BR112018016538B1 - SUBMARINE PUMP ARRANGEMENT - Google Patents

Abstract

The present invention relates to various subsea production arrangements that may utilize a base module (12) and a pump module (14) including one or more subsea pumps, such as ESPs or subsea centrifugal pumps, wherein the base module and the pump module are fluidly coupled to each other. An adjustable foot (18) can be used to at least partially support the pump module at a horizontal distance from the base module. A horizontally oriented pump module can be equipped with a beam arrangement intended to reduce bending loads on the pump module. The base module and pump module can be placed in a subsea location separately or in one trip. A modular subsea production arrangement can allow low-cost installation and/or operation and high adaptability of various combinations of well production equipment. Certain subsea production arrangements may include one or more recallable FCU/LCU modules for use with subsea appliances such as pumps and compressors.

Description

REFERENCE TO RELATED PATENT APPLICATIONS

[0001] The present PCT Patent Application claims priority to the U.S. Provisional Patent Application. At the. 62/297390 entitled "Flexible Subsea Pump Arrangement" and filed on 19 February 2016, Norwegian Patent Application No. 20160416 entitled "Flexible Submarine Pump Arrangement" and filed March 11, 2016, and U.S. Provisional Patent Application At the. 62/384520 entitled "Modular Production System" and filed on September 7, 2016. All such patent applications are incorporated herein by reference in their entirety and for all purposes.

TECHNICAL FIELD

[0002] The present invention generally relates to subsea hydrocarbon production systems and, more particularly, to flexible and adaptable arrangements for subsea pumping of hydrocarbon fluids.

BACKGROUND

[0003] The production of hydrocarbons from a wellhead may involve the use of various equipment, such as pumps, compressors, separators, heat exchangers, and others. In some cases, reservoir properties may change over time. A production system that operates well at the beginning of production may require additional components throughout its field life. However, constraints on capital costs may preclude the installation of components that, at some point, may be desirable.

[0004] In addition, production from a wellhead may involve the use of intensification (eg, through pump equipment). Intensification can be particularly useful in subsea production systems, where a well stream originating from a wellhead on the ocean floor requires additional flowline pressure to reach an upside or shore facility. Subsea pumping can significantly increase the value of an offshore field. Some subsea pumping technology is complicated, and can lead to problems related to installation/maintenance cost and equipment reliability. It is now recognized that there is a need for subsea pump arrangements that result in lower cost over the life of such equipment.

SUMMARY

[0005] According to the above embodiments, the presently disclosed embodiments relate to a subsea pump arrangement that includes a base module, a pump module and a foot. The base module includes a foundation, which may be a mud mat, suction anchor, or stack, an input connector, an output connector fluidly coupled to the input connector, and at least one module connector. pump arranged between the input connector and the output connector. The pump module is separated in a horizontal direction from the base module and includes a fluid inlet fluidly coupled to the inlet connector and a fluid outlet fluidly coupled to the outlet connector. Both the fluid inlet and fluid outlet are disposed only at one horizontal end of the pump module to couple the fluid inlet and fluid outlet to the base module. The foot is at least partially supporting the pump module, in particular supporting at least 50% of the weight of the pump module, and the foot is separated from the base module by a distance, in particular by a distance of more than three metres. THE . The pump arrangement also includes a fluid conditioning unit (FCU) disposed between the inlet connector and the at least one pump module connector, and a liquid collection unit (LCU) disposed between the at least one pump module and the output connector. The base module may additionally comprise a recirculation line, particularly comprising a blocker arranged between the LCU and the FCU. The pump module may additionally comprise: - a U-shaped conduit or pipeline with the fluid inlet and fluid outlet at only one end, the U-shaped conduit or pipeline comprising two horizontally oriented legs; and - at least one electric submersible pump (ESP) disposed in one or both horizontally oriented legs of the U-shaped conduit or pipeline. The subsea pump arrangement may further comprise a first dual bore connector portion which extends from the pump module and which is oriented vertically downwards when the pump module is installed in the base module, and a complementary dual bore connector portion which extends from the base module and which is oriented vertically upwards with the dual bore connector portion of the pump module. The pump module may comprise a stiffening structure comprising one or more of a beam structure, stiffening ribs, stiffening rockers or tubing, and additional U-shaped conduits or tubing. The pump module may comprise load-limiting elements comprising one or more of buoyancy elements, gas-filled tanks, or gas-filled piping elements, in particular located at at least one of: - an end opposite with respect to the inlet of fluid and fluid outlet; and - a midpoint between the foot and the base module. The foot may comprise a base configured to stabilize a position of the pump module on an ocean floor and a platform attached to the base and adjustable for positioning the pump module at different heights, orientations or lateral positions relative to the base of the foot.

[0006] In addition, the embodiments currently disclosed refer to a modular subsea production system for the production of hydrocarbons. The modular subsea production system includes a base module having a plurality of connection interfaces, in particular wet-coupled interfaces configured for subsea connection. The modular subsea production system further includes a satellite module having one or more production equipment components, wherein the satellite module is releasably connected to the base module at one or more of the connection interfaces.

[0007] Furthermore, the presently disclosed embodiments relate to a fluid conditioning module. The fluid conditioning module includes a fluid conditioning unit (FCU) and a liquid collection unit (LCU) configured to receive a fluid flow through an inlet and separate a portion of the liquid from the fluid flow. The fluid conditioning module optionally includes a recirculation line, which in particular comprises a choke, fluidly coupled between the FCU and the LCU and configured to direct the liquid portion of the LCU to the FCU. The fluid conditioning module includes a multi-hole connector disposed on a surface of the fluid conditioning module and configured to fluidly couple the FCU and/or LCU to a base module.

[0008] Furthermore, the presently disclosed embodiments refer to a foot configured to receive a horizontally oriented pump module. The foot includes a platform configured to receive and support the pump module, a base configured to seat the platform on the ground, and an adjustment mechanism configured to adjust a height of the pump module above a support surface, an angle of the platform relative to the base, a lateral position of the pump module, a step of the pump module, or a yaw of the pump module.

[0009] Furthermore, the presently disclosed embodiments relate to a pump module for producing an oil well stream. The pump module includes an upper longitudinal beam member, a lower longitudinal beam member, two or more support points, a camber point, a cross beam member and a diagonal beam member. At least one of the upper longitudinal beam member and the lower longitudinal beam member includes a tubular enclosure having an inlet and an outlet, and at least one machine disposed within the tubular enclosure between the inlet and outlet, in particular an ESP . The two or more support points are configured to couple to a vertical support of the pump module, wherein the support points are coupled to at least one of the upper and lower longitudinal beam members. The camber point is identifying a maximum predicted deformation of the upper and lower longitudinal beam members due to gravity. The cross beam member is connecting the upper and lower longitudinal beam members near the camber point. The diagonal beam member is connecting the upper and lower longitudinal beam members in which the diagonal beam member is intended for stress loading and the connection of the lower longitudinal beam member at a lower connection point to the upper longitudinal beam member at a top connection point, where the bottom connection point is closest to the camber point, and where the top connection point is closest to the closest support point.

[0010] Furthermore, the presently disclosed embodiments refer to a modular production system for the production of hydrocarbons. The modular production system includes a base module, and at least one of: a wellhead support configured to couple the base module to a wellhead, and in particular further comprises a Christmas tree coupling configured to mechanically couple a Christmas tree to the base module; and a pump, in particular a subsea pump, arranged in the base module and fluidly coupled to an FCU, an LCU and a recirculation line, each of which is arranged in the base module, wherein the base module with the subsea pump, the FCU, LCU and recirculation line is configured to be installed in a subsea location in one trip.

[0011] Furthermore, the presently disclosed embodiments refer to a system that includes a first frame portion configured to receive and support a base module of a submarine pump array, and a second frame portion directly coupled to the first frame portion , in particular through a hinged or rigid connection, wherein the second frame portion is configured to receive and support a subsea pump, in particular an ESP. The second frame portion comprises an elongate shape extending in a longitudinally outward direction from the first frame portion, wherein the first frame portion is taller in a height dimension and wider in a width dimension than the first frame portion. second frame portion.

