System and method for offshore hydrocarbon processing

Abstract

A system for hydrocarbon production comprising a host for receiving produced hydrocarbon; an offshore hydrocarbon production facility comprising: a production wellhead for connection to a subsea hydrocarbon reservoir; a production platform configured to receive produced fluid from the wellhead and being in fluid communication with the host via a long distance pipeline; wherein the wellhead is local to the production platform, and the production platform is configured to process the produced fluid to provide a semi-stable oil product suitable for exporting along the long distance pipeline to the host.

Claims

1. A system for hydrocarbon production comprising: a host for receiving produced hydrocarbon; and a plurality of offshore hydrocarbon production facilities, each being an unmanned production platform comprising: a production wellhead for connection to a subsea hydrocarbon reservoir; and a production platform configured to receive produced fluid from the wellhead and being in fluid communication with the host via a long distance pipeline at least 50 km in length; wherein the wellhead is local to the production platform, the production platform is configured to process the produced fluid to provide a semi-stable oil product suitable for exporting along the long distance pipeline to the host such that the semi-stable oil product is not fully stabilized but is taken outside of a hydrate envelope for the conditions under which the semi-stable oil product will be held in the long distance pipeline, and the host is configured to further process the semi-stable oil product to a fully stabilized product via separation, degassing and/or dewatering and store the fully stabilized oil product for subsequent transportation or transport the fully stabilized oil product directly to a terminal.

2. The system according to claim 1, wherein the processing of the produced fluid comprises degassing the produced fluid and/or separating water from the produced fluid to an extent that the semi-stabilised fluid is taken outside of the hydrate envelope for the conditions within the long distance pipeline, whereby significant formation of hydrates in the long distance pipeline is avoided.

3. The system according to claim 1, wherein the semi-stable oil product has a true vapour pressure (TVP) of greater than 1 bar and less than the true vapour pressure of the produced fluid from the well.

4. The system according to claim 3, wherein the semi-stable oil product has a true vapour pressure greater than 1.3 bar and less than 400 bar.

5. The system according to claim 3, wherein the semi-stable oil product has a true vapour pressure of greater than 20 bar and less than 60 bar.

6. The system according to claim 3, wherein the semi-stable oil product has a true vapour pressure of greater than 30 bar and less than 40 bar.

7. The system according to claim 1, wherein the production platform is further configured to process the produced fluid to produce a gas product and/or a water product.

8. The system according to claim 7, wherein the production platform is configured to re-inject at least part of the gas product and/or at least part of the water product into the subsea oil reservoir.

9. The system according to claim 1, wherein the production platform is configured to generate electrical power by combusting at least part of the gas product.

10. The system according to claim 1, wherein the production wellhead is arranged to supply produced fluid to the production platform via subsea flow lines, a riser base and a riser.

11. The system according to claim 7, wherein the production platform is arranged to supply water from the water product and/or gas from the gas product to injection wellheads on the seabed via a riser, a riser base and subsea flow lines.

12. The system according to claim 1, wherein the host is an offshore platform or vessel or is located onshore.

13. The system according to claim 1, wherein the host is located at least 100 km or at least 200 km from the offshore hydrocarbon production facility.

14. The system according to claim 1, wherein the semi-stable oil product is stored at the host.

15. The system according to claim 1, wherein the production platform is configured to process the produced fluid to provide the semi-stable oil product that is sufficiently stable to be transported to the host located at least 100 km or at least 200 km distant therefrom via an unheated subsea pipeline, without the use of hydrate inhibitors, whereby formation of significant hydrates in the long distance pipeline is avoided.

16. The system according to claim 1, wherein the production platform comprises a two-stage separation system for producing the semi-stable oil product.

17. The system according to claim 16, wherein an oil product outlet from a second stage of the two-stage separation system is connected to the long distance pipeline via a riser and a riser base at the seabed.

18. The system according to claim 16, wherein a water product outlet from a first stage of the two stage separation system is connected to injection wellheads on the seabed.

19. The system according to claim 16, wherein a first stage and a second stage of the two-stage separation system have gas outlets leading to a plurality of gas compressors arranged in series and wherein a final compressor of the plurality of gas compressors has an outlet for the gas product.

