US20170248308A1

Movatterモバイル変換

Info

Publication number: US20170248308A1
Application number: US15/056,228
Authority: US
Inventors: Sergey Makarychev-Mikhailov; Richard Hutchins; Christopher Daeffler
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2016-02-29
Filing date: 2016-02-29
Publication date: 2017-08-31

Abstract

The present disclosure is directed to an apparatus having a separator and mixing equipment. The separator is operable to receive exhaust from fuel-burning equipment at a wellsite and separate the exhaust into a gas component and water. The mixing equipment is operable to receive at least one of the gas component and the water to form a subterranean formation treatment fluid. The present disclosure is further directed to a method of operating fuel-burning equipment at a wellsite to form an exhaust and utilizing the exhaust to form a fluid for injecting into a wellbore to treat a subterranean formation into which the wellbore extends.

Description

BACKGROUND OF THE DISCLOSURE

A subterranean formation from which oil, gas, and/or other hydrocarbons are produced may utilize stimulation to enhance hydrocarbon flow from the formation, such as to make or keep operations economically viable. Stimulating production by fracturing the subterranean formation entails pumping high-pressure fluids into the formation via one or more wellbores extending into and in fluid communication with the formation.

A fracturing fluid for performing such fracturing operations may be or comprise an aqueous solution treated with various chemicals, such as surfactants, foamers, cross-linkers, and/or gelling agents. The fracturing fluid may further comprise non-aqueous fluids, such as oils (e.g., diesel, mineral oil, crude oil), liquefied gases (e.g., propane-butane blends), and/or combustion exhaust gases. The fracturing fluid may also include proppants, such as bauxite, sand, and/or ceramic particulates. However, utilizing fracturing fluids to perform fracturing operations may have certain drawbacks. For example, in some parts of the world, water utilized in creating the fracturing fluid may be difficult and/or expensive to obtain, while some fracturing fluids may not be sufficiently environmentally compatible. Still other fracturing fluids may not be sufficiently recoverable without also increasing the time in which fracturing operations can be completed, thus delaying the start of production or commercialization of hydrocarbons from the well and/or causing hydrocarbons to be lost during or after fracturing operations.

Furthermore, wellsite operations, including fracturing operations, often waste energy and produce heat and/or process byproducts that may be harmful to the environment. For example, fracturing operations produce substantial amounts of carbon dioxide. Carbon dioxide emissions are a major global pollutant, contributing to the atmospheric greenhouse effect and ocean acidification. Carbon dioxide is a by-product resulting from on-site burning of fuels, such as natural gas, petroleum, or coal.

SUMMARY OF THE DISCLOSURE

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.

The present disclosure introduces a method that includes operating fuel-burning equipment at a wellsite to form an exhaust, and utilizing the exhaust to form a fluid for injecting into a wellbore to treat a subterranean formation into which the wellbore extends.

The present disclosure also introduces a method that includes combusting a fuel at a wellsite, separating exhaust from the combustion into a gas component and water, and forming a subterranean formation treatment fluid including at least one of the gas component and water.

The present disclosure also introduces an apparatus that includes a separator and mixing equipment. The separator receives exhaust from fuel-burning equipment and separates the exhaust into a gas component and water. The mixing equipment receives at least one of the gas component and the water to form a subterranean formation treatment fluid.

The present disclosure also introduces an apparatus that includes a system operable to form a compositional component of a subterranean formation treatment fluid at a wellsite. The system includes a heat exchanger and a separator. The heat exchanger system receives and cools exhaust from fuel-burning equipment disposed at the wellsite. The separator separates exhaust cooled by the heat exchanger into a gas and water. The compositional component is at least one of the separated gas and water.

These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 2 is a schematic view of at least a portion of an example implementation of the apparatus shown inFIG. 1 according to one or more aspects of the present disclosure.

FIG. 3 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.

FIG. 4 is a flow-chart diagram of at least a portion of another example implementation of a method according to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.

Carbon dioxide and nitrogen may be utilized in subterranean formation treatment fluids, such as in foamed or energized fracturing fluids. Consequently, a substantial portion of foamed and energized fracturing fluids may utilize less water (e.g., up to about 80% less water in the case of the foamed fracturing fluid), provide improved proppant transport and cleanup compared to conventional fracturing fluids, and improve hydrocarbon production from water sensitive reservoirs.

Oxidation of certain fuels via combustion creates an exhaust comprising mainly carbon dioxide and water. If air is used as a source of oxygen, the exhaust will also contain a substantial concentration of nitrogen gas from the air. Combusting some fuels, such as diesel fuel, in air may also create an exhaust containing nitrogen oxides. For example, in diesel engines, nitrogen oxides may be converted to nitrogen gas (N₂) by diesel exhaust fluid (DEF). Nitrogen oxides may also be reduced with reducing agents included in the fracturing fluid.

The present disclosure introduces systems and methods for capturing and utilizing the carbon dioxide and nitrogen gases and the water contained within the exhaust generated by various fuel-burning or combusting equipment at a wellsite to form at least a portion of a subterranean formation treatment fluid. Such implementations may reduce the amount of carbon dioxide, nitrogen, and/or water having to be transported to the wellsite for inclusion in the subterranean formation treatment fluid. One or more aspects of the present disclosure may also be utilized to eliminate or reduce emission of greenhouse gases and other pollutants into the atmosphere by capturing and utilizing the exhaust generated by the fuel-burning equipment at the wellsite to form at least a portion of the subterranean formation treatment fluid.

The systems and methods within the scope of the present disclosure may utilize various hydrocarbon and/or non-hydrocarbon fuels to form the exhaust. A fuel within the scope of the present disclosure may include natural gas, methane, ethane, and/or another combustible hydrocarbon gas (hereinafter collectively referred to as “natural gas”) as a source of energy for fuel-burning engines and other fuel-burning equipment at the wellsite. The fuel within the scope of the present disclosure may further include oil condensate, gas condensate, diesel fuel, gasoline, coal, ethanol, biogas, syngas, and other biofuels, and/or other combustible fuels as a source of energy for the fuel-burning equipment at the wellsite. The fuel-burning equipment may include, for example, fracturing pump systems, gas compressor systems, electrical power generator systems, water heaters, heat exchangers (e.g., coolers), vehicles, and other wellsite equipment operable to burn the fuel described above for energy. The fuel may be transported to the wellsite, for example, via trucks or a pipeline. Combustion of the fuel, such as natural gas, substantially produces carbon dioxide and water, with minor compositional components of nitrogen oxides, sulfur oxides, and carbon monoxide. After the fuel is utilized for energy (e.g., burned or combusted) by the fuel-burning equipment, the exhaust may be captured, collected, and/or directed from the fuel-burning equipment to be utilized as a compositional component or an ingredient of one or more subterranean formation treatment fluids.

