Artificial lift wellhead assembly systems and methods
Patent Information
- Application Number
- PCT/US2026/024022
- Authority / Receiving Office
- WO · WO
- Patent Type
- Applications
- Current Assignee / Owner
- Priority Date
- 2025-04-16
- Filing Date
- 2026-04-16
- Publication Date
- 2026-10-22
Smart Images
Figure US2026024022_22102026_PF_FP_ABST
Abstract
Description
ARTIFICIAL LIFT WELLHEAD ASSEMBLY SYSTEMS AND METHODSCROSS-REFERENCES TO RELATED APPLICATIONS
[0001] This application claims priority to and benefit of U.S. Provisional Patent Application No. 63 / 789,493 filed April 16, 2025, which is hereby incorporated by reference herein in its entirety for all purposes.BACKGROUND
[0002] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the presently described embodiments. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present embodiments. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.
[0003] In order to meet consumer and industrial demand for natural resources, companies often invest significant amounts of time and money in searching for and extracting oil, natural gas, and other subterranean resources from the earth.Particularly, once a desired subterranean resource is discovered, drilling and production systems are often employed to access and extract the resource. These systems may be located onshore or offshore depending on the location of a desired resource. Further, such systems generally include a wellhead assembly through which the resource is extracted. These wellhead assemblies may include a wide variety of components, such as various casings, valves, fluid conduits, and the like, that control drilling or extraction operations.
[0004] Additionally, such wellhead assemblies may use a fracturing tree and other components to facilitate a fracturing process and enhance production from a well. As will be appreciated, resources such as oil and natural gas are generally extracted from fissures or other cavities formed in various subterranean rock formations or strata. To facilitate extraction of such resources, a well may besubjected to a fracturing process that creates one or more man-made fractures in a rock formation. This facilitates, for example, coupling of pre-existing fissures and cavities, allowing oil, gas, or the like to flow into the wellbore. Such fracturing processes typically include injecting a fracturing fluid — which is often a mixture including proppant (e.g., sand) and water — into the well to increase the well’s pressure and form the man-made fractures. The high pressure of the fluid increases crack size and crack propagation through the rock formation to release oil and gas, while the proppant prevents the cracks from closing once the fluid is depressurized. During fracturing operations, fracturing fluid may be routed via fracturing lines (e.g., pipes) to fracturing trees or other assemblies installed at wellheads.Conventional fracturing trees have valves that can be opened and closed to control flow of fluid through the fracturing trees into the wells. After fracturing is completed, fluid may be produced from the well through the wellhead.
[0005] To compensate for the lack of natural energy in some formations, operators may equip the wells with artificial lift systems. Artificial lift well candidates may be those wells completed in formations that have economically viable reserves and sufficient permeability for the fluids to move to the wellbore but do not have sufficient reservoir drive to lift those fluids to the surface. Secondary recovery efforts, such as waterfloods designed to capture remaining reserves in pressure-depleted reservoirs, often result in increased fluid volumes that can be lifted to the surface more effectively through artificial lift methods.
[0006] When choosing a specific artificial lift system, engineers may consider a host of parameters, such as surface conditions based on location, reservoir characteristics, production properties, fluid types, and operational considerations. Choice of an artificial lift system may be influenced by subsurface conditions, expected production rates, fluid composition, well geometry, reservoir depths, completion configuration, and surface facilities. In addition, operators may consider the potential return on their investment by balancing the value of increased production against the cost of hardware for and installation and maintenance of an artificial lift system.SUMMARY
[0007] Certain aspects of some embodiments disclosed herein are set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of certain forms the invention might take and that these aspects are not intended to limit the scope of the invention. Indeed, the invention may encompass a variety of aspects that may not be set forth below.
[0008] Embodiments of the present disclosure generally relate to well assemblies and operations. More specifically, some embodiments relate to wellhead assemblies including a horizontal spool tree that may be installed on the well during fracturing, flowback, and production operations and may facilitate artificial lift techniques to enhance production. In some embodiments, a horizontal spool tree includes a tubing hanger installed in a bore of a main body having first and second ports extending from the bore to the exterior of the main body. The first and second ports may be provided at different axial locations along the bore, and external wing valves coupled to the main body may be used to control flow through the first and second ports. In some instances, lift gas may be injected into the well through the first port and produced fluid may flow out from the main body through the second port. The horizontal spool tree may also or instead be used with other artificial lift techniques, such as with a downhole pump (e.g., an electric submersible pump) or a plunger lift system.
