WO2020080951A1

WO2020080951A1 - Petroleum processing system

Info

Publication number: WO2020080951A1
Application number: PCT/NO2019/050219
Authority: WO
Inventors: Gyri SOLUMSMOEN; Jostein KOLBU; Lars K. LIEN; He Zhao; Klar Gøran ERIKSSON; Kjell Olav Stinessen; Jens Kristian BERG
Original assignee: Aker Solutions As
Priority date: 2018-10-16
Filing date: 2019-10-15
Publication date: 2020-04-23
Also published as: NO20210566A1

Abstract

A method of processing a petroleum wellstream (3) comprises receiving the wellstream (3) in a processing system (100); separating a produced water stream out of the wellstream (3) in a primary separator (2) in the processing system (100); receiving the produced water stream in a floatation separator (1) in the processing system (100) and separating a petroleum component out of the produced water stream by means of floatation; wherein the floatation is carried out at a pressure above 20 bar.

Description

PETROLEUM PROCESSING SYSTEM

The present invention relates to a processing system, and particularly to a processing system configured to process a well stream during petroleum production.

BACKGROUND

In petroleum production, the production stream may have a high content of water, which can be increasing over time as the well matures and may exceed 80% or more water at late stages, before the production becomes unprofitable and the well is decommissioned. If the production is from subsea wells located at long distances from the receiving platform or shore, the need for flow line transportation of the production stream can reduce the production of oil to unprofitable levels at significantly lower water contents due to the flow losses and the backpressure of the water column.

Separation of water from oil or gas production from subsea wells is known in the industry. Such separation can be carried out subsea, topside, or both subsea and topside. The content of oil in the separated water from such separators will, however, normally be too high for either reinjection to the reservoir or a receiving formation, or for discharge to sea.

The present invention has the objective to provide improved processing systems and methods, to reduce or eliminate the abovementioned challenges, or provide other advantages over known solutions and techniques.

SUMMARY

The present disclosure provides methods of processing a petroleum wellstream the method comprising: receiving the wellstream in a processing system; separating a produced water stream out of the wellstream in a primary separator in the processing system; receiving the produced water stream in a floatation separator in the processing system and separating a petroleum component out of the produced water stream by means of floatation; wherein the floatation is carried out at a pressure above 20 bar. The floatation may be carried out at a pressure of, for example, between 20 bar and 100 bar, between 20 bar and 70 bar, or between 20 bar and 40 bar.

The floatation separator may comprise a pressure vessel wherein the floatation is carried out. The processing system may be a subsea processing system arranged on a sea floor.

The processing system may be arranged on land.

The processing system may be arranged on a fixed or floating offshore structure.

When the processing system is a subsea processing system arranged on a sea floor, the floatation may be carried out in the pressure vessel at a pressure lower than an ambient sea water pressure at the sea floor.

The wellstream may have a wellstream pressure when received in the processing system, and the floatation can be carried out at a pressure which is, for example, not more than 20 bar lower than the wellstream pressure, not more than 10 bar lower than the wellstream pressure, not more than 5 bar lower than the wellstream pressure, or between 0.5 and 2 bar lower than the wellstream pressure.

The primary separator may have a primary separator operating pressure, and the floatation may, for example, be carried out at a pressure which is not more than 20 bar lower than the primary separator operating pressure, not more than 10 bar lower than the primary separator operating pressure, not more than 5 bar lower than the primary separator operating pressure, or between 0.5 and 2 bar lower than the primary separator operating pressure.

The step of separating a petroleum component out of the first produced water stream by means of floatation may comprise introducing floatation gas into the floatation separator.

The method may comprise sourcing the floatation gas from the primary separator.

The method may comprise sourcing the floatation gas from a gas reservoir at higher pressure than the pressure in the floatation separator. The step of introducing floatation gas into the floatation separator may comprise introducing floatation gas into the floatation separator together with a motive fluid.

The motive fluid may be produced water having been treated in the floatation separator. The motive fluid may be sourced downstream a pump arranged to receive produced water from the floatation separator.

The floatation gas may be sourced from a gas reservoir at lower pressure than the pressure in the floatation separator.

The method may comprise throttling a produced water stream between the primary separator and the floatation separator, whereby a pressure reduction is obtained in the produced water stream.