FIG. 1 is a schematic view of at least a portion of an example implementation of awellsite system100 utilized to form at least a portion of a subterranean formation treatment fluid according to one or more aspects of the present disclosure. Thewellsite system100 may be located at awellsite101 adjacent awellbore103 extending from thewellsite101 into a subterranean formation. Thewellsite system100 may include afluid separator102 that receives, via one ormore exhaust conduits113, exhaust generated by the fuel-burningequipment107 during wellsite operations, and that separates the exhaust into water and a gas. For clarity, the gas portion of the exhaust will be referred to hereinafter as a “gas component.” The separated water and/or gas component may be directed to different portions of thewellsite system100 to be utilized as a compositional component of the subterranean formation treatment fluid for injection into thewellbore103.

The fuel-burningequipment107 may include, for example, electric generator systems, pump systems, air and/or compressor systems, water heater systems, heat exchangers, vehicles, and/or other equipment operated at thewellsite101. The fuel-burningequipment107 may be fluidly coupled to receive the fuel from asource112 of fuel, and thefluid separator102 may be fluidly coupled to receive the exhaust from the fuel-burningequipment107 and separate the exhaust into the gas component and water. Thewellsite system100 may also include aheat exchanger114 fluidly coupled between the fuel-burningequipment107 and theseparator102, such as between portions of theexhaust conduit113. Theheat exchanger114 may reduce the temperature of the exhaust discharged from the fuel-burningequipment107 prior to the exhaust being received by theseparator102.

The water from theseparator102 may be communicated to one or

more mixing devices

122,124 viaconduits121. The mixing

devices

122,124 receive the water from theseparator102 and mix the water with other materials or compositional components received from

material sources

128,130, respectively, to form as least a portion of the subterranean formation treatment fluid. If the amount of water generated by the fuel-burningequipment107 and received from theseparator102 is insufficient to form the intended fluid, additional water may be supplied from awater source126.

In an example implementation of thewellsite system100, the mixing

devices

122,124 may be utilized to form a fracturing fluid. For example, themixing device122 may be a hydration unit operable to receive the water from theseparator102 and thewater source126 and a hydratable material from thematerial source128 to form a fluid, which may be or comprise that which is known in the art as a gel. Theother mixing device124 may be a blender operable for receiving the gel from themixing device122 and a proppant material from thematerial source130 to form a mixture, which may be or comprise that which is known in the art as a fracturing fluid. Themixing device124 may also receive additional materials or additives, such as foaming or surface-active agents or polymers operable to facilitate formation of a foam downstream, such as by lowering tension of the gas/liquid interface. The fuel-burningequipment107 may include afracturing pump system105, such as may comprise apump106 and anengine104 for actuating thepump106. The fracturing fluid may be communicated to thepump106 to be pumped or otherwise injected into thewellbore103.

Thewellsite system100 may also be utilized to form a gas compositional component, which may be utilized in a subterranean formation treatment fluid for injection into thewellbore103. For example, the fuel-burningequipment107 may include acompressor system109, such as may comprise acompressor110 and anengine108 for actuating thecompressor110. The

engines

104,108 may be fluidly coupled to receive the fuel from thesource112 of fuel, and thefluid separator102 may be fluidly coupled to receive the exhaust from the

engines

104,108 and separate the exhaust into the gas component and water. The exhaust may be communicated through theheat exchanger114 fluidly coupled along theexhaust conduit113 between the

engines

104,108 and theseparator102 to reduce the temperature of the exhaust prior to being received by theseparator102.

Thecompressor110 may be fluidly coupled with theseparator102 via one ormore conduits111, permitting thecompressor110 to receive and pressurize the gas component to an intended pressure for injection into thewellbore103. Thewellsite system100 may also include anotherheat exchanger115 located along theconduit111 between theseparator102 and thecompressor110. Theheat exchanger115 may be operable to further cool and/or liquefy the gas component discharged from theseparator102. Accordingly, thecompressor110 may be or comprise apump110, which may be operable to pump and/or compress the liquefied gas component for injection into thewellbore103. The compressed gas component may be mixed or combined with another fluid prior to being injected into thewellbore103.

If the amount of the gas component in the exhaust is insufficient to form the intended subterranean formation treatment fluid, the gas component generated by the fuel-burningequipment107 may be supplemented with a gas from asupplemental gas source116. Thesupplemental gas source116 may include one or more gas transports or containers transported to the wellsite101 from another location. The supplemental gas within thesupplemental gas source116 may be pressurized, such as may permit the supplemental gas to flow into thewellbore103. However, thesupplemental gas source116 may also comprise a pump (not shown), which may be operable to pump or otherwise move the supplemental gas in a gaseous or liquid state into theconduit111 to be combined with the gas component pressurized by thecompressor110. Thesupplemental gas source116 may also include a remote gas source located at a distance or otherwise outside thewellsite101 and fluidly connected with theconduit111. Thesupplemental gas source116 may supply thewellsite system100 with additional nitrogen, carbon dioxide, and/or other gases that may be utilized to form the subterranean formation treatment fluids.

The gases communicated via theconduit111 and the fluid communicated via theconduit121 may be received and combined at or by amixing device120 and jointly injected into thewellbore103. Themixing device120 may be or comprise a fluid junction, a tee connection, a wye connection, an eductor, a mixing valve, an inline mixer, a foam generator, and/or another device operable to combine and/or mix two or more streams of fluid.

Thewellsite system100 may be further utilized to form that which is known in the art as a foamed fracturing fluid or energized fracturing fluid. For example, the fracturing fluid formed by the mixing

devices

122,124 and pressurized by the fracturingpump system105 may be combined with the compressed gas component and/or the supplemental gas at themixing device120. The gases increase the volume of the fracturing fluid and dilute the fracturing fluid by reducing the concentration of the proppant material and other additives in the fracturing fluid. The added foaming or surface-active agents or polymers facilitate formation of a foam downstream when the fracturing fluid is combined with the gases. Depending on the foam quality, which is defined as a volumetric ratio of gas to a combined fluid (e.g., the gas and the fracturing fluid), the combined fluid may be or comprise the foamed fracturing fluid or the energized fracturing fluid.

FIG. 2 is a schematic view of at least a portion of an example implementation of thewellsite system100 shown inFIG. 1 according to one or more aspects of the present disclosure and designated inFIG. 2 byreference number200.FIG. 2 shows thewellsite system200 located at awellsite202 adjacent awellbore204, a partial sectional view of asubterranean formation206 penetrated by thewellbore204 below thewellsite202, and various pieces of wellsite equipment located at thewellsite202.

