CROSS REFERENCE PARAGRAPH

[0001] This application claims the benefit of U.S. Provisional Application No. 63/401,550, entitled "SUBSEA WELL TEST FLUID REINJECTION SYSTEM TO ELIMINATE FLARING," filed August 26, 2022, and U.S. Provisional Application No. 63/578,034, entitled " SUBSEA WELL TEST FLUID REINJECTION SYSTEM TO ELIMINATE FLARING," filed August 22, 2023, and U.S. Provisional Application No. 63/534,860, entitled " SUBSEA WELL TEST FLUID REINJECTION SYSTEM TO ELIMINATE FLARING," filed August 27, 2023, the disclosures of which are hereby incorporated herein by reference.

BACKGROUND

[0002] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below. 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 disclosure. Accordingly, it may be understood that these statements are to be read in this light, and not as admissions of prior art.

[0003] The conventional approach for well testing of a subsea well is to flow the reservoir fluids to a surface rig via a riser, through a well test package, after which point, the fluids are typically flared to environment thus generating carbon emissions.

[0004] The present disclosure relates generally to techniques and systems that operate to reduce emissions due to well test fluid flaring. BRIEF DESCRIPTION OF THE DRAWINGS

[0005] The subject disclosure is further described in the following detailed description, and the accompanying drawings and schematics of non-limiting embodiments of the subject disclosure. The features depicted in the figures are not necessarily shown to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form, and some details of elements may not be shown in the interest of clarity and conciseness. These and other features, aspects, and advantages of the present invention 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:

[0006] FIG. 1 illustrates a first embodiment of a system for subsea well test fluid reinjection according to one or more aspects of the present disclosure;

[0007] FIG. 2 illustrates a second embodiment of a system for subsea well test fluid reinjection according to one or more aspects of the present disclosure;

[0008] FIGS. 3 illustrates a third embodiment of a system for subsea well test fluid reinjection according to one or more aspects of the present disclosure; and

[0009] FIG. 4 illustrates a fourth embodiment of a system for subsea well test fluid reinj ection according to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

[0010] One or more specific embodiments of the present disclosure will be described below. The particulars shown herein are by way of example, and for purposes of illustrative discussion of the embodiments of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure. Tn this regard, no attempt is made to show structural details of the subject disclosure in more detail than is necessary for the fundamental understanding of the subject disclosure, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice. Additionally, in an effort to provide a concise description of these exemplary 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.

[0011] When introducing elements of various embodiments of the present invention, 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 used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.” Also, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is intended to mean either an indirect or a direct interaction between the elements described. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. The use of “top,” “bottom,” “above,” “below,” and variations of these terms is made for convenience but does not require any particular orientation of the components.

[0012] Certain terms are used throughout the description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name, but not function.

[0013] An open-water conduit may be deployed from a rig or vessel, connected to an optional subsea safety device, and further connected to a subsea well via a wellhead, Christmas tree via choke body or an alternative access point such as a tree re-entry mandrel or well jumper connector, or other intervention access point on a subsea system. The proposed embodiment enables well test fluids to be injected into a reservoir or existing subsea production stream and onto a processing facility thus eliminating the requirement for flaring.

[0014] During well testing from a rig or vessel, produced fluids may be reinjected back into a reservoir or subsea production system thus eliminating flaring at surface. This application is most relevant for, but not limited to, gas developments and has the potential to eliminate gas flaring during well testing thus contributing significantly to the reduction of emissions generated during this phase of the development.

