SYSTEMS AND METHODS FOR IMPROVING RESERVOIR FLUID RECOVERY FROM FRACTURED SUBTERRANEAN FORMATIONS

Abstract

Systems and methods for improving reservoir fluid recovery from fractured subterranean formations. The methods may include injecting a pressurizing fluid into an injection fracture that extends within a subterranean formation and producing a produced fluid from a production fracture that extends within the subterranean formation. The production fracture is spaced apart from the injection fracture and is in indirect fluid communication with the injection fracture via a portion of the subterranean formation that extends therebetween and the pressurizing fluid injection provides a motive force for the production of the produced fluid. The methods further include injecting a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture. The systems may include hydrocarbon production systems that may be utilized to perform the methods and/or that may be created while performing the methods.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the priority benefit of U.S. Provisional Patent Application 61/845,862 filed Jul. 12, 2013 entitled SYSTEMS AND METHODS FOR IMPROVING RESERVOIR FLUID RECOVERY FROM FRACTURED SUBTERRANEAN FORMATIONS, the entirety of which is incorporated by reference herein.

FIELD

The present disclosure is directed generally to systems and methods for improving reservoir fluid recovery from fractured subterranean formations, and more particularly to systems and methods that include injection of a foaming agent into a production fracture to enhance production of the reservoir fluid from the subterranean formation and/or to limit production of a pressurizing fluid from the subterranean formation.

BACKGROUND

Production of reservoir fluid (or hydrocarbons) from low permeability reservoirs (or hydrocarbon reservoirs), such as reservoirs with fluid permeabilities of less than 10 millidarcy (md), presents unique challenges associated with generation of acceptable flow rates of the reservoir fluid within the reservoir and/or economical production rates of the reservoir fluid from the reservoir. However, because of the large number of low permeability reservoirs that exist, their overall size, and the volume of hydrocarbons that are contained therein, the potential rewards associated with production from these low permeability reservoirs are substantial. Thus, the oil and gas industry is devoting significant resources to the development of economical production methodologies for low permeability reservoirs.

One such production methodology is hydraulic fracturing, which generates fractures in the low permeability reservoir to increase the fluid permeability of the reservoir. While hydraulic fracturing may permit production of some of the reservoir fluid that is present within low permeability reservoirs, the maximum achievable recovery typically is only 15%.

One challenge associated with increasing the economic recovery of reservoir fluid is generation of a driving force for fluid flow within the reservoir. Conventionally, reservoirs that have been hydraulically fractured rely upon volumetric expansion of the reservoir fluid and/or compaction of the reservoir itself to provide the driving force for reservoir fluid production, and attempts to provide additional pressure support often have been unsuccessful.

For example, and in conventional (or high permeability) reservoirs, water may be injected to pressurize the reservoir and provide a driving force for production of reservoir fluid from the reservoir. However, in low permeability reservoirs, water injection may be ineffective due to low water permeability of the reservoir, plugging of a pore space within the reservoir, and/or injection pressure constraints. An alternative to water injection is gas injection. However, this approach also has been largely unsuccessful due to the relatively tight well spacing that is utilized in low permeability reservoirs and the existence of higher permeability zones or streaks within the reservoir. These higher permeability zones may serve as bypass pathways that permit the injected gas to flow from an injection well to a production well without providing a desired level of pressure support for production of reservoir fluid from the reservoir. Thus, there exists a need for improved systems and methods for improving reservoir fluid recovery from fractured subterranean formations, including fractured low permeability subterranean formations.

SUMMARY

Systems and methods for improving reservoir fluid recovery from fractured subterranean formations are disclosed herein. The methods may include injecting a pressurizing fluid into an injection fracture that extends within a subterranean formation and producing a produced fluid from a production fracture that extends within the subterranean formation. The production fracture is spaced apart from the injection fracture and is in indirect fluid communication with the injection fracture via a portion of the subterranean formation that extends therebetween and the pressurizing fluid injection provides a motive force for the production of the produced fluid. The methods further may include injecting a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture.

The methods further may include ceasing the producing during the injecting the foaming agent and resuming the producing subsequent to the injecting the foaming agent. The injecting the pressurizing fluid and the injecting the foaming agent may be performed at least partially concurrently. Additionally or alternatively, the injecting the pressurizing fluid and the injecting the foaming agent may be performed sequentially. Further additionally, the injecting the foaming agent may occur prior to the injecting the pressurizing fluid.

A single wellbore may be utilized to provide both the pressurizing fluid and the foaming agent to the injection fracture and the production fracture, respectively. Additionally or alternatively, separate wellbores may be utilized to provide the pressurizing fluid and the foaming agent to the injection fracture and the production fracture, respectively.

Injecting the foaming agent may include injecting a substantially continuous foaming agent stream. The injecting the foaming agent may include injecting alternating volumes of a liquid foaming agent and a gas. The injecting the foaming agent may include preferentially diverting the pressurizing fluid into an unproduced region of the subterranean formation.

The methods further may include forming the injection fracture and/or the production fracture. The forming may include restricting intersection of the injection fracture and the production fracture. The methods further may include repeating at least a portion of the methods.

The methods further may include detecting a variable associated with production of the pressurizing fluid from the production fracture and the injecting the foaming agent is based, at least in part, on the detecting. The methods further may include determining that the pressurizing fluid is being produced from the production fracture and the injecting the foaming agent is based, at least in part, on the determining.

The systems include hydrocarbon production systems that may be utilized to perform the methods and/or that may be created while performing the methods and include the injection fracture and the production fracture. The systems further may include a pressurizing fluid supply system that is configured to inject the pressurizing fluid into the injection fracture and a foaming agent supply system that is configured to selectively inject the foaming agent into the production fracture.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of illustrative, non-exclusive examples of a hydrocarbon production system that may include and/or utilize the systems and methods according to the present disclosure.

FIG. 2 provides schematic cross-sectional views of illustrative, non-exclusive examples of a subterranean formation that includes an injection fracture and a production fracture that may be utilized with the systems and methods according to the present disclosure.

FIG. 3 is another schematic cross-sectional view of the subterranean formation of FIG. 2 subsequent to production of a portion of the reservoir fluid from the subterranean formation.

FIG. 4 is another schematic cross-sectional view of the subterranean formation of FIG. 3 subsequent to injection of a foaming agent into the production fracture.

FIG. 5 is another schematic cross-sectional view of the subterranean formation of FIG. 4 during production of additional reservoir fluid from the subterranean formation.

FIG. 6 is a flowchart depicting methods according to the present disclosure.

DETAILED DESCRIPTION

FIGS. 1-5 provide illustrative, non-exclusive examples of hydrocarbon production systems 10 according to the present disclosure, components thereof, and/or process flows that may be utilized therewith. Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of FIGS. 1-5, and these elements may not be discussed in detail herein with reference to each of FIGS. 1-5. Similarly, all elements may not be labeled in each of FIGS. 1-5, but reference numerals associated therewith may be utilized herein for consistency. Elements, components, and/or features that are discussed herein with reference to one or more of FIGS. 1-5 may be included in and/or utilized with any of FIGS. 1-5 without departing from the scope of the present disclosure.

In general, elements that are likely to be included are illustrated in solid lines, while elements that are optional are illustrated in dashed lines. However, elements that are shown in solid lines may not be essential, and an element shown in solid lines may be omitted without departing from the scope of the present disclosure.

FIG. 1 is a schematic representation of illustrative, non-exclusive examples of a hydrocarbon production system 10 that may include and/or utilize the systems and methods according to the present disclosure. Hydrocarbon production system 10 is configured to produce a reservoir fluid 22 from a subterranean formation 20 that is present within a subsurface region 14. As illustrated in FIG. 1, hydrocarbon production system 10 includes an injection fracture 50 and a production fracture 60, both of which extend within the subterranean formation (such as to increase a fluid permeability of the subterranean formation). The production fracture is spaced apart from the injection fracture and is in indirect fluid communication with the production fracture via a portion 24 of subterranean formation 20 that extends therebetween.

Hydrocarbon production system 10 further includes a pressurizing fluid supply system 80 that is configured to inject a pressurizing fluid 82 into injection fracture 50 (such as via a suitable wellbore 30). The pressurizing fluid increases a pressure within subterranean formation 20 proximal to, locally to, and/or in a vicinity of injection fracture 50. This increase in pressure provides a driving, or motive, force for flow of reservoir fluid 22 that may be present within portion 24 of the subterranean formation into production fracture 60. The reservoir fluid then may flow from the subterranean formation to a surface region 12 (such as via a suitable wellbore 30) as a produced fluid 62.

Hydrocarbon production system 10 also includes a foaming agent supply system 90 that is configured to selectively inject a foaming agent 92 into production fracture 60. As discussed in more detail with reference to FIGS. 2-5, foaming agent 92 may form, generate, produce, and/or become a flow restriction within subterranean formation 20, thereby limiting flow of pressurizing fluid 82 from injection fracture 50 to production fracture 60 and/or limiting production of pressurizing fluid 82 from the production fracture.

FIGS. 2-5 are schematic cross-sectional views of illustrative, non-exclusive examples of a subterranean formation 20 that includes an injection fracture 50 and a production fracture 60 that may be utilized with the systems and methods according to the present disclosure and that may include and/or be subterranean formation 20, injection fracture 50, and/or production fracture 60 of FIG. 1. In FIG. 2, pressurizing fluid 82 is provided to injection fracture 50. As illustrated in dash-dot lines in FIG. 2, pressurizing fluid 82 may flow into portion 24 of subterranean formation 20 that is located between injection fracture 50 and production fracture 60. Pressurizing fluid 82 may pressurize the subterranean formation in a region that is proximal to the injection fracture. This may provide a driving force for flow of reservoir fluid 22 from portion 24 and into production fracture 60, as illustrated. The reservoir fluid then may be produced from production fracture 60 as produced fluid 62.

In FIG. 2, produced fluid 62 is illustrated as exiting production fracture 60 from a portion of the production fracture that is proximal to a portion of injection fracture 50 that receives pressurizing fluid 82 and/or from a portion of the production fracture that is distal from the portion of the injection fracture that receives the pressurizing fluid. The conduit that provides pressurizing fluid 82 to the injection fracture and the conduit that receives produced fluid 62 from the production fracture may be proximal to one another (or located in the same wellbore) and/or may be distal from one another (or located in different wellbores).

