BACKGROUND TO INVENTION Production of hydrocarbons from remote or marginal oil and gas fields offshore is proving to be of significant importance to oil companies, and the economies of some oil producing countries. The larger oil discoveries are now in the minority. It is the economic production of the smaller fields of less than 100 million barrels of recoverable oil, which are remote from the shore, in deep water, or a long distance from any other facility or pipelines, that is today's challenge.

To produce such fields in an economically and environmentally secure method, it would be beneficial to separate on the sea bed the majority of unwanted by- products from the oil well, such as produced water and solids, whilst managing large intermittent volumes of the gas, solids, oil and water, known in the industry as "slugs". It has been the management of these slugs that has historically called for large pressure vessels with a considerable retention or hold up time, or slug catchers to smooth out this intermittent or slugging flow.

Once the produced water and solids waste streams have been separated they need to be managed, with for example, the produced water (water which is carried up from the

bore hole with the oil) being re-injected into the reservoir to maintain reservoir pressure, or into a disposal well or zone, as appropriate. The solids need to be free of oil to international standards prior to being released to the sea. Although this may be possible to achieve on the sea bed, the sub sea measurement of oil on solids is not currently available. Such measurement currently requires a"Retort"system which evaporates the liquids attached or absorbed by the solids, condenses them and measures the oil fraction on a volume by volume basis. Current oil on solids standards for discharge to the sea where allowed are targeted at drill cuttings, and require oil on solids to be equal to or less than 10 grammes of oil per kilogram of solids. Owing to the industries current inability to measure oil on solids concentrations on the sea bed, the solids need to be sent to the surface process plant for cleaning and disposal to the sea, transport to land, or re-injected into a disposal zone below sea level.

It may also be desirable to have sea water, either alone or combined with produced water, injected into the producing reservoir. In the case of a low permeability well or tight formation there will be a requirement for the removal of fine solids in both the produced water and seawater prior to injection. Other issues such as scale formation precipitated by mixing of dissimilar waters, sulphate reducing bacteria and dissolved oxygen levels will also need addressing.

Aspects of this invention utilise various processes and products together to achieve phase separation, solids

management and marinisation required to achieve sub-sea separation. One particular aspect comprises a novel free water knockout (removal of produced water from a three phase oil, gas and water stream) system that uses pressure differential and water quality as its control set points. Fig (1) is a process schematic for one such system.

It is known that marginal oil producing wells can, over time, have a production profile typically as shown in Fig (2). In general terms the gas pressure decreases, hence volume increases, stabilises and then drops over the life of the field. Oil production typically starts high with very little water and then depending on the reservoir, the water cut (percent water to oil of produced fluids) starts to increase. Once the water cut is above 55%, i. e. continuous water phase (i. e. passed its phase inversion, or flip point) the first stage separation of any process system must operate as a free water and gas knockout vessel.

In the case of offshore fields where the production fluids are transported to the surface facilities from the sea bed by risers (flexible pipes or hoses), this level of water in the produced fluids results in a bottleneck which hinders the production of the oil field. This is particularly the case where an FPSO (Floating Production Storage and Offloading) unit is used, owing to the limited number of slots for risers to enter the FPSO via its swivel or turret.

The heart of any sub sea produced water separation system will be the efficient separation of the oil and water phases. This has historically been achieved on the surface by the use of reasonably large pressure vessels with various internal baffles and weirs, and enough hold up time for the liquids to stratify under gravity as defined by Stokes Law. Control of these separators is based on pressure control for gas removal rates, interface (oil and water boundary) level control for removal of water, and total level control for removal of the oil phase.

Several attempts have been made to reduce the size and weight of these separators, which typically have a three minute retention time at design flowrates. They must also be designed to operate under the motion characteristics experienced onboard floating structures, which can establish waves inside the pressure vessel, leading to remixing of the separated phases. One method to counteract this problem has been to use vertical separation vessels with plug flow and a thick pad at the oil phase. The produced water phase from these separators can typically have free oil contents of anywhere between 2,000 to 50 mg/1. The separation efficiency of these separators is very. dependant on the following factors: temperature-affects liquid viscosities and hence interfacial drag forces, typically the higher the temperature the better the separation in a shorter time;

specific Gravity or density difference between oil and water, The lighter oils separate quicker; droplet size distribution of oil in water or water in oil, which affects rise or sink rates; and emulsion characteristics, if present.