The method may comprise operating a sensor in a produced water pipe downstream the floatation separator to measure an oil content in the produced water pipe and operating an automatic controller to receive measurements from the sensor. The sensor may, in response to the measurements, control at least one operational parameter of the processing system.

The operational parameter may be one, or any combination, of: a flow rate of floatation gas into the floatation separator;

a flow rate of produced water into the floatation separator;

- a flow rate of produced water out of the floatation separator;

a flow rate of petroleum products out of the floatation separator;

a flow rate of motive fluid into the floatation separator;

a throttling rate of a produced water stream between the primary separator and the floatation separator, or

- a pressure of a motive fluid provided to a gas injection unit for injection into the floatation separator.

The gas injection unit may comprise a plurality of gas injectors arranged at different vertical height on the floatation separator.

The method may further comprise adjusting a flow rate of floatation gas into the floatation separator between the plurality of gas injectors. The method may comprise dissolving a floatation gas into the produced water stream in a supply pipe upstream the floatation separator, and reducing the pressure of the produced water stream upon entry to the floatation separator.

The floatation gas may be introduced into the produced water stream in a supply pipe upstream the floatation separator.

The floatation gas may be introduced into the produced water stream in a venture device arranged in the supply pipe.

Other embodiments and advantageous features are described below and in the appended figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Various characteristics of different embodiments will become clear from the following description of non-restrictive examples, with reference to the attached drawings, in which Figure 1 is a schematic view of a processing system according to an embodiment.

Figure 2 is a schematic view of a part of the processing system illustrated in Fig. 1.

Figure 3 is a schematic view of certain components of the processing system illustrated in Fig. 2.

Figures 4-7 illustrate further embodiments.

DETAILED DESCRIPTION

Figure 1 is an illustration of a high pressure compact flotation unit (CFU) separator 1 in a subsea processing system 100 with a primary separator 2 which removes a major part of water present in a wellstream 3. The primary separator 2 may be a conventional three-phase separator. Typically, such a primary separator may remove about 80 to 98% of the produced water from the wellstream 3. The produced water from the primary separator 1 is routed to the CFU 1 via a produced water pipe 4. In the CFU 1 , oil droplets are removed from the produced water by flotation, described in further detail below. The CFU 1 has an oil/gas reject outlet 5, a produced water outlet 6 and a floatation gas and motive water inlet 7, which will be described in further detail below. Liquid and gaseous petroleum products from the primary separator 2 are led to a transport pipe 8 via intermediate pipe 9, while fluids from the oil/gas reject outlet 5 are also led to the transport pipe 8 via an intermediate pipe 10. Each of the intermediate pipes 9 and 10 may have a respective valve 9a, 10a arranged therein. The transport pipe 8 may lead to an offshore platform, to a shore location, or to some other receiver or storage arrangement for petroleum products.

A gas supply pipe 11 is provided, in this embodiment leading from the primary separator 2 and to a flotation gas injection unit 16 which in this embodiment is part of the CFU 1. The gas supply pipe 11 is arranged to receive (bleed off)

predominantly gaseous fluid separated out in the primary separator 2 and supply this to the CFU 1 as flotation gas. This is described in further detail below.

Optionally, the flotation gas injection unit 16 may be provided with flotation gas from a different source, such as a different part of the subsea processing system 100 (which may include several further components than those illustrated in Fig. 1) and/or a dedicated flotation gas supply for this purpose.

Fluid from the produced water outlet 6 is led to a pump 13 via produced water pipe 12. The pump 13 provides energy to pump the water from the produced water pipe 12 to a discharge pipe 14, which may lead to a reservoir or formation for re-injection of the produced water from the CFU 1 , to a discharge point for discharge of the produced water to sea, to another processing or storage unit, e.g. at shore or on a platform, or to a different receiver of the produced water from the CFU 1.

A motive water pipe 15 is provided from the discharge pipe 14 and leading to the flotation gas injection unit 16. The function of the motive water pipe 15 and the flotation gas injection unit 16 will be clear from the description below. The motive water pipe 15 may have a valve 15a arranged therein to control the flow of motive water. In this case, the motive water is bled off the discharge pipe 14, as can be seen in Fig. 1. Optionally, the flotation gas injection unit 16 may be provided with motive water from a different source, such as a different part of the subsea processing system 100 (which, as noted, may include further components than those illustrated in Fig. 1), and/or a dedicated water supply for this purpose.