FIG. 2 also illustrates in dashed lines that pressurizing fluid 82 may flow through portion 24 of subterranean formation 20 and enter production fracture 60. This pressurizing fluid may combine with reservoir fluid 22 to form a portion of produced fluid 62 and be produced from the subterranean formation, as discussed in more detail herein with reference to FIG. 3. However, the presence of pressurizing fluid 82 (or a significant amount of pressurizing fluid 82) within produced fluid 62 may be undesirable and/or may decrease an overall efficiency of hydrocarbon production system 10.

FIG. 3 illustrates that pressurizing fluid 82 may flow through certain regions of portion 24 of subterranean formation 20, while bypassing, or channeling around, other regions of portion 24. Thus, and subsequent to providing pressurizing fluid 82 to subterranean formation 20 for a period of time, portion 24 may include produced regions 72, in which a substantial portion of reservoir fluid 22 has been removed and/or swept, and unproduced regions 76, wherein a substantial portion of reservoir fluid 22 remains. The flow through produced regions 72 may be detrimental to maximizing production of reservoir fluid 22 from subterranean formation 20 and/or may decrease an overall efficiency of production of the reservoir fluid from the subterranean formation.

As an illustrative, non-exclusive example, and since pressurizing fluid 82 simply may flow from injection fracture 50 to production fracture 60 via produced regions 72, reservoir fluid that is present within unproduced regions 76 may not be removed from the subterranean formation. As another illustrative, non-exclusive example, flow of pressurizing fluid 82 through produced regions 72 may increase a proportion of the pressurizing fluid within produced fluid 62, thereby decreasing an overall efficiency of production of reservoir fluid 22 from subterranean formation 20.

Such a structure may be present when subterranean formation 20 is a heterogeneous subterranean formation 20 that includes regions and/or zones of varying fluid permeability. As an illustrative, non-exclusive example, produced regions 72 may represent regions of (relatively) higher fluid permeability, while unproduced regions 76 may represent regions of (relatively) lower fluid permeability. With this in mind, the systems and methods according to the present disclosure may be effective at improving reservoir fluid production from both heterogeneous subterranean formations and homogeneous subterranean formations; however, the benefits of the systems and methods according to the present disclosure may increase for heterogeneous subterranean formations.

Thus, and as illustrated in FIG. 4, the systems and methods include injection of a foaming agent 92 into production fracture 60. Foaming agent 92 may flow from production fracture 60 into produced regions 72 to generate a fluid flow restriction 96 therein. As illustrative, non-exclusive examples, foaming agent 92 may block, restrict, and/or occlude fluid flow through produced regions 72, may increase an effective viscosity of the fluid that is present within produced regions 72, and/or may decrease an effective mobility of the fluid that is present within produced regions 72, thereby decreasing a flow rate of pressurizing fluid 82 through produced regions 72.

Foaming agent 92 may restrict fluid flow through produced regions 72 in any suitable manner. As an illustrative, non-exclusive example, the foaming agent may foam within produced regions 72 to generate fluid flow restrictions 96. Fluid flow restrictions 96 may be present in any suitable portion, or fraction, of produced regions 72. As an illustrative, non-exclusive example, and as illustrated in solid lines in FIG. 4, the fluid flow restriction may be present within a fraction of (or less than the entirety of) a volume that is defined by produced regions 72 (or each produced region 72). As another illustrative, non-exclusive example, and as illustrated in dashed lines in FIG. 4, the fluid flow restriction may be present in all (or at least substantially all) of the volume that is defined by produced regions 72 (or each produced region 72).

Subsequent to formation of fluid flow restrictions 96, and as illustrated in FIG. 5, pressurizing fluid 82 may be pushed, forced, diverted, and/or urged into unproduced regions 76, thereby providing a driving force for flow of reservoir fluid 22 from the unproduced region 76. This may decrease the proportion of pressurizing fluid 82 within produced fluid 62, increase production of reservoir fluid 22 from unproduced regions 76, and/or increase an overall sweep efficiency of subterranean formation 20 and/or of portion 24 of the subterranean formation 20.

With reference to FIGS. 1-5, pressurizing fluid 82 may be provided to injection fracture 50 in any suitable manner. Additionally or alternatively, produced fluid 62 may be received from production fracture 60 in any suitable manner and/or foaming agent 92 may be provided to production fracture 60 in any suitable manner.

As an illustrative, non-exclusive example, and as illustrated in solid lines in FIG. 1, hydrocarbon production system 10 may include a wellbore 30 that extends within subterranean formation 20, and injection fracture 50 and production fracture 60 both may originate and/or emanate from wellbore 30. Under these conditions, hydrocarbon production system 10 further may include an injection conduit 84 that extends within wellbore 30 and a production conduit 94 that also extends within wellbore 30 (or within the same wellbore 30). Injection conduit 84 may extend and/or provide fluid communication between pressurizing fluid supply system 80 and injection fracture 50. Similarly, production conduit 94 may extend and/or provide fluid communication between foaming agent supply system 90 and production fracture 60.

When wellbore 30 includes both injection conduit 84 and production conduit 94, a portion of the injection conduit that extends within the wellbore may be fluidly isolated from a portion of the production conduit that extends within the wellbore. As illustrative, non-exclusive examples, the injection conduit may be spaced apart from the production conduit, discrete from the production conduit, fluidly isolated from the production conduit, and/or radially spaced apart from the production conduit.

As more specific but still illustrative, non-exclusive examples, injection conduit 84 and production conduit 94 may be defined by separate and/or distinct lengths of pipe and/or tubing that extend within wellbore 30. As a more specific but still illustrative, non-exclusive example, one of injection conduit 84 and production conduit 94 may be defined by a length of pipe and/or tubing that extends within wellbore 30, while the other may be an annular space that is defined between the pipe and/or tubing and wellbore 30. Regardless of the specific configuration of injection conduit 84 and production conduit 94, subterranean formation 20 (or portion 24 thereof) may provide fluid communication (or indirect fluid communication) between the injection conduit and the production conduit, such as via injection fracture 50, production fracture 60, and portion 24 of subterranean formation 20.

As another illustrative, non-exclusive example, hydrocarbon production system 10 may include a production wellbore 32 (as illustrated in solid lines in FIG. 1) and an injection wellbore 34 (as illustrated in dashed lines in FIG. 1). The production wellbore may be spaced apart from, separate from, distinct from, and/or formed separately from the injection wellbore. Injection conduit 84 may be defined by and/or within injection wellbore 34, and injection fracture 50 may originate and/or emanate from the injection wellbore. Similarly, production conduit 94 may be defined by and/or within production wellbore 32, and production fracture 60 may originate and/or emanate from the production wellbore.

Under these conditions, pressurizing fluid supply system 80 may be configured to provide pressurizing fluid 82 to injection fracture 50 via injection wellbore 34, and foaming agent supply system 90 may be configured to provide foaming agent 92 to production fracture 60 via production wellbore 32. In addition, subterranean formation 20 (or portion 24 thereof) provides fluid communication (or indirect fluid communication) between injection wellbore 34 and production wellbore 32 via injection fracture 50 and production fracture 60, respectively.

As illustrated in dashed lines in FIG. 1, hydrocarbon production system 10 may include a plurality of injection fractures 50 and/or a plurality of production fractures 60, with each of the injection fractures being associated with one or more of the production fractures (or being in fluid communication therewith via a respective portion of subterranean formation 20). Thus, and as illustrated in FIG. 1, injection fractures 50 and production fractures 60 may alternate along a length of wellbore(s) 30 (though this alternation is not required).

Each injection fracture may be configured to receive pressurizing fluid 82 from pressurizing fluid supply system 80 to provide a driving force for flow of reservoir fluid 22 to one or more associated production fracture(s) 60. Similarly, foaming agent supply system 90 may be configured to selectively inject foaming agent 92 into each production fracture 60, such as to decrease production of pressurizing fluid 82 therefrom and/or to increase production of reservoir fluid 22 from the subterranean formation.

It is within the scope of the present disclosure that hydrocarbon production system 10 may define any suitable distance between injection fractures 50 and associated production fractures 60. As illustrative, non-exclusive examples, the distance may be at least 10 meters (m), at least 20 m, at least 30 m, at least 40 m, at least 50 m, at least 60 m, at least 70 m, at least 80 m, at least 90 m, or at least 100 m. Additionally or alternatively, the distance also may be less than 400 m, less than 375 m, less than 350 m, less than 325 m, less than 300 m, less than 275 m, less than 250 m, less than 225 m, less than 200 m, less than 175 m, less than 150 m, or less than 125 m. This distance may be selected based upon any suitable criteria, illustrative, non-exclusive examples of which include a fluid permeability of subterranean formation 20, a level of heterogeneity of subterranean formation 20, completion costs, and/or risk of intersection between injection fractures 50 and production fractures 60 during formation thereof.

Similarly, it is also within the scope of the present disclosure that injection fractures 50 and/or production fractures 60, which may collectively be referred to herein as fractures 50/60, may extend from respective wellbore(s) 30 any suitable distance. As illustrative, non-exclusive examples, fractures 50/60 may extend at least 10 m, at least 20 m, at least 30 m, at least 40 m, at least 50 m, at least 75 m, at least 100 m, at least 125 m, at least 150 m, at least 175 m, at least 200 m, at least 225 m, at least 250 m, at least 300 m, at least 350 m, or at least 400 m from wellbore(s) 30. Additionally or alternatively, fractures 50/60 also may extend less than 600 m, less than 550 m, less than 500 m, less than 450 m, less than 400 m, less than 350 m, less than 300 m, less than 250 m, less than 200 m, less than 150 m, or less than 100 m from wellbore(s) 30.

As illustrated in dashed lines in FIGS. 1-5, fractures 50/60 may include a proppant 70 and also may be referred to herein as propped fractures 50/60. Additionally or alternatively, fractures 50/60 may not include proppant 70 and/or may be referred to herein as unpropped fractures 50/60.