BRIEF DESCRIPTION OF THE DRAWINGS

[0012] For a more complete understanding of the present invention and its features and advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:

[0013] Figure 1A is a perspective view of a modular subsea pump system having an electric submersible pump (ESP), in accordance with an embodiment of the present invention;

[0014] Figure 1B is a schematic representation of bending moments in the pump module of Figure 1A, in accordance with an embodiment of the present invention;

[0015] Figure 2 is a schematic diagram of a modular subsea pump system having two ESPs, in accordance with an embodiment of the present invention;

[0016] Figures 3A and 3B are schematic top and side views of the modular subsea pump system of Figure 2, in accordance with an embodiment of the present invention;

[0017] Figure 4 is a schematic side view of a pump module of the modular subsea pump system of Figures 3A and 3B being lowered or raised, in accordance with an embodiment of the present invention;

[0018] Figures 5A and 5B are schematic top and side views of a modular subsea pump system equipped with a drag, in accordance with an embodiment of the present invention;

[0019] Figure 6 is a schematic block diagram illustrating a modular subsea equipment arrangement, in accordance with an embodiment of the present invention;

[0020] Figure 7 is a schematic diagram of a modular subsea equipment arrangement that includes a flow conditioning unit (FCU) and a liquid collection unit (LCU) arranged in separate modules, in accordance with an embodiment of the present invention;

[0021] Figure 8 is a schematic diagram of an FCU, an LCU and an associated flow circuit, in accordance with an embodiment of the present invention;

[0022] Figure 9 is a perspective view of an FCU and an LCU arranged in a single module, according to an embodiment of the present invention;

[0023] Figure 10 is a perspective view of an adjustable base for supporting a subsea pump module, in accordance with an embodiment of the present invention;

[0024] Figures 11A to 11E are schematic diagrams of rocker arm arrangements for a subsea pump module having an inlet and outlet on the same side, in accordance with an embodiment of the present invention;

[0025] Figures 12A to 12C are schematic diagrams of rocker arm arrangements for a subsea pump module having an inlet and outlet on opposite sides, in accordance with an embodiment of the present invention;

[0026] Figures 13A and 13B are schematic diagrams of vertically mounted submarine pump modules, in accordance with an embodiment of the present invention;

[0027] Figure 14 is a schematic diagram of a subsea pump module equipped with buoys, according to an embodiment of the present invention;

[0028] Figure 15 is a schematic cross-sectional view of a beam structure on a subsea pump module, in accordance with an embodiment of the present invention;

[0029] Figure 16 is a perspective view of a beam structure on a subsea pump module, in accordance with an embodiment of the present invention;

[0030] Figure 17 is a schematic diagram of a pump module that is installed in a subsea location, in accordance with an embodiment of the present invention;

[0031] Figure 18 is a perspective view of a subsea pump module with support points directly on a pump module rocker structure and unloaded goosenecks, in accordance with an embodiment of the present invention;

[0032] Figure 19 is a perspective view of one of the support points of the pump module of Figure 18, according to an embodiment of the present invention;

[0033] Figure 20 is a schematic diagram of a base module coupled to a wellhead through a connector, according to an embodiment of the present invention;

[0034] Figure 21 is a schematic diagram of a base module with a pump module integrated with and supported by the base module, in accordance with an embodiment of the present invention;

[0035] Figure 22 is a schematic side view of a subsea pump system that can be lowered in one trip, in accordance with an embodiment of the present invention; and

[0036] Figures 23A and 23B are perspective views of a frame with drag protection to be used with the submarine module of Figure 22, in accordance with an embodiment of the present invention.

DETAILED DESCRIPTION

[0037] Illustrative embodiments of the present invention are described in detail herein. For clarity, not all features of an actual implementation are described in this descriptive report. Of course it should be appreciated that, in the development of such a real modality, numerous implementation-specific decisions must be made to achieve specific goals of the developers, such as compliance with system-related and business-related constraints, which will range from an implementation the other. Furthermore, it should be appreciated that such a development effort can be complex and time-consuming, yet it should be a routine task for those of ordinary skill in the art to benefit from the present invention. Furthermore, in no way should the following examples be read as limiting, or defining, the scope of the invention.

[0038] There is a demand for subsea pump arrangements that result in a lower cost over the life of such equipment. These costs include not only the initial cost for the equipment itself, but also the cost for installing, repairing or replacing equipment, upgrading or modifying equipment, effects on adjacent subsea equipment, and so on. Based on ongoing incentives for cost reduction, it is desirable to install downhole pumps in a subsea environment. Such pumps, called electric submersible pumps (ESP), are widely used in downhole environments to provide artificial lift in wellboreholes. Due to their mature design and sales quantity, they can be considered as a commodity item at reasonably low cost. It is desirable to use such ESPs for subsea pumping. The term "subsea pumping" in the present context refers to the placement and use of the ESP in a subsea location on or near the ocean floor, not downhole in a well. However, installing such ESPs for subsea use poses significant challenges.

[0039] Embodiments of the present invention relate to subsea pump arrangements that are intended to address and overcome the challenges associated with the installation and efficient operation of ESPs in a subsea environment. Embodiments of the present invention further relate to modular production equipment arrangements that allow the installation/operation at low cost and high adaptability of various combinations of well production equipment. Embodiments of the present invention further relate to a separate and recoverable FCU/LCU module for use with subsea appliances such as pumps and compressors. Embodiments of the present invention further relate to a foot used to support a horizontally oriented pump module. Other embodiments of the present invention relate to a beam arrangement designed to reduce bending loads on a horizontally oriented pump module. Embodiments of the present invention further relate to other modular production systems and pump arrangements that may be particularly useful in subsea environments.

[0040] Returning now to the drawings, Figure 1A illustrates a submarine pump arrangement 10 in accordance with the present invention. The subsea pump arrangement 10 is a modular pump arrangement 10 that includes at least a base module 12 and a pump module 14. The pump module 14 generally includes at least one pump, in this case an ESP 16, to provide pumping subsea production fluid extracted from a subsea wellbore. The ESP 16 can pressurize production fluid to facilitate the transfer of production fluid from a subsea wellhead to a surface installation. The pump module 14 can extend in a horizontal direction from the base module 12, as shown. Pump module 14 can only be partially supported by base module 12 or not supported by base module 12 at all.

[0041] The expression "can only be partially supported by the base module 12 or not be supported by the base module 12 at all" generally refers to the case where the weight of the pump module 14 is not supported or is only partially supported by the base module 12. To that end, the pump module 14 may generally include a pump module foot 18 and/or other optional elements to limit or eliminate the weight of the pump module 14 that is supported by the base module 12. base module 12 may generally include a separate base module support structure 20 to support the weight of base module 12 above the ocean floor.

[0042] The modular subsea pump arrangement 10 can physically separate equipment components that do not require frequent or regular replacement/maintenance from equipment that is in greater demand for replacement or maintenance. Specifically, equipment that does not require frequent or regular replacement/maintenance is arranged in base module 12, while ESPs 16 or other subsea pumps in greater demand for replacement/maintenance are located in pump module 14. By using such an arrangement, the pump module 14 can be positioned horizontally apart from the base module 12, thereby providing a subsea pump that has a low weight, is easily accessible, and in particular adapted for easy and safe installation/refurbishment. Furthermore, the installation time for the subsea pump arrangement 10 can be minimized, as only two units 12 and 14 need to be installed/connected. Due to the low weight of pump module 14, a lightweight intervention vessel can be used for restoration and installation of pump module 14.

[0043] The expression "located horizontally away from the base module 12" refers to the pump module 14 which is fixed in a direction in principle 90 degrees with respect to the vertical. This separation can provide improved access to install and retrieve the pump module 14, which results in faster, safer, and less expensive installation and restoration operations. Except for cases where a drag protection structure is desired, there is typically no restriction on accessing the pump module 14 from above in the modular subsea pump arrangement 10.

[0044] Various additional features of the modular submarine pump arrangement 10 of Figure 1A will be described in more detail throughout the detailed description below.

[0045] As mentioned above, the weight of the pump module 14 can be "partially" supported by the foot 18. The placement of the foot 18 relative to a connector end 100 of the pump module 14 can be selected such that a part of the weight of the pump module 14 is supported by the base module 12 and another major part of the weight of the pump module 14 is supported by the foot 18. Figure 1B schematically represents the bending moments that may be present at various points along of the length of the pump module 14. The foot 18 of the pump module 14 can be positioned at a predetermined horizontal distance 590 from the connector end 100 of the pump module 14. This distance 590 can be determined on the basis of the bending moments foreseen in the various support points 312 and sag points 314 along the pump module 14. The support points 312 are the locations where the weight of the pump module 14 is supported, for example by the foot 18 or the base module (eg r example, 12 of Figure 1A). Buckle points 314 are points which, due to various forces (eg, the mass of the pump module 14 and/or its components) must "bend" due to gravity.

