System and method for automating a subsea test unit

Abstract

A system for testing barrier pressure includes a Christmas tree (XT) (202) coupled to a wellbore (206) including a downhole pressure barrier (212). The XT (202) includes a first valve (216) along the flow path (280) and a second valve (226) coupled to the flow path (280). The system also includes a test unit (230) including a vessel (232) fluidly coupled to the flow path (280). The test unit (230) further comprises a fluid mover (234) associated with the vessel (232) for drawing fluid into the vessel (232) or driving fluid out of the vessel (232). The test unit (230) also includes an actuator (236) coupled to the fluid mover (234) for controlling operation of the fluid mover (234). The test unit (2340) is configured to draw a volume of fluid from the XT (202) and also return the volume of fluid to the XT (202).

Description

Background Art

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to and the benefit of U.S. Provisional Patent Application No. 63 / 349,424, filed on June 6, 2022, entitled “SYSTEM AND METHOD FOR ANAUTOMATED SUBSEA TESTING UNIT,” and U.S. Patent Application No. 18 / 205,321, filed on June 2, 2023, entitled “SYSTEM AND METHOD FOR AN AUTOMATED SUBSEA TESTING UNIT,” the entire disclosures of which are incorporated herein by reference in their entirety for all purposes. 1. Technical Field

[0003] The present disclosure relates to wellbore operations. In particular, the present disclosure relates to systems and methods for remotely testing barriers, such as barriers formed in subsea wellbores.

[0004] 2. Related technical description

[0005] In some cases, it may be necessary to test a remotely located barrier, such as a valve associated with a wellbore that may be used for oil and gas recovery, CO2 injection, etc. In one case, the formation pressure may be too low to generate a significant pressure differential between the components for inflow testing. Additionally, there may be limited or no fluid supply as an alternative means of providing sufficient pressure for these tests. As a result, testing may be expensive or challenging, or may result in environmental risks. Summary of the invention

[0006] Applicants recognized the problems noted herein above and conceived and developed embodiments of systems and methods for pressure barrier testing in accordance with the present disclosure.

[0007] In one embodiment, a system for testing barrier pressure includes a Christmas tree (XT) coupled to a wellbore that includes a downhole pressure barrier. The XT includes a first valve along a flow path. The XT also includes a second valve coupled to the flow path. The system also includes a test unit that includes a vessel fluidly coupled to the flow path, wherein the second valve is located between the vessel and the first valve. The test unit also includes a fluid mover associated with the vessel for pumping fluid into the vessel or driving fluid away from the vessel. The test unit also includes an actuator coupled to the fluid mover to control the operation of the fluid mover. The test unit is configured to extract a volume of fluid from the XT in response to a command to perform a pressure test on at least one pressure barrier, and the test unit also returns the volume of fluid to the XT after the pressure test is completed.

[0008] In one embodiment, a method includes determining one or more barriers for pressure testing. The method also includes operating one or more valves to isolate the one or more barriers. The method also includes causing a fluid mover to draw a certain amount of fluid into a vessel. The method includes performing one or more pressure testing operations. The method also includes causing the fluid mover to drive the certain amount of fluid away from the vessel after completing the one or more pressure testing operations.

[0009] In one embodiment, a system for testing barrier pressure includes a well component, the well component including at least a first valve and a second valve arranged along a flow path, the flow path being coupled to a well. The system also includes a downhole pressure barrier positioned in the well. The system also includes a vessel fluidly coupled to the well component. The system also includes a controllable fluid mover associated with the vessel, the controllable fluid mover being configured to reduce pressure within the vessel to draw fluid into the vessel along the flow path, and to increase pressure within the vessel to drive the fluid away from the vessel along the flow path.

[0010] In one embodiment, a system for testing barrier pressure includes a Christmas tree (XT) coupled to a wellbore and a test unit. The wellbore includes a downhole pressure barrier. The XT includes a main valve along a flow path. The XT also includes a wing valve coupled to the flow path, the wing valve fluidly coupled to a fluid source for injecting fluid into the XT. The XT also includes an inlet valve coupled to the flow path. The test unit includes a vessel fluidly coupled to the inlet valve. The test unit also includes a fluid mover associated with the vessel for pumping fluid into the vessel or driving fluid away from the vessel. The test unit also includes an actuator coupled to the fluid mover to control the operation of the fluid mover. The test unit is configured to withdraw a volume of fluid from the XT in response to a command to perform a pressure test on at least one pressure barrier, and the test unit also returns the volume of fluid to the XT after the pressure test is completed.

[0011] In one embodiment, a method includes determining one or more downhole barriers for pressure testing. The method also includes operating one or more valves to isolate the one or more downhole barriers. The method also includes causing a fluid mover to draw a quantity of fluid into a vessel. The method also includes causing the fluid mover to drive the quantity of fluid away from the vessel after completing the pressure test.

[0012] A system for testing barrier pressure includes a fluid system associated with a wellbore and a test unit. The wellbore includes a downhole pressure barrier. The fluid system includes: a first valve along a flow path; a second valve coupled to the flow path, the second valve fluidly coupled to a fluid source for injecting fluid into the fluid system; and a third valve coupled to the flow path. The test unit includes a vessel fluidly coupled to the third valve, a fluid mover associated with the vessel for pumping fluid into the vessel or driving fluid away from the vessel, and an actuator coupled to the fluid mover for controlling the operation of the fluid mover. The test unit is configured to withdraw a volume of fluid from the fluid system in response to a command to perform a pressure test on at least one pressure barrier, and the test unit also returns the volume of fluid to the fluid system after the pressure test is completed. The fluid system may include at least a portion of one or more of a Christmas tree (XT), a manifold, a downhole portion within the wellbore, or a wellhead associated with the wellbore. BRIEF DESCRIPTION OF THE DRAWINGS

[0013] The present technology will be better understood by reading the following detailed description of non-limiting embodiments of the present technology and by viewing the accompanying drawings, in which:

