NO339736B1

NO339736B1 - Subsea pump and system and methods for control

Info

Publication number: NO339736B1
Application number: NO20150973A
Authority: NO
Inventors: Gunder Homstvedt; Robin Slater; Marcelo Santos
Original assignee: Aker Subsea As
Priority date: 2015-07-10
Filing date: 2015-07-27
Publication date: 2017-01-30
Also published as: BR112018000356B1; NO20150973A1; US20180202432A1; BR112018000356A2

Description

SUBSEA PUMP AND SYSTEM AND METHODS FOR CONTROL

Field of the invention

The present invention relates to subsea pumping of multiphase fluid. More specifically, the invention relates to a subsea or downhole pump and a subsea pump system comprising a subsea pump and a flow conditioning system operatively coupled to the subsea pump, and methods for control thereof.

Background of the invention and prior art

Most subsea pumps are driven by a variable speed drive, a VSD, also termed a variable frequency drive, a VFD. A variable speed drive provides stepless variable control of the speed of the pump. An adjustable speed drive, ASD, provides stepwise control and can alternatively be used to drive a subsea pump. In this context the term VSD covers VSDs, VFDs and ASDs. A subsea or topsides RotoConverter, a motor generator set, is a feasible option as a subsea pump drive, particularly for high power subsea pumps deployed with long subsea step outs.

A VSD located topsides or onshore is the most used device to drive a subsea pump. Typically, an increase in frequency and speed is accompanied by an increase in torque, allowing the subsea pump to operate at higher power. However, the relationship between torque, power and speed can be complex, for different reasons, for example that the fraction of the applied power that contributes to hydraulic (pumping) work varies. The gas/liquid mixture and density are important factors that contribute to change in pumping performance.

Subsea pumps have very difficult location and restricted access for maintenance, therefore reliability is vital. Any improvement in the reliability of subsea pumps will be welcomed.

It is well known that operating pumps at feasible operating conditions will prolong the service life. The optimal condition is often termed the sweet spot,

often achievable for a steady state operating situation.

For subsea pumps receiving multiphase flow of variable gas volume fraction, the control is complex. The pump curve and therefore optimal setpoint for operation changes according to the gas fraction. Comprehensive subsea instrumentation to control the pump operation and robust pump design to allow the pump to operate for longer periods under harsh operating conditions are typical measures to provide reliability. Subsea multiphase flow meters and level sensors in pipes and equipment upstream to the pump are typical examples of instrumentation needed to control a subsea pump. Control devices and fluid conditioning devices like recirculation lines, valves, chokes, mixers and related instrumentation, are used for control of varying gas volume fraction, GVF, of a multiphase flow to be pumped.

The patent publications US 5,254,292, GB 2 215 408, US 5,393,202, US 20110155385, WO 2015/011369, US 8,857,519 B2, the OTC paper OTC16477 "An efficient Wellstream Booster Solution for Deep and Ultradeep Water Oil Fields", May 3-6, 2004, the document SPE 146784 of February 2012, the document "Proceedings of the thirteenth international pump user symposium, page 159, and the textbook "Pumping of Gas-Liquid Mixtures, page 890, "Centrifugal Pumps" by Johan Friedrich Gulich, 3rd edition 2014, provide background art relevant for the present invention.

The above mentioned publications contains no teaching on how the speed of a subsea or downhole pump should be controlled as the gas volume fraction of a multiphase flow enter the pump, without depending on multiphase metering, level metering or other subsea instrumentation.

The objective of the invention is to provide improved reliability to subsea pumps, downhole pumps and subsea pump system and related methods for control thereof.

Summary of the invention

The invention meets the objective by providing a subsea or downhole pump, a

subsea pump system and methods for control thereof.

The invention provides a subsea or downhole pump comprising an inlet and an outlet, a multiphase fluid flow entering the inlet can have a variation in the GVF-gas volume fraction- of the fluid, distinctive in that the pump includes or is operatively coupled to devices for normal pump control as the GVF varies, said devices consisting of:

a transmitter for electric pump current and

a transmitter for at least one of: pump speed, pump frequency or pump voltage, and

a controller acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases.

