing component; a hydraulic injection
component, including a mixture of water and a suspending or
thickening agent at a concentration between about 1 and about 50
mg/L, and a non-reactive or reactive material at a concentration
between about 0.1 and 30 pounds per gallon; and downhole injection
tooling.
2. The system of claim 1, wherein the pneumatic fracturing
component includes a high-pressure/high-flow module, an injection
control manifold module, a digital flowmeter module, a pressure
monitoring module, and a transducer/data-logger monitoring
module.
3. The system of claim 1, wherein the hydraulic injection component
includes a mobile mixing and injection plant further comprising a
re-circulation batch tank with a load-cell weighing module, an
automated dry material hopper/feed screw module, a progressive
cavity pump, a digital flowmeter module, a pressure monitoring
module, and a transducer/data-logger monitoring module.
4. The system of claim 1, wherein the suspending or thickening
agent comprises guar.
5. The system of claim 1, wherein the non-reactive or reactive
material comprises an about 1% to about 80% solids mixture.
6. The system of claim 1, wherein the downhole injection tooling
includes an injection assembly further comprising a plurality of
pneumatic packers and a pipe including a plurality of slots.
7. The system of claim 1, wherein the downhole injection tooling
includes an injection assembly further comprising a nozzle
including a plurality of openings.
8. The system of claim 1, wherein the downhole injection tooling
includes an injection assembly further comprising a spring-loaded
nozzle.
9. The system of claim 1, wherein the system creates a dense
fracture network with a radius of influence of at least about 12
feet and with at least about 2 orders of magnitude increase in
subsurface flow rates.
10. A system for viscosity differential fracturing of ground
comprising: a pneumatic fracturing component, including a
high-pressure/high-flow module, an injection control manifold
module, a digital flowmeter module, a pressure monitoring module,
and a transducer/data-logger monitoring module; a hydraulic
injection component, including a mobile mixing and injection plant
further comprising a re-circulation batch tank with a load-cell
weighing module, an automated dry material hopper/feed screw
module, a progressive cavity pump, a digital flowmeter module, a
pressure monitoring module, and a transducer/data-logger monitoring
module; and downhole injection tooling, including an injection
assembly further comprising a plurality of pneumatic packers and a
pipe including a plurality of slots, wherein the system creates a
dense fracture network with a radius of influence of about 12 to 15
feet and with about 2 to about 3 order of magnitude increase in
subsurface flow rates.
11. A system for viscosity differential fracturing of ground
comprising: a pneumatic fracturing component, including a
high-pressure/high-flow module, an injection control manifold
module, a digital flowmeter module, a pressure monitoring module,
and a transducer/data-logger monitoring module; a hydraulic
injection component, including a mobile mixing and injection plant
further comprising a re-circulation batch tank with a load-cell
weighing module, an automated dry material hopper/feed screw
module, a progressive cavity pump, a digital flowmeter module, a
pressure monitoring module, and a transducer/data-logger monitoring
module; and downhole injection tooling, including an injection
assembly further comprising a spring-loaded nozzle, wherein the
system creates a dense fracture network with a radius of influence
of about 12 to 15 feet and with about 2 to about 3 order of
magnitude increase in subsurface flow rates.
12. A method of using a system for viscosity differential
fracturing of ground comprising the steps of: pneumatic fracturing
for about 5 to about 15 seconds using a low-viscosity fluid; and
hydraulic fracturing using a fluid of greater viscosity than the
low-viscosity fluid.
13. The method of claim 12, wherein the pneumatic fracturing step
comprises the use of gas.
14. The method of claim 13, wherein the pneumatic fracturing step
comprises the use of nitrogen gas.
15. The method of claim 14, wherein the initial nitrogen gas
pressure is between about 350 to about 405 pounds per square
inch.
16. The method of claim 14, wherein the maintenance nitrogen gas
pressure is at least about 50 pounds per square inch, but not more
than about 500 per square inch.
17. The method of claim 16, wherein the maintenance nitrogen gas
pressure is between about 200 to about 370 pounds per square
inch.
18. The method of claim 14, wherein the initial nitrogen gas flow
rate is at least about 250 standard cubic feet per minute, but not
more than 2,400 standard cubic feet per minute.
19. The method of claim 18, wherein the initial nitrogen gas flow
rate is between about 1,500 to about 2,400 standard cubic feet per
minute.