[0046] Two support points 312 (one at the end 100 connected to the base module, and the other at the foot 18) may be present along the pump module 14, while an arching point 314 may be present at a location between the two support points 312. The approximate bending moment at different points along the length of the pump module 14 is illustrated. For example, the "upward" bending moment of the pump module 14 at the support point 312 located at the connector end 100 is indicated as Ms, the "upward" bending moment of the pump module 14 at the support point 312 located at the foot 18 is denoted as M1, and the "down" bending moment of the pump module 14 at bending point 314 is denoted as M2. Foot 18 can be positioned along the length of pump module 14 such that the magnitude of M1 (moment at foot 18) is more or less equal to, within about 10%, or within about 20% , of the magnitude of M2 (moment at warp point 314). This can help keep the bending forces on the pump module 14 relatively low. To satisfy these criteria, it may be necessary for a portion of the weight of the pump module to be supported by the base module interacting with the connector end 100 of the pump module 14. Specifically, the base module can support, for example, at least 2% of the pump module weight, between about 5% and 25% of the pump module weight, or between about 10% to 20% of the pump module weight. The foot 18 can be positioned such that the foot 18 supports at least 50% of the weight of the pump module, or at least 80% of the weight of the pump module. Foot 18 can be positioned a certain minimum distance from connector end 100 (and base module) to still satisfy these criteria. For example, the foot 18 can be positioned at least 3 meters from the base module, at least 6 meters from the base module, or any other minimum distance from the base module.

[0047] Figure 2 provides a detailed block diagram of a subsea pump arrangement 10 in accordance with the present techniques. Figures 3A and 3B provide top and side views of the subsea pump arrangement of Figure 2. This subsea pump arrangement 10 further includes a base module 12 coupled to a separate pump module 14, as described above. However, the pump module 14 can include two ESPs 16A and 16B, instead of just one, as shown in Figure 1A. It should be noted that the arrangement and function of the various components shown in Figure 2 can be applied analogously to modular subsea pump arrangements 10 having any number of ESPs 16 present in the pump module 14.

[0048] As mentioned above, the modular subsea pump arrangement 10 is designed in such a way that the base module 12 includes components that are not likely to need much maintenance during the lifetime of the pump arrangement 10. The base module 12 may include a foundation 22, an inlet connector 24, an outlet connector 26, a bypass line 28 with a bypass valve 30 arranged between the inlet connector 24 and the output connector 26, at least one pump 32 or a connector portion disposed between inlet connector 24 and outlet connector 26, and a number of isolation valves 34 and guide pins 36 (shown in Figure 3B).

[0049] In addition, the base module 12 may include a fluid conditioning system. The fluid conditioning system generally includes a fluid conditioning unit (FCU) 38 (or an arrangement thereof) disposed between the inlet connector 24 and at least one pump module connector 32, a liquid collection unit ( LCU) 40 (or an arrangement thereof) disposed between at least one pump module connector 32 and the output connector 26, and a recirculation line 42 with an adjustable choke 44 arranged between the FCU 38 and the LCU 40. as fully described below, the FCU 38 can be used for gas/liquid homogenization and mixing, while the LCU 40 can be used for gas/liquid separation and liquid collection.

[0050] The foundation 22 generally supports the other components of the base module 12, and the foundation 22 may be supported on the ocean floor or elevated above the ocean floor via the base module support structure 20 (e.g., a pile, a suction anchor, or a mud mat, depending on ground conditions). The inlet connector 24 can fluidly connect the base module 12 to a subsea wellhead flow line to direct a flow from the subsea wellhead well 46 to a flow line 48 of the base module 12. from well 46 can be distributed through flow line 48 to the FCU 38, to pump module 14 where the flow is further pressurized, back to base module 12 where it passes through LCU 40, and through another flow line 50 before an enhanced flow 52 is output through the outlet connector 26. With the inclusion of the bypass line 28 and the bypass valve 30 in the base module 12, an additional bypass jumper is not required for system operation. bomb.

[0051] Instead of having the illustrated FCU/LCU arranged in the base module 12, the base module 12 can only include an FCU 38 (or an arrangement thereof), and optionally a recirculation line 42. That is, the base module 12 may not include LCU 40 at all. The recirculation line 42, if included in the base module 12, can route the separate gas from the FCU 38 directly to the flow line 50 during start-up of the pump module 14. In other cases, a separate module containing an LCU 40 can be joined to the base module 12 to couple to the FCU 38 (for example, through the recirculation line 42) arranged in the base module 12, so that the gas and/or liquid can flow between the FCU 38 and the LCU 40 through all pump operations.

[0052] Instead of having the illustrated FCU/LCU arranged in the base module 12, the base module 12 can only include an LCU 40 (or an arrangement thereof), and optionally a recirculation line 42. That is, the base module 12 may not include the FCU 38 at all. The recirculation line 42, if included in the base module 12, can distribute the liquid separated from the LCU 40 directly to the flow line 48 during the operation of the pump module 14. In other cases, a separate module containing an FCU 38 can be joined to base module 12 to couple to LCU 40 (e.g. via recirculation line 42) arranged in base module 12, so that gas and/or liquid can flow between FCU 38 and LCU 40 through all pump operations.

[0053] The fluid flow can be distributed between the base module 12 and the pump module 14 through at least one pump module connector 32. The at least one pump module connector 32 can include a dual-hole connector that allows the connection of the base module 12 to the suction and discharge pump, so that the flow can be directed from the base module 12 to the pump module 14 and then the pressurized flow can be directed from the pump module 14 back to the base module 12. Guide pins 36 of base module 12 can facilitate relatively easy seating and coupling of pump module 14 to base module 12 during installation.

[0054] The pump module 14 may include only those components necessary to operate the ESP(s) 16 of the modular subsea pump arrangement 10. The pump module 14 may include a conduit or U-shaped flow pipe 90 with an inlet 92 and an outlet 94 at one end only, as illustrated in Figures 2, 3A and 3B. Pump module 14 can include at least one pump (e.g. ESP 16) arranged in U-shaped conduit 90 and foot 18 of the pump module. As illustrated, pump module 14 can be oriented horizontally as installed. The U-shaped flow conduit 90, therefore, may include a first horizontally oriented canister or leg of tubing 96A and a second horizontally oriented canister or leg of tubing 96B.

[0055] If two pumps (for example, ESPs 16A and 16B) are being used in pump module 14, the first foot 96A can contain the first ESP 16A and the second foot 96B can contain the second ESP 16B. Each of the ESPs 16A and 16B may be horizontally oriented, but directed in opposite directions, in respective horizontally oriented canisters or pipe legs 96A and 96B. If only one pump (e.g. ESP 16) is being used in pump module 14 (e.g. as shown in Figure 1), ESP 16 can be arranged in the first leg 96A, while the second leg 96B provides an empty return transfer pipeline. In such cases, the second leg 96B without a pump may be of a generally smaller diameter than the leg 96A containing the ESP 16. The two legs 96A and 96B of the U-shaped conduit 90, containing one or two ESP(s) ) 16 in total, can be horizontally oriented, but vertically arranged one on top of the other, as shown. By providing a gap between the legs 96A and 96B of the U-shaped conduit 90, the illustrated pump arrangement allows for easier handling, greater rigidity (due to the ability to include a beam structure), and optional integration of buoyancy elements in the pump module 14.

[0056] The pump module 14 includes at least one base module connector 98, which may include the connector portions 54 for the input and output of the ESP(s) 16 on the pump module 14. illustrated, both connector portions 54 may be disposed on only one end 100 of the pump module 14. At least one base module connector 98 may be oriented vertically downwards during installation of the pump module 14. base module 98 is intended to interface directly with at least one pump module connector 32 of base module 12 to fluidly couple base module 12 to pump module 14. At least one base module connector 98 may include a double-hole connector part, two separate single-hole connector parts for the inlet and outlet respectively, or one or more multi-hole connector parts.

[0057] Connector parts 54 may include flexible flow lines that are intended to interface with and be mated to at least one pump module connector 32. Such flexible flow lines may include steel pipe flow lines that have an elongated section, creating flexibility to bend without causing excess stress or fatigue in the connection. The flexible flow lines can allow the pump module 14 to be effectively connected to the base module 12 regardless of the exact vertical positioning of the pump module 14 relative to the base module 12 due to, for example, some sagging of the foot 18/mounting module bomb 14 on the floor of the ocean floor over time.