Individual components of the system shown in Fig. 1 may be optional in certain implementations; for example the valves 9a, 10a, 15a may not be necessary in some cases, the pump 13 may not be necessary if the pressure levels are such that no additional energy is required to move the produced water from the produced water pipe 12 to the discharge pipe 14 for re-injection or discharge, etc. In some embodiments, the gas injection unit may introduce gas into the produced water pipe 4, alternatively to or in addition to introducing gas directly into the CFU 1. Figure 2 illustrates the CFU 1 used in this embodiment, and its associated components, in greater detail. Components already described above are given the same reference numeral, and have the same function as previously described.

While Fig. 2 shows the detailed design of the CFU 1 according to one embodiment, it should be understood that modifications to the detailed design are possible within the scope of the present disclosure, and several features shown in Fig. 2 may be optional in certain embodiments, some examples being explained below.

In Figure 2, it can be seen that the produced water pipe 12 leading from the CFU 1 may also have a valve 12a arranged therein, the produced water pipe 4 leading to the CFU 1 may have a valve 4a arranged therein, and the gas supply pipe 11 may have a valve 11a arranged therein.

The CFU 1 may be arranged in a frame or support structure 21 , which may have common connectors 22,23 to interface with other parts of the subsea processing system 100. The support structure 21 may, for example, enable the CFU 1 to be installed to the subsea processing system 100 from a vessel (not shown), whereby the connectors 22,23 interfaces and engages corresponding connectors in a receiver unit in the subsea processing system 100, to which the CFU 1 is connected. Optionally, if the CFU 1 is located topside, the support structure 21 and connectors 22,23 may interface with relevant process equipment on the platform.

In Figure 2, the gas from the gas supply pipe 11 is introduced by ejectors 20a-d, where gas bubbles of desired size are created. In this embodiment, the uppermost ejector 20a introduces gas into the pipe 4, whereas the three lowermost ejectors 20b-d introduce gas into the CFU 1. The ejectors 20a-d are in this embodiment provided with motive water from a pump 13, as shown in Figure 1 , which in this case is a pump 13 for discharging produced water from the CFU 1. The pump providing the motive water may, alternatively, be a dedicated pump for this purpose. In yet another alternative, the pump may be a pump being part of the processing system 100 and regularly carrying out a different function, and whereby motive water for the CFU 1 can be bled off the discharge from this pump.

In yet another alternative, the motive water may be omitted, if a pressurized gas supply with appropriate pressure levels is available, and/or the operating pressure in the CFU 1 is lowered. For example, the pump and ejectors can be omitted by utilizing a higher pressure gas to be introduced and create bubbles by adjusting the water pressure in the pipe 4 to the CFU 1 to be somewhat lower than the gas pressure in the gas supply pipe 11 , say 1 to 10 bars lower. This can, for example, be done by a throttling valve (or an equivalent throttling element, which need not necessarily be a valve), e.g. the valve 4a arranged in the produced water pipe 4.

This will result in gas bubbling into the water in the CFU 1 driven by the pressure differences in the system. The pressure levels of the gas combined with how it is introduced to the water, and the device used to introduce the gas, will decide the size of bubbles. By calibration of gas pressure for the specific device, gas bubble size can be controlled and optimized.

The CFU 1 comprises a pressure vessel 24 into which the fluid to be processed and the flotation gas are injected, and wherefrom produced water and reject oil/gas are withdrawn after processing. The pressure vessel 24 may be designed for an internal pressure of 20 to 100 bar or higher, and, in a subsea system, for the relevant external seawater pressure, which in some cases could be typically between 100 and 300 bar depending on the water depth. With reference to Fig. 2, the produced water from the primary separator 2 (see Fig.

1) is routed to the CFU 1 via the produced water pipe 4. In the CFU 1 , oil droplets are removed by flotation, i.e. small gas bubbles, typically dso = in the range of 50 to 300 pm, are introduced in the CFU vessel 24 via the gas injection unit 16. The ascending gas bubbles hit oil droplets, typically dso = 5-20 pm, and transport them out of the water for discharge together with gas and usually a small amount of water, e.g. 5%, through the reject outlet 5.

In the embodiment shown in Fig. 2, the gas bubbles are introduced by ejectors 20a- d which receive motive water from a pump. As noted above, in alternative embodiments, the pressure levels may be so arranged, or controlled, to induce gas flow into the vessel 24 by means of pressure differences.

