Treating a formation with a chemical agent and liquefied natural gas (LNG) de-liquefied at a wellsite

A method and system of treating a formation and a well extending therethrough, including storing liquefied natural gas (LNG) at an on-site location of the well, injecting a first stream of LNG into the formation through the well to contact at least one of a surface of the formation or a metal surface locatable in the well, injecting a chemical agent into the formation through the well to contact at least one of the surface of the formation or the metal surface locatable in the well, and treating at least one of the surface of the formation or the metal surface locatable in the well with the chemical agent and the first stream of LNG.

BACKGROUND

This section is intended to provide relevant background information to facilitate a better understanding of the various aspects of the described embodiments. Accordingly, it should be understood that these statements are to be read in this light and not as admissions of prior art.

A reservoir volume through a parent well (“original well”) may be under sufficient pressure to flow fluids, such as oil, gas, and hydrocarbons, to a surface. As the fluids are produced, the pressure in the reservoir volume will often decline, and production from the parent well is reduced or halted. If an infill well, such as a child well, is completed before the reduced-pressure reservoir volume through the parent well is re-pressured, asymmetrical fractures from the child well may propagate in the direction of the parent well. In such cases, natural gas may be used to partially or fully re-pressurize the reduced-pressure reservoir volume.

A natural gas pipeline system begins at a natural gas producing wellhead or field. Transporting the natural gas used for re-pressuring from the wellhead to a point of use involves several physical transfers of custody and multiple processing steps. Depending upon the initial quality of the wellhead product, a pipeline gathering system directs the flow of the natural gas to a processing plant. During processing, the natural gas is subjected to various extraction processes to remove water and other impurities and contaminants. After cleaning, the natural gas is directed to a mainline transmission grid to be distributed to the point of use.

However, due to its volume, natural gas is not easily stored or moved by various modes of transportation, such as railways or tankers, and is usually transported through an extensive, yet complex, network of pipelines. The natural gas pipeline system in the United States alone includes 305,000 miles of interstate and intrastate transmission pipe, more than 1,400 compressor stations to maintain

pressure of the network, and more than 11,000 delivery points, 5,000 receipt points, and 1,400 interconnection points to provide transfer of the natural gas.

DETAILED DESCRIPTION

FIG. 1is a schematic view of an example liquefied natural gas (“LNG”) pressuring system100for pressuring a formation101, according to one or more embodiments. The formation101includes reservoir volumes102,104composed of porous and permeable rocks (i.e., reservoir rocks) that contain reservoir fluids (e.g., oil, gas, water, hydrocarbons) located in an onshore environment or in an offshore environment. A well system includes at least one well106drilled to penetrate the formation101to carry out exploration and extraction of fluids from the reservoir volumes102,104. The well106ofFIG. 1is shown as near-vertical, but can be formed at any suitable angle to reach a hydrocarbon-rich portion of the formation101. In other examples, the well106can follow a partially-vertical, angled, or even a partially-horizontal path through the formation101. The well106is shown as being lined with a protective lining108extending through the formation101. The protective lining108may include a casing, liner, or tubing made of any material, including steel, alloys, or polymers, among others. The well106may also be partially or fully openhole, i.e., no protective lining. The protective lining108is perforated so that the reservoir fluids flow through fractures110formed in the formation101and into the well106.

During primary recovery techniques (e.g., natural depletion), reservoir pressure is sufficient so that reservoir fluids can flow from the fractures110and into the well106. As described herein, the reservoir pressure includes the pressure of the fluids present in pore spaces of the reservoir rocks. As the reservoir fluids are produced from the reservoir rocks, the pressure, flow capacity, and recovery factor from the reservoir volume102is reduced until production from the well106is minimal or no longer feasible. Since the reservoir volume102may contain oil that has been relieved of pressure such that the oil is near, at, or below its bubble point, natural gas can be injected into the well106to increase pressures to a level equal to or greater than the original reservoir pressures, for example, pressures exhibited at original production conditions. The terms pressured, re-pressured, pressurized, and re-pressurized are used interchangeable herein to imply that reservoir volume pressures are increased or restored to pressure levels occurring during initial recovery from the well106.

