CUSTOMIZABLE DOWNHOLE MIXING OF LEAN GAS STREAMS WITH ENHANCED OIL RECOVERY CHEMICALS

FIELD OF THE INVENTION

The techniques described herein relate generally to the field of hydrocarbon well completions and hydrocarbon production. More specifically, the techniques described herein relate to the mixing of enhanced oil recovery chemicals (EORCs) with lean gas streams to improve the efficiency of enhanced oil recovery (EOR) methods.

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, which may be associated with embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques.

Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

Gas injection is a technique that is used to maximize the value of hydrocarbon resources produced from a reservoir. For example, gas injection may be used in enhanced oil recovery (EOR) operations. Enhanced oil recovery chemicals (EORCs) may be mixed with a lean gas stream and pressurized at the surface, then injected into a reservoir.

According to classical gas injection theory, enriching a gas stream in this manner will promote improved recovery of hydrocarbons. However, operational limits may constrain the production of hydrocarbon resources using injected gas mixed with EORCs at the surface. Examples of these operational limits include the availability of EROCs and liquid drop-out considerations that may damage compressors. These limits may impact the ability to achieve a target enrichment level, and the ability to vary the amount of enrichment in a safe and efficient manner.

SUMMARY OF THE INVENTION

An embodiment provided herein relates to a method for performing an enhanced oil recovery (EOR) operation. The method includes injecting a gas stream into a well via a first channel. The method also includes injecting enhanced oil recovery chemicals (EROCs) into the well via a second channel.

The second channel is different from the first channel. An end of the first channel and an end of the second channel are positioned to facilitate static mixing of the gas stream with the EROCs to form an enriched gas stream in a subsurface region. The enriched gas stream facilitates the EOR operation.

Another embodiment provided herein relates to a well system for performing an enhanced oil recovery (EOR) operation. The well system includes a well that includes a first channel leading to a subsurface region and a second channel leading to the subsurface region. The second channel is different from the first channel. The first channel receives an injected gas stream. The second channel receives enhanced oil recovery chemicals (EORCs). An end of the first channel and an end of the second channel are positioned so that the injected gas stream statically mixes with the EORCs to form an enriched gas stream in the subsurface region.

A still further embodiment provided herein relates to a well system for performing an enhanced oil recovery (EOR) operation. The well system includes a well that has a first channel leading to a subsurface region and a second channel leading to the subsurface region. The second channel is different from the first channel. The first channel receives an injected gas stream and the second channel receives enhanced oil recovery chemicals (EORCs). An end of the first channel and an end of the second channel are positioned so that the injected gas stream statically mixes with the EORCs to form an enriched gas stream in the subsurface region. The well system further includes a computing system that computes an optimized composition of the enriched gas stream for use in the EOR operation. The computing system also controls a flow of the EORCs through the second channel to obtain the optimized composition.

These and other features and attributes of the disclosed embodiments of the present techniques and their advantageous applications and/or uses will be apparent from the detailed description that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

To assist those of ordinary skill in the relevant art in making and using the subject matter described herein, reference is made to the appended drawings, where:

FIG. 1 is a simplified schematic view of a well that may be utilized in an EOR operation in accordance with the present techniques;

FIG. 2 is a schematic view of an exemplary embodiment of the well of FIG. 1 shown in the context of a reservoir;

FIG. 3 is a schematic illustration showing an exemplary embodiment of a well configured to perform an EOR operation according to the present techniques;

FIG. 4 is a schematic illustration showing another exemplary embodiment of a well configured to perform an EOR operation according to the present techniques;

FIG. 5 is a process flow diagram of an exemplary method for performing an EOR operation according to the present techniques;

FIG. 6 is a block diagram of an exemplary cluster computing system that may be utilized to implement at least a portion of the present techniques; and

FIG. 7 is a block diagram of an exemplary non-transitory, computer-readable storage medium that may be used for the storage of data and modules of program instructions for implementing at least a portion of the present techniques.

It should be noted that the figures are merely examples of the present techniques and are not intended to impose limitations on the scope of the present techniques. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the techniques.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In the following detailed description section, the specific examples of the present techniques are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

At the outset, and for case of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition those skilled in the art have given that term as reflected in at least one printed publication or issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.

As used herein, the singular forms “a,” “an,” and “the” mean one or more when applied to any embodiment described herein. The use of “a,” “an,” and/or “the” does not limit the meaning to a single feature unless such a limit is specifically stated.

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 “including,” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, 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 term “any” means one, some, or all of a specified entity or group of entities, indiscriminately of the quantity.

The phrase “at least one,” when used in reference to a list of one or more entities (or elements), should be understood to mean at least one entity selected from any one or more of the entities 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, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, 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.

As used herein, the phrase “based on” does not mean “based only on,” unless expressly specified otherwise. In other words, the phrase “based on” means “based only on,” “based at least on,” and/or “based at least in part on.”

As used herein, the terms “example,” exemplary,” and “embodiment,” when used with reference to one or more components, features, structures, or methods according to the present techniques, are intended to convey that the described component, feature, structure, or method is an illustrative, non-exclusive example of components, features, structures, or methods according to the present techniques. Thus, the described component, feature, structure, or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, structures, or methods, including structurally and/or functionally similar and/or equivalent components, features, structures, or methods, are also within the scope of the present techniques.