[0009] Various refinements of the features noted above may exist in relation to various aspects of the present embodiments. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. Again, the brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of some embodiments without limitation to the claimed subject matter.BRIEF DESCRIPTION OF THE DRAWINGS
[0010] These and other features, aspects, and advantages of certain embodiments will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:
[0011] FIG. 1 generally depicts various components, including a wellhead assembly and one or more tubular strings, that can be installed at a well in accordance with one embodiment of the present disclosure;
[0012] FIG. 2 is a perspective view of a wellhead assembly with a horizontal spool tree coupled to a wellhead in accordance with one embodiment;
[0013] FIG. 3 is a section view of the horizontal spool tree of FIG. 2 and shows a tubing hanger installed in a tubing spool in accordance with one embodiment;
[0014] FIG. 4 is an illustration of an annular gas lift system using a horizontal spool tree in accordance with one embodiment;
[0015] FIG. 5 is an illustration of a tubular gas lift system using a horizontal spool tree in accordance with one embodiment;
[0016] FIG. 6 is a section view of a horizontal spool tree with an eccentric tubing hanger and pump run in accordance with one embodiment;
[0017] FIG. 7 is a detail view of the tubing hanger of FIG. 6 in accordance with one embodiment;
[0018] FIG. 8 is a section view of a horizontal spool tree with a concentric tubing hanger and pump run in accordance with one embodiment;
[0019] FIG. 9 is a detail view of the tubing hanger of FIG. 8 in accordance with one embodiment;
[0020] FIG. 10 is a section view of a horizontal spool tree including a tubing hanger installed in a main body in accordance with one embodiment;
[0021] FIG. 11 is a side detail view of the tubing hanger and main body of FIG. 10, showing a feed-through penetrator installed in a port of the main body, in accordance with one embodiment;
[0022] FIG. 12 is a side detail view like that of FIG. 11, but with the feed-through penetrator installed at a lower position along the main body, in accordance with one embodiment; and
[0023] FIG. 13 illustrates a horizontal spool tree with a plunger lift system in accordance with one embodiment.DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS
[0024] Specific embodiments of the present disclosure are described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
[0025] When introducing elements of various embodiments, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Moreover, any use of “top,” “bottom,” “above,” “below,” other directionalterms, and variations of these terms is made for convenience, but does not require any particular orientation of the components.
[0026] Certain embodiments of the present application generally involve a system and methodology to facilitate well operations. According to an embodiment, the system comprises a modular assembly configured for coupling to a wellhead mounted over a borehole. The modular assembly can include a production subassembly and a fracturing sub-assembly. As discussed in greater detail below, the production sub-assembly may be provided as a horizontal spool tree. The horizontal spool tree may provide efficiencies out on location for operators by allowing fracturing, flowback, and production within the same body. This may allow operators to avoid reworking piping from other scenarios and focus flowback and production through a single focal point that during flowback can be redirected to sand screens or otherwise be closed off directly for production lines. The system may further include an artificial lift system, such as an annular gas lift system, a tubular gas lift system, an electric submersible pump system, or a plunger lift system. The horizontal spool tree may facilitate artificial lift techniques, allowing each of fracturing, flowback, and enhanced production through the horizontal spool tree in at least some instances.
[0027] Turning now to the present figures, a system 10 is illustrated in FIG. 1 in accordance with one embodiment. Notably, the system 10 is a production system that facilitates extraction of a resource, such as oil, from a reservoir 12 through a well 14, such as an onshore well. A wellhead assembly 16 is installed at the well 14. As depicted, the wellhead assembly 16 includes a wellhead 20 over the well 14, a production sub-assembly 22 mounted above the wellhead 20, and a fracturing subassembly (e.g., a fracturing tree 24) mounted above the production sub-assembly. The wellhead 20 can include one or more pressure-containing housings, such as a casing head. Hangers can be connected to tubular strings, such as a tubing string 26 (e.g., production tubing) or a casing string 28, to suspend the strings within the well 14. The hangers can be mandrel-style hangers or slip-style hangers. The well 14 can include a single casing string 28 or include multiple casing strings 28 of different diameters. In at least some embodiments, and as described in further detailbelow, a tubing hanger connected to the tubing string 26 is landed in a tubing head (also referred to as a tubing spool) of the production sub-assembly 22.
