Subsea processing of crude oil

Abstract

A subsea production unit for subsea treatment of oil has a frame that supports an onboard multiphase separation system for separating gas and water from a wellstream containing oil. The subsea production unit also includes an onboard water treatment system for cleaning oil from water that is produced by the separation system.

Claims

1. A method of separating fluids from a multiphase oil-containing wellstream, the method comprising: separating gas and water from the wellstream to produce oil; cleaning oil from the water that is produced by the separation step by passing the produced water through at least one flotation unit and mixing the produced water with gas separated from the wellstream in the separation step; storing oil produced by the separation step in a storage tank and performing the cleaning step also on water settled from the stored oil; and injecting the produced water, with gas separated from the wellstream in the separation step and gas separated from the oil in the storage tank, into a subsea reservoir after cleaning; the separation, storage and cleaning steps each being performed subsea onboard a frame of a transportable subsea production unit provided on the seabed.

2. The method of claim 1, comprising passing the produced water through first and second flotation units in series, the water output from the first flotation unit being input to the second flotation unit.

3. The method of claim 1, further comprising injecting, with the produced water, processed water drawn from surrounding seawater.

4. The method of claim 1, comprising effecting gas separation on the wellstream upstream of said water separation on the wellstream.

5. The method of claim 4, comprising performing water separation in at least one dual pipe separator.

6. The method of claim 5, comprising conditioning the wellstream in a pre-separator pipe section downstream of gas separation and upstream of the dual pipe separator.

7. The method of claim 6, comprising guiding the wellstream to follow a sinuous path in the pre-separator pipe section.

8. The method of claim 7, comprising guiding the wellstream to reverse in flow direction in the pre-separator pipe section.

9. The method of claim 1, preceded or followed by transporting the subsea production unit to or from a subsea location.

Description

(1) In order that the invention may be more readily understood, reference will now be made, by way of example, to the accompanying drawings, in which:

(2) FIG. 1 is a schematic diagram of a subsea processing system in accordance with the invention;

(3) FIG. 2 is a schematic side view of a pre-separator pipe section of the system of FIG. 1, in longitudinal section;

(4) FIG. 3 is a schematic side view of a dual pipe separator in longitudinal section, which is positioned in the system of FIG. 1 immediately downstream of the pre-separator pipe section exemplified in FIG. 2;

(5) FIG. 4 is a perspective view of a subsea production unit in accordance with the invention installed on the seabed, showing a functional module being removed from a surrounding frame of the unit to be lifted to the surface for servicing;

(6) FIG. 5 is a perspective view showing the positional layout of various functional modules of the subsea production unit of FIG. 4, with the frame of the unit omitted for ease of viewing;

(7) FIG. 6 is a schematic detail side view showing the compact arrangement of a pre-separator pipe section and a dual pipe separator in the layout shown in FIG. 5;

(8) FIG. 7 is a block diagram of alternative subsea degassing and water separation facilities, showing an additional pipe separator stage for water separation;

(9) FIG. 8 is a block diagram corresponding to FIG. 7 but showing an additional dual pipe separator stage for water separation; and

(10) FIG. 9 is a schematic process flow diagram corresponding to the arrangement shown in FIG. 8.

(11) It should be noted that conventional piping equipment, such as some valves, may not be represented in these simplified drawings for clarity.

(12) Referring firstly to the subsea processing system 10 shown in FIG. 1 of the drawings, this system has optional provisions for water discharge and for water re-injection. Water re-injection may be beneficial to maintain reservoir pressure, either to maintain or to increase production.

(13) In the system 10 shown in FIG. 1, a wellstream of production fluids flows from a subsea production wellhead 12 via a conventional ‘Christmas tree’ structure 14 installed on top of the wellhead 12.

(14) Optionally, the wellstream flows into a production header 16 that serves as a manifold to divide the flow into parallel paths. Processing of the portion of the wellstream on one of those parallel paths will now be described, it being understood that other portions of the wellstream on the other paths may undergo similar parallel processing steps. The outputs of those parallel processing steps may be combined at any convenient stage.

