CROSS REFERENCE TO RELATED APPLICATIONS

The present PCT Patent Application claims priority to U.S. Provisional Patent Application No. 62/297,390 entitled "Flexible Subsea Pump Arrangement" and filed on February 19, 2016, Norwegian Patent Application No. 20160416 entitled "Flexible Subsea Pump Arrangement" and filed on March 11, 2016, and "U.S. Provisional Patent Application No. 62/384,520 entitled "Modular Production System" and filed on September 7, 2016. All of these applications are hereby incorporated by reference in their entirety and for all purposes.

TECHNICAL FIELD

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

BACKGROUND

Hydrocarbon production from a wellhead may involve the use of various equipment, such as pumps, compressors, separators, heat exchangers, and the like. In some cases, reservoir properties may change over time. A production system that works well at the beginning of production may require additional components across the lifetime of the field. However, constraints on capital expenditures may prevent the installation of components that, at some point, may be desirable.

In addition, production from a wellhead may entail the use of boosting (e.g., via pump equipment). Boosting may be particularly useful in subsea production systems, in which a wellstream originating at a wellhead on the seafloor requires additional pressure in the flowline to reach a topside or onshore facility. Subsea pumping can increase the value of an offshore field significantly. Some technology for subsea pumping is complicated, and can lead to issues related to cost of installation/maintenance and reliability of the equipment. It is now recognized that a need exists for subsea pump arrangements resulting in lower cost over the life of such equipment. SUMMARY

In accordance with the above, presently disclosed embodiments are directed to a subsea pump arrangement including a base module, a pump module, and a foot. The base module includes a foundation, particularly a mud mat, suction anchor, or pile, an inlet connector, an outlet connector fluidicly coupled to the inlet connector, and at least one pump module connector disposed between the inlet connector and the outlet connector. The pump module is separated in a horizontal direction from the base module and includes a fluid inlet fluidicly coupled to the inlet connector and a fluid outlet fluidicly coupled to the outlet connector. Both the fluid inlet and the fluid outlet are disposed at only one horizontal end of the pump module for coupling both the fluid inlet and the fluid outlet to the base module. The foot is at least partially supporting the pump module, particularly supporting at least 50% of the weight of the pump module, particularly including at least 80% of the weight of the pump module, and the foot is separated from the base module by a distance, particularly by a distance greater than three meters, particularly including a distance greater than six meters.

In addition, presently disclosed embodiments are directed to a modular subsea production system for producing hydrocarbons. The modular subsea production system includes a base module having a plurality of connection interfaces, particularly wet-mated interfaces configured to connect subsea. The modular subsea production system also includes a satellite module having one or more production equipment components, wherein the satellite module is removably connected to the base module at one or more of the connection interfaces.

In addition, presently disclosed embodiments are directed to a fluid conditioning module. The fluid conditioning module includes a fluid conditioner unit (FCU) and a liquid collecting unit (LCU) configured to receive a fluid flow through an inlet and separate out a portion of liquid from the fluid flow. The fluid conditioning module optionally includes a recirculation line, particularly comprising a choke, fluidly coupled between the FCU and the LCU and configured to direct the portion of liquid from the LCU to the FCU. The fluid conditioning module includes a multi-bore connector disposed on a surface of the fluid conditioning module and configured to fluidly couple the FCU and/or the LCU to a base module.

In addition, presently disclosed embodiments are directed 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 pitch of the pump module, or a yaw of the pump module.

In addition, presently disclosed embodiments are directed to a pump module for producing a petroleum wellstream. The pump module includes an upper longitudinal truss member, a lower longitudinal truss member, two or more support points, a sag point, a transverse truss member, and a diagonal truss member. At least one of the upper longitudinal truss member and the lower longitudinal truss member includes a tubular casing having an inlet and an outlet, and at least one machine disposed within the tubular casing between the inlet and outlet, particularly an ESP. The two or more support points are configured to couple to a vertical support of the pump module, the support points coupled to at least one of the upper and lower longitudinal truss members. The sag point is identifying an expected maximum deformation of the upper and lower longitudinal truss members due to gravity. The transverse truss member is connecting the upper and lower longitudinal truss members proximate the sag point. The diagonal truss member is connecting the upper and lower longitudinal truss members wherein the diagonal truss member is designed for tensile loading and connecting the lower longitudinal truss member at a lower connection point to the upper longitudinal truss element at an upper connection point, wherein the lower connection point is closer to the sag point, and wherein the upper connection point is closer to the nearest support point.

In addition, presently disclosed embodiments are directed to a modular production system for producing 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, particularly further comprising a Christmas tree coupling configured to mechanically couple a Christmas tree to the base module; and a pump, particularly a subsea pump, disposed on the base module and fluidly coupled to an FCU, LCU, and recirculation line each disposed on the base module, wherein the base module with the subsea pump, FCU, LCU, and recirculation line is configured to be installed at a subsea location in a single trip.

Further, presently disclosed embodiments are directed to a system including a first frame portion configured to receive and support a base module of a subsea pump arrangement, and a second frame portion directly coupled to the first frame portion, particularly via a hinged or rigid connection, wherein the second frame portion is configured to receive and support a subsea pump, particularly an ESP. The second frame portion comprises an elongated shape that extends in a direction longitudinally outward from the first frame portion, wherein the first frame portion is taller in a height dimension and wider in a width dimension than the second frame portion. BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 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 disclosure;

FIG. IB is a schematic representation of the bending moments on the pump module of FIG. 1A, in accordance with an embodiment of the present disclosure;

FIG. 2 is a schematic diagram of a modular subsea pump system having two ESPs, in accordance with an embodiment of the present disclosure;

FIGS. 3 A and 3B are top and side schematic views of the modular subsea pump system of FIG. 2, in accordance with an embodiment of the present disclosure;

FIG. 4 is a side schematic view of a pump module of the modular subsea pump system of FIGS. 3 A and 3B being lowered or raised, in accordance with an embodiment of the present disclosure;

FIGS. 5 A and 5B are top and side schematic views of a modular subsea pump system equipped with trawling, in accordance with an embodiment of the present disclosure;

FIG. 6 is a schematic block diagram illustrating a modular subsea equipment arrangement, in accordance with an embodiment of the present disclosure;

FIG. 7 is a schematic diagram of a modular subsea equipment arrangement including a flow conditioner unit (FCU) and a liquid collection unit (LCU) disposed on separate modules, in accordance with an embodiment of the present disclosure;

FIG. 8 is a schematic diagram of an FCU, LCU, and associated flow circuit, in accordance with an embodiment of the present disclosure;

FIG. 9 is a perspective view of an FCU and LCU disposed in a single module, in accordance with an embodiment of the present disclosure;