Preferably, the devices for measuring the parameters electric current and measuring or using a set pump speed or frequency or pump voltage, are integrated into or coupled for real-time measurements at a topsides or onshore variable speed drive, eliminating the requirement or use of subsea or downhole instrumentation. Most preferably, the devices consist of a transmitter for electric pump current and a transmitter for pump speed.

In a preferable embodiment, the pump is a subsea pump and a flow conditioning unit arranged upstream to the pump dampens the variation of a gas volume fraction GVF and reduces gas bubble sizes in a multiphase flow entering the inlet to the fluid conditioning unit, to an acceptable level for delivery of multiphase fluid through an outlet of the fluid conditioning unit to the downstream subsea pump; and a liquid collecting unit arranged downstream to the pump, with a liquid recirculation line from the liquid collecting unit to upstream the pump, provides liquid for decreasing GVF to an acceptable level for the pump in situations where the GVF is excessive. In addition or as an alternative for allowing higher GVF, a line coupled to the flow conditioning unit, preferably a pipe of an umbilical arranged to a topsides position, has been arranged for export of excessive gas or import of liquid in a situation of

excessive GVF of the multiphase fluid to be pumped.

In another preferable embodiment, the pump is an ESP, an electrical submersible pump, arranged in a subsea flowline jumper.

The invention also provides a method for control of a subsea or downhole pump according to the invention, distinctive by the steps: to measure or transmit parameters in the group of parameters consisting of: electric pump current and at least one of pump speed or frequency and pump voltage, and to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases.

Most preferably, the parameters consist of electric current and pump speed, measured in real-time at a topsides variable speed drive.

The invention also provides a subsea pump system, comprising a subsea pump with an inlet and an outlet, a multiphase fluid flow entering the system can have a higher GVF-gas volume fraction-, a larger variation in the GVF, or larger gas bubbles, than acceptable for efficient and reliable operation of the subsea pump. The subsea pump system is distinctive in that it further comprises:

a flow conditioning unit arranged upstream to the subsea pump,

a liquid collecting unit arranged downstream to the subsea pump, and

a liquid recirculation line arranged from the liquid collecting unit to upstream the subsea pump,

wherein the flow conditioning unit reduces the variation in GVF, mixes gas and liquid and reduces the size of gas bubbles in a multiphase flow entering the inlet to the flow conditioning unit, and recirculation of liquid from the liquid containment unit reduces the GVF of the flow entering an inlet of the subsea pump, so the subsea pump can operate within an operational window with efficient and reliable operation, and

the subsea pump includes or are operatively coupled to devices for normal pump control as the GVF of the pump inlet flow varies, said devices consisting of:

a transmitter for electric pump current and

a transmitter for at least one of: pump speed, pump frequency or pump

voltage, and

For the subsea pump system according to the invention, preferably:

the flow conditioning unit comprises an inlet, a volume and an outlet with a perforated outlet pipe extending upwards into said volume,

the liquid collecting unit comprises an inlet, a volume and an outlet with an outlet pipe extending upwards into said volume, said outlet pipe is perforated only in an upper part of said volume, and

the liquid recirculation line has been arranged from a lower liquid filled part of the volume of the liquid collecting unit to the flow conditioning unit.

For the subsea pump system according to the invention, preferably the devices for measuring the parameters electric current and at least one of pump speed or frequency and voltage, preferably electric current and pump speed, are integrated into or coupled for real-time measurements at a topsides or onshore variable speed drive, eliminating the requirement or use of subsea instrumentation.

In a preferable embodiment, the subsea pump system according to the invention comprises a line coupled to the flow conditioning unit, preferably a pipe of an umbilical arranged to a topsides position, for export of excessive gas or import of liquid in a situation of excessive GVF of the multiphase fluid to be pumped. The controller can also activate a topsides valve in a line going from the subsea conditioning unit through the umbilical to the topsides separator to vent excessive gas. The controller can thereby alter the gas-to-liquid ratio going to the pump in favourable way to increase pump efficiency. If arranged differently or as an alternative, a topside located valve and pump can be activated by the same controller to feed additional liquid the conditioning unit to obtain better operational pumping conditions.