In operation, the natural gas is injected into the well106to flow into a tubing string112or an annular area114located between an inner surface of the well106and the string112. Specifically, the natural gas introduced into the formation101is miscible and/or displaced in the fluids of the reservoir volume102to help mobilize and flow the fluids from the volume102and into the well106. Natural gas, as opposed to water, includes a miscibility that is greater in reservoir fluids than the miscibility of water in such fluids. In particular, the molecules of the injected natural gas are capable of mixing or dissolving within the reservoir fluids to lower fluid viscosity and, thus, subsequently assist in the production of higher volumes of reservoir fluids from the volume102. Further, the natural gas mixed or dissolved within the reservoir fluids can be released, for instance, using liberation techniques. Thus, unlike water, a portion of the natural gas used to pressurize the reservoir volume102can be recovered and later sold and/or further used in other operations.

However, before the natural gas is transported for use via remote pipelines or other remote transportation methods, heavier hydrocarbons and contaminants are often extracted to produce a processed natural gas. In a gaseous form, the low density and flammable nature of the processed natural gas presents various challenges during transportation to the point of use, i.e., the well106. However, natural gas can be compressed in volume and cooled to or below cryogenic temperatures, e.g., −260 Fahrenheit (° F.) (−162 Celsius (° C.)), to produce liquefied natural gas (“LNG”)116. The reduction in volume enables natural gas to be transported in liquid form across extended distances and to remote locations where pipelines are not available.

The LNG pressuring system100includes a LNG source vessel118to store LNG116on-site at the well106. The storage of LNG at the well106reduces the distance between the source of the natural gas, e.g., remote pipelines, supply and the point of injection into the well106and thus, overcomes any challenges associated with using and transporting natural gas. The LNG source vessel118includes a cooling system or a separate cooling system120located at the well106to maintain the LNG116at cryogenic temperatures. The LNG source vessel118is further in fluid communication with a cryogenic system122capable of de-liquefying the LNG116to a gaseous state. The cryogenic system122includes a cryogenic pump124capable of processing fluids at cryogenic temperatures. The cryogenic pump124supplies a feed pressure to flow the LNG116into a heating unit126to be heated and vaporized into natural gas, e.g., de-liquefied LNG128. Once in a gaseous state, the de-liquefied LNG128may flow into the well106to increase the reservoir pressure of the reservoir volume102. In some cases, an injection pump131pressurizes the de-liquefied LNG128to maintain an injection flow rate sufficient to inject and deliver the LNG128into the well106and further into the fractures110.

The LNG116transported to the well106may already be processed and thus, free of contaminants including water, hydrogen sulfide, and carbon dioxide, among others. In other examples, the LNG116stored in the LNG source vessel118may be processed at the well106or requires additional processing so that additional equipment may be located at the well106. However, equipment in contact with the LNG116must be suitable for cryogenic service, i.e., suitable to handle cryogenic temperatures, e.g., at or below −260° F. (−162° C.).

It should be clearly understood that the LNG pressuring system100ofFIG. 1is merely one embodiment of an application of the principles of this disclosure in practice, and a wide variety of other embodiments are possible. Therefore, the scope of this disclosure is not limited at all to the details ofFIG. 1described herein and/or depicted in the additional drawings.

FIG. 2Ais a schematic view of a subterranean formation201before pressuring a reservoir volume202, according to one or more embodiments. An initial well drilled to discover and produce fluids from one or more reservoir volumes202,204is often referred to as a parent well206. As fluids are recovered from the reservoir volume202through the parent well206, the reservoir pressure decreases so that the reservoir volume202is referred to as a “depleted” reservoir volume. As described herein, a depleted reservoir volume includes reservoir pressures that have been reduced due to production, production from other producing wells, or due to low permeability of the formation201. The reduction in pressure limits the recovery of reservoir fluids that may remain in the reservoir volume202after implementing primary recovery techniques, such as natural pressure recovery. Other recovery techniques, such as artificial lift recovery, water injection recovery, or steam injection recovery, among others, may be implemented to further produce and recover the fluids from the reservoir volume202or fluids from an adjacent reservoir volume204. In some cases, a child well230is drilled and completed in a producing area or between a producing well(s), such as the parent well206, to sustain rates or contact portions of one or more reservoir volumes202,204that are inadequately drained or untouched using existing production methods. To promote production, the child well230is stimulated to produce fluids unrecovered from the reservoir volume202, not easily accessible through the parent well206, and/or fluids from the adjacent reservoir volume204.

