Patent Publication Number: US-2023160293-A1

Title: Conversion of carbon dioxide captured from fracturing operation to formic acid used in fracturing fluid

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not applicable. 
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     TECHNICAL FIELD 
     The present disclosure relates generally to systems and methods of sequestering carbon dioxide (CO 2 ). More specifically, this disclosure relates to collecting exhaust gas comprising CO 2  and forming formic acid utilizing at least a portion of the CO 2  in the collected exhaust gas. Still more specifically, this disclosure relates to collecting exhaust gas comprising CO 2 , separating high purity CO 2  from the collected exhaust gas, forming formic acid utilizing at least a portion of the high purity CO 2 , and utilizing the formic acid in a wellbore servicing fluid (e.g., a fracturing fluid). 
     BACKGROUND 
     Natural resources (e.g., oil or gas) residing in a subterranean formation can be recovered by driving resources from the formation into a wellbore using, for example, a pressure gradient that exists between the formation and the wellbore, the force of gravity, displacement of the resources from the formation using a pump or the force of another fluid injected into the well or an adjacent well. A number of wellbore servicing fluids can be utilized during the formation and production from such wellbores. For example, in embodiments, the production of fluid in the formation can be increased by hydraulically fracturing the formation. That is, a treatment fluid (e.g., a fracturing fluid) can be pumped down the wellbore to the formation at a rate and a pressure sufficient to form fractures that extend into the formation, providing additional pathways through which the oil or gas can flow to the well. Subsequently, oil or gas residing in the subterranean formation can be recovered or “produced” from the well by driving the fluid into the well. During production of the oil or gas, substantial quantities of produced water, which can contain high levels of total dissolved solids (TDS), and produced gas can also be produced from the well, and a variety of exhaust gases and flare gases conventionally sent to flare can be formed. For example, oil and gas wells produce oil, gas, and/or byproducts from subterranean formation hydrocarbon reservoirs. A variety of subterranean formation operations are utilized to obtain such hydrocarbons, such as drilling operations, completion operations, stimulation operations, production operations, enhanced recovery operations, and the like. Such subterranean formation operations typically use a large number of vehicles, heavy equipment, and other apparatus (collectively referred to as “machinery” herein) in order to achieve certain job requirements, such as treatment fluid pump rates. Such equipment may include, for example, pump trucks, sand trucks, cranes, conveyance equipment, mixing machinery, and the like. Many of these operations and machinery utilize combustion engines that produce exhaust gases (e.g., including carbon dioxide (CO 2 )/greenhouse gas emissions) that are emitted into the atmosphere. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of this disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts. 
         FIG.  1    is a schematic flow diagram of a method, according to one or more embodiments of this disclosure; 
         FIG.  2    is a schematic of a system, according to one or more embodiments of the present disclosure; 
         FIG.  3    is a schematic of a plurality of machinery that may be located and operated a wellsite for performing a subterranean formation operation and may produce exhaust gas comprising CO 2 , according to one or more embodiments of the present disclosure; 
         FIG.  4    is a schematic of a reaction apparatus, according to one or more embodiments of the present disclosure; and 
         FIG.  5    is a schematic of a catalytic reaction process suitable for use in an electrocatalytic reaction apparatus, according to one or more embodiments of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     It should be understood at the outset that although an illustrative implementation of one or more embodiments are provided below, the disclosed systems and/or methods can be implemented using any number of techniques, whether currently known or in existence. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques below, including the exemplary designs and implementations illustrated and described herein, but can be modified within the scope of the appended claims along with their full scope of equivalents. 
     Carbon dioxide may now be considered a pollutant, and is a product that can be created in significant volumes with oilfield operating equipment, such as hydraulic horsepower pumping units on hydraulic fracturing locations in the field. For example, 150 to 300 metric tons of CO 2  per day per fracturing crew can be produced. Via the system and method of this disclosure, CO 2  emissions can be reduced by the formation of formic acid and the introduction of the formic acid downhole, for example as a component of a wellbore servicing fluid. Accordingly, the system and method described herein enable sequestering of CO 2  and a reduction of greenhouse gas (e.g., CO 2 ) emissions. 
     Via the system and method of this disclosure, exhaust gas can be captured at a wellsite (e.g., a hydraulic fracturing location), carbon dioxide separated therefrom, and the separated carbon dioxide utilized to form formic acid. The formic acid can be reintroduced downhole. For example, in embodiments, the formic acid can be incorporated into the hydraulic fracturing fluid and be injected downhole for long term sequestration. Formic acid is formation friendly, and is easier to reinject into a well than carbon dioxide as it requires no compression on location. 