Thewellsite system200 may comprise amixer208 fluidly connected with one ormore tanks210 and acontainer212. Thecontainer212 may contain a material and thetanks210 may contain a liquid. The material may be or comprise a hydratable material or gelling agent, such as guar, polymers, synthetic polymers, galactomannan, polysaccharides, cellulose, and/or clay, among other examples. For clarity, the material contained within thecontainer212 will be referred to hereinafter as “hydratable material.” The liquid may be or comprise an aqueous fluid, which may comprise water or an aqueous solution comprising water, among other examples. For clarity, the liquid contained within thetanks210 will be referred to hereinafter as “water.” Themixer208 may be operable to receive the hydratable material and water, via two or

more conduits

214,216, and mix or otherwise combine the hydratable material and water to form a fluid, which may be or comprise that which is known in the art as a gel. Themixer208 may then discharge the gel via one ormore conduits218. Themixer208 and thecontainer212 may each be disposed on corresponding trucks, trailers, and/or other

mobile carriers

220,222, respectively, such as may permit their transportation to thewellsite202. However, themixer208 and/or thecontainer212 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at thewellsite202.

Thewellsite system200 may further comprise amixer224 fluidly connected with themixer208 and acontainer226. Thecontainer226 may contain a material that may be substantially different than the hydratable material. For example, the material within thecontainer226 may be or comprise a proppant material, such as sand, sand-like particles, silica, quartz, and/or propping agents, among other examples. For clarity, the material contained within thecontainer226 will be referred to hereinafter as “proppant material.” Themixer224 may be operable to receive the gel from themixer208 via one ormore conduits218, and the proppant material from thecontainer226 via one ormore conduits228, and mix or otherwise combine the gel and the proppant material to form a mixture. Themixer224 may also receive additional materials or additives, such as foaming or surface-active agents or polymers operable to facilitate formation of a foam downstream when mixed with other fluids. The mixture may be or comprise that which is known in the art as a fracturing fluid. Themixer224 may then discharge the fracturing fluid via one ormore conduits230. Themixer224 and thecontainer226 may each be disposed on corresponding trucks, trailers, and/or other

mobile carriers

232,234, respectively, such as may permit their transportation to thewellsite202. However, themixer224 and/orcontainer226 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at thewellsite202.

One or more compositional components of the fracturing fluid may be heated, such as to optimize the mixing and/or efficiency of the fracturing fluid during fracturing operations. Accordingly, awater heater237 may be fluidly coupled along theconduit214 to increase the temperature of the water flowing into themixer208 from thetanks210. Thewater heater237 may comprise aburner portion236 for generating heat and aheat exchanger portion238 for transferring the heat form theburner portion236 to the water flowing through theheat exchanger portion238. Thewater heater237 may be a fuel-burning piece of wellsite equipment operable to receive a fuel as a source of power to heat the water flowing into themixer208.

The fracturing fluid may be communicated from themixer224 to acommon manifold240 via the one ormore conduits230. Thecommon manifold240 may comprise a plurality of valves and diverters, as well as asuction line242 and adischarge line244, which may collectively direct the flow of the fracturing fluid in a selected or predetermined manner. Thecommon manifold240, which may be known in the art as a missile or a manifold trailer, may distribute the fracturing fluid to a fleet of fracturingpump systems250.

Each fracturingpump system250 comprises apump252, anengine254 operable to actuate thepump252, and perhaps aheat exchanger256 operable to cool theengine254. Eachpump system250 may receive the fracturing fluid from thesuction line242 of thecommon manifold240 via one or more conduits, and discharge the fracturing fluid under pressure to thedischarge line244 of thecommon manifold240 via one or more conduits. Eachpump system250 may be a fuel-burning piece of wellsite equipment, such as where eachengine254 is operable to receive the fuel as a source of power to actuate acorresponding pump252. The fracturing fluid may then be discharged from thecommon manifold240 into thewellbore204 via one ormore conduits246, awellhead205, and perhaps various valves, conduits, and/or other hydraulic circuitry (not shown) fluidly connected between thecommon manifold240 and thewellbore204. Thepump systems250 may each be mounted on corresponding trucks, trailers, and/or othermobile carriers258, such as may permit their transportation to thewellsite202. However, thepump systems250 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at thewellsite202. Although the pump fleet of thewellsite system200 is shown comprising sixpump systems250, the pump fleet may comprise other quantities ofpump systems250 within the scope of the present disclosure.

Thewellsite system200 may also comprise acontrol center260, which may be operable to provide control to one or more portions of thewellsite system200. Thecontrol center260 may be further operable to monitor health and functionality of one or more portions of thewellsite system200. Control signals may be communicated between thecontrol center260 and other wellsite equipment via electrical cables (not shown). However, other means of signal communication, such as wireless communication, are also within the scope of the present disclosure. Thecontrol center260 may be disposed on a corresponding truck, trailer, and/or othermobile carrier262, such as may permit its transportation to thewellsite202. However, thecontrol center260 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at thewellsite202.

Thewellsite system200 may also comprise an electric power source operable to provide electric power to one or more portions of thewellsite system200. The electric power source may be or comprise an engine-generator set265 (hereinafter referred to as a “generator system”), which includes anelectrical portion264, comprising an alternator for generating the electric power, and aprime mover portion266, comprising an actuator, such as a gas turbine or an internal combustion engine for actuating theelectrical portion264. Accordingly, thegenerator system265 may be a fuel-burning piece of wellsite equipment operable to receive the fuel as a source of power. For example, thegenerator system265 may be utilized to supply electrical power to thecontrol center260 and various other pieces of wellsite equipment to sustain wellsite operations, such as lighting, cranes, forklifts, feeders for transporting solid material, and pumps for transporting liquid material through pipelines. Thegenerator system265 may also be utilized to charge replaceable batteries of electric vehicles utilized for delivering equipment and materials to and within thewellsite202 and removing waste material from thewellsite202. Thegenerator system265 may also supply electricity to local communities. Thegenerator system265 may be disposed on a corresponding truck, trailer, and/or othermobile carrier267, such as may permit transportation to thewellsite202. However, thegenerator system265 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at thewellsite202.

A source of fuel may be provided at the wellsite202 to supply the fuel to power thewater heater237, the fracturingpump systems250, thegenerator system265, and other fuel-burning equipment. The source of fuel may include one or more natural gas transports orcontainers270 comprising liquefied natural gas (LNG), compressed natural gas (CNG), or another form of natural gas, transported to the wellsite202 from another location. Thecontainer270 may be disposed on a corresponding truck, trailer, and/or othermobile carrier272, such as may permit transportation to thewellsite202. However, thecontainer270 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at thewellsite202. The source of fuel may also include thewellbore204 or another wellbore (not shown) that produces natural gas at thewellsite202. The source of fuel may also be located at a distance or otherwise outside thewellsite202, and may include, for example, a natural gas well or a natural gas container (not shown), which may be fluidly connected with asupply conduit274 or another portion of thewellsite system200 via a pipeline orconduit271. One ormore supply conduits274 may fluidly connect theconduit271, thecontainer270, and/or thewellhead205 with the fuel-burning equipment, such as theengines254 of the fracturingpump systems250, theburner portion236 of thewater heater237, and/or theprime mover portion266 of thegenerator system265.