However, during stimulation of the child well230, asymmetrically induced fractures232may generate to propagate in the direction of the reservoir volume202, i.e., the depleted reservoir volume. Specifically, the asymmetrically induced fractures232generated in the child well230migrate to lower pressure, i.e., lower stress, zones of the formation201, such as the reservoir volume202, or any other previously depleted well(s) with a low reservoir pressure. The fractures232of the child well230follow the path of least resistance or the path that requires less fracture energy, thus, resulting in the asymmetric fracture pattern. As shown inFIG. 2A, the asymmetrically induced fractures232, as described herein, can include fractures that grow preferentially on one side of the child well230in the direction of the reservoir volume202. Such asymmetric fracture growth restricts the fractures232from generating on another side of the child well230or fracturing in the direction of other producing reservoirs, such as the reservoir volume204that is pressured and capable of producing reservoir fluids. As a result, the reservoir volume204may be bypassed or untouched due to the asymmetric induced fractures232propagating in the direction of the reservoir volume202.

FIG. 2Bis a schematic view of a subterranean formation201after pressuring the reservoir volume202ofFIG. 2Ausing a LNG pressuring system200, according to one or more embodiments. As described with respect toFIG. 1, the reservoir volume202can be pressurized using the LNG pressuring system200, for example, to pre-recovery reservoir pressures using LNG216before completion and/or stimulation of a child well230. The system200includes a LNG source vessel218to store the LNG216and a cooling system or a separate cooling system220located at the well206to maintain the LNG216at or below cryogenic temperatures, e.g., −260° F. (−162° C.). The LNG source vessel218supplies the LNG216to a cryogenic system222capable of de-liquefying and returning the LNG216to a gaseous state. The cryogenic system222includes a cryogenic pump224to supply a feed pressure to flow the LNG216into a heating unit226. The unit226heats and vaporizes the LNG216into natural gas, i.e., de-liquefied LNG228. Once in a gaseous state, the de-liquefied LNG228flows into the well206via a tubing string212to increase the reservoir pressure of the reservoir volume202. In some cases, an injection pump231pressurizes the de-liquefied LNG228to maintain an injection flow rate sufficient to deliver and inject the de-liquefied LNG228into the well206. In the embodiments, the storage of LNG216at the well206reduces the distance between the natural gas supply source (e.g., remote natural gas pipelines) and the point of injection into the well206for various operations, such as the pressuring of the reservoir volume202. In this way, storage of LNG216at the well206overcomes any challenges associated with using natural gas, remote pipelines, and other remote transportation methods.

After injecting the de-liquefied LNG228to increase the pressures of the reservoir volume202, the child well230may be drilled or if already drilled, it may be completed. Upon stimulation of the child well230, asymmetric fracturing from the child well230towards the parent well206, as previously shown inFIG. 2A, is mitigated. Instead, stimulation of the child well230generates more symmetric fractures234that do not grow in an unbalanced pattern towards the re-pressurized reservoir volume202. Instead, the symmetric fractures234may propagate in a balanced direction towards the reservoir volume204that is capable of producing reservoir fluids and also in the direction of the re-pressurized reservoir volume202, if capable of producing fluids into the well206. Thus, re-pressuring the reservoir volume202before stimulating the child well230promotes symmetric fracturing upon stimulating the child well230that is balanced and does not grow into lower pressure/lower stressed areas of the formation201, i.e., a depleted reservoir volume such as the reservoir volume ofFIG. 2A. As described herein, symmetrically induced fracturing includes fractures234growing simultaneously upward and downward, or along one or more sides of the child well.