[0014] Figure 1 is a schematic side view of an embodiment of an offshore drilling operation according to an embodiment of the present disclosure;

[0015] Figure 2 is a schematic diagram of an embodiment of a test environment including an embodiment of a Christmas tree (XT) and an embodiment of a test cell according to an embodiment of the present disclosure;

[0016] Figure 3 is a schematic diagram of an embodiment of a test environment including an embodiment of a Christmas tree (XT) and an embodiment of a test cell according to an embodiment of the present disclosure;

[0017] Figure 4 is a schematic diagram of an embodiment of a test environment including an embodiment of a Christmas tree (XT) and an embodiment of a test cell according to an embodiment of the present disclosure;

[0018] Figure 5 is a schematic diagram of an embodiment of a test environment including an embodiment of a Christmas tree (XT) and an embodiment of a test cell according to an embodiment of the present disclosure;

[0019] Figure 6 is a schematic diagram of an embodiment of a test environment including an embodiment of a Christmas tree (XT) and an embodiment of a test cell according to an embodiment of the present disclosure; and

[0020] Figure 7 is a flow chart of an embodiment of a process for conducting a pressure barrier test according to an embodiment of the present disclosure. DETAILED DESCRIPTION

[0021] The aforementioned aspects, features and advantages of the present disclosure will be further understood when considered with reference to the following embodiment descriptions and accompanying drawings. In describing the embodiments of the present disclosure shown in the accompanying drawings, specific terms will be used for clarity. However, the present disclosure is not intended to be limited to the specific terms used, and it should be understood that each specific term includes equivalents that operate in a similar manner to achieve similar purposes.

[0022] When introducing elements of various embodiments of the present disclosure, the articles "one", "an", "the" and "said" are intended to mean that there are one or more elements. The terms "including", "comprising" and "having" are intended to be inclusive and mean that there may be additional elements in addition to the listed elements. Any examples of operating parameters and / or environmental conditions do not exclude other parameters / conditions of the disclosed embodiments. In addition, it should be understood that references to "one embodiment", "embodiment", "certain embodiments" or "other embodiments" of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also include the referenced features. In addition, references to terms such as "above", "below", "upper", "lower", "side", "front", "rear" or other terms regarding orientation or direction are made with reference to the embodiments shown, and are not intended to limit or exclude other orientations or directions. It should also be understood that terms such as approximately or substantially can represent + / -10%.

[0023] Embodiments of the present disclosure relate to systems and methods of automated test units (e.g., automated subsea test units) (ATU / ASTU) for periodic barrier testing of downhole systems, including but not limited to subsea carbon dioxide (CO2) injection systems in carbon capture and storage (CCS) applications and various other applications. Various embodiments enable remote testing in places where inflow testing is challenging due to low reservoir back pressure. Systems and methods can utilize pistons in vessels actuated (e.g., electrically) by rotary electric actuators (REA) and / or rotary to linear motion devices (RLM) to generate a pressure differential in a system (e.g., a wellbore including an XT) by pumping a volume of fluid from a Christmas tree (XT). It should be understood that such a system is provided by way of example, and various other drive mechanisms can be used for the movement of the piston (which can be linear motion in certain embodiments, but is not limited to linear motion), including but not limited to linear hydraulic actuators, linear pneumatic actuators, linear motors, solenoid devices, various mechanical, electrical or pneumatic drive systems, and the like. Thus, the systems and methods may be described in terms of linear motion relative to a piston, but such examples are not intended to limit the scope of the present disclosure, as other drive systems may also be incorporated to move the piston and / or some other device to increase and / or decrease volume. The systems and methods may then be used to return the fluid upon completion of the test, and thus, there may be no need to recover or manage the volume of the fluid. Furthermore, the marine device prevents the need to discharge the process fluid into the ocean, thereby providing a positive environmental advantage.

[0024] Embodiments of the present disclosure may relate to an ASTU for periodic remote testing of barriers in subsea CO2 injection systems for CCS and various other applications. Embodiments may also be used with direct and / or otherwise planned tests, such as using one or more subsea robots, etc. to initiate the test. The ASTU enables testing by pumping a predetermined volume of fluid from the XT and / or well to generate the pressure differential required to test various valves and / or barriers associated with the well, such as valves on the XT (e.g., XT main valve, XT wing valve, etc.) and / or downhole safety valves. Due to the limited reservoir back pressure of the wellbore, such testing is impossible in various applications without inflow testing. In at least one embodiment, the ASTU at least partially includes a vessel having a movable piston (e.g., linear motion along the axis of the vessel), which is electrically actuated by an RLM connected to a subsea control system, so that remote operation can be achieved. The piston can be moved within the vessel to extract fluid from the XT. It should be understood that the flow line can connect the vessel to the XT, such as via a hot plug to a dedicated discharge line, via a direct connection between the XT and the vessel, and / or the like. The introduction of the ASTU avoids the environmentally undesirable discharge of fluid volumes to the ocean (or to the surrounding environment in non-subsea applications), and allows the fluid to be returned after the test is completed, for example by reversing the movement of the piston. Thus, the configuration of the disclosed embodiments also prevents the need for recycling the unit for periodic emptying, further simplifying operations and reducing costs to the operator.

[0025] Embodiments of the present disclosure provide significant cost savings to operators of these CO2 injection systems in terms of capital expenditures (CAPEX) and operating expenditures (OPEX). For example, various embodiments may eliminate the need for dedicated service lines or fluid lines in umbilicals used to support valve testing operations, since fluids are also typically not required for chemical injection in these applications. In addition, for all electrical systems, embodiments also support efforts to replace expensive umbilicals with simple power and communication cables to further save costs. In terms of OPEX, embodiments may reduce or eliminate the need for support vessels that are frequently moved to support valve testing operations, which would otherwise be required to supply fluids or manage discharge volumes.