[0058] At least one pump module connector 32 on the base module 12 can include complementary connector parts 102 to the connector parts 54 of the base module connector 98. These complementary connector parts 102 can be oriented vertically upwards when the module base 12 is installed and intended to interface directly with connector portions 54 of base module connector 98 on pump module 14. Connectors 32 and 98 may include clamp or clamp type connectors that are operable by a remotely operated vehicle (ROV), and these connectors 32 and 98 may include a single double hole or a multi hole clamp connector.

[0059] The pump module 14 may include an ROV panel 104 that allows an ROV to interface with the ESP(s) 16 on the pump module 14. The ROV panel 104 may provide a power connection to ESP(s) 16, as well as any hydraulic or electrical connections required for flow assurance or instrumentation into ESP(s) 16. ROV panel 104 may include an ROV boarding structure that includes ROV receptacles or sockets with connectors or holes to supply hydraulic power (for flow assurance) and/or electrical power to the ESP(s) 16.

[0060] The pump module 14 can include a stiffening structure 106 that connects the two legs 96A and 96B of the U-shaped conduit 90. The stiffening structure 16 can provide rigidity to fix the structure of the pump module 14, limiting thereby arching the ESP(s) 16 to ensure proper motor/pump impeller dynamic rotor stability and long service life. The stiffening structure 106 can provide a rigid, lightweight structure with increased stability and rigidity for handling during installation and restoration. The stiffening structure 106 may include a beam structure, stiffening ribs, stiffening rockers or tubing, additional U-shaped conduits or tubing that may or may not contain pumps, and connector portions for downstream coupling, among others.

[0061] As illustrated in Figure 3B, for example, the stiffening structure 106 can be arranged by welding two steel plates to the sides of the horizontal pipe sections (legs 96) of the U-shaped conduit 90. The plates may have materials removed to reduce weight such that a beam-like pattern is created. These plates joined to the two legs 96 can thus form a very rigid structure while keeping the weight down. Thus, the stiffening structure 106 can be a separate part of the legs 96 of the U-shaped conduit 90 which is coupled to the legs 96 to provide additional structural support.

[0062] In other arrangements, the two legs 96 of the U-shaped conduit 90 can act as parts of the stiffening structure 106 itself. This can further reduce the weight of the pump module 14, since no other longitudinal parts are required to obtain the desired stiffness. The stiffening structure 106 in this case can be formed by welding rockers or plates directly to the horizontal piping legs 96 of the U-shaped conduit 90 and extending between the two legs 96 to create a beam-like structure. This can be done, for example, by welding the plates that are at an angle of 90 degrees with respect to the axes of the horizontal piping of the legs 96 and the plates that are at an angle of about 20 degrees with respect to the axes of the horizontal piping of the legs. 96. It should be understood that other arrangements of the stiffening structure 106 can be used to maintain the rigidity of the pump module 14 while the weight of the pump module 104 is kept low and the two legs 96 are integrated into the stiffening structure 106. In this way, the two ESPs 16A and 16B can be oriented horizontally in the U-shaped conduit 90 with the legs 96A and 96B acting as load carrying members in a beam arrangement where the legs 96 are interconnected with steel members to form the frame. of stiffening 106.

[0063] The pump module 14 may include load-limiting elements such as, for example, one or more buoyancy elements, gas-filled tanks, gas-filled piping elements, and the like. For example, as shown in Figure 14, the pump module 14 can be equipped with one or more floats 430 disposed therein. Floats 430 may be constructed of any desirable type of material (eg, foam) or equipment (eg, gas-filled container) that enhances the buoyancy of the portion of pump module 14 in which float 430 is disposed. Any desired shape, position, and/or number of floats 430 can be positioned on pump module 14. Floats 430 can remove stress from pump module 14 and the ESP(s), particularly at points of sagging. In some cases, one or more floats 430 may be used to remove stresses from the pump module 14 at the end of the pump module 14 which interfaces with the base module. In this way, the weight of the pump module 14 can be almost or entirely removed from the base module. Strain gauges, fatigue gauges, or other monitoring components can be used to confirm that floats 430 are decreasing loads on pump module 14 as desired. Floats 430 can help dampen oscillations through the stiffened structure of pump module 14 and control dynamic loads in the system.

[0064] As shown in Figure 14, the lifting points 496 can be positioned along the length of the horizontal pump module 14. The number and arrangement of the lifting points 496 can be chosen so as to minimize bending during lifting/lowering the pump module 14, for example via a spreader bar (see Figure 17). One of the lifting points 496 can be positioned above the foot 18 of the pump module 14. In this way, the foot 18 can be integrated with the rest of the pump module 14 during installation while the pump module 14 is lowered through the connections at the lifting points 496. This allows the foot 18 integrated with the pump module 14 to be installed in a single voyage of a delivery vessel. The foot 18 may be adjustable via an ROV such that a base 108 of the foot 18 can be properly positioned and bent to seat the entire pump module 14 on the ocean floor.

[0065] As mentioned above, the pump module 14 generally includes a foot 18 to support most of the weight of the pump module 14 extending horizontally from the base module 12. As illustrated, the foot 18 can be supported on a small base 108 on the ocean floor. The foot 18 is releasable and connectable with respect to the pump module 14, in such a way that the foot 18 can be joined and articulated to the pump module 14 before being installed together with the pump module 14. The foot 18 can be released into its seating position during the final phase of the installation process. The remainder of the pump module 14 can be removed from the foot 18 once the system is installed, thereby allowing the foot 18 to remain in place while the remainder of the pump module 14 is retracted to the surface for maintenance. In other cases, the foot 18 can be completely fixed to the pump module 14.

[0066] The foot may include a height adjustment mechanism. This can help provide proper support to the pump module 14 in the event of a soft ground condition on the ocean floor. The height adjustment mechanism may include an ROV torque tool operated mechanical screw adjustment, indicated as 110 in Figure 3B. However, other types of height adjustment mechanisms can be used.

[0067] The pump module 14 may include transmitters for the slope, a water level or a bubble or target level, a height/position sensor for the pump module 14, and/or other instrumentation. These can help with seating and placing the pump module 14 on the base module 12 during installation. Pump module 14 may include guide funnels 107 intended to interface with and seat on guide pins 36 of base module 12. This type of connection interface between pump module 14 and base module 12 can aid in proper alignment of pump module 14 with respect to base module 12 during installation.

[0068] The pump module 14 generally does not include an FCU, since this component (38) is, in turn, located in the base module 12 as described above. Thus, the U-shaped conduit 90 does not include an integrated volume or fluid conditioning function. This helps to reduce the weight and size of the pump module 14, thereby providing greater ease of handling during installation and restoration.

[0069] The pump module 14 generally does not include an LCU, since this component (40) is, in turn, located in the base module 12 as described above. Thus, the U-shaped conduit 90 does not include a volume or an integrated fluid separation/collection function. This helps to further reduce the weight and size of the pump module 14, thereby providing greater ease of handling during installation.

[0070] A module may include a subsea pump. For example, a pump module 14 may be equipped with one or more subsea centrifugal pumps, as opposed to the ESP(s) 16. The pump module 14 may be oriented vertically as installed, rather than horizontally, and contain one or two vertically oriented subsea centrifugal pumps in a U-shaped conduit 90. Similarly, pump modules 14 containing one or more ESPs 16 may be oriented vertically, as shown as vertical ESP modules 390 in Figures 13A and 13B . In some locations (eg, on the surface, deep underwater), vertical orientation of the ESP module 390 may be possible.

[0071] The pump module 14 may include one or more subsea centrifugal pumps and/or ESPs, as disclosed above. The choice of type and number of pumps can be made according to well and/or field requirements. Subsea centrifugal pumps are generally short, stubby, heavy, and require higher horsepower. ESPs are typically intended for use in wells, and as such are long and thin, and generally operate at a lower power. Certain common differences between pump types are outlined in Table 1 below. ESP Subsea Centrifugal Pump

[0072] Since the connecting components of the pump module 14 can only be arranged at one end of the pump module 14, the other end can be left free to move axially in response to changes in temperature and pressure in the pump module 14 pump for various operating conditions. This ability of the system to expand axially is possible in the disclosed pump arrangement 10 without the use of large goosenecks, thereby limiting the size of the installation and the weight of the system. Arrangement of the foot 18 at an axial distance of about 2/3 of the total length of the connection side of the pump module 14 can reduce deflection and stress in the legs 96A and 96B of the U-shaped conduit 90. the free end acts as a counterweight, the illustrated piping arrangement effectively has a rigid anchor at the foot location 18.