20. The method of claim 12, wherein the hydraulic fracturing step
comprises the use of water.
21. The method of claim 12, wherein the hydraulic fracturing step
comprises the use of a proppant slurry of water, guar, and
sand.
22. The method of claim 21, wherein the proppant slurry pressure is
at least about 20 pounds per square inch, but not more than 500
pounds per square inch.
23. The method of claim 22, wherein the proppant slurry pressure is
between about 80 to about 190 pounds per square inch.
24. The method of claim 21, wherein the proppant can be injected at
a flowrate of at least about 5 gallons per minute, but not more
than about 25 gallons per minute.
25. The method of claim 12, wherein the method comprises cycling
between the pneumatic fracturing step and the hydraulic fracturing
step through at least one cycle.
26. The method of claim 25, wherein the method comprises cycling
between the pneumatic fracturing step and the hydraulic fracturing
step for a plurality of cycles.
27. The method of claim 25, wherein the cycling step is
electronically programmable by a computer program.
28. The method of claim 26, wherein the cycling step is
electronically controlled by a computer program.
Description
1. FIELD OF THE INVENTION
[0001] The present invention relates to a system and method of
fracturing ground and geo-formations of many types, more
specifically, a system and method for fracturing ground to enhance
the application of amendments to remediate contaminants in ground
or groundwater and also to improve and enhance ground permeability
for subsurface extraction processes.
2. DESCRIPTION OF THE PRIOR ART
[0002] The most common accepted theories about inducing fractures
in low-permeable deposits are based on simple geotechnical
principles: (1) induced fractures form perpendicular to the
direction of least principle stress (horizontally in
over-consolidated sediments) (2) the overall profile of a fracture
takes on a concave shape, depending on the degree of sediment
over-consolidation, as fractures vent upward towards the surface
with radial distance and (3) fractures' direction may be influenced
by other paths of least resistance such as existing fractures or
variations in geologic stratification in fine grained deposits and
along bedding planes/joints of rock formations.
[0003] The mechanics associated with pneumatic fracturing are based
on the introduction of gas at a pressure that exceeds the in situ
stresses and at a volume or flow rate that exceeds the in situ
permeability. This causes failure of the subsurface medium and the
propagation of outward fractures perpendicular to the least
principal stress. Due to the low viscosity of the fracturing gas
(e.g. nitrogen), "leak-off" or penetration of gas into secondary
micro-fracture networks, pore spaces and permeable lenses requires
that large volumes of gas be emplaced to account for leak-off to
continue the propagation of fractures. To take this one step
further, research has shown that maximum fracture dimensions are
attained within several seconds of pneumatic injection and do not
change unless flow rate is altered. This rapid fracturing
essentially shocks the matrix and forces the matrix to respond or
behave in a brittle fashion.
[0004] In contrast, the fracture dimensions created by hydraulic
fracturing have been found to be time dependent. The different
behaviors of pneumatic vs. hydraulic fractures can be attributed to
the much lower viscosity of gas compared to liquids used in
hydraulic fracturing.
[0005] Applicants have surprisingly found that using controlled
techniques with two or more fluids of varying viscosity during a
fracturing event yield a more dense and influential fracturing
pattern than using either low or high viscosity fluids alone. These
techniques are particularly important at locations with difficult
geologic ground conditions that are not amenable to typical
injection processes or subsurface ground that possess a high degree
of heterogeneity or complexity.
BRIEF SUMMARY OF THE INVENTION
[0006] The Viscosity Differential Fracturing (VDF) technique will
incorporate the benefits of two technologies consisting of
pneumatic and hydraulic processes, and a viscosity differential to
achieve greater networking, higher amendment loading rates, and
more controlled propagation. Applicants disclose a system and
process whereby a multistep or hybrid approach is used to integrate
the physical and dynamic properties of the media used to induce
fractures within the subsurface.
DESCRIPTION OF THE DRAWINGS
[0007] The invention can be better understood by reference to the
following drawings, wherein:
[0008] FIG. 1 illustrates a downhole tool and fracture network
using the system and method disclosed herein.
[0009] FIG. 2 illustrates another downhole tool and fracture
network using the system and method disclosed herein.
[0010] FIG. 3 illustrates a downhole tool and fracture network
using the system and method disclosed herein.