[0026] Various embodiments of the present disclosure combine the ASTU in the seabed environment. It should be understood that the ASTU can also be deployed in the surface environment, such as in a remote location, and in this case can be referred to as an ATU, or can also be referred to as an ASTU, it should be understood that unless otherwise specifically stated, the use of the term "seabed" does not limit the embodiment to this application. The ASTU may include one or more components, which can be arranged into a collection or system with different configurations, which can include more or less components, and various support systems can also be included in various embodiments. In at least one embodiment, the ASTU includes a container or ship with a piston therein, which is electrically actuated by the RLM connected to the seabed control system, so that it can be remotely operated. The piston moves upward in the ship to extract the fluid from the XT to which it is connected, such as by a hot plug to a dedicated discharge line or via a direct connection to one or more inlet ports, and other options. The rod of the piston can be threaded into the RLM, and the RLM is used to convert the rotary motion of the REA into the linear motion of the piston. Various embodiments can also utilize a REA motor position sensor for calibration points (e.g., opening and closing on the piston), which can provide a calibrated piston pressure based on the position. Thus, the operator will be able to remotely withdraw a required (eg, determined) amount of fluid from the closed system to generate the pressure differential necessary to perform the test, which may vary depending on the volume involved in the valve being tested, and the shut-in pressure that will increase over time.

[0027] Embodiments enable fluids that have been extracted from the system to be returned without the need to periodically drain or recover the unit to the surface with a support vessel, which can minimize or reduce operating costs. Various embodiments can be mounted on the XT, but it should be understood that if access to the discharge or annulus line is required, the clip connected to the discharge line can be removed and wet parked. In addition, in a removable configuration where access is required through one or more ports associated with the vessel, the vessel or other components can be "hard piped" to the XT. In at least one embodiment, such a configuration can be used in embodiments where the vessel is maintained in a pressurized state (e.g., pressurized above a defined threshold) to account for temperature changes, etc.

[0028] Embodiments of the present disclosure address and overcome one or more problems of existing systems and operations associated with remote and / or subsea barrier testing. Testing of subsea XT valves or downhole safety valves in CO2 injection systems for CCS applications is problematic and challenging for a number of reasons. First, the formation pressure is relatively low, or the back pressure from the reservoir is insufficient to perform inflow testing of these barriers, or insufficient to produce a significant and sufficient pressure differential for a good test. In fact, for valves that are sealed in one direction (e.g., downhole safety valves with a baffle mechanism), specification requirements specify that the valve should be tested in the flow direction (i.e., with high pressure on the reservoir side). One way to overcome this shortcoming is to discharge fluid from the volume in the well above the XT and safety valve to produce the pressure differential necessary to test these barriers. However, this is undesirable because the discharge is often to the surrounding environment. A second problem is that there is typically no fluid supply to the subsea CO2 injection system, which could otherwise support valve testing operations. Subsea CO2 injection systems are suitable for power systems due to the long step-outs typically involved, and typically do not require chemical injection to support operations (e.g., for hydrate inhibition). Therefore, by eliminating any fluid lines in the umbilical (which can be replaced by simple power and communication cables), there is a great opportunity for cost savings for the operators of these sites, since no fluid is required for hydraulic supply or chemical injection. Therefore, the testing of barrier valves and safety valves, which is required periodically throughout the life of the site, may be either challenging due to the low back pressure from the reservoir, or incur large operating costs due to the need to mobilize support vessels to inject fluids for valve testing operations or manage the volume of discharged fluids. The frequency of testing may be high, especially in the early stages of life, with a large number of wells (these developments have these in terms of initial stages and expansion potential). Therefore, the operating costs of regularly deploying support vessels may be significant, especially in remote areas or areas with little or no support for offshore infrastructure and industry. In addition, from an environmental point of view, the purpose of these projects is to prevent CO2 from being released into the atmosphere from emission sources, so it is necessary to have a low carbon footprint. Frequent use of support vessels will adversely increase the carbon footprint of the project itself, thus weakening its value and the objectives. Finally, from an environmental or social point of view, it is undesirable to discharge small or large amounts of CO2 from wells or XTs to the ocean. Embodiments of the present disclosure address these and other shortcomings of the prior art in the industry.

[0029] Embodiments provide a low-cost solution that enables periodic remote testing of barriers in subsea CO2 injection wells and other applications, overcoming the problem of low return pressure and other problems without requiring support vessels or discharging volumes of CO2 and / or process fluids into the ocean, which is undesirable from an environmental or social point of view. Thus, the systems and methods may be used in a variety of different applications and are not limited to CCS (where low back pressure from the reservoir may exist) and / or remote applications (where it may be desirable to reduce the cost or equipment for intervention and testing).

[0030] Various embodiments of the present disclosure may be related to the operation of one or more XTs. It should be understood that such disclosure is merely exemplary and is not intended to limit the scope of the present disclosure. For example, various embodiments may be associated with manifolds, wellheads, wellbore components, or various other fluid systems. That is, the scope of the present disclosure can be extended to various systems associated with forming one or more pressure boundaries, and the pressure boundary includes a volume that can hold fluids and / or pressures. For example, a manifold may be associated with a wellhead, wherein the manifold includes a pipe with a certain volume that can be extracted from the manifold to generate the pressure difference described herein. In addition, in various embodiments, at least a portion of the wellhead may have a volume that can be used to generate a pressure difference. In addition, in at least one embodiment, a portion of the wellbore itself, such as a portion downhole relative to the surface position, may include a volume by which a pressure difference can be formed. In addition, different XT configurations may be used, such as different configurations for vertical or horizontal XTs. In addition, these different XTs may be specifically selected and specialized for a given application, but as an example, one or more common pipelines or valve configurations may be included, such as a minimum number of barriers between the well and the outlet. Therefore, although the embodiments may be related to XTs with specific configurations, it should be understood that this is only a non-limiting example.