During fracturing or other wellsite operations, the exhaust generated by each of theengines254, theburner portion236, and theprime mover portion266 may be captured and directed into or through aheat exchanger280 via one ormore exhaust conduits276. Theheat exchanger280 cools or otherwise reduces the temperature of the exhaust discharged by the fuel-burning equipment prior to being received by aseparator286. Theheat exchanger280 may include a shell and tube heat exchanger, a plate heat exchanger, a plate and shell heat exchanger, a spiral heat exchanger, or a helical-coil heat exchanger, although other heat exchanger types are also within the scope of the present disclosure. Theheat exchanger280 may also utilize a vapor compression refrigeration cycle to cool down the exhaust. For example, theheat exchanger280 may comprise aprime mover portion282, comprising an engine for actuating or otherwise facilitating the vapor compression refrigeration cycle, and anevaporator portion284, comprising an evaporator operable to receive and absorb heat from the exhaust and, thus, cool the exhaust. Theheat exchanger280 may be a fuel-burning piece of wellsite equipment operable to receive the fuel via thesupply conduit274 as a source of power to facilitate the operation of theheat exchanger280. Similarly to the other fuel-burning equipment described above, exhaust from theprime mover portion282 of theheat exchanger280 may be directed into theevaporator portion284, such as via theexhaust conduit276, to cool the exhaust prior to being received by theseparator286.

After the exhaust is cooled to a predetermined temperature, the exhaust may be received by theseparator286 to be separated into a gas component and water. The separated water may be directed, pumped, or otherwise moved from theseparator286 to themixer208 via aconduit287 to be combined and/or mixed with the water from thetanks210 and the hydratable material from thecontainer212 to form a gel, as described above. The gas component may be directed, pumped, or otherwise moved to acompressor system290 via aconduit288 extending between theseparator286 and amixing device294. Thecompressor system290 pressurizes the gas component to a predetermined pressure prior to being injected into thewellbore204. Thewellsite system200 may also include another heat exchanger (not shown), which may be similar to theheat exchanger280 described above, but located along theconduit288 between theseparator286 and thecompressor portion291 of thecompressor system290. The heat exchanger may be operable to further cool and/or liquefy the gas component discharged from theseparator286. Accordingly, thecompressor portion291 may be or comprise a pump, which may be operable to pump and/or compress the liquefied gas component for injection into thewellbore204.

Thecompressor system290 may include acompressor portion291 comprising a compressor operable to receive and pressurize the gas component, and aprime mover portion292 comprising an engine for actuating thecompressor portion291. Thecompressor portion291 may include a positive displacement compressor, such as a rotary or reciprocating compressor, and a dynamic compressor, such as a centrifugal or axial compressor, although other compressor types are also within the scope of the present disclosure. Thecompressor portion291 may comprise a single or multi-stage compressor operable to increase the pressure of the gas component to a pressure suitable for injection into thewellbore204, which may be 10,000 pounds per square inch (PSI) or higher. Thecompressor system290 may be a fuel-burning piece of wellsite equipment operable to receive the fuel from the source of fuel via thesupply conduit274 to power the operation of thecompressor system290. Similarly to the other fuel-burning equipment described above, exhaust from theprime mover portion292 of thecompressor system290 may be directed into theevaporator portion284 of theheat exchanger280 via theexhaust conduit276 to cool the exhaust prior to being received by theseparator286.

After the gas component is pressurized to the predetermined pressure by thecompressor system290, the pressurized gas component may be mixed or combined with the fracturing fluid from thecommon manifold240 by themixing device294 joining the

conduits

246,288, such as may permit the gas component and the fracturing fluid to be jointly injected into thewellbore202 via thewellhead205. Themixing device294 may be or comprise a fluid junction, a tee connection, a wye connection, an eductor, a mixing valve, an inline mixer, and/or another device operable to combine and/or mix two or more streams of fluid. Themixing device294 may also be or comprise a fluid junction at thewellhead205, such as may be operable to combine the gas component and the fracturing fluid for injection into thewellbore204. Themixing device294 may also be or comprise a foaming device utilized, for example, to mix the compressed gas component from thecompressor system290 with the fracturing fluid from thecommon manifold240, such as to produce a foamed or energized fracturing fluid for delivery to thewellhead205. A polymer additive, a cross-linked polymer stabilizer, and/or another additive may be added to the gas component and/or the fracturing fluid by the foaming device to facilitate the formation of foam.

If the amount of the gas component in the exhaust is insufficient to form the intended foamed fracturing fluid, energized fracturing fluid, or other intended subterranean formation treatment fluid, the gas component generated by the fuel-burning equipment may be supplemented with gas from supplemental gas sources. The supplemental gas sources may supply additional nitrogen and/or carbon dioxide to be injected into thewellbore204 along with the fracturing fluid discharged from thecommon manifold240 and the pressurized gas component discharged by thecompressor290. The gases within the supplemental sources may be pressurized, such as may permit the gases to flow into theconduit246 or directly into thewellhead205. However, the supplemental gas sources may also comprise a pump (not shown) operable to pump or otherwise move the gas in a gaseous or liquefied state into theconduit246 to be combined with the fracturing fluid discharged by thecommon manifold240 and the gas component discharged by thecompressor290.

The supplemental gas sources may include gas transports or

containers

296,298 transported to awellsite202. Each

gas container

296,298 may be disposed on a corresponding truck, trailer, and/or other

mobile carrier

297,299, respectively, such as may permit transportation to thewellsite202. However, each

container

296,298 may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at thewellsite202. The supplemental gas sources may also include pipelines or conduits extending from a remote source of gas (not shown) located at a distance or otherwise outside thewellsite202. The gases from the

containers

296,298 or other supplemental gas sources may be mixed or combined with the fracturing fluid from thecommon manifold240 via

additional mixing devices

293,295, respectively, which may each have similar structure and/or operation as themixing device294. Depending on the foam quality, the combined fluid injected into thewellbore204 may be or comprise the foamed fracturing fluid or the energized fracturing fluid.

If a fraction of the gases injected into the wellbore return back to surface during flowback operations, such gases may be captured, compressed, and re-used by re-injecting the gases into the same or a different wellbore along with new fracturing fluid discharged from thecommon manifold240. Carbon dioxide may be captured by utilizing existing carbon dioxide sequestration technologies, such as calcium looping or amine scrubbing, or the carbon dioxide may be separated from nitrogen and injected into deep underground formations or depleted reservoirs for permanent storage.