In a preferable embodiment, the subsea pump of the pump system of the invention is an ESP, an electrical submersible pump, arranged in a flow line jumper.

The invention also provides a method for control of the subsea pump system of the invention, distinctive by the steps: to measure ortransmit parameters in the group of parameters consisting of: electric pump current and at least one of pump speed or frequency and pump voltage, and

to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases.

The embodiments of the invention, that is the pumps of the invention and the pump system of the invention, and associated respective methods, have in common that the devices for normal pump control as the GVF varies, consist of: a transmitter for electric pump current and a transmitter for at least one of pump speed or frequency and pump voltage, and a controller acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases.

The electric pump current is measured. The at least one additional parameter: pump speed or frequency and pump voltage, is measured or transmitted as a set. Speed and frequency are synonyms in this context, since skilled persons know that a VSD frequency and the pump speed are directly related. In a pump speed range from zero up to a base load, pump voltage and speed/frequency are directly related; therefore pump voltage can be measured or transmitted as the parameter additional to pump electric current for normal control of the pump as the GVF vary.

The skilled person will recognize that the invention has two main embodiments: one with a fluid conditioning system, that is the pump system of the invention

and related method; and one without requirement of a fluid conditioning system, that is the subsea pump or downhole pump if the invention and related method.

The pump system of the invention is feasible when the GVF or variation thereof, or occurrence of large gas bubbles or other limiting factors, of a multiphase flow is higher or larger than the pump per se can handle effectively and reliably, since the fluid conditioning system dampens the variation in GVF, mixes the phases, break up large gas bubbles and recirculates liquid. For an ESP, the limit is typical about 35 % GVF, meaning that at higher GVF the pump system of the invention is feasible. For a liquid subsea pump, efficiency and reliability can drop too much when the GVF exceeds 10%, for a state of the art multiphase pump, efficiency and reliability can drop too much when the GVF exceeds 80 %. However, the exact limit for acceptable maximum GVF will depend on other factors and economic considerations as well, hence the reference to efficiency. Other factors are pressure, since higher pressure results in a higher allowable GVF since the density of the gas phase is increased and conversely lower pressure reduces the allowable GVF, and the density of the liquid phase components, since a low density liquid will separate out more gas at reduced pressure, and viscosity. Large variations in the gas fraction entering a centrifugal pump can be very detrimental to the pump's function and service life. Even centrifugal pumps that are specifically designed to handle high gas fractions, like the helico-axial pump, described in patent US 5 375 976, will have a substantial efficiency drop with high gas fractions. While standard centrifugal pumps with radial impeller will gas-lock (zero efficiency) at 10% gas, the helico-axial pumps will maintain a pumping efficiency of approx. 30% with an 80% gas fraction. At a fixed speed, the ability to generate pressure will also drop significantly with increasing gas fractions. All centrifugal pumps including its drivetrain will be exposed to high vibrations and rapid load variations if the gas fraction is changing rapidly and with large amplitude. In order to obtain reliability and long service life, it is therefore imperative that the rapid variations of gas fractions are avoided. Since the pressure generation is dependent upon the average gas fraction, it is also important that such variations are slow enough to allow for compensation by pump speed adjustment. In practice, many factors are related and each well or well system will have to be considered specifically. Turpin curves or similar curves can be feasible in this context. The terminology "normal pump control as the GVF of the pump inlet flow varies" refers to the expected flow conditions, expected for 100 % or in substance 100 % of the time of operation. Collapse of wells or upstream equipment can give unexpected flow conditions, which may result in shut down or may require different solutions to handle. If the expected GVF is too high, or the variation of GVF is too high for the actual subsea pump, the subsea pump system of the invention will be feasible.