[0031] Figure 11 is a schematic diagram of an embodiment of a subsea operation 100. It should be understood that one or more features have been removed from this discussion for clarity, and the removal or inclusion of particular features is not intended to be limiting, but is provided by way of example only. In addition, while the illustrated embodiments describe a subsea drilling operation, it should be understood that one or more similar processes may be used for subsea well interventions for surface applications, and in various embodiments, similar arrangements or substantially similar arrangements described herein may also be used in surface applications. In addition, the drilling operation is shown only as an example of an offshore well, and it should be understood that embodiments may be directed to situations after the well has been drilled and may be in operation and / or after the end of life when the well has been converted to an alternative application such as CO2 injection. The drilling operation includes a vessel 102 floating on the sea surface 104 substantially above a wellbore 106. A wellbore housing 108 is located at the top of the wellbore 106 and is connected to a blowout preventer (BOP) assembly 110, which may include a shear ram 112, a sealing ram 114, and / or an annular ram 116. One purpose of the BOP assembly 110 is to help control the pressure in the wellbore 106. The BOP assembly 110 is connected to the vessel 102 by a riser 118. During drilling operations, a drill string 120 is passed from a drilling rig 122 on the vessel 102 through the riser 118, through the BOP assembly 110, through the wellhead housing 108 and into the wellbore 106. It should be understood that reference to the vessel 102 is for illustrative purposes only, and the vessel may be replaced with a floating platform or other structure. The lower end of the drill string 120 is attached to a drill bit 124, which extends the wellbore 106 as the drill string 120 rotates. Figure 1 Additional features shown include a mud pump 126 with a mud line 128 connecting the mud pump 126 to the BOP assembly 110, and a mud return line 130 connecting the mud pump 126 to the vessel 102. A remotely operated vehicle (ROV) 132 can be used to make adjustments, repairs, or replacements to the equipment as needed. Although a BOP assembly 110 is shown in the drawings, the wellhead housing 104 can also be attached to other well equipment, including, for example, a subsea Christmas tree (XT), a spool, a manifold, or another valve or completion assembly.

[0032] One effective way to begin drilling the wellbore 106 is by using suction piles 134. Such a procedure is accomplished by attaching the wellhead housing 108 to the top of the suction piles 134 and lowering the suction piles 134 to the seafloor 136. When the interior chamber in the suction piles 134 is evacuated, the suction piles 134 are driven into the seafloor 136, as shown in FIG. Figure 1As shown, until the suction pile 134 is substantially submerged in the seafloor 136 and the wellhead housing 108 is positioned at the seafloor 136 so that further drilling can begin. As the wellbore 106 is drilled, the walls of the wellbore are reinforced with a concrete casing 138, which provides stability to the wellbore 106 and helps control pressure from the formation. It should be understood that this describes one example of a portion of a seafloor drilling operation and may be omitted in various embodiments. In at least one embodiment, the systems and methods of the present disclosure may be used for drilling operations accomplished through a BOP and a wellhead, with casing hangers and strings being dropped continuously.

[0033] Embodiments of the present disclosure relate to an automated subsea test unit (ASTU) (eg, subsea test unit, automated test unit, test unit, etc.) that may be used in one or more environments, such as a subsea environment or a remote environment. Figure 2 2 is a schematic diagram of an embodiment of a subsea environment 200 in which the present disclosure may be used. In this example, the subsea environment 200 includes a Christmas tree (XT) 202, which is connected to a wellhead 204 or / and wellhead components, such as a pipe hanger, of a wellbore 206 extending into the formation. As described above, the XT 202 is provided by way of non-limiting example only, and in various other embodiments may be replaced with one or more additional fluid systems, which may include valves, pipes, instructions, etc. sufficient to generate a volume from which fluid is extracted and / or a pressure to generate a differential pressure. In addition, the illustration of a vertical XT (VXT) is also provided as an example and is not intended to limit the scope of the present disclosure, as the systems and methods may also be adapted for horizontal XTs and various other piping configurations. In one or more embodiments, the XT 202 may be replaced with a manifold, a portion of the wellhead 204, various piping configurations, a portion of the wellbore 206, etc. The wellbore 206 includes a pipe 208 (e.g., casing, production pipe, injection pipe, etc.) and an annulus 210 formed around the pipe 208 defined by the wellbore wall. In this example, a downhole safety valve (DHSV) 212 is arranged along the tubular 208, but it should be understood that the DHSV 212 can be associated with the wellbore itself and can be positioned to effectively seal the wellbore, including both the tubular 208 and the annulus 210. In addition, in this example, a separate annulus isolation device (AID) 214 is also shown. As will be understood, various isolation devices may be used in accordance with various codes and regulations, such as those that provide at least two pressure barriers between the formation and the access point.

[0034] It should be understood that the arrangement of XT 202 (including the location or number of valves, flow paths, etc.) is provided by way of example only, and embodiments of the present disclosure may be used with trees having several different configurations. In addition, various types of valves, pipes, fittings, etc. may be combined within the scope of the present disclosure. For example, different valve types may be used, such as ball valves, gate valves, needle valves, stop valves, and / or the like. In addition, it should be understood that XT 202 may be a specially selected XT 202 for use with CO2 injection, or may be a standard tree that has been modified or otherwise adapted for CO2 injection, as well as other options. In this configuration, the main valve 216 (MV or IMV) is arranged along the flow path 280 of XT 202 (e.g., along the path coupled to tube 208). Although a single main valve 216 is shown, other embodiments may include an upper main valve and a lower main valve or a main valve and a pumping valve, as well as other configurations and options. The flow path continues along the tree cap 218 and the wing valve (WV or IWV) 220, which can be connected to the production vessel 222 to receive fluid produced from the formation. In various embodiments, the flow path 280 may include one or more branches and / or portions. For example, a first portion of the flow path 280 may extend between the wellbore 206 and the main valve 216, and a second portion may extend from the main valve 216 to the wing valve 220. In addition, as described herein, for simplicity, the embodiments relate to a specific XT configuration, but it should be understood that in various embodiments, one or more portions may be modified, such as to allow CO2 to be injected into the wellbore 206. For example, in at least one embodiment, the production vessel 222 may be replaced by a source that directs flow into the wellbore 206. As described above, different configurations may include more or fewer valves, which may have different flow paths or alternative routes, and the examples provided herein are for illustrative purposes only and are not intended to limit the scope of the present disclosure.

