Patent Application
20140138093
The present invention relates to a subsea hydrocarbon cooling system, a subsea cooling medium and heat transfer system, and related subsea processes for facilitating the cooling, separating and onward processing of hydrocarbons.
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 various offshore topsides processing steps, including dehydrating the hydrocarbon gas and/or separating condensates therefrom, and as part of compression.
Subsea applications for hydrocarbon cooling generally occur where the hydrocarbons are sourced from subsea wells, as distinct from ‘dry tree’ platform wells, when the wells are brought up to either fixed or floating platform facilities. Cooling has been required to meet maximum pipeline design temperature, (to prevent pipeline upheaval buckling, and to prevent excessive corrosion) particularly in high pressure, high temperature (HP/HT) wells. Another subsea cooling application occurs as part of subsea compression projects.
In the future, as there is expected to be greater demand to conduct more processing subsea, as compared to on fixed or floating platform facilities, particularly in deepwater and remote locations, there will be a greater demand for improved subsea hydrocarbon cooling systems.
Various devices have been proposed for cooling hydrocarbons subsea.
The cooling devices generally send the hydrocarbons down either a single exposed pipe or a network of pipes from which cooling results from energy loss through the pipe wall to the surrounding sea. There are several significant disadvantages from current proposals:
Other proposed subsea cooling devices look to enhance the cooling duty obtained and provide temperature control. This is proposed by pumping seawater, in various configurations and by various devices, across the pipe-network containing the hydrocarbon fluids.
The pumped seawater passes across the pipes at an increased velocity. This in theory achieves a higher forced-convection external pipe heat transfer coefficient and may achieve temperature control by varying the seawater velocity. While the principle of this heat transfer method is correct, in practice this method will reduce in effectiveness if any marine fouling or scale coating develops over time. Loss of temperature control may result.
The present invention seeks to overcome at least some of the aforementioned disadvantages.
In its broadest aspect, the invention provides a subsea hydrocarbon cooling system, a subsea cooling unit, and a method of cooling a subsea hydrocarbon process fluid, by way of a cooling medium fluid.
According to a first aspect of the invention there is provided a subsea hydrocarbon cooling system, said system comprising:
The cooling system may be provided with a pump to circulate the cooling medium fluid through the hydrocarbon process fluid heat exchangers and the subsea cooling units of the cooling medium system.
According to another aspect of the invention there is provided a subsea cooling unit for cooling a cooling medium fluid circulating through a subsea heat exchange circuit, the subsea 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 subsea hydrocarbon process fluid, said method comprising:
Referring to the Figures, where like numerals refer to like features throughout, there is shown a subsea hydrocarbon cooling system 10.
The subsea cooling system 10 is 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 subsea cooling system and the character of the body of water in which it is located.
The subsea cooling system 10 may be associated with a hydrocarbon processing area 12 located on, or proximal to, a seabed 14. The hydrocarbon processing area 12 is configured to process hydrocarbon fluids in accordance with subsea processing requirements, such as subsea condensate and/or water separation and subsea compression processes and will have a need for hydrocarbon fluid cooling. Accordingly, it will be appreciated that one or more of the subsea cooling systems 10 of the present invention may be conveniently integrated into the hydrocarbon processing area 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.
The system 10 includes one or more heat exchangers 16, 16′ arranged in heat exchange communication with a hydrocarbon fluid. The heat exchangers 16, 16′ may be of various types, such as shell & tube, 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 area 12. It will be appreciated that the heat exchangers 16, 16′ may comprise conventional shell & tube heat exchangers which have been modified for subsea use.
The system 10 also includes a heat exchange circuit 18 disposed in parallel heat exchange relationship with the heat exchangers 16, 16′. A cooling medium fluid circulates through the heat exchange circuit 18.
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 18. 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 18 and transferring heat from a fluid, such as a hydrocarbon fluid, via the heat exchanger 16, 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 18.
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 18, 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. It is possible that the fluid is the same fluid as used in water-based subsea hydraulic control systems, as this should also meet the requirements for heat transfer.
Both the heat exchangers 16, 16′ and the heat exchange circuit 18 are disposed subsea, preferably supported by mud mats 20 or other suitable structural foundations on the seabed 14. The mud mats 20 may be simple structural steel pallets.
It will be appreciated that the heat exchanger 16, 16′ and the heat exchange circuit 18 will be fabricated from materials which are suitable for use in a subsea environment and which are corrosion resistant. For example, the shell of the heat exchanger 16 may be fabricated from carbon steel, with appropriate cathodic protection systems and coatings to resist external corrosion. The heat exchanger 16 tubing may be formed from a suitable corrosion resistant alloy (CRA), stainless steel or equivalent material suitable to resist corrosion from the hydrocarbon fluid.