20. A method of hydrocarbon production comprising: providing a host for receiving produced hydrocarbon, and a plurality of offshore hydrocarbon production facilities, each hydrocarbon production facility being an unmanned production platform comprising: a production wellhead for connection to a subsea hydrocarbon reservoir; and a production platform local to the production wellhead, configured to receive produced fluid from the wellhead and being in fluid communication with the host via a long distance pipeline at least 50 km in length; wherein the production platform processes the produced fluid to provide a semi-stable oil product and exports the semi-stable oil product along the long distance pipeline to the host such that the semi-stable oil product is not fully stabilised but is taken outside of a hydrate envelope for the conditions under which the semi-stable oil product will be held in the long distance pipeline, and the host further processes the semi-stable oil product to a fully stabilized product via separation, degassing and/or dewatering and stores the fully stabilized oil product for subsequent transportation or transports the fully stabilized oil product directly to a terminal.

21. The method as claimed in claim 20, comprising, providing, and using a system according to claim 1.

Description

(1) Certain embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

(2) FIG. 1 is a perspective view of a satellite field and host of an embodiment of the present invention;

(3) FIG. 2 is an overview of the embodiment of FIG. 1;

(4) FIG. 3 is a schematic fluid flow diagram showing the separation and processing features of a local Unmanned Production Platform (UPP™), which forms part of the embodiment; and

(5) FIG. 4 shows a generic hydrate-formation phase diagram for an oil product.

(6) The illustrated embodiment is a subsea hydrocarbon production system in which a number of satellite fields are connected to a remote host platform or vessel over long distances. The remote fields contain what would traditionally have been regarded as marginal reserves. In FIG. 1 only one such satellite field is shown in the foreground and a remote host in the background, but other satellite fields are provide at other remote locations. As will be described below, the satellite field has a local Unmanned Production Platform (UPP™), which separates hydrocarbon-containing fluid produced from local wellheads, partially stabilises an oil product at a and subsequently transports the oil product via a long distance pipeline to a host for further processing, as will be described below.

(7) Wellheads 1 are shown on the seabed in communication with a subsea hydrocarbon reservoir (not shown). The wellheads comprise producers 2 and injectors 3. The wellheads 1 are connected via flow lines 5, subsea multiphase pumps 6 and riser base 7 to a riser 8, which provides multiple fluid flow conduits to and from UPP™ 9.

(8) Extending away from the riser base 7 along the seabed is long distance pipeline 10, which extends to a remote host 11, in the form of a tanker vessel 11.

(9) The UPP™ is a floating platform anchored to the seabed. It provides various facilities for treating hydrocarbon-containing fluids (hereinafter also referred to as the produced fluid). These include a separation system 16, which is illustrated in FIG. 3, water treatment system 14, a gas-fueled power production unit 15 and a gas conditioning system.

(10) The produced fluid is a mixture including oil, water, and natural gas. It is produced from the reservoir in the conventional manner at the producers 2. It then passes through flow lines 5 and is boosted through the subsea multiphase pumps 6 to riser base 7. The hydrocarbon-containing fluid is then lifted through a conduit in riser 8 to UPP™ 9.

(11) At the UPP™, the hydrocarbon-containing fluid is separated into constituent parts—oil, gas, water, sediments, etc. by separator 16—as will be discussed in more detail below with reference to FIG. 3. The oil is then transported via riser 8 and riser base 7 to a long distance pipeline 10 on the seabed.

(12) The oil is partly stabilized, through degassing and dewatering processes, such that it is outside of the hydrate forming envelope of the long-distance pipeline 10, whilst also being within the final processing capability of the host 11. This allows the oil to be transported via long-distance pipelines 10 (up to 250 or even 500 km) to the host 11.

(13) With reference to FIG. 4, a hydrate formation phase diagram of a typical oil product (which may contain oil, water and gas) can be seen, with the temperature and pressure that the oil product may be held at shown on the X and Y axes respectively. There is a hydrate free region 401 on the right hand side of a hydrate dissociation curve 402, a hydrate stable region 403 (i.e. a region where hydrates have formed and are stable in the fluid) on the left hand side of a hydrate formation curve 404 and a metastable region 405 in between the hydrate formation curve and the hydrate dissociation curve where there is a risk of hydrate formation.

(14) An oil product held at low pressure and high temperature will reduce hydrate formation, whereas high pressures and low temperatures increase hydrate formation.

(15) The degassing and separation of water from the product alters the location of the hydrate formation and dissociation curves. Typically, such processing will move the hydrate formation curve to the left of the figure such that the oil product can be held at higher pressures and lower temperatures without the formation of hydrates.