As used herein, the term “field” (sometimes referred to as an “oil and gas field” or a “hydrocarbon field”) refers to an area including one or more hydrocarbon wells for which hydrocarbon production operations are to be performed to provide for the extraction of hydrocarbon fluids from a corresponding subterranean formation.

The term “fracture” refers to a crack or surface of breakage induced by an applied pressure or stress within a subterranean formation.

The term “hydraulic fracturing” refers to a process for creating fractures (also referred to as “hydraulic fractures”) that extend from a wellbore into a reservoir, so as to stimulate the flow of hydrocarbon fluids from the reservoir into the wellbore. A fracturing fluid is generally injected into the reservoir with sufficient pressure to create and extend multiple fractures within the reservoir, and a proppant material is used to “prop” or hold open the fractures after the hydraulic pressure used to generate the fractures has been released.

As used herein, the term “surface” refers to the uppermost land surface of a land well, or the mud line of an offshore well, while the term “subsurface” (or “subterranean”) generally refers to a geologic strata occurring below the earth's surface. Moreover, as used herein, “surface” and “subsurface” are relative terms. The fact that a particular piece of equipment is described as being on the surface does not necessarily mean it must be physically above the surface of the earth but, rather, describes only the relative placement of the surface and subsurface pieces of equipment. In that sense, the term “surface” may generally refer to any equipment that is located above the casing strings and other equipment that is located inside the wellbore. Moreover, according to embodiments described herein, the terms “downhole” and “subsurface” are sometimes used interchangeably, although the term “downhole” is generally used to refer specifically to the inside of the wellbore. The term “wellbore” refers to a borehole drilled into a subterranean formation. The borehole may include vertical, deviated, highly deviated, and/or horizontal sections. The term “wellbore” also includes the downhole equipment associated with the borehole, such as the casing strings, production tubing, gas lift valves, and other subsurface equipment. Relatedly, the term “hydrocarbon well” (or simply “well”) includes the wellbore in addition to the wellhead and other associated surface equipment.

In performing EOR operations, it is sometimes desirable to mix a gas stream with enhanced oil recovery chemicals (EORCs). In an exemplary embodiment of the present techniques, the gas stream is a lean gas stream.

Mixing the lean gas stream with EORCs at the surface may be done, resulting in an enriched gas stream. The enriched gas stream must be safely compressed at the surface prior to injection into a well for EOR applications. Compression of the enriched gas stream at the surface may present a safety hazard that may be desirably avoided by the present techniques.

FIGS. 1 and 2 provide examples of wells that may be utilized to perform the techniques described herein. Within such figures, elements that serve a similar (or at least substantially similar) purpose may be labeled with like numbers. Moreover, those skilled in the art will appreciate that the schematic views of FIGS. 1 and 2 are not intended to indicate that the well(s) described herein are to include all of the components shown in the figures in every embodiment, or that the well(s) are limited to only such components. Rather, any number of components may be added to, or omitted from, the well(s) without departing from the scope of the present techniques.

FIG. 1 is a simplified schematic view of a well that may be utilized in an EOR operation in accordance with the present techniques, while FIG. 2 is a schematic view of an exemplary embodiment of the well of FIG. 1 shown in the context of a reservoir. In other words, FIG. 2 is a more detailed illustration of examples of components/structures that may be included in the well shown in FIG. 1.

Turning first to FIG. 1, a well 100 is provided. In various embodiments, the well 100 may be a producer well used to perform an EOR operation as described herein. Moreover, the well 100 may be used to deliver a lean gas stream and EORCs independently from each other through separate channels for mixing in a subsurface region 102. Such delivery may be desirably performed without pressurizing the enriched gas stream at the surface prior to injecting the enriched gas stream into the well 100.

The flow of the lean gas stream into the subsurface region 102 is indicated by arrow 104. The separate flow of EORCs into the subsurface region 102 is indicated by arrow 106. As explained herein, the lean gas stream will be mixed with the EORCs in the subsurface region 102 rather than at the surface prior to pressurization.

Once they arrive at the subsurface, the lean gas stream and the EORCs mix to form an enriched gas stream. The enriched gas stream flows through perforations 106 within a fracturing stage of the well 100, and into one or more hydraulic fractures 110. In an exemplary embodiment, the hydraulic fractures 110 have been previously created by a hydraulic fracturing operation. At least a portion of such hydraulic fractures 110 may provide one or more hydraulic connections between the well 100 and other wells in the reservoir. The enriched gas stream mixes into the hydrocarbons in the subsurface to facilitate improved recovery of the hydrocarbons.

Those skilled in the art will appreciate that the presence of lean gas and EORCs in the subsurface region 102 may be measured by any typical measuring device. The measuring device may be located at or near the surface or wellhead of the well 100. Alternatively, the measuring device may be positioned anywhere within the wellbore itself, including within proximity to the stage of interest. Furthermore, in some embodiments, multiple measuring devices may be used.

By way of example and not of limitation, the measuring device may comprise a fluid influx sensor. Examples of fluid influx sensor(s) may include one or more fiber optic cables that are configured to measure strain data corresponding to the wellbore of the well 100. Fiber optic cables could be configured for DAS/DTS (distributed acoustic sensing/distributed temperature sensing) to infer fluid movement and composition. In addition, multiphase flow meters and production logging test (PLT) devices could be used. Strain data may provide additional diagnostic detail regarding the presence/dynamic response of the fractures 110.