Fractures 50/60 may define any suitable orientation, or relative orientation, with respect to one another and/or with respect to wellbore(s) 30 and may be formed along any suitable portion of a length of wellbore(s) 30. As an illustrative, non-exclusive example, injection fracture 50 may be (at least substantially) parallel to production fracture 60. As another illustrative, non-exclusive example, fractures 50/60 may be (at least substantially) planar fractures 50/60. As yet another illustrative, non-exclusive example, fractures 50/60 may be oriented in (an at least substantially) vertical orientation within subterranean formation 20 (i.e., a major axis of fractures 50/60 may be aligned at least substantially along a vertical direction).

As another illustrative, non-exclusive example, and as illustrated in FIG. 1, wellbore(s) 30 may include and/or define (an at least substantially) horizontal portion 36, and fractures 50/60 may emanate from the horizontal portion of the wellbore. As yet another illustrative, non-exclusive example, wellbores 50/60 may extend (at least substantially) transverse to wellbore(s) 30 (or to a longitudinal axis thereof).

As discussed, injection fractures 50 are not in direct fluid communication with production fractures 60. Additionally or alternatively, and when a given injection fracture 50 is in direct fluid communication with a given production fracture 60, a portion of the given injection fracture and/or a portion of the given production fracture may be plugged, blocked, and/or occluded to prevent direct fluid communication therebetween.

Foaming agent supply system 90 may include any suitable structure that may be designed, constructed, adapted, and/or configured to provide foaming agent 92 to production fracture 60. As illustrative, non-exclusive examples, foaming agent supply system 90 may include any suitable tank, pump, compressor, valve, pipe, and/or fluid conduit that may be utilized to store the foaming agent, pressurize the foaming agent, regulate a flow rate of the foaming agent, and/or convey the foaming agent.

Foaming agent 92 may be injected into production fracture 60 at a foaming agent pressure that is sufficient to provide a driving force for flow of the foaming agent into the production fracture and/or into a portion of subterranean formation 20 that is proximal thereto (such as into produced regions 72 of FIGS. 3-5). As such, foaming agent supply system 90 may be configured to provide foaming agent 92 at the foaming agent pressure. This may include foaming agent pressures that are greater than a hydrostatic pressure within production fracture 60, foaming agent pressures that are greater than a pressure of pressurizing fluid 82 that is provided to injection fracture 50, foaming agent pressures that are greater than a fracture pressure of the subterranean formation, foaming agent pressures that are (at least substantially) equal to the fracture pressure of the subterranean formation, and/or foaming agent pressures that are less than the fracture pressure of the subterranean formation. As illustrative, non-exclusive examples, the foaming agent pressure may be within a threshold pressure difference of the fracture pressure, such as within 25%, within 20%, within 15%, within 10%, or within 5% of the fracture pressure.

Foaming agent supply system 90 may provide the foaming agent to production fracture 60 in any suitable manner. As an illustrative, non-exclusive example, the foaming agent supply system may (at least substantially) continuously provide the foaming agent to the production fracture during a foaming agent injection period. As another illustrative, non-exclusive example, the foaming agent supply system may periodically and/or intermittently provide the foaming agent to the production fracture during the foaming agent injection period. This may include sequentially providing a volume of the foaming agent and a volume of gas to the production fracture.

Foaming agent 92 may be provided to the subterranean formation (and/or foaming agent supply system 90 may be configured to generate the foaming agent) at any suitable temperature. As illustrative, non-exclusive examples, the foaming agent temperature may be less than a subterranean formation temperature. As more specific but still illustrative, non-exclusive examples, the foaming agent temperature may be at least 5° C., at least 10° C., at least 15° C., at least 20° C., at least 25° C., at least 30° C., at least 35° C., at least 40° C., at least 45° C., or at least 50° C. less than the subterranean formation temperature.

Foaming agent 92 may be provided to the subterranean formation (and/or foaming agent supply system 90 may be configured to generate the foaming agent) at any suitable rate, or flow rate. As illustrative, non-exclusive examples, production fracture 60 may define a peak production rate when producing produced fluid 62 from subterranean formation 20, and foaming agent 92 may be provided to the production fracture at a foaming agent injection rate that is less than the peak production rate, (at least substantially) equal to the peak production rate, or greater than the peak production rate. As more specific but still illustrative, non-exclusive examples, the foaming agent injection rate may be within 50%, within 40%, within 30%, within 20%, within 10%, or within 5% of the peak production rate.

Any suitable foaming agent volume of foaming agent 92 may be provided to production fracture 60 (and/or foaming agent supply system 90 may be configured to provide any suitable volume of the foaming agent to the production fracture). As an illustrative, non-exclusive example, portion 24 of subterranean formation 20 may define a pore volume, and the foaming agent volume may be less than the pore volume. As more specific but still illustrative, non-exclusive examples, the foaming agent volume may be less than 99%, less than 95%, less than 90%, less than 80%, less than 70%, less than 60%, less than 50%, less than 40%, less than 30%, less than 20%, or less than 10% of the pore volume.

Additionally or alternatively, the foaming agent volume also may be at least a threshold foaming agent volume. As illustrative, non-exclusive examples, the foaming agent volume may be at least 0.025 cubic meters, at least 0.05 cubic meters, at least 0.075 cubic meters, at least 0.1 cubic meters, at least 0.125 cubic meters, at least 0.15 cubic meters, at least 0.16 cubic meters, at least 0.175 cubic meters, at least 0.2 cubic meters, at least 0.25 cubic meters, or at least 0.3 cubic meters.

Foaming agent 92 may include any suitable structure, composition, and/or chemical composition that may permit supply of the foaming agent to production fracture 60 and/or that may generate fluid flow restriction 96 (as illustrated in FIGS. 4-5) within subterranean formation 20. As illustrative, non-exclusive examples, foaming agent 92 may include and/or be a pre-mixed foam, an aqueous solution that includes a surfactant, and/or a water-laden surfactant. Illustrative, non-exclusive examples of surfactants that may be utilized with and/or included in the systems and methods according to the present disclosure include a cationic surfactant, an anionic surfactant, a nonionic surfactant, an amphoteric surfactant, an alpha-olefin sulfonated surfactant, a betaine surfactant, a fluorinated surfactant, and a sulfonated ethoxylated alcohol.

When foaming agent 92 includes the surfactant, it is within the scope of the present disclosure that the surfactant may comprise any suitable fraction, or portion, of the foaming agent. As illustrative, non-exclusive examples, the surfactant may comprise at least 0.005 weight percent (wt %), at least 0.0075 wt %, at least 0.01 wt %, at least 0.025 wt %, at least 0.05 wt %, at least 0.075 wt %, at least 0.1 wt %, at least 0.2 wt %, or at least 0.3 wt %, at least 0.5 wt %, at least 0.75 wt %, at least 1 wt %, at least 2 wt %, or at least 3 wt % of the foaming agent. Additionally or alternatively, the surfactant also may comprise less than 10 wt %, less than 9 wt %, less than 8 wt %, less than 7 wt %, less than 6 wt %, less than 5 wt %, less than 4 wt %, less than 3 wt %, less than 2 wt %, or less than 1 wt % of the foaming agent.

Pressurizing fluid supply system 80 may include any suitable structure that may be adapted, configured, designed, and/or constructed to provide pressurizing fluid 82 to injection fracture 50. As an illustrative, non-exclusive example, pressurizing fluid supply system 80 may be (at least substantially) similar to foaming agent supply system 90.

Similar to foaming agent supply system 90, pressurizing fluid supply system 80 may be configured to provide pressurizing fluid 82 at a pressurizing fluid pressure. The pressurizing fluid pressure may be (at least substantially) similar to the foaming agent pressure. However, the pressurizing fluid pressure may be less than the foaming agent pressure. As illustrative, non-exclusive examples, the pressurizing fluid pressure may be less than 95%, less than 90%, less than 85%, less than 80%, less than 75%, less than 70%, less than 65%, less than 60%, less than 55%, or less than 50% of the foaming agent pressure.

Pressurizing fluid 82 may include any suitable composition, or chemical composition, that may be utilized with and/or included in the systems and methods according to the present disclosure. As an illustrative, non-exclusive example, the pressurizing fluid may include and/or be a low density pressurizing fluid. Illustrative, non-exclusive examples of low density pressurizing fluids include pressurizing fluids with a density of less than 70%, less than 60%, less than 50%, less than 40%, less than 30%, less than 20%, or less than 10% of a density of water at the temperature and the pressure that are present within the injection fracture.

As another illustrative, non-exclusive example, pressurizing fluid 82 may include and/or be a low viscosity pressurizing fluid. Illustrative, non-exclusive examples of low viscosity pressurizing fluids include pressurizing fluids with a viscosity that is less than 70%, less than 60%, less than 50%, less than 40%, less than 30%, less than 20%, or less than 10% of a viscosity of water at the temperature and the pressure that are present within the injection fracture.

As more specific but still illustrative, non-exclusive examples, the pressurizing fluid may include and/or be a gas and/or a supercritical fluid. Additional illustrative, non-exclusive examples of pressurizing fluids 82 include carbon dioxide, a light alkane hydrocarbon, methane, sulfur dioxide, nitrogen, water, steam, water vapor, and/or hydrogen sulfide.

Pressurizing fluid 82 may define any suitable solubility with, in, or within, reservoir fluid 22. As illustrative, non-exclusive examples, the pressurizing fluid may define a finite solubility in the reservoir fluid, may be miscible with the reservoir fluid, and/or may be immiscible with the reservoir fluid.

Subterranean formation 20 may include any suitable structure that includes reservoir fluid 22 and/or that may have fractures 50/60 formed therein. As an illustrative, non-exclusive example, subterranean formation 20 may include and/or be a homogeneous, or at least substantially homogeneous, subterranean formation 20 that defines (an at least substantially) constant fluid permeability throughout a volume thereof. As another illustrative, non-exclusive example, subterranean formation 20 may include and/or be a heterogeneous, or at least substantially heterogeneous, subterranean formation 20 that defines a plurality of different fluid permeabilities in different regions thereof. As yet another illustrative, non-exclusive example, subterranean formation 20 may include and/or be a hydrocarbon-containing formation and/or an oil shale formation. Similarly, reservoir fluid 22 may include and/or be a hydrocarbon, oil, and/or shale oil.