(16) Typically, the longer the (unheated) long distance pipeline is, the colder the semi-stabilised oil product will become as its temperature approaches that of the seawater surrounding the pipe, thereby increasing the risk of hydrate formation. As a result, a longer pipeline will require an oil product that is processed more (e.g. via degassing and/or water separation) in order to alter the hydrate formation curve and avoid the hydrate formation region.

(17) In these embodiments, the oil product is processed just to the extent that it is taken outside of the hydrate envelope for the conditions of the long distance pipeline so that significant hydrate formation in the pipeline can be avoided (along with avoiding the use of a heated pipeline and/or boosters) in addition to avoiding the use of unnecessary processing equipment at the UPP, thus reducing the cost, size and difficulty in setting up and maintaining these installations.

(18) At the host, further processing of the oil to a fully stabilized product is carried out. It is then stored for subsequent transportation, or transported directly, to a terminal. In a variant of the embodiment, the further processing also conditions the oil so that it meets final specification requirements.

(19) The gas separated from the hydrocarbon-containing fluid is conditioned at the UPP™ 9 so that it may be used for gas injection back into the subsea oil reservoir. After conditioning, the gas passes through a conduit in riser 8, via riser base 7 and flow lines 5 to injectors 3, where it is re-injected into the reservoir. The re-injection of gas is a known process that supports the pressure of the well as fluid is produced and can also cause the pressure to rise in the well, causing more gas molecules to dissolve in the oil, thereby lowering its viscosity and increasing the well's output.

(20) In the illustrated embodiment, some of the gas is used as fuel for power generation at the UPP™ 9. This is carried out by gas turbine power production unit 15 in which the gas (containing short-chain hydrocarbons, i.e. natural gas) is combusted to generate power. Such electrical power production may be used to meet some, or all, of the power demand at the reservoir.

(21) In a variant of this embodiment, instead of using the gas for re-injection, it is also conditioned at the UPP™ 9, (separately from the oil), such that it is also outside of the hydrate-forming region of an additional long-distance pipeline 10′ extending to host 11, along which it is then transported. This further improves the economic sustainability of the reservoir.

(22) The water separated from the hydrocarbon-containing fluid is treated and conditioned at the UPP™ 9 by produced water treatment system 14 to a standard that it can be re-injected into the reservoir to support its pressure. This treated water passes from the UPP™, down through a conduit in riser 8 via riser base 7, flow lines 5 and water injection pumps 13 to water injectors 34.

(23) The separation process is tailored to have specific injection qualities depending on reservoir requirements. The water could be tailored depending on fracking requirements in the reservoir, for pressure support, or treated to an ultrapure quality to meet environmental standards, for example. However, the main requirement is that the treatment allows the produced water to be re-injected into the reservoir via water injection pumps 13.

(24) Some or all water recovered from the hydrocarbon-containing fluid may be treated at the UPP™ 9 to a level that allows it to be released into the sea.

(25) The processing temperature of the liquids (oil/water separation and produced water treatment at the UPP™ 9) is mainly governed by the reservoir temperature, typically ranging from about 20° C. upwards but heat may be added to the liquids for optimal processing temperature.

(26) The long distances over which the oil product is transported may be seen from FIG. 2, which shows a number of offshore oil production facilities 101 located at marginal fields in the Barents Sea. Each of these offshore oil production facilities 101 corresponds to the local system described above and includes at least one Unmanned Production Platform that is “tied-back” via a long-distance pipeline 10 to a host 11, thereby allowing the transportation of the oil product to the host. In this embodiment an offshore production facility 101 is tied-back 175 km to a host 11.

(27) The flow diagram of FIG. 3 schematically shows the separation and processing features of the local UPP™ 9 in greater detail, along with the subsea components of the embodiment, which have been described already with reference to FIG. 1. Thus, produced fluid from a number of wellheads 1 is boosted through multi-phase pump 6 and then passes through flow lines 5, and riser base 7 and production riser conduit 17 to the UPP™ (which houses the components shown above the central horizontal dividing line). Also shown are certain water injection components, including water injection pumps 13, which are fed with produced water by water injection riser conduit, and water injectors 34. In addition, gas injectors 3 are shown connected to gas injection riser conduit 20.

(28) It should be noted that the production riser conduit 17, produced water riser conduit 18, semi-stable crude oil riser conduit 19 and gas injection riser conduit 20 are all included in the structure of riser 8 (see FIG. 1). They are shown separated in FIG. 3 merely for clarity.