Turning now to FIG. 2, the well 100 defines a corresponding wellbore 200 that extends from a surface 202 into a formation 204 within the subsurface. The formation 204 may include several subsurface intervals, such as a hydrocarbon-bearing interval that is referred to herein as a reservoir 206. In some embodiments, the reservoir 206 is an unconventional, tight reservoir, meaning that it has regions of low permeability. For example, the reservoir 206 may include tight sandstone, tight carbonate, shale gas, coal bed methane, tight oil, and/or tight limestone.

The wellbore 200 is completed by setting a series of tubulars into the formation 204. These tubulars include several strings of casing, such as a surface casing string 208, an intermediate casing string 210, and a production casing string 212, which is sometimes referred to as a “production liner.” In some embodiments, additional intermediate casing strings (not shown) are also included to provide support for the walls of the wellbore 200. According to the embodiment shown in FIG. 2, the surface casing string 208 and the intermediate casing string 210 are hung from the surface 202, while the production casing string 212 is hung from the bottom of the intermediate casing string 210 using a liner hanger 214.

The surface casing string 208 and the intermediate casing string 210 are set in place using cement 216. The cement 216 isolates the intervals of the formation 204 from the wellbore 200 and each other. The production casing string 212 may also be set in place using cement 216, as shown in FIG. 2. Alternatively, the wellbore 200 may be set as an open-hole completion, meaning that the production casing string 212 is not set in place using cement.

The exemplary wellbore 200 shown in FIG. 2 is completed horizontally (or laterally). A lateral section of the wellbore 200 is shown at 218. Each lateral section 218 has a heel 220 and a toc 222 that extends through the reservoir 206 within the formation 204.

In various embodiments, because the reservoir 206 is an unconventional, tight reservoir, a hydraulic fracturing process is performed to allow hydrocarbon fluids to be economically produced from the reservoir 206. As shown in FIG. 2, the hydraulic fracturing process may utilize an extensive amount of equipment at a well site 224 located at the surface 202. The equipment may include fluid storage tanks 226 to hold fracturing fluid, such as slickwater, and blenders 228 to blend the fracturing fluid with other materials, such as proppant 230 and other chemical additives, forming a low-pressure slurry. The low-pressure slurry 232 may be run through a treater manifold 234, which may use pumps 236 to adjust flow rates, pressures, and the like, creating a high-pressure slurry 238.

According to embodiments described herein, the high-pressure slurry 238 may be pumped down the wellbore 200 of the well 100 via a corresponding wellhead 240 and used to fracture the rocks in the reservoir 206. Moreover, a mobile command center 242 may be used to control the hydraulic fracturing process, as well as the inter-well parameter detection techniques described herein.

Each wellhead 240 may include any arrangement of pipes and valves for controlling the well 100. In some embodiments, the wellhead 240 is a so-called “Christmas tree.” A Christmas tree is typically used when the subsurface formation 204 has enough in-situ pressure to drive hydrocarbon fluids from the reservoir 206, up the corresponding wellbore 200, and to the surface 202. The illustrative wellhead 240 includes a top valve 244 and a bottom valve 246. In some contexts, these valves are referred to as “primary valves.” Moreover, in various embodiments, the wellhead 240 also couples the well 100 to other equipment, such as equipment for running a wireline (not shown) into the wellbore 200.

In some embodiments, the equipment for running the wireline into the wellbore 200 includes a lubricator (not shown), which may extend as much as 75 feet above the wellhead 240. In this respect, the lubricator must be of a length greater than the length of a bottomhole assembly (BHA) (not shown) attached to the wireline to ensure that the BHA may be safely deployed into the wellbore 200 and then removed from the wellbore 200 under pressure.

While there are several different methods for hydraulically fracturing the reservoir 206 via the well 100, a hydraulic fracturing process referred to as a “plug-and-perforation process” is described with respect to FIG. 2. During the plug-and-perforation process, a specialized BHA, referred to as a “plug-and-perf assembly,” (not shown) is run into the wellbore 200 of the well 100 via the wireline connected to the corresponding wellhead 240. The wireline provides electrical signals to the surface 202 for depth control. In addition, the wireline provides electrical signals to perforating guns (not shown) included within the plug-and-perf assembly. The electrical signals may allow the operator within the mobile command center 242 to cause the charges within the perforating gun to fire, or detonate, at a desired stage or depth within the wellbore 200.

In operation, the perforating gun is run into the first stage 248 of the well 100, which is located near the toc 222 of the lateral section 218. The perforating gun is then detonated to create a first perforation cluster 250A through the production casing string 212 and the surrounding cement 216.

In operation, the perforating gun typically forms one perforation cluster by shooting 12 to 18 perforations at one time, over a 1- to 3-foot region, with each perforation being approximately 0.3 to 0.5 inches in diameter. The perforating gun is then typically moved uphole 10 to 100 feet, and a second perforating gun is used to form a second perforation cluster 250B. This process of forming perforation clusters is repeated another 1 to 18 times to create multiple perforation clusters within a single stage. Therefore, while only five perforation clusters 250A, 250B, 250C, 250D, and 250E are depicted for the first stage 248 of the well 100, each stage of the well 100 may include a total of around 3 to 20 perforation clusters, with each perforation cluster being spaced around 10 to 100 feet apart, for example.