(15) Initially, the wellstream may flow through a cyclonic de-sander 18 to remove substantially all of the sand that may be entrained in the production fluids. Such sand could otherwise promote erosion, corrosion or clogging of the pipework and equipment downstream. Other de-sanding technologies are known, for example those that employ gravity.

(16) Conventionally, sand management generally relies upon down-hole systems such as sand screens or gravel packs. However, such down-hole systems cannot always be used because they can impair production. Even when down-hole systems are used, any failure that causes sand to be produced will have to be managed by back-up systems.

(17) Oily sand removed by the de-sander 18 is conveniently dumped into a removable sand storage tank 20, which can be raised to the surface periodically for topsides treatment or disposal of the sand within and to be replaced with an empty sand storage tank 20. This solution is practical for low to moderate rates of sand production. Higher rates of sand production can be managed by instead re-combining the removed sand with the production fluids after subsea processing, for later separation and clean-up topsides.

(18) Next, the de-sanded wellstream flows through a bulk gas separation unit, exemplified here by a harp gas separator 22. This removes a major portion of the gas in the wellstream, which is output from an upper branch of the gas separator 22 as wet gas. Some gas will remain in the wellstream downstream of the gas separator 22, but not to a problematic extent. In any event, much of that residual gas will be removed in subsequent subsea processing steps, as will be explained.

(19) The substantially-degassed liquid portion of the wellstream flows from the gas separator 22 into a bulk water separation unit, exemplified here by dual pipe separators (DPSs) 24 operating singly or preferably in parallel. This bulk water separation step removes a major portion of the water from the wellstream, which is output from the DPSs 24 as oily water. Typically, however, the resulting oil will still contain 5% to 10% of water by volume.

(20) More specifically, in practical embodiments, the mainly liquid flow downstream of the gas separator 22 enters a manifold that divides the flow into a number of branches corresponding to the number of DPSs 24 in a parallel array. The number of parallel DPSs 24 may be chosen for specific installations based upon factors such as the reservoir production profile, the results of high-pressure separability tests performed on production fluids during design qualification, and requirements for flexibility through the design life of the system 10.

(21) From the manifold, each DPS 24 is preceded by a substantially horizontal pre-separator pipe section 26 of typically 5 to 10 metres in length before the flow enters the upwardly-inclined DPS 24 itself. In this respect, reference is made to FIG. 2 of the drawings, which shows the layered flow of oil 28 and water 30 along a pre-separator pipe section 26 and the mixing characteristics of those layers 28, 30 at different points along its length.

(22) The flow is pre-separated within the pre-separator pipe section 26 before entering the DPS 24 through an inlet 32 at the lower end of the DPS 24, as shown in FIG. 3. The flow velocity in the pre-separator pipe section 26 is controlled to be typically between 0.5 to 1.5 m/s, depending upon the length of that section. Typically, the flow will pre-separate in that section 26 for about five to ten seconds before entering the DPS 24 itself.

(23) With reference to FIG. 2, the principle underlying these pre-separation parameters arises from the observation that the established dispersion band 34, or the phase between oil 28 and water 30, diminishes rapidly if the flow velocity differs between these two principal liquid phases. This velocity requirement is fulfilled if a slightly-upward pipe bend of 10-15 degrees from the horizontal is provided at the inlet 32 of the DPS 24, corresponding to the outlet of the pre-separator pipe section 26 as shown in FIG. 2.

(24) FIG. 3 shows that the inlet 32 of the DPS 24 carries the pre-separated oil 28 and water 30 into a flared and perforated inner pipe 36 of the DPS 24. The inner pipe 36 is concentric with and contained within a closed outer pipe 38 of the DPS 24 and extends just over halfway along that outer pipe 38.