[0015] With the foregoing in mind, FIG. 1 illustrates an offshore vessel 10 which may be, for example, a mobile offshore drilling unit (MODU) (e g., a vessel used in offshore oil and gas exploration and/or well maintenance or completion work including, but not limited to, casing and tubing installation, subsea tree installations, and well capping). Examples of MODUs include a semi-submersible platform or a jack up drilling platform. In other embodiments, the offshore vessel 10 may instead be a spar platform, a floating production system, or the like. Additionally, while an offshore vessel 10 is illustrated and described in FIG. 1, the techniques and systems described herein may also be applied to and utilized in onshore (e.g., land based) drilling activities. [0016] As illustrated in FIG. 1, the offshore vessel 10 includes a marine riser 12 extending therefrom. The marine riser 12 may include a pipe or a series of pipes that connect the offshore vessel 10 to the seabed 14 via, for example, a blowout preventer (BOP) 16 and a subsea tree 18 (e.g., a Christmas tree) that is coupled to a wellhead 20 on the seabed 14. In some embodiments, the marine riser 12 may transport produced hydrocarbons and/or production materials between the wellhead 20 and the offshore vessel 10, while the BOP 16 may include at least one BOP stack having at least one valve with a sealing element to control wellbore fluid flows. Furthermore, the subsea tree may be an assembly of valves, flow pathways, piping, connectors, and the like placed between the wellhead 20 and the marine riser 12 to monitor and control production flow and manage gas or fluid injection. In other embodiments, an open-water intervention riser system using a drill pipe riser deployed from a rig or semi-submersible intervention vessel or an alternative arrangement may be employed.

[0017] Regardless of the arrangement, a fluid conduit is connected to a subsea well 21 that is to be tested or cleaned through the removal of solids. Alternative conduits include drilling tubulars, coiled tubing, flexible hose, thermoplastic hose, composite pipe, or any other suitable conduit. The connection between the fluid conduit and well 21 may be via the subsea tree 18 (e.g., a Christmas tree), the wellhead 20, or an alternative access point on the subsea system.

[0018] The offshore vessel 10 as illustrated also includes a well test package 22. The well test package 22 may include, for example, one or more of a flowhead (e.g., a surface safety tree or test tree) that controls and/or diverts fluid flow, a data header that that serves as a connection point, a choke manifold that operates as a pressure-reducing device, a steam heat exchanger that operates as heating equipment as well as additional equipment. The well test package 22 operates to collect data of a reservoir by bringing reservoir fluids to the surface 24 to determine characteristics of a well 21 (e.g., pressure, temperature, impurities, etc.). Typically, the well test package 22 is connected to a flaring system, which may ignite, for example, hydrocarbons received by the well test package 22 during a well test operation. In this manner, reservoir fluids flowing to the flaring system are flared to the environment, thus generating carbon emissions.

[0019] However, FIG. 1 shows a first embodiment of a subsea well test fluid reinjection system 26 that eliminates flaring and instead allows for the hydrocarbons produced as well test fluids to be captured and/or routed to, for example, production facilities. The illustrated embodiment shows an embodiment where the well fluids are injected into an (existing) subsea infrastructure 28, which has already been installed and is producing to a host facility. Alternatively, the fluids may be injected into a subsea well 29, with or without a subsea tree 30 installed, and bullheaded into a reservoir. Moreover, a fluid well test spread, or clean up spread, may be installed upon the offshore vessel 10 to provide any necessary functionality; however, this functionality may be reduced versus a comparable spread used for a conventional well test.

[0020] To perform well testing, the reservoir fluids may be flowed from the well 21 to the surface via the fluid conduit (e.g., marine riser 12) with control provided by the well test package 22. Rather than flaring the produced fluids at surface as is conventionally done, the fluids are reinjected to a reservoir or subsea infrastructure 28, thus eliminating the requirement for flaring. This is achieved via an additional conduit 32, which may be deployed from the offshore vessel 10 and connected to the subsea infrastructure 28, for example, temporarily. FIG. 1 shows this achieved via a subsea tree 30, specifically using a choke body 34 as the access point; however, it may be achieved using an alternative access point on the tree 30, an alternative access location on the subsea infrastructure 28 (e.g., a manifold), or a new subsea structure, such as a storage vessel. Further, a topside return location (e.g., a rig, a vessel, etc.) may be selected. The conduit 32 (e.g., a reinjection conduit) may incorporate flow control devices (e.g., isolation valves, check valves, chokes), which may be located within the conduit 32 or within an independent structure. The construction of the conduit 32 may be conventional drilling tubulars, coiled tubing, flexible hose, thermoplastic hose, composite pipe, or any other suitable conduit. Alternatively, a well access package such as an open-water intervention riser system or subsea intervention lubricator may be used to provide the conduit 32 and means of connection to the subsea infrastructure 28. Subsea jumpers may also be used to interconnect the conduit 32 and additional structures.