The perforation clusters 250A-250E may be designed to be offset to a certain extent or to be within a certain amount of distance from each other. However, in other embodiments, the techniques described herein are performed without pre-designing or altering the well 100 to include perforation clusters that align (or approximately align).

In various embodiments, once the perforation clusters 250A, 250B, 250C, 250D, and 250E are formed within the first stage of the well 100, the plug-and-perf assembly is removed from the wellbore 200, and the high-pressure slurry 238 of fracturing fluid is pumped down the wellbore 200, through the perforations within the perforation clusters 250A-E, and into the surrounding reservoir 206, forming corresponding sets of fractures 252A, 252B, 252C, 252D, and 252E within the reservoir 206.

The present technological innovation is based in part on the recognition that the lean gas stream and EORCs may be safely delivered downhole via the well 100 without compression of an enriched gas stream after being mixed at the surface. The lean gas stream and EORCs are delivered separately downhole using a variety of techniques, as set forth herein. For example, EORCs may be pumped into the well via an annulus or secondary string independently from the lean gas stream. Mixing the lean gas stream and EORCs downhole avoids the need to perform compression of the enriched gas stream at the surface.

By mixing the EORCs and lean gas streams downhole, the user can customize the level of enrichment to maximize the technical performance of the EOR project and tailor the injected composition “on-the-fly.” By way of example and not limitation, one example of the present techniques is to inject EORCs down the annulus and lean gas through the tubing using a packer and cross-over/orifice valve. A second example is to pump EORCs downhole via a secondary string placed within the tubing (when using a packer) or placed in the annular space (when there is no packer) and lean gas is injected down the tubing or annulus. Other exemplary embodiments may be implemented using multiple secondary strings for dedicated injection of multiple EORCs and/or mobility control agents.

FIG. 3 is a schematic illustration showing an exemplary embodiment of the well 100 configured to perform an EOR operation according to the present techniques. In the embodiment shown in FIG. 3, the well 100 includes a casing string 302. Production tubing 304 is disposed within the casing string 302. The casing string 302 and the production tubing 304 form an annulus 306 therebetween. Exemplary embodiments of the present techniques may employ a variety of EORCs to mix with a gas stream such as a lean gas stream to produce an enhanced gas stream. As used herein, the term “enriched gas stream” includes a gas stream that is mixed with EORCs, including but not limited to NGLs.

Non-limiting examples of EORCs include condensates, polymers, alkaline chemicals, foamers, diverters and scale inhibitors. Additional examples of EORCs include ethane (C2H6), propane (C3H8), and their mixtures. Further examples of EORCs include alcohols such as McOH and EtOH. Still further examples of EORCs include carbon dioxide (CO2), ammonia (NH3), hydrogen sulfide (H2S), and gas phase surfactants. Additional examples of EORCs include natural gas liquids (NGLs), which are mixtures of NGL components that fall within a range of boiling points. Y-grade NGLs are mixtures that have a specific liquid-vapor equilibrium ratio. Moreover, the term “Y-grade” is a generic descriptor for mixtures of C2+C3+C4+natural gasolines (with a commercial limit on max amounts of trace C1 and heavies). For purposes of illustration and not of limitation, the examples set forth herein employ NGLs as EORCs.

A variety of techniques may be employed with respect to creating an EORC mixture to mix into a gas stream. Examples of such techniques include injecting a single EORC mixture or different EORC mixtures in sequence. In an exemplary embodiment, EORCs could be initially premixed with a gas stream at the surface in quantities not sufficient to create safety concerns. The resulting modified gas stream could then be injected into the subsurface as described herein.

As shown in the exemplary embodiment of FIG. 3, a lean gas stream 308 is pumped downhole through the production tubing 304 into the subsurface region using a gas compression train 318. In the exemplary embodiment shown in FIG. 3, Y-grade NGLs 312 are pumped through the annulus 306 separate from the lean gas stream 308. The NGLs 312 are allowed to enter the production tubing 304 through an orifice 316. In an exemplary embodiment, the orifice 316 may be provided by a cross-over valve. In the exemplary embodiment shown in FIG. 3, the NGLs 312 are prevented from traveling further through the annulus 306 by a packer 314.

Once the NGLs 312 enter the production tubing 304, the NGLs 312 mix statically with the lean gas stream 308 in a mixing region 320 to create an enriched gas stream 322. As shown in FIG. 3, the mixing region 320 may extend from the production tubing 304 further into the casing string 302. Subsequently, the mixture of the lean gas stream 308 and the NGLs 312 flows into the fractures 252A-252D to facilitate the EOR operation.

Annular deliver of the NGLs 312, as shown in FIG. 3, provides another practical means of delivering NGLs to the mixing region 320 based on a particular practitioner's needs and wellbore configuration(s).

Further, the content of the NGLs 312 injected via the annulus 306 may be customized based on a variety of factors. These factors include modifying the content of the NGLs 312 based on a commodity price of constituents of the NGLs 312 or other factors.

In exemplary embodiments of the present techniques, a system may be designed to have one or more mixing regions 320. The decision to employ multiple mix points may be made by practitioners based on system design considerations or objectives.

FIG. 4 is a schematic illustration showing another exemplary embodiment of the well 100 configured to perform an EOR operation according to the present techniques. Moreover, FIG. 4 illustrates that EORCs may be delivered to the subsurface separately from a lean gas stream by alternative means other than the annulus between a casing and production tubing.

