Patent Application
20140138046
The present invention relates to an offshore hydrocarbon cooling system.
Cooling systems are essential for several stages of hydrocarbon processing. For example, it is typical to cool hydrocarbon gas from wellhead temperatures, which commonly range from about 80° C. to about 150° C., down to about 30° C. to about 60° C., prior to dehydrating the hydrocarbon gas and/or separating condensates therefrom. Additionally, cooling is also needed after compressing the hydrocarbon gas which may occur at several stages during hydrocarbon processing.
Cooling systems that have been employed for offshore hydrocarbon processing include air cooling systems, direct seawater cooling systems, and indirect seawater cooling systems.
Air cooling systems are simple and cost effective. Their widespread deployment in offshore hydrocarbon processing facilities is restricted, however, by deck-space limitations, and in some locations, high ambient temperatures.
Direct seawater cooling systems employ a pump to lift the seawater, filter and then circulate seawater into a heat exchange circuit which communicates with a hydrocarbon process fluid. The heat exchangers employed in the heat exchange circuit must be fabricated from high specification metals or metal alloys which are resistant to corrosion by both the process fluid and seawater.
Accordingly, direct seawater cooling systems often involve difficult fabrication with high cost materials. Seawater fouling and mechanical integrity issues in the heat exchangers may be a concern.
Indirect cooling systems interpose a cooling medium heat exchange circuit between the hydrocarbon process fluid heat exchange circuit and a seawater heat exchange circuit. The cooling medium in the cooling medium heat exchange circuit is typically clean (non-fouling) and non-corrosive. In the indirect cooling system, seawater is typically pumped, filtered and circulated through a circuit which is in heat exchange communication with the cooling medium heat exchange circuit, thereby cooling the cooling medium. The cooled cooling medium, in turn, is employed to cool process fluid which is brought into heat exchange communication with the cooling medium heat exchange circuit.
The indirect cooling medium heat exchange circuit represents an additional heat exchange circuit, associated pumps and make-up capability in comparison with the requirements of the direct cooling system. However, the materials used in the heat exchange circuits do not need to meet the high specification requirements for materials used in the direct cooling system, and heat exchange designs can therefore use larger heat exchange areas (and therefore increase the efficiency of the circuit) for comparative costs. Additionally, the risk of fouling is limited to the seawater heat exchanger only. The cooling medium is a very clean, non-corrosive fluid and does not contribute to fouling or corrosion.
Both direct and indirect cooling systems feature a seawater heat exchange circuit in which seawater is filtered and then pumped onto the offshore processing facility platform, circulated in a heat exchange circuit, before being discharged back into the sea. The filters, pumps, and heat exchange circuits have significant capital and operating expense requirements.
Various other devices have been proposed for cooling of hydrocarbons on a topsides facility. One example of such device includes employing a subsea cooling loop to circulate a process fluid through a length of pipe located subsea to directly cool the process fluid and then pump the cooled process fluid back to the offshore processing facility platform for processing and export. However such a device does not provide adequate control over the outlet temperature to mediate the risk of solid hydrate formation (eg. methane hydrates, CO2 hydrates, or hydrates of C2 or C3 hydrocarbons) which would result in a blocked line. The additional inventory of hydrocarbon also represents an increased safety risk. For these reasons such a system has not been designed or installed in practice.
The present invention seeks to overcome at least some of the aforementioned disadvantages.
In its broadest aspect, the invention provides an offshore hydrocarbon cooling system, a subsea cooling unit, and a method of cooling a hydrocarbon process fluid on an offshore platform, by way of a cooling medium fluid.
According to one aspect of the invention there is provided a hydrocarbon cooling system for an offshore platform, said system comprising:
In one embodiment, the system further comprises one or more pumps to circulate the cooling medium fluid through the heat exchange circuit and the subsea cooling unit.
