Note: Descriptions are shown in the official language in which they were submitted.
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HYDRAULIC FRACTURING METHODS AND SYSTEMS USING
GAS MIXTURE
BACKGROUND
The present disclosure relates to systems and methods for fracturing
subterranean
formations.
Treatment fluids can be used in a variety of subterranean treatment
operations. As
used herein, the terms "treat," "treatment," "treating," and grammatical
equivalents thereof
refer to any subterranean operation that uses a fluid in conjunction with
achieving a desired
function and/or for a desired purpose. Use of these terms does not imply any
particular action
by the treatment fluid. Illustrative treatment operations can include, for
example, fracturing
operations, gravel packing operations, acidizing operations, scale dissolution
and removal,
consolidation operations, and the like.
Hydraulic fracturing is one type of treatment operation used to improve
production
from subterranean formations. Fracturing fluids and proppant materials may be
mixed and
pumped through a wellbore and into the subterranean formation containing the
hydrocarbon
materials to be produced. Injection of the fracturing fluid is completed at
high pressures
sufficient to create or enhance fractures within the subterranean formation.
The fracturing
fluid carries the proppant materials into the fractures, depositing the
proppant materials in the
fractures when the fluid flows back out of the well bore. Upon completion of
the fluid and
proppant injection, the pressure is reduced and the proppant holds the
fractures open. Upon
removal of sufficient fracturing fluid, production from the well is initiated
or resumed
utilizing the improved flow through the created fracture system.
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BRIEF DESCRIPTION OF THE DRAWINGS
These drawings illustrate certain aspects of some of the embodiments of the
present
disclosure, and should not be used to limit or define the claims.
Figure 1 is a diagram illustrating a fracturing system for injecting a
fracturing fluid
mixture of natural gas, unreactive gas, and a liquid base fluid into a
subterranean formation
according to at least some of the embodiments of the present disclosure.
Figure 2 is a diagram illustrating a system for controlling the fracturing
system
according to at least some of the embodiments of the present disclosure.
While embodiments of this disclosure have been depicted, such embodiments do
not
imply a limitation on the disclosure, and no such limitation should be
inferred. The subject
matter disclosed is capable of considerable modification, alteration, and
equivalents in form
and function, as will occur to those skilled in the pertinent art and having
the benefit of this
disclosure. The depicted and described embodiments of this disclosure are
examples only,
and not exhaustive of the scope of the disclosure.
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DESCRIPTION OF CERTAIN EMBODIMENTS
The present disclosure relates to systems and methods for fracturing
subterranean
formations. More particularly, the present disclosure relates to systems and
methods for
fracturing in subterranean formations using treatment fluids that comprise a
mixture of
natural gas and other gases.
The present disclosure in some embodiments provides methods for using certain
treatment fluids to carry out hydraulic fracturing treatments. Natural gas and
an unreactive
gas such as nitrogen (N2), carbon dioxide (CO2), argon (Ar2), helium (He2), or
the like may
be blended (either separately or as a single gas stream) with a liquid base
fluid, and other
optional components, to form a treatment fluid, such as a fracturing fluid.
The fracturing
fluid may be introduced into a well bore that penetrates a subterranean
formation at or above
a pressure sufficient to create or enhance one or more fractures within the
subterranean
formation. The natural gas used in these fracturing fluids may be provided
and/or stored in
any form, including but not limited to compressed natural gas (CNG) or
liquefied natural gas
(LNG). The presence of the natural gas and/or unreactive gas in the fluid may,
in some
embodiments, cause the fracturing fluid to form a foam or mist. The fracturing
fluid may
comprise a number of other optional components or additives useful in
fracturing treatments,
including but not limited to viscosifiers and/or proppant particulates.
Following the
fracturing treatment, the gas and accompanying liquid can be recovered, the
unreactive gas
optionally separated from the natural gas, and the applied natural gas
directed to existing
facilities via pipeline for recovery and sale. In certain embodiments, the
unreactive gas may
be present in sufficiently small amounts (depending on the requirements of the
natural gas
processing facility) that it does not need to be separated out prior to
injection into the
pipeline. In certain embodiments, the fracturing systems of the present
disclosure may
further include gas venting, purging, and/or isolation equipment to facilitate
the operation and
maintenance of the system.