In the embodiment shown in FIG. 4, the well 100 includes a casing string 302. Production tubing 304 is disposed within the casing string 302. The casing string 302 and the production tubing 304 form an annulus 306 therebetween. The production tubing is fitted with a number of gas lift valves 402.

The well 100 shown in FIG. 4 also includes a secondary string 404 for delivery of EORCs or NGLs. The secondary string may include a capillary string, coiled tubing, jointed pipe and/or a plurality of tubular/annular members, to name just a few non-limiting examples.

A lean gas stream 308 is pumped downhole through the production tubing 304 into the subsurface region using a gas compression train 318. In the exemplary embodiment shown in FIG. 4, Y-grade NGLs 312 are pumped through the secondary string 404 separate from the lean gas stream 308. The NGLs 312 are allowed to enter the production tubing 304 through an end 406 of the secondary string 404. In the exemplary embodiment shown in FIG. 4, the NGLs 312 are prevented from traveling uphole toward the surface by a packer 314. Further, a check valve (not shown) may be used on the end 406 of the secondary string 404 to prevent retrograde flow of lean gas up the secondary string 404.

In an alternate embodiment of the present techniques, the well 100 may not have a packer. In that case, the secondary string 404 may be deployed in the annulus 306, with the lean gas stream 308 being injected via the production tubing 304 or the annulus 306. If no packer is present, it is desirable to ensure that the production casing has enough burst strength to allow injectants to mix below the end of tubing without the need for injection through the gas lift valve(s).

Once the NGLs 312 enter the production tubing 304 via the end 406 of the secondary string 404, the NGLs 312 mix statically with the lean gas stream 308 in a mixing region 320 to create an enriched gas stream 322. As shown in FIG. 4, the mixing region 320 may extend from the production tubing 304 further into the casing string 302. Subsequently, the mixture of the lean gas stream 308 and the NGLs 312 flows into the fractures 252A-252D to facilitate the EOR operation.

The exemplary well 100 shown in FIG. 4 allows subsequent gas lift operations during production. Gas lift operations may be facilitated by the gas lift valves 402.

The gas lift valves 402 could be used for two purposes. The first purpose is to provide an artificial lift mechanism for the well 100 during a puff cycle of production.

A second use of the gas lift valves 402 is to provide a downhole mixing and injection port for the injectant(s) for mixing with the lean gas being injected down the tubing. Typically, an orifice valve is run at the bottom of a string of gas lift valves. It might be expected to typically inject through this orifice valve. Each of the valves also contains a backpressure check.

Delivery of the NGLs 312 via the secondary string 404, as shown in FIG. 4, reduces surface facility concerns. Further, the secondary string 404 would enable the use of annular gas lift. In general, the use of the secondary string 404 may be desirable based on the objectives of an individual user given the specific configuration of the equipment in the reservoir.

Further, the content of the NGLs 312 injected via the secondary string 404 may be customized based on a variety of factors. These factors include modifying the content of the NGLs 312 based on a commodity price of constituents of the NGLs 312 or other factors.

In another exemplary embodiment the first and second channels described herein may be provided by two separate wellbores that are adjacent to each other. Mixing of the gas stream through the first wellbore with the EROCs delivered through the second wellbore could then occur wholly within the reservoir and fracture network.

Accordingly, the present techniques avoid the difficulties of pressurizing an enriched gas stream at the surface prior to injection of the enriched gas stream into the subsurface. Further, by employing the present techniques, the content of the enriched gas stream may be modified over time to achieve changing technical and/or economic objectives for the EOR operation.

Those of skill in the art appreciate that enriching a gas stream used in EOR operations will promote improved recovery and miscibility according to first-contact miscibility (FCM) or multi-contact miscibility (MCM) mechanisms. In FCM, displacement of oil from a reservoir is enhanced when an injected fluid directly contacts the oil in the reservoir and forms a homogeneous mixture without the presence of an intermediate phase or significant compositional changes. The injected gas and the oil mix together at the molecular level, allowing the gas to dissolve into and mix with the oil and reduce its viscosity, and in particular combinations, effect a volume change (“swelling”) upon mixing. In MCM, gas is injected into the reservoir in multiple stages or cycles. The injected gas and the reservoir oil undergo a series of contacts and mixings over time. In each contact, the injected gas dissolves into the oil, reducing its viscosity and improving displacement.

The present techniques provide a way to achieve a strategic target with respect to content of the enriched gas stream. Further, the present techniques allow variation of the amount of enrichment in a safe and efficient manner.

The present techniques avoid the liquid drop out problem at the surface because only the lean gas stream 308 is compressed via the gas compression train 318. Thus, safety hazards associated with creating highly pressurized enriched gas streams at the surface are also desirably avoided. In addition, the use of separate pumps for the NGLs 312 and the lean gas stream 308 allows a high degree of customization in the resulting enriched gas stream 322 composition. That composition may also be changed as conditions change over time.

Various aspects of the composition of the enriched gas stream 322 may be controlled by changing the flow or constituent components of the NGLs 312. For example, changing the flow rate of the NGLs 312 into the well 100 will change the composition of the resulting enriched gas stream 322. Similarly, changing the constituent parts of the NGLs 312 will also change the composition of the enriched gas stream 322.