According to another aspect of the invention there is provided a subsea cooling unit for cooling a cooling medium fluid circulating through a heat exchange circuit on an offshore platform, the heat exchange circuit having a cooling medium fluid distribution pipe system, the subsea cooling unit comprising:
In a further aspect of the invention there is provided a method of cooling a hydrocarbon process fluid on an offshore platform, said method comprising:
Referring to the Figures there is shown a hydrocarbon cooling system 10 for an offshore platform. The offshore platform may be a fixed offshore platform 12 or a floating offshore platform 12′, as shown in
The fixed platform 12 consists of a deck located above the sea surface supported on a substructure anchored directly onto the seabed. The substructure may be built on concrete or steel legs, or both, anchored directly onto the seabed, supporting a deck with space for drilling rigs, production facilities and crew quarters. Various types of substructure are used, including steel jacket, concrete caisson, floating steel and even floating concrete. Steel jackets are vertical sections made of tubular steel members, and may be piled into the seabed. Concrete caisson structures often have in-built oil storage in tanks below the sea surface. In general, fixed platforms are economically feasible for installation in water depths up to about 150-200 m, although this varies around the world depending on the particular economic and engineering factors in that area.
Other types of fixed platform 12 include, but are not limited to, a compliant tower consisting of slender flexible towers and a pile foundation supporting a conventional deck for drilling and production operations; or a gravity based substructure (GBS) constructed of either steel or concrete and anchored directly onto the seabed.
The floating platform 12′ may be one of several different types of floating platform 12′ including, but not limited to, a semi-submersible platform which has a hull comprised of columns and pontoons of sufficient buoyancy to cause the structure to float, but of sufficient weight to keep the structure upright; floating production, storage, and offloading systems (FPSO); floating storage and offloading system (FSO); floating liquefied natural gas production units (FLNG); tension-leg platforms(TLPs) which are floating platforms tethered to the seabed in a manner that eliminates most vertical movement of the structure; and spar platforms which are moored to the seabed with conventional mooring lines.
The offshore platforms 12, 12′ are generally sea-based, but could equally apply to any body of water including inland or lake-based water bodies. It will be appreciated that a reference to a sea floor, sea bed, or seawater may equally apply to a lake floor, lake bed, or lakewater and/or freshwater and/or saltwater and/or brine, respectively, depending on the location of the offshore platform and the character of the body of water in which it is located.
The offshore platform 12, 12′ includes a hydrocarbon processing area 14 located on the deck of the offshore platform 12, 12′. This is commonly referred to as the facility ‘topsides’, as compared to the facility ‘substructure’. The hydrocarbon processing area 14 is configured to process hydrocarbon fluids extracted from one or more well heads located in the sea bed and delivered to the platform 12, 12′ via a production line (not shown). The production wells may be an integrated part of the platform or may be remote from subsea wells or remote from an alternate platform. For example, where natural gas is extracted, the hydrocarbon processing area 14 may include various processing units to dehydrate and sweeten the natural gas to remove sour gases such as CO2 and H2S, separate and remove condensates such as NGLs, compress the gas, and liquefy the natural gas. Any one of the various processing units may require a cooling system to cool the hydrocarbon fluid. It will be appreciated that one or more of the cooling systems 10 of the present invention may be conveniently integrated into the hydrocarbon processing area 14 of the offshore platform 12, 12′.
The system 10 includes a heat exchanger 16 arranged in heat exchange communication with a hydrocarbon fluid. The heat exchanger 16 may be of various types, such as shell & tube, plate-fin, compact welded or various others well understood by those skilled in the art, and may be arranged in various configurations (series/parallel), locations, and number as part of the overall hydrocarbon processing that may occur on the platform 12, 12′.
The term ‘hydrocarbon fluid’ refers to a gas, liquid, or dual phase liquid-gas stream containing one or more hydrocarbons. The hydrocarbon may be extracted directly from a well head in the form of a liquid, for example in the form of crude oil, or as a gas, for example in the form of natural gas, or as a mixture of natural gas and crude oil. Alternatively, the hydrocarbon may be derived from the extracted hydrocarbon by various processing treatments, including dehydration, fractional distillation, cryogenic distillation, solvent absorption, pressure-swing absorption, and other processing techniques as will be well understood by those skilled in the art. In general, the hydrocarbon fluid will be communicated to the heat exchanger 16 from a processing unit within the hydrocarbon processing area 14 via conduit.
