WO2018032086A1

WO2018032086A1 - Fracture length increasing method

Info

Publication number: WO2018032086A1
Application number: PCT/CA2017/000184
Authority: WO
Inventors: Michael Brady WEBB
Original assignee: Velvet Energy Ltd.
Priority date: 2016-08-18
Filing date: 2017-08-09
Publication date: 2018-02-22
Also published as: CA2939679A1

Abstract

A method to increase the effective length of a fracture stimulation by drilling line drive (parallel) horizontal wells in an orientation that will allow a hydraulically created fracture to propagate to the adjacent well bore. The stimulation is pumped into a treatment well there is pressure communication in the offset well. The treatment well is place on production to recover the initial flow back from the completion. Upon recovery of a sufficient volume of flow back fluid, the well is shut in. Subsequently, high pressure gas is injected into the treatment well. The injection pressure is designed not to exceed the formation frac pressure. This displaces the remaining fracture fluid to the offset horizontal well and effectively cleans up the entire length of propped fracture.

Description

FRACTURE LENGTH INCREASING METHOD

FIELD OF THE INVENTION

A method to increase the effective length of the fracture stimulation, more specifically to increase the effective length of fracture stimulation to an adjacent well bore.

BACKGROUND OF THE INVENTION

Hydraulic fracturing has been around for a number of years and has shown great potential in increasing the available and recoverable bitumen reserves. While there are detractors to this type of oil recovery, hydraulic fracturing, also referred to as fracking, has shown great promise and increased well productivity. However, common fracking techniques are as of yet incapable of providing optimal oil recovery from wells There are a number of oil recovery techniques which are available and implemented in the industry. The following patents and patent applications disclose available relevant techniques and applications as they relate to oil recovery.

Canadian patent no. 2 026 483 teaches a process for obtaining initial steam injectivity at below fracture pressure in initially immobile tar sands or other very viscous hydrocarbonaceous fluid containing formation, where at least one horizontal well bore is utilized. A horizontal well is drilled into the formation or immobile tar sand reservoir. Steam is then injected into the formation at a previously determined rate and at a pressure slightly above the formation or reservoir pressure. The steam is continuously circulated for a pre-determined time which causes the horizontal well to act as a heat conducting rod in the formation. Steam, however, does not enter the formation. Upon reaching the predetermined time, steam injection is discontinued and a hydrocarbonaceous fluid mixture is produced to the surface via said well.

Canadian patent no.2 169 808 teaches a method where a wellbore is drilled to penetrate the formation comprising a substantially vertical section and a substantially horizontal section. The vertical section of the wellbore is cased and the horizontal section of the wellbore is completed with a slotted liner. The wellbore is completed with an injection tubing that extends from the surface to the far end of the horizontal wellbore and a production tubing that extends from the surface to the beginning of the formation surrounding the horizontal wellbore to reduce the viscosity of the viscous oil. This step is continued until the temperature of the horizontal wellbore reaches the saturation temperature of steam at horizontal wellbore pressure. Thereafter, a slug of steam is injected into the horizontal wellbore at a pressure below the formation's fracture pressure.. Thereafter, the formation is allowed to soak for a short period, preferably 1 to 7 days. After the soak period, the well is then flowed back until the production of fluids including oil substantially declines. Thereafter, steam circulation in and out the horizontal wellbore is resumed at a pressure below the formation's fracture pressure thereby heating the formation surrounding the horizontal wellbore by conduction and convective heat to reduce the viscosity of the viscous oil and steam - lifting fluids including oil from the horizontal wellbore. Steam circulation is continued until oil recovery is unfavorable. The sequence of injecting a slug of steam, soak period, flow back and steam circulation are repeated for a plurality of cycles until the rate of oil recovery is unfavorable.

US patent no. 3,160,206 teaches a method of treating an earth formation penetrated by a well and in communication therewith for increasing the permeability of said formation adjacent said well, said method comprising the steps of pumping a predetermined volume of a cleaning fluid down the well and into contact with said formation, injecting said cleaning fluid into a portion of said formation, pumping a predetermined volume of a formation-plugging material down the well behind the cleaning fluid and contacting the formation with it to seal the most permeable zone thereof, and subsequently repeating said steps of successively pumping alternate volumes of cleaning fluid and sealing material down the well and into contact with unsealed portions of said formation, each of said volumes being a minor amount of the volume used in a one-stage treatment, said plugging material being of a composition that breaks down to a free-flowing fluid after being exposed for a predetermined time to the well conditions at the level of the portion of formation being treated.