In Figure 3, the instrumentation and control functions for operation of the CFU 1 are illustrated schematically. The purpose of the flotation may, for example, be to achieve a certain cleanliness of the water required for either reinjection or discharge to the sea. A sensor 30 measures a concentration of oil-in-water in the produced water flow exiting the CFU 1. The sensor 30 may, for example, be an oil-in-water (OiW) meter. The controller 31 receives the sensor signals and is operable to control at least one of the valve actuators 4b, 10b, 11b, 12b and 15b. The valve actuators 4b, 10b, 11b, 12b and 15b are connected to the respective controllable valves as shown in Fig. 2. The valves 4a, 10a, 11a, 12a and 15a may be adjustable valves which allow a continuous or step-wise control of the flow rate through the respective valve, for example for throttling purposes.

In an embodiment, there is thus provided a method of processing a petroleum wellstream . According to the method, the wellstream 3 is received in the processing system 100, for example from a subsea wellhead. A produced water stream is separated out of the wellstream 3 in the primary separator 2 and provided to the CFU 1 via pipe 4 (see Fig. 1).

In the CFU 1 , a petroleum component is separated out of the produced water stream by means of floatation. Advantageously, the floatation is carried out at a pressure of above 20 bar within the CFU 1. The floatation separator 1 may comprise a pressure vessel 24 wherein the floatation is carried out. The pressure vessel 24 can be designed for the design operating pressures in the CFU 1 in view of the outside pressure, for example whether the CFU 1 is located topside or on land (where the outer pressure is atmospheric air pressure), or whether the CFU 1 is located subsea and at what depth.

Yet more preferably, the floatation is carried out at a pressure of between 20 bar and 100 bar, more advantageously between 20 bar and 70 bar, or more

advantageously between 20 bar and 40 bar.

The wellstream 3 has a wellstream pressure, which may be the same or similar to the wellhead pressure, or lower than the wellhead pressure if the wellstream 3 is processed upstream of the processing system 100, or if the wellstream 3 is transported a given distance before reaching the processing system 100. It may be an advantage to carry out the floatation at a pressure which is not more than 20 bar lower, more advantageously not more than 10 bar lower, more advantageously not more than 5 bar lower than the wellstream pressure, or between 0.5 and 2 bar lower than the wellstream pressure. This provides advantages of reduced energy losses in the system, whereby the natural wellhead pressure would be retained to as large an extent as possible in order to reduce energy requirements e.g. for further transport of the different fluids.

The primary separator 2 has a primary separator operating pressure, which may be the same or similar to the wellhead pressure, or lower than the wellhead pressure if the wellstream 3 is processed upstream of the processing system 100, or if the wellstream 3 is transported a given distance before reaching the processing system 100. It may an advantage if the floatation is carried out at a pressure which is not more than 20 bar lower than the primary separator operating pressure, not more than 10 bar lower than the primary separator operating pressure, not more than 5 bar lower than the primary separator operating pressure, or between 0.5 and 2 bar lower than the primary separator operating pressure. This may reduce the pressure and energy losses between the primary separator 2 and the CFU 1 , as well as making it easier to use e.g. bleed-off gases from the primary separator 2 as floatation gas for the CFU 1.

The processing system 100 according to any of the embodiments described herein may be arranged on a sea floor, arranged on land, or arranged on a fixed or floating offshore structure.

The method may comprise sourcing the floatation gas from the primary separator 2 and providing it to the CFU 1 via gas supply pipe 11. Alternatively, pressurized gas for this purpose could be supplied from a different source, for example an umbilical extending to a subsea processing system, or from a gas storage or gas generator on land or on an offshore structure.

The floatation gas may be sourced from a gas reservoir (which may be the primary separator 2 or a different gas reservoir) at a higher pressure than the pressure in the CFU 1. This may reduce the energy required to inject the floatation gas into the CFU 1 , reduce or remove the need for motive fluids, and may allow for enhanced separation performance in that improved gas distribution and flow characteristics within the CFU 1 may be secured.

If necessary or desirable, the introduction of floatation gas into the CFU 1 may be done with the aid of a motive fluid. This is the situation shown in Figs 1-2. In some applications, this may enhance overall system performance in that the motive fluid can be used to create desirable flow fields within the CFU 1 to ensure for example best possible distribution of the floatation gas bubbles.