Among the many potential advantages to the methods and compositions of the
present
disclosure, only some of which are alluded to herein, the methods,
compositions, and systems
of the present disclosure may provide relatively unreactive and/or inert
fracturing fluids that
reduce or minimize chemical damage to the formation being fractured. In some
embodiments, the systems of the present disclosure may provide a safe
apparatus for
preparing the fracturing fluids of the present disclosure and/or introducing
them into a
subterranean formation. In some embodiments, the natural gas and/or unreactive
gases may
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alter one or more properties of the liquid base fluid in the fracturing fluid,
including but not
limited to phase behavior, interfacial tension, viscosity, dissolved gas
content, and/or the like.
In some embodiments, unreactive gases such as carbon dioxide may act as a
natural solvent,
increasing the solubility of methane gas in the reservoir oil. In some
embodiments, the
unreactive gases may help decrease the viscosity of oil and/or other fluids in
the subterranean
formation in which they are used, which may increase the mobility of those
fluids and/or
facilitate their production out of the formation. In some embodiments, the
methods and
compositions of the present disclosure may decrease or eliminate the amount of
natural gas
that must be vented or flared from a flowback gas prior to injection into a
pipeline for
processing.
The fracturing fluids used in the methods and systems of the present
disclosure may
comprise any base fluid known in the art, including aqueous base fluids, non-
aqueous base
fluids, and any combinations thereof. The term "base fluid" refers to the
major component of
the fluid (as opposed to components dissolved and/or suspended therein), and
does not
indicate any particular condition or property of that fluids such as its mass,
amount, pH, etc.
Aqueous fluids that may be suitable for use in the methods and systems of the
present
disclosure may comprise water from any source. Such aqueous fluids may
comprise fresh
water, salt water (e.g., water containing one or more salts dissolved
therein), brine (e.g.,
saturated salt water), seawater, or any combination thereof. In most
embodiments of the
present disclosure, the aqueous fluids comprise one or more ionic species,
such as those
formed by salts dissolved in water. For example, seawater and/or produced
water may
comprise a variety of divalent cationic species dissolved therein. In certain
embodiments, the
density of the aqueous fluid can be adjusted, among other purposes, to provide
additional
particulate transport and suspension in the compositions of the present
disclosure. In certain
embodiments, the pH of the aqueous fluid may be adjusted (e.g., by a buffer or
other pH
adjusting agent) to a specific level, which may depend on, among other
factors, the types of
viscosifying agents, acids, and other additives included in the fluid. One of
ordinary skill in
the art, with the benefit of this disclosure, will recognize when such density
and/or pH
adjustments are appropriate. Examples of non-aqueous fluids that may be
suitable for use in
the methods and systems of the present disclosure include, but are not limited
to, oils,
hydrocarbons, organic liquids, and the like. In certain embodiments, the
fracturing fluids
may comprise a mixture of one or more fluids and/or gases, including but not
limited to
emulsions, foams, and the like.
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As used in this disclosure, natural gas refers to methane (CH4) alone or
blends of
methane with other gases such as other gaseous hydrocarbons. In some
embodiments, natural
gas may comprise a variable mixture of about 85% to 99% methane (CH4) and 5%
to 15%
ethane (C2H6), with further decreasing components of propane (C3H8), butane
(C4H10),
pentane (C5H12) with traces of longer chain hydrocarbons. As used herein,
"CNG" refers to
compressed natural gas, and "LNG" refers to liquefied natural gas.
The unreactive gases used in the present disclosure may comprise any gaseous
substance known in the art that will not substantially chemically react and/or
will remain
substantially inert in the conditions in which it is being used. Examples of
gases that may be
suitable in certain embodiments include, but are not limited to, nitrogen
(N2), carbon dioxide
(CO2), argon (Ar2), helium (He2), and any combination thereof The unreactive
gas may be
provided in a gaseous state, or may be initially provided in a liquid state
and then gasified for
use in the fracturing fluids of the present disclosure. The unreactive gas may
be added in an
amount of from about 0.01% to about 25% of the gaseous stream by total volume
of the
gaseous stream. In some embodiments, the unreactive gas may be added in an
amount of
from about 0.01% to about 5% by total volume of the gaseous stream.
