TECHNICAL FIELD

The present disclosure relates to a subsea installation, which includes a heat storing member comprising phase change material (PCM).

BACKGROUND

In the field of subsea oil and gas production, well fluid is commonly produced and communicated from a well using a variety of subsea installations, such as manifolds and Christmas trees. Whilst the well fluid is relatively hot when it is flowing through the installations during production from the well, if production should be stopped or interrupted (e.g., for installation repair or maintenance) well fluid remaining therein will be cooled by the ambient cold sea water around it. It is known that such cooling of production well fluid can result in the formation of hydrates (or other solid formations) in the well fluid. The formation of such hydrates can block the flow path for the well fluid through parts of the subsea installations, preventing or restricting further production of well fluid without first removing the hydrates.

Moreover, when production of well fluid is restarted and/or a gas lift operation is performed to encourage well fluid production, the expansion of fresh production fluid from the well and/or gas lift fluid as it enters and passes through (e.g., valves in) the subsea installation can provide sudden cooling owing to the Joule-Thompson effect. This sudden cooling can cause parts of the subsea installation to become embrittled or suffer from thermal fatigue that degrades their strength beyond allowable limits.

To help combat these effects, it is known to provide a layer of insulating material around the subsea installation. For example, the exterior of the body of the installation is generally coated in an insulating material, such as a resin, foam or thermoplastic. For example, a silicone resin, phenolic resin foam, or syntactic foam.

During normal production, heat from the well fluid flowing through the installation will warm the body of the installation above the hydrate formation temperature. When production is stopped or interrupted, the heat accumulated in the body will be insulated from the relatively cold seawater surrounding the installation by the insulating material. This will allow the heat to be retained for a period of time, which can keep the well fluid therein above a hydrate formation temperature for a period of time. In this sense, a “cool-down time” (i.e., the amount of time production of well fluid through the installation can be stopped before hydrates start to form) can be increased using the insulating material.

Oil and gas producers are generally looking to increase the length of cooldown times for subsea installations and improve protection against (e.g., Joule- Thompson) cooling effects, where possible. Although the use of insulating materials around installations may be satisfactory for some applications, the heat retention provided by the insulating material can be limited.

One way to improve the heat retaining capacity of known installations can be to increase the thickness and use of the insulating material around the installation. However, the insulating materials can be quite costly, and the increases in cool-down time provided may not be great enough to justify these cost increases. Moreover, there may be relatively “cold-spots” around the installation that do not receive as much heat during production of well fluid, and so do not retain as much heat as other parts of the installation. Such “cold-spots” can have shortened “cool-down times” and/or increased risk of embrittlement/thermal fatigue due to cooling effects that may not be easily addressed by adding insulation.

Other known measures can include adding electrical/active heating elements around the cold-spot area of the installation, injecting hydrate formation inhibitors into the well fluid and making the installation from more exotic materials that retain strength at lower temperatures/are less susceptible to thermal fatigue. However, these measures can also add excessive weight, complexity and/or cost to the installation design, as well as have increased operating costs and complexity.

Accordingly, the present disclosure provides an improved subsea installation which addresses the above concerns.

SUMMARY

From one aspect, the present disclosure provides a subsea installation defining a flow path for well fluid there through having a flow temperature and a lower hydrate formation temperature at which hydrates will form in the well fluid. The installation comprises a body through which the flow path is defined, an insulating coating defining a thickness on the exterior of the body for thermally insulating the body from ambient seawater surrounding it, and at least one heat storing member positioned around a portion of the exterior of the body and provided within the thickness of the insulating coating such that it is enclosed thereby. The heat storing member comprises a phase change material (PCM) that has a melting point which is below that of the flow temperature of the well fluid and above the hydrate formation temperature of the well fluid.

It should be understood that the heat storing member is a separate component to the insulating coating, and contains (a bulk of) PCM material therein. It is thus distinct to an insulating coating that happens to include PCM material within its composition (e.g., including encapsulate PCM material incorporated into an insulating matrix material). In embodiments, such an insulating coating may nevertheless be used in combination with the heat storing member.

In one embodiment of the above, the heat storing member is in physical contact with the portion of the exterior of the body.