Subterranean formation 20 may define any suitable fluid permeability, or average fluid permeability, prior to formation of fractures 50/60 therein. As an illustrative, non-exclusive example, subterranean formation 20 may be a low permeability subterranean formation wherein at least a threshold fraction of the volume of the subterranean formation defines less than a threshold fluid permeability. Illustrative, non-exclusive examples of the threshold fraction of the subterranean formation include threshold fractions of at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, at least 80%, or at least 90% of the volume of the subterranean formation. Illustrative, non-exclusive examples of the threshold fluid permeability include threshold fluid permeabilities of less than 100 millidarcy (md), less than 75 md, less than 50 md, less than 40 md, less than 30 md, less than 20 md, less than 10 md, less than 8 md, less than 6 md, less than 4 md, less than 2 md, less than 1 md, less than 0.5 md, less than 0.1 md, greater than 0.01 md and less than 10 md, or greater than 0.1 md and less than 10 md.

Illustrative, non-exclusive examples of low permeability formations include sandstone, carbonate, or/or shale formations. The permeability of a formation may be measured by any suitable method. For example, the permeability may be measured or determined from core tests or well tests. The average permeability of a formation may be based on a thickness-weighted arithmetic average of measured or estimated permeabilities within the formation, or it may be based on well test measurements. Furthermore, the permeability may vary greatly from region to region within a given subterranean formation (such as when the subterranean formation is a heterogeneous subterranean formation), and there may not be consistency between different measures of permeability.

FIG. 6 is a flowchart depicting methods 100 according to the present disclosure. Methods 100 may include forming one or more fractures within a subterranean formation at 110, injecting a pressurizing fluid into an injection fracture that extends within the subterranean formation at 120, and/or producing a produced fluid from a production fracture that extends within the subterranean formation at 130. Methods 100 further may include detecting a variable associated with production of the pressurizing fluid from the production fracture at 140 and/or determining that the pressurizing fluid is being produced from the production fracture at 150. Methods 100 include injecting a foaming agent into the production fracture at 160, and methods 100 further may include repeating at least a portion of the methods at 170.

Forming one or more fractures within the subterranean formation at 110 may include forming the injection fracture and/or the production fracture in any suitable manner. As illustrative, non-exclusive examples, the forming at 110 may include hydraulically, thermally, chemically, and/or mechanically fracturing the subterranean formation to generate the injection fracture and/or the production fracture.

The forming at 110 further may include restricting and/or avoiding intersection of the injection fracture and the production fracture. Additionally or alternatively, and should the injection fracture and the production fracture intersect, the forming at 110 also may include occluding a portion of the injection fracture and/or of the production fracture to restrict direct fluid communication therebetween.

Restricting fluid communication between the injection fracture and the production fracture may be accomplished in a variety of manners. As illustrative, non-exclusive examples, careful selection of the field, well orientation, and/or spacing between the fractures may be utilized to restrict and/or prevent the intersection. To help carefully select the field, well orientation, and/or spacing between the fractures, the method may include (a) logging the formation while drilling the wellbore, (b) monitoring and analyzing pressures and/or flow rates, (c) well testing after forming the injection fracture and/or the production fracture, and/or (d) monitoring pressures in adjacent wells.

Logging the formation while drilling the wellbore may include logging to obtain wellbore data and/or analyzing the wellbore data to assist in forming the injection fracture and/or the production fracture. Monitoring and analyzing pressures and/or flow rates may include monitoring and analyzing while forming the injection fracture and/or the production fracture. Well testing after forming the injection fracture and/or the production fracture may include well testing to assess effective fracture lengths. Monitoring pressures in adjacent wells may include monitoring while forming the injection fracture and/or the production fracture.

Log data may be used to design fracture spacing to reduce the risk of fracture intersection while still maintaining good well performance. The planned fracture spacing for the well may be adjusted based on reservoir quality as estimated from porosity and/or resistivity logs. A typical well plan often may have a consistent spacing of fractures along the well, but fracture spacing may be adjusted and/or the planned location of fractures may be changed if the logs show substantial reservoir quality variations along the length of the wellbore.

Analyzing wellbore and monitoring data may include assessing where fractures spread, determining an anisotropy in horizontal stresses in the formation, injection fracture, and/or production fracture, etc. After the wellbore data is analyzed, information such as the stress state, location of the axis of the wellbore and/or the minimum in-situ horizontal stress may be utilized to mitigate the risk of fracture intersection. As an illustrative, non-exclusive example, the stress state could be leveraged and the axis of the wellbore could be aligned with the minimum in-situ horizontal stress to mitigate the risk of fracture intersection since fractures tend to open against a minimum in-situ stress and tend to propagate in a directional fashion in reservoirs with strong anisotropy in the horizontal stresses.

Fractures may tend to propagate preferably more to one side of a well (i.e. North) rather than the other direction (i.e. South), which may need to be accounted for in the design. Increasing fracture spacing may reduce the risk of fracture intersection. The design of fracture spacing may depend on the permeability of the formation, reservoir heterogeneities, completion costs, risk of fracture intersection, and other factors. Identifying whether at least one of the fractures is at least 50 m long (i.e., the end of the fracture that emanates from the wellbore is at least 50 m from the other end of the fracture where the fracture has two ends) also may reduce the risk of fracture intersection. Fracture half length (i.e. the distance from the furthest end of the fracture and the wellbore) also may affect the risk of fracture intersection. Fracture half lengths may range from less than 50 m to more than 200 m. Longer fracture half lengths may increase recovery but also may increase the risk of fracture intersection.

Analyzing the fracture data may include reviewing the data to assess whether the injection and/or production fractures are having communication challenges and/or to identify what zone (i.e., production or injection) the fracture is in. After simultaneous injection and production begin, early production of water can indicate whether fractures are intersecting. Production logging tools that measure pressures, temperatures, flow rates, fluid capacitance, fluid density, water-hydrocarbon fractions and/or fluid properties along the wellbore may be used to identify which production fracture(s) in the wellbore may be communicating with an injection fracture.

Another illustrative, non-exclusive example of a way to identify which production fracture(s) might be in communication with injection fracture(s) is to monitor data from fixed sensors that have been installed as part of the completion, such as a fiber optic cable used as a distributed temperature sensor. Yet another way of identifying which production fracture(s) might be in communication with injection fracture(s) is to include different tracers with proppant for each fracture and analyzing produced fluids for relative tracer concentrations If one or more of the fractures is having communication challenges, workovers may be implemented to plug a problematic injection zone, and/or a flow control device may be used to prevent injection of the fluid into the problematic zone. While some of these ways to identify are discussed as being alternatives to one another, one or more of the ways may be implemented.

Injecting the pressurizing fluid into the injection fracture that extends within the subterranean formation at 120 may include injecting the pressurizing fluid in any suitable manner to provide a driving force for the producing at 130. As an illustrative, non-exclusive example, the injecting at 120 may include injecting with any suitable pressurizing fluid supply system 80. The injecting at 120 may include (at least substantially) continuously injecting the pressurizing fluid during the producing at 130, during the detecting at 140, during the determining at 150, during the injecting at 160, and/or during the repeating at 170. The injecting at 120 and the injecting at 160 optionally may be performed at least partially concurrently. Additionally or alternatively, the injecting at 120 also may include intermittently injecting the pressurizing fluid. As an illustrative, non-exclusive example, methods 100 further may include ceasing the injecting at 120 prior to and/or during at least a portion of the injecting at 160. Under these conditions, methods 100 also may include ceasing the injecting at 160 and resuming the injecting at 120 subsequent to ceasing the injecting at 160. As another illustrative, non-exclusive example, methods 100 further may include sequentially performing the injecting at 120 and the injecting at 160.

The injecting at 120, the producing at 130, and the injecting at 160 optionally all may be performed using a single (or the same) wellbore that extends within the subterranean formation. Under these conditions, and as discussed, both the injection fracture and the production fracture may originate and/or emanate from the single wellbore, and the injecting at 120 may include injecting via an injection conduit that extends within the single wellbore and is in fluid communication with the injection fracture. In addition, the injecting at 160 may include injecting via a production conduit that extends within the single wellbore and is in fluid communication with the production fracture. Additionally or alternatively, the injecting at 120 may be performed via an injection wellbore that extends within the subterranean formation and is in fluid communication with the injection fracture, while the producing at 130 and the injecting at 160 may be performed via a production wellbore that is spaced apart from, separate from, and/or distinct from the injection wellbore, extends within the subterranean formation, and is in fluid communication with the production fracture.

Producing the produced fluid from the production fracture that extends within the subterranean formation at 130 may include producing any suitable produced fluid in any suitable manner. As an illustrative, non-exclusive example, and as discussed, the injecting at 120 may include pressurizing a portion of the subterranean formation to provide a driving, or motive, force for the producing at 130. As another illustrative, non-exclusive example, the producing at 130 may include producing via a production conduit that extends within a single wellbore with an injection conduit that is utilized for the injecting at 120. Additionally or alternatively, the producing at 130 also may include producing via a production well that is spaced apart, distinct, and/or separate from an injection well that is utilized for the injecting at 120. As yet another illustrative, non-exclusive example, the producing at 130 may include producing the reservoir fluid, producing the pressurizing fluid, and/or producing a mixture, or combination, of the reservoir fluid and the pressurizing fluid.

Detecting the variable associated with production of the pressurizing fluid from the production fracture at 140 may include detecting any suitable variable, value, and/or parameter that may be associated with and/or is indicative of the presence of the pressurizing fluid within the production fracture and/or production of the pressurizing fluid from the production fracture. Illustrative, non-exclusive examples of the variable associated with production of the pressurizing fluid include (and/or the detecting at 140 may include detecting) a composition (or chemical composition) of the produced fluid, an oil-to-gas ratio and/or a water-to-oil ratio of the produced fluid, and/or a downhole pressure within the subterranean formation.