US patent no. 3,902,422 teaches a process for producing a network of fractures in a deep segment of mineralized rock to prepare said segment for the in situ recovery of mineral values therefrom comprising a. forming an assemblage of cavities in said rock segment;

b. positioning chemical explosive charges in a plurality of said cavities in the sections thereof located in said rock segment;

c. allowing liquid to fill the fractures existing in the rock around the cavities in the sections thereof located in said rock segment as can be evidenced by a liquid level which is at least as high as the top of said rock segment; and

d. detonating said explosive charges sequentially, each detonation in the sequence producing a zone of fracture in said segment and a drop in the level of said liquid, as measurable in the cavity which contained the detonated charge or in a cavity adjacent thereto, said charges being sufficiently large and spaced sufficiently close together that the fracture zones produced in said segment by the detonations of charges in adjacent cavities overlap, the detonation of the charge in each cavity being delayed until after the level of the liquid, as measurable in the cavity containing the charge to be detonated or in a cavity lying within the zone of fracture produced by a previous detonation in a cavity adjacent thereto, has ceased to drop and is at least as high as the top of said rock segment.

US patent no. 3,933,205 teaches a method of well treatment by hydraulic fracturing of the formation to be treated, said fracturing including at least one double cycle comprising injection of fluid into the formation for a period of at least three minutes under pressure throughout said period sufficient to fracture the formation; planned discontinuance of said fluid injection and at least one period of reverse flow of said fluid from said formation for a period of time at least long enough to allow a significant pressure drop-in said fluid, resumption of injection, and discontinuance of injection.

US patent no. 4,836,284 teaches a process which involves creating one or more fractures in a formation, reducing the pressure on the formation such that the fracture is held open without significant further extension, and contacting virtually the entire fracture surface area with acid flowed at rates sufficient to replace any fluids which leak off from the fracture, such that a flow rate equilibrium is approximately maintained. While the pressure on the fracture is held below the pressure at which the fracture was propagated in the formation, but above the pressure at which the fracture will close, the acid may flow through the fracture at a declining rate for a relatively long period of time, without significant further extension of the fracture. As the acid contacts the faces of the fracture, flow channels are etched in the fracture faces.

US patent no. 5,027,899 teaches a method of gravel packing a well bore annulus having a drainage radius, including perforations extending into a producing formation, comprising the sequential steps of:

(a) introducing a slurry of gravel in a carrier fluid into said annulus through the perforations and into said formation, said slurry being introduced at a pressure in excess of the formation fracturing pressure and in an amount to produce fractures extending outwardly a length of from 5 to 25 percent of the well bore drainage radius, and

(b) introducing another slurry of gravel in a carrier fluid into said annulus and through the perforations, said slurry being introduced at a pressure below the formation fracturing pressure. US patent no. 5,131,472 teaches a method of stimulating a well by suddenly applying pressures to the formation of interest in excess of fracturing pressure in the formation and pumping fluid into the well before pressure declines substantially below fracturing pressure. According to another embodiment, casing in the well is perforated originally or additionally into the zone of interest by a tubing-conveyed apparatus and the well is pressured with gas pressure and a gas-liquid mixture, the liquid containing solid particles, is pumped into the well immediately after the perforating apparatus operates.

US patent no. 5,253,707 teaches an improved method for fracturing an earth formation from a fluid injection well to improve the fluid injectivity rate without concomitant increase in fluid injection pressure, thereby increasing the rate of production fluids and extending the life of earth formations from which fluids are produced by pressure support of the formation with fluids including water and other fluid injection processes. The description also states that after a suitable liquid injection phase of the cycle, miscible gas is injected into the formation through the wellbore at pressures below the formation fracture pressure at the already-created fractures. In this way the near wellbore, unpropped portion of the fracture recloses and the injection gas is forced out into the formation over a broader area and does not enter the fracture itself.