FIG. 10 is a perspective view of an adjustable base for supporting a subsea pump module, in accordance with an embodiment of the present disclosure;

FIGS. 1 lA-1 IE are schematic diagrams of support beam arrangements for a subsea pump module having an inlet and outlet on the same side, in accordance with an embodiment of the present disclosure;

FIGS. 12A-12C are schematic diagrams of support beam arrangements for a subsea pump module having an inlet and outlet on opposite sides, in accordance with an embodiment of the present disclosure;

FIGS. 13A and 13B are schematic diagrams of vertically mounted subsea pump modules, in accordance with an embodiment of the present disclosure;

FIG. 14 is a schematic diagram of a subsea pump module equipped with buoys, in accordance with an embodiment of the present disclosure;

FIG. 15 is a schematic cross sectional view of a truss structure in a subsea pump module, in accordance with an embodiment of the present disclosure;

FIG. 16 is a perspective view of a truss structure in a subsea pump module, in accordance with an embodiment of the present disclosure;

FIG. 17 is a schematic diagram of a pump module being installed at a subsea location, in accordance with an embodiment of the present disclosure;

FIG. 18 is a perspective view of a subsea pump module with support points directly on a beam structure of the pump module and unloaded goosenecks, in accordance with an embodiment of the present disclosure;

FIG. 19 is a perspective view of one of the support points of the pump module of FIG.

18, in accordance with an embodiment of the present disclosure;

FIG. 20 is a schematic diagram of a base module coupled to a wellhead via a connector, in accordance with an embodiment of the present disclosure;

FIG. 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 disclosure;

FIG. 22 is a side schematic view of a subsea pump system that can be lowered in a single trip, in accordance with an embodiment of the present disclosure; and

FIGS. 23 A and 23B are perspective views of a frame with trawling protection for use with the subsea module of FIG. 22, in accordance with an embodiment of the present disclosure.

DETAILED DESCRIPTION

Illustrative embodiments of the present disclosure are described in detail herein. In the interest of clarity, not all features of an actual implementation are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation specific decisions must be made to achieve developers' specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure. Furthermore, in no way should the following examples be read to limit, or define, the scope of the disclosure.

A demand exists for subsea pump arrangements resulting in 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 installation, repair or replacement of the equipment, upgrading or modifications to the equipment, effects on adjacent subsea equipment, and so forth. Based on ongoing incentives to reduce costs, it is desirable to install downhole pumps in a subsea environment. Such pumps, called electric submersible pumps (ESP), have been widely used in downhole environments to provide artificial lift in wells. Due to their mature design and sales quantity they can be regarded as a commodity item at a reasonably low cost. It is desirable to utilize such ESPs for subsea pumping. The term "subsea pumping" in the present context refers to the placement and use of an ESP at a subsea location on or near the seabed, not downhole in a well. However, installing such ESPs for subsea use poses significant challenges.

Embodiments of the present disclosure are directed to subsea pump arrangements that are designed to address and overcome the challenges associated with installing and efficiently operating ESPs in a subsea environment. Embodiments of the present disclosure are also directed to modular production equipment arrangements that enable low cost installation/operation and high adaptability of various combinations of well production equipment. Embodiments of the present disclosure are also directed to a separate and retrievable FCU/LCU module for use with subsea apparatus, such as pumps and compressors. Embodiments of the present disclosure are further directed to a foot used to support a horizontally oriented pump module. Further embodiments of the present disclosure are directed to a truss arrangement designed to reduce bending loads on a horizontally oriented pump module. Embodiments of the present disclosure are also directed to other modular production systems and pump arrangements that may be particularly useful in subsea environments. Turning now to the drawings, FIG. 1A illustrates a subsea pump arrangement 10 in accordance with the present disclosure. The subsea pump arrangement 10 is a modular pump arrangement 10 including 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 subsea pumping of production fluid extracted from a subsea wellbore. The ESP 16 may pressurize the production fluid to facilitate transfer of the production fluid from a subsea wellhead to a topsides facility. The pump module 14 may extend in a horizontal direction from the base module 12, as shown. The pump module 14 may be only partially supported by the base module 12 or not at all supported by the base module 12.

The phrase "only partially supported by the base module 12 or not at all supported by the base module 12" generally refers to having the weight of the pump module 14 not supported or 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 features for limiting or eliminating the weight of the pump module 14 that is supported by the base module 12. The base module 12 may generally include a separate base module support structure 20 for supporting the weight of the base module 12 above the seabed.

The modular subsea pump arrangement 10 may physically separate equipment components that do not require frequent or regular replacement/maintenance from equipment that is in larger demand for replacement or maintenance. Specifically, the equipment that does not require frequent or regular replacement/maintenance is disposed on the base module 12, while the ESPs 16 or other subsea pumps in larger demand for replacement/maintenance are located on the pump module 14. Using such an arrangement, the pump module 14 may be located horizontally apart from the base module 12, thereby providing a subsea pump that is low weight, easily accessible, and particularly adapted for easy and safe installation/retrieval. In addition, the installation time for the subsea pump arrangement 10 may be minimized since only two units 12 and 14 would need to be installed/connected. Due to the low weight of the pump module 14, a light intervention vessel may be used for retrieval and installation of the pump module 14.

The phrase "located horizontally apart from the base module 12" refers to the pump module 14 being separated in a direction in principle 90 degrees from vertical. This separation may provide improved access for installing and retrieving the pump module 14, resulting in faster, safer, and less expensive installation and retrieval operations. Except for in instances where a trawl protective structure is desired, there is typically no restriction to accessing the pump module 14 from above in the modular subsea pump arrangement 10.

Various additional features of the modular subsea pump arrangement 10 of FIG. 1A will be described in greater detail throughout the following detailed description.

As mentioned above, the weight of the pump module 14 may be "partially" supported by the foot 18. The placement of the foot 18 relative to a connector end 100 of the pump module 14 may be selected such that a portion of the weight of the pump module 14 is supported by the base module 12 and another, larger portion of the weight of the pump module 14 is supported by the foot 18. FIG. IB schematically represents the bending moments that may be present at various points along the length of the pump module 14. The foot 18 of the pump module 14 may be positioned at a predetermined horizontal distance 590 from the connector end 100 of the pump module 14. This distance 590 may be determined based on the expected bending moments at various support points 312 and sag points 314 along the pump module 14. The support points 312 are locations where the weight of the pump module 14 is being supported by, for example, the foot 18 or the base module (e.g., 12 of FIG. 1A). The sag points 314 are points that, due to various forces (e.g., mass of the pump module 14 and/or its components) is expected to "sag" due to gravity.