     A method of this disclosure will now be described with reference to  FIG.  1   , which is a schematic flow diagram of a method I according to one or more embodiments of this disclosure. As seen in  FIG.  1   , method I includes collecting exhaust gas comprising carbon dioxide (CO 2 ) at a wellsite to provide a collected exhaust gas at  10 , separating CO 2  from the collected exhaust gas to provide a separated CO 2  at  30 , and forming formic acid utilizing at least a portion of the separated CO 2  at  40 . A method I of this disclosure can further comprise separating solids (e.g., dust, soot, ash) from the exhaust gas (e.g., from the produced exhaust gas or the collected exhaust gas) at  20 ; forming a wellbore servicing fluid (WSF) comprising at least a portion of the formic acid at  50 ; and/or introducing the WSF downhole at  60 . Although depicted in a certain order in  FIG.  1   , in embodiments, one or more of steps  10  to  60  can be absent, and/or one or more of the steps  10  to  60  can be performed more than once and/or in a different order than described herein or depicted in the embodiment of  FIG.  1   . 
     The method of this disclosure will now be detailed and a system for carrying out the method according to embodiments of this disclosure described with reference to  FIG.  2   , which is a schematic of a system  100  according to one or more embodiments of this disclosure. 
     With reference now to  FIG.  2   , system  100  comprises: an exhaust gas collection system  110  configured for collecting exhaust gas comprising carbon dioxide (CO 2 ) from exhaust gas  107  produced by exhaust gas production equipment or “machinery”  105  at a wellsite  170  to provide a collected exhaust gas  115  (e.g., step  10  of  FIG.  1   ); a CO 2  separation apparatus  130  configured for separating CO 2  from the collected exhaust gas to provide a separated CO 2    135  (e.g., step  30  of  FIG.  1   ); and a reaction apparatus  140  configured for forming formic acid  145  utilizing at least a portion of the separated CO 2    135  (e.g., step  40  of  FIG.  1   ). As depicted in  FIG.  2   , system  100  can further comprise solids removal apparatus  120  configured to separate solids (e.g., soot, dust) from the collected exhaust gas  115  (e.g., step  20  of  FIG.  1   ), WSF production apparatus  150  configured to produce a WSF, wherein the wellbore servicing fluid comprises at least a portion of the formic acid (e.g., step  50  of  FIG.  1   ), and/or pumping apparatus  160  configured for pumping the formic acid  145  and/or wellbore servicing fluid  155  downhole at the wellsite  170  or another wellsite, via a wellbore  175 , whereby the formic acid is sequestered downhole (e.g., in a formation, reservoir  177 ) (e.g., step  60  of  FIG.  1   ). 
     Method I comprises, at  10 , collecting exhaust gas comprising CO 2  at a wellsite  170  to provide a collected exhaust gas  115 . An exhaust gas collection system  110  can be configured to collect the collected exhaust gas  115  from exhaust gas  107  produced via exhaust gas production equipment  105 . Exhaust gas collection system  110  is configured to collect exhaust gas  107  from exhaust gas production equipment  105 , such as machinery  180  ( FIG.  3   , discussed hereinbelow) at a wellsite  170 . The field gas operating equipment  180  can comprise one or more vehicles (e.g., diesel trucks, cars, etc.), pumps (e.g., hydraulic pumps, fracturing pumps, etc.), or other equipment at a wellsite  170  that produces an exhaust gas  107  comprising CO 2  from which collected exhaust gas  115  can be collected. Exhaust gas collection apparatus  110  can include piping configured to combine the exhaust gas  107  from a plurality of the exhaust gas production equipment  105  (e.g., machinery  180  of  FIG.  3   ) to provide the collected exhaust gas  115 , and introduce the collected exhaust gas  115  to CO 2  separation apparatus  120 , storage apparatus to store the collected exhaust gas  115  prior to introduction into CO 2  separation apparatus  130 , or a combination thereof. Collecting the collected exhaust gas  115  comprising CO 2  at  10  can be performed by piping exhaust gas  107  from one or more pieces of exhaust gas production equipment  105  (e.g., field machinery  180  at a wellsite  170 , described hereinbelow with reference to  FIG.  3   ) together to provide the collected exhaust gas  115 . 
     The exhaust gas comprising CO 2    107  from which collected exhaust gas  115  is collected in exhaust gas collection system  110  can include greater than or equal to about 0.04, 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 95, or 100 volume percent (vol. %) CO 2 . By way of examples, the exhaust gas comprising CO 2    107  can include a waste gas, or one or more components thereof, produced at the wellsite  170  or another jobsite, such as, without limitation, one or more wellsites or industrial plants. The one or more industrial plants can include, without limitation, a cement plant, a chemical processing plant, a mechanical processing plant, a refinery, a steel plant, a power plant (e.g., a gas power plant, a coal power plant, etc.), or a combination and/or a plurality thereof. In embodiments, the exhaust gas comprising CO 2    115  comprises a waste (or “exhaust”) gas that is a product of fuel combustion, for example, the product of an internal combustion engine, or a gas fired turbine engine, such as, for example, from a microgrid having electric pumps. In embodiments, the internal combustion engine includes an engine fueled by diesel, natural gas (e.g., methane), gasoline, or a combination thereof (e.g., a diesel engine, or a hybrid engine that is fueled by diesel and natural gas). The exhaust gas comprising CO 2    115  can be produced at the wellsite  170  and/or another jobsite. A plurality of machinery  180  can be located and operated at a wellsite  170  for performing a subterranean formation operation, according to one or more embodiments of the present disclosure, and the exhaust gas comprising CO 2  can, in embodiments, be obtained therefrom. For example, the collected exhaust gas comprising CO 2    115  can be produced at the wellsite  170  or another wellsite from machinery  180  used to perform a wellbore servicing operation. Such wellbore servicing operations include, without limitation, drilling operations, completion operations, stimulation operations, production operations, enhanced recovery operations, and the like. The machinery may include one or more internal combustion or other suitable engines that consume fuel to perform work at the wellsite  170  and produce exhaust gas comprising CO 2    107 . 