US patent no. 6,192,985 B l teaches a method to manipulate the fluid in the near-tip region (based upon reservoir conditions) so that it has a greater mobility than the slab of fluid immediately proximal to it, that slab has a greater mobility than the slab of fluid immediately proximal to it, and so forth. The term "differential mobility" subsumes two primary mechanisms: differential viscosity (fluid movement in response to a viscosity gradient) and differential density (fluid movement in response to a density gradient). The description also mentions a non-uniform breaker schedule, and the use of foamed or energized fluids in the early pumping stages (near-tip region) and/or means to inhibit proppant flowback (e.g., fibers) in industry (hence one half of the entire fracture length is filled with stagnant fracturing fluid therefore preventing hydrocarbon production through this region) despite the extraordinary drain they cause on overall hydrocarbon recovery.

US patent no. 6,988,552 teaches a method for cleaning a gas well comprising: injecting a predetermined quantity of a treatment liquid comprising from 84.5% to 100% liquid carbon dioxide and from 0% to 15.5%) of a breaker composition into a wellbore and at least a portion of the near wellbore formation of a gas bearing formation, such that the pressure is below the fracturing pressure of said gas bearing formation; and releasing the pressure on said wellbore and allowing the liquid carbon dioxide to vaporize and flow out of the well.

US patent no. 7,677,317 B2 teaches a method for cleaning a wellbore in a formation comprising the steps of a) inserting a desired length of tubing into the wellbore; b) introducing a treatment medium comprising liquid carbon dioxide through the tubing into one or more locations within the wellbore and into at least a portion of the formation adjacent to the wellbore; and c) vaporizing at least a portion of said treatment medium after it is injected into said wellbore. The description also mentions in an alternate embodiment of the method of the present invention, flexible or coiled tubing can be used. In another embodiment, the treatment medium may impinge the casing perforations, the casing and/or the wellbore through the use of a nozzle or jetting tool which may be either affixed to, or integral with, the tubing. In another embodiment, the treatment medium can be injected into the wellbore and/or near wellbore areas such that the pressure within the formation remains below the fracturing pressure of the formation.

US patent no. 7,878,248 B2 teaches a method, comprising: hydraulically fracturing a subterranean formation with a first treatment fluid; allowing the hydraulic fracture to close; allowing the hydraulic fracture to unload and flow fluid out of the wellbore; preparing a second treatment fluid comprising carbon dioxide; and injecting the second treatment fluid into the subterranean formation at a downhole pressure below a fracturing pressure for the subterranean formation. US patent application no. 2013/01 18750 Al discloses a method comprising: injecting a first viscous fluid into a wellbore at a downhole treating pressure exceeding a first fracture initiation pressure; injecting a first high solids content fluid (HSCF) into the wellbore, maintaining the downhole treating pressure below a second fracture initiation pressure until a fracture termination event occurs; injecting a second viscous fluid into the wellbore at a downhole pressure exceeding a second fracture initiation pressure; and injecting a second HSCF fluid into the wellbore.

US patent application no. 2015/0060063 teaches a method, comprising: placing a downhole completion staging system tool in a wellbore adjacent a subterranean formation; operating the downhole completion staging system tool to establish one or more passages for fluid communication between the wellbore and the subterranean formation in a plurality of wellbore stages spaced along the wellbore; isolating one of the wellbore stages for treatment; injecting a in situ channelization treatment fluid through the wellbore and the one or more passages of the isolated wellbore stage into the subterranean formation to place clusters in a fracture in the subterranean formation; and repeating the isolation and clusters placement for one or more additional stages.

US patent application no. 2015/0060064 A 1 teaches a method comprising: placing in a wellbore adjacent a subterranean formation a downhole completion staging system production liner fitted with a plurality of sliding sleeves in the closed position; placing into the wellbore a downhole completion staging system tool comprising a sleeve-shifting device, using an in situ channelization treatment fluid as a medium to transport the downhole completion staging system tool; translating the downhole completion staging system tool into a capture feature of the downhole completion staging system to operate one or more of the sliding sleeves to open one or more fracturing ports for fluid communication between the wellbore and the subterranean formation in one of a plurality of wellbore stages spaced along the wellbore; isolating the one of the wellbore stages for treatment; injecting the in situ channelization treatment fluid through the wellbore and the one or more fracturing ports of the isolated wellbore stage to place particulate clusters in a fracture in the subterranean formation; and repeating the isolation and particulate clusters placement to treat one or more additional stages.