Produced water treatment from topside first stage separators used offshore, where weight and space is at a premium, has been achieved in the following manner: water from the separator is drawn off under pressure via a level control valve, the water is then passed to either an induced gas floatation unit or more recently a liquid/liquid hydrocyclone. The latter has become the most used although new technology is evolving which combines the benefits of gas assisted floatation and centrifugal forces into one vessel which requires less pressure to achieve the required separation. When treated at the surface facilities, the produced waters are normally treated to achieve oil in water levels of anywhere between 40 to 5 mg/1 free oil in water depending on which area of the world the operation is in, and if the water is to be disposed of to the sea. In sub sea separation this is not a requirement. Only the injectivity of the disposal well or enhanced recovery injection well is of importance, as is the volume of oil lost to the disposal well.

It can be seen therefore that it would be desirable to design a new generation separator, with the ability to be smaller, able to operate on the sea bed and achieve high separation efficiencies, and be capable of producing

consistently good quality separated water with low oil content. A target of 50 mg/1 free oil in water on average would be acceptable, with occasional excursions to around 100 mg/1. Further oil removal would then depend on the reservoir injectivity needs. The oil quality is not important, as the units'main function is to remove bulk water prior to the riser. Removal of 75% or more of the water at the required quality would be desirable.

An ideal separator to be used subsea for bulk water knock out would have the following abilities: manage Gas; remove equal to or more than 75% of the produced water at a quality equal to or better than 50 mg/1 free oil in water; be controlled by water quality and differential pressure rather than level controls ; have less than 30 seconds retention time; have the ability to remove solids on line; and be small enough to be deployed by current work boats, drill ships and rigs.

A liquid/liquid hydrocyclone separator, as shown in Fig.

(3), uses centrifugal force to accelerate separation by increasing apparent G forces.

Liquid-liquid hydrocyclones are capable of separating immiscible, insoluble liquid-liquid mixtures. Fluid normally enters the unit through a tangential or involute inlet. The flow is directed into a vortex without disrupting a reverse flowing core. As the flow is forced

down a hydrocyclone liner, it takes up a helical form along the liner walls. It is accelerated in a conically reducing section, to the high velocities required to create the strong centrifugal forces that promote rapid separation. These velocities are maintained along the liner, frictional losses being offset by a gradual reduction in cross sectional area throughout the conical section.

The denser fluid moves to the walls of the hydrocyclone and is removed at the downstream fluid outlet (underflow). The less dense fluid is drawn into the low pressure core. By applying a back pressure to the water outlet, an oil rich stream flows back up the hydrocyclone, to be removed at the upstream outlet orifice (overflow).

The vortex and reverse flowing core extend down into the tail-section of the hydrocyclone, increasing the residence time and allowing smaller, slower separating droplets to migrate to the core. The total residence time in the hydrocyclone, is in the order of a few seconds. The centrifugal force created in one such unit on the market available from US Filter@ is of the order of 1000 G. Hence, the hydrocyclone is insensitive to motion and orientation.

Dissolved gas break-out within conventional hydrocyclones has not proved to be a problem on any existing installations largely due to:-

i) The pressure drop across the cyclone being a smooth gradient, no sudden changes in geometry existing to accelerate changes in condition; ii). Residence time in the unit (approximately one second) is insufficient to approach any equilibrium condition. Evolved gas is lower in actual volume than predicted-often as low as 20 % of prediction.

Process Control of the De-oiling hydrocyclones is achieved by reference to the ratio of the volumetric flow rates of the de-oiling hydrocyclone overflow (reject Oil: PR) to underflow (Water: PO). This is governed by the ratio of the differential pressure from inlet to overflow to the differential pressure inlet to underflow, referred to as the Pressure Differential Ratio, or PDR.

PDR = PI-PR PI-PO The PDR may be maintained by a pressure differential control valve, (fail closed) in the oil outlet line, under the influence of a pressure differential ratio controller. Preferably, the PDRC can be adjusted to give a PDR of between 1.5 and 1.7. The de-oiling hydrocyclones may be followed by a degassing vessel which may have further means to remove or skim remaining oil from the water.