In a further embodiment of either of the above, the heat storing member is shaped to conform to the shape of the portion of the body.

In a further embodiment of any of the above, the portion is a cold-spot location on the body.

In a further embodiment of any of the above, the installation is a subsea manifold and the portion is a dead leg of the manifold through which production of well fluid is prevented. In another embodiment, the installation is a subsea Christmas tree and the portion is a spool casing of the Christmas tree. In yet another embodiment, the installation is a subsea Christmas tree and the cold-spot location is a gas lift injection passage of the Christmas tree. In yet another embodiment, the installation is a subsea Christmas tree and the cold-spot location is a cap of the Christmas tree.

In a further embodiment of any of the above, a plurality of heat storing members are arranged around the portion of the body.

In a further embodiment of any of the above, a plurality of heat storing members are arranged at different portions on the body. The different portions are different cold-spot locations on the body.

In a further embodiment of any of the above, the heat storing member and the insulating coating provide a combined thickness on the exterior of the portion of the body, and the heat storing member provides around a third of the combined thickness. In a further embodiment, the combined thickness is between 50-100mm and/or the heat storing member has a thickness of between 15-35mm. From another aspect, the present disclosure provides a subsea installation defining a flow path for well fluid there through. The installation comprises a body through which the flow path is defined and at least one heat storing member positioned around a portion of the flow path and attached to the body. The heat storing member comprises a phase change material (PCM) that is configured to solidify in response to a temperature drop communicated to the heat storing member during start-up of well fluid production through the body.

In one embodiment of the above, the installation is a subsea Christmas tree and the portion of the flow path is (immediately) downstream of a choke valve in the flow path.

In a further embodiment of either of the above, the PCM has a melting point which is about that of the ambient seawater around the subsea installation.

In a further embodiment of any of the above, the PCM has a melting point of between 1°C to 5°C, for example, 3°C to 5°C.

In yet a further embodiment of any of the above, the heat storing member is shaped to conform to the shape of the body around the portion of the flow path. This can be the shape of the external surface of the body around that portion or the shape of an annular groove formed in that body around that portion.

From yet another aspect, the present disclosure provides a subsea installation defining a flow path for gas lift fluid there through, the installation comprising a body through which the flow path is defined, and at least one heat storing member positioned around a portion of the flow path and attached to the body. The heat storing member comprises a phase change material (PCM) that is configured to solidify in response to a temperature drop communicated to the heat storing member during start-up of a gas lift injection operation communicating gas lift fluid through the body.

In one embodiment of the above, the installation is a subsea Christmas tree and the portion of the flow path is (immediately) downstream of a gas lift injection control valve in the flow path.

In a further embodiment of either of the above, the PCM has a melting point which is about that of the ambient seawater around the subsea installation.

In a further embodiment of any of the above, the PCM has a melting point of between 1°C to 5°C, for example, 3°C to 5°C.

In yet a further embodiment of any of the above, the heat storing member is shaped to conform to the shape of the body around the portion of the flow path. This can be the shape of the external surface of the body around that portion or the shape of an annular groove formed in the body around that portion.

Although certain advantages are discussed below in relation to the features detailed above, other advantages of these features may become apparent to the skilled person following the present disclosure.

BRIEF DESCRIPTION OF DRAWINGS

One or more non-limiting examples will now be described, by way of example only, and with reference to the accompanying figures in which:

Figure 1 shows a schematic, cross-sectional view through a subsea Christmas tree in accordance with an embodiment of the present disclosure; and Figure 2 shows a schematic, cross-sectional view through a subsea manifold in accordance with another embodiment of the present disclosure.

DETAILED DESCRIPTION

Referring to Figure 1, a schematic cross-section of a subsea Christmas tree 10 is shown. The Christmas tree 10 includes a body 12 that defines a flow path 14 for well fluid W to flow there through. The flow path 14 is defined by a passage in the body 12, and is in fluid communication with a well at an upstream end thereof and a production port at a downstream end thereof.

During production, well fluid Wwill pass from the well through the flow path 14 and exit the Christmas tree 10 via the production port 16. The production port 16 can be connected to further pipelines or fluid connections (not shown) that allow well fluid W to be communicated to production facilities for further processing.