     The wellbore  175  at wellsite  170  may be a hydrocarbon-producing wellbore (e.g., oil, natural gas, and the like) or another type of wellbore for producing other resources (e.g., mineral exploration, mining, and the like). Machinery  180  typically associated with a subterranean formation operation related to a hydrocarbon producing wellbore, and from which the exhaust gas comprising CO 2  can be produced, can be utilized to perform such operations as, for example, a cementing operation, a fracturing operation, or other suitable operation where equipment is used to drill, complete, produce, enhance production, and/or work over the wellbore. Other surface operations may include, for example, operating or construction of a facility. 
     As depicted in  FIG.  3   , which is a schematic of a plurality of machinery  180  that can be included in exhaust gas production equipment  105 , the machinery  180  may be located and operated a wellsite  170  for performing a subterranean formation operation and may produce exhaust gas  107  comprising CO 2 , according to one or more embodiments of the present disclosure. The machinery from which the exhaust gas comprising CO 2  can be produced, in embodiments, can include sand machinery  181 , gel machinery  182 , blender machinery  183 , pump machinery  184 , generator machinery  185 , positioning machinery  186 , control machinery  187 , and/or other machinery  188 . The machinery may be, for example, truck, skid or rig-mounted, or otherwise present at the wellsite  170 , without departing from the scope of the present disclosure. The sand machinery  181  may include transport trucks or other vehicles for hauling to and storing at the wellsite  170  sand for use in an operation. The gel machinery  182  may include transport trucks or other vehicles for hauling to and storing at the wellsite  170  materials used to make a gelled treatment fluid for use in an operation. The blender machinery  183  may include blenders, or mixers, for blending materials at the wellsite  170  for an operation. The pump machinery  184  may include pump trucks or other vehicles or conveyance equipment for pumping materials down the wellbore  175  for an operation. The generator machinery  185  may include generator trucks or other vehicles or equipment for generating electric power at the wellsite  170  for an operation. The electric power may be used by sensors, control machinery, and/or other machinery. The positioning equipment  186  may include earth movers, cranes, rigs or other equipment to move, locate or position equipment or materials at the wellsite  170  or in the wellbore  175 . 
     The control machinery  187  may include an instrument truck coupled to some, all, or substantially all of the other equipment at the wellsite  170  and/or to remote systems or equipment. The control machinery  187  may be connected by wireline or wirelessly to other equipment to receive data for or during an operation. The data may be received in real-time or otherwise. In another embodiment, data from or for equipment may be keyed into the control machinery. 
     The control machinery  187  may include a computer system for planning, monitoring, performing or analyzing the job. Such a computer system may be part of a distributed computing system with data sensed, collected, stored, processed and used from, at or by different equipment or locations. The other machinery  188  may include equipment also used at the wellsite  170  to perform an operation. 
     In other examples, the other machinery  188  may include personal or other vehicles used to transport workers to the wellsite  170  but not directly used at the wellsite  170  for performing an operation. 
     Many if not most of these various machinery at the wellsite  170  accordingly utilize a diesel or other fuel types to perform their functionality. Such fuel is expended and exhausted as exhaust gas, such as exhaust gas including CO 2 . The embodiments described herein provide a system and method for collecting, converting to formic acid, and, in embodiments, introducing the formic acid  145  downhole, thus sequestering CO 2  from such machinery  180  located and operated at a wellsite  170 , and reducing atmospheric CO 2  emissions, while reducing material and time costs. It is to be appreciated that other configurations of the wellsite  170  may be employed, without departing from the scope of the present disclosure. Although a number of various machinery  180  at wellsite  170  have been mentioned, many other machinery may utilize diesel or other fuel that creates exhaust gas including CO 2  that may conventionally be exhausted into the atmosphere, but herein utilized to form formic acid as described herein. 
     In some embodiments, the present disclosure provides collecting exhaust gas including CO 2    115  from such machinery  180  located and operated at a wellsite  170  and utilizing such collected exhaust gas  115  to form formic acid  145  as detailed herein. In embodiments, exhaust gas  107  is produced by fracturing equipment (e.g., hydraulic fracturing pumping equipment  184 , hydraulic horsepower pumping units  184 , electrical generation natural gas turbine units  188 , electrical generation reciprocating natural gas power units  185 , or a combination thereof) utilized to fracture a formation during a fracturing operation in formation  177 . 
     Although described hereinabove with reference to a wellsite  170 , a source of the exhaust gas comprising CO 2    107  that is collected at step  10  of the method I can be any convenient exhaust gas. The exhaust gas source can be a gaseous CO 2  source. This gaseous exhaust gas may vary widely, ranging from air, industrial waste streams, etc. As noted above, the exhaust gas can, in certain instances, include an exhaust waste product from an industrial plant. The nature of the industrial plant may vary in these embodiments, where industrial plants of interest include power plants, chemical processing plants, and other industrial plants that produce exhaust gas comprising CO 2  as a byproduct. By waste stream is meant a stream of gas (or analogous stream) that is produced as a byproduct of an active process of the industrial plant, e.g., an exhaust gas. The gaseous stream may be substantially pure CO 2  or a multi-component gaseous stream that includes CO 2  and one or more additional gases. Multi-component gaseous streams (containing CO 2 ) that may be employed as a CO 2  source in embodiments of the subject methods include both reducing, e.g., syngas, shifted syngas, natural gas, and hydrogen and the like, and oxidizing condition streams, e.g., flue gases from combustion. Particular multi-component gaseous streams of interest that may be treated according to the subject invention include: oxygen containing combustion power plant flue gas, turbo charged boiler product gas, coal gasification product gas, shifted coal gasification product gas, anaerobic digester product gas, wellhead natural gas stream, reformed natural gas or methane hydrates, and the like. 