[0073] Since the pump module 14 includes all connection components at one end only, as well as a fixed or pre-installed adjustable foot 18, no metrology may be required prior to installation of the pump module 14. eliminate an inspection trip with the installation vessel that would otherwise be required, thereby reducing installation costs and time.

[0074] The disclosed pump arrangement 10 generally provides a pump module 14 with a reduced size, length and weight compared to existing systems where a subsea centrifugal pump or ESP is provided in a subsea location. For example, the disclosed arrangement 10 can facilitate a 20% reduction in the length of the pump module 14 compared to existing systems, a 25% to 55% reduction in the weight of the pump module 14 (depending on whether an FCU/LCU is present in the existing system). Reducing the size and weight of the components in the pump module 14 can be particularly useful when the system is upgraded to a higher pressure rating, since the pump module 14 has pressure-containing items with a smaller diameter compared to a jumper arrangement having fluid conditioning equipment. The arrangement of the components of the pump module connector 14 on one side only can facilitate easy installation and restoration as it allows the use of either a single double hole clamp connector or a single two hole clamp connector, thereby reducing the number of critical fluid connector mating operations.

[0075] Figure 4 illustrates the pump module 14 of the subsea pump arrangement 10 that is lifted through the connection at two lifting points 130 coupled to the U-shaped conduit 90 and/or the stiffening structure 106. riser 130 can be carefully positioned to reduce or minimize bending forces on pump module 14 due to the weight of ESP(s) 16 on board during installation/restoration.

[0076] Figures 5A and 5B illustrate the submarine pump arrangement 10 completely assembled and with the drag protection disposed in it. The subsea pump arrangement 10 is generally suitable for the inclusion of drag protection, as shown, since the modular pump arrangement can be arranged close to the ocean floor and with a low vertical height to limit the flash profile of the protection equipment. As illustrated, a first guard structure 150 may be arranged on the base module 12 and a second guard structure 152 may be arranged for the pump module 14. These drag guard structures 150 and 152 may be supported by an anchor of suction 154, but can still be supported by a pile or else take on the loads that can occur during dragging. Hatches 156 openable via ROV are located along guard structures 150 and 152 to allow access during installation, restoration or maintenance of base module 12 and/or pump module 14. To be noted that drag protection arrangements other than that shown in Figures 5A and 5B can be used with the disclosed subsea pump arrangement 10 which has a relatively low height above the ocean floor.

[0077] Figure 17 illustrates a pump module 14 that is lowered into an installed position coupled to the base module 12. As shown, the pump module 14 can be lowered into that position via a spreader bar 490 that comes from a floating vessel. The spreader bar 490 can be lowered via an application cable 492 from top to bottom, and the spreader bar 490 can be coupled to the pump module 14 via several cables 494 that extend down from the spreader bar 490. The cables 494 can be attached to the pump module 14 at specific lifting points 496 arranged along the length of the horizontal pump module 14. The number and arrangement of the lifting points 496 can be chosen so as to minimize bending during deployment. pump module lifting/lowering 14. Spreader bar 490 can be used to minimize longitudinal compressive forces.

[0078] Figure 22 illustrates a pump arrangement 610 similar to the modular pump arrangement 10 of Figures 1 to 17, but with the base module 12 and the pump module 14 coupled using a connector 612 supported on the base module 12. In this way, the base module 12 and the pump module 14 can be lowered or restored in one trip. To that end, the pump arrangement 610 may further include an extended base 614 for supporting the foot 18 and the pump module 14, where such extended base 614 interfaces directly with and in some case is hinged (via a a hinge 616) to the foundation 20 of the base module 12. The foundation 20 and extended base 614 can be equipped with lifting points 496, thereby allowing the entire assembly to be lowered to a subsea location when using a spreader bar (such as as described above with reference to Figure 17). Connector 612 may be disposed on end 100 of pump module connector 14. In some examples, connector 612 may be adjustable to allow pump module 14 to laterally flex, slide, rotate, and/or move vertically relative to the base module 12 as required when the system is positioned on the ocean floor. Connector 612 can be configured to move similarly to adjustable foot 18 in this respect.

[0079] In addition to, or instead of, the base module 12 and the pump module 14 being coupled to each other via a connector (612) as shown in Figure 22, the pump arrangement may utilize an arming mechanism " coupled" to support both base module 12 and pump module 14 (e.g. the ESP). Figures 23A and 23B illustrate one embodiment of such a frame mechanism 630. As shown, the frame mechanism 630 may include a first portion 632 configured to receive and support the base module and a second frame portion 634 configured to receive and support the pump module (which may only include an ESP or a subsea centrifugal pump, without an additional foot). The first and second frame portions 632 and 634 may be coupled to each other, for example through a hinge 636 or through a rigid connection at their interface. As shown, the first frame portion 632 can have a relatively tall and wide box shape, while the second frame portion 634 can have a thin, elongated and relatively smaller shape. That is, the first frame portion 632 may be taller in a height dimension and wider in a width dimension than the second frame portion 634, as shown. The second frame portion 634 may be elongated in a direction such that the second frame portion 634 extends longitudinally outward from the first frame portion 632. The base module 12 and the ESP may be installed in the "coupled" frame mechanism 630 and lowered in one trip to a desired underwater location. To that end, the frame mechanism 630 can be equipped with a number of lifting points that can be used to lower the frame mechanism 630 with the base module 12 and ESP installed therein via a spreader bar.

[0080] In some cases, as shown, the cocking mechanism 630 may be equipped with the drag guard 638 that can be selectively rotated (hinged) out of the way to expose the interior of the cocking mechanism 630. In this way, the base module 12 and the ESP can be selectively placed in the frame mechanism 630. The drag guard 638 can include two separate frames (e.g., the first frame 640 and the second frame 642), and these can be moved separately so that, for example, when repair or replacement is required on the ESP, only the second drag guard structure 642 needs to be moved out of the way so that the ESP is restored from the frame portion 634. Drag 638 can have a generally trapezoidal shape to reduce the drag load.

[0081] Figure 6 illustrates a modular equipment arrangement 170 that can provide an extension of the modular pump arrangement described above. Modular equipment arrangement 170 can allow adaptability of a well production system to different amounts/types of hydrocarbons produced throughout the lifetime of the well. The modular subsea equipment arrangement 170 generally includes at least one base module 172 and one or more satellite modules 174. The satellite modules 174 may include one or more side-mounted modules 176, one or more top-mounted modules 178, or a combination of these. While various aspects of production equipment are described herein in the context of a subsea environment, the disclosed modular equipment arrangement 170 can be similarly applied to onshore or surface deployments.

[0082] As shown in Figure 20, the modular equipment arrangement 170 can include a wellhead support 550 configured to couple the base module 172 to a wellhead 552. The base module 172 can provide mechanical support to the wellhead wellhead 552 by "unloading" from wellhead 552 forces that can otherwise be supported by wellhead 552. Mechanical stress (e.g., fatigue) of wellhead 552 can be reduced by supporting various components by base module 172 instead of wellhead 552.

[0083] The wellhead support 550 can clamp, locate and/or then couple the wellhead 552 to the base module 172, in such a way that the base module 172 provides an extended "foot" around the wellhead 552 which reduces the stress (e.g. bending) of the wellhead 552. In particular for soft ground (e.g. sand, mud) and/or a shallow reservoir (e.g. within a few hundred meters of the surface), the lateral dimensions of base module 172 in combination with an attached wellhead 552 can minimize stress on wellhead 552.

[0084] The base module 172 may include one or more columns, a suction anchor, a mud mat, and others, according to the surface (for example, the ocean floor) on which the base module 172 is arranged . Although the deformation of a typical wellhead is limited by the circumferential interaction of the wellhead itself with the surrounding terrain, a 172 base module that acts as a wellhead support can "extend" the interaction area to a much larger area. (eg, greater than 10 times, 50 times, or even greater than 100 times the cross-sectional area of wellhead 552). A circumferential interaction region around a typical wellhead (e.g., 1 to 4 meters in circumference) can be extended to a circumference of base module 172 that has a length of at least 25, including at least 50, including at least least 100 meters.

[0085] The base module 172 may include a Christmas tree 554 (for example, fluidly coupled to the wellhead 552). At least one Christmas tree coupling 556 may be disposed on the base module 172 and used to mechanically couple the Christmas tree 554 to the base module 172. The Christmas tree 554 may be positioned as a top mounted module 178 on the base module 172, and the Christmas tree 554 can be fluidly attached to the wellhead 552. By combining the base module 172, the wellhead support 550, and the Christmas tree 554, the loads typically applied to the wellhead 552 (by the tree) can be transmitted directly to the surrounding terrain through the base module 172. The base module 172 can include a Christmas tree 554 and at least one of, including both, an FCU 38 and an LCU 40.