(25) A velocity difference between the oil 28 and the water 30 is established due to the specific gravity differences between those liquids as they climb within the upwardly-inclined DPS 24. This density difference also improves separation of water 30 dispersed in the oil 28, causing the heavier water 30 to sink and the lighter oil 28 to rise within the outer pipe 38 of the DPS 24.

(26) The outer pipe 38 has a water outlet 40 at its lower end and an oil outlet 42 at its upper end to draw off the respective liquid outputs 28, 30. As noted above, it is inevitable that the oil output will contain some water and that the water output will contain some oil in practice.

(27) Preferably, in practical embodiments, the geometry of the pipework between the gas separator 22 and the DPS 24 creates a liquid lock by locating the top of the water outlet 40 of the DPS 24 at substantially the same level as the inlet to the gas separator 22. This liquid lock prevents carry-under of gas and ensures that the pre-separator pipe section 26 is mainly water-filled. As incoming oil 28 is forced through the water 30 in the liquid lock, separation will occur.

(28) The separation of water 30 from oil 28 is suitably controlled using known capacitance measurement technology. The set location of the water level in the DPS 24, being the interface of emulsion 44 between oil 28 and water 30, may be monitored to control a water outlet valve (not shown) accordingly.

(29) The use of compact DPSs 24 ensure a small footprint, retrievability and effective separation of oil 28 and water 30. Their small-diameter pipework facilitates the use of the system 10 in the full depth range from shallow to ultra-deep waters.

(30) It has been found to be beneficial to remove free gas from the wellstream before the remaining liquid enters the bulk water separation unit comprising the pre-separator pipe section 26 and the DPS 24. Free gas could otherwise adversely influence the flow, producing a slug flow pattern. In this respect, the vertical pipes of the harp gas separator 22 provide a large volume to absorb the fast-arriving fluids and to provide sufficient volume for the free gas. Thus, the gas separator 22 suppresses slugs to smooth the liquid flow entering the bulk water separation unit, in addition to removing the free gas.

(31) Consequently, by separating gas from liquid in the wellstream, the bulk water separation unit performs subsequent water separation more effectively. Synergistically, the separated gas is also used for cleaning residual oil from the separated water, allowing the separated water to be discharged or re-injected as will be explained below.

(32) Oil flowing from the DPS 24 is channelled directly into a heated subsea oil storage and stabilisation tank 46. which settles and separates in the tank 46 into an oil layer of export quality atop a layer of oily water. The oil may be offloaded periodically from the tank to a shuttle tanker 48 at the surface, via a flexible offloading system 50 in this shallow-water example. Conveniently, the shuttle tanker 48 can carry the pumping equipment that is necessary to draw oil from the tank 46.

(33) Wet gas accumulating at the top of the oil storage and stabilisation tank 46 is drawn off to be combined with the wet gas flowing from the gas separator 22. Conversely, a water removal pump 52 draws accumulated oily water from the lower part of that tank 46. The oily water from the tank 46 is combined with the oily water output from the DPSs 24, and with any oil that may have settled out from the oily sand held in the sand storage tank 20. By way of illustration, oil may initially be present in the resulting combined flow at a level of >4500 ppm.

(34) The oily water then enters a water treatment system 54. In this example, the water treatment system 54 comprises a series of two compact flotation unit (CFU) stages. In each stage, a mixer 56 mixes incoming oily water with some of the wet gas output from the gas separator 22. The resulting mixture of oily water and gas is then separated in a CFU 58 into an output of treated water and another output of a gas/oil mixture.

(35) A CFU 58 is a multiphase separator that needs no moving parts and requires no external energy input. It is reliable and highly efficient in separating water, oil and gas to produce high-quality treated water, even with a short retention time.

(36) The CFU 58 comprises a hollow cylindrical vessel that is resistant to hydrostatic pressure. That vessel defines an internal flotation chamber that is generally circular in horizontal cross-section. Incoming oily water enters the chamber substantially horizontally and tangentially to impart swirl. The separation process is aided by internal features of the vessel and by a gas flotation effect caused by the release of residual gas from the water and/or by added gas.