There are no critical liquid levels or interfaces to be controlled to ensure efficient separation of oil and water, with control being managed by differential

pressures. Operation and maintenance requirements of these units are reported to be low as the hydrocyclones have no moving parts. Therefore, the need for maintenance and operator supervision is reduced, but on the seabed, operator intervention may not be allowed, or may even be impossible. Therefore due to flow restrictions apparent in vessels containing large numbers of hydrocyclone liners and the potential for blockage of the overflow orifice, an improved system is required for seabed separation.

STATEMENT OF INVENTION According to the present invention there is provided a separator for separating out a flow into a first fluid, a second fluid which is more dense than the first fluid, and solids, the separator comprising : a vessel having an inlet for the flow; means for causing the flow to rotate within the vessel ; a first outlet in the vessel for the first fluid, the first outlet comprising a passage, an inlet end of the passage being situated towards a central axis of the vessel; a second outlet for the second fluid, the second outlet being situated towards a side wall of the vessel; and a third outlet for the solids.

Preferably, the central axis of the vessel is substantially vertical. Preferably, the vessel is substantially symmetrical about its central axis.

Preferably, the vessel is cylindrical. Preferably, the means for causing rotation comprises shaping or aligning the inlet so that inlet flow is directed away from the central axis of the vessel.

Preferably, the vessel is operated at above atmospheric pressure, but it may alternatively be operated at below atmospheric pressure or may be open to the atmosphere.

Preferably, a gas vent is provided in an upper part of the vessel.

Preferably, the solids are stored in a lower part of the vessel for later removal. Removal of solids may be carried out continuously or in a batchwise process.

Preferably, a fluidising unit is provided in a lower part of the vessel. The fluidising unit is operated to fluidise settled solids and transport them out of the vessel. Preferably, the third outlet comprises a transport outlet of the fluidising unit.

It is an advantage of the fluidising unit that when the separator is used in a subsea application, the separated solids can be transported to the surface through a riser.

If necessary, the separated solids may be raised to the surface in a separate small riser. This has the further advantage that the solids are not re-entrained back into the oil rich stream, from which they would have to be removed again.

It is important to ensure that the outlet does not re- entrain the solids. Hence, it may be situated above the third outlet and may be shielded. It is also important to prevent the flow out of the second outlet leaving the vessel in such a way that it induces the vortex to break down or interferes with the swirling flow.

Preferably, a core finder is fixed in the vessel above the fluidising unit. A core finder captures and reflects a vortex core formed by the rotation of the mixed fluids.

Preferably, the separator has a hold-up (or retention) time of 10 to 30 seconds.

Preferably, the second outlet is provided in a lower part of the vessel. Preferably, the second outlet is situated in the side wall of the vessel.

Preferably, the outlet passage has a mouth which opens into a part of the vessel at which the first fluid accumulates as it separates out. Preferably, an axis of the outlet passage is substantially vertical.

Preferably, the axis of the outlet passage is aligned

with the central axis of the vessel. Preferably, the outlet passage comprises a pipe. Preferably the pipe extends into the vessel through a top part of the vessel, and preferably projects into the vessel.

Preferably, the vessel is a fluid tight pressure vessel, which can be operated in a hostile environment, such as at the seabed.

Preferably, the outlet passage is at a lower pressure than the vessel.

Preferably, the first fluid comprises a hydrocarbon fluid, such as crude oil and the more dense fluid comprises water, such as produced water and entrained impurities and solids from a bore hole. These solids may comprise sand and debris thrown to the outside of the separator and therefore leave the vessel with the separated water. It is considered that such material is cleansed of oil to a degree by the vortex action in the separator and thus leaves in a relatively clean condition. Depending on the nature of the sand, some erosion of the separator inlet and side wall may be expected. The separator inlet is therefore preferably made of stellite or other such hard faced material to minimise the erosion.

Under normal operating conditions the internal surfaces of the separator are not susceptible to scale deposition, due to high local fluid velocities; hence separation

performance will not be impaired. Low pressure and low velocity areas, such as downstream of the second outlet, may be susceptible to scale deposition. This effect can be minimised by the use of a suitable scale inhibitor chemical.

According to a further aspect of the present invention there is provided a separator for separating out a flow into a first fluid, a second fluid which is more dense than the first fluid, and solids, the separator comprising: a vessel having an inlet for the flow; means for causing the flow to rotate in a vortex within the vessel; a first outlet in the vessel for the first fluid, the first outlet comprising a passage, an inlet end of the passage being situated towards a central axis of the vessel; a second outlet for the second fluid, the second outlet being situated towards a side wall of the vessel; a third outlet for the solids; and a core finder fixed in a lower part of the vessel, the core finder being adapted to capture and reflect the core of the vortex towards the inlet end of the passage.