Those skilled in the art will know the various factors that determine which fluid, be it the process hydrocarbon fluid or the cooling medium fluid, pass through the shell or the shell & tube exchanger and which pass through the tubing. It is likely that the process hydrocarbon fluid will pass through the tubing, such that the shell can be formed from carbon steel. This arrangement is also preferred as it is likely to minimise the fouling potential of the hydrocarbon process fluid. However, it will be understood that the preferred arrangement may vary depending on other factors, such as the hydrocarbon composition and processing requirements.
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 18.
The subsea cooling unit 22 includes an inlet 24 and an outlet 26 which are connectable to the heat exchange circuit 18, 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 conduit 30 and a second conduit 32, respectively. The first and second conduits 30, 32 may be lengths of hard pipe or flexible pipe.
The flow of cooling medium fluid (and hence the degree of cooling achieved) through heat exchange circuit 18 may be controlled via a flow control valve (not shown) in the subsea cooling unit 22. Alternatively, flow may be controlled with a pump 34, such as a single phase variable speed pump, which is also located subsea. Pump service is not expected to be onerous due to the controlled, clean and single phase nature of the cooling medium fluid.
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 1½-2 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. Several manifolded units could be combined in the cooling module 28.
It will be appreciated that the diameter, individual lengths of pipe, number of manifolded units and cooling modules 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 or any other number and type of shapes and arrangements in heat exchange relationship with the surrounding seawater.
The plurality of pipes 36 may be coiled around at least part of a substructure of a subsea facility, such as a valve manifold, part of a subsea compression module, or even part of the substructure of an offshore platform.
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. Valve isolating sections of the cooling module het exchange may be used to establish a minimum operating temperature of the cooling medium fluid. This may be advantageous to ensure no ‘cold spots’ exist in the hydrocarbon process fluid heat exchanger. Other options may be preferred, such as operating the hydrocarbon process fluid heat exchanger in co-current instead of the more usual counter-current configuration. The detailed design option may vary depending on the particular installation and processing requirements for the hydrocarbon fluid.
The one or more subsea cooling modules 28 are preferably located above the sea bed 14. Sea currents are reduced very close to the sea bed 14. Therefore, locating the cooling modules 28 some metres above the sea bed 14 may have some 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 may be prone to some marine growth and scale formation. This will depend on location, ambient conditions, temperature, and water depth. Any marine growth and scale 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 (or length) 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.
The subsea cooling modules 28 may be supported by ‘mud mats’ 20′ or other structural foundations, residing on the sea bed 14. In this particular embodiment, the spacing between the cooling modules 28 and the sea bed 14 may be determined by the height of the mud mats 20′ which support the cooling modules 28. The mud mats 20′ may be simple structural steel pallets. In some embodiments, the mud mat 20′ could incorporate lengths of large diameter pipe through which the cooling medium fluid could also be circulated and/or distributed to the cooling modules 28.
In some embodiments, as shown in
In some embodiments, the subsea cooling modules 28 may be located remotely (i.e. several kilometres) from the subsea hydrocarbon processing area 12 in deeper and colder seawater. In this embodiment the first and second conduits 30, 32 may be in 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.
With reference to
The heated cooling medium fluid is subsequently cooled by diverting the heated cooling medium fluid from the heat exchange circuit 18 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 conduit 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 18 through outlet 26 via second conduit 32.
Another embodiment of the invention is described with reference to
The cooled hydrocarbon fluid is then passed to separator 38 and separated into a hydrocarbon gas component and a condensate (also including water). The hydrocarbon gas component is passed through conduit 40 to export or further processing, with optional glycol injection in conduit 40.
The condensate is passed through conduit 42 via pump 44 to heat exchanger 16′ which is also disposed in heat exchange circuit 18. The heated cooling medium fluid transfers thermal energy to the condensate. The re-heated condensate is subsequently passed through conduit 46 to export or further processing.
The partly cooled cooling medium fluid is subsequently further cooled by diverting the heated cooling medium fluid from the heat exchange circuit 18 into the subsea cooling unit 22, as shown in
In this particular embodiment, the subsea cooling system 10 of the present invention, may be employed to both cool a hydrocarbon stream and to heat a further process stream, such as the condensate stream described above. It will be appreciated by persons skilled in the art that the subsea cooling system 10 may be configured in alternative arrangements to utilise both cooling and heating capacity of the cooling medium fluid, so that a second (or subsequent) hydrocarbon process fluid may be heated or cooled. Appropriate insulation will be applied and pipe lengths minimised on connecting pipes where it is desired to maintain the heat in the heated cooling medium.
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/AU2012/000510 | May 2012 | US |
| Child | 14077500 | US |