[0011] FIG. 4 illustrates a pressure versus time curve for a
typical pneumatic fracturing event.
DETAILED DESCRIPTION
[0012] In the following detailed description, reference is made to
the accompanying drawings that form a part hereof, and in which are
shown by way of illustration specific embodiments or examples.
These embodiments may be combined, other embodiments may be
utilized, and structural, logical, and procedural changes may be
made without departing from the spirit and scope of the present
invention. The following detailed description is, therefore, not to
be taken in a limiting sense, and the scope of the present
invention is defined by the appended claims and their
equivalents.
[0013] VDF is a multi-phase fracturing technique that integrates
pneumatic and hydraulic components practiced in fracturing
processes to generate a dense and large-aperture fracture network
within the targeted zone that can accommodate a higher mass of
injected material/amendment. As shown in FIG. 1, the pneumatic
component relies on the compressibility and low viscosity of the
fracturing gas 101 and the resultant kinetic energy to create a
fracture network 102 emanating from the point of application 103.
The large volume of the low-viscosity gas enables "leak-off" or
penetration of gas into secondary micro-fractures and pore spaces
104. The hydraulic component introduces an incompressible
high-viscosity fracturing fluid 105 to propagate, dilate and
support large-aperture fractures 106 first initiated by the
pneumatic component and to better interconnect them. The high
viscosity of the hydraulic fracturing media (typically a proppant
slurry with guar) promotes large-aperture fractures 106 due to
minimal "leak-off" and a slower fracture propagation rate.
[0014] This new fracturing process offers unique benefits compared
to pneumatic fracturing (PF) and hydraulic fracturing (HF)
procedures. Conventional PF results in micro-fractures that limit
the quantity of treatment chemicals that can be emplaced in the
subsurface. These micro-fractures are also more likely to pinch
close in certain ground types such as expansive clay under high
moisture or applied vacuum conditions. Conventional HF is limited
to creating one or a very few discrete fractures at a time and not
an inter-connected network of fractures that is more effective in
either enhancing the ground permeability or providing more contacts
within the ground matrix in the case of in situ treatment.
Viscosity Differential Fracturing takes advantage of the gas
component 101 to initiate and create a fracture network 102, while
the hydraulic component 105 acts to dilate and prop open the both
primary and secondary fractures created by the initial gas
injection process. The combined process takes advantage of the
different characteristics of the two fracture fluids to result in
an enhanced and inter-connected network 102 of large-aperture
fractures capable of receiving large quantity of injectates such as
in-situ remediation chemicals or sand proppant.
[0015] The specialized equipment used for the VDF process comprises
three major components. A gas injection component centers around a
pneumatic injection module equipped with a specialty
high-pressure/high-flow regulator, injection control manifold,
digital flowmeter, pressure and a transducer/data-logger monitoring
system. The specialty regulator controls the applied gas pressure
to the formation. The control manifold provides on-off precise
control of gas flow. The flowmeter/pressure transducer system with
data-logger measures and records the process pressure and flow
rate.
[0016] A second component comprises a hydraulic injection system.
It consists of a mobile mixing and injection plant. The plant
includes a re-circulation batch tank resting on a load-cell
weighing system, an automated dry material hopper/feed screw
system, progressive cavity pump, digital flowmeter, a pressure
transducer/data-logger monitoring system. The hopper/feed screw
system conveys a prescribed quantity of proppant material into the
batch tank. The fracturing fluid is created with addition of water
with or without guar as a thickening agent. The progressive cavity
or diaphragm pump delivers the fracturing fluid into the
subsurface.
[0017] As shown in FIGS. 1 and 2, a third component is downhole
injection tooling 107 201. It consists of an injection assembly
comprised of a specialty nozzle 108 202 isolated by multiple
pneumatic packers 109. This assembly is inserted into the borehole
110 via an appropriate length of injection piping and an injection
wellhead above the surface. FIG. 3 is a multi-dimensional view of
the fracture network partially illustrating the density of the
network created at a point of application.
[0018] The components are interconnected by a series of
pressure-rated hoses. The process starts by fracturing the
formation first with delivering compressed nitrogen or gas into the
injection interval via the injection assembly for 5 to 15 seconds.
Once the gas injection ends, the batched hydraulic fracturing fluid
is pumped into the formation via the injection assembly. The
process terminates once the specific quantity of the fracturing
fluid is emplaced.