It should be clearly understood that the embodiments described with respect toFIGS. 2A and 2Binclude merely one example of an application of the principles of this disclosure in practice, and a wide variety of other embodiments are possible. Therefore, the scope of this disclosure is not limited at all to the details ofFIGS. 2A and 2Bdescribed herein and/or depicted in the additional drawings.

FIG. 3Aa schematic view of a LNG pressuring system300and a fracturing pump system336, according to one or more embodiments. Pressuring a previously depleted reservoir volume302before stimulating a child well330, re-establishes a pathway for any remaining reservoir fluids to flow from the reservoir volume302. Thereafter, the pressured reservoir volume302may be re-stimulated to subsequently produce and flow the remaining reservoir fluids into an original well, i.e., a parent well306.

A reduction in the pressure in the reservoir volume302through the parent well306can lead to asymmetrically-induced fracturing in the direction of the well306during stimulation of an adjacent reservoir volume(s), e.g.,304. As described with respect toFIG. 1, the reservoir volume302is re-pressurized to restore reservoir volume pressures to pre-production levels using LNG316returned to a gaseous state. The LNG316is stored in a LNG source vessel318located at the well306that includes a cooling system320to maintain the LNG316at or below cryogenic temperatures, e.g., −260° F. (−162° C.). The LNG source vessel318is in fluid communication with a cryogenic pump324capable of supplying a feed pressure to flow a first stream of LNG316into a heating unit326. The heating unit326heats and vaporizes the LNG316into natural gas, i.e., de-liquefied LNG328. The de-liquefied LNG328, thereafter, flows into the well306to increase the reservoir pressure or re-pressurize the reservoir volume302and thus, mitigates asymmetrically-induced fracturing in the direction of the parent well306.

After the reservoir volume302is pressurized, fractures334propagate away from the child well330to grow symmetrically into previously bypassed reservoirs, for example, the adjacent reservoir volume304. However, the fracturing fluid injected into the child well330during stimulation may flow into and infiltrate the pressured reservoir volume302, now capable of being re-stimulated. The infiltrating fracturing fluid from the child well330reduces and/or destroys any remaining producible fluids and reserve fluids of the reservoir volume302.

Various stimulation techniques, such as fracturing techniques, are implemented to re-stimulate the reservoir volume302and recover any remaining fluids in the parent well306after stimulating the child well330. Fracturing, a type of stimulation technique, includes creating a fracture system in the reservoir volume302by injecting fluid(s) under pressure into the well306to overcome stress and cause material failure of the volume302. Certain fluids injected into the well306to re-stimulate production, such as water, nitrogen and carbon dioxide, may damage reservoir rocks and/or cause formation contamination during recovery of such fluids from the formation301and/or the well306. For example, water retention due to higher capillary forces within the reservoir volume302can affect the reservoir volume permeability, reservoir volume wettability, and the geophysical integrity of the well306and/or formation301in the form of fines migration, deconsolidation, and rock weakening and softening. Such factors affect the ability of the fluids to be released and recovered from the reservoir volume302. However, the de-liquefied LNG328is non-damaging to reservoir rocks, inert and miscible in various reservoir volume fluids, and recoverable without contamination. As described in one or more embodiments, the de-liquefied LNG328used for pressuring the reservoir volume302is also used as a fracturing fluid to stimulate and increase the rate of fluid recovered from the pressured reservoir volume302.

The fracturing pump system336receives a second stream of LNG338from the cryogenic pump324. The fracturing pump system336includes a fracturing pump340, such as a high-pressure LNG pump, and a heating unit342. The fracturing pump340receives and pressures the second stream of LNG338at a fracturing pressure sufficient to fracture the reservoir volume302. A pressurized LNG346flows into the heating unit342to be heated and vaporized into natural gas, e.g., de-liquefied LNG348. The de-liquefied LNG348, acting as a fracturing fluid, is injected in the well306to flow into perforations350at a fracturing pressure sufficient to re-stimulate and generate fractures352in the reservoir volume302. Before injection into the well306, the de-liquefied LNG348may flow into a mixer354to be admixed with a stimulation material356, such as viscosifier agents, carrier aqueous fluids, proppants, demulsifiers, corrosion inhibitors, friction reducers, clay stabilizers, scale inhibitors, biocides, breaker aids, mutual solvents, surfactants, anti-foam agents, defoamers, viscosity stabilizers, iron control agents, diverters, emulsifiers, non-emulsifiers, foamers, nanoparticles-stabilized foams, oxygen scavengers, pH control agents, and buffering agents, and the like. The combination of the de-liquefied LNG348and the stimulation material356provides a fracturing fluid358capable of re-stimulating and re-fracturing the reservoir volume302. The mixer354may include static or dynamic mixing devices, diverters, and turbulizers, among others.