(37) These combined processes act on fluid components of different specific gravities. Small oil droplets are caused to agglomerate and coalesce to produce larger oil droplets, making it easier to separate them from water. A continuous oil or emulsion layer is created at an upper liquid level of the flotation chamber, while treated water exits through the bottom of the vessel. On occasion, however, process optimisation may involve the introduction of external gas and/or flocculants.

(38) The separated gas/oil mixture is removed continuously from the CFU 58 via an outlet pipe suspended at the top of the vessel. This multiphase reject flow may be controlled by a valve in the outlet pipe. The liquid flow rate of the reject flow is typically about 1% of the overall inlet water flow to the CFU 58, and the oil content in that liquid is typically 0.5% to 10%.

(39) By way of example, a CFU 58 having a flotation chamber with an operational volume of just 2.4 m.sup.3 can treat a water flow of up to 220 m.sup.3/h (33 000 bpd). Higher flow rates can be achieved by arranging multiple CFUs 58 in parallel.

(40) The CFU 58 in the first stage of the water treatment system produces an output of partially-treated water with a much-reduced oil content of about 100 ppm, which serves as the water input into the mixer 56 of the second stage of the system. The CFU 58 in the second stage further reduces the oil content in the partially-treated water so as to output fully-treated produced water that preferably contains oil at a level of <30 ppm, for example 9 ppm.

(41) The outputs of gas/oil mixture from the successive CFU stages are combined and fed into a gas/oil separator 60, which is exemplified here by a gas/oil knockout drum. The gas/oil separator 60 outputs oil that may still contain a minor fraction of water. That oil is fed into the oil storage and stabilisation tank 46 to settle and separate out before being offloaded. The gas/oil separator 60 also outputs wet gas, which is combined with the wet gas flowing from the gas separator 22.

(42) The produced water from the two-stage water treatment system 54 is clean enough to be discharged, optionally, directly into the sea via a valve 62 and a discharge outlet 64. Alternatively, the produced water can be re-injected into the well, conventionally via a Christmas tree structure 66 atop a water/gas injection wellhead 68. In that latter case, the second stage of water treatment could be omitted.

(43) An oil-in-water sensor in a flowmeter 70 measures the oil concentration in the produced water to ensure that the concentration is below appropriate thresholds, for example <100 ppm for re-injection or <30 ppm for discharge to sea.

(44) The ability to discharge or to re-inject the produced water saves valuable space in oil transport lines, increasing the amount of oil that can be produced using the available infrastructure. For example, bulk separation of typically 50%-75% of water from the wellstream allows for tie-in of more wells to a manifold.

(45) Subsea discharge of produced water has other important benefits. For example, it eliminates the need to transport large volumes of water from production sites to tieback hosts, reducing the cost of the production system. This benefit increases with water depth and tie-back distance.

(46) By decreasing hydrostatic pressure on subsea production flowlines, subsea discharge of produced water helps to reduce back-pressure on a subsea wellhead and allows for more production. The resulting effect provides additional economic benefits to justify the capital expenditure for the plant.

(47) Subsea discharge of produced water also minimises the topside equipment footprint and so protects much of the production equipment from damage by bad weather.

(48) For the purpose of re-injection, the produced water passes through a water/gas injection system 72. Here, the wet gas flowing from the gas separator 22, supplemented with wet gas from the gas/oil separator 60 and from the oil storage and stabilisation tank 46, is combined with the produced water to be re-injected.

(49) In the water/gas injection system 72, the produced water is fed via a one-way valve to a water injection suction header 74, from which a multiphase water injection pump 76 draws the water and outputs the water to the Christmas tree structure 66 under pressure. The water flowing through the water injection pump 76 may contain up to about 10% gas by volume.

(50) Optionally, as shown, the pressurised water from the water injection pump 76 flows through a water injection discharge header 78 interposed between the water injection pump 76 and the Christmas tree structure 66. The header 78 is a manifold structure that can receive water from any parallel water treatment units (not shown) and/or that can output water on parallel paths to any other injection wellheads via respective Christmas tree structures (also not shown).