[0028] In at least some embodiments, fracturing fluid is pumped into the fracturing tree 24 and down the well 14 through the production sub-assembly 22 and the wellhead 20 to fracture a rock formation having the reservoir 12. Those skilled in the art will appreciate that fracturing trees 24 can include various elements, such as some or all of master valves, wing valves, swab valves, connection blocks, or frac heads. In other embodiments, the fracturing sub-assembly may include a valve or other equipment without a fracturing tree 24 mounted over the wellhead 20.
[0029] The fracturing tree 24 and any other fracturing sub-assembly equipment may be rated for high-pressure applications, such as fracturing fluid pressures of up to 10000 psi, 12000 psi, or 15000 psi (approximately 70000 kPa, 80000 kPa, or 100000 kPa). Other equipment of the wellhead assembly 16 may also be rated for such pressures or protective devices may be used to isolate some components from such pressures. For instance, an isolation mandrel could be installed through a main bore of the production sub-assembly 22 to isolate valves of the production subassembly 22 from the fracturing fluid.
[0030] Once fracturing is completed, the fracturing sub-assembly (e.g., the fracturing tree 24) can be removed from the wellhead assembly 16, leaving the production sub-assembly 22 in place over the wellhead 20 and well 14. Valves of the production sub-assembly 22 may be selectively opened to control flow of fluids through the sub-assembly 22, such as for flowback from the well 14 after fracturing. Reservoir fluids may also or instead be produced from the well 14 through the production sub-assembly 22. Various artificial lift systems 30 may be used alone or in combination to facilitate such production in some embodiments. As generally depicted in FIG. 1, for instance, an artificial lift system 30 may include one or more of a lift gas source 32 (for gas lift) or a pump installed in the well 14, such as an electric submersible pump (ESP) 34, a plunger pump 36, or some other form of pump 38 (e.g., a progressing cavity pump or rod lift pump). While artificial lift may be used in the well 14 after removing the fracturing tree 24 from the wellheadassembly 16, artificial lift could also or instead be used with the fracturing tree 24 remaining installed above the production sub-assembly 22 in some cases.
[0031] An example of an onshore apparatus 40 having the production subassembly 22 mounted on a surface wellhead 20 is shown in FIG. 2 in accordance with one embodiment. In this depicted embodiment, the production sub-assembly 22 is provided as a horizontal spool tree having a main body 42 (shown here as a tubing spool) with a lower flange fastened to a casing head of the wellhead 20. A blind flange 44 is fastened to the upper end of the main body 42 in FIG. 2. The blind flange 44 may be fastened to the upper end of the main body 42 after disconnecting and removing the fracturing tree 24 from the upper end of the main body 42 in at least some embodiments. Portions of casing strings 28 extending downward from the wellhead 20 are generally shown in FIG. 2, as is a portion of the tubing string 26 suspended from a tubing hanger 70 (FIG. 3) installed in the main body 42.
[0032] The horizontal spool tree is depicted in FIG. 2 as having four wings extending laterally outward from the main body 42, with each wing including a pair of valves 50, 52, 54, or 56. Although each of these wings is shown having two valves in FIG. 2, in other embodiments any or all of the wings may have some other number of valves (e.g., a single valve). And while four wings are shown in FIG. 2, the horizontal spool tree could have more or fewer wings in other instances. In one embodiment, for example, one or multiple of the wings shown in FIG. 2 could be omitted.
[0033] The valves 50, 52, 54, and 56 may be provided as gate valves or any other suitable valves. The bodies and sealing features of the valves 50, 52, 54, and 56 may be identical or may differ from one another. In FIG. 2, a shared connection block 60 is fastened to ends of the two wings having valves 50 and 52, and a shared connection block 62 is fastened to ends of the two wings having valves 54 and 56. In some instances, one of the connection blocks 60 or 62 is used to supply a fluid (e.g., lift gas) to the two wings connected to that connection block 60 or 62, while the other connection block 60 or 62 is used to receive a fluid (e.g., aproduction fluid from the well) from the two wings connected to that other connection block 60 or 62.