In certain embodiments, the fracturing fluids used in the methods and systems
of the
present disclosure optionally may comprise any number of additional chemical
additives.
Examples of such additional additives include, but are not limited to, salts,
surfactants, acids,
.. proppant particulates, diverting agents, fluid loss control additives,
surface modifying agents,
tackifying agents, foamers, corrosion inhibitors, scale inhibitors, catalysts,
clay control
agents, biocides, friction reducers, antifoam agents, bridging agents,
flocculants, additional
H2S scavengers, CO2 scavengers, oxygen scavengers, lubricants, additional
viscosifiers,
breakers, weighting agents, relative permeability modifiers, resins, wetting
agents, coating
enhancement agents, filter cake removal agents, antifreeze agents (e.g.,
ethylene glycol), and
the like. In certain embodiments, one or more of these additional additives
(e.g., a
crosslinking agent) may be added to the fracturing fluid and/or activated
after the viscosifying
agent has been at least partially hydrated in the fluid. A person skilled in
the art, with the
benefit of this disclosure, will recognize the types of additives that may be
included in the
fluids of the present disclosure for a particular application.
The treatment fluids of the present disclosure may be prepared using any
suitable
method and/or equipment (e.g., blenders, mixers, stirrers, etc.) known in the
art at any time
prior to their use. The fracturing fluids may be prepared at least in part at
a well site or at an
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offsite location. In certain embodiments, the base fluid may be mixed with
certain
components of the fracturing fluid at a well site where the operation or
treatment is
conducted, either by batch mixing or continuous ("on-the-fly") mixing. The
term "on-the-
fly" is used herein to include methods of combining two or more components
wherein a
flowing stream of one element is continuously introduced into a flowing stream
of another
component so that the streams are combined and mixed while continuing to flow
as a single
stream as part of the on-going treatment. Such mixing can also be described as
"real-time"
mixing. In other embodiments, the fracturing fluids of the present disclosure
may be
prepared in part at an offsite location and transported to the site where the
treatment or
operation is conducted. In introducing a fracturing fluid of the present
disclosure into a
portion of a subterranean formation, the components of the fracturing fluid
may be mixed
together at the surface and introduced into the formation together, or one or
more components
may be introduced into the formation at the surface separately from other
components such
that the components mix or intermingle in a portion of the formation to form a
fracturing
fluid. In either such case, the fracturing fluid is deemed to be introduced
into at least a
portion of the subterranean formation for purposes of the present disclosure.
In some embodiments, a method of forming a fracturing fluid mixture that
comprises
natural gas and an unreactive gas as a gas phase in sufficient quantity to
desirably alter the
characteristics of the fracturing treatment is provided. First, a sufficient
quantity of natural
.. gas and unreactive gas is made available to complete the fracturing
treatment. Fracturing
treatments can consume considerable quantities of fracturing fluids with
common volumes
over 500 m3 (130,000 gal) with unconventional fracturing consuming volumes in
the order of
4,000 m3 (1,000,000 gal). Applying any reasonable quantity of natural gas to
the fracturing
treatment can consume anywhere from 50,000 sm3 (1.5 MMscf) to 300,000 5m3 (10
MMscf)
of gas within a 4 to 6 hour pumping period. To meet the volume and rate
requirement, the
natural gas is stored awaiting pumping for most applications. Storage of
natural gas can be
completed by either holding it in pressured vessels or by liquefying for
storage in cryogenic
vessels. Efficient storage of natural gas in pressured vessels is achieved at
the highest
possible pressure which is typically less than 30 MPa (4,400 psi), holding
approximately
10,000 sm3 (0.4 MMscf) in each unit. Effective storage of these quantities
even at maximum
pressures would require several pressurized vessels with numerous connections
between
tanks and pumping equipment at the elevated storage pressures. Alternatively,
LNG can be
stored in LNG tanks on-site which permits considerable volumes to be stored
efficiently and
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at pressures as low as atmospheric. As a cryogenic liquid one unit volume of
LNG contains
approximately six hundred volumes of gas at atmospheric conditions. In a
single LNG
storage vessel containing 60 m3 (16,000 gal) of LNG, an equivalent of 36,000
sm3 (1.2
MiMscf) is stored. A large treatment would require approximately 10 LNG
storage tanks
compared to over 30 pressured natural gas tanks. The use of LNG eliminates the
issues found
with gas phase storage; the multitude of high pressure vessels and piping
needed to draw the
natural gas from the pressure vessels result in a very complex and potentially
hazardous
system.