Determining that the pressurizing fluid is being produced from the production fracture at 150 may include determining that the pressurizing fluid is being produced in any suitable manner. As an illustrative, non-exclusive example, the determining at 150 may include observing (or visually observing) the produced fluid to determine that the pressurizing fluid is present within the produced fluid. As another illustrative, non-exclusive example, the determining at 150 also may include estimating and/or calculating that the pressurizing fluid is (and/or is likely to be) present within the produced fluid. As yet another illustrative, non-exclusive example, the determining at 150 may be at least substantially similar to (and/or may include) the detecting at 140.

Injecting the foaming agent into the production fracture at 160 may include injecting any suitable foaming agent 92 into the production fracture to limit, slow, reduce, retard, and/or mitigate production of the pressurizing fluid 82 from the production fracture. The injecting at 160 may be initiated at any suitable time and/or based upon any suitable criteria. As illustrative, non-exclusive examples, the injecting at 160 may be responsive to and/or based, at least in part, on the detecting at 140 and/or the determining at 150. As another illustrative, non-exclusive example, the injecting at 160 may include injecting based, at least in part, on a value of the variable associated with production of the pressurizing fluid from the production fracture.

Methods 100 optionally may include limiting and/or ceasing the producing at 130 during the injecting at 160, such as to permit injection of the foaming agent into the production fracture. When methods 100 include ceasing the producing at 130 during the injecting at 160, methods 100 further may include resuming the producing at 130 subsequent to (or subsequent to completion of) the injecting at 160. Additionally or alternatively, the producing at 130 may be performed at least partially concurrently with the injecting at 160.

The injecting at 160 may be accomplished in any suitable manner. As an illustrative, non-exclusive example, the injecting at 160 may include injecting via the production conduit that extends within the single wellbore with the injection conduit that is utilized for the injecting at 120. As another illustrative, non-exclusive example, the injecting at 160 also may include injecting via the production well that is spaced apart, distinct, and/or separate from the injection well that is utilized for the injecting at 120.

The injecting at 160 may include injecting a continuous, or at least substantially continuous, foaming agent stream. However, it is also within the scope of the present disclosure that the injecting at 160 may include intermittently injecting the foaming agent. As an illustrative, non-exclusive example, the foaming agent may include and/or be a liquid foaming agent, and the injecting at 160 may include injecting alternating volumes of the liquid foaming agent and of a gas.

The injecting at 160 may include injecting to limit production of the pressurizing fluid from the production fracture. As an illustrative, non-exclusive example, a portion of the subterranean formation that is located between the injection fracture and the production fracture may include a produced region and an unproduced region. In the produced region, a substantial portion and/or a majority of the reservoir fluid may have been removed by flowing to the production fracture. In the unproduced region, a substantial portion and/or a majority of the reservoir fluid may not have been removed. Under these conditions, the injecting at 160 may include limiting, blocking, and/or occluding flow of the pressurizing fluid through the produced region and/or preferentially diverting the pressurizing fluid into the unproduced region. This may improve a sweep efficiency of the portion of the subterranean formation that is located between the injection fracture and the production fracture.

As an illustrative, non-exclusive example, the injecting at 160 may include increasing a flow resistance within a pore space that is present, or defined, within the produced region. As another illustrative, non-exclusive example, the injecting at 160 additionally or alternatively may include increasing an effective viscosity of a fluid that is located within the pore space. As discussed herein, the increase in flow resistance and/or the increase in effective viscosity may be accomplished by generating a foam within the produced region with the foaming agent.

Repeating at least a portion of the methods at 170 may include repeating any suitable portion of methods 100 any suitable number of times. As illustrative, non-exclusive examples, the repeating at 170 may include repeating the forming at 110, repeating the injecting at 120, repeating the producing at 130, repeating that detecting at 140, repeating the determining at 150, and/or repeating the injecting at 160. As another illustrative, non-exclusive example, the repeating at 170 may include repeating a plurality of times. This may include repeating at least 2, at least 4, at least 6, at least 8, at least 10, at least 12, at least 14, at least 16, at least 18, or at least 20 times.

In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently. The blocks, or steps, of the methods optionally may be implemented as logic, which also may be described as implementing the blocks, or steps, as logics. In some applications, the blocks, or steps, may represent expressions and/or actions to be performed by functionally equivalent circuits or other logic devices. The illustrated blocks may, but are not required to, represent executable instructions that cause a computer, processor, and/or other logic device to respond, to perform an action, to change states, to generate an output or display, and/or to make decisions.

As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer to A only (optionally including entities other than B); to B only (optionally including entities other than A); or to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally.

As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

Illustrative, non-exclusive examples of systems and methods according to the present disclosure are presented in the following enumerated paragraphs. It is within the scope of the present disclosure that an individual step of a method recited herein, including in the following enumerated paragraphs, may additionally or alternatively be referred to as a “step for” performing the recited action.

A1. A method of enhancing production of a reservoir fluid from a subterranean formation, the method comprising: injecting a pressurizing fluid into an injection fracture that extends within the subterranean formation; producing a produced fluid from a production fracture that extends within the subterranean formation, wherein the production fracture is spaced apart from the injection fracture and in indirect fluid communication with the injection fracture via a portion of the subterranean formation that extends therebetween, and further wherein the injecting provides a driving force for the producing; and injecting a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture.

A2. The method of paragraph A1, wherein the method further includes detecting a variable associated with production of the pressurizing fluid from the production fracture, and further wherein the injecting is based, at least in part, on the detecting.

A3. The method of any of paragraphs A1-A2, wherein the method further includes determining that the pressurizing fluid is being produced from the production fracture, and further wherein the injecting is based, at least in part, on the determining.

A4. The method of any of paragraphs A1-A3, wherein the injecting the foaming agent includes injecting the foaming agent based, at least in part, on a/the variable associated with production of the pressurizing fluid from the production fracture.

A5. The method of any of paragraphs A1-A4, wherein the injecting the foaming agent includes injecting the foaming agent based, at least in part, on a composition, or a chemical composition, of the produced fluid.

A6. The method of any of paragraphs A1-A5, wherein the injecting the foaming agent includes injecting the foaming agent based, at least in part, on an oil-to-gas ratio and/or a water-to-oil ratio of the produced fluid.

A7. The method of any of paragraphs A1-A6, wherein the injecting the foaming agent includes injecting the foaming agent based, at least in part, on a downhole pressure within the subterranean formation.

B1. A method of limiting production of a pressurizing fluid from a production fracture that extends within a subterranean formation, wherein the pressurizing fluid is injected into an injection fracture that is spaced apart from the production fracture, extends within the subterranean formation, and is in indirect fluid communication with the production fracture via a portion of the subterranean formation that extends therebetween, and further wherein the pressurizing fluid is injected to provide a driving force for production of a produced fluid from the production fracture, the method comprising: detecting a variable associated with production of the pressurizing fluid from the production fracture; and injecting a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture, wherein the injecting is based, at least in part, on the detecting.

B2. The method of paragraph B1, wherein the method further includes injecting the pressurizing fluid into the injection fracture.

B3. The method of any of paragraphs B1-B2, wherein the method further includes producing the produced fluid from the production fracture.

C1. The method of any of paragraphs A6-B3, wherein the variable associated with production of the pressurizing fluid includes a/the composition, or a/the chemical composition, of the produced fluid, and optionally wherein the detecting includes detecting the composition, or the chemical composition, of the produced fluid.

C2. The method of any of paragraphs A6-C1, wherein the variable associated with production of the pressurizing fluid includes an/the oil-to-gas ratio of the produced fluid, and optionally wherein the detecting includes detecting the oil-to-gas ratio of the produced fluid.

C3. The method of any of paragraphs A6-C1, wherein the variable associated with production of the pressurizing fluid includes a/the water-to-oil ratio of the produced fluid, and optionally wherein the detecting includes detecting the water-to-oil ratio of the produced fluid.

C4. The method of any of paragraphs A6-C3, wherein the variable associated with the production of the pressurizing fluid includes a/the downhole pressure within the subterranean formation, and optionally wherein the detecting includes detecting the downhole pressure.

C5. The method of any of paragraphs A1-C4, wherein the method further includes ceasing the producing the produced fluid during the injecting the foaming agent.

C6 The method of paragraph C5, wherein the method includes resuming the producing the produced fluid subsequent to the injecting the foaming agent.

C7 The method of any of paragraphs A1-C6, wherein the method includes producing the produced fluid at least partially concurrently with injecting the pressurizing fluid.

C8. The method of any of paragraphs A1-C7, wherein the injecting the pressurizing fluid includes (at least substantially) continuously injecting the pressurizing fluid during the producing.

C9. The method of any of paragraphs A1-C8, wherein the method further includes continuing the injecting the pressurizing fluid during the injecting the foaming agent.

C10. The method of any of paragraphs A1-C9, wherein the injecting the pressurizing fluid and the injecting the foaming agent are at least partially concurrent.

C11. The method of any of paragraphs A1-C10, wherein the injecting the pressurizing fluid includes intermittently injecting the pressurizing fluid.

C12. The method of any of paragraphs A1-C11, wherein the method further includes ceasing the injecting the pressurizing fluid during the injecting the foaming agent.

C13. The method of paragraph C12, wherein the method further includes ceasing the injecting the foaming agent, and further wherein the method includes resuming the injecting the pressurizing fluid subsequent to ceasing the injecting the foaming agent.

C14. The method of any of paragraphs A1-C13, wherein the method includes sequentially injecting the pressurizing fluid and injecting the foaming agent.

C15. The method of any of paragraphs A1-C14, wherein the method includes injecting the foaming agent prior to injecting the pressurizing fluid.

C16. The method of any of paragraphs A1-C14, wherein the method includes injecting the foaming agent after injecting the pressurizing fluid.

C17. The method of any of paragraphs A1-C16, wherein a wellbore extends within the subterranean formation, wherein the injection fracture emanates from the wellbore, wherein the production fracture emanates from the wellbore, wherein the injecting the pressurizing fluid includes injecting the pressurizing fluid via an injection conduit that extends within the wellbore and is in fluid communication with the injection fracture, and further wherein the injecting the foaming agent includes injecting the foaming agent via a production conduit that extends within the wellbore and is in fluid communication with the production fracture.

C18. The method of paragraph C17, wherein the injection conduit is at least one of spaced apart from the production conduit, discrete from the production conduit, fluidly isolated from the production conduit, and radially spaced apart from the production conduit, optionally within the wellbore.