     As noted above, in embodiments, the exhaust gas comprising CO 2    115  can comprise greater than or equal to about 5, 6, 7, 8, 9, 10, 15, 20, 25, 30, 40, 50, 60, 70, 80, 90, 95, 96, 97, 98, 99, or 100 volume percent (vol %) CO 2 . In embodiments, the exhaust gas comprising CO 2    115  includes primarily CO 2  (e.g., greater than or equal to about 50, 60, 70, 80, 90, 95, 96, 97, 98, 99, or 100 volume percent (vol %) CO 2 ). For example, when the exhaust gas comprising CO 2    115  is obtained from a waste gas produced at a different jobsite than the wellsite  170 , CO 2  can be separated from the waste gas in order to reduce a volume of gas to be transported to the wellsite  170 . For example, when the exhaust gas includes a flue gas from a power plant, which typically contains from about 7 to about 10 vol. % CO 2 , the method I can further include transporting the exhaust gas (or a waste gas from which the gas including CO 2  is obtained) from the another jobsite at which the waste gas is obtained to the wellsite  170 . In embodiments, the method I can further include separating CO 2  from the waste gas including CO 2  (step  30 ), prior to transport to wellsite  170 , to reduce a volume of gas for transport. Although the separating of the CO 2  from the exhaust gas comprising CO 2  can be performed at the wellsite  170  (e.g., after transport of the waste gas from the another jobsite at which the waste gas is obtained and/or produced to the wellsite  170 ), to facilitate transportation, the separating of the CO 2  from the exhaust gas comprising CO 2  at  30  can be performed at the another jobsite at which the waste gas is produced and/or obtained and subsequently, the separated CO 2    135  can be transported to the wellsite  170 . Accordingly, CO 2  separation apparatus  130  can be located at a jobsite different from wellsite  170  or can be located at wellsite  170 . 
     As noted above, method I comprises, at  30 , separating CO 2  from collected exhaust gas  115 . Separating the separated CO 2    135  from the collected exhaust gas  115  at  30  can comprise separating substantially pure separated CO 2    135  from the collected exhaust gas  115 . That is, in embodiments, the separated CO 2    135  is substantially pure CO 2 . The substantially pure CO 2  (and the substantially pure separated CO 2 ) can include greater than or equal to about 90, 95, 96, 97, 98, 99, 99.5, 99.8, 99.9, or 100 vol % CO 2 . Separating CO 2  from the collected exhaust gas at  30  can comprise passing the collected exhaust gas  115  through a CO 2  separation unit or apparatus  130 . CO 2  separation apparatus  130  can comprise any apparatus operable to provide high purity (e.g., greater than or equal to 95, 96, 97, 98, 98.5, 99, 99.5, 99.9, 99.99, or substantially 100 volume percent (vol %) CO 2  from the collected exhaust gas  115  (or a solids-reduced exhaust gas  125  produced in solids removal apparatus  120 , described below). CO 2  separation apparatus  130  can operate by separating via amine absorption, calcium oxide (CaO) absorption, filtration, packed bed, another technique, or a combination thereof. In embodiments, CO 2  separation apparatus  130  comprises a membrane unit, an amine unit, a carbon fiber filtration unit, a reaction bed unit, a venturi reactor, batch reactor, continuous reactor, fluidized pack column, another unit configured to remove the at least the portion of the CO 2  from the collected exhaust gas  115 , or a combination thereof. In embodiments, the at least the portion of the CO 2  utilized to produce formic acid at step  40  comprises from about 10 to about 90, from about 20 to about 80, from about 30 to about 70, from about 40 to about 60, from about 10 to about 50, from about 50 to about 90, or greater than or equal to about 10, 20, 30, 40, 50, 60, 70, 80, or 90 volume percent (vol %) of the CO 2  in the collected exhaust gas  115 . 
     As noted above, method I can further comprise, at  20 , separating solids (e.g., ash, soot, dust) from the exhaust gas (e.g., exhaust gas  107  or collected exhaust gas  115 ). Separating of the solids can be effected in solids removal apparatus  120  configured to remove solids from a gas. Such gas/solids removal equipment can comprise, for example, a cyclone, a dust filtration unit, a venturi scrubber, carbon fiber filtration unit a bag filtration unit, or a combination thereof. 
     As noted above, method I further comprises, at  40 , forming formic acid utilizing at least a portion of the separated CO 2 . A reaction apparatus  140  is configured for forming formic acid from the at least a portion of the separated CO 2    135 . Reaction apparatus  140  can comprise any apparatus operable to produce formic acid from at least a portion of the separated CO 2    135 . 
     Forming formic acid utilizing at least a portion of the separated CO 2    135  can comprise electrochemically reacting the at least the portion of the separated CO 2  with water to produce the formic acid and oxygen. In such embodiments, the reaction apparatus  140  can comprise an electrochemical reactor  140 A configured for electrochemically reacting the at least the portion of the separated CO 2    135  with water to produce the formic acid and oxygen. 
     For example, with reference to  FIG.  4   , which is a schematic of an electrochemical reaction apparatus  140 A, according to one or more embodiments of the present disclosure, forming formic acid at  40  can comprise introducing the at least the portion of the separated CO 2    135  into an electrochemical reaction apparatus  140 A. Within electrochemical reaction apparatus  140 A, separated CO 2    135  reacts with water via Equation (1): 
       2CO 2 +H 2 O+2e − →2(HCOOH)+O 2    Eq. (1),
 