(51) Using a header 78 such as this, water injection arrangements can be tailored to the individual reservoir. Separate water/gas injection systems 72 could be located at individual wells, or high-pressure in-field lines could distribute injection fluid to multiple wells from a single water/gas injection system 72.

(52) Where produced water flowing from the water treatment system 54 is to be re-injected, the wet gas could simply be combined with that produced water. In this example, however, sea water is also drawn from the sea and processed in a filtration and treatment plant 80 to supplement the produced water by co-mingling, for example in a venturi system, for re-injection. Thus, the wet gas is firstly mixed with the treated seawater in a gas ejector 82 and then the resulting multiphase mixture is combined with the produced water in the water injection suction header 74.

(53) Moving on now to FIGS. 4 and 5 of the drawings, these show a subsea production unit 84 in a practical embodiment of the invention. Like numerals are used for like features.

(54) FIG. 4 shows the unit 84 installed on the seabed, complete with an elongate supporting frame 86 that surrounds various functional or processing modules within the unit 84. Those modules implement the various sub-systems of the system 10 described above.

(55) FIG. 5 omits the frame 86 for ease of viewing the positional layout of the illustrated modules. The layout shown there is an example that omits some of the modules required to implement the system 10 described above, which could be provided either onboard the unit 84 or outside and connected to the unit 84, for example on a neighbouring similarly-constructed unit installed on the seabed.

(56) Specifically, the frame 86 of the subsea production unit 84 shown in FIG. 4 comprises a steel deck 88 that supports various processing modules and their connecting pipework. A GRP superstructure 90 is bolted together and connected to the deck 88 so that the deck 88 and the superstructure 90 together form a truss structure to carry the heavy payload of the processing plant during towing and installation. Conveniently, buoyancy required for towing the unit 84 to the production site may be pre-shaped and assembled into the superstructure 90.

(57) Subsea production units 84 of the invention are apt to be fabricated in dry dock facilities. To maximise the choice of available fabrication facilities, it is important that the size of such units 84 is minimised. By way of example, a subsea production unit 84 as shown in FIG. 4 may have a length of about 41.3 m, a width of about 9.2 m and a height of about 7.6 m.

(58) An advantage of the GRP/steel hybrid structure of the frame 86 is that sections of the superstructure 90 can be fabricated at a supplier's premises and shipped to the launch site to be assembled onto the foundation of the steel deck 88 in a short period of time. Another significant benefit is that this solution allows for onshore prefabrication and for a full system check to be performed onshore, or in shallow water inshore, before tow-out to an offshore location.

(59) As is conventional, the superstructure 90 has tapered ends to protect the unit 84 against over-trawling. Removable GRP cover panels may be provided on the superstructure to minimise snagging risks and beneficially to reduce hydrodynamic flow of water within the unit as the unit moves through the water during installation.

(60) Some cover panels, particularly on the sides of the superstructure, can be removed after installation to facilitate ROV access. Also, the upwardly-facing cover panels 92 on top of the superstructure 90 can be opened to provide apertures for access to the processing modules supported in upwardly-opening silos on the steel deck 88 beneath.

(61) The processing modules are retrievable from their silos by being lifted through the apertures as shown in FIG. 4, which shows a module 94 comprising a flowmeter 70 being lifted by a wire 96 hanging from a winch or crane of a surface vessel, not shown. A work-class ROV (WROV) 98 is shown performing and supervising the necessary subsea connection, guiding and monitoring operations. It will be apparent that the aforementioned optional onboard removable sand storage tank may be lifted and replaced in a similar fashion.

(62) More generally, subsea processing systems 84 of the invention can comprise a variety of processing modules depending upon the type of processing needed for a particular field development. To reduce costs, standardised modular designs are preferably used throughout the system of the invention. This allows providers of subsea processing equipment to develop their own system modules, and thereafter those modules can be integrated into the subsea processing unit 84 in much the same way as topside platform modules.