[0019] Modification of the injection pressure and flow rates of the
gas and hydraulic fluid is necessary to accommodate site conditions
or application objectives. Additionally, the makeup of the
fracturing fluid may be modified to achieve desired viscosity,
grain size, or composition to control the distribution pattern.
Delivery of the fluid within an interval maybe conducted in 2 or
more stages. An initial stage may entail a smaller grain size solid
to penetrate the smaller fractures such as secondary fractures or
those at the distal end of the emplacement radius. The following
stage may include larger grained material to fill the primary
fractures or those closer to the borehole. In addition, by altering
the flow of the emplaced media and the carrier fluids, "packing" of
the fractures can occur.
[0020] Under the VDF approach, optional suspending or thickening
agents are mixed with water at concentrations between 1 and 50
mg/L. The solution is then homogenized in a mixing tank. Once this
is completed, specific quantities of non-reactive or reactive
materials are introduced to the solution at concentrations between
0.1 and 30 lbs. per gallon, which correspond to a 1% and 80% solids
mixture, respectively. Once sufficiently homogenized, the liquid is
introduced under pressure utilizing the equipment discussed above
into the gas induced network.
[0021] The VDF approach can be applied through temporary vertical,
angled and horizontal bore holes, and permanently taste vertical,
angled and horizontal wells. Pressure, flow rate, and fluid
viscosity can be regulated at the surface to optimize permeability
enhancements and minimize potential surfacing of the solution and
maximize performance of the process.
Example 1
[0022] A full scale application of VDF was implemented at a
facility in West Virginia. Over 44,000 lbs. of sand proppant were
injected within an induced fracture network, increasing
permeability and facilitating the extraction of contaminants via
applied vacuum from a low permeable clay unit. This field-scale
demonstration of VDF, confirmed the significant advantages of this
new approach over conventional hydraulic or pneumatic fracturing
alone. The fractures created by this process lead to a greater
density of fractures within the subsurface. This allowed for
emplacement of a greater mass of materials (proppants, sand, and/or
treatment chemicals) facilitating increased permeability, treatment
rates, and elimination of closure due to the applied vacuum.
[0023] Pneumatic fracturing was applied first in order to create a
dense network of small fractures. This was followed by a hydraulic
component consisting of water, guar, and sand to act as a proppant.
Due to the PF, the guar/sand material can be injected into these
fractures at a significant flowrate (about 5 to 25 gpm) and
extend/expand these fractures while filling them with the proppant.
The advantage of VDF versus traditional HF is that the density of
fractures created by the initial gas process leads to an overall
greater density of fractures emplaced within the subsurface coupled
with the ability to emplace a greater mass of material (e.g.
proppants, sand, or reactants).
[0024] The site geology consisted of soil and fill material
underlain by a low permeable clay unit inter-bedded with seams of
sand of varying grain size. Site geology was further detailed on a
per boring basis as ground cores were collected from each location
prior to fracture operations in order to determine the necessity of
fracturing across the designated treatment depths in each location
and to determine the site specific operational parameters (e.g.
flow rates, injection pressures and fluid viscosity).
[0025] The equipment used for the VDF process comprised three
components. On the gas side, a skid-mounted high pressure-high flow
fracture module complete with an injection control manifold and a
digital data logger that were used to monitor various operational
parameters. Injection pressures were regulated with a
high-pressure, high-flow injection manifold. The manifold system
provided precise control of injection pressures combined with
sufficient flows, which enabled the creation and/or enhancement of
fractures within the subsurface. The duration of the gas injections
typically ranged between 10 to 15 seconds.
[0026] An automated mixing and injection plant comprised the second
component. A 350 gallon tank resting on load cells, combined with
an automated hopper/feed screw system, allowed for accurate
metering of sand/water/guar for each VDF event. The injection pump
utilized by this Mixing Plant was a 6 stage Progressive Cavity Pump
with a digital flowmeter and pressure transducer mounted inline to
provide real-time data monitoring.
[0027] A third component was downhole injection tooling. It
included an injection assembly comprised of a specialty nozzle
isolated by multiple pneumatic packers. This assembly was inserted
into the borehole via an appropriate length of injection piping and
an injection wellhead above the surface.