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 a sag 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 are 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 indicated as Ml, and the "downward" bending moment of the pump module 14 at the sag point 314 is indicated as M2. The foot 18 may be positioned along the length of the pump module 14 such that the magnitude of Ml (moment at the foot 18) is approximately equal to, within approximately 10% of, or within approximately 20% of, the magnitude of M2 (moment at the sag point 314). This may help to keep the bending forces on the pump module 14 relatively low. To meet this criteria, it may be necessary for a portion of the pump module weight to be supported by the base module interacting with the connector end 100 of the pump module 14. Specifically, the base module may support, for example, at least 2% of the pump module weight, between approximately 5% and 25% of the pump module weight, or between approximately 10% to 20% of the pump module weight. The foot 18 may be positioned such that the foot 18 supports at least 50% of the pump module weight, or at least 80% of the pump module weight. The foot 18 may be positioned a certain minimum distance from the connector end 100 (and the base module) to meet this criteria as well. For example, the foot 18 may be positioned at least 3 meters from the base module, at least 6 meters from the base module, or some other minimum distance from the base module.

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

As mentioned above, the modular subsea pump arrangement 10 is designed such that the base module 12 includes components that are not likely to need much maintenance throughout the life 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 outlet connector 26, at least one pump module connector 32 or connector part disposed between the inlet connector 24 and the outlet connector 26, and a number of isolation valves 34 and guideposts 36 (shown in FIG. 3B).

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

The foundation 22 generally supports the other components of the base module 12, and the foundation 22 may be resting on the seabed or elevated above the seabed via the base module support structure 20 (e.g., a pile, suction anchor, or mud-mat, depending on soil conditions). The inlet connector 24 may fluidly connect the base module 12 to a flow line from a subsea wellhead to direct a well flow 46 from the subsea wellhead into a flow line 48 of the base module 12. The well flow 46 may be routed through the flow line 48 to the FCU 38, into the pump module 14 where the flow is further pressurized, back to the base module 12 where it passes through the LCU 40, and through another flow line 50 before a boosted flow 52 is output through the outlet connector 26. By including the bypass line 28 and bypass valve 30 on the base module 12, an additional bypass jumper is not required for operation of the pump system.

Instead of having the illustrated FCU/LCU disposed on the base module 12, the base module 12 may include only an FCU 38 (or arrangement thereof), and optionally a recirculation line 42. That is, the base module 12 may not include the LCU 40 at all. The recirculation line 42, if included in the base module 12, may route separated gas from the FCU 38 directly to the flow line 50 during startup of the pump module 14. In other instances, a separate module containing an LCU 40 may be attached to the base module 12 for coupling to the FCU 38 (e.g., via recirculation line 42) disposed on the base module 12, so that gas and/or liquid may flow between the FCU 38 and LCU 40 throughout pump operations.

Instead of having the illustrated FCU/LCU disposed on the base module 12, the base module 12 may include only an LCU 40 (or 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, may route separated liquid from the LCU 40 directly to the flow line 48 during operation of the pump module 14. In other instances, a separate module containing an FCU 38 may be attached to the base module 12 for coupling to the LCU 40 (e.g., via recirculation line 42) disposed on the base module 12, so that gas and/or liquid may flow between the FCU 38 and LCU 40 throughout pump operations.

Fluid flow may be routed between the base module 12 and the pump module 14 via the at least one pump module connector 32. The at least one pump module connector 32 may include a dual bore connector allowing connection of the base module 12 to the pump suction and discharge, so that 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. The guideposts 36 of the base module 12 may facilitate relatively easy landing and coupling of the pump module 14 to the base module 12 during installation.

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

If two pumps (e.g., ESPs 16A and 16B) are being used in the pump module 14, the first leg 96A may contain the first ESP 16A and the second leg 96B may contain the second ESP 16B. The ESPs 16A and 16B may each be horizontally oriented, but oppositely directed, in the respective horizontally oriented canisters or pipe legs 96 A and 96B. If only one pump (e.g., ESP 16) is being used in the pump module 14 (e.g., as shown in FIG. 1), the ESP 16 may be disposed in the first leg 96A while the second leg 96B provides an empty return transfer pipe. In such instances, 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 total, may be horizontally oriented but arranged vertically one above the other, as shown. By providing a distance between the legs 96A and 96B of the U- shaped conduit 90, the illustrated pump arrangement enables easier handling, increased stiffness (due to ability to include a truss structure), and optional integration of buoyancy elements into the pump module 14.

The pump module 14 includes at least one base module connector 98, which may include connector parts 54 for the inlet and outlet of the ESP(s) 16 in the pump module 14. As illustrated, both of the connector parts 54 may be disposed in only one end 100 of the pump module 14. The at least one base module connector 98 may be oriented vertically downwards during installation of the pump module 14. The at least one base module connector 98 is designed to interface directly with the at least one pump module connector 32 of the base module 12 to fluidically couple the base module 12 to the pump module 14. The at least one base module connector 98 may include a dual-bore connector part, two separate single bore connector parts for the inlet and outlet, respectively, or one or more multi-bore connector parts.

The connector parts 54 may include flexible flow lines that are designed to interface with and be coupled to the at least one pump module connector 32. Such flexible flow lines may include steel tube flow lines that have an elongated section creating flexibility to bending without causing excessive stress or fatigue on the connection. The flexible flow lines may 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 sinking of the foot 18 / pump module 14 into the seabed soil over time.

The at least one pump module connector 32 on the base module 12 may include complementary connector parts 102 to those connector parts 54 of the base module connector 98. These complementary connector parts 102 may be oriented vertically upwards when the base module 12 is installed and designed to interface directly with the connector parts 54 of the base module connector 98 on the pump module 14. The connectors 32 and 98 may include clamp- or collet- type connectors that are operable by a remotely operated vehicle (ROV), and these connectors 32 and 98 may include a single dual-bore or multi-bore clamp connector.

The pump module 14 may include an ROV panel 104 that enables an ROV to interface with the ESP(s) 16 on the pump module 14. The ROV panel 104 may provide a power connection to the ESP(s) 16, as well as any hydraulic or electric connections needed for flow assurance or instrumentation on the ESP(s) 16. The ROV panel 104 may include an ROV docking structure including ROV receptacles or sockets with connectors or bores for providing hydraulics (for flow assurance) and/or electric power to the ESP(s) 16.