Once provided, the natural gas (and, optionally, the unreactive gas) may be
processed
to the fracturing pressure in sufficient quantity. Fracturing pressures are
often in the range of
35 MPa (5,000 psi) to 70 MPa (10,000 psi), while the natural gas rate is
usually from 400
sm3/min (15,000 scf/min) to 1,200 sm3/min (40,000 scf/min). Pressuring the
compressed
natural gas to fracturing pressures may require gas phase compressors of some
form.
Alternatively, pressuring natural gas to the extreme pressures encountered in
hydraulic
fracturing in liquid form as LNG may be more efficient. As a liquid the
volumetric rates are
much reduced and incompressible as compared to gaseous natural gas,
compression heating
may be eliminated and equipment size and numbers reduced. The cryogenic
natural gas liquid
is directly pressured to the fracturing pressure by a single pump, and then
simply heated to
the application temperature. For an upper-end fracturing gas rate at pressure,
LNG is pumped
at approximately 2 m3/min (500 gal/min) of liquid yielding a gas rate in
excess of 1,500,000
sm3/day (60 MMscf/day) through 8 units of rate to 160 sm3/min each. This
smaller and
simpler equipment configuration may significantly reduce the complexity of the
operation
removing many of the costs and hazards which would be present with compressed
gas
techniques.
After the natural gas (and, optionally, the unreactive gas) is processed to
the desired
fracturing pressure, the gas stream(s) are combined with a liquid base fluid
stream (and,
optionally, other additives) to form a fracturing fluid that is then injected
into the well. The
natural gas and unreactive gas may be provided in a single stream that is
combined with the
liquid base fluid stream, or may be provided in separate streams for
combination with the
base fluid stream. A mixer can be used to combine the streams in a high
pressure treating line
prior to or at the wellhead; this approach may allow easy handling of the
separate streams
without disruption to typical fracturing operations, complete the task without
modification to
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the well, and/or provide a simple and effective way to accomplish mixing the
natural gas and
liquid-slurry streams.
Alternatively, the liquid base fluid stream can be combined with the gas
stream(s) in a
low-pressure process or within the wellbore at fracturing pressure. The gases
are injected
down one or more conduits within the wellbore and the liquid-slurry down
another conduit
with the streams combining at some point in the wellbore. In these cases, some
type of a
specialized wellhead or wellbore configuration in the form of an additional
tubular and a
common space is provided where the streams can meet.
In some embodiments, a fracturing system is provided that includes equipment
for
storing the components of the fracturing fluid, equipment for injecting the
fracturing fluid
into a subterranean formation, such as an oil well or a gas well, and
equipment for recovering
and separating fluids from the well. In some embodiments, the natural gas
source is
compressed gas (CNG) held in pressurized vessels with a fracturing pump
further
compressing the natural gas to a suitable fracturing pressure. In other
embodiments, the
compressed gas is held in pressurized vessels above the fracturing pressure
and simply
released into the fracturing stream. In some embodiments, the gas source is a
vessel
containing liquefied natural gas (LNG) with the fracturing pump pressuring the
LNG to
fracturing pressure and heating the pressurized LNG stream.