The body 12 includes a spool casing 13 (i.e., tubing) that defines a portion of the flow path 14 there through, and also includes a cap 15 and a choke valve 18.

The cap 15 seals the body 12 and prevents leakage of produced well fluid therefrom to the surrounding seawater, or surrounding seawater from entering the body 12.

The choke valve 18 is arranged within the body 12 and is operable to control the flow rate of well fluid exiting the production port 16 during production. As shown, this can be achieved by controlling the degree of protrusion of a valve element 19 into the flow path 14 to selectively block and open the flow path 14 by varying amounts. The choke valve 18 can also be operated to stop production of well fluid, by closing the flow path 14 completely. Alterative or additional flow control and shut down means (not shown) can also be provided in the Christmas tree 10, for example, in the spool casing 13 or in the form of further valves (e.g., check valves) therein.

A gas lift injection port 20 is defined through the body 12 and is fluidly connected to a gas lift injection passage 22 that protrudes through the spool casing 13 parallel to the flow path 14. The gas lift injection passage 22 is fluidly connected to the flow path 14 (not shown) in order to allow the injection of fluid therein to encourage well fluid production in a generally known manner.

The body 12 includes an insulating coating 30 defining a thickness Tj on the exterior thereof. The insulating coating 30 insulates the body from the ambient seawater surrounding the Christmas tree 10 and helps retain heat from the flow of production well fluid in the body 12.

The insulating coating 30 can be made of any suitable insulating material, such as a resin, foam or thermoplastic. Suitable examples include silicone resins, phenolic resin foams, or syntactic foams, such as a syntactic silicone foam or a syntactic epoxy foam.

In accordance with one aspect of the present disclosure, heat storing members 40a-c (shown schematically in hatched boxes) are positioned around portions of the exterior of the body 12. The heat storing members 40a-c are provided within the thickness Tj Of the insulating coating 30 and are enclosed thereby. In other words, the insulating coating 30 surrounds the heating storing members 40a-c and encases them against the body 12. It may thus be seen that the heat storing members 40a-c are placed within a cavity defined with the insulating coating 30. The heat storing members 40a-c can thus be in physical contact with the insulating coating 30.

In this manner, the heat storing members 40a-c define a thickness Th, and in the areas where the heat storing members 40a-c are provided, the heat storing members 40a-c and the insulating coating 30 define a combined thickness T _c around the exterior of the body 12.

Any suitable thicknesses can be used, however, in one example, the combined thickness T _c can be between 50-100mm, with the heat storing member thickness Th being between 15-35mm. In this manner, the heat storing members 40a-c may provide around a third of the combined thickness T _c , and thus replace a third of the insulating coating thickness Tj. As discussed below, this can provide improved heat supply and retention around the body 12 with reduced costs. The heat storing members 40a-c comprise a phase change material (“PCM”) that has a melting point which is below that of the flow temperature of the well fluid (i.e., when it is being produced through the flow path 14) and above the hydrate formation temperature of the well fluid.

In one example, production well fluid flowing through the flow path 14 can have a temperature in the region of 50°C or greater, and hydrates can form therein at a temperature of around 20°C. The temperature of the ambient seawater around the tree 10 can be at a temperature of around 5°C or less, and Joule-Thompson effects may cool below freezing for short periods. In this case, to keep the body above the hydrate forming temperature, the PCM melting point can be set to be between e.g., 25-45°C, and to protect parts of the body 12 from damage due Joule- Thompson effects, the PCM melting point can be set to be at the ambient seawater temperature.

In this manner, when well fluid is flowing through the flow path 14 and body 12 during production, heat therefrom will be transferred to the PCM to melt it. The PCM will thus be held in liquid form in the heat storing members 40a-c during well fluid production. When production is stopped or interrupted, the cold subsea temperatures around the tree 10 will cause the PCM to cool to below its melting temperature, converting it into solid form. This will cause latent heat stored in the PCM to be released to supply heat to the portions of the body 12 around which they are positioned. This additional heat will be communicated to the body 12 and to well fluid W remaining in the flow path 14 to keep it above the hydrate formation temperature. This can help keep the well fluid flow path 14 clearer for longer after shut down.