[0021] The system 26 may be connected to a plurality of wells allowing testing and/or returning fluids to/from multiple locations.

[0022] The system 26 may be operated using only reservoir energy to drive flow (i.e., natural drive) or may include an energy source, either topside or subsea, to add energy to the fluid and facilitate flow (e.g., compressor).

[0023] An intervention workover control system (IWOCS) may also be included to operate a subsea device 36 (e.g., a subsea safety device or a subsea process device), which may be, for example an intervention system (e.g., skid with isolation valves). The subsea device 36 may be a packaged device that is deployable and retrievable. The IWOCS may also operate the subsea tree 18 on the tested well 21 , if present, and the subsea tree 30 well receiving the fluids. A conventional IWOCS using an umbilical or a subsea workover control system (SWOCS) using a subsea hydraulic power unit (HPU) and electronic test unit may be used. Alternatively, or in combination with an IWOCS/SWOCS, power and/or communications may be supplied wirelessly, from an existing subsea structure/production control system, integrated batteries, or some renewable or alternative source.

[0024] Various processing functionalities may be incorporated into the topside well test spread as required for the application (e g., sand knock-out, chemical injection). Further, processing functionality or additional data acquisition may be integrated into the subsea package, either the package accessing the well 21 to be tested and/or the package used to return fluids to the subsea infrastructure 28.

[0025] The subsea well test fluid reinjection system 26 may include a conduit 38 coupled to the well test package 22 to receive the well test fluids that would otherwise be flared. This conduit 38 may be part of conduit 32 or coupled to conduit 32 and may be deployed subsea 40 via, for example, a downline deployment reeler 42 or similar device to control the release of the conduit 32 subsea. As illustrated, the conduit 32 is coupled to a subsea device 36, which may include, for example, valves, pressure adjustment equipment, disconnects, and the like to control and or alter characteristics of the well test fluids. In some embodiments, portions or all of the subsea device 36 may instead be disposed on the offshore vessel 10 or along the conduit 32 and coupled to the subsea tree 30 directly therefrom.

[0026] As illustrated, the subsea device 36 may be coupled, for example, via a jumper 44 to the subsea tree 30 via a choke body 34 as the access point. Alternatively, the choke body 34 or its equivalent may be part of the subsea device 36. The well test fluids may be transmitted from the subsea tree 30 into the well 29 and/or via a conduit 46 to a production facility or to another subsea element. Further, one or more control lines may be coupled to the subsea device 36 to provide power and/or control signals to the subsea safety device 36. These may provide electric, hydraulic, and/or another type of control line, or a combination thereof. [0027] Tn an alternative embodiment, the subsea device 36 may include a well test portion (performing one or more of the operations of the well test package 22) and may be run subsea and connected to two or more subsea wells (either directly or via jumpers). Fluid from the well(s) to be tested flows to the well test portion then onto a receiving well to convey the fluid into an existing subsea flow stream or reservoir. The connection to the wells may be achieved via a choke body or an alternative access point such as a tree re-entry mandrel, a well jumper connector, or other dedicated intervention access point on a subsea system. Control of the subsea well test portion and/or the subsea device is achieved from the deployment vessel via an IWOCS or SWOCS, or alternatively from a subsea production control system. Control of the subsea trees (or alternative structures) may be achieved from the deployment vessel or from a host facility if available.

[0028] This alternate system allows well testing to be performed subsea, thus removing the need to produce the fluid to be tested to the surface and eliminating the requirement for flaring. This application is most relevant for, but not limited to, gas developments and has the potential to eliminate gas flaring during well testing thus significantly contributing to the reduction of emissions generated during this phase of development.