The stimulation material356, as described, may include acidic agents, such as a regular acid or a salt of hydrochloric acid (HCl) where the salt is thioamide, urea, glycine, or an amino acid such as tryptophan, proline, valine, among others. The acidity of some of the acidic agents increases in the presence of water at certain concentrations. For example, HCl is soluble in the presence of water and other aqueous solutions but insoluble and thus, non-acidic in the presence of other well fluids, e.g., oil, gas, hydrocarbons, corrosion inhibitors, surfactants, foaming agents, and nanoparticles. Removing water from the well306or from the formation301is not feasible since water naturally forms in the reservoir volume302and is often injected into the formation301during fracturing operations. Therefore, using de-liquefied LNG348in the presence of the acidic agents mitigates the acidic impact caused by acidic agents in the presence of the water and other aqueous based solutions.

The injection location, pressure, flow rate, fluid composition, and/or other parameters of the de-liquefied LNG348may be modified to improve sweep efficiency and rates of recovery. In some examples, the de-liquefied LNG348, as a fracturing fluid, is water-based and can be commingled with an aqueous solution to aid in load recovery, i.e., the amount of fracturing fluid produced back, after stimulating and fracturing the reservoir volume302. The de-liquefied LNG348can also be foam-based to transport additional agents commingled in the fracturing fluid, such as proppants, diverter materials, solid acids, and scale inhibitors, among others surface active agents. In some cases, before de-liquefying, a stream of the LNG316is injected into the well302as a fracturing fluid, with or without the stimulation material356, to re-fracture the formation302.

FIG. 3Bis schematic view of an example recovery and separation system362in a fracturing pump system336ofFIG. 3A, according to one or more embodiments. The de-liquefied LNG328,348ofFIG. 3Athat flows into the well306is miscible in fluids329recovered from the reservoir302. The de-liquefied LNG328,348that is in solution with the recovered fluids329is releasable using various techniques, such as flash liberation and differential liberation, among others. As shown inFIG. 3B, the recovered fluids329released from the reservoir302may flow into the well306and into a processing facility362. The processing facility362includes one or more separators364to separate out the various components within the recovered fluids329, such as the de-liquefied LNG328,348previously injected into the well306for pressuring and fracturing the reservoir302. The recovered de-liquefied LNG366flows from the processing facility362to be further processed and/or later sold or further used other operations.

It should be clearly understood thatFIGS. 3A and 3Bmerely depict one embodiment of an application of the principles of this disclosure in practice, and a wide variety of other embodiments are possible. Therefore, the scope of this disclosure is not limited at all to the details ofFIGS. 3A and 3Bdescribed herein and/or depicted in the additional drawings. For example, instead of using the fracturing pump system336to generate and flow de-liquefied LNG348into the well306, the cryogenic pump324can be rated to pressurize the LNG316at a fracturing pressure sufficient to fracture the formation301after re-pressuring. Further, the heater326can be used to heat and vaporize the LNG316to generate the de-liquefied LNG348before being injected into the well306as a fracturing fluid.

FIG. 4is a schematic view of an example LNG pressuring system400and an example tracer injection system444, according to one or more embodiments. As described with respect toFIG. 3A, a heating unit426heats and vaporizes LNG416to generate de-liquefied LNG428, e.g., natural gas. To increase the pressure of a reservoir volume402, a first stream of de-liquefied LNG428is injected into a well406to flow into a reservoir volume402, as described with respect toFIG. 1.