[0035] The illustrated XT 202 also includes an annulus flow path 282 associated with the AID 214 coupled to the annulus 210. Similar to the flow path 280, the annulus flow path 282 may include one or more branches and may further combine with the flow path 280 such that the combination of the annulus flow path 282 and the flow path 280 forms a flow path. Along the flow path 282 is an annulus master valve (AMV) 224, which, as described above, may include additional valves in addition to the single valve shown in the example. The annulus flow path 282 continues to an annulus access valve (AAV) 226, which may also be referred to as a drain line and / or port. A connecting flow path 284, which may also be considered to be at least a portion of one or more of the flow path 280 and the annulus flow path 282, is shown, which couples the annulus flow path 282 to the flow path 280 via a crossover valve (XOV) 228. Thus, flow between the annulus flow path 282 and the production flow path 280 may be provided via opening of the XOV 228, thereby forming a common flow path, which may be collectively referred to as flow path 280, it being understood that different portions or branches of flow path 280 may be fluidly coupled together after one or more valves are opened and / or closed.

[0036] Embodiments of the present disclosure relate to an ASTU 230, which in this example is coupled to an annulus flow path 282, and thus may be further connected to the flow path 280 via a hot plug at a discharge port on the downstream (relative to the outflow direction of the XT 200) side of the AAV 226. It should be understood that the location of the ASTU 230 is provided only as a non-limiting example to aid in this discussion. It should be understood that the ASTU 230 may be coupled to a variety of different locations along the XT 202 to allow for testing of various pressure barriers. Additionally, the use of the hot plug is also provided as a non-limiting example, and different coupling mechanisms may be utilized, for example, the ASTU 230 may be a portion of a spool formed within the XT 202 and / or may be integrally formed within the XT 202, as well as other options. As another example, one or more components of the ASTU 230 may be mounted to the XT 202 and may be hard-piped or otherwise rigidly connected to one or more ports or drains, wherein further embodiments may allow for removal of the ASTU 230 or components thereof in response to a need for access via the one or more ports or drains.

[0037] The ASTU 230 shown includes a vessel 232, a fluid mover 234, and an actuator 236 (which is an RLM in this example, but such an actuator is provided by way of example only and does not limit the different types of actuators that can be used to drive movement of the fluid mover 234) that can be used to drive the fluid mover 234. In addition, a flow line 238 hot-swaps to the XT 202, wherein the flow line 238 allows flow into and out of the vessel 232. As described herein, embodiments may eliminate the flow line 238 and / or the flow line may be replaced with a hard pipe connection or connection between the vessel 232 and the XT, such as at the outlet of one or more valves or along the annulus flow path 282 and / or the connecting flow path 284. In this example, the fluid mover 234 is a piston positioned within the vessel 232. The piston can be driven to move linearly along the vessel axis so that in a first direction (e.g., based on the vessel axis), the flow line 238 is moved linearly. Figure 2 The configuration of the vessel 232 is configured to move in a downward direction toward the opening of the vessel 232) to reduce the vessel volume and in a second direction (e.g., based on Figure 2 The movement of the piston 232 in an upward direction away from the opening of the vessel 232 increases the vessel volume. The movement can be driven by an actuator 236, which in this example comprises a rotary electric actuator (REA) coupled to a rotary to linear motion machine (RLM). As described above, such a system can be an electric system that does not require the use of additional support equipment, such as hydraulic fluid, to drive the movement of the piston. It should be understood that Figure 2 The embodiments are shown by way of example only, and different actuators 236 and fluid movers 234 may be used, such as linear actuators, hydraulic actuators, electric motors, solenoid devices, pumps, etc. In addition, one or more ROVs may be used to actuate the fluid movers 234.

[0038] Various embodiments of the present disclosure may include one or more combinations of fluid movers 234 and / or actuators 236 for driving fluids (e.g., gases, liquids, solids, or combinations thereof) into and / or out of the vessel 232. In at least one embodiment, the fluid mover 234 may be used to increase or decrease the pressure within the vessel 232, such as the embodiments described herein, where a piston may increase or decrease the volume within a tank. Additionally, various embodiments may not include a fluid mover 234 within the vessel 232. For example, the fluid mover 234 may be an electric pump that is used to drive fluid into the vessel 232 and / or drive fluid out of the vessel 232.

[0039] As will be described below, in operation, the ASTU 230 can be used to remove a certain volume of fluid from the XT 202 and / or the wellbore 206 in order to generate a pressure differential for the barrier test. For example, the piston movement in the first direction draws the fluid into the vessel 232, and the piston movement in the second direction can drive the fluid out of the vessel 232 and back into the XT 202 and / or the wellbore 206. Therefore, a pressure differential can be generated in the direction of the fluid flow, which can be useful for testing the DHSV 212 when the formation pressure is insufficient. In addition, various embodiments also provide a method that uses the fluid already in the XT 202 and / or the wellbore 206 to generate a pressure differential, and then returns the fluid after the test, thereby reducing the need for support equipment (such as a vessel) to come and periodically empty the vessel 232. For example, the vessel 232 can be empty or substantially empty so that it is ready to receive a volume of fluid. It should be understood that the volume of the vessel 232 can be specifically selected based at least in part on the expected volume of fluid to be received. For example, the vessel size may be based on the volume within the XT 202 and / or wellbore 206 and also based on the expected operating conditions in order to determine the amount of fluid to be pumped into the vessel 232 to create a desired pressure differential. In addition, various embodiments may also maintain a fluid volume within the vessel 232 to pressurize the vessel 232 to account for various temperature changes, etc.