The present techniques may be employed to alter characteristics in a reservoir relative to the production of hydrocarbons. Examples of factors that may be taken into account in applying the present techniques include minimum miscibility enrichment (MME) and/or minimum miscibility pressure (MMP) design points. The present techniques may be employed to achieve a desired enrichment level based on those design points and/or other objectives.

Those of skill in the art will appreciate that the present techniques do not require reaching any particular composition of fluids in the reservoir, including specific levels of MME or MMP. Moreover, any level of enrichment of a lean gas stream used for EOR operations is beneficial and provides enhanced recovery whether a given recovery process is partially miscible or fully miscible. More information on EOR operations in general may be found in Lake, Larry, et al. “Fundamentals of Enhanced Oil Recovery.” (2014), the contents of which are incorporated by reference as though set forth in their entirety herein. More information on gas injection techniques may be found in Orr, Franklin Mattes. Theory of Gas Injection Processes. Vol. 5. Copenhagen: Tic-Line Publications, 2007, the contents of which are incorporated by reference as though set forth in their entirety herein.

The present techniques may be employed in a variety of manners for a variety of purposes. By way of example and not limitation, examples of those purposes include combing the present techniques with one or more systems/methods to optimize recycling, retention, separation, and/or recovery of injectants.

In an exemplary embodiment, the NGLs 312 have a greater density than the lean gas stream 308. Because of this relationship, a specific bottom-hole pressure at the mixing region 320 can be achieved using a low pressure pump since a larger hydrostatic gain will be realized in the secondary string for the NGLs 312 than for the lean gas stream 308. The pump outlet pressure for the NGL stream, p_pump,NGL, is approximated via the following relation requiring the outlet pressure to be greater than the pressure of the gas at the mixing point downhole, where

$\begin{matrix} p_{pump, NGL} \geq p_{pump, C 1} - (γ_{NGL} - γ_{C 1}) \times D_{mixpoint} & [1] \end{matrix}$

where p_pump,C1is the compressor discharge pressure for the lean gas, γ_C1˜0.1 psi/ft is the approximate lean gas gradient, γ_NGL˜0.18 psi/ft is the approximate NGL gradient, and D_mixpointis the depth of the mixing point (cross-over valve or end of capillary string). Those of skill in the art will appreciate that the value of 0.18 psi/ft is given by way of example and not by way of limitation. In Equation [1], frictional effects have been neglected. Note that the increased density of the NGLs 312 reduces the pump pressure needed.

As noted, the composition of the enriched gas stream 322 may be customized using the present techniques. To impact the composition of the resulting mixture of NGL and lean gas, the practitioner may change the injection rates of the NGLs 312, the lean gas stream 308, or both such that the mole fraction of NGLs 312 is increased. In formal terms, the mole fraction of NGL, z_NGL, is

$\begin{matrix} Z_{NGL} = \frac{n_{NGL}}{n_{NGL} + n_{C 1}} = \frac{{\dot{n}}_{NGL}}{{\dot{n}}_{NGL} + {\dot{n}}_{C 1}} & [2] \end{matrix}$

where subscripts NGL and C1 refer to the natural gas liquid and lean gas streams respectively, n is the number of moles, and {dot over (n)} denotes a molar flux (mols/time).

FIG. 5 is a process flow diagram of an exemplary method 500 for performing an EOR operation according to the present techniques. The method 500 may be executed, at least in part, by one or more computing systems including one or more processors, such as the cluster computing system described with respect to FIG. 6, or any suitable variation(s) thereof. In some embodiments, such computing system(s) (or a portion of such computing systems) may be located at the mobile command center 242 described with respect to FIG. 2, which may form part of the same hydrocarbon field as the well 100 described herein.

The method 500 begins at block 502, at which a lean gas stream is injected into the well 100 via a first channel. The first channel may be the production tubing 304, the annulus 306 or any other suitable channel.

At block 504, EROCs are injected into the well via a second channel. The EORCs may include the NGLs 312 as described herein. The second channel may include the secondary string 404, which may include a capillary string, coiled tubing or any other suitable channel. Further, the second channel is desirably different from the first channel, as explained herein. The composition of the enriched gas stream 322 resulting from the static mixing may be controlled as described herein such that the enriched gas stream 322 causes FCM or MCM as understood by one of skill in the art. As shown at block 506, an end of the first channel and an end of the second channel are positioned to facilitate static mixing of the lean gas stream with the EROCs to form an enriched gas stream in a subsurface region, the enriched gas stream facilitating the EOR operation.

In various embodiments, the method 400 includes altering the composition of the enriched gas stream 322 by controlling the flow rate of the EGLs 312 into the subsurface. Further, the composition of the NGLs 312 and/or other EORCs may be changed as described herein to optimize hydrocarbon production during an EOR operation.

FIG. 6 is a block diagram of an exemplary cluster computing system 600 that may be utilized to implement at least a portion of the present techniques. The exemplary cluster computing system 600 shown in FIG. 6 has four computing units 602A, 602B, 602C, and 602D, each of which may perform calculations for a portion of the present techniques. However, one of ordinary skill in the art will recognize that the cluster computing system 600 is not limited to this configuration, as any number of computing configurations may be selected. For example, a smaller analysis may be run on a single computing unit, such as a workstation, while a large calculation may be run on a cluster computing system 600 having tens, hundreds, or even more computing units.