The system 10 also includes a heat exchange circuit 20 disposed in parallel heat exchange relationship with the heat exchanger 16. A cooling medium fluid circulates through the heat exchange circuit 20 via pump 18. It will be appreciated that
The temperature of the cooling medium fluid is less than the temperature of the hydrocarbon fluid. When the hydrocarbon fluid is passed through the heat exchanger 16, thermal energy from the hydrocarbon fluid is transferred to the cooling medium fluid which is circulated through the heat exchange circuit 20. Consequently, the hydrocarbon fluid is cooled.
The cooling medium fluid may be any suitable fluid which is capable of flowing through the heat exchange circuit 20 and transferring heat from a fluid, such as a hydrocarbon fluid, via the heat exchanger 16. Preferably, the cooling medium fluid has a high thermal capacity, low viscosity, is low cost, non-toxic, and chemically inert, neither causing nor promoting corrosion of the heat exchange circuit 20.
In general, the cooling medium fluid of the present invention may be a liquid, although in some alternative embodiments of the invention the cooling medium may be a gas.
Suitable examples of cooling medium fluids include, but are not limited to, aqueous media containing additives to inhibit corrosion within the heat exchange circuit 20, depress the melting point and/or raise the boiling point. In a preferred embodiment the cooling medium fluid comprises water mixed with a suitable organic chemical, such as ethylene glycol, diethylene glycol, or propylene glycol.
Both the heat exchanger 16 and the heat exchange circuit 20 may be disposed on the offshore platform 12, 12′. In general, the heat exchanger 16 and the heat exchange circuit 20 may be disposed in the hydrocarbon processing area 14 on the offshore platform 12, 12′.
The system 10 of the present invention also includes a subsea cooling unit 22 for cooling the cooling medium fluid. In use, the cooling medium fluid must be continuously cooled for reuse as a heat transfer fluid as it circulates through the heat exchange circuit 20.
The subsea cooling unit 22 includes an inlet 24 and an outlet 26 which are connectable to the heat exchange circuit 20, and one or more subsea cooling modules 28. The one or more subsea cooling modules 28 are arranged in fluid communication with the inlet 24 and the outlet 26 via a first riser 30 and a second riser 32, respectively. In the embodiment described in
In the embodiment described in
The cooling module 28 comprises a plurality of cooling pipes 36 configured in heat exchange relationship with surrounding seawater. The plurality of cooling pipes 36 may be configured in a simple network of fully-welded small bore pipe lengths, typically of about ½ to 2 inch diameter. The inventor estimates that approximately 250 m of 2 inch pipe would provide a typical cooling duty of around 0.25 MW, and cool 1500 bpd (barrels per day) or 240 m3/h of cooling medium by approximately 25° C. A manifolded unit of 10 lengths of such pipe in parallel would have a cooling duty of about 2.5 MW. Actual performance will depend on both engineering design factors, including cooling medium velocity, and ambient conditions such as the sea water temperature and any current velocity. Several manifolded units could be combined in the cooling module 28.
While not shown in
It will be appreciated that the diameter, individual lengths of pipe, number of manifolded units and cooling modules 28 may vary and be optimised according to the desired design and performance requirements as well as ambient conditions.
Alternatively, the plurality of pipes 36 may be configured in a coiled arrangement in heat exchange relationship with the surrounding seawater. The coiled arrangement of pipes 36 may itself be coiled around at least part of the substructure of the offshore platform 12, 12′.
In another alternative embodiment, the plurality of pipes 36 of the cooling modules 28 may be arranged end-to-end in an arrangement which wraps around at least part of the substructure of the offshore platform 12, 12′. The arrangement may be optimised for ease of construction and to promote heat transfer from the cooling medium fluid in the pipes to the surrounding seawater.
Further, it will be appreciated that further cooling to lower temperatures may be possible with longer lengths. Efficiency, in terms of heat loss per unit length of pipe decreases with a lower temperature differential between the cooling medium and the ambient seawater. It is envisaged that in some embodiments, a portion of the cooling medium could be cooled or chilled to a lower temperature, with series units, in addition to, or alternatively to, the parallel arrangement described above.