The specified control devices are the only devices required and used for normal control of the pump or pump system as the GVF of the inlet flow to the pump varies. The phrase; a controller acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases; means that the pump speed change is sufficient to reverse an increasing GVF in the inlet flow and reverse a decreasing GVF in the inlet flow, achieving a regulation at or around a favourable GVF of the inlet flow. The control must act faster than the variation in GVF of the inlet flow, and should preferably adjust the pump speed setpoint to a changed GVF when the speed changes are not symmetrical about increase and decrease of the speed.

Additional instrumentation is superfluous for normal operation with respect to varying GVF of the inlet flow to the pump of the invention. Any additional instrumentation, if present, can be for redundancy and other purposes. The pump is without any subsea instrumentation for normal control thereof if the pump is driven by a topside or onshore-located drive, such as a topsides VSD or a topsides RotoConverter, since all input parameters can be measured or tåken from the topsides or onshore drive. This also means that the pump is without or do not need for normal operation, any recirculation or bypass lines, control valves or chokes or mixers for controlling the recirculation or bypass flow through the recirculation line or a bypass line, and related subsea instrumentation. Multiphase meters or level sensors are not required for control of the pump of the invention, providing savings of 500 000 USD or higher and increasing reliability.

The algorithms applied may sufficiently estimate gas volume fraction at the pump input allowing selection of the appropriate pump curve for the fluid density. Control thereof of the pump is driven by a subsea, topside or onshore- located drive, such as a VSD, or RotoConverter. All input parameters to infer liquid level of the fluid conditioning unit can be measured or tåken from the electrical system at the drive, preferably topsides, or at the pump motor input.

The term subsea pump means a pump located on or at the seabed. The subsea pump can be a typical seabed located subsea centrifugal pump or an electrical submersible pump arranged in a flow line jumper, such as POWERJump™ as available from the Subsea Production Alliance. The term downhole pump means an ESP, an electrical submersible pump, a long slim pump normally arranged in a wellbore. The pump and pump system of the invention preferably are or comprises centrifugal pumps, respectively. The controller and the drive of the pump and pump system of the invention, respectively, are preferably arranged topsides or onshore.

Each of the subsea pump of the invention, the subsea pump system of the invention and the methods of the invention, can include any feature or step herein described or illustrated, in any operative combination, each such operative combination is an embodiment of the present invention.

As mentioned, a VSD typically have a given output voltage for a given frequency, at least for a given operation window, such as from very low speed up to a base load speed. Accordingly, instead of speed/frequency, voltage can be measured or used as an input parameter, together with current. The Applicant has verified that a direct correlation between motor current, speed and GVF exists, allowing a simple control algorithm to be used. The deviation from a reference current at a set or measured speed or voltage for a reference GVF, can be used as the proportional input to a control algorithm. Alternatively, a look up table can be used for the control, established during commissioning. Alternatively, the GVF of the pump inlet flow or a fluid conditioning unit liquid level can be inferred based on the measured pump current for a set or measured speed/frequency or voltage, the pump speed is then adjusted according to the inferred GVF or liquid level.

For a RotoConverter, that is a motor generator set, a look up table established during commissioning, giving the relation between GVF and the measured parameters can be used for control. However, it is likely that a similar or identical relationship between GVF and the measured parameters exists also for a RotoConverter, allowing a control algorithm to be developed. However, the RotoConverter is most preferably a passive machine without any active subsea control or instrumentation for normal operation, allowing for merely topsides control from a VSD.

Even though merely current and speed or voltage are required for operation of the pump or pumps system as the GVF varies, the pump and pump system and upstream and downstream equipment may comprise and preferably do comprises sensors of various kinds, measuring various parameters. These additional data can be used to optimise the control according to the methods of the invention. Furthermore, the data can be used to optimise operation and maintenance, for example by finding patterns for sweet spot operation or early warning for wear or failure.

Fiqure

Figure 1 illustrates a typical embodiment of a subsea pump of the invention, and

Figure 2 illustrates a pump system of the invention.