[0029] One configuration of this alternate embodiment is illustrated in FIG. 2. FIG. 2 illustrates a subsea well test fluid reinjection system 48 to provide an alternative embodiment for subsea well test fluid reinjection. As illustrated, the well 21 is coupled via a wellhead 20 to a subsea tree 18. Additionally, a flow diverter crossover 50 is coupled to the subsea tree 18 and a subsea intervention lubricator (STL) 52 is coupled therero to allow for riserless operations A SIL umbilical 54 is in fluid communication with a topside return location (e.g., the offshore vessel 10) and may provide control signals to the SIL. [0030] The flow diverter crossover 50 may transmit the well test fluids to the subsea device 36 via a jumper 56. The subsea device 36 may incorporate a well test device that may perform one or more of the functions of the well test package 22 and may be disposed subsea 40, which removes the need to produce fluid to the offshore vessel 10, thus eliminating flaring. The subsea device 36 is run to the seabed 14 from a deployment vessel (e.g., offshore vessel 10) and the subsea device 36 may be independent on a mudmat or landed onto another subsea structure (e.g., tree, pile, manifold, etc.). The subsea device 36 may incorporate various well testing functionalities as required for the application (e.g., sand knock-out, chemical injection) as a well test device. The well test device is connected to a first subsea well 21 that will undergo testing and a second subsea location that will receive the reservoir fluids produced from the first well 21. This second subsea location may be a subsea well 29 (with or without a subsea tree 30 installed) that uses the choke body 34 as an access point; however, an alternative access point on the subsea tree 30 or an alternative access location upon the subsea infrastructure 28 may be used (e.g., a manifold inlet, or a new subsea structure, such as a storage vessel). Further, a topside return location (e.g., a vessel or rig) may be selected and the well test fluids may be transmitted thereto via the conduit 46. The well test device may be connected directly to one or both subsea structures (e.g., subsea tree 18 and/or subsea tree 30) or connected via jumper 44 and jumper 56. Control of the subsea well test device 36 and/or the well test device is achieved from surface 24 using some form of IWOCS, either a conventional solution using an umbilical or a SWOCS via a remotely operated vehicle (ROV), or alternatively using an existing subsea structure/production control system. The umbilical may additionally control additional elements, such as the subsea tree 18 and/or subsea tree 30. Power may be supplied wirelessly, from the deployment vessel (e.g., offshore vessel 10), from an existing subsea structure/production control system, via integrated batteries, or some renewable or alternative source.

[0031] To perform well testing, the fluid from a first well 21 flows to the well test device of the subsea device 36 (allowing any processing to be performed) before continuing to a second well 29 and/or location where the fluids are returned to the production system (e.g., to the surface 24 via conduit 46). In an alternative embodiment, discussed in greater detail below with respect to FIG. 4, the well test fluids may be returned to the first well 21 instead of to a second well 29 and/or other location of a production system. The subsea well test fluid reinj ection system 48 may operate using only reservoir energy to drive flow (i.e., natural drive) or may include an energy source to add energy to the fluid and facilitate flow (e.g., compressor). On-board functionality (for example, provided by the well test device) may include, but is not limited to, metering, water measurement, gas/contaminant measurement (e.g., carbon dioxide (CO2), hydrogen sulfide (H2S)), pressure/temperature measurement, erosion detection/measurement, sand detection, and fluid sampling.

[0032] Additionally, FIG. 2 shows the first well 21 with a subsea tree 18 installed; however, it may be possible to test fluids from well 21 without a subsea tree 18 (e.g., tubing hanger installed into wellhead 20 or tubing head spool) if well isolation can be achieved. In other embodiments, well fluids from the second well 29 may be tested (with or without subsea tree 30 installed), and then reinjected into the first well 21.

[0033] The illustrated embodiment shows scenarios where the well fluids may be injected into an existing subsea infrastructure 28, which has already been commissioned and is producing to a host facility. Alternatively, the fluids may be injected into a subsea well (e.g., well 29), with or without a subsea tree 30 installed, and bullheaded into a reservoir. [0034] Another embodiment of the alternate system that allows well testing to be performed subsea, thus removing the need to produce the fluid to be tested to the surface and eliminating the requirement for flaring, is illustrated in FIG. 3. FIG. 3 illustrates a subsea well test fluid reinjection system 58 to provide an alternative embodiment for subsea well test fluid reinjection. As illustrated, the well 21 is coupled via a wellhead 20 to a subsea tree 18. Additionally, a well access cap 60 is coupled to the subsea tree 18. As illustrated, well test fluids may be transmitted via the well access cap to the subsea device 36 via the jumper 56.