Natural gas produced at thewellsite202 may be flared or burned, for example, if no pipelines or wellsite equipment are available for capturing, utilizing, or transporting such natural gas. Flaring may be performed via aflare stack207 located at thewellsite202 and fluidly connected with thewellhead205 or another portion of thewellsite system200 receiving natural gas produced from thewellbore204 or another wellbore. However, gas flaring wastes energy and negatively impacts the environment by generating and releasing carbon dioxide into the atmosphere. For example, in North Dakota in 2012 an estimated 217 million standard cubic feet (MMSCF) of natural gas was flared or vented. If exhaust from such flaring was collected, cooled, and separated, the exhaust would have yielded about 2.47 million gallons of water per day. Accordingly, exhaust produced during flaring operations may also be utilized to provide the gas component and water for use in subterranean formation treatment fluids. Similarly to the exhaust produced by the fuel-burning equipment, the exhaust produced at theflare stack207 during flaring operations may be captured and directed to theseparator280, such as via theexhaust conduit276, and further utilized as described above.

FIG. 2 shows thewellsite system200 operable to produce and/or mix fluids and/or mixtures that may be pressurized and individually or collectively injected into thewellbore204 during hydraulic fracturing of thesubterranean formation206. However, it is to be understood that thewellsite system200 may be operable to mix and/or produce other mixtures and/or fluids that may be pressurized and individually or collectively injected into thewellbore204 during other oilfield operations, such as drilling, cementing, acidizing, chemical injecting, and/or water jet cutting operations, among other examples.

Several studies were conducted to calculate or otherwise determine the feasibility of producing a foamed or energized fracturing fluid for conducting fracturing operations by utilizing the

wellsite systems

100,200 and methods described herein. The conclusions reached for each study were based on certain assumptions related to environmental conditions and job specifications.

A first study included determining an amount of natural gas consumed in relation to an amount of exhaust gas and water produced during a typical stage of a fracturing job. A typical fracturing job stage was assumed to consume 200,000 gallons of water and 400,000 pounds of sand to produce 5,200 barrels of fracturing fluid. The job included using sixteen fracturing pump systems operated continuously for 100 minutes consuming about 60 gallons of diesel fuel per hour, thus consuming a total of 1,600 gallons of diesel fuel. The fracturing job treating pressure was about 10,000 PSI, and the bottomhole static temperature was about 93.3 degrees Celsius (° C.). Standard atmospheric conditions were assumed to be 14.7 PSI and 15.6° C., such that at standard atmospheric conditions, one standard cubic foot (SCF) of gas was equal to about 1.198 mole of ideal gas.

With these assumptions in place, the fracturing fluid composed entirely of water was modified to comprise a 65% quality foam, wherein 65% of the volume of the fracturing fluid was replaced by a compressed gas or supercritical fluid. Accordingly, the fracturing job assumptions were modified to consume 70,000 gallons of water and about 6,018 thousand standard cubic feet (MSCF) of gas (about 17.4 thousand cubic feet (MCF) at 10,000 PSI and 93.3° C., calculated using the Peng-Robinson equation of state). The number of fracturing pump systems was reduced to six due to the lower volume of water being pumped. Furthermore, diesel-powered wellsite equipment was replaced with fuel-burning equipment operable to burn natural gas, wherein one gallon of diesel fuel was energetically equivalent to about 130 SCF of combustible gas supplied as natural gas. Accordingly, the fracturing pump systems were calculated to consume a total of 78 MSCF of natural gas.

Natural gas is a multi-component gas obtained from a crude oil well or from a subterranean gas-bearing formation. Natural gas obtained from a crude oil well is referred to as an associated gas, while natural gas obtained from a subterranean gas-bearing formation is referred to as a non-associated gas. The composition and pressure of natural gas may vary substantially. For example, a natural gas may comprise methane as a main component. Raw natural gas may also comprise ethane, other hydrocarbons, one or more acid gases (such as carbon dioxide, hydrogen sulfide, carbonyl sulfide, carbon disulfide, and mercaptans), and/or minor amounts of water, nitrogen, iron sulfide, wax, crude oil, and/or other contaminants.

Oxidation or combustion of methane, the main component of natural gas, and air generates water and carbon dioxide, as demonstrated by Equation (1).

CH₄+2O₂(+7.52N₂)→CO₂+2H₂O(+7.52N₂) (1)

where C is carbon, H is hydrogen, O is oxygen, and N is nitrogen. Equation (1) shows that a reaction between one mole of methane (CH₄), two moles of oxygen (2O₂), and 7.52 moles of nitrogen (N₂) produces one mole of carbon dioxide (CO₂), two moles of water (H₂O), and 7.52 moles of nitrogen.

Based on the modified fracturing job assumptions described above and Equation (1), calculations were conducted to determine the amount of water, nitrogen, and carbon dioxide produced from combustion of methane in air. With a mole fraction of air being about 0.79 nitrogen and 0.21 oxygen, a reaction between one mole of methane, two moles of oxygen, and 7.52 moles of nitrogen produces one mole of carbon dioxide, two moles of water, and 7.52 moles of nitrogen.

Accordingly, for each cubic foot of methane burned as fuel for the fracturing pump systems, 8.52 SCF of nitrogen and carbon dioxide blend may be produced for use in the fracturing fluid. Additionally, up to about 11.4 gallons of fresh water may be recovered from the exhaust of one MSCF of burned methane. Based on a complete recovery and separation of nitrogen and carbon dioxide blend (i.e., gas component) and water from the exhaust of the fracturing pump systems during a 100 minute fracturing job stage, it was determined that about 11% of the gas and about 1.2% of the water utilized for the typical fracturing job stage using the foamed fracturing fluid may be met.

A second study included evaluating the use of a natural gas-powered compressor system at the wellsite during the typical stage of the fracturing job described above. During such typical fracturing job stage, the exhaust that was captured from the fuel-burning equipment utilized in fracturing operations was initially collected at ambient pressure (14.7 PSI), but was pressurized to a fracturing pressure. Accordingly, the following assumptions were taken into account for the compression of the nitrogen and carbon dioxide blend: inlet or initial pressure was 14.7 PSI, the outlet or final pressure was 10,000 PSI, the adiabatic coefficient (Cp/Cv) was 1.395, the maximum compression ratio was 34.5, the number of compression stages was 20, the adiabatic compressor power output was 9,092 horsepower (HP), and the burner efficiency was 35%. Based on such assumptions and the exhaust utilized to form the fracturing fluid described above, it was determined that the compressor will utilize about 108 MSCF of natural gas during one fracturing stage, providing about 15% of the gas and about 2.7% of the water sufficient to form the foamed fracturing fluid for the typical fracturing job stage described above.