The cluster computing system 600 may be accessed from any number of client systems 604A and 604B over a network 606, for example, through a high-speed network interface 608. The computing units 602A to 602D may also function as client systems, providing both local computing support and access to the wider cluster computing system 600.

The network 606 may include a local area network (LAN), a wide area network (WAN), the Internet, or any combinations thereof. Each client system 604A and 604B may include one or more non-transitory, computer-readable storage media for storing the operating code and program instructions that are used to implement at least a portion of the present techniques, as described further with respect to the non-transitory, computer-readable storage media of FIG. 7. For example, each client system 604A and 604B may include a memory device 610A and 610B, which may include random access memory (RAM), read only memory (ROM), and the like. Each client system 604A and 604B may also include a storage device 612A and 612B, which may include any number of hard drives, optical drives, flash drives, or the like.

The high-speed network interface 608 may be coupled to one or more buses in the cluster computing system 600, such as a communications bus 614. The communication bus 614 may be used to communicate instructions and data from the high-speed network interface 608 to a cluster storage system 616 and to each of the computing units 602A to 602D in the cluster computing system 600. The communications bus 614 may also be used for communications among the computing units 602A to 602D and the cluster storage system 616. In addition to the communications bus 614, a high-speed bus 618 can be present to increase the communications rate between the computing units 602A to 602D and/or the cluster storage system 616.

In some embodiments, the one or more non-transitory, computer-readable storage media of the cluster storage system 616 include storage arrays 620A, 620B, 620C and 620D for the storage of models, data. visual representations, results (such as graphs, charts, and the like used to convey results obtained using the present techniques), code, and other information concerning the implementation of at least a portion of the present techniques. The storage arrays 620A to 620D may include any combinations of hard drives, optical drives, flash drives, or the like.

Each computing unit 602A to 602D includes at least one processor 622A, 622B, 622C and 622D and associated local non-transitory, computer-readable storage media, such as a memory device 624A, 624B, 624C and 624D and a storage device 626A, 626B, 626C and 626D, for example. Each processor 622A to 622D may be a multiple core unit, such as a multiple core central processing unit (CPU) or a graphics processing unit (GPU). Each memory device 624A to 624D may include ROM and/or RAM used to store program instructions for directing the corresponding processor 622A to 622D to implement at least a portion of the present techniques. Each storage device 626A to 626D may include one or more hard drives, optical drives, flash drives, or the like. In addition, each storage device 626A to 626D may be used to provide storage for models, intermediate results, data, images, or code used to implement at least a portion of the present techniques.

The present techniques are not limited to the architecture or unit configuration illustrated in FIG. 6. For example, any suitable processor-based device may be utilized for implementing at least a portion of the embodiments described herein, including (without limitation) personal computers, laptop computers, computer workstations, mobile devices, and multi-processor servers or workstations with (or without) shared memory. Moreover, the embodiments described herein may be implemented, at least in part, on application specific integrated circuits (ASICs) or very-large-scale integrated (VLSI) circuits. In fact, those skilled in the art may utilize any number of suitable structures capable of executing logical operations according to the embodiments described herein.

FIG. 7 is a block diagram of an exemplary non-transitory, computer-readable storage medium 700 that may be used for the storage of data and modules of program instructions for implementing at least a portion of the present techniques. The non-transitory, computer-readable storage medium 700 may include a memory device, a hard disk, and/or any number of other devices, as described herein. A processor 702 may access the non-transitory, computer-readable storage medium 700 over a bus or network 704. While the non-transitory, computer-readable storage medium 700 may include any number of modules for implementing the present techniques, in some embodiments, the non-transitory, computer-readable storage medium 700 includes an enriched gas stream composition calculation module 706 for performing the techniques described herein (and/or any suitable variations thereof). Moreover, the enriched gas stream composition calculation module 706 may be adapted to analyze data representing the composition and amount of NGLs 312 to be mixed into the lean gas stream 308 in order to optimize an EOR operation as described herein.

In one or more embodiments, the present techniques may be susceptible to various modifications and alternative forms, such as the following embodiments as noted in paragraphs 1 to 42:

1. A method for performing an enhanced oil recovery (EOR) operation, comprising: injecting a gas stream into a well via a first channel; injecting enhanced oil recovery chemicals (EROCs) into the well via a second channel, the second channel being different from the first channel; and wherein an end of the first channel and an end of the second channel are positioned to facilitate static mixing of the gas stream with the EROCs to form an enriched gas stream in a subsurface region, the enriched gas stream facilitating the EOR operation.

2. The method of paragraph 1, comprising compressing the gas stream prior to injecting the gas stream into the well.

3. The method of paragraph 1 or 2, wherein the gas stream is a lean gas stream.

4. The method of any of paragraphs 1 to 3, wherein the first channel comprises production tubing of the well.

5. The method of any of paragraphs 1 to 4, wherein the end of the second channel comprises an orifice in fluid communication with the first channel.

6. The method of any of paragraphs 1 to 5, wherein the second channel comprises an annulus between casing and production tubing of the well.

7. The method of any of paragraphs 1 to 5, wherein the second channel comprises a capillary string running through production tubing of the well.

8. The method of any of paragraphs 1 to 7, comprising adjusting a flow rate of the EORCs to control a composition of the enriched gas stream.

9. The method of any of paragraphs 1 to 8, comprising adjusting a composition of the EORCs to control a composition of the enriched gas stream.