Well and reservoir monitoring of the first stream of de-liquefied LNG428, among other components within the well406and formation401, can be traced and monitored using tracers414. In general, tracers414are chemical compounds that are injected into the well406to trace and analyze the flow of fluids in the well406and/or a formation401during various operations, such as reservoir pressurization and fluid recovery. The tracers414can observe and track well and reservoir conditions, such as, the injection profile of injected fluids, the extent of injected fluid recovery, the influx of water, the amount of fluids produced from the well406, the location of fractures, and the like. In the embodiments, the tracers414can be injected during the re-pressuring of the reservoir volume402or during fracturing of the re-pressurized volume as described with respect toFIG. 3A.

To monitor various characteristics and fluids in the well406, including the injected de-liquefied LNG428, the tracer414is mixed with a second stream of de-liquefied LNG438. For example, a mixer454admixes the second stream of the de-liquefied LNG438with the tracer414to form an injectable tracer material458. The tracer material458is continuously injected into the well or in a spiked or single injection process using injection equipment460. The injection equipment460can include tubing, pipes, pumps, compressors, or other equipment to flow the tracer material458through the well406and/or into the formation401. The tracer material458flows through the formation401to be produced back into the well406, for example, at a location where the tracer material458originally entered or leaked from a fracture formed in the formation401. In some cases, the first stream of de-liquefied LNG428can be considered as a tracer material and solely injected into the well406without the tracer414after pressuring the reservoir volume402.

The de-liquefied LNG438is suitable for use as a tracer due to a pure methane (CH4) content and a non-detectable presence at a measurable level in the reservoir fluids recovered from the well406. Further, the de-liquefied LNG438does not interfere or interact undesirably with reservoir fluids, e.g., oil, gas, water, hydrocarbons, etc., and is injected into the well406at concentrations above detection limits. The detection limits may include, for example, at about five (5) parts per trillion to about 1,000 parts per million and more, preferably at a range of about 100 parts per trillion to about 100 parts per million.

In operation, the de-liquefied LNG438that is produced back into the well406is detected by one or more tracer detectors462installed in the well406and/or at a ground surface415. The tracer detectors462can include electrochemical detectors and gamma ray detectors, among other types of detectors and/or sensors. The tracer detectors462can detect and analyze characteristics of the de-liquefied LNG438, such as the concentration of the de-liquefied LNG438in the fluids recovered from the formation401and/or well406. In addition to data related to concentrations, the parameter data can include data related to the time of de-liquefied LNG438detection, the location of the de-liquefied LNG438when detected, the amount of de-liquefied LNG438detected, and the like. A computing system464may receive and analyze the parameter data from the trace detectors462. For instance, the computing system464analyzes the parameter data to provide information related to various characteristics of the formation401and/or the well406, for example, information related to the pressure of the first stream of de-liquefied LNG428injected into the well to pressurize the reservoir volume402.

It should be clearly understood that the fracturing system ofFIG. 4is merely one embodiment of an application of the principles of this disclosure in practice, and a wide variety of other embodiments are possible. Therefore, the scope of this disclosure is not limited at all to the details ofFIG. 4described herein and/or depicted in the additional drawings.

FIG. 5is a schematic view of an example LNG pressuring system500and an example treatment system544, according to one or more embodiments. A formation501includes a reservoir volume502composed of porous and permeable rocks that contain fluids, e.g., oil, gas, hydrocarbons, water. A well506is drilled to penetrate the formation501to carry out exploration and production of fluids from the reservoir volume502. However, after production, the reservoir volume502may be depleted of pressure and incapable of further production. In some cases, natural gas is injected into the well506using the LNG pressuring system500to re-pressurize the reservoir volume502for subsequent re-stimulation and production of additional fluids from the well502.

LNG is transported to and stored in a LNG source vessel518at an on-site location of the well506. The LNG source vessel518can include a cooling system or a separate cooling system520can be located at the on-site location to maintain the LNG at or below cryogenic temperatures, e.g., −260° F. (−162° C.). As described with respect toFIG. 1, a cryogenic pump524supplies a feed pressure to flow a first stream of LNG516the into a heating unit526. The heating unit526heats and vaporizes the first stream of LNG516into the natural gas, e.g., de-liquefied LNG528. Once in a gaseous state, the de-liquefied LNG528flows into the well506to increase the reservoir pressure of the reservoir volume502. Pressuring the reservoir volume502mitigates or reduces asymmetrically-induced fracturing in the direction of the well506. Further, after pressuring, production operations from the well506may be re-established to recovery any remaining fluids in the reservoir volume502or bypassed in the adjacent reservoir volume504.