[0040] The rod of the piston may be threaded into the RLM, and the RLM may be used to convert the rotational motion of the REA into linear motion of the piston. Utilizing a REA motor position sensor for calibration points (e.g., opening and closing on the piston) may be used to obtain a calibrated piston pressure based on position, which may enable an operator to draw the correct amount of fluid based on the barrier being tested (e.g., XT valve or DHSV 212). In at least one embodiment, a controller 240 (which may be part of a subsea controller that may be integrated into or separate from the XT 202) may receive one or more signals, such as from various gauges (such as a pressure transducer 242), to determine differential pressures within the XT 202 and / or other locations, and based on this information may control the position of a fluid mover 234 within the vessel 232.

[0041] As noted, various embodiments may also include additional piping configurations, valves, sensors, etc. For example, in this example, a choke 244 (CV or ICV) and a flow valve 246 (FV or FIV) are disposed downstream of the WV 220 (in embodiments where flow exits the wellbore 206). Additionally, in the illustrated embodiment, an annulus wing valve (AWV) 248 is disposed between the AMV 224 and the AAV 226. Additional valves such as swabbing valves (SV, ASV, ISV) 250, 252 may also be used in various embodiments.

[0042] Various embodiments may be used for pressure testing of one or more barriers associated with environment 200 (such as the various valves of XT 202) and / or barriers associated with wellbore 206 (such as IMV 216). Figure 3 is a schematic diagram of an embodiment of an XT valve testing environment 300 in which features of the present disclosure may be used. In this example, an XT valve is tested using the ASTU 230. It should be understood that the various references to specific valves and their positions (e.g., open or closed) are examples using the XT configuration shown, and in other embodiments, different configurations may be utilized within the scope of the present disclosure.

[0043] In this example, a test procedure may be utilized in which the FIV 246 is in a closed position, thereby isolating the wellbore 206. In at least one embodiment, this step may be referred to as shutting in or isolating the well, and may include closing one or more additional valves that may provide fluid communication with the well. The illustrated embodiment also shows the MV 216 in a closed position. Thus, the pressure below the MV 216 will be the shut-in pressure, which is determined by reservoir conditions. Also shown in this example is the AMV 224 in a closed position, which further shuts in the well relative to the reservoir.

[0044] The illustrated embodiment may then include steps such as opening the XOV 228 and AAV 226, thereby providing fluid access to the vessel 232. For example, fluid may flow through the flow path 280, the annulus flow path 282, and / or the connecting flow path 284, which as described above may be generally referred to as the use flow path 280 or a portion thereof. The actuator 236 may then be used to drive the fluid mover 234 in a second direction to increase the volume of the vessel 232, thereby drawing fluid into the vessel 232 and out of the XT 202. The fluid may be drawn from the cavity of the XT 202, and in various embodiments may be calculated or determined by the controller to provide a desired pressure differential across one or more valves. In this configuration, after the fluid mover 234 is moved to increase the volume of the vessel, a pressure differential exists across the MV 216 and the WV 220, depending on the test requirements. This pressure may be maintained for any period of time depending on the test requirements. For example, the XOV 228 may be closed and the pressure in the XT chamber may be monitored to verify both the MV 216 and the WV 220 simultaneously. After the test is completed, the various valves and components may be operated to push the fluid out of the vessel 232 and back into the XT 202. For example, the XOV 228 may be opened, the actuator 236 may drive the fluid mover 234 in one direction to reduce the volume of the vessel 232, and the fluid may then flow through the AAV 226 and through the XOV 228 back into the XT 202, such as along the connecting flow path 284 and / or the flow path 280. In this manner, the test may be completed without discharging the fluid into the environment and without retaining the fluid within the vessel 232 (or without retaining more than a threshold amount of fluid within the vessel 232), which may be emptied or substantially emptied to return the fluid to the XT chamber, thereby reducing the need for a support vessel to arrive on-site to periodically empty the vessel 232.

[0045] Various embodiments may be used for pressure testing of one or more barriers associated with environment 200 (such as the various valves of XT 202) and / or barriers associated with wellbore 206 (such as DHSV 212). Figure 4 is a schematic diagram of an embodiment of a DHSV testing environment 400 in which features of the present disclosure may be used. In this example, the DHSV 212 is tested using the ASTU 230. It should be understood that the various references to specific valves and their positions (e.g., open or closed) are examples using the XT configuration shown, and in other embodiments, different configurations may be utilized within the scope of the present disclosure.

[0046] In this example, the testing process may shut down or isolate the well and may include closing one or more additional valves that may provide fluid communication with the well. For example, the well may be shut down with IWV 220. In the illustrated embodiment, DHSV 212 is moved to a closed position where the pressure below the valve will be the shut-in pressure determined by reservoir conditions. XOV 228 and AAV 226 may then both be opened to provide a fluid path to vessel 232. As described above, a fluid path may refer to flow path 280, flow path 282, flow path 284, and / or combinations thereof. It should be understood that when used with Figure 3 When compared, the MV 216 Figure 4 202. In this configuration, the actuator 236 can be used to drive the movement of the fluid mover 234 to increase the volume of the vessel 232, thereby drawing pressure from the XT 202, which creates a pressure differential across the DHSV 212. Advantageously, the pressure differential is considered to be on the reservoir side (e.g., in the direction of flow), and therefore meets various testing standards. Thereafter, the XOV 228 and / or AAV 226 can be closed, and the pressure can be monitored, such as at the pressure transducer 242, as well as other options, to verify the DHSV 212. Upon completion of the test, the actuator 236 can drive the movement of the fluid mover 234 to reduce the volume of the vessel 232 and return the fluid to the XT 202. In this way, testing can be accomplished without discharging fluid into the environment and without retaining fluid within the vessel 232 (or retaining less than a threshold amount), the vessel can be emptied or substantially emptied to return the fluid to the XT chamber, thereby reducing the need for a support vessel to arrive on site to periodically empty the vessel 232.