(63) Standardised transport and installation frames 100 surrounding the required modules can be installed into the subsea processing unit 84 in a plug-and-play fashion. Such frames 100 also help to reduce variations in terms of handling and installation procedures.

(64) Installation and retrieval of modules may be performed according to the following simplified process: 1. A module such as a flowmeter module 94 including a transport and installation frame 100 is lowered from a vessel through a moonpool of the vessel, where possible, to reduce weather dependency. Alternatively the module 94 may be lowered over the side of the vessel. 2. The WROV 98 guides the module 94 into an appropriate silo of the subsea production unit 84 through the top of the unit 84. No guide wires are required. A handle may be provided on the module 94 for the WROV 98 to grab to apply lateral guide forces to the module 94. Upwardly-extending guide formations around the silo guide the transport and installation frame 100 into the correct position in the unit 84, while also aligning piping and electrical connectors between the unit 84 and the module 94. 3. Once aligned, the module 94 is lowered further into the silo of the unit 84. Dampers are suitably provided to ensure that the module 94 will stop softly some 300 mm above the mechanical connectors. The WROV 98 will then lower the module 94, for example by a screw mechanism or hydraulically, and mate the connectors in a fully controlled manner. 4. Depending on the module 94, various connections will be necessary, for example electrical connections, hydraulic connections and piping. Normally, such connections will be vertically-oriented, coming up from main piping that runs at the level of the deck 88. Pipe connections may be made by standard clamp connectors actuated by the WROV 98.

(65) The water management system of the invention does not need pumps or compressors demanding a large power supply. However some units such as flowmeters, oil-in-water meters and remote-controlled valves will require control cables and minor power cables. Wet-mate connectors are available for this purpose. In this way, power can easily be provided in-field from a central power station to remotely-located water management systems.

(66) Turning next to the layout of the modules shown in FIG. 5 and schematically in FIG. 6, a harp gas separator 22 and an array of parallel DPSs 24 are shown side-by-side. The DPSs 24 of the array are substantially parallel to each other, lying side-by-side in an inclined plane that rises longitudinally with respect to the underlying deck 88 of the subsea processing unit 84 shown in FIG. 4.

(67) The gas separator 22 and the DPSs 24 are centralised lengthwise with respect to the subsea processing unit 84. Centralising these large masses in longitudinally-inboard positions in this way improves the stability of the unit 84 during transportation and installation. In this respect, it will be noted that smaller, lighter modules such as the CFUs 58 and the flowmeter 70 are at longitudinally-outboard positions with respect to the gas separator 22 and the DPSs 24.

(68) The wellstream flows through the gas separator 22 in a first longitudinal direction. The degassed wellstream fluid flowing out of the gas separator 22 then enters a branch or manifold 102 that divides that fluid into a number of flowpaths corresponding to the number of DPSs 24 in the array. The manifold 102 also reverses the flow direction into a second longitudinal direction opposed to the first longitudinal direction.

(69) Before reaching the respective DPSs 24, the flowpaths first follow respective pre-separator pipe sections 26 that, in this example, are collapsed longitudinally by being bent or folded sinuously. This defines upper and lower portions 26A, 26B of the pre-separator pipe sections 26 that are in mutually-stacked, vertically-spaced relation, and that have mutually-opposed shallow inclination. In this respect, reference is made to the schematic detail view of FIG. 6.

(70) More specifically, each pre-separator pipe section 26 comprises an upper portion 26A in which the wellstream fluid flows in the second longitudinal direction from a manifold end adjacent the liquid outlet of the gas separator 22. The upper portion 26A is inclined upwardly in the second longitudinal direction, corresponding to the flow direction in that portion.

(71) A first downward bend 104 at the other end of the upper portion 26A joins the upper portion 26A to the lower portion 26B, reversing the flow between the upper and lower portions 26A, 26B. Consequently, the wellstream fluid flows in the lower portion 26B in the first longitudinal direction, generally parallel to the flow in the gas separator 22. The lower portion 26B is inclined upwardly in the first longitudinal direction, again corresponding to the flow direction in that portion.