The pump module 14 may include a stiffening structure 106 connecting the two legs 96A and 96B of the U-shaped conduit 90. The stiffening structure 16 may provide stiffness to secure the structure of the pump module 14, thereby limiting sagging of the ESP(s) 16 to ensure appropriate rotor-dynamic stability of the motor/rotor of the pump and long service life. The stiffening structure 106 may provide a stiff, lightweight structure with improved stability and stiffness for handling during installation and retrieval. The stiffening structure 106 may include a truss structure, stiffening ribs, stiffening beams or pipes, additional U-shaped conduits or pipes that may or may not contain pumps and connector parts for later in-line coupling, among others.

As illustrated in FIG. 3B, for example, the stiffening structure 106 may be arranged by welding two steel plates onto the sides of the horizontal pipe sections (legs 96) of the U-shaped conduit 90. The plates may have materials removed to reduce weight in such a way that a trusslike pattern is created. These plates attached to the two legs 96 may thereby form a very stiff structure while keeping the weight low. Thus, the stiffening structure 106 may be a separate part from the legs 96 of the U-shaped conduit 90 that is coupled to the legs 96 to provide additional structural support.

In other arrangements, the two legs 96 of the U-shaped conduit 90 may act as portions of the stiffening structure 106 itself. This may further reduce the weight of the pump module 14 as no other longitudinal parts are needed to achieve a desired stiffness. The stiffening structure 106 in this instance may be formed by welding beams or plates directly to the horizontal pipe legs 96 of the U-shaped conduit 90 and extending between the two legs 96 to create a truss-like structure. This may be done, for example, by welding in plates having a 90 degree angle with respect to the horizontal pipe axes of the legs 96 and plates having approximately a 20 degree angle with respect to the horizontal pipe axes of the legs 96. It should be understood that other arrangements of the stiffening structure 106 may be utilized to maintain stiffness of the pump module 14 while keeping the weight of the pump module low 104 and integrating the two legs 96 in the stiffness structure 106. Thus, the two ESPs 16A and 16B may be horizontally oriented in the U-shaped conduit 90 with the legs 96A and 96B acting as load carrying members in a truss arrangement where the legs 96 are interlinked with steel members to form the stiffening structure 106.

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

As shown in FIG. 14, lifting points 496 may be positioned along the length of the horizontal pump module 14. The number and arrangement of lifting points 496 may be chosen to minimize bending during lifting/lowering of the pump module 14, for example, via a spreader bar (see FIG. 17). One of the lifting points 496 may be positioned above the foot 18 of the pump module 14. That way, the foot 18 may be integrated with the rest of the pump module 14 during installation as the pump module 14 is lowered via connections at the lifting points 496. This enables the foot 18 integrated with the pump module 14 to be installed in a single trip from a deployment vessel. The foot 18 may be adjustable via an ROV such that a base 108 of the foot 18 may be appropriately positioned and angled for landing the entire pump module 14 on the seabed.

As mentioned above, the pump module 14 generally includes a foot 18 for supporting a majority of the weight of the pump module 14 extending horizontally from the base module 12. As illustrated, the foot 18 may be resting on a small base 108 at the seafloor. The foot 18 may be releasable and connectable to the pump module 14, such that the foot 18 may be attached and hinged to the pump module 14 before being installed together with the pump module 14. The foot 18 may be released to its landing position during the final phase of the installation process. The rest of the pump module 14 may be removable from the foot 18 once the system is installed, thereby enabling the foot 18 to remain in place while the rest of the pump module 14 is being retrieved to the surface for service. In other instances, the foot 18 may be entirely fixed to the pump module 14.

The foot may include a height adjustment mechanism. This may help provide appropriate support to the pump module 14 in the event of a soft soil condition at the seafloor. The height adjustment mechanism may include an ROV torque tool operated mechanical screw adjustment, indicated as 110 in FIG. 3B. However, other types of height adjustment mechanisms may be utilized.

The pump module 14 may include transmitters for inclination, a water level or bubble level or bullseye, a height/position sensor for the pump module 14, and/or other instrumentation. These may help with landing and placement of the pump module 14 onto the base module 12 during installation. The pump module 14 may include guide funnels 107 designed to interface with and land on the guide posts 36 of the base module 12. This type of connection interface between the pump module 14 and base module 12 may aid in properly aligning the pump module 14 with respect to the base module 12 during installation.

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

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

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 ESP(s) 16. The pump module 14 may be vertically oriented as installed, instead of horizontally, and containing one or two subsea centrifugal pumps vertically oriented 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 FIGS. 13A and 13B. In some locations (e.g., topside, deep subsea), vertical orientation of the ESP module 390 may be possible.

The pump module 14 may include one or more subsea centrifugal pumps and/or ESPs, as disclosed above. The choice of pump type and number may be made according to well and/or field requirements. Subsea centrifugal pumps generally are short, squat, heavy, and demand higher power. ESPs have typically been designed for in-well use, and so are long and thin, and generally operate at lower power. Certain common differences between the pump types are outlined in Table 1 below.

Since the connection components of the pump module 14 may be arranged only in one end of the pump module 14, the other end may be free to move axially in response to temperature and pressure changes in the pump module 14 for various operational 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 installation size and weight of the system. Arranging the foot 18 at an axial distance of approximately 2/3 of the overall length from the connection side of the pump module 14 may reduce the deflection and stress on the legs 96A and 96B of the U-shaped conduit 90. Since the free end acts as a counterweight, the illustrated pipe arrangement effectively has a stiff anchor at the location of the foot 18.

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

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 at a subsea location. For example, the disclosed arrangement 10 may facilitate a 20% reduction in length of the pump module 14 compared to existing systems, a 25%-55% reduction in weight of the pump module 14 (depending on whether an FCU/LCU is present on the existing system). The reduction in size and weight of the components on the pump module 14 may be particularly useful when upgrading the system to a higher pressure rating since the pump module 14 has pressure containing items with a smaller diameter compared with a jumper arrangement having fluid conditioning equipment. Arranging the connector components of the pump module 14 on only one side may facilitate easy installation and retrieval since it allows for the use of a single dual-bore or double single-bore clamp connector, thereby reducing the number of critical fluid connector coupling operations.

FIG. 4 illustrates the pump module 14 of the subsea pump arrangement 10 being lifted via connection at two lifting points 130 coupled to the U-shaped conduit 90 and/or the stiffness structure 106. The lifting points 130 may be carefully positioned to reduce or minimize bending forces on the pump module 14 due to the weight of the on-board ESP(s) 16 during installation/retrieval.