[0047] Various embodiments may be used for pressure testing of one or more barriers associated with environment 200 (such as the various valves of XT 202) and / or barriers associated with wellbore 206 (such as IWV 220). Figure 5 is a schematic diagram of an embodiment of a DHSV test environment 500 in which features of the present disclosure may be used. In this example, the IWV 220 is tested using the ASTU 230. It should be understood that the various references to specific valves and their positions (e.g., open or closed) are examples using the XT configuration shown, and in other embodiments, different configurations may be utilized within the scope of the present disclosure.

[0048] In this example, a test procedure may be utilized in which the well is shut in, such as by closing the FIV 246. In the illustrated embodiment, the DHSV 212 is illustrated in an open position. Then, both the XOV 228 and the AAV 226 may be opened along with the IMV 216, thereby providing a fluid path to the vessel 232. In this configuration, the actuator 236 may be used to drive the movement of the fluid mover 234 to increase the volume of the vessel 232, thereby drawing pressure from the XT 202, which creates a pressure differential across the IWV 220. Thereafter, the XOV 228 and / or the AAV 226 may be closed, and the pressure may be monitored, such as at the pressure transducer 240, as well as other options, to verify the DHSV 212. Upon completion of the test, the actuator 236 may drive the movement of the fluid mover 234 to reduce the volume of the vessel 232 and return the fluid to the XT 202. In this way, testing can be accomplished without discharging fluid into the environment and without retaining fluid within the vessel 232 (or retaining less than a threshold amount), the vessel can be emptied or substantially emptied to return the fluid to the XT chamber, thereby reducing the need for a support vessel to arrive on site to periodically empty the vessel 232.

[0049] Various embodiments of the present disclosure may also provide one or more configurations to allow utilization of the ASTU 230. In at least one embodiment, one or more components of the ASTU 230 may be coupled directly to the XT, for example at a port or drain. Figure 6 is a schematic diagram of an embodiment of a test environment 600 in which features of the present disclosure may be used. As described herein, various embodiments of the present disclosure may provide alternative methods or systems for coupling a vessel 232 to an XT 202, for example, via one or more ports or drains. While certain embodiments may include hot-swap connections extending into one or more portions of a flow path 280, a connecting flow path 284, and / or an annulus flow path 282, systems and methods may also hard-pipe or directly connect the vessel 232 to one or more ports or drains of the XT. Figure 6 In the example of , direct connection of the vessel 232 may enable the omission or removal of one or more components, such as the AAV 226. In addition, various systems or methods may also enable removal of the vessel 232 and / or access to the drain or port through the vessel 232 in the event that certain access operations are required or desired. For example, the vessel 232 may include one or more openings to facilitate the insertion of hot-swap or other flow lines that may be coupled to the flow paths 282, 282, 284.

[0050] Figure 7700 is a flow chart of an embodiment of a process for performing a barrier test. It should be understood that this process and other processes discussed herein may include more or fewer steps. In addition, unless otherwise specifically stated, the steps may be performed in another order or in parallel. In this example, one or more barriers are determined for testing 702. For example, different barriers (e.g., valves) may have different test requirements or different configurations for testing. Therefore, the determination of which barriers to test can be used to isolate or otherwise prepare for the test. One or more valves can be operated to isolate the desired barrier 704. For example, one or more actuators can be used to move the valve between an open or closed position, wherein the one or more actuators can be remotely controllable. Therefore, different configurations can prevent or allow fluid flow along various flow paths.

[0051] In at least one embodiment, a fluid mover can draw a certain amount of fluid into the vessel 706. The amount of fluid can come from the volume or space within the XT, as well as other options, and can be used to create a pressure differential across one or more barriers being tested. In at least one embodiment, an actuator can be used to drive the fluid mover within the vessel so that the volume of the vessel increases, thereby allowing fluid to enter the vessel. In various embodiments, the amount of fluid is determined based at least in part on the desired pressure differential. It should be understood that the volume can be a factor of various components that can change over the life of the formation. For example, in a CO2 injection well, as more CO2 is injected, the formation pressure can increase over time. Therefore, the volume used in the early stage can be changed compared to the volume in the late stage. Various embodiments may include a controller for adjusting the position of a fluid mover (such as a piston) based on pressure information monitored within the XT. For example, the volume can be increased to produce a larger pressure differential based on the pressure reading. In this way, the volume can be dynamically changed to also change the pressure differential.

[0052] Pressure testing may be performed on the one or more downhole barriers 708. This may include opening or closing various additional valves and also include holding pressure for a period of time, among other options. Upon completion, the fluid mover may drive the fluid out of the vessel and back into the XT 710. For example, the fluid mover may move in the opposite direction from before to return the fluid to the XT, thereby reducing or eliminating the need for support equipment to drain the vessel and / or eliminating discharges to the surrounding environment. In this way, the test may be performed remotely using an automated system that may incorporate one or more electrical components that reduce the use of expensive support equipment (such as additional hydraulic systems) and also maintain the containment of the various fluids utilized by the wellbore.

[0053] The embodiments may also be described in terms of:

[0054] 1. A system for testing barrier pressure, the system comprising:

[0055] A Christmas tree (XT) coupled to a wellbore, the wellbore including a downhole pressure barrier, the XT comprising:

[0056] a first valve along the flow path; and

[0057] a second valve coupled to the flow path;

[0058] A test unit, the test unit comprising:

[0059] a vessel fluidly coupled to the flow path, wherein the second valve is located between the vessel and the first valve;

[0060] a fluid mover associated with the vessel for drawing fluid into the vessel or driving fluid away from the vessel; and

[0061] an actuator coupled to the fluid mover for controlling operation of the fluid mover;

[0062] Wherein the test unit is configured to withdraw a volume of fluid from the XT in response to a command to perform a pressure test on the at least one pressure barrier, the test unit also returning the volume of fluid to the XT after the pressure test is completed.

[0063] 2. The system of clause 1, wherein the fluid mover is a piston disposed within the vessel.