     providing oxygen and a gas  136  depleted in CO 2 . Electrochemical reaction apparatus  140 A can comprise a cathode side CM and an anode side AM. A DI water  139  inlet  131 , O 2  outlet  132 , center compartment DI water  142  inlet  133 , formic acid HCOOH product  145  outlet  134 , CO 2  gas  135  inlet  137  and depleted CO 2  gas  136  product outlet  138  can be located as depicted in  FIG.  4   . During operation, DI water  139  can be recirculated through the anode flow field using a pump. CO 2  can be humidified (e.g., on the cathode side CM or anode side AM) using a gas humidifier at room temperature (23-25° C.), e.g., using a gas mass flow controller. In a center compartment  141 , DI water  142  can be metered into the bottom inlet connection  133  in a single-pass flow mode at a selected flow rate using a pump. The formic acid product solution  145  can be collected from the outlet  134  of the center compartment  141 . 
     Alternatively or additionally, forming formic acid at step  40  can comprise catalytically reacting the at least the portion of the separated CO 2    135  in water or dimethylsulfoxide (DMSO) to hydrogenate CO 2  and form formic acid. In such embodiments, reaction apparatus  140  can comprise a catalytic reactor configured for forming the formic acid by catalytically reacting the at least the portion of the CO 2  in water or dimethylsulfoxide (DMSO) to hydrogenate CO 2 . In such embodiments, reaction apparatus  140  can include a ruthenium (II) catalyst comprising [Ru(PTA) 4 Cl 2 , wherein PTA=1, 3, 5-triaza-7-phosphaadamantane or variations of thereof: 
     