C19. The method of any of paragraphs A1-C16, wherein a production wellbore extends within the subterranean formation and is in fluid communication with the production fracture, wherein an injection wellbore extends within the subterranean formation and is in fluid communication with the injection fracture, wherein the production wellbore is spaced apart from the injection wellbore, wherein the injecting the pressurizing fluid includes injecting the pressurizing fluid via the injection wellbore, and further wherein the injecting the foaming agent includes injecting the foaming agent via the production wellbore.

C20. The method of any of paragraphs A1-C19, wherein the injecting the foaming agent includes injecting a continuous, or at least substantially continuous, foaming agent stream.

C21. The method of any of paragraphs A1-C20, wherein the injecting the foaming agent includes injecting a liquid foaming agent stream.

C22. The method of any of paragraphs A1-C21, wherein the injecting the foaming agent includes injecting alternating volumes of a/the liquid foaming agent and a gas.

C23. The method of any of paragraphs A1-C22, wherein the subterranean formation has a subterranean formation temperature, and further wherein the injecting the foaming agent includes injecting the foaming agent at a foaming agent temperature that is less than the subterranean formation temperature, optionally wherein the foaming agent temperature is at least 5° C., at least 10° C., at least 15° C., at least 20° C., at least 25° C., at least 30° C., at least 35° C., at least 40° C., at least 45° C., or at least 50° C. less than the subterranean formation temperature.

C24. The method of any of paragraphs A1-C23, wherein the subterranean formation defines a fracture pressure, and further wherein the injecting the foaming agent includes injecting the foaming agent at a foaming agent pressure that is at least one of less than the fracture pressure, (substantially) equal to the fracture pressure, and greater than the fracture pressure, optionally wherein the foaming agent pressure is within a threshold pressure difference of the fracture pressure, and further optionally wherein the threshold pressure difference is less than 25%, less than 20%, less than 15%, less than 10%, or less than 5% of the fracture pressure.

C25. The method of any of paragraphs A1-C24, wherein the production fracture defines a peak production rate, and further wherein the injecting the foaming agent includes injecting the foaming agent at a foaming agent injection rate that is at least one of less than the peak production rate, (substantially) equal to the peak production rate, and greater than the peak production rate, optionally wherein the foaming agent injection rate is within a threshold injection rate difference of the peak production rate, and further optionally wherein the threshold injection rate difference is less than 50%, less than 40%, less than 30%, less than 20%, less than 10%, or less than 5% of the peak production rate.

C26. The method of any of paragraphs A1-C25, wherein the subterranean formation defines a pore volume within a portion of the subterranean formation that is located between the injection fracture and the production fracture, and further wherein the injecting the foaming agent includes injecting a foaming agent volume that is less than the pore volume, optionally wherein the foaming agent volume is less than 99%, less than 95%, less than 90%, less than 80%, less than 70%, less than 60%, less than 50%, less than 40%, less than 30%, less than 20%, or less than 10% of the pore volume, and further optionally wherein the foaming agent volume is at least 0.025 cubic meters, at least 0.05 cubic meters, at least 0.075 cubic meters, at least 0.1 cubic meters, at least 0.125 cubic meters, at least 0.15 cubic meters, at least 0.16 cubic meters, at least 0.175 cubic meters, at least 0.2 cubic meters, at least 0.25 cubic meters, or at least 0.3 cubic meters.

C27. The method of any of paragraphs A1-C26, wherein a/the portion of the subterranean formation that is located between the injection fracture and the production fracture includes a produced region, in which a majority of the reservoir fluid has been removed by flowing to the production fracture, and an unproduced region, in which a majority of the reservoir fluid has not been removed, and further wherein the injecting the foaming agent includes preferentially diverting the pressurizing fluid into the unproduced region.

C28. The method of paragraph C27, wherein the preferentially diverting includes increasing a flow resistance within a pore space that is present within the produced region.

C29. The method of any of paragraphs C27-C28, wherein the preferentially diverting includes increasing an effective viscosity of a fluid that is located within a/the pore space that is present within the produced region.

C30. The method of any of paragraphs C27-C29, wherein the preferentially diverting includes generating a foam within the produced region with the foaming agent.

C31. The method of any of paragraphs C27-C30, wherein the preferentially diverting includes improving a sweep efficiency of the portion of the subterranean formation that is located between the injection fracture and the production fracture via the preferentially diverting.

C32. The method of any of paragraphs A1-C31, wherein the method further includes forming at least one, and optionally both, of the injection fracture and the production fracture.

C33. The method of paragraph C32, wherein the forming includes at least one of hydraulically, thermally, chemically, and mechanically fracturing the subterranean formation to generate at least one, and optionally both, of the injection fracture and the production fracture.

C34. The method of any of paragraphs C32-C33, wherein the forming includes restricting intersection of the injection fracture and the production fracture.

C35. The method of any of paragraphs C32-C34, wherein the forming includes selectively occluding a portion of at least one of the injection fracture and the production fracture to restrict direct fluid communication between the injection fracture and the production fracture.

C36. The method of any of paragraphs C32-C35, wherein the method includes forming the production fracture, and further wherein the method includes injecting the foaming agent subsequent to forming the producing fracture and prior to injecting the pressurizing fluid.

C37. The method of any of paragraphs A1-C36, wherein the method further includes repeating the method.

C38. The method of paragraph C37, wherein the repeating includes ceasing the injecting the foaming agent and subsequently initiating the injecting the foaming agent a plurality of times, optionally wherein the plurality of times includes at least 2, at least 4, at least 6, at least 8, at least 10, at least 12, at least 14, at least 16, at least 18, or at least 20 times.

C39. The method of any of paragraphs A1-C38 performed using the hydrocarbon production system of any of paragraphs D1-D21.

D1. A hydrocarbon production system for producing a reservoir fluid from a subterranean formation, the hydrocarbon production system comprising: an injection fracture that extends within the subterranean formation; a production fracture that is spaced apart from the injection fracture and extends within the subterranean formation, wherein the production fracture is in indirect fluid communication with the injection fracture via a portion of the subterranean formation that extends therebetween; a pressurizing fluid supply system that is configured to inject a pressurizing fluid into the injection fracture to provide a driving force for flow of the reservoir fluid to the production fracture; and a foaming agent supply system that is configured to selectively inject a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture.

D2. The hydrocarbon production system of paragraph D1, wherein the hydrocarbon production system includes a wellbore that extends within the subterranean formation, wherein the production fracture emanates from the wellbore, and further wherein the injection fracture emanates from the wellbore.

D3 The hydrocarbon production system of paragraph D2, wherein the hydrocarbon production system includes an injection conduit that extends within the wellbore between the pressurizing fluid supply system and the injection fracture, and wherein the hydrocarbon production system further includes a production conduit that extends within the wellbore between the foaming agent supply system and the production fracture.

D4. The hydrocarbon production system of paragraph D3, wherein a portion of the injection conduit that extends within the wellbore is fluidly isolated from a portion of the production conduit that extends within the wellbore.

D5. The hydrocarbon production system of any of paragraphs D3-D4, wherein the subterranean formation provides fluid communication between the injection conduit and the production conduit via the injection fracture and the production fracture.

D6. The hydrocarbon production system of any of paragraphs D2-D5, wherein the wellbore includes a horizontal, or at least substantially horizontal, portion, and further wherein the production fracture and the injection fracture emanate from the horizontal, or at least substantially horizontal, portion.

D7. The hydrocarbon production system of any of paragraphs D2-D6, wherein at least one, and optionally both, of the production fracture and the injection fracture extend (at least substantially) transverse to the wellbore.

D8 The hydrocarbon production system of paragraph D1, wherein the hydrocarbon production system inludes a production wellbore that extends within the subterranean formation and an injection wellbore that extends within the subterranean formation and is spaced apart from the production wellbore, wherein the production fracture emanates from the production wellbore, and further wherein the injection fracture emanates from the injection wellbore.

D9. The hydrocarbon production system of paragraph D8, wherein the pressurizing fluid supply system is configured to provide the pressurizing fluid to the injection fracture via the injection wellbore.

D10. The hydrocarbon production system of any of paragraphs D8-D9, wherein the foaming agent supply system is configured to provide the foaming agent to the production fracture via the production wellbore.

D11. The hydrocarbon production system of any of paragraphs D8-D10, wherein the subterranean formation provides fluid communication between the injection wellbore and the production wellbore via the injection fracture and the production fracture.

D12. The hydrocarbon production system of any of paragraphs D8-D11, wherein the injection wellbore includes a horizontal, or at least substantially horizontal, portion, and further wherein the injection fracture emanates from the horizontal, or at least substantially horizontal, portion of the injection wellbore.

D13. The hydrocarbon production system of any of paragraphs D8-D12, wherein the production wellbore includes a horizontal, or at least substantially horizontal, portion, and further wherein the production fracture emanates from the horizontal, or at least substantially horizontal, portion of the production wellbore.

D14. The hydrocarbon production system of any of paragraphs D8-D13, wherein the injection fracture extends (at least substantially) transverse to the injection wellbore.

D15. The hydrocarbon production system of any of paragraphs D8-D14, wherein the production fracture extends (at least substantially) transverse to the production wellbore.

D16. The hydrocarbon production system of any of paragraphs D1-D15, wherein the hydrocarbon production system includes a plurality of production fractures and a plurality of injection fractures that are associated therewith.

D17. The hydrocarbon production system of paragraph D16, wherein each of the plurality of injection fractures is configured to receive the pressurizing fluid from the pressurizing fluid supply system to provide a driving force for flow of the reservoir fluid to at least one of the plurality of production fractures.

D18. The hydrocarbon production system of any of paragraphs D16-D17, wherein the foaming agent supply system is configured to selectively inject the foaming agent into each of the plurality of production fractures.

D19. The hydrocarbon production system of any of paragraphs D1-D18, wherein the hydrocarbon production system further includes the pressurizing fluid.

D20. The hydrocarbon production system of any of paragraphs D1-D19, wherein the hydrocarbon production system further includes the foaming agent.

D21. The hydrocarbon production system of any of paragraphs D1-D20, wherein the foaming agent supply system is configured to sequentially supply a volume of the foaming agent and a volume of gas to the production fracture.