FIG. 1 is a generic depiction of the main components of a fracturing system
100
according to certain embodiments of the present disclosure which use a
fracturing fluid
comprising a liquid base fluid portion and a gaseous portion that comprises
natural gas and an
unreactive gas, and may further comprise proppant particulates and/or one or
more chemical
additives. A liquid base fluid is stored in a liquid tank (13), proppant is
stored in a proppant
container (12), and chemical additives such as a viscosifier is stored in a
chemical additive
container (22). Liquid tank (13) suitable for water or hydrocarbon based
liquids is connected
via a conduit (26) to a fracturing blender (14) with viscosifying chemicals
added via a conduit
from chemical additive container (22). The fracturing liquid tanks (13) can be
any of those
common within the industry for hydraulic fracturing and may apply more than
one tank or
other suitable arrangement to store sufficient liquid volume. The conduit
(26), like all other
conduits shown in FIG. 1, comprises a pipe or hose rated to the described
application and
conditions. The blender (14) receives the viscosified fracturing liquid and
blends proppant
material from a proppant supply container (12) with the fracturing liquid to
form the base
fluid which is now in a slurry form. The blender (14) is a multiple task unit
that draws liquids
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from the liquids tank with a centrifugal pump (not shown), accepts chemicals
from the
chemical additive container (22) and mixes them with the liquid base fluid,
often within the
centrifugal pump. The liquid base fluid is combined with proppant from
proppant supply
container (12) in a mixing tub or other mixing device on the blender (14) to
form a slurry, and
then drawn into another centrifugal pump mounted on the blender (14). The
created slurry is
then pumped via a conduit (50) from the blender (14) to a high pressure slurry
pump (16).
The high pressure slurry pump (16) pressurizes the liquid stream to a suitable
fracturing
pressure and is connected via conduit (42) to a fracturing fluid mixer (18).
In some
embodiments, more than one pump may be used as the pump (16). In some
embodiments,
certain of the foregoing components may be combined such as the blender (14)
and high
pressure slurry pump (16).
Natural gas is stored in a natural gas container (15) and a natural gas stream
is
pressurized and supplied by a high pressure natural gas pump (17) and enters a
fracturing
fluid mixer (18) via a conduit (24). The natural gas stored in container (15)
can be
compressed natural gas or liquefied natural gas. An example of a vessel
applied for
compressed natural gas transport and storage is the trailer mounted Lincoln
Composites'
TITAN Tank holding up to 2,500 scm (89,000 scf) of CNG at pressures to 25 MPa
(3,600
psi). An example of a vessel applied for liquefied natural gas storage is the
skid mounted
EKIP Research and Production Company LNG Transporter with a capacity of 35.36
m3
(9,336 gal) holding up to 21,000 scm (750,000 scf) of liquid natural gas at
pressures to 0.6
MPa (90 psi). LNG is typically stored at atmospheric pressure at a temperature
of
approximately ¨162 C (-260 F).
The high pressure natural gas pump (17) comprises a compressor if compressed
natural gas is the source or a specialized liquefied natural gas fracturing
pump and a heating
component to vaporize the LNG if LNG is the source. The output from the high
pressure
natural gas pump (17), regardless of the state of the source gas, is in a
gaseous state. In some
embodiments, more than one pump may be used as the pump (17). If CNG is the
natural gas
source, the high pressure natural gas compressor pump (17) is used to compress
the gas to the
fracturing pressure, if necessary. Compression may be accomplished by any pump
capable of
increasing the pressure within a gas stream; for example reciprocating
compressors may be
applied to achieve high pressure such as that required for hydraulic
fracturing. Typically
compressors achieve a fixed compression factor, such that multiple stages of
compression
may be required to attain fracturing pressure. Similarly, in order to achieve
the desired rate,
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multiple of compressor stages may be applied in parallel. If LNG is the
natural gas source,
the high pressure natural gas pump (17) may be arranged to pressure the LNG to
the
fracturing pressure (e.g., using a pump component) and then heat the pressured
LNG to
compressed gas (e.g., using a heater component, such as a flameless catalytic
heater
comprising at least one catalytic element fluidly communicable with and
capable of oxidizing
a fuel gas to generate heat).
An unreactive gas such as nitrogen (N2), carbon dioxide (CO2), argon (Ar2),
helium
(He2), or the like is stored in gas source (30). The gas source (30) can
contain a cryogenic
unreactive gas cooled to pre-cool the high pressure natural gas pump or other
equipment prior
to introducing the natural gas. This may reduce or eliminate the need to pre-
cool the system
using flammable natural gas and eliminates the natural gas flaring otherwise
needed. The
unreactive gas from gas source (30) can be introduced into conduit (23) via
conduit (32)
upstream of the natural gas pump (17), and/or into conduit (24) via conduit
(34) downstream
of the natural gas pump (17). In the former embodiments, the pump (17) may be
used to
pressurize and/or heat the unreactive gas along with the natural gas. In the
latter
embodiments, the unreactive gas may be pressurized and/or heated separately
prior to its
introduction into conduit (24), for example, using separate high pressure
pumps, heaters, etc.