[0035] The subsea device 36 may incorporate a well test device that may perform one or more of the functions of the well test package 22 and may be disposed subsea 40, which removes the need to produce fluid to the offshore vessel 10, thus eliminating flaring. The subsea device 36 is run to the seabed 14 from a deployment vessel (e.g., offshore vessel 10) and the subsea device 36 may be independent on a mudmat or landed onto another subsea structure (e.g., tree, pile, manifold, etc.). The subsea device 36 may incorporate various well testing functionalities as required for the application (e.g., sand knock-out, chemical injection) as a well test device. The well test device is connected to a first subsea well 21 that will undergo testing and a second subsea location that will receive the reservoir fluids produced from the first well 21. This second subsea location may be a subsea well 29 (with or without a subsea tree 30 installed) that uses the choke body 34 as an access point; however, an alternative access point on the subsea tree 30 or an alternative access location upon the subsea infrastructure 28 may be used (e.g., a manifold inlet, or a new subsea structure, such as a storage vessel). Further, a topside return location (e g , a vessel or rig) may be selected and the well test fluids may be transmitted thereto via the conduit 46. The well test device may be connected directly to one or both subsea structures (e.g., subsea tree 18 and/or subsea tree 30) or connected via jumper 44 and jumper 56. Control of the subsea well test device is achieved from surface 24 using some form of IWOCS, either a conventional solution using an umbilical 59 or a SWOCS via a ROV, or alternatively using an existing subsea structure/production control system. The umbilical 59 may additionally control additional elements, such as the subsea tree 18 and/or subsea tree 30. Power may be supplied wirelessly, from the deployment vessel (e.g., offshore vessel 10), from an existing subsea structure/production control system, via integrated batteries, or some renewable or alternative source.

[0036] To perform well testing, the fluid from a first well 21 flows to the well test device of the subsea device 36 (allowing any processing to be performed) before continuing to a second well 29 and/or location where the fluids are returned to the production system (e g., to the surface 24 via conduit 46). In an alternative embodiment, discussed in greater detail below with respect to FIG. 4, the well test fluids may be returned to the first well 21 instead of to a second well 29 and/or other location of a production system. The subsea well test fluid reinj ection system 48 may operate using only reservoir energy to drive flow (i.e., natural drive) or may include an energy source to add energy to the fluid and facilitate flow (e.g., compressor). On-board functionality (for example, provided by the well test device) may include, but is not limited to, metering, water measurement, gas/contaminant measurement (e.g., carbon dioxide (CO2), hydrogen sulfide (H2S)), pressure/temperature measurement, erosion detection/measurement, sand detection, and fluid sampling.

[0037] Additionally, FIG. 3 shows the first well 21 with a subsea tree 18 installed; however, it may be possible to test fluids from well 21 without a subsea tree 18 (e g., tubing hanger installed into wellhead 20 or tubing head spool) if well isolation can be achieved. In other embodiments, well fluids from the second well 29 may be tested (with or without subsea tree 30 installed), and then reinjected into the first well 21. [0038] The illustrated embodiment shows scenarios where the well fluids may be injected into an existing subsea infrastructure 28, which has already been commissioned and is producing to a host facility. Alternatively, the fluids may be injected into a subsea well (e.g., well 29), with or without a subsea tree 30 installed, and bullheaded into a reservoir.

[0039] As discussed above, in some embodiments, the well test fluids may be returned to the first well 21 instead of to a second well 29 and/or other location of a production system. FIG. 4 illustrates an embodiment of a subsea well test fluid reinjection system 62 that eliminates flaring. The illustrated embodiment shows an embodiment where the well fluids are returned to the first well 21. Returning the well fluids to the first well 21 may include transmitting the well fluids towards the well 21, for example, into different zones of the well 21 or other formations of the well 21. Returning the well fluids to the first well 21 may alternatively and/or additionally include transmitting the fluids to an existing subsea system, for example, via conduit 46. This existing subsea system may be installed in the field and/or may connect or may be a production path to a host facility. A fluid well test spread, or clean up spread, may be installed upon the offshore vessel 10 to provide any necessary functionality; however, this functionality may be reduced versus a comparable spread used for a conventional well test.