A third study included evaluating the use of a natural gas-powered generator system at the wellsite to supply electrical power to other pieces of equipment, such as lighting, control vehicles, cranes, forklifts, and perhaps electric vehicles during the typical stage of the fracturing job described above. For example, a natural gas-powered generator was assumed to produce exhaust at a flow rate of 11,844 cubic feet per minute (CFM) at an exhaust stack temperature of about 523.3° C. However, when the temperature of the exhaust was reduced to about 15.6° C., and assuming that the water was still in a gas phase, the exhaust was calculated to be produced at a flow rate of about 4,293 CFM. If the exhaust was separated into the gas component and water, the gas component would be produced at a flow rate of about 3,477 CFM and the water would be produced at a flow rate of about 4.7 gallons per minute (GPM). Accordingly, when utilized at a wellsite, it was determined that the exhaust produced by the generator may supply about 5.8% of the gas and about 0.66% of the water sufficient to form the foamed fracturing fluid for the typical fracturing job stage described above.

A fourth study included evaluating the use of a natural gas-powered water heater at the wellsite to heat the water utilized in the formation of the foamed fracturing fluid during a typical stage of a fracturing job. For example, to heat 70,000 gallons of water utilized in a typical fracturing job from about 4.5° C. to about 37.8° C., the water heater was calculated to utilize about 34.2 MSCF of natural gas. The exhaust from combustion of such amount of natural gas was determined to provide about 4.9% of the gas and about 0.56% of the water sufficient to form the foamed fracturing fluid for the typical fracturing job stage described above.

A fifth study included evaluating the use of a natural gas-powered heat exchanger or cooler at the wellsite to reduce the temperature of the exhaust produced by the various fuel-burning wellsite equipment. For example, to cool the exhaust from about 523.3° C. to about 37.8° C., it was estimated that the heat exchanger would utilize about 22.9 MSCF of natural gas to cool down the exhaust from the fuel-burning equipment described above and the heat exchanger itself. The exhaust from the heat exchanger was determined to provide about 3.2% of the gas and about 0.79% of the water sufficient to form the foamed fracturing fluid for the typical fracturing job stage described above.

Table 1 set forth below lists percentage gas and water contributions related to each piece of fuel-burning equipment evaluated in the studies described above. In total, the fuel-burning equipment located at the wellsite was determined to provide about 39.9% of the gas and about 5.9% of the water sufficient to form the foamed fracturing fluid described above.

TABLE 1

		Gas	Water
	Fuel-burning	Contribution	Contribution
Study	Equipment	(%)	(%)

1	Fracturing Pumps	11	1.2
2	Compressor	15	2.7
3	Generator	5.8	0.66
4	Water Heater	4.9	0.56
5	Heat Exchanger	3.2	0.79

Total	39.9	5.9

Furthermore, well conditions during treatment may vary substantially from job to job. For foamed fracturing fluids, the reservoir temperature and fracturing pressure play a substantial role, as the reservoir temperature and pressure affect compressibility and volume of the gas within the foamed fracturing fluid. Assuming substantially the same fracturing fluid volume (i.e., 65% foam quality and 70,000 gallons of water) for each typical fracturing stage, Table 2 set forth below lists the percentage of gas and water formed on-site under different bottomhole/reservoir conditions. As shown, under pressures of about 10,000 PSI or less, the on-site fuel-burning equipment may generate a majority of the gas sufficient to form the foamed or energized fracturing fluid. For example, at 10,000 PSI and 93.3° C., the fuel-burning equipment may generate about 51% of the gas and about 5.9% of the water sufficient to form the foamed fracturing fluid. At 5,000 PSI and 74.4° C., the fuel-burning equipment may generate about 67% of the gas and about 4.9% of the water sufficient to form the foamed fracturing fluid, while at 3,000 PSI and 50.6° C., the fuel-burning equipment may generate about 84% of the gas and about 4.3% of the water sufficient to form the foamed fracturing fluid.

TABLE 2

	Bottomhole
Fracturing	Static	Gas	Water
pressure	Temperature	Formed	Formed
(PSI)	(° C.)	(%)	(%)

3,000	50.6	88	4.3
5,000	74.4	62	4.9
10,000	93.3	39.9	5.9

As in many locations, fresh water may be scarce and expensive. Oil and gas service companies may spend between two and ten dollars to condition one barrel of produced water for use in fracturing operations. However, the natural gas price at the wellhead may be assumed to be about $1.00/MSCF, because the gas is non-treated and is free of transportation costs, sales markups, taxes, and speculation. Based on the stoichiometry of methane combustion, one barrel of water necessitates about 3.7 MSCF of methane, resulting in water cost of about $3.70/barrel, which is comparable with water treatment costs. Because the combustion generates fresh water, such water does not necessitate additional treatment and may be utilized to dilute high salinity produced waters. Utilizing the undiluted produced water in fracturing operations may have detrimental effects on well production due to poor fluid performance, scale deposition, and other factors. Table 5 set forth below lists amounts of methane to be combusted to fully supply the gas and water to form the foamed fracturing fluid during the typical fracturing stage described above. To produce the 70,000 gallons of water to form the foamed fracturing fluid, it was determined that about 6,140 MSCF of natural gas may be consumed by the fuel-burning equipment. To produce 100% of the gas utilized to form the foamed fracturing fluid utilized during the typical fracturing stage at 10,000 PSI and 93.3° C., about 705 MSCF of natural gas may be consumed by the fuel-burning equipment. To produce 100% of the gas utilized to form the foamed fracturing fluid at 5,000 PSI and 74.4° C., about 450 MSCF of natural gas may be consumed by the fuel-burning equipment. To produce 100% of the gas utilized to form the foamed fracturing fluid at 3,000 PSI and 50.6° C., about 317 MSCF of natural gas may be consumed by the fuel-burning equipment.

TABLE 3

	Bottomhole	Methane Combusted	Methane Combusted
Fracturing	Static	for Full Gas	for Full Water
Pressure	Temperature	Contribution	Contribution
(PSI)	(° C.)	(MSCF)	(MSCF)

3,000	50.6	317	6,140
5,000	74.4	450
10,000	93.3	705

FIG. 3 is a flow-chart diagram of at least a portion of an example implementation of a method (300) according to one or more aspects of the present disclosure. The method (300) may be performed utilizing at least a portion of one or more implementations of the apparatus shown inFIGS. 1 and 2 and/or otherwise within the scope of the present disclosure.

The method (300) comprises operating (310) fuel-burning equipment at a wellsite202 to form an exhaust, utilizing (320) the exhaust to form a fluid for injecting into awellbore204 to treat asubterranean formation206 into which thewellbore204 extends, and injecting (330) the fluid into thewellbore204. Utilizing (320) the exhaust to form the fluid may form a fracturing fluid comprising the exhaust, such that treating thesubterranean formation206 comprises fracturing thesubterranean formation206.