[0028] Ground surface heave is used as a method to detect fracture
initiation and propagation. Since ground is a deformable medium,
the observed surface heave represents the lower limit of fracture
aperture and radius. Ground surface heave measurements were
recorded during each fracturing event using one or more surveying
levels and heave rods. A heave rod was placed at a predetermined
radial distance from the fracture well. During each fracture event,
the rod was observed for the maximum amount of upward motion
(surface heave) and residual or permanent heave. During fracturing
operations, wireless tiltmeters were placed around the injection
point at a pre-determined radius in order to collect real-time
surface deformation data as the fracture events were taking
place.
[0029] A total of 58 locations were successfully completed.
Thirty-eight points targeted a clay unit situated between 26' and
38' below ground surface (bgs) and 20 points were targeted 15' to
25' bgs. In the deeper points, approximately 1,250 pounds of sand
proppant were injected within each three-foot interval for a total
of .about.20 tons of sand. A fracturing slurry consisting of 200
gallons of water and 20 lbs. of guar served as the fracturing and
carrier fluid. The shallow injection points received approximately
half this amount
[0030] Sand/guar injection pressures varied from below 5 psi to
over 200 psi depending on local variations in formation as well as
extent and effectiveness of the PF events. Flowrates during
sand/guar injection events were maintained around 20 gpm.
[0031] Based upon surface heave, tiltmeter, and fracturing pressure
data, a conservatively estimated radius of influence ("ROI") of
about 12 to 15 feet was achieved for the soil vapor extraction
("SVE") wells using the VDF approach. Confirmation coring also
confirmed a 12-15 foot ROI was achieved through visual observations
of induced fractures filled with sand. Post-injection SVE testing
revealed at least a 2-3 order of magnitude increase in subsurface
flow rates when compared to pre-injection or baseline
conditions.
Example 2
[0032] VDF proppant injection was performed at a site in Livermore,
Calif. in six boreholes that were later converted to deep
dual-extraction well locations. The target treatment zone consists
of unconsolidated clay, silt, and minor sand and gravel deposits.
Depth to ground water is approximately 99 feet below ground surface
(bgs.). Chlorinated solvents, mainly trichloroethylene (TCE), were
detected in groundwater at 0.5 mg/liter.
[0033] Pneumatic fracturing was applied first to create a network
of small aperture fractures. This was followed by a high flow-rate
injection of a hydraulic fracturing fluid comprising a
sand-guar-water mixture. The equipment used for the pneumatic
fracturing included a skid-mounted fracture module equipped with a
high-flow, high pressure specialty regulator, an electronically
controlled and pneumatically activated control manifold, pressure
transducer, inline flow meter, and a digital data-logger. Those
skilled in the art will appreciate that pneumatic fracturing
equipment can be adapted to be controlled by computer.
[0034] The second component comprised a portable automated slurry
mixing/injection plant. The mixing/injection plant receives the
sand proppant in bulk bags into a hopper. The proppant is then
conveyed into a 500-gallon mixing tank and suspended in water as
well as other additives such as guar gum, zero valent iron, or
chemical oxidants. The content of the mixture is measured by three
load-cells installed beneath the tank. The operator controls the
quantity of the proppant and water entering the mixing tank at a
digital control panel. A 6-stage progressive cavity pump capable of
flow rates up to 70 gpm and pressure up to 500 psi serves as the
injection pump on the mixing/injection plant; it is controlled by a
digital variable frequency drive and monitored by a magnetic flux
flow meter and pressure transducer mounted inline to provide
real-time data.
[0035] During each fracture initiation, pressures in the discrete
fracture interval were recorded by a pressure transducer located
in-line within the conduit leading to the injection nozzle. These
pressures were recorded by a data-logging system located on the
injection module and accessed using a laptop computer for real-time
display of the injection pressure. The pattern of a
pressure-history curve (see FIG. 4) serves as an indicator of
whether fracture initiation and propagation have occurred. This
information allows the evaluation of two critical measurements: the
fracture initiation pressure and the fracture maintenance
pressure.
[0036] A typical PF event can be subdivided into three distinct
stages: (1) Borehole Pressurization, (2) Fracture Initiation, and
(3) Fracture Maintenance. These independent stages are illustrated
in FIG. 4. It should be noted that the shape of the pressure-time
history curve depends on a number of factors including in situ
stress fields, geologic characteristics of the medium being
fractured, depth of application, and the presence of man-made
disturbances (boreholes, utilities, etc.) within the influence of
fracturing.