[0040] To perform well testing, the reservoir fluids may be flowed from the well 21 to the surface via the fluid conduit (e.g., marine riser 12) with control provided by the well test package 22. Rather than flaring the produced fluids at surface as is conventionally done, the fluids are reinjected to a reservoir or existing subsea infrastructure coupled to the conduit 46, thus eliminating the requirement for flaring. This is achieved via an additional conduit 32, which may be deployed from the offshore vessel 10 and connected to the subsea device 36, for example, temporarily. Likewise, the subsea device 36 is coupled to the subsea tree 18, specifically using a choke body 34 as the access point; however, it may be achieved using an alternative access point on the subsea tree 18, an alternative access location on the subsea infrastructure (e.g., a manifold), or a new subsea structure, such as a storage vessel. Further, a topside return location (e.g., a rig, a vessel, etc.) may be selected. The conduit 32 (e.g., a reinjection conduit) may incorporate flow control devices (e.g., isolation valves, check valves, chokes), which may be located within the conduit 32 or within an independent structure. The construction of the conduit 32 may be conventional drilling tubulars, coiled tubing, flexible hose, thermoplastic hose, composite pipe, or any other suitable conduit. Alternatively, a well access package such as an open-water intervention riser system or subsea intervention lubricator may be used to provide the conduit 32 and means of connection to the subsea infrastructure. Subsea jumpers may also be used to interconnect the conduit 32 and additional structures.

[0041] The system 62 may be operated using only reservoir energy to drive flow (i.e., natural drive) or may include an energy source, either topside or subsea, to add energy to the fluid and facilitate flow (e.g., compressor).

[0042] An IWOCS may also be included to operate the subsea device 36, which may be, for example an intervention system (e.g., skid with isolation valves). The IWOCS may also operate the subsea tree 18 on the tested well 21, if present. A conventional IWOCS using an umbilical or a SWOCS using a subsea HPU and electronic test unit may be used. Alternatively, or in combination with an IWOCS/SWOCS, power and/or communications may be supplied wirelessly, from an existing subsea structure/production control system, integrated batteries, or some renewable or alternative source.

[0043] Various processing functionalities may be incorporated into the topside well test spread as required for the application (e g., sand knock-out, chemical injection). Further, processing functionality or additional data acquisition may be integrated into the subsea package, either the package accessing the well 21 to be tested and/or the package used to return fluids to the subsea infrastructure.

[0044] The subsea well test fluid reinjection system 62 may include conduit 38 coupled to the well test package 22 to receive the well test fluids that would otherwise be flared. This conduit 38 may be part of conduit 32 or coupled to conduit 32 and may be deployed subsea 40 via, for example, downline deployment reeler 42 or a similar device to control the release of the conduit 32 subsea. As illustrated, the conduit 32 is coupled to a subsea device 36, which may include, for example, valves, pressure adjustment equipment, and the like to control and or alter characteristics of the well test fluids. The subsea device 36 may be coupled, for example, via jumper 44 to the subsea tree 18 via choke body 34 as the access point. Alternatively, the choke body 34 or its equivalent may be part of the subsea device 36. The well test fluids may be transmitted from the subsea tree 30 into the well 21 and/or via conduit 46 to existing subsea infrastructure and/or to a production facility or to another subsea device. Further, one or more control lines may be coupled to the subsea device 36 to provide power and/or control signals to the subsea device 36. These may provide electric, hydraulic, and/or another type of control lines, or a combination thereof.

[0045] By returning the well fluids to the first well 21, involvement of a second well 29 may be omitted. Thus, the subsea tree 30 need not be disturbed to include receipt of well test fluids from well 21. Furthermore, situations exist whereby the second well 29 is inconvenient to reach or otherwise inaccessible from the first well 21 or situations where control of both subsea tree 18 and subsea tree 30 are difficult. In these situations, returning the well fluids to the first well 21 may be advantageous. [0046] While the subject disclosure is described through the above embodiments, it will be understood by those of ordinary skill in the art that modification to and variation of the illustrated embodiments may be made without departing from the inventive concepts herein disclosed. Moreover, while some embodiments are described in connection with various illustrative structures, one skilled in the art will recognize that the system may be embodied using a variety of specific structures.