[0034] As shown in FIG. 3, the tubing string 26 is suspended from the tubing hanger 70, which is installed in a bore 66 of the main body 42. In at least some embodiments, a fracturing tree 24 mounted above the main body 42 is removed from the wellhead assembly 16 before the tubing hanger 70 is installed in the main body 42. The wings are connected to the exterior of the main body 42 in fluid communication with the bore 66 through side access ports in the main body 42. The wings having valves 52 and 56 are in fluid communication with an annular space surrounding the tubing string 26 within the bore 66. In contrast, the wings having valves 50 and 54 are in fluid communication with the tubing string 26 via side access ports in the tubing hanger 70. In FIG. 3, the side access ports by which the valves 52 and 56 are in fluid communication with the bore 66 are located at an axial position along the bore 66 that is different than the axial position of the side access ports by which the valves 50 and 54 are in fluid communication with the bore 66. The valves 50, 52, 54, and 56 may be opened or closed to selectively control flow of fluid laterally into or out of the main body 42.
[0035] In some instances, the valves 50, 52, 54, and 56 are operated to facilitate injection of a lift gas (e.g., from gas source 32) into the well and production of formation fluid from the well. For instance, in certain embodiments, injecting the lift gas into the well includes routing the lift gas laterally into the bore 66 through at least one of the wings of the horizontal spool tree of FIG. 2. The lift gas received in the bore 66 in this manner may flow into the well 14 to mix with liquids in the well. Further, producing the formation fluid can include receiving the formation fluid from the well 14 into the bore 66 and routing the formation fluid laterally out from the bore 66 through at least one other wing of the horizontal spool tree.
[0036] Two examples of using the horizontal spool tree of FIG. 2 in this manner may be better understood with reference to FIGS. 4 and 5. The first example of FIG. 4 depicts an annular gas lift system in which the lift gas is injected down the tubing string 26 into the well 14 and production fluid flows up from the well 14 inthe casing-tubing annulus surrounding the tubing string 26. The second example of FIG. 5 depicts a tubular gas lift system in which the lift gas is instead injected down the casing-tubing annulus and the production fluid flows up from the well 14 through the tubing string 26. In both examples, rather than having the blind flange 44 attached to the main body 42, an adapter 80 and access valves 82 may be mounted above the main body 42. Additionally, in both examples the lift gas flows into the connection block 60 and then into the bore 66 through one of the wings connected between the connection block 60 and the main body 42, and produced fluid flows out of the bore 66 through one of the wings connected between the main body 42 and the connection block 62. Additional equipment 86 (e.g., production valves, chokes, or sand screens) may be coupled to receive the produced fluid from the connection block 62.
[0037] As shown in FIG. 4, the valves 50 are open and the valves 52 are closed. This allows the lift gas to flow from the connection block 60 through the open valves 50, laterally into the bore 66 of the main body 42, into the tubing hanger 70 (e.g., through lateral ports of the tubing hanger 70), and down the tubing string 26 into the well. This flow path of the injected lift gas is generally represented by dashed arrows in FIG. 4. Additionally, the valves 54 are closed and the valves 56 are open so that fluid produced from the well flows into the annular space between the tubing string 26 and the wall of the bore 66 in the main body 42, laterally out from the bore 66 through the valves 56, and into the connection block 62, as generally represented by solid arrows in FIG. 4.
[0038] In FIG. 5, the valves 50 and 56 are closed and the valves 52 and 54 are open. Lift gas flows from the connection block 60 through the open valves 52, laterally into the bore 66 below the hanger 70 (specifically, into the annular space surrounding the tubing string 26), and down into the well via the casing-tubing annulus. Production fluid flows up the well 14 through the tubing string 26 into the bore 66, from which the production fluid flows laterally out through the valves 54 to the connection block 62.
[0039] In some embodiments, the horizontal spool tree is used with a downhole pump, such as an electric submersible pump (ESP) 34. For example, in FIG. 6, a connector 90 is attached to a feed-through penetrator in the adapter 80 to provide electrical communication (e.g., power) to the downhole pump via one or more conductors of a cable 102 (FIG. 7) electrically connected between the feed-through penetrator and the downhole pump. As shown in FIG. 7, the tubing hanger 70 is an eccentric tubing hanger with a primary bore 92 that is aligned with the tubing string 26 and is offset from the centerline of the hanger. The depicted tubing hanger 70 includes an additional bore or passageway 96 for receiving the cable 102.
[0040] One or more pressure barriers, such as back-pressure valves or plugs, may be installed in the tubing hanger 70 for sealing purposes. Such barriers may be threaded into the tubing hanger 70 or secured in any other suitable manner. As shown in FIG. 7, for example, a back-pressure valve 104 is threaded into the lower end of the bore 92 to isolate and block flow from the tubing string 26 to the upper end of the bore 92 and to the side access ports leading to the valves 50 and 54.