(29) The production riser conduit 17 leads to a first stage, three phase, separator 21 having outlet conduits 23 for gas, 24 for oil and 36 for water. The first is connected to the output from a downstream flash gas compressor, which will be discussed below. The second leads via valve 26 to the input of second stage separator 28. The separators may be gravity separators, cyclone separators or any other separator known in the art. The third outlet conduit leads, via water treatment unit 29 and produced water pump 31, to produced water riser 18.

(30) The second stage separator is two-phase, having outlet conduits 44 for gas and 45 for oil. The former is connected to flash gas compressor 35 which has an outlet conduit 43 which connects to gas outlet conduit 23 from the first stage separator and leads to first interstage gas cooler 36 and then to first stage suction scrubber 37. The latter 45 leads via oil product pump 30 and semi-stable crude oil riser 19 to the long distance pipeline 10 leading to host 11 (see FIG. 1).

(31) First stage suction scrubber 37 has a single outlet conduit 46 leading to first stage gas injection compressor 38. The outlet conduit 47 from this leads via a second interstage gas cooler 39 to a second stage suction scrubber 40 and a second stage gas injection compressor 41 which feeds gas inlet riser conduit 20, which leads to the gas injectors 3 at the sea bed.

(32) The suction scrubbers both also have outlet conduits 47, 48 for oil that has been scrubbed from the gas. The one from the second stage suction scrubber 48 leads back via valve 49 to the first stage scrubber and the one from the first stage scrubber 47 leads back via valve 50 to second stage separator 28.

(33) After the produced fluid has been lifted through the production riser 17 to the UPP™ 9, it enters first stage separator 21. This holds the hydrocarbon-containing fluid at a pressure of approximately 15 bar and partially separates the fluid into three components: primarily consisting of oil, gas, and water respectively in the known manner.

(34) The separated oil is then passed via conduit 24 and valve 26 to second stage separator 28. The separated water is passed through water conduit 25 to water treatment unit 29 and the separated gas is passed through gas conduit 23.

(35) The second stage separator 28 reduces the oil fluid to a pressure of approximately 4 bar, a lower pressure than the first stage separator in order to flash down the oil fluid, thereby releasing gas from within the fluid. This flash gas is separated from the oil fluid such that the oil is conditioned (dewatered and degassed) to a level at which it is semi-stabilised. The level of dewatering and degassing required depends on the conditions that the oil will be held at, particularly when transported via the long-distance oil pipeline 10, and the corresponding hydrate forming envelope for the oil product under these conditions.

(36) Thus, the semi-stabilised oil product passes from the second stage separator 28 in a condition that is outside of the hydrate-forming envelope of the long-distance pipeline 10 to the host 11. Following this, the semi-stabilised oil product is boosted through oil product pump 30, and passed down semi-stable oil product riser 19, after which it is exported to the host along subsea long-distance export lines 10. As the semi-stabilised oil product is outside of the hydrate-forming region, the use of heating, insulation, introduction of hydrate inhibitors and/or pigging is not necessary in the long-distance pipeline 10.

(37) In this embodiment, the flash gas produced in second stage separator 28 (at a pressure of 4 bar) is removed from the second stage separator 28 and recompressed to a pressure of 15 bar (the same pressure as the gas removed from the first stage separator 21) in flash gas compressor 35. The flash gas is then recombined with the gas removed via the first stage separator 21 and passed through a first interstage gas cooler 36 in order to cool the gas and remove the resultant heat from the prior compression. In this embodiment, the cooling in each cooler is carried out via a heat exchanging relationship with seawater and/or air.

(38) The combined gas (“the gas”) is then passed through first stage suction scrubber 37 in order to remove particulates and condensates from the gas and protect later gas compressors. This improves the performance of later stage gas compressors and other components.

(39) The gas is then passed through first stage gas injection compressor 38 in order to raise its pressure to 38 bar. The gas is subsequently cooled in second interstage gas cooler 39.

(40) The gas then enters second stage suction scrubber 40 in order to remove any further particulates or condensate before entering a second stage gas injection compressor 41 that raises the pressure of the gas to 100 bar, the final pressure before re-injection into the subsea reservoir.

(41) The gas at 100 bar is then passed down through gas injection riser 20 to gas injectors 3, where it is re-injected into the reservoir to support the reservoir pressure.

(42) The separated water from first stage separator 21 is conditioned at water treatment unit 29 in order to meet the conditions required for re-injection into the subsea oil reserve, as discussed above. This produced water is then pumped through produced water pump 31, and passed down produced water riser conduit 18.