Detailed description

A subsea pump 5 with motor 4 is driven by a topsides variable speed drive VSD 2, as illustrated in Fig. 1. A topsides controller 1 is operatively arranged to the VSD. A flow conditioning unit 3, arranged upstream to the pump, receives a multiphase flow 7 through an inlet. An outlet 6 from the fluid conditioning unit includes a perforated pipe section extending up above a liquid level in the flow conditioning unit, providing an average mix of gas and liquid to the pump inlet. When the liquid level rises in the flow conditioning unit, more liquid is mixed into the flow from the flow conditioning unit to the pump, resulting in a higher measured current. The control system then increases the pump speed, resulting in decreasing liquid level in the flow conditioning unit. When the liquid level in the flow conditioning unit decreases below a chosen setpoint, more gas will be delivered to the pump, the control system then decreases the pump speed. Accordingly, a in substance fixed GVF to the pump can be achieved, as well as a in substance fixed liquid level in the flow conditioning unit, in the illustrated example a fluid retaining mixertank. The devices required for normal pump control are as follows: a transmitter (28) for electric pump current; and a transmitter (29) for at least one of: pump speed, pump frequency or pump voltage; and a controller (30) acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases. Said devices are only illustrated on Figure 1, and are omitted on Figure 2 for clarity.

Figure 2 illustrates a pump system of the invention. In addition to the pump 5, a fluid conditioning system is arranged to the pump, in order to dampen the variation in GVF, decrease the GVF in the fluid entering the pump by retaining liquid and recirculating liquid from a liquid collecting unit downstream the pump. A flow conditioning unit FCU 3 is arranged upstream to the pump, a perforated outlet pipe extending upwards into a volume of the FCU act to mix the phases according to the liquid-gas level in the FCU. A liquid collecting unit LCU 10 downstream to the pump retains liquid for recirculating liquid to the pump inlet, for more effective pump operation. The LCU comprises an inlet, a volume and an outlet with an outlet pipe extending upwards into said volume, said outlet pipe is perforated only in an upper part of said volume, to ensure a liquid filled lower part of the volume of the LCU. A liquid recirculation line 11 has been arranged from the lower liquid filled part of the volume of the LCU to the FCU. Line 14 allows supply of liquid from a topsides chemical injection unit or a hydraulic power unit to the pump system. The line 26 allows draining of gas from the FCU, controlled by a topsides valve 27. Said lines are preferably pipes in an umbilical. Check valves 9 and 15 ensure correct direction of flow. Valve 12 in the liquid recirculation line chokes down the recirculated liquid pressure conveniently.

More specifically, hydrocarbon flow from a subsea well (20) is routed through a subsea valve-stack (christmas-tree) (21) and a flow-line jumper (22) to the subsea pump system (23). The connection line (7) to the boosting system is typically done via ROV operated connectors (17) at a subsea template (19). The pressurized flow leaving the subsea pump system is connected in a similar fashion via a connector (18), arranged on a subsea template (19) through a flow-line/riser arrangement (24) to a topsides receiver separator (25). This receiving separator can be arranged on a platform or floating production vessel or another host facility. Several connections and communication lines from topside to the subsea pump system are typically bundled into an umbilical. This might contain the power lines (16) transmitting the variable frequency electric power to the pump motor (4). It further typically may contain one or more chemical injection lines (14) to handle flow assurance related issues. Chemical additives to eliminate formation of hydrate, scale deposits, wax or asphaltenes are pressurized in a topsides chemical injection unit (13), routed through one or more lines in the umbilical (14) to a suitable injection point (15) at the subsea pump system. Electric communication lines and/or fiber optic lines (not shown in figure 2) might also be included in the umbilical for data transfer. A dedicated hydraulic line (26) might be connected with the fluid conditioning unit (3) and the topside separator. The function of this line will be described later.

The subsea pump system, also termed the boosting system, will typically be equipped with some additional components to enhance the function in presence of high gas fractions and gas/liquid slugging. With reference to figure 1 and 2, these components are described below while their function will be further elaborated later.