The method (300) may further comprise operating (340) afracturing pump system250 to inject the fracturing fluid into thewellbore204. The fracturingpump system250 may be a piece of the fuel-burning equipment forming the exhaust, and utilizing (320) the exhaust to form the fracturing fluid may utilize exhaust from the fracturingpump system250. Before utilizing (320) the exhaust to form the fluid, the method (300) may further comprise capturing and cooling (350) the exhaust and separating (360) the exhaust into a gas component and water, and utilizing (320) the exhaust to form the fluid may comprise forming the fluid utilizing at least one of the gas component and the water. The water may be fresh water, the method (300) may further comprise combining the fresh water with water produced from the wellbore (204) to dilute the produced water, and forming (320) the fluid may comprise forming a fracturing fluid comprising the diluted produced water.

The method (300) may also comprise compressing (370) the gas component, and utilizing (320) the exhaust to form the fluid may include forming a foamed fracturing fluid comprising the compressed gas component. The gas component may comprise carbon dioxide and/or nitrogen. Compressing (370) the gas component may comprise compressing the gas component with acompressor system290, wherein thecompressor system290 is a piece of the fuel-burning equipment forming the exhaust, and utilizing (320) the exhaust to form the fluid may utilize the compressor system exhaust.

The fuel-burning equipment may comprise at least one of anelectric generator system265, a fracturingpump system250, acompressor system290, awater heater system237, and aheat exchanger system280. Operating (310) the fuel-burning equipment may comprise operating the fuel-burning equipment to burn (380) natural gas at the wellsite to form the exhaust, wherein the natural gas may be produced from thesubterranean formation206 at thewellsite202. Operating (310) the fuel-burning equipment may also comprise operating aflare stack207 to burn natural gas produced from thesubterranean formation206 at the wellsite202 during gas flaring operations to form the exhaust.

Utilizing (320) the exhaust to form the fluid may further comprise forming a foamed fracturing fluid by combining (390) the compressed gas component and a mixture comprising the water and a proppant material. Utilizing (320) the exhaust to form the fluid may also reduce greenhouse gas emission at the wellsite relative to forming the fluid without utilizing the exhaust.

FIG. 4 is a flow-chart diagram of at least a portion of another example implementation of a method (400) according to one or more aspects of the present disclosure. The method (400) may be performed utilizing at least a portion of one or more implementations of the apparatus shown inFIGS. 1 and 2 and/or otherwise within the scope of the present disclosure.

The method (400) may comprise combusting (405) fuel at awellsite202, separating (410) exhaust from the combustion into a gas component and water, forming (415) a subterranean formation treatment fluid comprising at least one of the gas component and water, and injecting (420) the fluid into thewellbore204. Forming (415) the subterranean formation treatment fluid may comprise forming a fracturing fluid comprising at least one of the gas component and water.

The method (400) may further comprise operating (430) afracturing pump system250 to inject the fracturing fluid into thewellbore204, wherein the fracturingpump system250 combusts (405) the fuel to form the exhaust, and wherein separating (410) the exhaust from the combustion comprises separating the exhaust from the fracturingpump system250 into the gas component and water. The gas component may comprise carbon dioxide and/or nitrogen. Before separating (410) the exhaust, the exhaust may be captured and perhaps cooled (435).

The separated water may be fresh water, the method (400) may further comprise combining (440) the fresh water with water produced at the wellsite202 to dilute the produced water, and forming (415) the subterranean formation treatment fluid may comprise forming a fracturing fluid comprising the diluted produced water.

The gas component may be compressed (445) such that forming (415) the subterranean formation treatment fluid may include forming a foamed fracturing fluid comprising the compressed gas component. The gas component may be compressed (445) with a compressor system (290), wherein thecompressor system290 combusts (450) the fuel to form the exhaust, and wherein separating (410) the exhaust from the combustion comprises separating the exhaust from thecompressor system290 into the gas component and water. After compressing the gas component, forming (415) the subterranean formation treatment fluid may comprise forming a foamed fracturing fluid by combining (455) the compressed gas component and a mixture comprising the water and a proppant material.

Combusting (405) the fuel at thewellsite202 may further comprise combusting (460) natural gas at thewellsite202. The natural gas may be produced from asubterranean formation206 at thewellsite202. Combusting (405) the fuel at thewellsite202 may further comprise combusting the fuel at the wellsite202 with at least one of an electric generator system, a fracturing pump system, a compressor system, a water heater system, and a heat exchanger system. Combusting (405) the fuel at thewellsite202 may also comprise operating aflare stack207 to burn natural gas produced from thesubterranean formation206 at the wellsite202 during gas flaring operations to form the exhaust.

Forming (415) the subterranean formation treatment fluid may reduce greenhouse gas emission at thewellsite202 relative to when forming the subterranean formation treatment fluid without utilizing at least one of the gas component and water.

In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces a method comprising: operating fuel-burning equipment at a wellsite to form an exhaust; and utilizing the exhaust to form a fluid for injecting into a wellbore to treat a subterranean formation into which the wellbore extends.

The method may further comprise injecting the fluid into the wellbore.

Utilizing the exhaust to form the fluid may form a fracturing fluid comprising the exhaust, and treating the subterranean formation may comprise fracturing the subterranean formation. In such implementations, among others within the scope of the present disclosure, the method may further comprise operating a fracturing pump system to inject the fracturing fluid into the wellbore. The fracturing pump system may be a piece of the fuel-burning equipment forming the exhaust, and utilizing the exhaust to form the fracturing fluid may utilize exhaust from the fracturing pump system.

The method may further comprise capturing and cooling the exhaust before utilizing the exhaust to form the fluid.

The method may further comprise separating the exhaust into a gas component and water, and utilizing the exhaust to form the fluid may comprise forming the fluid utilizing at least one of the gas component and the water. The gas component may comprise carbon dioxide and/or nitrogen. The water may be fresh water, the method may further comprise combining the fresh water with water produced from the wellbore to dilute the produced water, and forming the fluid may comprise forming a fracturing fluid comprising the diluted produced water. The method may further comprise compressing the gas component, and forming the fluid may comprise forming a foamed fracturing fluid comprising the compressed gas component. Compressing the gas component may comprise compressing the gas component with a compressor system, the compressor system may be a piece of the fuel-burning equipment forming the exhaust, and utilizing the exhaust to form the fluid may utilize the compressor system exhaust. The method may further comprise compressing the gas component, and forming the fluid may comprise forming a foamed fracturing fluid by combining the compressed gas component and a mixture comprising the water and a proppant material.

The fuel-burning equipment may comprise at least one of an electric generator system, a fracturing pump system, a compressor system, a water heater system, and a heat exchanger system.