As illustrated in Figs 1 and 2, the motive fluid can be produced water having been treated in the CFU 1 , and which is sourced downstream a pump 13 arranged to handle produced water from the CFU 1. The pump 13 may be a pump handling the entire stream of produced water from the CFU 1 , for example for pumping it to a remote location, or it may be a pump handling only a partial stream of produced water from the CFU 1 , for example if a partial stream is bled off for the purpose of use as a motive fluid. In the latter case, the pump may be arranged to increase the pressure of the bled-off fluid to a level required (or desired) by the gas injection unit 16.

The floatation gas may also be sourced from a gas reservoir at lower pressure than the pressure in the floatation separator 1. This may, for example, be desirable if such gas is abundantly available at such a pressure. The floatation gas may then be introduced into the CFU 1 for example by means of ejectors arranged in the gas injection unit 16 and a motive fluid supplied via the ejectors. Alternatively, or additionally, a pressure intensifier, such as a pump or compressor, may be arranged to bring the floatation gas up to a required pressure before injection into the CFU 1.

It may be advantageous to throttle the produced water stream between the primary separator 2 and the CFU 1. This can be done by, for example, operating valve 4a or by providing a flow restriction or the like (e.g. a throttling element, which need not necessarily be a valve) in pipe 4. This can produce a pressure reduction in the produced water stream and thus a pressure difference between the CFU 1 and the primary separator 2. This may for example be an advantage in that floatation gas can be sourced from the primary separator 2, which then has a pressure which is slightly higher than the operating pressure of the CFU 1. The floatation gas may then be injected into the CFU 1 without having to pressurize it up, or without motive fluid. It may an advantage if the floatation is carried out at a pressure which is not more than 20 bar lower than the primary separator operating pressure, not more than 10 bar lower than the primary separator operating pressure, not more than 5 bar lower than the primary separator operating pressure, or between 0.5 and 2 bar lower than the primary separator operating pressure. This may allow the use of floatation gas from the primary separator 2 while ensuring that excessive pressure drops are avoided in order to reduce energy requirements for further transport of the relevant fluids.

Any of the embodiments described herein may include operating a sensor 30 in the produced water pipe 12 downstream the CFU 1 , to measure an oil content of the produced water stream in the produced water pipe 12.

Illustrated in Fig. 3, an automatic controller 31 can be arranged to receive measurements from the sensor 30 and, in response to the measurements, control one or more operating parameters of the system. Actuators 4b, 10b, 11b, 12b and 15b may provide control variables for this purpose, however other control variables may also be available.

One such operating parameter is the flow rate of floatation gas into the CFU 1. This may be controlled by, for example, adjusting the valve 11a (see Fig. 2) to control the flow of floatation gas directly, or by adjusting valve 15a to regulate the flow rate of motive fluid.

Another such operating parameter is the flow rate of produced water into the CFU 1. This may be controlled by, for example, adjusting the valve 4a.

Another such operating parameter is the flow rate of produced water out of the CFU 1. This may be controlled by, for example, adjusting the valve 12a.

Another such operating parameter is the flow rate of petroleum products together with water in the reject out of the CFU 1. This may be controlled by, for example, adjusting the valve 10a.

Another such operating parameter is the flow rate of motive fluid into the CFU 1.

This may be controlled by, for example, adjusting the valve 15a and/or the power of the pump 13. Another such operating parameter is the throttling rate of the produced water flowing between the primary separator 2 and the CFU 1 in pipe 4. This may be controlled, for example, by adjusting the valve 4a. By controlling the throttling of produced water, a stable pressure difference can be obtained between the primary separator 2 and the CFU 1 , thus ensuring good separation performance.

Another such operating parameter is the pressure of a motive fluid provided to the gas injection unit 16 for injection into the CFU 1. The pressure of the motive fluid, for example produced water from downstream the CFU 1 , influences the performance and thus may be used as a control variable to ensure effective separation.

Particularly advantageous aspects of some of the embodiments described herein are that they can handle variations in the wellstream pressure, primary separator 2 and/or downstream pressures in pipes 8 and/or 14, without excessive losses in separation efficiency or effectiveness. Such variations may take place in a larger, or interconnected, processing plant, such as subsea systems where more than one well is connected to a subsea processing plant. By means of the embodiments described herein, high-performance operation can be secured also under varying operating conditions, thereby reducing the risk of going outside operational boundaries for oil-in-water content for the produced water, for example for re injection or for discharge to sea.