[0041] The horizontal spool tree may also be used with concentric pump runs, such as shown in FIGS. 8 and 9. In this depicted embodiment, the tubing hanger 70 is a concentric hanger with the bore 92 along the centerline of the hanger body and offset channels 110 that extend between the upper and lower surfaces of the hanger body and allow electrical communication between the surface (e.g., from a penetrator installed in the adapter 80) and the downhole pump (e.g., an ESP 34) through the body of the hanger 70. In FIG. 9, two plugs 106 and 108 are shown installed in the bore 92 above side access ports in the hanger body to block flow through the upper end of the bore 92. These plugs may be threaded into mating portions of the hanger body or secured in any other suitable manner. In at least some embodiments, each of these plugs is a metal plug and provides a metal-to-metal seal against the body of the hanger 70.
[0042] In some instances, such as in embodiments depicted in FIGS. 10-12, an electrical connection between a downhole ESP 34 (or other pump) and surface equipment outside the wellhead assembly is made via a feed-through penetratorinstalled in a port of the main body 42 of the horizontal spool tree. As shown in the front section view of FIG. 10, the horizontal spool tree of production subassembly 22 includes the tubing hanger 70 installed in the bore 66 of the main body 42 and wing valves 50, 52, 54, and 56 for controlling flow into and out of the bore 66. FIG. 11 is a side section view of the horizontal spool tree of FIG. 10 and shows a feed-through penetrator 120 installed in a port that extends through a side of the main body 42 from the bore 66 to an exterior surface of the main body 42. This allows the electrical connection into the bore 66 to be made laterally (e.g., horizontally) through the side of the main body 42, rather than being made above the main body 42 (e.g., in the adapter 80 of FIGS. 6 and 8). In FIG. 11, the tubing hanger 70 includes a channel 116 for receiving the cable 102. Rather than extending from the lower surface to the upper surface of the hanger 70, the channel 116 of FIG. 11 extends only partially into the hanger body from the lower surface and is isolated from the upper surface. In FIG. 12, the penetrator 120 is positioned in the main body 42 at an axial location that is below the tubing hanger 70. This allows the penetrator 120 to be connected to the cable 102 below the hanger 70 and the channel 116 to be omitted. When installing the tubing hanger 70 of FIGS. 10-12 in the main body 42, the tubing hanger 70 may be oriented angularly so that the upper end of the cable 102 is positioned near the penetrator 120 to facilitate electrical connection. This orientation may be performed manually, or the spool tree may include one or more alignment features (e.g., pins, keys, ridges, slots) to help align the hanger 70 in a desired orientation.
[0043] Still further, the horizontal spool tree of the production sub-assembly 22 may be used with a plunger lift system, such as shown in FIG. 13. In this embodiment, a lubricator 130 and a valve 82 are coupled above the main body 42 of the horizontal spool tree. It will be appreciated that the plunger lift system may include a plunger that travels up and down the well 14 through the tubing string 26. When the plunger reaches the surface, the plunger may be received in the lubricator 130. Produced fluids may be routed laterally out of the bore 66 of the main body 42, such as through valves 54 to the connection block 62. The lubricator 130 is tied into the connection block 62 via piping 134. A production linemay also be connected to the connection block 62 (e.g., to the right side of the connection block 62 in FIG. 13), allowing fluid entering the connection block 62 from the valves 54 (or 56) and from the piping 134 to flow into the production line. The apparatus of FIG. 13 has a simplified tie in of the lubricator 130 to the production line, with a single line of piping 134 connecting the lubricator to the production line via the connection block 62. This is in contrast to some systems in which the lubricator is tied in via multiple pipelines. Additionally, in at least some embodiments, the lubricator 130 can be plumbed into existing production lines connected to the horizontal spool tree without the need to reconfigure either the production lines or the tree.
[0044] While the aspects of the present disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. But it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.
Claims
CLAIMS1. A method for producing fluid from a well, the method comprising: injecting a lift gas into the well, wherein injecting the lift gas into the well includes routing the lift gas laterally into a bore of a tubing spool of a wellhead assembly such that the lift gas flows into the well from the bore of the wellhead assembly; andproducing a formation fluid from the well, wherein producing the formation fluid from the well includes receiving the formation fluid from the well into the bore of the tubing spool and routing the formation fluid laterally out from the bore of the tubing spool.