A preferred embodiment of the present invention provides a separator acting subsea which amalgamates some of the features of normal three phase separators, de-oiling hydrocyclones and degassing/floatation vessels, at the lowest operable pressure drop. The unit can be controlled by pressure differentials and not levels, with an override provision based on water quality measurement.

Various processes may be used to remove bulk gas rapidly, such as an auger separator, a simple tee, a cyclonic device and a pipe expansion. One of these units will be utilised in the sub sea process as the first processing unit (A) this will have the benefit of simplifying the operation of a pump (G), if used, and certainly reduce the size of the separator (B). In some cases high gas flows or slugs will not be an issue and this unit can be omitted from the process.

The present invention provides a reliable method of removing, on the sea bed, at least 75% of the produced water. It also provides management of solids, so that the liquid volumetric flowrate to a riser would be reduced, allowing more wells to be drilled and produced with existing facilities. This would in many cases increase the production economics and recoverable reserves of both existing oil production facilities offshore, new offshore installations and offshore marginal fields.

Preferably, the system is able to manage slugs of gas up to 1000 pipe diameters without a process upset (that is to say a volume of gas as a single phase which is

equivalent to a volume of gas at a given pressure and temperature inside a given inside diameter pipe from the wellhead, flowing at a given velocity, as a function of the separation minimum hold up or retention time needed for process or control systems to manage the said gas slug). In a preferred embodiment the system achieves one or more of the following key process steps:- 1. Management and control of gas slugs.

2. Separation of a minimum 75% of free water.

3. Management of produced solids.

4. Re-injection of produced water.

5. Seawater injection.

6. Management of produced water and seawater filtration media wash waters.

7. Increasing production from well by booster pumping on the sea bed to lower the wells hydrostatic head.

In an alternative embodiment of the invention, a vortex valve can be incorporated into the pre-water knockout separator. A major benefit of using a vortex valve is the complete lack of actuated control valves with moving parts on main flow lines, the ability to manage slugs and in a slowly swirling vessel, the ability to detect and manage interface levels. There is also a considerable benefit in not requiring hydraulic or electric power to actuate a vortex valve and its ability to respond instantly, ie with no delay between cause and effect.

It is an advantage of the separator that it is capable of managing gas slugs, solids and liquid/liquid separation

with no moving parts or valve actuators on the main flow lines.

It is a further advantage of the separator that, in a subsea application, the fluidising unit can move any separated solids to the surface for treatment by means of a riser.

In a preferred arrangement of the invention inlet water can be used to wash media in a radial type filter, and the very small amount of media wash water used can be displaced into a riser for treatment at the top side (in a subsea application).

Preferably, the radial filter utilises ceramic media.

If produced water is injected into reservoirs to enhance recovery or into a disposal zone, it is necessary to be able to manage the water quality in terms of solids concentration. There is not always an available injection zone with a very high permeability, and therefore it is preferable to have the ability to filter the water to the desired injection quality. Preferably, the filter should be capable of operating for up to ten years without a change of media. Therefore, ceramic media is an ideal media for the filter.

BRIEF DESCRIPTION OF THE DRAWINGS For a better understanding of the present invention, and to show more clearly how it may be carried into effect,

reference will now be made, by way of example, to the accompanying drawings, in which:- Fig (1) is a diagram of the principal steps in a process used to separate oil from water on the seabed; Fig (2) is the production profile of a typical oil producing well; Fig (3) is a diagram of a conventional de-oiling hydrocyclone; Fig (4) is a cross-section through a separator in accordance with the present invention; Fig (5) is a longitudinal cross-section through a fluidising apparatus ; Fig (6) is a cross-section on line AA in Fig (5); Fig (7) shows an alternative filtering arrangement in which a low pressure high flow rate de-oiling hydrocyclone is provided downstream of a filter assembly; and Fig (8) is a computer representation of cyclone flow.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENT Referring to Fig (1), a system is described which has the required process units needed to create a modular subsea separation system.