FIGS. 5A and 5B illustrate the subsea pump arrangement 10 fully assembled and with trawling protection disposed thereon. The subsea pump arrangement 10 is generally suitable for the inclusion of trawling protection, as shown, since the modular pump arrangement 10 can be arranged close to the seafloor and with a low vertical height to limit the snagging profile of the protective equipment. As illustrated, a first protecting structure 150 may be arranged on the base module 12 and a second protection structure 152 may be arranged for the pump module 14. These trawling protection structures 150 and 152 may be supported by a suction anchor 154, but could also be supported by a pile or otherwise to take the loads that can occur during trawling. Hatches 156 that may be opened via ROV are located along the protection structures 150 and 152 to allow access during installation, retrieval, or service of the base module 12 and/or pump module 14. It should be noted that other arrangements of trawling protection than that shown in FIGS. 5A and 5B may be utilized with the disclosed subsea pump arrangement 10 having a relatively low height above the seafloor. FIG. 17 illustrates a pump module 14 being lowered into an installed position coupled to the base module 12. As shown, the pump module 14 may be lowered into this position via a spreader bar 490 that is deployed from a floating vessel. The spreader bar 490 may be lowered via a deployment wire 492 from above, and the spreader bar 490 may be coupled to the pump module 14 via several wires 494 extending downward from the spreader bar 490. The wires 494 may be attached to the pump module 14 at specific lifting points 496 disposed along the length of the horizontal pump module 14. The number and arrangement of lifting points 496 may be chosen to minimize bending during lifting/lowering of the pump module 14. The spreader bar 490 may be used to minimize longitudinal compressive forces.

FIG. 22 illustrates a pump arrangement 610 similar to the modular pump arrangement 10 of FIGS. 1-17, but with the base module 12 and pump module 14 coupled using a connector 612 supported at the base module 12. That way, the base module 12 and pump module 14 may be lowered or retrieved in a single 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, this extended base 614 interfacing directly with and, in some case, hinged to (via a hinge 616) the foundation 20 of the base module 12. The foundation 20 and extended base 614 may be equipped with lifting points 496, thereby enabling the entire assembly to be lowered to a subsea position using a spreader bar (as described above with reference to FIG. 17). The connector 612 may be disposed at the connector end 100 of the pump module 14. In some instances, the connector 612 may be adjustable to enable the pump module 14 to flex, slide laterally, rotate, and/or move vertically relative to the base module 12 as needed when positioning the system on the seafloor. The connector 612 may be configured to move similarly to the adjustable foot 18 in this regard.

In addition to, or in lieu of, the base module 12 and pump module 14 being coupled together via a connector (612) as shown in FIG. 22, the pump arrangement may utilize a "coupled" frame mechanism to support both the base module 12 and the pump module 14 (e.g., ESP). FIGS. 23 A and 23B illustrate an embodiment of one such frame mechanism 630. As shown, the frame mechanism 630 may include a first frame 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 just include an ESP or subsea centrifugal pump, without an additional foot). The first and second frame portions 632 and 634 may be coupled together, for example, via a hinge 636 or via a rigid connection at their interface. As shown, the first frame portion 632 may have a relatively elevated and wide box shape, while the second frame portion 634 may have a relatively lower, elongated, skinny 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 ESP may be installed into the "coupled" frame mechanism 630 and lowered in a single trip to a desired subsea location. To that end, the frame mechanism 630 may be equipped with a number of lifting points that may be used for lowering the frame mechanism 630 with the base module 12 and ESP installed therein via a spreader bar.

In some instances, as shown, the frame mechanism 630 may be equipped with trawling protection 638 that can be selectively rotated (hinged) out of the way to expose the interior of the frame mechanism 630. That way, the base module 12 and ESP can be selectively placed into the frame mechanism 630. The trawling protection 638 may include two separate structures (e.g., first structure 640 and second structure 642), and these may be separately moved out of the way so that, for example, when repair or replacement is needed on the ESP, only the second structure 642 of trawling protection would need to be moved out of the way for the ESP to be retrieved from the frame portion 634. Both pieces of the trawling protection 638 may have a generally trapezoidal shape to reduce trawl loading.

FIG. 6 illustrates a modular equipment arrangement 170 that may provide an extension of the modular pump arrangement described above. The modular equipment arrangement 170 may enable adaptability of a well production system to different amounts/types of hydrocarbons produced throughout the life of the well. The modular subsea equipment arrangement 170 generally includes at least a 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 thereof. Although various aspects of the production equipment are described herein in the context of a subsea environment, the disclosed modular equipment arrangement 170 may be similarly applied to onshore or topside implementations.

As shown in FIG. 20, the modular equipment arrangement 170 may include a wellhead support 550 configured to couple the base module 172 to a wellhead 552. The base module 172 may provide mechanical support to the wellhead 552 by "unloading" the wellhead 552 of forces that might otherwise be supported by the wellhead 552. Mechanical stress (e.g., fatigue) of the wellhead 552 may be reduced via the support of various components by the base module 172 rather than the wellhead 552.

The wellhead support 550 may clamp, locate, and/or otherwise couple the wellhead 552 to the base module 172, such that the base module 172 provides an extended "foot" around the wellhead 552 that reduces strain (e.g., bending) of the wellhead 552. Particularly for soft terrain (e.g., sand, mud) and/or a shallow reservoir (e.g., within a few hundred meters of the surface), the lateral dimensions of the base module 172 in combination with a gripped wellhead 552 may minimize strain on the wellhead 552.

The base module 172 may include one or more pillars, a suction anchor, a mud mat, and the like, according to the surface (e.g., the seabed) on which the base module 172 is disposed. Whereas the deformation of a typical wellhead is limited by the circumferential interaction of the wellhead itself with the surrounding terrain, a base module 172 that acts as a wellhead support may "extend" the area of interaction to a much larger area (e.g., greater than 10 times, 50 times, or even greater than 100 times the cross sectional area of the wellhead 552. A circumferential interaction region around a typical wellhead (e.g., 1-4 meters circumference) may be extended to a circumference of the base module 172 that is at least 25, including at least 50, including at least 100 meters long.

The base module 172 may include a Christmas tree 554 (e.g., fluidically 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 may be f uidly coupled to the wellhead 552. By combining the base module 172, wellhead support 550, and the Christmas tree 554, the loads typically imparted to the wellhead 552 (by the tree) may be transmitted directly to the surrounding terrain via the base module 172. The base module 172 may include a Christmas tree 554 and at least one of, including both of, an FCU 38 and an LCU 40.

In some embodiments, as shown in FIG. 21, the base module 172 may itself include a pump (e.g., subsea centrifugal pump or ESP) 570 disposed thereon. The pump 570 may be positioned on the base module 172, instead of on a satellite module that is separately deployed and coupled to the base module 172. The base module 172 may also include an FCU 38, LCU 40, and/or recirculation line 42 disposed thereon, as well as the other bypass lines, valves, and flow lines discussed above with reference to FIG. 2. This may facilitate a one-trip installation of the subsea pump arrangement.