[0086] In some embodiments, as shown in Figure 21 , the base module 172 itself may include a pump (e.g., an underwater centrifugal pump or ESP) 570 disposed therein. The pump 570 can be positioned in the base module 172, and not in a satellite module that is applied separately and coupled to the base module 172. The base module 172 can still include an FCU 38, an LCU 40 and/or a recirculation line 42 disposed therein, as well as other bypass lines, valves and flow lines discussed above with reference to Figure 2. This can facilitate a one-trip installation of the subsea pump arrangement.

[0087] Returning to Figure 6, the generalized base module 172 can include a plurality of connection interfaces 180 intended to receive and directly connect different satellite modules 174 that can be employed throughout the life of the well. Each of the connection interfaces 180 may include one or more of the following connections: inlet/outlet well stream to communicate the flow of production fluids; hydraulic connections; electrical power connections; and control connections (eg electrical, optical). A single satellite module 174 may be coupled to each interface of the plurality of connection interfaces 180. The connection interfaces 180 for the side-mounted modules 176 may be disposed along the outer perimeter of the base module 172, while the connection 180 for top mounted modules 178 may be arranged closer to the center of base module 172. All connection interfaces 180 may be located on an upper face of base module 172 such that base module 172 can provide a amount of support to each of the side mounted modules 176 coupled thereto.

[0088] The base module 172 may interface with any desirable number of additional satellite modules 174 (side-mounted, top-mounted, or both). The base module 172 can generally function as a motherboard to which the satellite modules 174 containing various functional components of the production equipment can be selectively connected. This allows adaptability of the resulting production system throughout the life of the well by only having to add, remove or replace the smaller, relatively lightweight satellite modules 174 rather than the entire system. This can be particularly useful in subsea production contexts, as adapting or providing maintenance to the production system must be possible when using smaller vessels due to the relatively light weight of the equipment that is employed.

[0089] Furthermore, the modular equipment arrangement 170 can allow individual satellite modules 174 to be selectively removed for maintenance or replacement without further having to remove additional components that do not require replacement/maintenance. This is the case, for example, when the base module 172 is similar to the base module 12 of Figures 1 to 5 and a side mounted module 176 coupled to the base module 172 is similar to the pump module 14 of Figures 1 to 5. arrangement allows the pump module 14 to be selectively removed and attached or replaced without requiring a vessel to lift the heavier equipment from the base module 12 which does not require repair/replacement.

[0090] The modular equipment arrangement 170 of Figure 6 can still allow updates or adaptations to the production system to be made throughout the life of the well. For example, as well flow changes over time, additional satellite modules 174 can be incorporated into array 170 to provide desired functionality without having to replace the entire system. As an example, in some embodiments, base module 172 may not initially be equipped with enhancement features. The system can operate well initially without an ESP or other subsea pump. However, as the well ages, the production flow pressure from the well may decrease, and ESPs or other subsea pumps may have to be added through one or more satellite modules 174 to provide additional boost.

[0091] Similarly, the system can operate well initially without any FCU/LCU equipment. However, as the well ages, the gas fraction of the production stream may increase to the point where fluid conditioning is desired. FCU/LCU equipment can then be added via one or more satellite modules 174 to facilitate effective operation of ESPs or other subsea pumps. Base module 172 can be initially installed with piping and connectors in place (eg interface 180) for use with FCU/LCU equipment that is added later. The distributor and FCU/LCU can both be fitted with recoverable connectors in such a case. Since the equipment arrangement 170 is adaptable throughout the life of the well, this allows for reduced costs as one is not paying for the equipment until it is actually needed for production operations.

[0092] Each of the satellite modules 174 may include equipment such as, for example, one or more ESPs, one or more underwater centrifugal pumps, a compressor, a cyclone, an FCU, an LCU, raw seawater injection components , turbomachinery, or a combination thereof. ESPs or subsea centrifugal pumps can be selectively attached as satellite modules 174 to serve for wellbore flow enhancement or to provide backup when other pumps are retrofitted/replaced. ESPs or subsea centrifugal pumps may be included in side-mounted satellite modules 176 (as described above with reference to Figures 1 to 5), or in top-mounted satellite modules 178 (e.g., vertically oriented pumps as shown in Figures 13A and 13B). On side-mounted satellite modules 176, ESPs or subsea centrifugal pumps may include loaded or unloaded goosenecks.

[0093] As mentioned above, the FCU/LCU components may be attached to the base module 172 as one or more separate and retrievable satellite modules 174. Figure 7 illustrates one embodiment of a modular equipment arrangement in which an FCU module 210, an LCU module 212 and a machine module 214 are coupled together. As fully described above, each of these modules 210, 212, and 214 can be coupled to each other through a common base module (not shown; for example, base module 172 of Figure 6). The FCU module 210 may include an FCU 38, whereas the LCU module 212 may include an LCU 40. The machine module 214 may include any desired machine 216 such as, for example, an ESP, a subsea centrifugal pump, a compressor, a turbomachinery, a cyclone, or a separator. The FCU module 210 can be coupled to the base module in such a way that the FCU 38 is fluidly coupled between an inlet 217, the machine 216 (through a flow line 218), and the LCU 40 (through the flow line 218). recirculation 42). The LCU module 210 can be coupled to the base module in such a way that the LCU 40 is fluidly coupled between an output 219, the machine 216 (through a flow line 220), and the FCU 38 (through the flow line 210). recirculation 42). As illustrated, the FCU module 38 and the LCU module 40 are separately recoverable and replaceable as needed.

[0094] The function of the FCU/LCU equipment will now be described with reference to Figure 8. The FCU/LCU equipment can be used in combination with a machine such as an ESP to prime the machine during start-up or to feed back the machine during a scheduled stop. Wellhead production fluids including gas, liquid and/or sand can enter the FCU 38 through inlet 217. The FCU 38 separates the gas portion of the inlet production fluids from the liquid portion by allowing the gas portions to and liquid have different internal velocities. The lighter gas portion moves from the FCU 38 to the LCU 40 through the recirculation line 42 during machine start-up 216. The heavy fraction of the production fluid (ie liquid and sand) sinks to the bottom of the FCU 38, and the liquid is directed to the machine 216 through the flow line 218 coupled to the bottom of the FCU 38. The liquid can help prime the machine 216 so that it will operate effectively when there is a relatively large amount of gas coming from the flow head. pit.

[0095] The resultant gas, liquid and sand exiting the machine 216 are then directed to the LCU 40 via the flow line 220. The LCU 40 can separate the liquid from the gas again (similarly to the FCU 38). A large portion of pressurized fluid (e.g., gas, liquid, and sand) received from machine 216 may be routed through outlet 219 for communication to a surface installation. A portion of the liquid in the LCU 40 may be separated from the flow of pressurized fluid through the LCU. Recirculation line 42 may direct the separated portion of liquid from the LCU to the FCU during operation of machine 216. This liquid portion may later be used to prime machine 216 during a cold start. That is, liquid may be supplied from the FCU 38 to the machine 216 first before new production fluid is dispensed from the FCU 38 to the machine 216 in order to prevent the machine 216 from being shut down due to a gas within the machine 216.

[0096] The FCU/LCU equipment can be positioned on a base module (eg, 12, 172) as a simple self-contained FCU/LCU module 250, as illustrated in Figure 9. As shown, the FCU module /LCU 250 may include the FCU 38, the LCU 40 and the recirculation line 42, and the recirculation blocker 44. The FCU/LCU module 250 may further include a vertically oriented multi-hole connector 252 disposed on a lower surface of the FCU/LCU module 250. Connector and multiple holes 252 may include connections for each of the flowlines (e.g., 217, 218, 219, and 220) described above with reference to Figure 8. The specific flowlines are not all visible from the perspective of the illustration, however they are located generally on the multi-hole connector on the bottom surface of the FCU/LCU module 250. The multi-hole connector 252 can facilitate the connection of the FCU/LCU module 250 to a module base such as 172 of Figure 6. In the present arrangement jo, the FCU/LCU module 250 can act as a top mounted satellite module (eg 178 of Figure 6) for connection to a base module. The FCU/LCU module 250 may include a frame 254 disposed around the FCU 38 and LCU 40 to provide protection for these structures. The FCU/LCU 250 module may include one or more locator components 256 such as guide funnels intended to help orient and align the FCU/LCU 250 module to a desired position on the base module during installation of the FCU/LCU 250 module .