Fluids from the production well or wells (W) report to a gas liquid separator (A), free gas from (A) exits the separator under pressure control and may or may not report to an inductor or jet pump (C) and from (C)'s outlet to the production riser. Liquids and solids from (A) report directly, or via a booster pump (G), to free water knock out separator vessel (B). The continuous oil phase from (B) reports under differential pressure control to the suction side of the booster jet pump (C), or direct to a production riser as required by the pressure balance across the system. The continuous water phase from (B) reports under differential pressure control or quality control (oil in water content) either directly to an injection/disposal well or zone via injection pump (H), or to a water polishing unit (E) to further reduce the oil in water content of the produced water.

As analytical methods of remotely monitoring the produced water quality becomes reliable at subsea locations, this water, if clean enough and gas free, could be disposed of directly to the sea. Produced solids from the well which have settled out in (B) are removed in a slurry by a fluidising unit such as that described in our earlier UK application No 0212728.0. This unit is capable of continuous or batch operation at set concentrations of solids to liquids such that they can report to a sand separating unit (D) which may be of a cyclonic type. Once (D) is charged with solids to a predetermined volume, it is isolated from (B) thus allowing a small volume of treated water from injection pump (H) at elevated

pressure to transport the solids again with a fluidising unit to either a disposal zone, or if clean to the sea bed, or (preferably) to the production riser downstream of the jet pump (C) to avoid erosion of the jet pump internals and unnecessary maintenance on the sea bed. The solids are then removed at the topside production facilities. Waste liquid streams from (D) and (E) when used report to the suction side of (C) or the riser as the case may be.

In some circumstances the producing hydrocarbon reservoir in question may benefit from water injection to enhance recovery or maintain reservoir pressures, in such cases sea water is normally filtered to meet reservoir permeability and dissolved oxygen is normally removed down to around 20ppb (parts per billion), some scale and corrosion inhibitors can be injected to the water, as can biocides. If the volume of water needed to be injected can be met with produced water from the well then this can be used, again in some cases following some filtration. In many cases however the volume of produced water is insufficient for the reservoirs needs and must be supplemented by aquifer waters, if readily available, or if not by seawater. It is known that the mixing of waters with varying levels of total suspended solids (TSS), total dissolved solids (TDS), biological oxygen demand (BOD), chemical oxygen demand (COD), temperatures, dissolved oxygen and carbon dioxide levels, can vary the resultant waters pH (acidity verses alkalinity) which in turn affects corrosion rates, scaling tendencies and particulate precipitation. This water chemistry needs

careful management in order to ensure good injectivity rates and avoid reservoir damage.

When water injection is required therefore it can be from the following sources: Raw or treated produced water from the hydrocarbon reservoir Raw or treated seawater Raw or treated aquifer water A mixture of produced water and aquifer water A mixture of produced water and seawater Aquifer water requires a well to be drilled and must be available in sufficient quantities in order to be viable, so seawater is likely to be the most abundant and economic source available. Consequently, in most cases produced water removed and treated on the seabed, will be mixed with seawater to make up the required volumes of injection water for enhanced recovery. In this case filters (E) and (F) have different filtration needs to overcome. Filter (E) will experience fine solids which may be oil wetted but are normally fairly resistant to deformation by pressure across them, i. e. easier to trap in a filtration media bed, this would usually allow the filtration flux rate (unit flowrate of fluid per unit surface area of filter media) normally measured as metre cubed per metre squared per second, or m/s to be quite high, however these fluxrates can not be used when filtering the oil which has been removed from the captured solids as the oil has the ability to migrate through the media bed at these high flux rates. Oil can

be trapped efficiently at lower flux rates in a media bed. It follows therefore that filter (E) must be sized to meet the required oil capture or removal rate, rather than the solids removal rate. At lower flux rates solids removal efficiencies generally improve, but the unit's size increases for a given flowrate. Filter (F) will only have to remove solids with no oil, when it is treating seawater or aquifer waters. This will allow the unit to be designed for a higher flux rate, and hence be of a smaller size.

Turning now to the washing of filters (E) and (F). They again have different problems to overcome when used on the seabed. Filter (E)'s media wash water will contain high levels of solids and oil which are inadmissible to the sea, and will therefore need to report to the riser for further treatment on surface facilities, whereas filter (F) is removing inert solids or zooplankton with no associated oil. It may therefore be allowable to discharge the media wash water from filter (F) directly into the sea via a stack to allow the concentrated solids to plume or spread over large distances by use of under water currents.