The heat storing member 40a-c being enclosed within the thickness Tj of the insulating coating 30 around the body 12 itself provides improved retention of additional heat around the body 12, improving the cool-down time available for the tree 10 without the use of other costlier and/or complex measures.

As will be appreciated, this can allow production of well fluid through the tree 10 to be stopped or interrupted for longer, without costly or time consuming operations being needed to clear blockages from hydrates (or other solid deposits) when production is to be restarted. This can reduce operational costs and down time for well fluid production through the tree 10.

Accordingly, the depicted PCM heat storing members 40a-c are strategically positioned on portions of the body 12 that are known “cold-spot” locations. These are locations so-called because they are not as readily heated by the flow of well fluid through the body 12 (i.e., above the hydrate forming temperature). This is in part due to their closer proximity to the surrounding seawater than the flow path 14. Accordingly, these locations may require additional heat to keep them above the hydrate formation temperature for a longer period of time after shut down, and to avoid them becoming susceptible to embrittlement or thermal fatigue due to (e.g., Joule-Thompson) cooling effects encountered during production start-up and/or gas lift injection.

Thus, the combination of the insulating coating 30 encasing distinct PCM heat storing members 40a-c at particular portions of the body 12 can help prevent these cold-spot locations from becoming sources of hydrate formation. The specific cold-spot locations depicted are discussed below:

A heat storing member 40a is provided around the spool casing 13 of the body 12; heat storing members 40b are provided around the gas lift injection port 20 and passage 22; heat storing members 40c are provided around the cap 15.

The spool casing 13 can be particularly exposed to the ambient sea water compared to the interior of the body 12, and is also in more intimate contact with the relatively colder injected lift gas flowing in the passage 22 (as discussed in more detail below). Therefore, it can particularly benefit from the heat storing member 40a being configured to provide heat thereto during production shut down.

During gas lift injection, the injected gases can cool the body 12 around the passage 22 e.g., due to Joule-Thompson effects from expansion of the injected gases in the passage 22 through control valves (not shown) and/or the injected gases generally having relatively cooler temperatures than the body 12 (e.g., as they are supplied to the tree 10 by a feed line passing long distances through the ambient seawater). This means that if gas lift injection is used, the body 12 may be cooler in this area when a shutdown occurs. The heat storing members 40b near the gas lift injection port 20 and passage 22 can thus be beneficial to provide heat to counteract the cooler temperatures found in this area.

The distal end of the cap 15 is also more exposed to the ambient seawater temperatures than the interior of the body 12. It may thus be beneficial to provide heat from heat storing members 40c thereto during shut down to enhance the length of cool-down time.

The PCM heat storing members 40a-c being encased by the coating 30 can reduce the amount of insulating material needed in a particular area (e.g., to reduced Tj = T _c - Th). Thus, an improvement in the cool-down time and protection of cold-spot locations can be realised whilst also reducing the amount of insulating material surrounding portions of the body 12. This may reduce the costs associated with the manufacture, design and installation of the tree 10.

In a further aspect of the present disclosure, a PCM heat storing member 40d is provided to help protect against sudden cooling owing to the Joule- Thompson effect e.g., upon production start-up. As discussed above, such sudden cooling can cause problematic thermal fatigue and embrittlement of the body 12 and other components of the tree 10.

In one example, the portion of the flow path 14 immediately downstream of the choke valve 18 is particularly susceptible to sudden (Joule-Thompson) cooling during production start-up due to production fluid expanding through the choke valve 18. This can lead to thermal fatigue, embrittlement and possibly failure in the body 12 (i.e., the spool casing) defining this portion of the flow path 14. Such effects may also cause issues with the operation/failure of the choke valve 18. Thus, the heat storing member 40d is wrapped around this portion of the flow path 14 by being attached to the portion of the body 12 (i.e., spool casing) defining it. In this manner, the heat storing member 40d makes direct contact with the portion of the body 12.