US patent application no. 2015/0292308 teaches a method for stimulating a well in a nano-darcy shale formation comprising: providing a treatment mixture containing between about 0.1% and 95% by weight metal complexing agent at a pH of between about 0 and 10; injecting the treatment mixture into the well at a pressure less than a fracture pressure of the nano-darcy shale formation until at least some of the treatment mixture contacts the nano-darcy shale formation; maintaining the treatment mixture in contact with the nano-darcy shale formation for a contact time of between about 1 minute to 100 days, thereby allowing the metal complexing agent to bind with at least some naturally-occurring metals contained within the nano- darcy shale formation; and removing the treatment mixture from the well after the contact time, thereby removing the bound naturally-occurring metals from the nano-darcy shale formation and thereby improving the hydrocarbon production of the well relative to the hydrocarbon production immediately prior to performance of the method.

Accordingly, there is still a need for a process to extract oil from a well which has been fracked and which no longer produces sufficient amounts of oil to be commercially viable.

SUMMARY OF THE INVENTION

According to one aspect of the present invention, there is provided a novel method to increase the output of an oil well or gas well which has been tracked. According to a preferred embodiment of the present invention, the method provides an increase in the effective length of the fracture stimulation. This is preferably done by drilling line drive (parallel) horizontal wells in an orientation that will allow a hydraulically created fracture to propagate to an adjacent well bore. The stimulation is pumped into a treatment well until there is pressure communication in an adjacent well. This is repeated down the treatment well bore until the entire well bore has been stimulated. According to a preferred embodiment, the treatment well is placed on production to recover the initial flow back from the completion (usually 3 to 4 days, but may depend on the formation properties). Once a sufficient volume of flow back fluid is recovered, the well is shut in. According to a preferred embodiment of the present invention, high pressure gas is subsequently injected into the treatment well.

Preferably, the injection pressure should not exceed the formation fracturing pressure. The injection pressure displaces the remaining fracture fluid to an adjacent offset horizontal well and effectively cleans up the entire length of propped fracture. The amount of gas injected depends on the amount of hydraulic fluid injected but will generally be less than 2 times the reservoir volume of the fracture fluid injected. The well is subsequently placed on production. The process may or may not be repeated in the adjacent offset well.

BRIEF DESCRIPTION OF THE FIGURES

The present invention may be better understood in consideration of the following description of various embodiments of the invention in connection with the accompanying drawings, in which:

Figure la is a top cross-sectional view of a well bore and the fracture.

Figure lb is a top cross-sectional view of a well bore and the effective fracture length.

Figure 2 is a graph depicting the volume yield from conventional fracking activities and from a method according to the present invention.

Figure 3 is a schematic representation of the two adjacent well bores (Hz-1 and Hz-2) and the fracture length between the two wells. DESCRIPTION OF A PREFERRED EMBODIMENT OF THE INVENTION

To conduct an effective fracking operation there are a number of parameters that one must take into account. The following is a non-comprehensive list of factors that come into play when deploying a fracking operation: formation permeability; total fluid volume pumped; fracture-fluid viscosity; injection rate; in situ stress profile; and the type of proppant used. Formation permeability is an indicator of the capacity of fluid to pass through a rock formation. Facture-fluid viscosity is an indication of how the viscosity of a fluid which is important to maintain proppant in suspension while the fluid is being pumped into a well for fracking. The selected fracturing fluid should be capable of transporting the proppant over long distances, generally be compatible with the formation rock and fluid. Ideally as well, the fracturing fluid should be capable to create a high width fracture, minimize pressure loss caused by friction and use products/chemicals which are compliant with the regulations in place. Ultimately, the fluids as well as the proppants must be cost effective or else the entire operation becomes moot.

A fracking operation is a capital intensive endeavor for oil recovery as opposed to conventional well oil recovery. Any increase in efficiency can justify new exploration and consideration of new wells to recover seemingly depleted hydrocarbon reservoirs.

According to a preferred embodiment of the present invention, the method, when hydraulically fracture stimulating horizontal wells, comprises the injection of fluid and sand into the wellbore. The pressure breaks down the formation and the fluid and sand are carried out into the formation through induced fractures. These fractures are usually 3-7 mm wide. At the end of pumping, the fracture contains proppant (generally proppants are sand but can be also include man-made proppants) and a fluid (usually water-based but can be carbon dioxide, nitrogen gas or be hydrocarbon-based). Subsequently, the well is placed on flow back in an attempt to recover as much of the injected fluid as possible leaving the sand behind. In general, fluid recovery is low (less than 1/3 of the injected fluid is usually recovered). The fluid remaining resides in the induced fracture and formation. The length of the sand filled fracture is often several hundreds of feet out from the wellbore.