E1. The method of any of paragraphs A1-C39 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the production fracture is (at least substantially) parallel to the injection fracture.

E2. The method of any of paragraphs A1-C39 or E1 or the hydrocarbon production system of any of paragraphs D1-D21, wherein at least one, and optionally both, of the production fracture and the injection fracture includes a proppant.

E3. The method of any of paragraphs A1-C39 or E1-E2 or the hydrocarbon production system of any of paragraphs D1-D21, wherein at least one, and optionally both, of the production fracture and the injection fracture does not include a proppant.

E4. The method of any of paragraphs A1-C39 or E1-E3 or the hydrocarbon production system of any of paragraphs D1-D21, wherein at least one, and optionally both, of the production fracture and the injection fracture is a planar, or at least substantially planar, fracture.

E5. The method of any of paragraphs A1-C39 or E1-E4 or the hydrocarbon production system of any of paragraphs D1-D21, wherein at least one, and optionally both, of the production fracture and the injection fracture is a vertically oriented, or at least substantially vertically oriented, fracture.

E6. The method of any of paragraphs A1-C39 or E1-E5 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the pressurizing fluid is a low density pressurizing fluid, optionally wherein the pressurizing fluid defines a density of less than 70%, less than 60%, less than 50%, less than 40%, less than 30%, less than 20%, or less than 10% of a density of water at the temperature and the pressure that are defined within the injection fracture.

E7. The method of any of paragraphs A1-C39 or E1-E6 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the pressurizing fluid is a low viscosity pressurizing fluid, optionally wherein the pressurizing fluid defines a viscosity of less than 70%, less than 60%, less than 50%, less than 40%, less than 30%, less than 20%, or less than 10% of a viscosity of water at the temperature and the pressure that are defined within the injection fracture.

E8. The method of any of paragraphs A1-C39 or E1-E7 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the pressurizing fluid includes, and optionally is, at least one, and optionally both, of a gas and a supercritical fluid.

E9. The method of any of paragraphs A1-C39 or E1-E8 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the pressurizing fluid at least one of defines a finite solubility in the reservoir fluid, is miscible with the reservoir fluid, and is immiscible with the reservoir fluid.

E10. The method of any of paragraphs A1-C39 or E1-E9 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the pressurizing fluid includes, and optionally is, at least one, optionally at least two, and further optionally at least three, of carbon dioxide, a light alkane hydrocarbon, methane, sulfur dioxide, nitrogen, water, steam, water vapor, and hydrogen sulfide.

E11. The method of any of paragraphs A1-C39 or E1-E9 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the pressurizing fluid includes, wholly or in part, water.

E12. The method of any of paragraphs A1-C39 or E1-E11 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the foaming agent is located within the production fracture.

E13. The method of any of paragraphs A1-C39 or E1-E12 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the foaming agent includes at least one of a pre-mixed foam, an aqueous solution that includes a surfactant, and a water-laden surfactant.

E14. The method of paragraph E13 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the surfactant includes at least one of a cationic surfactant, an anionic surfactant, a nonionic surfactant, an amphoteric surfactant, an alpha-olefin sulfonated surfactant, a betaine surfactant, a fluorinated surfactant, and a sulfonated ethoxylated alcohol.

E15. The method of any of paragraphs E13-E14 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the surfactant defines a concentration within the foaming agent of at least one of: at least 0.005 wt %, at least 0.0075 wt %, at least 0.01 wt %, at least 0.025 wt %, at least 0.05 wt %, at least 0.075 wt %, at least 0.1 wt %, at least 0.2 wt %, at least 0.3 wt %, at least 0.5 wt %, at least 0.75 wt %, at least 1 wt %, at least 2 wt %, or at least 3 wt %; and less than 10 wt %, less than 9 wt %, less than 8 wt %, less than 7 wt %, less than 6 wt %, less than 5 wt %, less than 4 wt %, less than 3 wt %, less than 2 wt %, or less than 1 wt %.

E16. The method of any of paragraphs A1-C39 or E1-E15 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the subterranean formation is a homogeneous, or at least substantially homogeneous, subterranean formation.

E17. The method of any of paragraphs A1-C39 or E1-E15 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the subterranean formation is a heterogeneous, or at least substantially heterogeneous, subterranean formation.

E18. The method of any of paragraphs A1-C39 or E1-E17 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the subterranean formation is a low permeability subterranean formation, optionally wherein at least a threshold fraction of a volume of the subterranean formation defines less than a threshold fluid permeability.

E19. The method of paragraph E18 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the threshold fraction of the subterranean formation is at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, at least 80%, or at least 90% of the volume of the subterranean formation.

E20. The method of any of paragraphs E18-E19 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the threshold fluid permeability is less than 100 millidarcy (md), less than 75 md, less than 50 md, less than 40 md, less than 30 md, less than 20 md, less than 10 md, less than 8 md, less than 6 md, less than 4 md, less than 2 md, less than 1 md, less than 0.5 md, or less than 0.1 md.

E21. The method of any of paragraphs E18-E20 or the hydrocarbon production system of any of paragraphs D1-D21, wherein the threshold fluid permeability is greater than 0.01 millidarcy (md) and less than 10 md, optionally greater than 0.1 md and less than 10 md.

F1. The use of any of the methods of any of paragraphs A1-C39 or E1-E21 with any of the hydrocarbon production systems of any of paragraphs D1-D21.

F2. The use of any of the hydrocarbon production systems of any of paragraphs D1-E20 with any of the methods of any of paragraphs A1-C39 or E1-E21.

F3. The use of any of the methods of any of paragraphs A1-C39 or E1-E21 or any of the hydrocarbon production systems of any of paragraphs D1-D21 to limit production of a pressurizing fluid from a subterranean formation.

F4. The use of any of the methods of any of paragraphs A1-C39 or E1-E21 or any of the hydrocarbon production systems of any of paragraphs D1-D21 to improve sweep of a subterranean formation.

F5. The use of any of the methods of any of paragraphs A1-C39 or E1-E21 or any of the hydrocarbon production systems of any of paragraphs D1-D21 to enhance production of a reservoir fluid from a subterranean formation.

F6. The use of a foaming agent to limit production of a pressurizing fluid from a fractured subterranean formation.

EP1. A method of enhancing production of a reservoir fluid from a subterranean formation, the method comprising: injecting a pressurizing fluid into an injection fracture that extends within the subterranean formation; producing a produced fluid from a production fracture that extends within the subterranean formation, wherein the production fracture is spaced apart from the injection fracture and in indirect fluid communication with the injection fracture via a portion of the subterranean formation that extends therebetween, and further wherein the injecting provides a driving force for the producing; and injecting a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture.

EP2. The method of paragraph EP1, wherein the method further includes ceasing the producing the produced fluid during the injecting the foaming agent, and further wherein the method includes resuming the producing the produced fluid subsequent to the injecting the foaming agent.

EP3. The method of any of paragraphs EP1 or EP2, wherein a wellbore extends within the subterranean formation, wherein the injection fracture emanates from the wellbore, wherein the production fracture emanates from the wellbore, wherein the injecting the pressurizing fluid includes injecting the pressurizing fluid via an injection conduit that extends within the wellbore and is in fluid communication with the injection fracture, and wherein the injecting the foaming agent includes injecting the foaming agent via a production conduit that extends within the wellbore and is in fluid communication with the production fracture, and further wherein the injection conduit is at least one of spaced apart from the production conduit, discrete from the production conduit, fluidly isolated from the production conduit, and radially spaced apart from the production conduit within the wellbore.

EP4. The method of any of paragraphs EP1 or EP2, wherein a production wellbore extends within the subterranean formation and is in fluid communication with the production fracture, wherein an injection wellbore extends within the subterranean formation and is in fluid communication with the injection fracture, wherein the production wellbore is spaced apart from the injection wellbore, wherein the injecting the pressurizing fluid includes injecting the pressurizing fluid via the injection wellbore, and further wherein the injecting the foaming agent includes injecting the foaming agent via the production wellbore.

EP5. The method of any of paragraphs EP1-EP4, wherein a portion of the subterranean formation that is located between the injection fracture and the production fracture includes a produced region, in which a majority of the reservoir fluid has been removed by flowing to the production fracture, and an unproduced region, in which a majority of the reservoir fluid has not been removed, and further wherein the injecting the foaming agent includes preferentially diverting the pressurizing fluid into the unproduced region, and optionally wherein the preferentially diverting includes at least one of increasing a flow resistance within a pore space that is present within the produced region and increasing an effective viscosity of a fluid that is located within the pore space.

EP6. The method of any of paragraphs EP1-EP5, wherein the method further includes forming at least one of the injection fracture and the production fracture, and optionally wherein the forming includes restricting intersection of the injection fracture and the production fracture.

EP7. The method of any of paragraphs EP1-EP6, wherein the method further includes detecting a variable associated with production of the pressurizing fluid from the production fracture, and further wherein the injecting is based, at least in part, on the detecting.

EP8. The method of any of paragraphs EP1-EP7, wherein the method further includes determining that the pressurizing fluid is being produced from the production fracture, and further wherein the injecting is based, at least in part, on the determining.

EP9. The method of any of paragraphs EP1-EP8, wherein the injecting the foaming agent includes injecting the foaming agent based, at least in part, on at least one of a composition of the produced fluid, an oil-to-gas ratio and/or a water-to-oil ratio of the produced fluid, and a downhole pressure within the subterranean formation.

EP10. A method of limiting production of a pressurizing fluid from a production fracture within a subterranean formation, wherein the pressurizing fluid is injected into an injection fracture that is spaced apart from the production fracture, extends within the subterranean formation, and is in indirect fluid communication with the production fracture via a portion of the subterranean formation that extends therebetween, and further wherein the pressurizing fluid is injected to provide a driving force for production of a produced fluid from the production fracture, the method comprising: detecting a variable associated with production of the pressurizing fluid from the production fracture; and injecting a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture, wherein the injecting is based, at least in part, on the detecting.