       
         
         
             
             
         
       
     
     Collecting the collected exhaust gas  115  at  10 , separating the separated CO 2    125  from the collected exhaust gas  115  at  30 , and/or forming formic acid  145  at  40  can be performed substantially continuously or intermittently. 
     As noted above, method I can further comprise forming a WSF comprising at least a portion of the formic acid at  50 . Accordingly, system  100  can further include wellbore servicing fluid production apparatus  150  configured to produce a wellbore servicing fluid  155  from at least a portion of the formic acid  145 . In embodiments, the wellbore servicing fluid  155  comprises a fracturing fluid, a stimulating fluid, an acidizing fluid, or a combination thereof. In embodiments, the gas exhaust gas collection system  110  is configured to collect at least a portion of the collected exhaust gas  115  from fracturing equipment (e.g., hydraulic fracturing pumping equipment), and the wellbore servicing fluid  155  comprises a fracturing fluid. Although depicted as a disparate unit  150  in  FIG.  2   , forming the WSF  155  comprising the at least the portion of the formic acid  145  at  50  can comprise injecting the formic acid  145  directly into a wellbore servicing fluid being injected/pumped downhole (e.g., at step  60 ) to form the WSF  155  comprising the formic acid  145  that is pumped downhole at  60 . 
     As noted hereinabove, method I can further include introducing the WSF downhole (e.g., below a surface  176  of the earth) at  60 , whereby formic acid  145  is sequestered downhole (e.g., in a reservoir  177 ). In such embodiments, system  100  can further include pumping apparatus  150  configured for pumping the wellbore servicing fluid  155  downhole, via a wellbore  175 , whereby the formic acid  145  is sequestered downhole (e.g., in a formation, reservoir  177 ). The formic acid  145  introduced downhole at  50  can be sequestered downhole for a time period of at least 6 months, one year, two years, or five years or more. 
     The formic acid  145  enables CO 2  to be sequestered long term in the hydrocarbon reservoir  177  as much of the fracturing fluid WSF  155  will remain in the reservoir  177 . The formic acid  145  can also react with some formation  177  materials and enhance hydrocarbon mobility. 
     In embodiments, a method of this disclosure comprises forming formic acid  145  using as a reactant carbon dioxide (CO 2 )  135  separated from exhaust gas  107  produced at a wellsite  170  comprising at least one wellbore  175 . The method can further comprise introducing the formic acid  145  downhole via the at least one wellbore  175 , whereby the formic acid  145  is sequestered downhole (e.g., in a formation, reservoir  177 ). The formic acid  145  can be introduced downhole as a component of a WSF  155 . 
     In embodiments, a method of this disclosure comprises collecting/capturing the exhaust gas  115  from hydraulic fracturing pumping equipment on a hydraulic fracturing location at  10 , removing unwanted solids, such as dust and soot, from the collected exhaust gas  115  at  20 , passing the collected exhaust gas  115  through a CO 2  separation unit  130  (e.g., a membrane unit, an amine unit, a carbon fiber filtration unit, or any other commercial unit capable of removing most of the CO 2  from the collected exhaust gas  115 ) at  30 ; introducing the separated CO 2    135  through an electrolytic or catalytic reaction apparatus  140  with water to convert the CO 2  to formic acid  145  (as described with reference to  FIG.  4    and  FIG.  5   ) at  40 , and injecting the formic acid  145  directly into a WSF  155  (e.g., a hydraulic fracturing fluid) as it is being pumped downhole at  60 . 
     By way of nonlimiting examples, the WSF  155  comprising formic acid  145  can be introduced downhole to dissolve deposits, break gels, increase a permeability of the formation  177 . In embodiments, the WSF  155  comprising at least a portion of the formic acid  145  can be introduced downhole after a perforating stage to establish infectivity by helping to clean up and remove any acid soluble damage in or around a created perforation tunnel that can increase fracture breakdown pressure and fracture treating pressure. 
     The system and method of this disclosure can provide for continuous, semi-continuous, or intermittent collecting of exhaust gas  115  from exhaust gas production equipment (e.g., machinery  180  at a wellsite  170 ) and utilization of the collected exhaust gas  115  to produce formic acid  145 . The formic acid  145  can be utilized to benefit at the wellsite  170 , for example, as a component of a WSF  155  that can be introduced downhole. Accordingly, the herein disclosed system and method enable a reduction in an emission of CO 2  to the atmosphere relative to a method in which formic acid  145  is not formed from the at least the portion of the separated CO 2    135 . 
     Via the system and method described herein, carbon dioxide can be utilized on location to generate formic acid  145 , which can be utilized as part of a hydraulic fracturing fluid WSF  155  that is being injected into a hydrocarbon reservoir  177 . Injection of formic acid  145  downhole, as described herein, can be superior to injecting carbon dioxide downhole, as the density of formic acid  145  can be favorably more consistent, and specialized compression equipment that would be required to reinject carbon dioxide downhole may not be needed to inject formic acid  145  downhole. Formic acid  145  is compatible with most hydrocarbon formations  177  and can provide some secondary benefits in helping to improve oil mobility and displacement of oil when the formic acid  145  is introduced downhole. 