The incoming gas/liquid mixture (7) is entering the fluid conditioning unit (3) - for short called FCU - upstream the pump intake. The function of the FCU is to buffer the liquid phase and in a controlled way re-mix the gas and liquid at the outlet. This is done to ensure a homogenous mixture of gas and liquid going into the pump in order to obtain stable and good pump performance. The FCU has a volume retaining gas and liquid, the perforated outlet pipe mixes the liquid according to a liquid-gas level in the volume and how the perforations are arranged.

The conditioned fluid (6) is entering the pump (5) driven by the electrical motor (4). The output flow (8) from the pump is being fed through a check-valve (9) to prevent backflow and into a liquid collecting unit (10) - for short called LCU. The LCU has the function of separating the gas and liquid and retain or collect/store some of the liquid. The outlet from the LCU is arranged so that all the gas is going to the outlet stream together with some of the liquid. As some solids particles might be coming with the well flow, these particles are separated to the bottom of the LCU and routed to the outlet flow as well. Part of the remaining liquid in the LCU is routed through a pressure reduction valve/choke (12) back to the FCU in a separate liquid recirculation line (11).

An important feature in order to obtain stable operation of a pump of the kind described here, is to retain as much or at least sufficient of the incoming liquid in the recirculation system as possible. More specifically, liquid should be retained and recycled in order to achieve a GVF less than 60% for the pump, in order to avoid excessive heating and wear, when the pump is an ESP. Such liquid is mixed with the incoming gas-liquid flow and will reduce the gas-to-liquid fraction going to the pump. The liquid collecting unit at the pump outlet and recirculation of liquid from this tank to the inlet conditioning-mixer unit is therefore important.

A typical well fluid mixture consists of multi-components of various densities. When the lighter components in such a hydrocarbon mixture is depressurized across the choke (item 12 in figure 2), it is likely that they will flash back into gas when reaching the pump inlet. Such gas will not contribute in lowering the gas-to-liquid fraction going to the pump. It is therefore important to design the liquid collection unit in such a way that the heaviest liquid components are separated to be recirculated. On the other hand, the heaviest components coming with the well flow will be solids particles. Re-routing such particles via the recirculation system to the pump inlet is not favourable as it will create wear both on the choke and on the pump internals. The liquid collection unit is therefore constructed such that solids will be drained from the tank together with the gas and some liquid, preferable the lightest components. The outlet pipe from the LCU therefore comprises some perforations at the lowest level in the volume of the LCU, where solids will accumulate, in addition to perforations where gas and the lightest liquids will accumulate, towards the top of the volume.

Additional measures that can be used in order to alter the gas fraction going to the pump is using the additional line (26, figure 2) going from the FCU to the topside separator. If the gas fraction the FCU is too high, this line can be used to drain gas into the topsides separator. Alternatively this line can be used to inject liquid from topsides to the FCU and thereby reduce the gas fraction being fed to the pump. The use of this line can be controlled via valves located topsides.

The simplicity of the pump, pump system and methods of the invention provides increased reliability. Each component of a pump or pump system represents a source of failure, reducing the number of components therefore improves reliability. Removing any need for control devices subsea or downhole improves reliability further. In contrast, state of the art subsea pumps and downhole pumps, and subsea pump systems, require more comprehensive instrumentation, recirculation arrangements and other control devices, arranged subsea, for control of the operation as the GVF of an inlet multiphase flow varies.

Claims

1. Subsea (5) or downhole pump comprising an inlet (6) and an outlet (8), a multiphase fluid flow entering the inlet can have a variation in the GVF-gas volume fraction- of the fluid,characterised in thatthe pump includes or is operatively coupled to devices for normal pump control as the GVF varies, said devices consisting of: a transmitter (28) for electric pump current and a transmitter (29) for at least one of: pump speed, pump frequency or pump voltage, and a controller (30) acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases.

2. Subsea or downhole pump according to claim 1, wherein the devices for measuring the parameters electric current (28) and measuring or using a set pump speed or frequency or pump voltage (29), are integrated into or coupled for real-time measurements at a topsides or onshore variable speed drive (2), eliminating the requirement or use of subsea or downhole instrumentation.