EP11. A hydrocarbon production system for producing a reservoir fluid from a subterranean formation, the hydrocarbon production system comprising: an injection fracture that extends within the subterranean formation; a production fracture that is spaced apart from the injection fracture and extends within the subterranean formation, wherein the production fracture is in indirect fluid communication with the injection fracture via a portion of the subterranean formation that extends therebetween; a pressurizing fluid supply system that is configured to inject a pressurizing fluid into the injection fracture to provide a driving force for flow of the reservoir fluid to the production fracture; and a foaming agent supply system that is configured to selectively inject a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture.

EP12. The hydrocarbon production system of paragraph EP11, wherein the hydrocarbon production system includes a wellbore that extends within the subterranean formation, wherein the production fracture emanates from the wellbore, and further wherein the injection fracture emanates from the wellbore.

EP13 The hydrocarbon production system of paragraph EP12, wherein the hydrocarbon production system includes an injection conduit that extends within the wellbore between the pressurizing fluid supply system and the injection fracture, and wherein the hydrocarbon production system further includes a production conduit that extends within the wellbore between the foaming agent supply system and the production fracture, and optionally wherein a portion of the injection conduit that extends within the wellbore is fluidly isolated from a portion of the production conduit that extends within the wellbore.

EP14. The hydrocarbon production system of paragraph EP11, wherein the hydrocarbon production system includes a production wellbore that extends within the subterranean formation and an injection wellbore that extends within the subterranean formation and is spaced apart from the production wellbore, wherein the production fracture emanates from the production wellbore, and further wherein the injection fracture emanates from the injection wellbore, and optionally wherein the pressurizing fluid supply system is configured to provide the pressurizing fluid to the injection fracture via the injection wellbore, and further optionally wherein the foaming agent supply system is configured to provide the foaming agent to the production fracture via the production wellbore.

EP15. The hydrocarbon production system of any of paragraphs EP11-EP14, wherein the hydrocarbon production system includes a plurality of production fractures and a plurality of injection fractures that are associated therewith, wherein each of the plurality of injection fractures is configured to receive the pressurizing fluid from the pressurizing fluid supply system to provide a driving force for flow of the reservoir fluid to at least one of the plurality of production fractures, and further wherein the foaming agent supply system is configured to selectively inject the foaming agent into each of the plurality of production fractures.

Claims

1. A method of enhancing production of a reservoir fluid from a subterranean formation, the method comprising:

injecting a pressurizing fluid into an injection fracture that extends within the subterranean formation;

producing a produced fluid from a production fracture that extends within the subterranean formation, wherein the production fracture is spaced apart from the injection fracture and in indirect fluid communication with the injection fracture via a portion of the subterranean formation that extends therebetween, and further wherein the injecting provides a driving force for the producing; and

injecting a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture.

2. The method of claim 1, wherein the method further includes ceasing the producing the produced fluid during the injecting the foaming agent, and further wherein the method includes resuming the producing the produced fluid subsequent to the injecting the foaming agent.

3. The method of claim 1, wherein the injecting the pressurizing fluid and the injecting the foaming agent are at least partially concurrent.

4. The method of claim 1, wherein the method includes sequentially injecting the pressurizing fluid and injecting the foaming agent.

5. The method of claim 1, wherein a wellbore extends within the subterranean formation, wherein the injection fracture emanates from the wellbore, wherein the production fracture emanates from the wellbore, wherein the injecting the pressurizing fluid includes injecting the pressurizing fluid via an injection conduit that extends within the wellbore and is in fluid communication with the injection fracture, and wherein the injecting the foaming agent includes injecting the foaming agent via a production conduit that extends within the wellbore and is in fluid communication with the production fracture, and further wherein the injection conduit is at least one of spaced apart from the production conduit, discrete from the production conduit, fluidly isolated from the production conduit, and radially spaced apart from the production conduit within the wellbore.

6. The method of claim 1, wherein a production wellbore extends within the subterranean formation and is in fluid communication with the production fracture, wherein an injection wellbore extends within the subterranean formation and is in fluid communication with the injection fracture, wherein the production wellbore is spaced apart from the injection wellbore, wherein the injecting the pressurizing fluid includes injecting the pressurizing fluid via the injection wellbore, and further wherein the injecting the foaming agent includes injecting the foaming agent via the production wellbore.

7. The method of claim 1, wherein the injecting the foaming agent includes injecting an at least substantially continuous foaming agent stream.

8. The method of claim 1, wherein the injecting the foaming agent includes injecting alternating volumes of a liquid foaming agent and a gas.

9. The method of claim 1, wherein a portion of the subterranean formation that is located between the injection fracture and the production fracture includes a produced region, in which a majority of the reservoir fluid has been removed by flowing to the production fracture, and an unproduced region, in which a majority of the reservoir fluid has not been removed, and further wherein the injecting the foaming agent includes preferentially diverting the pressurizing fluid into the unproduced region.

10. The method of claim 9, wherein the preferentially diverting includes at least one of increasing a flow resistance within a pore space that is present within the produced region and increasing an effective viscosity of a fluid that is located within the pore space.

11. The method of claim 9, wherein the preferentially diverting includes generating a foam within the produced region with the foaming agent.

12. The method of claim 1, wherein the method further includes forming at least one of the injection fracture and the production fracture.

13. The method of claim 12, wherein the forming includes restricting intersection of the injection fracture and the production fracture.

14. The method of claim 1, wherein the method further includes repeating the method, wherein the repeating includes ceasing the injecting the foaming agent and subsequently initiating the injecting the foaming agent at least six times.

15. The method of claim 1, wherein the method further includes detecting a variable associated with production of the pressurizing fluid from the production fracture, and further wherein the injecting is based, at least in part, on the detecting.

16. The method of claim 1, wherein the method further includes determining that the pressurizing fluid is being produced from the production fracture, and further wherein the injecting is based, at least in part, on the determining.

17. The method of claim 1, wherein the injecting the foaming agent includes injecting the foaming agent based, at least in part, on at least one of a composition of the produced fluid, an oil-to-gas ratio of the produced fluid, and a downhole pressure within the subterranean formation.

18. The method of claim 1, wherein the injecting the foaming agent includes injecting the foaming agent based, at least in part, on at least one of a composition of the produced fluid, a water-to-oil ratio of the produced fluid, and a downhole pressure within the subterranean formation.

19. A method of limiting production of a pressurizing fluid from a production fracture within a subterranean formation, wherein the pressurizing fluid is injected into an injection fracture that is spaced apart from the production fracture, extends within the subterranean formation, and is in indirect fluid communication with the production fracture via a portion of the subterranean formation that extends therebetween, and further wherein the pressurizing fluid is injected to provide a driving force for production of a produced fluid from the production fracture, the method comprising:

detecting a variable associated with production of the pressurizing fluid from the production fracture; and

injecting a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture, wherein the injecting is based, at least in part, on the detecting.

20. A hydrocarbon production system for producing a reservoir fluid from a subterranean formation, the hydrocarbon production system comprising:

an injection fracture that extends within the subterranean formation;

a production fracture that is spaced apart from the injection fracture and extends within the subterranean formation, wherein the production fracture is in indirect fluid communication with the injection fracture via a portion of the subterranean formation that extends therebetween;

a pressurizing fluid supply system that is configured to inject a pressurizing fluid into the injection fracture to provide a driving force for flow of the reservoir fluid to the production fracture; and

a foaming agent supply system that is configured to selectively inject a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture.

21. The hydrocarbon production system of claim 20, wherein the hydrocarbon production system includes a wellbore that extends within the subterranean formation, wherein the production fracture emanates from the wellbore, and further wherein the injection fracture emanates from the wellbore.

22. The hydrocarbon production system of claim 21, wherein the hydrocarbon production system includes an injection conduit that extends within the wellbore between the pressurizing fluid supply system and the injection fracture, and wherein the hydrocarbon production system further includes a production conduit that extends within the wellbore between the foaming agent supply system and the production fracture.

23. The hydrocarbon production system of claim 22, wherein a portion of the injection conduit that extends within the wellbore is fluidly isolated from a portion of the production conduit that extends within the wellbore.

24. The hydrocarbon production system of claim 20, wherein the hydrocarbon production system includes a production wellbore that extends within the subterranean formation and an injection wellbore that extends within the subterranean formation and is spaced apart from the production wellbore, wherein the production fracture emanates from the production wellbore, and further wherein the injection fracture emanates from the injection wellbore.

25. The hydrocarbon production system of claim 24, wherein the pressurizing fluid supply system is configured to provide the pressurizing fluid to the injection fracture via the injection wellbore, and further wherein the foaming agent supply system is configured to provide the foaming agent to the production fracture via the production wellbore.

26. The hydrocarbon production system of claim 20, wherein the hydrocarbon production system includes a plurality of production fractures and a plurality of injection fractures that are associated therewith, wherein each of the plurality of injection fractures is configured to receive the pressurizing fluid from the pressurizing fluid supply system to provide a driving force for flow of the reservoir fluid to at least one of the plurality of production fractures, and further wherein the foaming agent supply system is configured to selectively inject the foaming agent into each of the plurality of production fractures.

27. The hydrocarbon production system of claim 20, wherein the hydrocarbon production system further includes the pressurizing fluid and the foaming agent.

28. The hydrocarbon production system of claim 27, wherein the pressurizing fluid is a low density pressurizing fluid that defines a density of less than 70% of a density of water at the temperature and the pressure that are defined within the injection fracture, and further wherein the pressurizing fluid is a low viscosity pressurizing fluid that defines a viscosity of less than 70% of a viscosity of water at the temperature and the pressure that are defined within the injection fracture.

29. The hydrocarbon production system of claim 27, wherein the pressurizing fluid includes at least one of a gas and a supercritical fluid.

30. The hydrocarbon production system of claim 27, wherein the foaming agent includes at least one of a pre-mixed foam, an aqueous solution that includes a surfactant, and a water-laden surfactant.

31. The hydrocarbon production system of claim 20, wherein the subterranean formation is a low permeability subterranean formation, wherein at least a threshold fraction of a volume of the subterranean formation defines less than a threshold fluid permeability.

32. The hydrocarbon production system of claim 31, wherein the threshold fraction of the subterranean formation is at least 50% of the volume of the subterranean formation, and further wherein the threshold fluid permeability is less than 10 md.