(72) The lower portion 26B, in turn, ends in a second downward bend 106 that is longitudinally opposed to the first downward bend 104 and that is disposed under the end of the upper portion 26A adjacent to the manifold 102. The second downward bend 106 joins the lower portion 26B to the inlet of the associated DPS 24 and again reverses the flow between the lower portion 26B and the DPS 24. Thus, the wellstream fluid flows through the DPS 24 in the second longitudinal direction. The resulting reversal of flow between the gas separator 22 and the array of DPSs 24 facilitates the compact side-by-side disposition of those bulky components.

(73) In this example, the length of the system is also minimised relative to the use of a standard pipe separator in other ways. Firstly, the inclination of the DPSs 24 shortens their overall length parallel to the length of the subsea processing unit 84, while maintaining their effective length. Secondly, the reversal of flow direction in the pre-separator pipe sections 26A, 26B approximately halves their overall length parallel to the length of the unit 84 compared with their effective length. Thirdly, most of the upper and lower portions 26A, 26B of the pre-separator pipe sections 26 are stacked above the DPSs 24 rather than being offset longitudinally from the DPSs 24, benefitting from the space allowed by the inclination of the DPSs 24.

(74) Conventionally, large specialist offshore construction vessels are used for the installation of heavy subsea structures by lifting. Because of their size, such structures are often split into smaller components, hence requiring multiple operations for installation and connection. This increases the number of offshore operations and the need for subsea connection work. The resulting dependence on favourable weather for installation becomes an important factor in the cost and risk of an installation project.

(75) By combining components such as a manifold, sand removal unit, harp gas separator, parallel DPSs and serial CFUs in a supporting frame 86 as a subsea processing unit 84, offshore lifting operations and subsea connection operations are minimised. However, the size and weight of the unit 84 means that it can only be lifted by relatively few available heavy-lift vessels.

(76) Consequently, other methods of installation are preferred for the purposes of the invention, such as the towed production systems exemplified in WO 2014/095942 and WO 2016/071471. In this approach, large subsea processing plants may be assembled in coastal yards as subsea production units 84.

(77) Having assembled and tested the system, the subsea production unit 84 can be towed to field using the well-proven Controlled Depth Towing Method (CDTM). This reduces the cost and risk of installation compared to lift solutions, due to the reduced need for installation resources.

(78) A controlled-depth tow can be performed in a higher sea states than offshore lifting operations and minimises the field access requirements significantly. Use of towing installation methods for subsea production units 84 reduces the environmental impact and the risk to personnel by minimising the exposure of components. The towing and lowering operations impose lower dynamic installation forces on the unit 84 than for installation by lifting. The duration and cost of the installation operation can be reduced greatly.

(79) Many variations are possible within the inventive concept. For example, FIGS. 7, 8 and 9 show improved water separation systems in which the oil output of the DPS 24 is subjected to a second stage of water separation. These variants are apt to be used in, or in conjunction with, subsea processing units 84 like that shown in FIG. 4 but they may also have wider application. Again, like numerals are used for like features.

(80) In each of FIGS. 7, 8 and 9, a wellstream enters a harp gas separator 22 that performs bulk gas separation. The wellstream is preferably de-sanded beforehand but that step has been omitted in these drawings for simplicity. As before, the separated wet gas is channelled away for subsequent use in a water treatment system 54 to clean oil from the produced water, and optionally also for re-injection into a well.

(81) The degassed wellstream then passes through a DPS 24 that is suitably preceded by a pre-separator pipe section 26 as before. The pre-separator pipe section 26 shown in FIGS. 7 and 8 is omitted from FIG. 9 but is optional. In practice, the pre-separator pipe section 26 and the DPS 24 may be shaped and positioned compactly relative to each other like the corresponding components shown in FIGS. 5 and 6.