(not shown).
Within the mixer (18), the gas stream from conduit (24) is combined with a
liquid
fluid stream from conduit (42); this liquid can comprise the liquid base fluid
optionally
combined with proppant and/or chemical additive(s). As described above, the
gas stream
from conduit (24) may comprise both the unreactive gas from gas container (45)
and natural
gas from the high pressure natural gas pump (17). Alternatively, the
unreactive gas can be
provided to mixer 18 in a gaseous stream separate from the gaseous stream
comprising the
natural gas, for example, via a separate conduit (not shown). The combined
fracturing fluid
then enters a well (19) via a conduit (25) where it travels down the well bore
to the formation
creating or enhancing the hydraulic fracture using the rate and pressure of
the fracturing fluid.
Upon applying the desired fracturing materials within the well (19), injection
is stopped and
placement of the fracturing treatment is complete. Following the fracture
treatment and at a
time deemed suitable for the well, the well (19) is opened for flow with the
stream directed to
a conduit (20 a) and then through a separator vessel (60) wherein gases are
separated from
liquids. Initial flow from the well will be mostly comprised of the injected
fracturing
materials and the separator vessel (60) is used to separate the injected
natural gas from the
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recovered stream through the conduit (20 a). The liquids and solids recovered
from separator
vessel (60) are directed to tanks or holding pits (not shown). The natural gas
from the
recovered stream exits the separator (60) and is initially directed to a flare
(20), e.g., through
a flare conduit line fluidically coupled to the separator (60), until flow is
suitably stabilized,
and/or to remove any of the unreactive gas from the natural gas stream. Once
the natural gas
stream is stabilized, it may be directed to a pipeline (21) for processing and
sale. In some
embodiments, the relative amounts of natural gas and/or unreactive gas in the
gas stream(s)
provided to the mixer 18 may be determined based at least in part on flow back
requirements
for the gas being directed to the pipeline (21) for processing and/or sale,
such that the natural
gas and unreactive gas can be directed to the pipeline without removal of the
unreactive gas,
venting of the natural gas and unreactive gas, or flaring of the natural gas
and unreactive gas.
In these instances, the system 100 may omit the flare 20 and/or other
separation equipment.
A number of control valves (V1) through (V13) may be selectively opened and/or
closed to control the flow of liquids, gases, and other components through the
conduits shown
in the system 100. For example, feed valve (V4) may be selectively opened
and/or closed to
a desired degree to regulate the supply of pressurized natural gas flowing
from its source (15)
to the natural gas stream slurry mixer (18). Fracturing liquid control valve
(V1) may similarly
regulate flow from the fracturing liquid tank (13), proppant supply valve (V2)
may regulate
flow of proppant from proppant supply (12), chemical supply valve (V10) may
regulate flow
of chemical additives from the chemical source (22), and fracturing blender
valve (V3) may
regulate flow from the fracturing blender (14) in order to supply a properly
constructed liquid
mixtures or slurries to the high pressure slurry pump (16). Additional valves
(not shown)
may be present in system 100, among other purposes, to control venting or
purging
operations, and to monitor the condition of system components.
In some embodiments the fracturing systems of the present disclosure can
further
include equipment for venting, purging, and/or isolating natural gas
("venting, purging and
isolation equipment"). Among other benefits, such equipment may aid in
controlling the
risks associated with natural gas being a flammable high pressure gas source.
The equipment
can include use of a cryogenic inert gas cooled to pre-cool the high pressure
natural gas pump
or other equipment prior to introducing the natural gas. This reduces or
eliminates the need to
pre-cool the system using flammable natural gas and eliminates the natural gas
flaring
otherwise needed. In some embodiments, an inert gas can also be used to
pressure test the
fracturing system to identify any leaks or failures, or permit any
configuration or function
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testing of the system, or to quickly purge any residual natural gas, oxygen,
or air before,
during or after fracturing treatment. In the event of a leakage or component
failure during
fracturing treatment, the venting, purging and isolation equipment allows for
that component
to be isolated so that the remainder of the system is unaffected. The venting,
purging and
isolation equipment may comprise a series of additional valves and supply
conduits to deliver
purging gas to, or vent gas from, various points in the system. In some
embodiments, the
venting, purging and isolation equipment also may comprise a purge gas supply.