3. Subsea or downhole pump according to claim 1 or 2, wherein the devices consist of a transmitter for electric pump current (28) and a transmitter for pump speed (29).

4. Subsea or downhole pump according to claim 1, wherein the pump is a subsea pump (5) and a flow conditioning unit (3) arranged upstream to the pump dampens the variation of a gas volume fraction GVF and reduces gas bubble sizes in a multiphase flow entering the inlet to the fluid conditioning unit, to an acceptable level for delivery of multiphase fluid through an outlet of the fluid conditioning unit to the downstream subsea pump (5); and a liquid collecting unit (10) arranged downstream to the pump, with a liquid recirculation line (11) from the liquid collecting unit to upstream the pump, provides liquid for decreasing GVF to an acceptable level for the pump in situations where the GVF is excessive.

5. Subsea or downhole pump according to any one of claim 1-4, wherein the pump is an ESP, an electrical submersible pump, arranged in a subsea flowline jumper.

6. Method for control of a subsea pump or downhole pump according to any one of claim 1-5,characterized bythe steps: to measure or transmit parameters in the group of parameters consisting of: electric pump current and at least one of pump speed or frequency or pump voltage, and to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases.

7. Method according to claim 6, whereby the parameters consist of electric current and pump speed, measured in real-time at a topsides variable speed drive.

8. Subsea pump system, comprising a subsea pump (5) with an inlet (6) and an outlet (8), a multiphase fluid flow entering the system can have a higher GVF-gas volume fraction-, a larger variation in the GVF, or larger gas bubbles, than acceptable for efficient and reliable operation of the subsea pump,characterised in thatthe subsea pump system further comprises: a flow conditioning unit (3) arranged upstream to the subsea pump, a liquid collecting unit (10) arranged downstream to the subsea pump, and a liquid recirculation line (11) arranged from the liquid collecting unit to upstream the subsea pump, wherein the flow conditioning unit (3) reduces the variation in GVF, mixes gas and liquid and reduces the size of gas bubbles in a multiphase flow entering the inlet to the flow conditioning unit, and recirculation of liquid from the liquid collection unit (11) reduces the GVF of the flow entering an inlet of the subsea pump, so the subsea pump can operate within an operational window with efficient and reliable operation, and the subsea pump (5) includes or are operatively coupled to devices for normal pump control as the GVF of the pump inlet flow varies, said devices consisting of: a transmitter (28) for electric pump current and a transmitter (29) for at least one of: pump speed, pump frequency or pump voltage, and a controller (30) acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases.

9. Subsea pump system according to claim 8, wherein: the flow conditioning unit (3) comprises an inlet (7), a volume and an outlet with a perforated outlet pipe extending upwards into said volume, the liquid collecting unit (10) comprises an inlet, a volume and an outlet with an outlet pipe extending upwards into said volume, said outlet pipe is perforated only in an upper part of said volume, and the liquid recirculation line (11) has been arranged from a lower liquid filled part of the volume of the liquid collecting unit to the flow conditioning unit.

10. Subsea pump system according to claim 8 or 9, wherein the devices for measuring the parameters electric current (28) and at least one of (29) pump speed or frequency or voltage, preferably electric current and pump speed, are integrated into or coupled for real-time measurements at a topsides or onshore variable speed drive (2), eliminating the requirement or use of subsea instrumentation.

11. Subsea pump system according to any one of claim 8-10, comprising a line (26) coupled to the flow conditioning unit, preferably a pipe of an umbilical arranged to a topsides position, for export of excessive gas or import of liquid in a situation of excessive GVF of the multiphase fluid to be pumped.

12. Subsea pump system according to any one of claim 8-11, wherein the subsea pump is an ESP, electrical submersible pump, arranged in a flow line jumper.

13. Method for control of the subsea pump system of any one of claim 8-12,characterized bythe steps: to measure or transmit parameters in the group of parameters consisting of: electric pump current and at least one of pump speed or frequency or pump voltage, and to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases.

14. Method according to claim 13, whereby the parameters consist of electric current and pump speed, measured in real-time at a topsides variable speed drive.