Unlike the PCM in the heat storing members 40a-c, the PCM used in heat storing member 40d is configured such that the sudden temperature drop provided by production fluid undergoing rapid expansion through the body 12 causes the PCM to solidify to supply latent heat to the body 12 to compensate for the cooling. This can lessen the sudden temperature drop and thus help protect the body 12 (and associated components - e.g., choke valve 18) in the vicinity of the heat storing member 40d.

As discussed above, the temperature of the ambient seawater around the tree 10 can be at a temperature of around 5°C or less, and Joule-Thompson effects may cool several degrees below freezing (albeit for short periods). Thus, in one example, the heat storing member 40d is comprised of a PCM that melts at the ambient seawater temperature (e.g., between 1°C to 5°C, 3°C to 5°C, or about 3°C, 4°C or 5°C) and that solidifies when cooled below this temperature (e.g., by expanding production fluid). The heat released from the PCM in heat storing member 40d as it solidifies will serve to warm the portion of the body 12 (i.e., spool casing) around the flow path 14 to prevent or mitigate against the associated cooling and resulting embrittlement or thermal fatigue. Of course, these are just certain examples, and any suitable melting temperature can be selected, depending on the ambient seawater and/or relative cooling effect experienced in a given application.

Moreover, although heat storing member 40d is exemplified around a portion of the flow path 14 downstream of the choke valve 18, there may be other areas of the body 12/tree 10 that are susceptible to detrimental Joule-Thompson cooling effects. Thus, in further examples, heat storing members 40d can be provided additionally or alternatively in any such areas. It will be understood that in general, such areas are those which are downstream of a constriction that causes rapid expansion of fluid (such as production fluid or gas lift fluid) in the body 12 (or spool casings) of the tree 10. In one example, such an area includes a portion of the gas lift injection passage 22 that is downstream of a gas lift fluid control valve (not shown) therein.

Suitable PCMs for the heat storing members 40a-d are widely available, and their melting point can be readily tuned to suit different applications, hydrate formation temperatures and Joule-Thompson/cooling effects for different subsea installations and well fluid conditions. A suitable PCM is a wax material, such as a paraffin or petroleum wax. Other suitable PCMs may include a hydrated salt or eutectic salt.

Although a plurality of heat storing members 40a-d are depicted, only at least one heat storing member need be used within the scope of this disclosure. As shown, there may also be one or more heat storing members within each particular cold-spot location (e.g., one member 40a, two members 40b, 40c) and one or more areas susceptible to detrimental Joule-Thompson cooling effects (e.g., one member 40d).

In any event, within the scope of this disclosure, any suitable number and arrangement of PCM heat storing members 40a-d may be used and placed around portions of a body of a subsea installation. The precise number and arrangement can depend, for example, on the configuration and geometry of the body of the installation, as well as the desired cool-down time, cold-spot locations and/or areas susceptible to detrimental Joule-Thompson cooling effects.

In the depicted example, the heat storing members 40a-d are placed in physical contact with the exterior of the body 12 and can be shaped to conform to its external geometry (i.e. , contours). For example, member 40a is annular and conforms to the outer diameter of the spool casing 13, and member 40d is annular and conforms to the outer diameter of the portion of the flow path 14 (defined by the body 12) downstream of the choke valve 18.

These additional, optional measures can provide further improvement to the thermal communication between the PCM and the body 12. In an alternative example, the heat storing members 40a-d can be provided in standardised block shapes.

In one example, the heat storing members 40a-c are attached to the required portions of the body 12 and then coated with insulating material until the insulating coating 30 and desired combined thickness T _c is provided there over. This can provide a convenient means of applying the heat storing members 40a-c to the body 12, without making the insulating coating process more complicated. In an alternative example, cavities may be provided in insulating coating 30 around the portions of the body 12, which are then filled with the heat storing members 40a-c and covered over.

In one example, the heat storing member 40d is attached to the required portions of the body 12, and may be secured to the external surface thereof or an external annular groove formed therein. There may or may not be insulation provided in combination with heat storing member 40d (e.g., insulation surrounding the heat storing member 40d attached to the body 12), depending on where it is implemented and the application.