In some
embodiments, the unreactive gas supply (30) may be used as a purge gas supply,
for example,
when it is not being used to supply the unreactive gas to the fluid introduced
into well (19).
In some embodiments, the operation of a fracturing system of the present
disclosure
(including any purging or venting equipment therein) may be controlled by a
controller.
FIGURE 2 is a diagram illustrating a system for controlling the fracturing
system of some of
the embodiments. The controller (58) has a memory programmed to control the
operation of
at least some components within the system. The controller (58) may
communicate with
components in the system by direct connection or wireless connection to the
various
components. For example, fracturing blender (814), high pressure natural gas
pump (817) and
high pressure slurry pump (816) may be remotely controlled by such a
controller. One or
more of valves (V18) through (V138) (which may correspond to valves V1 through
V13
shown in FIG. 1) also may be connected to and remotely controlled by such a
controller (58).
Among other benefits, remote control capability may permit ready and reliable
control of the
operation from a central point plus allows control of the system during normal
operations,
and in particular an emergency, without exposing personnel to hazards. The
controller also
may ensure a properly proportioned mixed natural gas and liquid slurry stream
is created by
controlling the relative supply of the gas fracturing stream compared to the
liquid slurry
stream by control of the high pressure slurry pump (16) and the high pressure
natural gas
pump (14). Control of the components may be directed by either the operator of
the system
via a user interface or through software containing algorithms stored on the
memory of the
controller and developed to direct the components to complete the task in a
suitable manner.
The controller may be any suitable process control system and may include
control inputs
from operator panels or a computer. Similar control capability is applicable
to other described
configurations and other components as required.
For example, the controller (58) is connected to and controls the operation of
the feed
valve (V48) and the high pressure natural gas pump (817) thereby controlling
the supply of
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pressurized natural gas from its source (815) to the natural gas stream slurry
mixer (18).
Concurrently, controller (58) is connected to and controls the operation of
the fracturing
liquid control valve (V18) to regulate flow from the fracturing liquid tank
(813), the proppant
supply valve (V28) to regulate flow from proppant supply (812), the chemical
source (822)
and the fracturing blender (814) in order to supply a properly constructed
liquid slurry to the
high pressure slurry pump (816). Simultaneous control functions continue with
controller
(58) connected to and controlling high pressure slurry pump (816). Controller
(58) may
further ensure a properly proportioned mixed natural gas and liquid slurry
stream is created
by controlling the relative supply of the natural gas fracturing stream
compared to the liquid
slurry stream by control of the high pressure slurry pump (816) and the high
pressure natural
gas pump (814). Controller 58 is connected to and controls the operation of
the feed valves
(V118) and (V128) thereby controlling the supply of unreactive gas from its
source (830) to
the high pressure pump (817) and/or the mixer (18) (as shown in FIG. 1).
In the system shown in FIG. 1, or other systems of the present disclosure, one
or more
of the above-described components (e.g., the liquid base fluid tank, natural
gas source,
chemical additive source, proppant source, unreactive gas source, blenders,
pumps,
controllers, and/or user interfaces) may be mounted on a series of mobile
trucks or other
surface equipment that can be located at the surface at a well site, among
other reasons, to
facilitate the transport of that equipment to and from a well site. The
configuration and
apparatus on any one unit can be altered or the equipment may be temporarily
or permanently
mounted as desired. Moreover, similar systems may be used in matrix
stimulation treatments
such as acidizing treatments or scale removal treatments. In those treatments,
the systems of
the present disclosure may be used to introduce a treatment fluid comprising a
liquid base
fluid, natural gas, and an unreactive gas at a pressure appropriate to those
treatments.
