HYDRAULIC FRACTURING METHODS AND SYSTEMS USING GAS MIXTURE

Abstract

Systems and methods for fracturing in subterranean formations using treatment fluids that comprise a mixture of natural gas and other gases are provided. In some embodiments, the methods comprise: 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.

Description

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.

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.

FIG. 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.

FIG. 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.

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 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.

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 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 sm³ (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 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 MMscf) 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 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 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, 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 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 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. FIG. 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 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 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 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.

Claims

1. 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.

2. The method of claim 1 wherein the unreactive gas comprises at least one gas selected from the group consisting of: nitrogen (N2), carbon dioxide (CO2), argon (Ar2), helium (He2), and any combination thereof.

3. The method of claim 1 further comprising: vaporizing liquefied natural gas (LNG) to form the natural gas.

4. The method of claim 1 wherein the natural gas is provided as compressed natural gas (CNG).

5. The method of claim 1 wherein the unreactive gas is present in an amount of from about 0.01% to about 25% by total volume of the gaseous component.

6. The method of claim 1 wherein the unreactive gas is present in an amount of from about 0.01% to about 5% by total volume of the gaseous component.

7. The method of claim 1 further comprising: flowing at least a portion of the gaseous component comprising the unreactive gas out of the subterranean formation to a pipeline having at least one end disposed proximate to a well bore penetrating the subterranean formation.

8. 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 a pressure sufficient to create or enhance one or more fractures in at least a portion of the subterranean formation.

9. The method of claim 8 wherein the at least one unreactive gas is provided in a first gaseous stream and the natural gas is provided in a second gaseous stream that is different from the first gaseous stream.

10. The method of claim 9 wherein

the method further comprises mixing the first gaseous stream and the second gaseous stream to form a mixed gaseous stream, and

the step of mixing the liquid base fluid, the natural gas, and the at least one unreactive gas comprises mixing a liquid stream comprising the liquid base fluid with the mixed gaseous stream to form the fracturing fluid.

11. The method of claim 9 wherein the step of mixing the liquid base fluid, the natural gas, and the at least one unreactive gas comprises mixing a liquid stream comprising the liquid base fluid with the first gaseous stream and the second gaseous stream to form the fracturing fluid.

12. The method of claim 8 wherein providing gaseous natural gas comprises vaporizing liquefied natural gas (LNG) to form the gaseous natural gas.

13. The method of claim 8 wherein the unreactive gas is present in the fracturing fluid in an amount of from about 0.01% to about 5% by total volume of a gaseous component consisting of the natural gas and the unreactive gas.

14. The method of claim 8 wherein the unreactive gas is present in the fracturing fluid in an amount of from about 0.01% to about 25% by total volume of a gaseous component consisting of the natural gas and the unreactive gas.

15. The method of claim 8 further comprising:

providing a proppant material; and

mixing the proppant material with the liquid base fluid prior to mixing the liquid base fluid with the natural gas and the at least one unreactive gas.

16. The method of claim 8 further comprising: flowing at least a portion of the gaseous component comprising the unreactive gas out of the subterranean formation to a pipeline having at least one end disposed proximate to a well bore penetrating the subterranean formation.

17. 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.

18. The system of claim 17 wherein the natural gas source comprises at least one LNG tank, the natural gas pump comprises a high pressure natural gas pump, and the system further comprises a heater component fluidically coupled to an outlet of the high pressure natural gas pump.

19. The system of claim 17 further comprising at least one controller communicatively connected to one or more of the liquid base fluid pump, the natural gas pump, the mixer, and/or one or more valves fluidically connected to one or more of the liquid base fluid source, the natural gas source, and the unreactive gas source.

20. The system of claim 17 wherein the system does not comprise a flare in fluid communication with the wellhead.