     In embodiments, the system of this disclosure, or one or more components thereof (e.g., exhaust gas collection apparatus  110 , solids removal apparatus  120 , CO 2  separation apparatus  130 , reaction apparatus  140 , or a combination thereof) can be provided on a skid (e.g., a trailer skid), whereby at least a portion the separated CO 2    135  can be converted to formic acid  145  at the wellsite  170 . In embodiments, the system of this disclosure, or one or more components thereof (e.g., exhaust gas collection apparatus  110 , solids removal apparatus  120 , CO 2  separation apparatus  130 , reaction apparatus  140 , or a combination thereof) is provided as a small-scale formic acid plant (e.g., on one or more skids  190 ) at wellsite  170 , whereby formic acid  145  can be produced on location. 
     In embodiments, collected exhaust gas  115  is collected on location at wellsite  170 , carbon dioxide is separated from the collected exhaust gas  115  on location to provide separated CO 2    135 , the separated carbon dioxide  135  is introduced into a reaction apparatus  140  on location (e.g., at wellsite  170 ) configured for reaction of the separated CO 2    135  with water to create formic acid  145 , the formic acid  145  is introduced into a WSF  155  (e.g., a hydraulic fracturing fluid, a stimulation fluid), and the WSF  155  is pumped downhole as part of a wellbore operation (e.g., hydraulic fracturing operation, stimulation treatment). The exhaust gas can be produced by equipment/machinery  180  utilized during the wellbore operation (e.g., hydraulic fracturing operation, stimulation treatment), in embodiments. 
     In embodiments, the system and method of this disclosure enable capture of CO 2  from hydraulic fracturing operations (e.g., via collection of collected exhaust gas  115  from equipment  180  utilized during a hydraulic fracturing operation at  10  and separation of the separated CO 2    135  from the collected exhaust gas at  30 ) and sequestration of the separated CO 2    135  long term (via formation of formic acid  145  from the separated CO 2  at  40  and introduction of the formic acid  145  downhole at  60 ). The formic acid  145  can be introduced downhole during the hydraulic fracturing operations, in embodiments. 
     Sequestration of the separated CO 2    135  via this disclosure can provide for a reduction in the emissions of CO 2  to the atmosphere relative to methods in which the CO 2  is not converted to formic acid  145  and introduced downhole. 
     ADDITIONAL DISCLOSURE 
     The following are non-limiting, specific embodiments in accordance with the present disclosure: 
     In a first embodiment, a method comprises: collecting exhaust gas comprising carbon dioxide (CO 2 ) at a wellsite to provide a collected exhaust gas; separating CO 2  from the collected exhaust gas to provide a separated CO 2 ; and forming formic acid utilizing at least a portion of the separated CO 2 . 
     A second embodiment can include the method of the first embodiment further comprising separating solids (e.g., soot, dust) from the exhaust gas. 
     A third embodiment can include the method of the first embodiment or the second embodiment further comprising: forming a wellbore servicing fluid comprising at least a portion of the formic acid; and introducing the wellbore servicing fluid downhole via a wellbore, wherein the formic acid is sequestered downhole (e.g., in a reservoir). 
     A fourth embodiment can include the method of the third embodiment, wherein the wellbore servicing fluid comprises a fracturing fluid, a stimulating fluid, an acidizing fluid, or a combination thereof. 
     A fifth embodiment can include the method of the third embodiment or the fourth embodiment, wherein the formic acid is sequestered downhole for a time period of at least 6 months, one year, two years, or five years. 
     A sixth embodiment can include the method of any one of the third to fifth embodiments, wherein the wellbore servicing fluid comprises a fracturing fluid, an acidizing fluid, a stimulating fluid, or a combination thereof. 
     A seventh embodiment can include the method of any one of the first to sixth embodiments, wherein the exhaust gas is produced by fracturing equipment (e.g., hydraulic fracturing pumping equipment, hydraulic horsepower pumping units, electrical generation natural gas turbine units, electrical generation reciprocating natural gas power units or a combination thereof). An eighth embodiment can include the method of any one of the first to seventh embodiments, wherein forming formic acid comprises electrochemically reacting the at least the portion of the separated CO 2  with water to produce the formic acid and water. 
     A ninth embodiment can include the method of any one of the first to eighth embodiments, wherein forming the formic acid comprises catalytically reacting the at least the portion of the CO 2  in water or dimethylsulfoxide (DMSO) to hydrogenate CO 2 . 
     A tenth embodiment can include the method of the ninth embodiment, wherein the catalytically reacting comprises hydrogenating the CO 2  in the presence of a ruthenium (II) catalyst comprising [Ru(PTA) 4 Cl 2 , wherein PTA=1, 3, 5-triaza-7-phosphaadamantane or variations of thereof. 
     