Like heat storing members 40a-c, heat storing member 40d can be any suitable thickness, such as between 15-35mm. The heat storing member 40d can also extend any suitable length along the flow path 14, as necessary to combat the localised cooling effects felt thereby in a particular application.

The heat storing members 40a-d generally include a container that encloses and seals PCM therein. Heat that is stored and released from the PCM in the container will be communicated to the body 12 and/or insulating coating 30 via conduction through the container (i.e. , through walls of the container).

In the depicted embodiments, the containers are rigid containers comprising rigid container walls between which the PCM is enclosed. The container can be made from any suitable material, such as a plastic or metal material. In other embodiments (not depicted), the container is a flexible container e.g., made from a flexible plastic/film material. In this sense, the container may be a flexible bag-type container that allows some deformation of the container. This can make it easier to mould the heat storing members 40a-d around the portions of the body 12 and/or conform to the geometry thereof, as may be necessary.

Although embodiments of the present disclosure have been exemplified in Fig. 1 in the context of a subsea Christmas tree, it should be understood that the teachings of the present disclosure are applicable to any other suitable subsea installations that may be apparent to the skilled person.

For example, referring to Figure 2, a schematic cross-section of a subsea manifold 110 in accordance with another embodiment of the present disclosure is shown.

The manifold 110 includes a body 112 formed as a substantially tubular casing that defines a flow path 114 for flowing well fluid there through. There are several different ports 113, 115, 116, 124, 125, 126 and flow control means 118, 128 (e.g., housing valves, sensors etc.) defined within the body 112 that allow for connection and control of different fluid flows through the manifold 110.

During production, well fluid Wwill pass into an inlet port 113 and flow along the flow path 114 and exit the manifold 110 at an outlet port 116. The outlet port 116 can be connected to further pipelines or fluid connections (not shown) that allow well fluid W to be communicated to production facilities for further processing. In this manner, the manifold 110 can be used to distribute and communicate well fluid to subsea installations and production facilities as needed (e.g., between a wellhead and a pipeline).

It is common for the manifold 110 to have an active section 120 (the right side in Fig. 2) that receives and communicates a flow of well fluid W there through during production, and a non-active section 122 (the left side in Fig. 2) that does not actively communicate production well fluid W there through. This non-active section 122 is commonly referred to in the art as a “dead leg” of the manifold 110. The dead leg 122 can provide access to the flow path 114 (e.g., via ports 124, 125, 115) in the event that further fluids need to be added during production (e.g., to add additives to the well fluid W or additional well fluid from other wells), but does not necessarily receive a flow of fresh well fluid W there through during production. Accordingly, the dead leg 122 provides a cold-spot location that will be more susceptible to cooling quicker to hydrate forming temperatures when production is stopped. This can cause the dead leg 122 to become blocked, which can prevent use of the manifold 110 until it is unblocked or require the circulation of expensive inhibiting agents therein. Therefore, as in Fig. 1 , the exterior of the body 112 is provided with an insulating coating 130 and the dead leg 122 portion is provided with PCM heat storing members 140a-c enclosed in the thickness Tj of the insulating coating 130 there around.

As with Fig. 1, the heat storing members 140a-c may be in physical contact with the body 112 and conform to its shape, and can include any of the features discussed above in relation to the heat storing members 40a-c of Fig. 1.

As shown, a heat storing member 140a is provided along a length of the body 112 to help heat the main length of the dead leg 122 during cool down, and other members 140b, 140c are provided adjacent the ports 124, 125 and flow control means 128 to keep them unblocked and in better working order for longer during cool down and at start-up.

As will be appreciated, Figs 1 and 2 are highly simplified depictions of a subsea Christmas tree and manifold to aid understanding of the present disclosure, and other embodiments can be more complex and include combinations of a variety of additional and alternative components (e.g., casings, ports, flow paths, fluid connections, valves, control means etc.) that are not depicted, but which will nonetheless be apparent to the skilled person. All such configurations and variations subsea Christmas trees and manifolds are envisaged within the scope of this disclosure.

Although specific embodiments of the present disclosure have been described and depicted, these are not limiting in natures, and the scope of the present disclosure is to be determined by the following claims.