Technical Field

The present disclosure relates to a submersible and method therefor. In particular the present disclosure relates to submersible for decommissioning a subsea well and a method of decommissioning a subsea well.

Background

Subsea wells in the seafloor are used to extract oil and gas. Eventually the oil and gas field will become depleted or the subsea well is no longer viable. In this case, the subsea well is decommissioned to prevent the subsea well contaminating the marine environment.

Typically, a subsea well is decommissioned by sealing the top of the subsea well with one or more plugs. The plugs prevent the potentially harmful fluids in the well from being introduced into the marine environment.

However, there may be some environmentally harmful drilling fluid(s) present above the height of the plugs in the subsea well between the casings of the subsea wellhead. Overtime, the casings and the conductor in the subsea well may deteriorate and this can lead to the drilling fluid(s) leaking from the subsea well. This means that some of the drilling fluid(s) can still potentially contaminate the marine environment even if the plug itself is not compromised and still seals the lower portion of the subsea well.

It is known to extract some of the drilling fluid from the plugged subsea wells with a decommissioning vessel. A problem with this arrangement is that connection must be made between the decommissioning vessel and the subsea well during the time drilling fluid is extracted. This means a clear weather window and heavy rig-up on the well are required to perform this type of decommissioning operation. Furthermore, decommissioning deep subsea wells can be particularly demanding and costly.

Summary

Examples of the present disclosure aim to address the aforementioned problems. According to an aspect of the present disclosure there is a submersible for decommissioning a subsea well comprising: a first reservoir containing a displacement fluid; at least one seal for mounting on a subsea well; a fluid insertion pipe in fluid communication with the first reservoir and arranged to insert the displacement fluid into the subsea well; and a second reservoir arranged to receive displaced drilling fluid from the subsea well when the displacement fluid is inserted into the subsea well.

Optionally, the submersible comprises a tank arranged to house the first and second reservoirs.

Optionally, the tank comprises a moveable barrier arranged to modify the respective volumes of the first and second reservoirs.

Optionally, the remotely operated submersible comprises one or more perforators for perforating a wall of the subsea well.

Optionally, the submersible comprises a first perforator arranged to perforate the wall of the subsea well at a first distance from the at least one seal and a second perforator arranged to perforate the wall of the subsea well at a second distance from the at least one seal wherein the first distance is smaller than the second distance.

Optionally, the submersible comprises an inner seal positioned between the first and second perforators arranged to engage the wall of the subsea well.

Optionally, the submersible comprises drilling fluid inlet in fluid communication with the second reservoir.

Optionally, the submersible comprises one or more valves between the drilling fluid inlet and the second reservoir arranged to selectively control flow of the drilling fluid into the second reservoir.

Optionally, the submersible comprises at least one pump for pumping the displacement fluid into the subsea well. Optionally, the second reservoir comprises at least one gas valve for venting gas.

Optionally, the submersible a pressure valve arranged to equalise pressure in the first reservoir or the second reservoir as the submersible changes depth.

Optionally, the submersible is remotely operable.

Optionally, the submersible comprises at least one power source.

Optionally, the submersible comprises a controller configured to autonomously control the submersible.

Optionally, the displacement fluid comprises a density of 1 .3 to 1 .6 kg/m ³ .

Optionally, the displacement fluid has a density greater than the drilling fluid. Optionally, the drilling fluid is oil based mud.

Optionally, the subsea well comprises a plug sealing at least part of the subsea well from the marine environment and the fluid insertion pipe is positioned above the plug when the submersible is mounted on the subsea well.

According to another aspect of the present disclosure there is a method of removing drilling fluid from a subsea well comprising; sealing a submersible apparatus on a subsea well, the submersible apparatus comprising a first reservoir containing a displacement fluid; inserting the displacement fluid into the subsea well from the first reservoir; displacing drilling fluid from the subsea well with the displacement fluid; transferring the displaced drilling fluid into a second reservoir into the submersible apparatus.

Brief Description of the Drawings Various other aspects and further examples are also described in the following detailed description and in the attached claims with reference to the accompanying drawings, in which: Figure 1 shows a schematic side view of part of a subsea well according to an example; Figures 2 to 8 show a sequence of schematic side views of a submersible interacting with a subsea well according to an example;

Figure 9 shows a schematic side view of a submersible according to an example; and Figure 10 shows a flow diagram of a method of using a submersible according to an example.

Detailed Description

Figure 1 shows a schematic side view of part of a subsea well 100 according to an example. The subsea well 100 is formed in the seabed 102. The subsea well 100 comprises a conductor pipe 104 to prevent the seabed falling into the wellbore. The conductor pipe 104 comprises a casing string 106 installed within the conductor pipe 104 and within a drilled bore (not shown). In some examples the casing string 106 is supported by the conductor pipe 104 by a casing hanger (not shown).

A first cement annulus 108 is formed between the conductor pipe 104 and the casing string 106. In some examples, the conductor pipe 104 is 36” (91.4cm) in diameter. Cement is pumped into a void 206 between the conductor pipe 104 and the casing string 106. In some examples, the first cement annulus 108 comprises a first height 112 which is between an upper end 110 of the conductor pipe 104 and the seabed 102. However in other examples, the first cement annulus 108 comprises a first height 112 which is below the level of the seabed 102.

The casing string 106 comprises a plurality of casings with sequentially smaller diameters. For example the casing string 106 as shown in Figure 1 can comprise one or more of a surface casing, an intermediate casing, a production casing, and a production liner.