According to some embodiments described herein, low pressure and energy losses can be achieved, so that the overall energy consumption during production is reduced, and the power requirements of the plant are also reduced.

Particularly advantageous may be the control of a combination of flotation gas supply and reject flow rate by measurement from the sensor 30.

The gas injection unit may comprise a plurality of gas injectors arranged at different vertical height on the floatation separator (as shown in Fig. 2), and the method comprises adjusting the a flow rate of floatation gas into the CFU 1 between the plurality of gas injectors. In this manner, the height at which the floatation gas is injected can be adjusted. Such adjustment of the height, or the injection rate distribution over a vertical height of the CFU 1 , can be used to improve separation performance. For example, by means of feedback control via the controller 31 , an optimum height or mass flow distribution may be established. Alternatively, or additionally, the controller 31 can be operated to adjust the mass flow ratio of gas injected directly into the CFU 1 relative to the mass flow injected into the pipe 4.

The method may comprise solving a floatation gas into the produced water stream in the supply pipe 4 upstream the CFU 1. For example, the produced water stream to the CFU 1 may be saturated, or partially saturated, with a floatation gas. The pressure of the produced water stream may then be reduced upon entry to the CFU 1 , such that when the produced water enters the CFU 1 , gas dissolves and gas bubbles are formed. The gas bubbles may then carry out all, or part, of the floatation function. Such gas saturation may thus be used alone, or in combination with an injection unit 16 to introduce floatation gas into the CFU 1. Introducing gas into the produced water stream may be carried out by means of appropriate process equipment arranged in the supply pipe 4. In some embodiments, such gas introduction and dissolved gas floatation may replace the injection unit 16. Figure 4 illustrates another embodiment. In this embodiment, gas from the primary separator 2 is fed into the supply pipe 4 upstream the CFU 1. An appropriate flow of gas from gas supply pipe 11 into the supply pipe 4 can, for example, be arranged by means of controlled throttling of valve 4a.

Figure 5 illustrates another embodiment. In this embodiment, gas from a dedicated gas supply line (e.g. supplied through an umbilical or from a different part of the processing system) is fed into the supply pipe 4 upstream the CFU 1. In this embodiment, the flow in the supply pipe 4 may not need to be throttled if the gas supply is provided with sufficient pressure. Control of the gas flow rate may, for example, be ensured by using a controllable valve 11a in the gas supply pipe 11. Figures 6 and 7 illustrate further embodiments, being similar to those illustrated in Figs 4 and 5, respectively, but whereby the floatation gas from the gas supply pipe 11 is introduced into the supply pipe 4 in a venturi device 25. This may provide benefits in terms of the introduction of gas into the fluid stream in the supply pipe 4, for example requiring less pressure differential between the supply pipe 4 and the gas supply pipe 11. For example, by introducing gas into a low-pressure region in the venture device 25, sufficient gas flow rates can be ensured without requiring e.g. significant throttling or high gas supply pressures. Options for inducing bubble formation in embodiments according to the present invention may include (i) dissolved gas flotation, where the gas is released from a supersaturated solution as a result of the reduction of pressure, (ii) dispersed gas flotation, where the gas and liquid are mechanically mixed to induce bubble formation in the liquid, or (iii) other methods. In practice, the may also be a natural element of dissolved gas flotation in the dispersed gas flotation when the pressure of the produced water is reduced (e.g. by throttling) before introduction into the CFU.

As noted above, the processing system 100 may be arranged subsea, and may be arranged close to a subsea wellhead. High pressure flotation at these circumstances can preserve pressure for driving the flowline transportation of fluids, e.g. fluids to an offshore structure or land-based location, and fluids for injection to a reservoir.

High quality separation may give sufficiently low levels of petroleum products in the produced water to allow discharge to sea, say 30 ppm or lower, or secondarily reinjection without harming the oil reservoir, say 100 ppm or lower. The invention is not limited by the embodiments described above; reference should be had to the appended claims.

Claims

1. A method of processing a petroleum wellstream (3), the method comprising: receiving the wellstream (3) in a processing system (100);

separating a produced water stream out of the wellstream (3) in a primary separator (2) in the processing system (100);

receiving the produced water stream in a floatation separator (1) in the processing system (100) and separating a petroleum component out of the produced water stream by means of floatation;

wherein the floatation is carried out at a pressure above 20 bar.