It may be practicable to combine filters (E) and (F) and send all media wash waters to the surface facilities, particularly when a forward washing filter is used which minimises waste volumes. Other advantages of combining (E) and (F) into a single unit are: A lower number of valves, pumps or moving parts on the seabed to maintain

The filter can initially be used for treating seawater or aquifer water, and start to treat produced waters later in the production cycle Mixtures of the waters that produce solids by precipitation can be mixed upstream of the filter, which will then remove the said solids.

No discharge to the sea prior to full chemical analysis and recording.

Injection pump (H) can be a normal centrifugal pump, or a down-hole type. as would currently be used as ESP's (electrically submerged pumps).

Fig (4) shows a free water knockout separator (B) comprising a pressure vessel or tank 1 with an inlet for well fluids 2 which is preferably tangential or has means to cause the fluids entering 1 to rotate in a vortex, a treated water outlet means 3 situated at the lower end of vessel 1, an oil rich outlet means 4 at the upper end of vessel 1 which can extend as required into vessel 1 axially to a position where an oil pad will exist, an inlet or outlet means 5 for control of pressure or removal of gas from vessel 1, a core finder 6 for the capture and reflection of the vortex core produced by the rotational motion of the fluids in vessel 1, a fluidising unit 7, which when fed by water at a higher pressure than that existing in vessel 1, will fluidise settled solids and direct them to a solids outlet 8.

Figs (5) and (6) illustrate a fluidising apparatus comprising a flow chamber 102 having a fluid inlet 104

and a fluid outlet 106. The flow chamber 102 comprises a housing in the form of a cap 108 having a side wall 110 and a top 112 which in the region 114 is generally in the shape of a cone with a concave side wall. The underside of the top 112 is provided with an annular recess 116 in which is located a cylindrical flow guide 118. As best shown in Fig (6), the upper portion 120 of the flow guide 118 is provided with a series of tangential slots 122a to 122f. The lower portion 124 of the flow guide 118 has an external thread which cooperates with an internal thread formed in an annular flange 126.

A fluid outlet 106 is defined between the side wall 110 of the cap 108 and the flange 126 and an annular flow passage 128 is defined between the side wall 110 of the cap 108 and the upper portion 120 of the flow guide 118.

The annular flow passage 128 is continuous with the fluid outlet 106, so that the fluid inlet 104 communicates with the fluid outlet 106 by means of the tangential slots 122a to 122f and the flow passage 128. Directly above the flow chamber 102 is located a transport outlet 130.

In use of the fluidising unit in a pressurised system, fluid under pressure enters the fluidising unit through the fluid inlet 104, passes down the flow guide 118 and exits the flow guide tangentially via the slots 122a to 122f (as the open end of the flow guide 118 is closed by the cap 108). The cap 108 also acts as a swirl enhancer and is positioned such that its side wall 110 forms one side of the said annular flow passage 128 around the tangential slots 122a to 122f. The cap 108 is longer than the slots 122a to 122f, such that it overlaps the

slots by an amount'd'and defines the fluid outlet 106 by which the concentrated swirling fluid exits the flow chamber 10 The profiled region 114 of the cap 108 is shaped in order to encourage a stable fluid regime above the flow chamber 102. The swirling flow exiting the flow chamber 102 fluidises, mixes and breaks up settled or partly settled solids adjacent to the flow chamber 102, thereby forming a mobile slurry, which is directed towards the transport outlet 8 (Fig (4) ) from where it can be directed to a slurry pipeline or for further processing. The transport outlet 8 may, for example, comprise a substantially horizontal pipe or a pipe with a bend (preferably a 90 degree bend), and it may be funnelled, such that it flares outwardly towards the flow chamber 102.

The separator vessel (B) receives well fluids either indirectly from a bulk gas removal unit or directly from the well itself. Referring to Fig (4), the fluids enter the separator at inlet 2 which imparts a rotational force on the fluids, the purpose of which is to enhance the separation forces above those which exist under normal gravity. It is not intended to create the same level of separation force as those existing within de-oiling hydrocyclones, rather to develop a balance between centrifugal force and retention time, the separator is designed to have a retention time of less than 20 seconds which for a given flowrate is considerably smaller than a conventional three phase separator, but larger than a de- oiling hydrocyclone. The fluids rotating in vessel 1 start to separate, with any free gas migrating to the top of vessel 1, and oil moving to the centre of vessel 1 and

upwards to sit above the water which has migrated outwards to the wall of vessel 1 and downwards. Any solids entering with the fluids report to the bottom of vessel 1. The gas outlet/inlet 5 is used to keep a gas blanket at the desired pressure above the oil pad, this achieves two functions. The first function is to provide additional pressure to remove oil from vessel 1, via oil outlet 4, and the second function is to assist the establishment of a strong vortex by establishing a gas core for the oil to migrate to.