10. The method of any of paragraphs 1 to 8, comprising computing with a computing device a composition of the enriched gas stream based on a composition of the gas stream and a composition of the EORCs.

11. The method of any of paragraphs 1 to 10, comprising adjusting a flow rate of the EORCs to control the composition of the enriched gas stream.

12. The method of any of paragraphs 1 to 11, comprising adjusting the composition of the EORCs to control the composition of the enriched gas stream.

13. The method of any of paragraphs 1 to 12, wherein the EORCs comprise separate mixtures that are injected sequentially into the second channel.

14. The method of any of paragraphs 1 to 12, wherein the EORCs are injected into the second channel after the gas stream is injected into the first channel.

15. A well system for performing an enhanced oil recovery (EOR) operation, the well system comprising: a well that includes a first channel leading to a subsurface region and a second channel leading to the subsurface region, the second channel being different from the first channel, the first channel receiving an injected gas stream, the second channel receiving enhanced oil recovery chemicals (EORCs); and wherein an end of the first channel and an end of the second channel are positioned so that the injected gas stream statically mixes with the EORCs to form an enriched gas stream in the subsurface region.

16. The well system of paragraph 15, wherein the gas stream is compressed prior to being injected into the well.

17. The well system of paragraphs 15 or 16, wherein the gas stream is a lean gas stream.

18. The well system of any of paragraphs 15 to 17, wherein the first channel comprises production tubing of the well.

19. The well system of any of paragraphs 15 to 18, wherein the end of the second channel comprises an orifice in fluid communication with the first channel.

20. The well system of any of paragraphs 15 to 19, wherein the second channel comprises an annulus between casing and production tubing of the well.

21. The well system of any of paragraphs 15 to 19, wherein the second channel comprises a capillary string running through production tubing of the well.

22. The well system of any of paragraphs 15 to 21, wherein a flow rate of the EORCs is adjusted to control a composition of the enriched gas stream.

23. The well system of any of paragraphs 15 to 22, wherein a composition of the EORCs is adjusted to control a composition of the enriched gas stream.

24. The well system of any of paragraphs 15 to 23, wherein a computing device computes a composition of the enriched gas stream based on a composition of the gas stream and a composition of the EORCs.

25. The well system of any of paragraphs 15 to 24, wherein a flow rate of the EORCs is adjusted to control the composition of the enriched gas stream.

26. The well system of any of paragraphs 15 to 25, wherein the composition of the EORCs is adjusted to control the composition of the enriched gas stream.

27. The well system of any of paragraphs 15 to 26, wherein the EORCs comprise separate mixtures that are injected sequentially into the second channel.

28. The well system of any of paragraphs 15 to 26, wherein the EORCs are injected into the second channel after the gas stream is injected into the first channel.

29. A well system for performing an enhanced oil recovery (EOR) operation, the well system comprising: a well that includes a first channel leading to a subsurface region and a second channel leading to the subsurface region, the second channel being different from the first channel, the first channel receiving an injected gas stream, the second channel receiving enhanced oil recovery chemicals (EORCs); wherein an end of the first channel and an end of the second channel are positioned so that the injected gas stream statically mixes with the EORCs to form an enriched gas stream in the subsurface region; and a computing system that computes an optimized composition of the enriched gas stream for use in the EOR operation and controls a flow of the EORCs through the second channel to obtain the optimized composition.

30. The well system of paragraph 29, wherein the gas stream is compressed prior to being injected into the well.

31. The well system of paragraphs 29 or 30, wherein the gas stream is a lean gas stream.

32. The well system of any of paragraphs 29 to 31, wherein the first channel comprises production tubing of the well.

33. The well system of any of paragraphs 29 to 32, wherein the end of the second channel comprises an orifice in fluid communication with the first channel.

34. The well system of any of paragraphs 29 to 33, wherein the second channel comprises an annulus between casing and production tubing of the well.

35. The well system of any of paragraphs 29 to 34, wherein the second channel comprises a capillary string running through production tubing of the well.

36. The well system of any of paragraphs 29 to 35, wherein a flow rate of the EORCs is adjusted to control a composition of the enriched gas stream.

37. The well system of any of paragraphs 29 to 36, wherein a composition of the EORCs is adjusted to control a composition of the enriched gas stream.

38. The well system of any of paragraphs 29 to 37, wherein the computing system computes a composition of the enriched gas stream based on a composition of the gas stream and a composition of the EORCs.

39. The well system of any of paragraphs 29 to 38, wherein a flow rate of the EORCs is adjusted to control the composition of the enriched gas stream.

40. The well system of any of paragraphs 29 to 39, wherein the composition of the EORCs is adjusted to control the composition of the enriched gas stream.

41. The well system of any of paragraphs 29 to 40, wherein the EORCs comprise separate mixtures that are injected sequentially into the second channel.

42. The well system of any of paragraphs 29 to 40, wherein the EORCs are injected into the second channel after the gas stream is injected into the first channel.

While the embodiments described herein are well-calculated to achieve the advantages set forth, it will be appreciated that such embodiments are susceptible to modification, variation, and change without departing from the spirit thereof. In other words, the particular embodiments described herein are illustrative only, as the teachings of the present techniques may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Moreover, the systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

CUSTOMIZABLE DOWNHOLE MIXING OF LEAN GAS STREAMS WITH ENHANCED OIL RECOVERY CHEMICALS

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