(82) In the variants shown in FIGS. 7, 8 and 9, the second stage of water separation is performed by an electrocoalescer 108 downstream of the DPS 24 in combination with a further liquid-liquid separator in series with, and downstream of, the electrocoalescer 108. That further liquid-liquid separator is exemplified by a pipe separator 110 in FIG. 7 and by a DPS 112 in FIGS. 8 and 9. The latter option is preferred for efficiency and compactness.

(83) In each case, the further liquid-liquid separator 110/112 outputs: oil containing a reduced water fraction, which oil may be sent to a tank 46 as shown in FIG. 1 for settling, if necessary, and for periodic offloading; and oily water that is added to the oily water output from the DPS 24 in the first separation stage, before treatment in a water treatment system 54 that is preferably like that described above in relation to FIG. 1.

(84) By promoting coalescence of smaller oil droplets into larger oil droplets, the electrocoalescer 108 conditions the mixture of oil and water flowing from the first-stage DPS 24 to improve the effectiveness of the further liquid-liquid separator 110/112 downstream in the second stage.

(85) Synergistically, by dewatering the wellstream and by modifying the flow, the first-stage DPS 24 improves the effectiveness of the electrocoalescer 108 and hence, in turn, the effectiveness of the further liquid-liquid separator 110/112 downstream in the second stage.

(86) Also synergistically, by degassing the wellstream upstream of the first-stage DPS 24 and by modifying the flow, the gas separator 22 improves the effectiveness of the electrocoalescer 108 and hence, in turn, the effectiveness of the further liquid-liquid separator 110/112 downstream in the second stage.

(87) These synergies combine beneficially with the aforementioned synergy between the gas separator 22 and the first-stage DPS 24, which as noted previously improves the effectiveness of the first-stage DPS 24.

(88) The result of these various synergies is that substantially more water is removed from the oil in the wellstream than if only one liquid-liquid separation stage was used.

(89) Similarly, substantially more water is removed from the oil in the wellstream than if successive liquid-liquid separation stages were used without the intermediate step of promoting coalescence. Also, substantially more water is removed from the oil in the wellstream than if the preliminary degassing step was omitted before the, or the first, liquid-liquid separation stage.

(90) By virtue of containing substantially less water, the oil output from the further liquid-liquid separator 110/112 is less susceptible to the formation of hydrates or other solids that could subsequently plug a pipeline or other production equipment.

(91) A challenging consequence of the improved separation of water from the oil in the wellstream is that more water has to be cleaned, preferably subsea by the water treatment system 54. The preferably two-stage operation of the water treatment system 54 and the use of CFUs, as described above in relation to FIG. 1, is beneficial to handle this increased flow of water while ensuring that the OiW ratio is sufficiently low to allow for re-injection or discharge of that water as the case may be.

(92) FIG. 9 shows that the first-stage DPS 24 shown schematically in FIGS. 7 and 8 is preferably an array of parallel, manifolded DPSs 24, in this example an array of four DPSs 24. FIG. 9 also shows that the second-stage DPS 112 is preferably also an array of parallel, manifolded DPSs 112, in this example a pair of two DPSs 112. The DPSs 112 of the second stage are fewer in number than the DPSs 24 of the first stage to reflect that less water is present to be separated from the oil in the second stage than in the first stage.

(93) FIG. 9 also shows, schematically, provisions for controlling the separation and treatment system to maintain appropriate output characteristics. Similar provisions may of course be added to the system shown in FIG. 1. In this respect, an Oil-in-Water sensor 114 monitors the OiW ratio in water produced by the water treatment system 54 and a Water-in-Oil sensor 116 monitors the WiO ratio in oil exiting the second-stage DPSs 112. Optionally, a further Water-in-Oil sensor may monitor the WiO ratio in oil exiting the first-stage DPSs 24. Both sensors 114, 116 report to a control system 118 that, in turn, controls appropriate valves 120 to modify the flow of fluids in the system, if required, to maintain the desired output characteristics.