A pressure control valve on outlet 5 is used to modulate the pressure inside vessel 1 to the desired level. After the liquids have been rotating for some time, an oil pad will form on top of the water, it is intended to allow this pad to exit vessel 1 via oil rich outlet 4 which is always below the total level of liquids in vessel 1 and in the oil phase. Control of the flowrate of the oil rich stream leaving outlet 4, is obtained by the gas pressure above the oil pad which is adjustable. Separated produced water leaves vessel 1 via outlet 3; this is preferably controlled by a water quality monitor and a flow control valve or the speed of the water injection pump (H).

Vessel 1 may also have its split ratio (ratio of water removed to oil removed) controlled by differential pressure similar to that described earlier for de-oiling hydrocyclones. Solids that have settled into the base of vessel 1 are fluidised and removed to the next process as may be the case by the use of a hydro transport unit such as that described in our earlier UK application No 0212728.0 or similar.

Preferably, the separator (B) is able to manage the complete flow range of phases it is likely to experience during the life of the field. For example in the early days of production there may be very little water, whereas at the final stages of production it is most likely that the bulk phase will be that of water. Control of this variation in flow is best achieved by monitoring water quality on line using instruments such as a Jorin Vipa unit or similar. This can be achieved using fibre optic communication from the seabed to the surface facilities with very fast response times.

The Vipa unit is a video microscope that films droplets and solids as they pass through a sample cell at line pressure; this information is then digitised and fed to a computer programme that can determine oil in water mg/1 and solids content, both of which are important factors when considering the next steps of injection or filtration. Should water quality not meet design requirements for whatever reason the water out line 3, will close and allow all fluids to depart vessel 1 via the oil outlet 4, after a set time the water will again be sampled and when it meets specification it will be allowed to move on to the next process stage.

Referring to Fig (1), solids will normally be constantly removed using a small amount of treated produced water from down stream of injection pump (H) and fed into sand cyclone (D), the overflow from (D) joins the oil rich stream from (B), (D) will be made up of a solid liquid cyclone section that has a small sand holding volume and a lower section which is isolatable by valve means from

the cyclone section, such that once isolated and full of solids it can be elevated in pressure by water from downstream of injection pump (H) via its fluidising hydro transport unit, such as our earlier UK application No 0212728.0, in order to transport the solids to the riser downstream of any inductor or jet pump (C) to avoid erosion. If required the solids from (D) can be raised direct to the topside in a separate small riser to avoid re-entraining them back into the oil rich stream, from which they would have to be removed again. The bottom sand pot of cyclone separator (D) therefore operates as a batch process controlled by a solids level monitor or other means within the sand pot.

Filters (E) and (F) or a combined unit to achieve the filtration after mixing of the waters to be injected will preferably be of the type described in our earlier UK application No 0308291. 4, or similar, as these type of filters wash their filtration media online, and by use of their media wash vessel can displace oily waste wash water back into the riser by operating the fluidising unit in the wash vessel at elevated pressures. In certain systems it may be possible to use cyclone separator (D) to act as the Filter (E) and (F)'s media wash vessel, hence reducing the number of pressure vessels on the sea bed.

Depending on the process requirements it may be beneficial to use a low pressure high flowrate less efficient de-oiling hydrocyclone downstream of (B) on the water outlet as typically shown in Fig (7), particularly

where no filtration is required to meet reservoir injectivity or disposal zone requirements.

As part of the development of cyclonic separation, a computational fluids dynamics (CFD) model has been developed. This is based on both theoretical and measured parameters, so that the resultant outputs can be used to simulate separation efficiencies within dynamic process modelling tools such as Hysis. This allows rapid simulation of expected performance, should the modular subsea separation system be moved from well to well. Fig (8) is a typical output for cyclone modelling showing pressure contours and solid trajectories.