Through certain test and analyzing the production history of these hydraulically stimulated wells, it was determined that the effective length of the induced fracture is always much less than the propped fracture length. It is thought that by increasing the effective length of the fracture, the productivity of the well can similarly be increased. Figures 1 and 2 are reservoir simulator results that illustrate the benefit for cleaning up the fracture stimulation for a typical gas/oil well that is being drilled. Figure 2 shows that the method according to a preferred embodiment of the present invention will allow to recover the same amount of gas in 3 years that was recovered in 30 years from the conventionally stimulated well and if produced longer is expected to recover 28% more gas.

Figure 2 shows the associated oil recovery from the well. As with the gas, oil recovery is greatly accelerated and has higher recovery.

Figure la is a schematic depiction of the cross-section of a well having had a fracture treatment. It shows the wellbore ( 10), the created fracture ( 12), the created fracture length ( 14), and the filtrate invaded zone (16).

Figure lb is a schematic depiction of the cross-section of a well having had a fracture treatment. It shows the wellbore (10), the created fracture (12), the created fracture length (14), and the propped fracture length (18), the effective fracture length (24). Although the propped fracture length is of a length called L_p it does not provide production along the entire length. Rather, production from fracking is limited to the effective fracture length (24), L_eF- The present invention provides for increased production, access to a larger oil volume by increasing the effective fracture length through a subsequent injection of a high pressure fluid to push the proppant present in the created fracture further outwards. Preferably, the method according to a preferred embodiment provides for the zonal communication between to wellbores by having the second fluid injection injected in first well bore breach through to an adjacent wellbore.

The stimulation fluid can be selected form the group consisting of: slickwater; linear gel fluids; borate crosslinked gel fluids; organometallic crosslinked fluids; gelled oil fluids; liquid gel concentrates; foamed fluids; and guar-based fluids. Slickwater is a low viscosity water-based fracturing fluid uses friction reducer additives to reduce friction pressure up to 70%. Friction reducers include polyacrylamide derivatives and copolymers added to water at low concentrations. Linear gel fracturing fluids are formulated with a wide array of different polymers in an aqueous base. Polymers that are commonly used in these include guar, hydroxypropyl guar (HPG), carboxymethyl HPG (CMHPG), and hydroxyethyl cellulose (HEC). These polymers are dry powders that hydrate or swell when mixed with an aqueous solution and form a viscous gel. Borate crosslinked gel fracturing fluids utilize borate ions to crosslink the hydrated polymers and provide increased viscosity. The polymers most often used in these fluids are guar and HPG. Organometallic Crosslinked fluids that are commonly used include zirconate and titanate complexes of guar, hydroxypropyl guar (HPG) and carboxymethyl-hydroxypropyl guar (CMHPG). Gelled oil fluids are simply gelled oil systems. Liquid gel concentrates are concentrated liquid slurries prepared with the polymers. Foamed fluids provide energized gas for fluid recovery after the fracturing treatment. Foamed fracturing fluids contain the liquid phase of the fluid system (usually gelled), a foaming agent, and an internal phase of typically 60 to 80% of N2 or C0₂. According to an embodiment of the present invention, a first wellbore is drilled having a horizontal section intersecting at least one subterranean hydrocarbon containing formation. According to the same embodiment, a second adjacent horizontal wellbore is drilled within sufficient proximity of said first wellbore to allow for zonal communication following fracturing to breach through from either wellbore. According to a preferred embodiment of the method, the treatment fluid used in the second injection can include a liquid or a gas. Preferably, if the fluid selected is a gas, it will be under high pressure gases that can be used include carbon dioxide. Liquids that can be used include brine. The pressure of the injected fluid must be sufficiently high enough to be capable of displacing the first treatment fluid further into the fracture. This has two immediate benefits: increase in the productivity of a well by using the same amount of proppant and eliminates the need to drill additional wellbores.

Additional compounds (additives) may be employed during the second injection to minimize friction losses, for example. Such additives include but are not limited to polymer and/or viscoelastic surfactants. The type of additive and amount thereof can be selected by the person skilled in the art based on the information available relating to the type of formation, proppant and other parameters specific as the case may be.