2. The method of claim 1, wherein injecting the lift gas into the well includes routing the lift gas laterally into the bore of the tubing spool through a first wing connected to the tubing spool, and producing the formation fluid from the well includes routing the formation fluid laterally out from the bore of the tubing spool through a second wing connected to the tubing spool.
3. The method of claim 2, wherein:routing the lift gas laterally into the bore of the tubing spool through the first wing includes routing the lift gas laterally into an annular space within the bore of the tubing spool through the first wing, wherein the annular space surrounds a tubing string suspended from a tubing hanger installed in the tubing spool; and receiving the formation fluid from the well into the bore of the tubing spool includes receiving the formation fluid from the well into the bore of the tubing spool through the tubing string.
4. The method of claim 2, wherein:routing the lift gas laterally into the bore of the tubing spool through the first wing includes routing the lift gas laterally into the bore of the tubing spool throughthe first wing such that the lift gas flows into the well through a tubing string suspended from a tubing hanger installed in the tubing spool; andreceiving the formation fluid from the well into the bore of the tubing spool includes receiving the formation fluid from the well into an annular space surrounding the tubing string in the tubing spool.
5. The method of claim 2, wherein routing the lift gas laterally into the bore of the tubing spool through the first wing includes opening at least two valves of the first wing, and routing the formation fluid laterally out from the bore of the tubing spool through the second wing includes opening at least two valves of the second wing.
6. The method of claim 2, wherein the wellhead assembly includes a third wing connected to the tubing spool and a connection block coupled to the first wing and to the third wing such that each of the first wing and the third wing extends from the connection block to the tubing spool, and routing the lift gas laterally into the bore of the tubing spool through the first wing includes routing the lift gas laterally into the bore of the tubing spool from the connection block through one or more open valves of the first wing while one or more valves of the third wing are closed.
7. The method of claim 6, wherein the wellhead assembly includes a fourth wing connected to the tubing spool and an additional connection block coupled to the second wing and to the fourth wing such that each of the second wing and the fourth wing extends from the tubing spool to the additional connection block, and routing the formation fluid laterally out from the bore of the tubing spool through the second wing includes routing the formation fluid laterally out from the bore of the tubing spool through one or more open valves of the second wing and into the additional connection block while one or more valves of the fourth wing are closed.
8. The method of claim 1, comprising removing a fracturing tree mounted above the tubing spool from the wellhead assembly before injecting the lift gas into the well.
9. The method of claim 8, comprising installing a tubing hanger in the tubing spool after removing the fracturing tree from the wellhead assembly.
10. An apparatus comprising:a horizontal spool tree configured to be coupled to a wellhead over a well, wherein the horizontal spool tree includes:a main body having a bore that is configured to receive a tubing hanger, a first port extending from the bore to an exterior of the main body, and a second port extending from the bore to the exterior of the main body, wherein the first port and the second port are located at different axial positions along the bore;a first wing valve coupled to an exterior of the main body to control flow through the first port; anda second wing valve coupled to the exterior of the main body to control flow through the second port.
11. The apparatus of claim 10, wherein the horizontal spool tree is coupled to the wellhead.
12. The apparatus of claim 11, comprising the tubing hanger, wherein the tubing hanger is installed in the bore of the main body with a tubing string suspended from the tubing hanger into the well.
13. The apparatus of claim 12, wherein the first port is in fluid communication with an annular space surrounding the tubing string within the bore and the second port is in fluid communication with an interior of the tubing string through the tubing hanger.
14. The apparatus of claim 12, wherein two barriers are installed in the tubing hanger.
15. The apparatus of claim 12, comprising a lift gas source coupled to the horizontal spool tree.
16. The apparatus of claim 10, comprising a shared connection block coupled to each of the first wing valve and the second wing valve.
17. The apparatus of claim 16, comprising a lubricator coupled to the horizontal spool tree, wherein the lubricator is tied into the shared connection block via piping.
18. The apparatus of claim 10, wherein:the main body of the horizontal spool tree includes a third port extending from the bore to the exterior of the main body; andthe horizontal spool tree includes a third wing valve coupled to the exterior of the main body to control flow through the third port.
19. The apparatus of claim 18, wherein:the main body of the horizontal spool tree includes a fourth port extending from the bore to the exterior of the main body; andthe horizontal spool tree includes a fourth wing valve coupled to the exterior of the main body to control flow through the fourth port.
20. The apparatus of claim 10, comprising a feed-through penetrator installed in an additional port extending from the bore to the exterior of the main body to facilitate electrical communication with an electric submersible pump disposed in the well.