However, various physical and chemical factors reduce the permeability of the reservoir volume502to flow the fluids, thus, leading to a reduction in fluid recovery. For example, various fluids injected into the well506during operations, such as drilling, completion, and production operations, can cause damage to the formation501and/or well506. Additionally, reactions among drilling fluids, production fluids, and formation fluids, such as emulsification due to oil/water incompatibilities, the precipitation of solids, the creation of an immiscible fluid, and water saturation, among others, can limit gas and oil permeabilities. Other damaging factors include organic and inorganic scale formation and depositions, fines production and accumulation, mechanical damage, microorganism growth, and the like.

In one or more embodiments, a second stream of LNG538and the chemical agents517flow into a mixer554to form a treatment fluid558that is thereafter injected into the well506. In examples, the second stream of LNG538may be in a gaseous state (i.e., de-liquefied LNG) or a gas/liquid mixture of natural gas upon entering the well506. The second stream of LNG538combined with the chemical agent517provides an enhanced treatment solution to remove formation and well damage. The treatment fluid558lands at a near wellbore region519of the formation501or in an area of reduced permeability around the well506. As described herein, the near-wellbore region519is the subterranean material and rock surrounding the well506and is considered the region within about 100 feet (ft) of the well506. The treatment fluid558flows into the well506and into the fractures510propagating through the reservoir volume502that have been damaged during the course of the drilling and the production operations. The treatment fluid558is used to carry out pre-fracturing treatments, fracture clean-out treatments, scale and deposit removal treatments, emulsion removal treatments, and corrosion inhibition, among others. The treatment fluid558can be injected during or after re-pressuring of the reservoir volume502.

Using the LNG538as a component of the treatment fluid558changes the physiochemical characteristics of one or more chemical agents517, for instance, the LNG538modulates or adjusts the reactive force of the agents517when in the presence of water. For example, one or more chemical agents injected into the well506can react with a metal surface, such as a metal surface of a packer521, to induce corrosion. Further, one or more of the chemical agents517may react with water injected or naturally found in the well506to produce an acidic solution. However, injecting the second stream of LNG538with the chemical agents517reduces or mitigates the acidic nature of the chemical agents517to reduce corrosion or other damaging effects in the well506and or formation501. In some cases, an injection rate of the second stream of LNG538is adjusted to control the corrosion rate of the surfaces susceptible to corrosion, such as the packer521.

It should be clearly understood that the fracturing system ofFIG. 5is merely one embodiment of an application of the principles of this disclosure in practice, and a wide variety of other embodiments are possible. Therefore, the scope of this disclosure is not limited at all to the details ofFIG. 5described herein and/or depicted in the additional drawings.

In addition, to the embodiments described above, many examples of specific combinations are within the scope of the disclosure, some of which are detailed below:

A method of treating a formation and a well extending therethrough, comprising: storing liquefied natural gas (LNG) at an on-site location of the well; injecting a first stream of LNG into the formation through the well to contact at least one of a surface of the formation or a metal surface locatable in the well; injecting a chemical agent into the formation through the well to contact at least one of the surface of the formation or the metal surface locatable in the well; and treating at least one of the surface of the formation or the metal surface locatable in the well with the chemical agent and the first stream of LNG.

The method of Example 1, wherein the treating of the metal surface with the chemical agent and the first stream of LNG comprises controlling a rate of corrosion in the well.

The method of Example 1, further comprising adjusting an injection rate of the first stream of LNG to control a rate of corrosion in the well.

The method of Example 1, wherein the treating of the formation with the chemical agent and the first stream of LNG comprises one of a pre-fracturing treatment, fracture cleaning-out treatment, scale and deposit removal treatment, and emulsion removal treatment.