Turning back to FIG. 6, the generalized base module 172 may include a plurality of connection interfaces 180 designed to receive and connect directly to the different satellite modules 174 that may be employed throughout the life of the well. The connection interfaces 180 may each include one or more of the following connections: wellstream out/in for communicating the flow of production fluids; hydraulic connections; electrical power connections; and control (e.g., electrical, optical) connections. A single satellite module 174 may be coupled to each of the plurality of connection interfaces 180. The connection interfaces 180 for side-mounted modules 176 may be disposed along the outer perimeter of the base module 172, while the connection interfaces 180 for top-mounted modules 178 may be disposed closer to the center of the base module 172. All of the connection interfaces 180 may be located on a top face of the base module 172, such that the base module 172 may provide an amount of support to each of the side mounted modules 176 coupled thereto.

The base module 172 may interface to any desirable number of additional satellite modules 174 (side mounted, top mounted, or both). The base module 172 may generally function like a motherboard to which satellite modules 174 containing various functional components of the production equipment may be selectively connected. This allows for 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, as opposed to the entire system. This may be particularly useful in subsea production contexts since adapting or providing maintenance to the production system would be possible using smaller vessels due to the relatively light weight of the equipment being deployed.

In addition, the modular equipment arrangement 170 may allow individual satellite modules 174 to be selectively removed for maintenance or replacement without having to also 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 FIGS. 1-5 and a side- mounted module 176 coupled to the base module 172 is similar to the pump module 14 of FIGS. 1-5. This arrangement enables the pump module 14 to be selectively removed and repaired or replaced without requiring a vessel to lift the heavier equipment of the base module 12 that does not require repair/replacement.

The modular equipment arrangement 170 of FIG. 6 may also allow for upgrades or adaptations to the production system to be made throughout the lifetime of the well. For example, as the flow from the well changes over time, additional satellite modules 174 may be incorporated into the arrangement 170 to provide the desired functionalities without having to replace the entire system. As an example, in some embodiments, the base module 172 may not come initially equipped with boosting functionalities. The system may initially operate well without an ESP or other subsea pump. However, as the well ages, the pressure of production flow from the well may decrease, and ESPs or other subsea pumps may need to be added via one or more satellite modules 174 to provide additional boosting.

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

Each of the satellite modules 174 may include equipment such as, for example, one or more ESPs, one or more subsea centrifugal pumps, a compressor, a cyclone, an FCU, an LCU, raw seawater injection components, turbomachinery, or a combination thereof. ESPs or subsea centrifugal pumps may be selectively attached as satellite modules 174 to tailor boosting of the well flow or to provide backup for when other pumps are retrieved/replaced. The ESPs or subsea centrifugal pumps may be included on side-mounted satellite modules 176 (as described above with reference to FIGS. 1-5), or on top-mounted satellite modules 178 (e.g., vertically oriented pumps as shown in FIGS 13A and 13B). In side-mounted satellite modules 176, the ESPs or subsea centrifugal pumps may include loaded or unloaded goosenecks.

As mentioned above, FCU/LCU components may be attached to the base module 172 as one or more separate and retrievable satellite modules 174. FIG. 7 illustrates an embodiment of a modular equipment arrangement where an FCU module 210, an LCU module 212, and a machine module 214 are coupled together. As described at length above, these modules 210, 212, and 214 may each be coupled together via a common base module (not shown; e.g., base module 172 of FIG. 6). The FCU module 210 may include an FCU 38, while 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, turbomachinery, a cyclone, or a separator. The FCU module 210 may be coupled to the base module such that the FCU 38 is fluidly coupled between an inlet 217, the machine 216 (via a flowline 218), and the LCU 40 (via the recirculation line 42). The LCU module 210 may be coupled to the base module such that the LCU 40 is fluidly coupled between an outlet 219, the machine 216 (via a flowline 220), and the FCU 38 (via the recirculation line 42). As illustrated, the FCU module 38 and the LCU module 40 may be separately retrievable and replaceable as needed. The function of the FCU/LCU equipment will now be described with reference to FIG. 8. The FCU/LCU equipment may be utilized in combination with a machine such as an ESP to prime the machine during startup or backfill the machine during shutdown. Production fluids from the wellhead including gas, liquid, and/or sand may enter the FCU 38 through the inlet 217. The FCU 38 separates the gas portion of the incoming production fluids from the liquid portion by allowing the gas and liquid portions to have different internal velocities. The lighter gas portion moves from the FCU 38 to the LCU 40 via the recirculation line 42 during startup of the machine 216. The heavy fraction of the production fluid (i.e., liquid and sand) sinks to the bottom of the FCU 38, and the liquid is routed to the machine 216 via the flow line 218 coupled to the bottom of the FCU 38. The liquid may help to prime the machine 216 so that it operates effectively when there is a relatively large amount of gas incoming from the wellhead.

The resulting gas, liquid, and sand output from the machine 216 is then routed to the LCU 40 via the flow line 220. The LCU 40 may separate the liquid from the gas again (similarly to the FCU 38). A large portion of the pressurized fluid (e.g., gas, liquid, and sand) received from the machine 216 may be routed through the outlet 219 for communication to a topsides facility. A portion of the liquid in the LCU 40 may be separated from the pressurized fluid flow by the LCU. The recirculation line 42 may direct the separated portion of liquid from the LCU to the FCU during operation of the machine 216. This liquid portion may later be used to prime the machine 216 during a cold start. That is, the liquid may be provided to the machine 216 from the FCU 38 first before new production fluid is routed from the FCU 38 to the machine 216 in order to keep the machine 216 from stalling due to gas within the machine 216.

The FCU/LCU equipment may be positioned on a base module (e.g., 12, 172) as a single self-contained FCU/LCU module 250, as illustrated in FIG. 9. As shown, the FCU/LCU module 250 may include the FCU 38, the LCU 40, and the recirculation line 42, and the recirculation choke 44. The FCU/LCU module 250 may also include a vertically oriented multi-bore connector 252 disposed on a bottom surface of the FCU/LCU module 250. The multi-bore connector 252 may include connections for each of the flow lines (e.g., 217, 218, 219, and 220) described above with reference to FIG. 8. The specific flow lines are not all visible from the perspective of the illustration, however they are generally located at the multi-bore connector on the bottom surface of the FCU/LCU module 250. The multi-bore connector 252 may facilitate connection of the FCU/LCU module 250 to a base module such as 172 of FIG. 6. In the present arrangement, the FCU/LCU module 250 may act as a top-mounted satellite module (e.g., 178 of FIG. 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 of these structures. The FCU/LCU module 250 may include one or more locator components 256 such as guide funnels designed to help orient and align the FCU/LCU module 250 to a desired position on the base module during installation of the FCU/LCU module 250.