The necessary equipment to perform the injection of fluid (i.e. the second injection) includes a pump adapted to provide sufficient fluid injection pressure to inject into the wellbore and the created fracture and displace the first treatment fluid. Of course, the person skilled in the art will understand that one or more pumps may be used to perform this step without departing from the scope of the present invention. The pump (or pumps) is operatively connected to the wellbore. The wellbore contains a casing disposed therein. Said casing having certain predetermined perforated sections where the fracking fluid exits the wellbore and enters the formation to be fracked.

According to a preferred embodiment, the wellbores offsetting the treatment wellbore contain pressure sensors located therein to allow for better monitoring of the fracking activities and to assess whether or not zonal communication has been achieved between two adjacent horizontal wellbores.

FIG. 3 is a schematic flow diagram of a method according to a preferred embodiment of the present invention to enhance the fracture length in a fracked well and thereby have the fracture become in fluid communication with an adjacent well. From a first horizontal well (32) propagate eleven hydraulic fracture sites (3 1 ) which are interspersed with fracture sites (33) from a second parallel horizontal well (34).

The primary treatment which involves the initial fracking of the formation is not to be understood as the part of the inventive aspect of the process but is to be understood as part of the comprehensive process where the novel method disclosed herein provides for increased yields from established wells.

According to a preferred embodiment of the present invention, a plurality of hydraulic fractures emanating from the wellbore receive a secondary treatment until there is fluid communication with an adjacent well. Subsequently, the adjacent well is put into production to recover hydrocarbon and fracking fluid

According to a preferred embodiment, where a wellbore has a number of fractures extending therefrom, the method can be applied to a select number of the fractures already present or can be applied to the entirety of the fractures emanating from the treatment well. This can be done in the case where certain fracked areas have a higher hydrocarbon reserve potential than other fracked areas.

According to a preferred embodiment of the present invention, the method comprises fracking a subterranean formation in at least two adjacent wells with a first treatment fluid.(the first treatment fluid must establish pressure communication with the offsetting wellbore; allowing the fracture thus formed to close; preparing a second treatment fluid; injecting the second treatment fluid into the subterranean formation at a downhole pressure at a pressure less than the fracturing pressure of the subterranean formation; maintaining the downhole pressure of the second treatment fluid above a threshold pressure (close to initial reservoir pressure) value and for a sufficient period of time to allow for first treatment fluid be displaced from the treatment fracture to the adjacent wells.

The terms and descriptions used herein are set forth by way of illustration only and are not meant as limitations unless otherwise specifically indicated. Those skilled in the art will recognize that many variations are possible within the scope of the invention as defined in the following claims, and their equivalents, in which all terms are to be understood in their broadest possible sense unless otherwise specifically indicated. While the system shown and described in detail herein is fully capable of attaining the above-described aspects of the invention, the persons skilled in the art will understand that it is but a preferred embodiment of the present invention and the invention is not to be limited to that singular embodiment.

Claims

1. A method to increase the effective length of a fracture between at least two horizontal hydrocarbon wellbores, said method comprising:

- providing a first horizontal treatment well bore;

- providing a second horizontal well bore located adjacent said first well bore;

- injecting a stimulation fluid to stimulate a section of the treatment well bore until the second horizontal well bore shows signs of pressure communication;

- placing the treatment well back on production;

- recovering a sufficient volume of flow back fluid from the completion;

- shutting in the well;

- injecting a fluid at a high injection pressure into the treatment well, where the injection pressure does not exceed the formation fracture pressure;

- displacing the remaining stimulation fluid to the second horizontal well bore; and

- placing the second horizontal well on production.

2. The process according to claim 1 , where the second well is fracked and flowing it back and injecting the second treatment fluid to displace the frac fluid to the first well. 3. The method according to claim 1, wherein the stimulation fluid is selected form the group consisting of: slickwater; linear gel fluids; borate crosslinked gel fluids; organometallic crosslinked fluids; gelled oil fluids; liquid gel concentrates; foamed fluids; and guar-based fluids.

3. The method according to any one of claims 1 to 3, wherein the gas is selected form the group consisting of: methane; ethane; propane; butane; pentane; C0₂; N₂; air; flue gas; and combinations thereof.

4. The method according to any one of claims 1 to 4, wherein the injection pressure ranges from at least 70 % to 99% of the frac pressure.

5. The method according to claim 4, wherein the injection pressure ranges from at least 90 % to 99% of the frac pressure.