[0097] The recirculation block valve 44 can be removed and retrieved separately from the other components of the FCU/LCU 250 module. The recirculation block valve 44 can be arranged on one side of the FCU/LCU 250 module where the frame protection 254 is relatively open.

[0098] The recirculation line 42 can be an optional component of the FCU/LCU 250 module. That is, some versions of the FCU/LCU 250 module can only include the FCU 38 and the LCU 40 arranged in it, without the line recirculation line 42 and blocker 44. In such cases, a recirculation line 42 (which may include a blocker 44) can be arranged in the base module (e.g. 12, 172) to which the FCU/LCU module 250 is attached removable. The connections of the FCU 38 and the LCU 40 to a recirculation line in the base module can be established through the multi-hole connector 252, for example. The FCU/LCU 250 module without a recirculation line can still be used for pump arrangements where the fluid connection between the FCU 38 and the LCU 40 is not desired.

[0099] Returning now to discussions of the stiffening structure and the foot associated with a side-mounted pump module (e.g., 14 of Figures 1 to 5), Figure 10 illustrates a pump module foot 18 that is fully adjustable for support the extended portion of the pump module over any type of ocean floor terrain. Although the arrangement of Figures 1 to 5 show a single foot 18 for the pump module, multiple feet 18 such as that shown in Figure 10 can be used to support a single pump module.

[0100] The adjustable foot 18 can be positioned on and attached to a rigid or flexible base 108, which may include a mud mat, a suction anchor, or a pile. The lightweight/modular aspects of the pump module may allow the use of a mud mat (which is the cheapest) for the base 108, rather than a suction anchor or a stack. However, any of these or any other type of base 108 can be used with foot 18.

[0101] The foot 18 may include a platform 270 on its upper surface intended to directly engage a lower portion of the pump module components that are positioned on the foot 18. Adjustable poles or a support 272 that extend upwards from the platform may engage a complementary section of the ESP, subsea centrifugal pump, U-shaped conduit and/or pump module stiffening structure.

[0102] Foot 18 can be adjusted when using an ROV. For example, an ROV interface can drive a screw impeller, a pair of scissors, or something else. A hydraulic actuator (eg with a mechanical lock) can be used to adjust foot 18 in some embodiments. Foot 18 adjustments can allow the pump module to adapt to ocean floor terrain, changing subsea conditions, and more. Tuning can be performed entirely using the ROV and without human touch.

[0103] The foot can feature the vertical adjustability (up/down) 274 of the platform 270 in relation to the base 108, the lateral adjustability 276 of the platform 270 and/or the support 272 in relation to the base 108, the angle adjustability of the foot (e.g., rotation of the platform around the X or Y axes), and the adjustability of the rotation (about the Z axis) of the platform 270 relative to the base 108. The adjustable guide/support pins 272 can be used to adjusting the vertical position, horizontal position, pitch or yaw of the horizontally extended portion of the pump module relative to the base 108. Interfacing the remainder of the pump module with the adjustable guide/support pins 272 can allow the ESP to be restored from the 18th foot and replaced relatively easily without the 18th foot having to be adjusted to the ground again. The adjustability of the foot 18 in the horizontal direction can allow the system to handle the thermal expansion of the ESP during operation. Foot 18 adjustability can still provide load leveling.

[0104] Returning now to Figures 11A to 11D, various arrangements of the stiffening structure 106 (or beam structure) of the pump module 14 will now be described. These stiffening frame arrangements can be used specifically on pump modules 14 that include the U-shaped conduit 90 such that both connections are provided at one end 100 of the pump module 14. In addition, the stiffening structures 106 illustrated incorporate the U-shaped conduit 90 into the beam structure. In Figures 11A to 11D, one foot of the U-shaped conduit 90 includes the ESP 16, while the other includes a return tube 310. The ESP 16 and the return tube 310 are coupled at the opposite end of the rocker arm. end 100 with the connectors.

[0105] The following illustrations show each pump module 14 simplified as a rocker arrangement and indicate the support points 312, the arching points 314, the horizontal beam members 316 (containing the ESP 16 and the return pipe 310 ), cross beam members 318 coupled between horizontal beam members 316, and diagonal beam members 320 coupled between horizontal beam members 316. Horizontal beam members 316 include an upper horizontal beam member 316A and a horizontal beam member 316A. bottom crossbeam 316B that are substantially parallel and separated by a vertical distance. Support points 312 are the locations where the weight of the pump module 14 is being supported, for example by a foot or by the base module. A reaction force in the vertical direction acts on the pump module 14 at these support points 312. As shown, the pump module 14 can be supported at or near the end 100 that mates with the base module (not shown). One or more support points 312 may be located along the pump module 14 at longitudinal points chosen through finite element analysis (FEA) to minimize bending of the longitudinal beam members 316 as the pump module 14 is installed.

[0106] The sagging points 314 are points that, due to various forces (for example, the mass of the rocker arm and/or its components) must "bend" due to gravity. Bow points 314 are located generally between adjacent support points 312 and at the far horizontal end of pump module 14 opposite base module 12. Bow points 314 are where the greatest amount of downward displacement of the horizontal beam members occurs 316 due to the weight of the pump module 14. The pump module 14 may have one or more sag points 314, depending on the number of additional support points 312 and their locations along the pump module 14. In Figures 11A to 11C , for example, the pump module 14 has an external camber point 314 at the end of the pump module, and an internal camber point between the interface support point 312 and the support platform support point 312. In the Figure 11D, the pump module 14 may have three buckling points 314, one at each end of the pump module 14 and the other between the two support points 312.

[0107] The beam members 318 and 320 can be arranged between the horizontal beam member 316 specifically to distribute the mechanical loads that are acting on the ESP 16 and the return pipe 310 when the pump module 14 is installed. This can prevent the longitudinal beam members 316 from sagging at the camber points 314. The transverse beam members 318 can connect the longitudinal beam members 316 at or near the camber points 314. The transverse (vertically oriented) beam members 318 can be designed to be loaded in compression during use. In this way, these transverse beam members 318 can be relatively thick and heavy and as short as possible (eg, orthogonal to both longitudinal beam members 316).

[0108] The diagonal beam members 320 can connect the different longitudinal points of the two longitudinal beam members 316A and 316B. The diagonal rafter members 320 are generally oriented to be loaded in tension in order to counteract gravity-induced "sag" at the sag points 314. Specifically, a connection 322 between a diagonal rafter member 320 and the lower horizontal rafter member 316B may be closer to the closest camber point 314 than the corresponding connection 324 between diagonal beam member 320 and upper horizontal beam member 316A (closest to support point 312). In this way, the sag point 314 is prevented from sagging through tension in the diagonal beam members on either side of the sag point 314. Since the diagonal beam members 320 are loaded in tension, they need not be strong. to deformation and therefore can be relatively thin (eg plates). The tension between the upper and lower horizontal beam members 316 can be displaced by compression through the cross beam members 318.

[0109] Figure 16 provides a relatively detailed view of an exemplary beam arrangement. The beam arrangement shows thin plate-like diagonal beam members 320 and thicker transverse beam members 318 coupled between two longitudinal beam members 316, one of which contains the ESP 16. As shown, the beam members 318 and 320 can be attached to longitudinal beam members 316 through clamps 450.

[0110] As shown in Figure 1A, the horizontally oriented pump module 14 may include a stiffening frame 106 having plate-like beam members that are relatively trapezoidal in shape. A schematic plan view of such a plate-type beam member 470 is illustrated in Figure 15. An upper hole 472 in the trapezoidal plate-type beam member 470 may be arranged around and/or attached to the foot of smaller diameter piping. (eg, 96B of Figure 1) from the pump module U-shaped conduit (eg, 90 of Figure 1). Similarly, a smaller hole 474 in the trapezoidal plate-type beam member 470 may be arranged around and/or attached to the foot of the larger diameter pipe (eg, 96A of Figure 1) containing the ESP. The trapezoidal plate-type beam member 470 can be used to form the transverse beam members that are loaded in compression between the two legs (eg, 96 of Figure 1) of the pump module 14. The wider beam design may increase the lateral stiffness of the beam structure.

[0111] By maximizing the use of diagonal beam members 320 (which may be lightweight) loaded in tension and minimizing the mass of cross members 318 (which resist deformation) loaded in compression, the pump module 14 can be significantly stiffened without increasing the mass of the pump module 14. An ESP 16 may have a maximum allowable curvature (eg, 1 degree per 30.48 meters (100 linear feet)) that can be tolerated during operation. By keeping the ESP 16 aligned horizontally, the service life of the pump module 14 is increased. Furthermore, reducing the weight of the pump module 14 in this manner reduces the manufacturing and installation costs associated with the pump module 14.