2. A method according to claim 1 , wherein the floatation is carried out at a pressure of between 20 bar and 100 bar, between 20 bar and 70 bar, or between 20 bar and 40 bar.

3. A method according to claims 1 or 2, wherein the floatation separator (1) comprises a pressure vessel (24) wherein the floatation is carried out.

4. A method according to any preceding claim, wherein

the processing system (100) is a subsea processing system arranged on a sea floor;

the processing system (100) is arranged on land; or

the processing system (100) is arranged on a fixed or floating offshore structure.

5. A method according to claim 3, wherein the processing system (100) is a subsea processing system arranged on a sea floor, and the floatation is carried out in the pressure vessel (24) at a pressure lower than an ambient sea water pressure at the sea floor.

6. A method according to any preceding claim, wherein the wellstream (3) has a wellstream pressure when received in the processing system (100), and wherein the floatation is carried out at a pressure which is not more than 20 bar lower than the wellstream pressure, not more than 10 bar lower than the wellstream pressure, not more than 5 bar lower than the wellstream pressure, or between 0.5 and 2 bar lower than the wellstream pressure.

7. A method according to any preceding claim, wherein the primary separator (2) has a primary separator operating pressure, and wherein the floatation is carried out at a pressure which is not more than 20 bar lower than the primary separator operating pressure, not more than 10 bar lower than the primary separator operating pressure, not more than 5 bar lower than the primary separator operating pressure, or between 0.5 and 2 bar lower than the primary separator operating pressure.

8. A method according to any preceding claim, wherein the step of separating a petroleum component out of the first produced water stream by means of floatation comprises introducing floatation gas into the floatation separator (1).

9. A method according to the preceding claim, comprising sourcing the

floatation gas from the primary separator (2).

10. A method according to any of the two preceding claims, comprising sourcing the floatation gas from a gas reservoir at higher pressure than the pressure in the floatation separator (1).

11. A method according to any of the three preceding claims, wherein the step of introducing floatation gas into the floatation separator (1) comprises introducing floatation gas into the floatation separator (1) together with a motive fluid.

12. A method according to the preceding claim, wherein the motive fluid is

produced water having been treated in the floatation separator (1).

13. A method according to the preceding claim, wherein the motive fluid is

sourced downstream a pump (13) arranged to receive produced water from the floatation separator (1).

14. A method according to any of the three preceding claims, comprising

sourcing the floatation gas from a gas reservoir at lower pressure than the pressure in the floatation separator (1).

15. A method according to any preceding claim, comprising throttling a produced water stream between the primary separator (2) and the floatation separator (1), whereby a pressure reduction is obtained in the produced water stream.

16. A method according to any preceding claim comprising:

operating a sensor (30) in a produced water pipe (12) downstream the floatation separator (1) to measure an oil content in the produced water pipe (12) ;

operating an automatic controller (31) to receive measurements from the sensor (30) and, in response to the measurements, control at least one operational parameter of the processing system (100).

17. A method according to the preceding claim, wherein the operational

parameter is one, or a combination, of:

a flow rate of floatation gas into the floatation separator (1);

a flow rate of produced water into the floatation separator (1);

a flow rate of produced water out of the floatation separator (1);

a flow rate of petroleum products out of the floatation separator (1); a flow rate of motive fluid into the floatation separator (1);

a throttling rate of a produced water stream between the primary separator (2) and the floatation separator (1), or

a pressure of a motive fluid provided to a gas injection unit (16) for injection into the floatation separator (1).

18. A method according to the preceding claim, wherein the gas injection unit (16) comprises a plurality of gas injectors arranged at different vertical height on the floatation separator (1), and whereby the method further comprises adjusting the flow rate of floatation gas into the floatation separator (1) between the plurality of gas injectors.

19. A method according to any preceding claim, comprising dissolving a

floatation gas into the produced water stream in a supply pipe (4) upstream the floatation separator (1), and

reducing the pressure of the produced water stream upon entry to the floatation separator (1).

20. A method according to any preceding claims, comprising

introducing a floatation gas into the produced water stream in a supply pipe (4) upstream the floatation separator (1).

21. A method according to the preceding claim, wherein the floatation gas is introduced into the produced water stream in a venture device (25) arranged in the supply pipe (4).