[0037] The following section describes each stage as it relates to
the PF mechanism as illustrated in FIG. 4. During the first stage
identified as "Borehole Pressurization," the pressure rapidly
builds up as gas is injected into the target-sealed interval within
the borehole. This stage is identified as curve segment A-B. This
stage is relatively short and typically last 1-2 seconds--depending
on the length of conduit (injection hose and piping) that needs to
be pressurized. Once the pressure is built to a level that exceeds
the in situ stress and overburden pressure within the borehole
interval, the formation yields and fractures are initiated. Stage B
in FIG. 4 represents the fracture initiation pressure. Following
the formation fracture initiation stage, the pressure decreases
rapidly and stabilizes at a plateau as the injection continues.
This rapid decline in the borehole pressure is represented by
segment B-C. During this time period, the injection gas flow rate
usually maximizes or steadily increases as the fractures are
propagated, thereby reducing the back pressure within the treatment
zone to the injection. Segment C-D reflects the continual gas
injection under a relatively constant injection pressure. As the
injection pressure is terminated, the maintenance pressure declines
rapidly from D-E.
[0038] The shape and magnitude of the pressure history curve can be
affected by factors such as soil cohesion, depth, presence of
leak-off points or preferential pathways, or presence of a
confining layer within or above the formation.
[0039] During the fracturing events, pressure gauges were placed at
select monitoring wells and adjacent injection borings, where
available, to monitor pressure influence. Each pressure gauge was
fitted with a maximum drag-arm indicator, which enabled field
personnel to identify the maximum pressure influence at that
location during each event. The data also assisted in determining
which directions fractures may have propagated. In addition, the
degree of pressure response can often help determine whether a
monitoring point has been directly influenced (i.e., fractures
propagate outward and intersect wells or boreholes) or indirectly
influenced through localized groundwater displacement and/or
mounding.
[0040] As in Example 1, ground surface heave was measured and
recorded using a surveying level, heave rods, and wireless
tiltmeters. Collected data can then be used to produce visual
representations of surface deflection in all directions around the
injection point. Note that surface heave either collected by a
heave rod or surface tiltmeter system may not be representative of
the actual formation/deformation occurring at the injection depth.
Fracture formation magnitude and pattern may be affected by soil
compression or variation in stratigraphy above the fracturing zone
as well as the presence of a surface cover.
[0041] Pneumatic fracture initiation pressures ranged between 350
and 405 psi and maintenance pressures of at least about 50 psi and
typically between about 200 to 370 psi, but not more than 500 psi.
Nitrogen flow rate was at least about 250 standard cubic feet per
minute and typically about 1,500 to about 2,400 standard cubic feet
per minute, but not more than 2,400 standard cubic feet per minute,
and with a general trending indicating less flow required to
fracture the formation at shallower depths. Hydraulic injection
pressures were at least 20 psi and typically between 80-190 psi,
but not more than 500 psi. Approximately, 150 gallons of viscosity
adjusted fluid was injected in each 3-foot interval, including
about 825 lbs. of sand and 12 lbs. of guar. A total of about 48,585
lbs. of sand was injected in 6 injection points from .about.75 to
100 ft. bgs.
[0042] Soil coring in six (6) confirmatory boreholes was used to
confirm the ROI of the VDF injection. The cores were collected with
a 5-ft. long, 4-inch diameter split sampler in 5-ft. acetate
liners. Ten (10) cores were sampled between 62 ft. and 112 ft. bgs.
Seven (7) cores were sampled at each of the remaining 5 locations
between the depths of 72 ft. and 107 ft. bgs. Traces of the sand
proppant as well as rhodamine WT and fluorescein dyes were detected
on the surface of several soil cores. The emplacement radial
distance was 25 feet or more. This was confirmed by tiltmeter
contours showing ground surface movement at distances 25 feet or
greater.
[0043] It is to be understood that the above description is
intended to be illustrative and not restrictive. For example, the
above-described embodiments and variations may be used in
combination with each other. Many other embodiments will be
apparent to those of skill in the art upon reviewing the above
description. The scope of the invention should, therefore, be
determined with reference to the appended claims, along with the
full scope of equivalents to which such claims are entitled. In the
appended claims, the terms "including" and "in which" are used as
the plain-English equivalents of the respective terms "comprising"
and "wherein."
* * * * *