[0112] Figure 11E illustrates another simplified rocker arrangement of a pump module 14, and this pump module 14 has multiple ESPs 16 arranged in it in series and both connection points at the same end 100 of the pump module 14 The stiffening structure 106 is shown as having four longitudinal beam members 316, transverse beam members 318 which extend vertically and are coupled to each of the four longitudinal beam members 316, and multiple diagonal beam members 320 each of which it extends between immediately adjacent longitudinal beam members 316. Support points 312 and camber points 314 are further illustrated.

[0113] Figures 12A to 12C illustrate arrangements of stiffening structures that may be used specifically in pump modules 350 that do not include a U-shaped conduit, but instead have a "jumper" construction. This means that the pump module 350 has an inlet 352 at one longitudinal end and an outlet 354 at the opposite longitudinal end. The illustrated stiffening structures 106 may incorporate the ESP conduit 16 into the beam structure. In Figures 12A and 12B, the pump module 350 may include the main conduit with the ESP 16 as a longitudinal beam member 316, as well as an additional lower longitudinal beam member 316.

[0114] The following illustrations show each pump module 350 simplified as a rocker arrangement and indicating the support points 312, the arching points 314, the horizontal beam members 316 (containing the ESP 16 and the return tube 310 ), the transverse beam members 318 coupled between the horizontal beam members 316, and the diagonal beam members 320 coupled between the horizontal beam members 316. These strength points and elements in the stiffening structure 106 of the type pump module "jumper" 350 can have the same general meanings and follow the same charging rules that have been fully described above with respect to pump module 14 in Figures 11A through 11E. In these "jumper" pump modules 350, however, both opposite ends of the module 350 are supported (312), which means that the modules 350 generally only have one point of camber 314, typically near the longitudinal center of the same.

[0115] Figure 12C illustrates another simplified rocker arm arrangement of the jumper pump module 350, in which it contains multiple ESPs 16 arranged in series therein and connection points at opposite ends of the pump module 350. The structure stiffening 106 in this case may include three longitudinal beam members, transverse beam members 318 that extend vertically and coupled to each of the three longitudinal beam members 316, and multiple diagonal beam members 320 each of which extends between the immediately adjacent longitudinal beam members 316. Support points 312 and camber points 314 are further illustrated.

[0116] Figure 18 illustrates a jumper pump module 350 having substantially discharged goosenecks 530, in accordance with the present invention. The jumper pump module 350 extends from a base module 532 to a second base module 534. The jumper pump module 350 directs and enhances the flow of production fluid from the first base module 532 to the second module base 534 through at least one ESP 16 in jumper module 350. Goosenecks 530 on either side of the interface of jumper pump module 350 interface directly with base modules 532 and 534 to provide the fluid connection between base modules 532 and 534 and module 350. Jumper pump module 350 is supported directly through contact with first and second base modules 352 and 354. A stiffening structure (eg, beam or rocker frame) 536 of the jumper pump module 350 can be disposed directly on the base modules 352 and 354 on either side of the module 350. The support points for the jumper pump module 350 are located directly on the stiffening structure 536 of the module 350, thereby removing all loads from the goosenecks 530 at either end of the jumper pump module 350.

[0117] Figure 19 illustrates in more detail an exemplary interface between the stiffening beam structure 536 of the jumper pump module 350 and one of the base modules (eg, 534). The base module 534 may include a flange 538 intended to fluidly seal against the gooseneck 530 and secure the gooseneck 530 in place, thereby facilitating the fluid connection between the base module 534 and the jumper pump module in bridge 350. However, gooseneck 530 and its associated connection to flange 538 are not loaded with any significant amount of weight from jumper pump module 350. Instead, loads from module 350 are transferred to the base module 354 directly from the stiffening structure 536. The stiffening structure 536 can be interfaced with the base module 354 through a connector 540 (e.g., a slip shoe) seated on the flange 538 in a position around the neck of goose down 530. Connector 540 may include sliding interfaces 542 that allow stiffening structure 536 and together with jumper pump module 530 to slide horizontally relative to base module and 534 in response to thermal expansion. Connector 540 may further include a hinged interface 544 that allows stiffening structure 536 and jumper pump module 350 to rotate about at least certain axes to facilitate proper positioning of jumper pump module 350 between the two base modules while the goosenecks 530 are kept unloaded.

[0118] Returning now to Figures 13A and 13B, embodiments of a vertically oriented top-mounted ESP module 390 are provided. A rocker structure can allow vertical mounting of one or more ESPs in a module mounted on top of a module base. With sufficient stiffening, the ESP(s) can be kept within the bending specification. In Figure 13A, the ESP pump module 390 includes a simple outflow and return passage having two vertical piping sections 392 connected at an upper U-shaped bend 394. The stiffening arrangement in this case may include a two-dimensional shear beam 396. In Figure 13B, the ESP pump module 390 includes a two-pass module having four vertical piping sections 394 connected by two upper U-bends 394 and a lower U-bend 398 The stiffening arrangement in this case may include a plurality of angle beams 400 positioned between the four vertical piping sections 392.

[0119] Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made in the present document without departing from the character and scope of the invention as defined by the following claims.

Claims (7)

1. Subsea pump arrangement, characterized in that it comprises: a base module (12) comprising a foundation (20), in particular a mud mat, a suction anchor, or stack, an inlet connector (24) , an output connector (26) fluidly coupled to the input connector, and at least one pump module connector (32) disposed between the input connector (24) and the output connector (26); a pump module (14) separated in a horizontal direction from the base module (12), the pump module (14) comprising a fluid inlet (92) fluidly coupled to the inlet connector (24) and an outlet (94) fluidly coupled to the outlet connector (26), and wherein the fluid inlet (92) and fluid outlet (94) are disposed only at one horizontal end (100) of the pump module ( 14) to couple the fluid inlet (92) and fluid outlet (94) to the base module (12); and a foot (18) that at least partially supports the pump module (14), particularly supporting at least 50% of the weight of the pump module (14), wherein the foot (18) is separate from the base module (12) over a distance, in particular over a distance of more than three metres, and wherein the base module (12) further comprises a fluid conditioning unit (FCU) (38) arranged between the inlet connector (24) and at least a pump module connector (32), a liquid collection unit (LCU) (40) disposed between at least one pump module connector (32) and the output connector (26). 2. Subsea pump arrangement according to claim 1, characterized in that the base module (12) additionally comprises a recirculation line (42), which in particular comprises a blocker (44), arranged between the LCU ( 40) and the FCU (38). 3. Subsea pump arrangement according to claim 1 or 2, characterized in that the pump module (14) further comprises: a conduit or U-shaped pipe (90) with the fluid inlet (92) and the fluid outlet (94) at one end only (100), the U-shaped conduit or pipe (90) comprising two horizontally oriented legs (96A and 96B); and at least one electric submersible pump (ESP) (16) disposed in one or both horizontally oriented legs (96A and 96B) of the U-shaped conduit or pipe (90). 4. Subsea pump arrangement according to any one of claims 1 to 3, characterized in that it additionally comprises a first dual bore connector part (98) which extends from the pump module (14) and the which is oriented vertically downwards when the pump module (14) is installed in the base module (12), and a complementary dual bore connector portion (32) which extends from the base module (12) and the which is oriented vertically upwards towards the interface with the dual bore connector portion (98) of the pump module (14). 5. Subsea pump arrangement according to any one of claims 1 to 4, characterized in that the pump module (14) comprises a stiffening structure (106) comprising one or more of a beam structure, ribs of stiffening, stiffening rockers or pipes, and additional U-shaped ducts or pipes. 6. Subsea pump arrangement according to any one of claims 1 to 5, characterized in that the pump module (14) comprises load limiting elements (430) comprising one or more of buoyancy elements, tanks filled with gas, or gas-filled piping elements, in particular located at at least one of: an end opposite with respect to the fluid inlet (92) and the fluid outlet (94); and a midpoint between the foot (18) and the base module (12). 7. Subsea pump arrangement according to any one of claims 1 to 6, characterized in that the foot (18) comprises a base (108) configured to stabilize a position of the pump module (14) on an ocean floor and a platform (270) coupled to the base (108) and adjustable to position the pump module (14) at different heights, orientations or lateral positions in relation to the base (108) of the foot (18).

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