The one or more subsea cooling modules 28 are preferably located above the sea bed 40. Sea currents are reduced very close to the sea bed 40. Therefore, locating the cooling modules 28 some metres above the sea bed 40 may have the advantage of exposing the cooling modules 28 to stronger sea currents. Stronger currents may generate some improvement in the efficiency of heat transfer from the cooling modules 28, although inherent thermal convection may largely contribute to adequate thermal energy transfer when sea currents are weak or absent.
The cooling module pipes 36 are likely to be prone to marine growth and scale formation which will reduce the efficiency of heat transfer in the subsea cooling modules 28 over time. This may also reduce the benefit of increased seawater velocity from currents or other sources. The reduced heat transfer can be countered by installing a greater number of pipes 36 than required. Additionally, the marine growth may be removed intermittently with suitable removal methods, such as by blasting with a high pressure water jet, to preserve the heat transfer capability of the cooling module pipes 36.
Spacing between the cooling modules 28 and the sea bed may be determined by the length of the first and second risers 30, 32.
Additionally, or alternatively, the subsea cooling modules 28 may be supported by ‘mud mats’ 38 residing on the sea bed 40, as shown in
In some embodiments, as shown in
In some embodiments, the subsea cooling modules 28 may be located remotely (i.e. several kilometres) from the offshore platform 12, 12′ in deeper and colder seawater. In this embodiment the first and second risers 30, 32 may be in fluid communication with the cooling modules 28 via respective seabed pipes. Colder seawater may significantly improve cooling efficiency as will the length of seabed pipe. The inventor notes that such additional cooling benefits would have to outweigh the costs associated with fabricating and installing offshore pipelines.
It will also be appreciated that in some alternative embodiments the first and second risers 30, 32 may be replaced with suitable conduits 30′, 32′ to facilitate substantially lateral placement of the cooling modules 28 in relation to the offshore platform 12, 12′. In particular, these embodiments may be employed where provision of risers for floating offshore platforms 12′ may be technically difficult eg. turret/swivel issues. In these embodiments, the cooling modules 28 could be tethered to the floating platform 12′ by chains, wires or other rigid structural support mechanisms. In use, a hydrocarbon fluid may be cooled on an offshore platform 12, by passing the hydrocarbon fluid through the heat exchanger 16 which is disposed in heat exchange relationship with the heat exchange circuit 20. The hydrocarbon fluid transfers thermal energy to the cooling medium fluid which is circulated through the heat exchange circuit 20, thereby cooling the hydrocarbon fluid and heating the cooling medium fluid.
The heated cooling medium fluid is subsequently cooled by diverting the heated cooling medium fluid from the heat exchange circuit 20 into the subsea cooling unit 22. The heated cooling medium fluid enters the subsea cooling unit 22 through an inlet 24 and is passed into one or more subsea cooling modules 28 via a first riser 30. The subsea cooling module(s) 28 are in heat exchange relationship with the surrounding seawater and therefore thermal energy in the heated cooling medium fluid is transferred to the surrounding seawater as cooling medium fluid is passed through the cooling module(s) 28. The cooled cooling medium fluid is then redirected from the cooling module(s) 28 to the heat exchange circuit 20 through outlet 26 via second riser 32.
It will be readily apparent to a person skilled in the relevant art that the present invention has significant advantages over the prior art including, but not limited to, the following:
Numerous variations and modifications will suggest themselves to persons skilled in the relevant art, in addition to those already described, without departing from the basic inventive concepts. All such variations and modifications are to be considered within the scope of the present invention, the nature of which is to be determined from the foregoing description.
It is to be understood that, although prior art use and publications may be referred to herein, such reference does not constitute an admission that any of these form a part of the common general knowledge in the art, in Australia or any other country.
For the purposes of this specification it will be clearly understood that the word “comprising” means “including but not limited to”, and that the word “comprises” has a corresponding meaning.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2011901794 | May 2011 | AU | national |
| Number | Date | Country | |
|---|---|---|---|
| Parent | PCT/AU2012/000509 | May 2012 | US |
| Child | 14077476 | US |