Example 6. The method of Example 1, further comprising injecting the chemical agent and the first stream of LNG into a near wellbore region of the formation.

The method of Example 1, further comprising admixing the chemical agent and the first stream of LNG before injecting the chemical agent and the LNG into a near wellbore region of the formation.

The method of Example 1, further comprising storing the LNG at the on-site location as a cryogenic fluid at or below a temperature of about −260 Fahrenheit (° F.) (−162 Celsius (° C.)).

The method of Example 1, further comprising: de-liquefying a second stream of LNG into natural gas at the on-site location; and injecting the natural gas into the formation to pressurize a reservoir volume of the formation.

The method of Example 9, further comprising: pumping a third stream of the LNG at a fracturing pressure; and injecting the third stream of pressurized LNG into the well as a fracturing fluid to fracture the formation.

A system for treating a formation with a well therethrough, comprising a source of liquefied natural gas (LNG) located at an on-site location of the well and useable to supply the LNG; a chemical agent source usable to supply a chemical agent; a mixer located at the on-site location in fluid communication with the source of the LNG and the chemical agent source and configured to admix a first stream of LNG and the chemical agent to form a treatment mixture; and treatment injection equipment located at the on-site location and in fluid communication with the well to inject the treatment mixture into the well, the treatment mixture to treat a surface of the formation or a metal surface locatable in the well.

The system of Example 12, wherein the chemical agent is further selected from a group consisting of diverting agents, corrosion inhibitors, scale inhibitors, foaming agents, chemically-active nanoparticles and particulates.

The system of Example 11, wherein the source of LNG comprises a storage container and cooling system to store and maintain the LNG at or below a temperature of about −260 Fahrenheit (° F.) (−162 Celsius (° C.)).

The system of Example 11, further comprising: a cryogenic system located at the on-site location and comprising a pumping unit and a heating unit configured to de-liquefy a second stream of LNG to form natural gas; natural gas injection equipment comprising a pump configured to inject the natural gas into a reservoir volume of the formation; and wherein the injected natural gas pressurizes the reservoir volume.

A method of treating a formation with a well therethrough, comprising: injecting a first stream of liquefied natural gas (LNG) and a second stream of LNG into the well; injecting a chemical agent into the well; injecting a fracturing fluid into the well; treating at least one of a surface of the formation and a metal surface locatable in the well with the chemical agent and the first stream of LNG; and fracturing the formation with the fracturing fluid and the second stream of the LNG to increase recovery of fluids from the formation.

The method of Example 16, further comprising: admixing the chemical agent and the first stream of LNG to form a treatment mixture; and injecting the treatment mixture into the well to treat at least one of the surface of the formation and the metal surface locatable in the well.

The method of Example 16, further comprising adjusting a rate of the first stream of LNG injected into the well to control a rate of the corrosion in the well.

The method of Example 16, further comprising admixing the fracturing fluid and the second stream of LNG before injecting the fracturing fluid and the second stream of LNG into the well to fracture the formation.

The method of Example 16, further comprising transporting the LNG to the on-site location of the well and storing the LNG as a cryogenic fluid at or below a temperature of about −260 Fahrenheit (° F.) (−162 Celsius (° C.)).

In the previous discussion and in the claims, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “including,” “comprising,” and “having” and variations thereof are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” “mate,” “mount,” or any other term describing an interaction between elements is intended to mean either an indirect or a direct interaction between the elements described. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. The use of “top,” “bottom,” “above,” “below,” “upper,” “lower,” “up,” “down,” “vertical,” “horizontal,” and variations of these terms is made for convenience, but does not require any particular orientation of the components.

Reference throughout this specification to “one embodiment,” “an embodiment,” “an embodiment,” “embodiments,” “some embodiments,” “certain embodiments,” or similar language means that a particular feature, structure, or characteristic described in connection with the embodiment may be included in at least one embodiment of the present disclosure. Thus, these phrases or similar language throughout this specification may, but do not necessarily, all refer to the same embodiment.

The embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. It is to be fully recognized that the different teachings of the embodiments discussed may be employed separately or in any suitable combination to produce desired results. In addition, one skilled in the art will understand that the description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.