[0064] 3. A system according to clause 2, wherein the actuator is an electrically driven rotary to linear motion device.

[0065] 4. The system of clause 1, wherein the pressure test is performed on at least one of the first valve or the downhole pressure barrier.

[0066] 5. The system according to clause 1, further comprising:

[0067] A third valve is coupled to the flow path, the third valve being fluidly coupled to a fluid source for injecting a second fluid into the XT.

[0068] 6. A system according to clause 5, wherein the fluid source is a carbon dioxide source.

[0069] 7. The system according to clause 1, further comprising:

[0070] A fourth valve is located in the connecting flow path between the first valve and the second valve.

[0071] 8. The system of clause 1, wherein the test unit is fluidically coupled to the XT via a thermal snap.

[0072] 9. The system of clause 1 wherein the test unit is directly coupled to the XT at one or more of a drain or port.

[0073] 10. The system of clause 1, wherein the actuator is configured to be controlled by a subsea control system and the XT is a subsea XT.

[0074] 11. A method comprising:

[0075] Identify one or more barriers for stress testing;

[0076] operating one or more valves to isolate the one or more barriers;

[0077] causing the fluid mover to pump a certain amount of fluid into the vessel;

[0078] performing one or more stress testing operations; and

[0079] After completing the one or more pressure testing operations, the fluid mover is caused to drive the quantity of fluid away from the vessel.

[0080] 12. The method according to clause 11, wherein the amount of fluid is taken from a Christmas tree (XT)

[0081] Removed.

[0082] 13. The method according to clause 12, further comprising:

[0083] The amount of the fluid is determined based at least in part on a pressure differential associated with the one or more barriers.

[0084] 14. The method of clause 12, wherein the quantity of fluid is returned to the XT after completion of the pressure test.

[0085] 15. The method of clause 11, wherein the one or more barriers comprise at least one of a main valve or a downhole safety valve.

[0086] 16. The method of clause 11, wherein the pressure testing occurs in a subsea environment.

[0087] 17. A system for testing barrier pressure, the system comprising:

[0088] a well component including at least a first valve and a second valve arranged along a flow path, the flow path being coupled to the well;

[0089] a downhole pressure barrier positioned in the well;

[0090] a vessel fluidly coupled to the well component; and

[0091] A controllable fluid mover is associated with the vessel, the controllable fluid mover being configured to reduce pressure within the vessel to draw fluid into the vessel along the flow path, and to increase pressure within the vessel to drive the fluid away from the vessel along the flow path.

[0092] 18. The system of clause 17, wherein the well component is one or more of a Christmas tree (XT), a manifold, a wellhead, or a combination thereof.

[0093] 19. The system according to clause 17, further comprising:

[0094] A third valve is disposed along the flow path, the third valve being positioned to regulate an inlet flow from a fluid source into the flow path.

[0095] 20. The system of clause 17, wherein the fluid is a gas, a liquid, a solid, or a combination thereof.

[0096] The above disclosure and description of the disclosed embodiments are exemplary and illustrative of the embodiments of the present disclosure. Various changes may be made to the details of the illustrated embodiments within the scope of the appended claims without departing from the true spirit of the present disclosure. The embodiments of the present disclosure should be limited only by the following claims and their legal equivalents.

Claims

1. A system for testing barrier pressure, the system comprising: A Christmas tree (XT) (202) coupled to a wellbore (206), the wellbore (206) including a downhole pressure barrier (212), the XT (202) comprising: a first valve (216) along the flow path (280); and a second valve (226) coupled to the flow path (280); A testing unit (230), the testing unit comprising: a vessel (232) fluidly coupled to the flow path (280), wherein the second valve (226) is located between the vessel (232) and the first valve (216); a fluid mover (234) associated with the vessel (232) for pumping fluid into the vessel (232) or driving fluid away from the vessel (232); and an actuator (236) coupled to the fluid mover (234) for controlling operation of the fluid mover (234); The test unit (230) is configured to withdraw a volume of fluid from the XT (202) in response to a command to perform a pressure test on at least one pressure barrier (212, 216), and the test unit also returns the volume of fluid to the XT (202) after the pressure test is completed.

2. The system of claim 1, wherein the fluid mover (234) is a piston disposed within the vessel (232).

3. The system of claim 2, wherein the actuator (236) is an electrically driven rotary to linear motion device.

4. The system of claim 1, wherein the pressure test is performed on at least one of the first valve (216) or the downhole pressure barrier (212).

5. The system according to claim 1, further comprising: A third valve (220) is coupled to the flow path (280), the third valve (220) being fluidly coupled to a fluid source (222) for injecting a second fluid into the XT (202).

6. The system of claim 5, wherein the fluid source (222) is a carbon dioxide source.

7. The system according to claim 1, further comprising: A fourth valve (228) is located in the connecting flow path (284) between the first valve (216) and the second valve (226).

8. The system of claim 1, wherein the test unit (230) is fluidly coupled to the XT (202) via a thermal snap.

9. The system of claim 1, wherein the test unit (230) is directly coupled to the XT (202) at one or more of a drain or port.

10. The system of claim 1, wherein the actuator (236) is configured to be controlled by a subsea control system (240), and the XT (202) is a subsea XT (202).

11. A method comprising: determining one or more barriers for stress testing (702); operating one or more valves to isolate the one or more barriers (704); causing the fluid mover to pump a certain amount of fluid into the vessel (706); performing one or more stress testing operations (708); as well as After completing the one or more pressure testing operations, the fluid mover is caused to drive the volume of fluid away from the vessel (710).

12. The method of claim 11, wherein the quantity of fluid is removed from a Christmas tree (XT) (202).

13. The method according to claim 12, further comprising: The amount of the fluid is determined based at least in part on a pressure differential associated with the one or more barriers.

14. The method of claim 12, wherein the amount of fluid is returned to the XT after completion of the pressure test (202).

15. The method of claim 11, wherein the one or more barriers include at least one of a main valve or a downhole safety valve.

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