Operating the fuel-burning equipment may comprise operating the fuel-burning equipment to burn natural gas at the wellsite to form the exhaust. In such implementations, among others within the scope of the present disclosure, the method may further comprise producing the natural gas from the subterranean formation at the wellsite.

Operating fuel-burning equipment may comprise operating a flare stack to burn natural gas produced from the subterranean formation at the wellsite during gas flaring operations to form the exhaust.

Utilizing the exhaust to form the fluid may reduce greenhouse gas emission at the wellsite relative to forming the fluid without utilizing the exhaust.

The present disclosure also introduces a method comprising: combusting a fuel at a wellsite; separating exhaust from the combustion into a gas component and water; and forming a subterranean formation treatment fluid comprising at least one of the gas component and water.

The method may further comprise injecting the fluid into the wellbore.

Forming the subterranean formation treatment fluid may comprise forming a fracturing fluid comprising at least one of the gas component and water. In such implementations, among others within the scope of the present disclosure, the method may further comprise operating a fracturing pump system to inject the fracturing fluid into the wellbore. The fracturing pump system may combust the fuel to form the exhaust, and separating the exhaust from the combustion may comprise separating the exhaust from the fracturing pump system into the gas component and water.

The method may further comprise capturing and cooling the exhaust before separating the exhaust.

The water may be fresh water, the method may further comprise combining the fresh water with water produced at the wellsite to dilute the produced water, and forming the subterranean formation treatment fluid may comprise forming a fracturing fluid comprising the diluted produced water.

The gas component may comprise carbon dioxide and/or nitrogen.

The method may further comprise compressing the gas component, and forming the subterranean formation treatment fluid may comprise forming a foamed fracturing fluid comprising the compressed gas component. Compressing the gas component may comprise compressing the gas component with a compressor system, the compressor system may combust the fuel to form the exhaust, and separating the exhaust from the combustion may comprise separating the exhaust from the compressor system into the gas component and water.

The method may further comprise compressing the gas component, and forming the subterranean formation treatment fluid may comprise forming a foamed fracturing fluid by combining the compressed gas component and a mixture comprising the water and a proppant material.

Combusting the fuel at the wellsite may comprise combusting the fuel at the wellsite with at least one of an electric generator system, a fracturing pump system, a compressor system, a water heater system, and a heat exchanger system.

Combusting the fuel at the wellsite may comprise combusting natural gas at the wellsite. In such implementations, among others within the scope of the present disclosure, the method may further comprise producing the natural gas from a subterranean formation at the wellsite.

Combusting the fuel at the wellsite may comprise operating a flare stack to burn natural gas produced from the subterranean formation at the wellsite during gas flaring operations to form the exhaust.

Forming the subterranean formation treatment fluid comprising at least one of the gas component and water may reduce greenhouse gas emission at the wellsite relative to forming the subterranean formation treatment fluid without utilizing at least one of the gas component and water.

The present disclosure also introduces an apparatus comprising: a separator operable to receive exhaust from fuel-burning equipment and separate the exhaust into a gas component and water; and mixing equipment operable to receive at least one of the gas component and the water to form a subterranean formation treatment fluid.

The apparatus may further comprise a heat exchanger operable to reduce the temperature of the exhaust from the fuel-burning equipment prior to being received by the separator.

The gas component may comprise carbon dioxide and/or nitrogen.

The apparatus may further comprise a compressor system operable to compress the gas component prior to being received by the mixing equipment. The compressor system may be an instance of the fuel-burning equipment forming the exhaust, and the exhaust received by the separator may include the compressor system exhaust. The subterranean formation treatment fluid may be a foamed fracturing fluid, and the mixing equipment may be operable to receive the compressed gas component to form the foamed fracturing fluid. The subterranean formation treatment fluid may be a foamed fracturing fluid, and the mixing equipment may be operable to receive the compressed gas component and a mixture comprising the water and a proppant material to form the foamed fracturing fluid.

The subterranean formation treatment fluid may comprise a fracturing fluid for performing well fracturing operations. In such implementations, among others within the scope of the present disclosure, the mixing equipment may comprise at least one of: a gel mixer operable to form a gel comprising the water and a hydratable material; and/or a proppant mixer operable to form a slurry comprising the gel and a proppant material. The apparatus may further comprise a fracturing pump system operable for injecting the fracturing fluid into a wellbore extending into the subterranean formation, the fracturing pump system may be an instance of the fuel-burning equipment forming the exhaust, and the exhaust received by the separator may include the fracturing pump system exhaust.

The fuel-burning equipment may comprise at least one of a heat exchanger system, a compressor system, an electric generator system, a fracturing pump system, and a water heater system.

The fuel-burning equipment may be operable to burn natural gas. The natural gas may be produced from a wellbore extending into the subterranean formation at a wellsite comprising the apparatus. The fuel-burning equipment may comprise a flare stack for combusting the natural gas during flaring operations to form the exhaust.

The present disclosure also introduces an apparatus comprising: a system operable to form a compositional component of a subterranean formation treatment fluid at a wellsite, wherein the system comprises: a heat exchanger system disposed at the wellsite and operable to receive and cool exhaust from fuel-burning equipment disposed at the wellsite; and a separator disposed at the wellsite and operable to separate exhaust cooled by the heat exchanger into a gas and water, wherein the compositional component is at least one of the separated gas and water.

The separated gas may comprise carbon dioxide and/or nitrogen.

The apparatus may further comprise a compressor system operable to compress the separated gas prior to being injected into a wellbore. The compressor system may be an instance of the fuel-burning equipment forming the exhaust, and the exhaust received by the separator may include the compressor system exhaust. The subterranean formation treatment fluid may be a foamed fracturing fluid, and the mixing equipment may be operable to receive the compressed separated gas to form the foamed fracturing fluid. The subterranean formation treatment fluid may be a foamed fracturing fluid, and the system may be further operable combine the compressed separated gas and a mixture comprising the separated water and a proppant material to form the foamed fracturing fluid.

The subterranean formation treatment fluid may comprise a fracturing fluid for performing well fracturing operations, and the system may further comprise at least one of: a gel mixer operable to form a gel comprising the separated water and a hydratable material; and/or a proppant mixer operable to form a slurry comprising the gel and a proppant material. The apparatus may further comprise a fracturing pump system operable for injecting the fracturing fluid into a wellbore extending into a subterranean formation, the fracturing pump system may be an instance of the fuel-burning equipment forming the exhaust, and the exhaust received by the separator may include the fracturing pump system exhaust.

The fuel-burning equipment may be operable to burn natural gas. The natural gas may be produced from a wellbore extending into a subterranean formation at the wellsite. The fuel-burning equipment may comprise a flare stack for combusting the natural gas during gas flaring operations to form the exhaust.

The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.