       
         
         
             
             
         
       
     
     An eleventh embodiment can include the method of any one of the first to tenth embodiments, wherein separating CO 2  from the collected exhaust gas comprises passing the collected exhaust gas through a CO 2  separation unit. 
     A twelfth embodiment can include the method of the eleventh embodiment, wherein the CO 2  separation unit comprises a membrane unit, an amine unit, a carbon fiber filtration unit, or another unit configured to remove the at least the portion of the CO 2  from the collected exhaust gas. 
     A thirteenth embodiment can include the method of the twelfth embodiment, wherein the at least the portion of the CO 2  comprises from about 10 to about 90, from about 20 to about 80, from about 30 to about 70, from about 40 to about 60, from about 10 to about 50, from about 50 to about 90, or greater than or equal to about 10, 20, 30, 40, 50, 60, 70, 80, or 90 volume percent (vol %) of the CO 2  in the exhaust gas. 
     A fourteenth embodiment can include the method of any one of the first to thirteenth embodiments, wherein the method reduces an emission of CO 2  to the atmosphere relative to a method in which formic acid is not formed from the at least the portion of the separated CO 2 : 
     In a fifteenth embodiment, a system comprises: an exhaust gas collection system configured for collecting exhaust gas comprising carbon dioxide (CO 2 ) at a wellsite to provide a collected exhaust gas; a CO 2  separation apparatus configured for separating CO 2  from the collected exhaust gas to provide a separated CO 2 ; and a reaction apparatus configured for forming formic acid utilizing at least a portion of the separated CO 2 . 
     A sixteenth embodiment can include the system of the fifteenth embodiment further comprising a solids removal apparatus configured to separate solids (e.g., soot, dust) from the collected exhaust gas. 
     A seventeenth embodiment can include the system of the fifteenth embodiment or the sixteenth embodiment further comprising wellbore servicing fluid production apparatus configured to produce a wellbore servicing fluid, wherein the wellbore servicing fluid comprises at least a portion of the formic acid. 
     An eighteenth embodiment can include the system of the seventeenth embodiment further comprising pumping apparatus configured for pumping the wellbore servicing fluid downhole, via a wellbore, whereby the formic acid is sequestered downhole (e.g., in a formation, reservoir). 
     A nineteenth embodiment can include the system of the eighteenth embodiment, wherein the wellbore servicing fluid comprises a fracturing fluid, a stimulating fluid, an acidizing fluid, or a combination thereof. 
     A twentieth embodiment can include the system of the eighteenth embodiment or the nineteenth embodiment, wherein the gas exhaust gas collection system is configured to collect at least a portion of the collected exhaust gas from fracturing equipment (e.g., hydraulic fracturing pumping equipment), and wherein the wellbore servicing fluid comprises a fracturing fluid. 
     A twenty first embodiment can include the system of the twentieth embodiment, wherein the fracturing fluid is introduced downhole via the wellbore by the pumping apparatus (e.g., hydraulic fracturing pumping apparatus). 
     A twenty second embodiment can include the system of any one of the fifteenth to twenty first embodiments, wherein the gas exhaust gas collection system is configured to collect at least a portion of the collected exhaust gas from fracturing equipment (e.g., hydraulic fracturing pumping equipment). 
     A twenty third embodiment can include the system of any one of the fifteenth to twenty second embodiments, wherein the reaction apparatus comprises an electrochemical reactor configured for electrochemically reacting the at least the portion of the separated CO 2  with water to produce the formic acid and water. 
     A twenty fourth embodiment can include the system of any one of the fifteenth to twenty third embodiments, wherein the reaction apparatus comprises a catalytic reactor configured for forming the formic acid comprises catalytically reacting the at least the portion of the CO 2  in water or dimethylsulfoxide (DMSO) to hydrogenate CO 2 . 
     A twenty fifth embodiment can include the system of the twenty fourth embodiment, wherein the catalytic reactor comprises a ruthenium (II) catalyst, e.g., comprising [Ru(PTA) 4 Cl 2 , wherein PTA=1, 3, 5-triaza-7-phosphaadamantane: 
     
       
         
         
             
             
         
       
     
     that catalyzes the hydrogenation of the at least the portion of the CO 2 . 
     A twenty sixth embodiment can include the system of any one of the fifteenth to twenty fifth embodiments, wherein the CO 2  separation apparatus comprises a membrane unit, an amine unit, a carbon fiber filtration unit, or another unit configured to remove the at least the portion of the CO 2  from the collected exhaust gas. 
     A twenty seventh embodiment can include the system of the twenty sixth embodiment, wherein the at least the portion of the CO 2  comprises from about 10 to about 90, from about 20 to about 80, from about 30 to about 70, from about 40 to about 60, from about 10 to about 50, from about 50 to about 90, or greater than or equal to about 10, 20, 30, 40, 50, 60, 70, 80, or 90 volume percent (vol %) of the CO 2  in the exhaust gas. 
     In a twenty eighth embodiment, a method comprises: producing formic acid using as a reactant carbon dioxide (CO 2 ) separated from exhaust gas produced at a wellsite comprising at least one wellbore. 
     A twenty ninth embodiment can include the method of the twenty eighth embodiment further comprising introducing the formic acid downhole via the at least one wellbore, whereby the formic acid is sequestered downhole (e.g., in a formation, reservoir). 
     A thirtieth embodiment can include the method of the twenty eighth embodiment or the twenty ninth embodiment, wherein the producing is performed substantially continuously or intermittently. 
     While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the embodiments disclosed herein are possible and are within the scope of this disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, R1, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=R1+k*(Ru—R1), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc. When a feature is described as “optional,” both embodiments with this feature and embodiments without this feature are disclosed. Similarly, the present disclosure contemplates embodiments where this “optional” feature is required and embodiments where this feature is specifically excluded. 
     Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as embodiments of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference herein is not an admission that it is prior art, especially any reference that can have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.