The recirculation choke valve 44 may be removable and retrievable separate from the other components of the FCU/LCU module 250. The recirculation choke valve 44 may be disposed on a side of the FCU/LCU module 250 where the protective frame 254 is relatively open.

The recirculation line 42 may be an optional feature of the FCU/LCU module 250. That is, some embodiments of the FCU/LCU module 250 may include just the FCU 38 and the LCU 40 disposed thereon, without the recirculation line 42 and choke 44. In such instances, a recirculation line 42 (which may include a choke 44) may be disposed on the base module (e.g., 12, 172) to which the FCU/LCU module 250 is removably attached. Connections from the FCU 38 and LCU 40 to a recirculation line on the base module may be established via the multi-bore connector 252, for example. The FCU/LCU module 250 without a recirculation line may also be utilized for pump arrangements where fluid connection between the FCU 38 and LCU 40 are not desired.

Turning now back to discussions of the stiffness structure and the foot associated with a side mounted pump module (e.g., 14 of FIGS. 1-5), FIG. 10 illustrates a pump module foot 18 that is fully adjustable for supporting the extended portion of the pump module over any type of seafloor terrain. Although the arrangement of FIGS. 1-5 show a single foot 18 for the pump module, multiple feet 18 such as the one shown in FIG. 10 may be utilized to support a single pump module.

The adjustable foot 18 may be positioned on and coupled to a stiff 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 enable the use of a mud mat (which is cheapest) for the base 108, as opposed to a suction anchor or pile. However, any of these or any other type of base 108 may be used with the foot 18.

The foot 18 may include a platform 270 on its upper surface designed to directly engage a bottom portion of the pump module components that are positioned on the foot 18. Adjustable poles or a cradle 272 extending upward from the platform may engage a complementary section of the ESP, subsea centrifugal pump, U-shaped conduit, and/or stiffness structure of the pump module. The foot 18 may be adjusted using an ROV. For example, an ROV interface may actuate a lead screw, scissors, or the like. A hydraulic actuator (e.g., with a mechanical lock) may be used to adjust the foot 18 in some embodiments. Adjustments to the foot 18 may enable the pump module to adapt to the terrain of the seafloor, subsea condition changes, and others. The adjustment can be carried out entirely using the ROV and without human touch.

The foot may feature vertical (up/down) adjustability 274 of the platform 270 relative to the base 108, sideways adjustability 276 of the platform 270 and/or cradle 272 relative to the base 108, foot angle adjustability (e.g., rotation of platform about the X or Y axes), and rotation adjustability (about the Z axis) of the platform 270 relative to the base 108. The adjustable guide poles/cradle 272 may be used to adjust the vertical position, horizontal position, pitch or yaw of the horizontally extended portion of the pump module relative to the base 108. The interface of the rest of the pump module with the adjustable guide poles/cradle 272 may enable the ESP to be retrieved from the foot 18 and replaced relatively easily without the foot 18 having to be adjusted to the terrain again. The adjustability of the foot 18 in the horizontal direction may enable the system to handle thermal expansion of the ESP during operation. The adjustability of the foot 18 may also provide load leveling.

Turning now to FIGS. 11A-11D, various arrangements of the stiffening structure 106 (or truss structure) of the pump module 14 will now be described. These stiffening structure arrangements may be utilized specifically in pump modules 14 including the U-shaped conduit 90 such that both connections are provided on the one end 100 of the pump module 14. In addition, the illustrated stiffening structures 106 incorporate the U-shaped conduit 90 into the truss structure. In FIGS. 11A-11D, one of the legs of the U-shaped conduit 90 includes the ESP 16, while the other one includes a return tube 310. The ESP 16 and return tube 310 are coupled at the opposite end of the beam from the end 100 with the connectors.

The following illustrations show each pump module 14 simplified as a beam arrangement and indicating support points 312, sag points 314, horizontal truss members 316 (containing the ESP 16 and the return tube 310), transverse truss members 318 coupled between the horizontal truss members 316, and diagonal truss members 320 coupled between the horizontal truss members 316. The horizontal truss members 316 include an upper horizontal truss member 316A and a lower horizontal truss member 316B that are substantially parallel and separated by a vertical distance. The support points 312 are locations where the weight of the pump module 14 is being supported by, for example, a foot or the base module. A reactive force in the vertical direction acts on the pump module 14 at these support points 312. As shown, the pump module 14 may be supported at or near the end 100 that couples to the base module (not shown). Another one or more support points 312 may be located along the pump module 14 at longitudinal points chosen via finite element analysis (FEA) to minimize bending of the longitudinal truss members 316 once the pump module 14 is installed.

The sag points 314 are points that, due to various forces (e.g., mass of the beam and/or its components) is expected to "sag" due to gravity. The sag points 314 are generally located between adjacent support points 312 and at the far horizontal end of the pump module 14 opposite the base module 12. The sag points 314 are where the greatest amount of downward displacement of the horizontal truss members 316 occurs 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 FIGS. 11A-11C, for example, the pump module 14 has an outer sag point 314 at the end of the pump module, and an inner sag point between the interface support point 312 and the support platform support point 312. In FIG. 11D the pump module 14 may have three sag points 314, one at each end of the pump module 14 and the other between the two support points 312.

The truss members 318 and 320 may be arranged between the horizontal truss member 316 specifically to distribute the mechanical loads that are acting on the ESP 16 and return tube 310 when the pump module 14 is installed. This may keep the longitudinal truss members 316 from sagging at the sag points 314. The transverse truss members 318 may connect the longitudinal truss members 316 at or near the sag points 314. The transverse (vertically oriented) truss members 318 may be designed to be loaded in compression during use. As such, these transverse truss members 318 may be relatively thick and heavy and as short as possible (e.g., orthogonal to both longitudinal truss members 316).

The diagonal truss members 320 may connect the different longitudinal points of the two longitudinal truss members 316A and 316B. The diagonal truss members 320 are generally oriented to be loaded in tension to counteract the gravity induced "sagging" at the sag points 314. Specifically, a connection 322 between a diagonal truss member 320 and the lower horizontal truss member 316B may be closer to the nearest sag point 314 than the corresponding connection 324 between the diagonal truss member 320 and the upper horizontal truss member 316A (closer to the support point 312). That way, the sag point 314 is prevented from sagging via tension in the diagonal truss members on either side of the sag point 314. Since the diagonal truss members 320 are loaded in tension, they do not need to be resistant to buckling and, therefore, may be relatively thin (e.g., plates). Tension between the upper and lower horizontal members 316 may be offset via compression across the transverse truss members 318.