An embodiment of the present disclosure is a method comprising: providing a
fracturing fluid comprising a liquid base fluid and a gaseous component
comprising natural
gas and at least one unreactive gas; and introducing the fracturing fluid into
a subterranean
formation at or above a pressure sufficient to create or enhance one or more
fractures in at
least a portion of the subterranean formation.
Another embodiment of the present disclosure is a method comprising: providing
a
liquid base fluid; providing gaseous natural gas; providing at least one
gaseous unreactive
gas; mixing the liquid base fluid, the natural gas, and the at least one
unreactive gas to form a
fracturing fluid; and introducing the fracturing fluid into a subterranean
formation at or above
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a pressure sufficient to create or enhance one or more fractures in at least a
portion of the
subterranean formation.
Another embodiment of the present disclosure is a system comprising: a liquid
base
fluid source; a liquid base fluid pump fluidly coupled to the liquid base
fluid source for
pressurizing a liquid base fluid to at least a pressure sufficient to create
or enhance one or
more fractures in at least a portion of a subterranean formation; a natural
gas source; a natural
gas pump fluidly coupled to the natural gas source; an unreactive gas source;
and a mixer
for mixing the liquid base fluid, gaseous natural gas, and gaseous unreactive
gas to form a
fracturing fluid mixture for injection into a wellhead at a well site
comprising a well bore
penetrating at least the portion of the subterranean formation, the mixer
having at least a first
inlet fluidly coupled to the liquid base fluid pump, a second inlet fluidly
coupled to the
natural gas pump, a third inlet fluidly coupled to the unreactive gas source,
and an outlet
fluidly coupled to the wellhead.
Another embodiment of the present disclosure is a method comprising: (a)
providing a
liquid base fluid and pressurizing the base fluid to at least a fracturing
pressure of the
formation; (b) providing liquefied natural gas (LNG) and pressurizing the LNG
to at least the
fracturing pressure then heating the LNG until the LNG is vaporized to a
gaseous state; (c)
providing at least one unreactive gas and pressurizing the unreactive gas to
at least the
fracturing pressure; (d) mixing the pressurized liquid base fluid, pressurized
gaseous natural
gas, and pressurized unreactive gas to form a fracturing fluid; and (e)
injecting the fracturing
fluid into a well bore penetrating at least a portion of a subterranean
formation to create or
enhance at least one fracture in the subterranean formation.
Another embodiment of the present disclosure is a system for generating an
energized
fracturing fluid mixture for hydraulically fracturing a downhole formation,
the system
comprising: (a) a fracturing base fluid source; (b) a base fluid pump fluidly
coupled to the
fracturing base fluid source, and configurable to pressurize a liquid base
fluid to at least a
fracturing pressure of a formation; (c) a liquefied natural gas ("LNG")
source; (d) an LNG
pump assembly fluidly coupled to the LNG source and comprising a pump
component
configurable to pressurize LNG to at least the fracturing pressure, and a
heater component
configurable to vaporize pressurized LNG to a gaseous phase; and (e) a
fracturing fluid mixer
having a first inlet fluidly coupled to the base fluid pump, a second inlet
fluidly coupled to
the LNG pump assembly and an outlet for coupling to a wellhead, and for mixing
the liquid
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base fluid and gaseous natural gas to form a fracturing fluid mixture for
injection into the
wellhead.
Therefore, the present disclosure is well adapted to attain the ends and
advantages
mentioned as well as those that are inherent therein. The particular
embodiments disclosed
above are illustrative only, as the present disclosure may be modified and
practiced in
different but equivalent manners apparent to those skilled in the art having
the benefit of the
teachings herein. While numerous changes may be made by those skilled in the
art, such
changes are encompassed within the spirit of the subject matter defined by the
appended
claims. Furthermore, no limitations are intended to the details of
construction or design
herein shown, other than as described in the claims below. It is therefore
evident that the
particular illustrative embodiments disclosed above may be altered or modified
and all such
variations are considered within the scope and spirit of the present
disclosure. In particular,
every range of values (e.g., "from about a to about b," or, equivalently,
"from approximately
a to b," or, equivalently, "from approximately a-b") disclosed herein is to be
understood as
referring to the power set (the set of all subsets) of the respective range of
values. The terms
in the claims have their plain, ordinary meaning unless otherwise explicitly
and clearly
defined by the patentee.