FIG. 16 provides a relatively detailed view of an example truss arrangement. The truss arrangement shows the thin plate-like diagonal truss members 320 and the thicker transverse truss members 318 coupled between the two longitudinal truss members 316, one of which contains the ESP 16. As shown, the truss members 318 and 320 may be coupled to the longitudinal truss members 316 via clamps 450.

As shown in FIG. 1A, the horizontally oriented pump module 14 may include a stiffening structure 106 having plate truss members with a relatively trapezoidal shape. A schematic plan view of one such plate truss member 470 is illustrated in FIG. 15. An upper hole 472 in the trapezoidal plate truss member 470 may be disposed around and/or clamped to the smaller diameter pipe leg (e.g., 96B of FIG. 1) of pump module U-shaped conduit (e.g., 90 of FIG. 1). Similarly, a lower hole 474 in the trapezoidal plate truss member 470 may be disposed around and/or clamped to the larger diameter pipe leg (e.g., 96A of FIG. 1) containing the ESP. The trapezoidal plate truss member 470 may be used to form the transverse truss members that are loaded in compression between the two legs (e.g., 96 of FIG. 1) of the pump module 14. The wider truss design may increase the lateral stiffness of the truss structure.

By maximizing the use of diagonal truss members 320 (which may be lightweight) loaded in tension and minimizing the mass of transverse members 318 (that resist buckling) loaded in compression, the pump module 14 may be stiffened significantly without increasing mass of the pump module 14. As ESP 16 may have a maximum allowable bend (e.g., 1 degree per 100 linear feet) that may be tolerated during operation. By keeping the ESP 16 aligned horizontally, the lifetime of the pump module 14 is increased. In addition, reducing the weight of the pump module 14 in this way reduces the manufacturing and installation costs associate with the pump module 14.

FIG. HE illustrates another simplified beam arrangement of a pump module 14, this pump module 14 having multiple ESPs 16 disposed in series therein and both connection points at the same end 100 of the pump module 14. The stiffness structure 106 is shown as having four longitudinal truss members 316, transverse truss members 318 extending vertically and coupled to each of the four longitudinal truss members 316, and multiple diagonal truss members 320 each extending between immediately adjacent longitudinal truss members 316. The support points 312 and sag points 314 are illustrated as well.

FIGS. 12A-12C illustrate stiffening structure arrangements that may be utilized 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 conduit of the ESP 16 into the truss structure. In FIGS. 12A and 12B, the pump module 350 may include the main conduit with the ESP 16 as one longitudinal truss member 316, as well as an additional lower longitudinal truss member 316.

The following illustrations show each pump module 350 simplified as a beam arrangement and indicating support points 312, sag points 314, horizontal truss members 316 (containing the ESP 16 and the return tube 310), transverse truss members 318 coupled between the horizontal truss members 316, and diagonal truss members 320 coupled between the horizontal truss members 316. These force points and elements on the stiffness structure 106 of the "jumper" type pump module 350 may have the same general meanings and follow the same loading rules as described at length above with respect to the pump module 14 in FIGS. 11A- 11E. In these "jumper" pump modules 350, however, both opposite ends of the module 350 are supported (312), meaning that the modules 350 generally only feature one sag point 314, typically proximate the longitudinal center thereof.

FIG. 12C illustrates another simplified beam arrangement of the jumper pump module 350, this one having multiple ESPs 16 disposed in series therein and connection points at opposite ends of the pump module 350. The stiffness structure 106 in this case may include three longitudinal truss members 316, transverse truss members 318 extending vertically and coupled to each of the three longitudinal truss members 316, and multiple diagonal truss members 320 each extending between immediately adjacent longitudinal truss members 316. The support points 312 and sag points 314 are illustrated as well.

FIG. 18 illustrates a jumper pump module 350 having substantially unloaded goosenecks 530, in accordance with the present disclosure. The jumper pump module 350 extends from one base module 532 to a second base module 534. The jumper pump module 350 directs and boosts production fluid flow from the first base module 532 to the second base module 534 via at least one ESP 16 on the jumper module 350. The goosenecks 530 on either side of the jumper pump module 350 interface directly with the base modules 532 and 534 to provide the fluidic connection between the base modules 532 and 534 and the module 350. The jumper pump module 350 is directly supported through contact with the first and second base modules 352 and 354. A stiffening structure (e.g., truss or beam structure) 536 of the jumper pump module 350 may be disposed directly onto the base modules 352 and 354 on both sides of the module 350. The support points for the jumper pump module 350 are directly on the stiffening structure 536 of the module 350, thereby removing all loads from the goosenecks 530 on either end of the jumper pump module 350.

FIG. 19 illustrates in more detail an exemplary interface between the stiffening truss structure 536 of the jumper pump module 350 and one of the base modules (e.g., 534). The base module 534 may include a flange 538 designed to fluidically seal against the gooseneck 530 and hold the gooseneck 530 in place, thereby facilitating the fluid connection between the base module 534 and the jumper pump module 350. However, the gooseneck 530 and its associated connection with the flange 538 are not loaded with any significant amount of weight from the jumper pump module 350. Instead, the loads from the module 350 are transferred to the base module 354 directly from the stiffening structure 536. The stiffening structure 536 may interface with the base module 354 through a connector 540 (e.g., sliding shoe) landed on the flange 538 at a position around the gooseneck 530. The connector 540 may include sliding interfaces 542 that allow the stiffening structure 536 and along with the jumper pump module 530 to slide horizontally relative to the base module 534 in response to thermal expansion. The connector 540 may also include a hinged interface 544 that allows the stiffening structure 536 and jumper pump module 350 to rotate about at least certain axes to facilitate proper positioning of the jumper pump module 350 between the two base modules while keeping the goosenecks 530 unloaded.

Turning now to FIGS. 13A and 13B, embodiments of a vertically oriented, top-mounted ESP module 390 are provided. A beam structure may enable vertical mounting of one or more ESPs in a module mounted on the top of a base module. With sufficient stiffening, the ESP(s) may be maintained within bending specification. In FIG. 13A, the ESP pump module 390 includes a single out-and-back flow path having two vertical tubing sections 392 connected at an upper U-shaped bend 394. The stiffening arrangement in this case may include a two dimensional shear truss 396. In FIG. 13B, the ESP pump module 390 includes a two pass module having four vertical tubing sections 394 connected by two upper U-shaped bends 394 and a lower U-shaped bend 398. The stiffening arrangement in this case may include a plurality of angle trusses 400 positioned between the four vertical tubing sections 392.

Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the disclosure as defined by the following claims.