For example, the casing string 106 comprises a plurality of concentric casings e.g. 20” (50.8cm) , a 13 3/8” (34.0cm) casing and a 10 ¾” (27.3 cm) casing. Alternatively, the casing string 106 comprises an alternative a plurality of concentric casings e.g. a 13 3/8” (34.0cm) casing and a 10 ¾” (27.3 cm) casing. In other examples, the casing string 106 can comprise any suitable arrangement of concentrically arranged casings having different diameters.

One or more additional cement annulus 114 can be provided around lower terminating ends of the casings. The installation and arrangement of the subsea well 100 and the casing string 106 is known and will not be described in any further detail.

The conductor pipe 104 is connected to a low pressure wellhead housing (LPWHH). Within the LPWHH, a high pressure wellhead housing (HPWHH) is landed. The casings 106 are landed in the HPWHH. The LPWHH and the HPWHH may form a wellhead 116. The well head 116 provides a temporary seal until the subsea well 100 can be fully decommissioned and abandoned. The well head 116 can be removed when the subsea well is abandoned.

The subsea well 100 as shown in Figure 1 is abandoned or plugged, and as such the subsea well 100 is sealed with at least one plug. An abandoned or plugged subsea well 100 is a subsea well 100 that is or will be decommissioned. In some examples, the subsea well 100 is sealed with an alloy plug 118 and a bridge plug 120. The alloy plug 118 extends through the casing string 106 and can be formed from a bismuth alloy. The alloy plug 118 may have perforated one or more locations in the casing string 106 in order to extend across the diameter of the casing string 106 up to the outmost casing string 106. However, in other examples, the subsea well 100 is plugged with any other suitable material for sealing the subsea well 100 from the marine environment.

The alloy plug 118 and the bridge plug 120 are arranged prevent the potentially environmentally harmful fluids in the subsea well 100 from being introduced into the marine environment. The alloy plug 118 and the bridge plug 120 are known and will not be described in further detail.

In some circumstances, there may be some drilling fluid 200 (best shown in Figure 2) present above the alloy plug 118 and the bridge plug 120 in the subsea well 100 between the different layers of the casing strings 106 of the subsea well 100. In this case normally, the drilling fluid 200 between the conductor pipe 104 and the casing string 106 is vented to the sea. Whilst the subsea well 100 may be sealed by the alloy plug 118 and the bridge plug 120, overtime the casing string 106 or the conductor pipe 104 located over the alloy plug 118 can degrade. This means that in some circumstances it is possible that drilling fluid 200 can leak from the between the casing strings 106 in the upper portion 122 of the subsea well 100 above the alloy plug 118 and the bridge plug 120 and the seabed 102.

For example, the structure or the material of the casing string 106 in the subsea well 100 may deteriorate over a long period of time. This may lead to the drilling fluid 200 leaking from the subsea well 100. This means that some of the drilling fluid 200 can still potentially contaminate the marine environment with hydrocarbons even if the plugs 118, 120 are not compromised and effectively still seals the subsea well 100.

A submersible 900 for removing the waste drilling fluid 200 in the upper portion 122 of the subsea well 100 above the plugs 118, 120 will now be discussed in reference to Figure 9.

Figure 9 shows a schematic side view of the submersible 900. The submersible 900 is mountable on a subsea well 100 and arranged to remove drilling fluid 200 from the subsea well 100. The submersible 900 in some examples is a remotely operated underwater vehicle (ROV).

The submersible 900 comprises a hull body 902 and a plurality of propulsors 904 are mounted on the hull body 902. As shown in Figure 9, there are four propulsors 904 mounted on the exterior surface of the hull body 902 for controlling the movement, position, and depth of the submersible 900. In other examples, there can be any suitable number of propulsors 904 for controlling the movement and depth of the submersible 900. The propulsors 904 are arranged to maneuverer the submersible 900 underwater and position the submersible 900 adjacent to the subsea well 100. In some examples, the propulsors 904 are thrusters which can be rotated about one or more axes.

In some examples, the submersible 900 does not have any propulsors 904 and is not able to move itself. Accordingly, the submersible 900 move into place with another method. For example, the submersible 900 is lowered onto the subsea well 100 with a crane mounted on a vessel or another ROV (not shown) positions the submersible 900 on the subsea well 100.

In some examples, the submersible 900 comprises a controller 906 arranged to control one or more components and systems of the submersible 900. The submersible 900 can be remotely controlled by a remote user or alternatively the submersible 900 can be autonomous. If the submersible 900 is remotely controlled, the controller 906 receives user control instructions via communications module 908. The communications module 908 is connected to an antenna (not shown) or a data connection for receiving and transmitting data e.g. receiving user control instructions.

Figure 9 shows various control modules and systems represented by boxes connected to the hull body 902. For the purposes of clarity these systems and control modules are represented as being outside the hull body 902. However, the systems and control modules are housed within the hull body 902.

The communications module 908 is configured to transmit data back to the remote user. The communications module 908 can send data relating to the status of the submersible 900 and / or the status of the subsea well 100. The submersible 900 can comprise one or more sensors (not shown) detecting a status of the submersible 900 and / or the subsea well 100. In some examples, the submersible 900 comprises a camera (not shown) and the communications module 908 transmits images of the subsea well 100 to the remote user.

The controller 906 is configured to actuate one or more components and systems of the submersible 900 in response to the user control instructions. For example, the controller 906 can actuate one of more of the propulsors 904 to move the submersible 900 in response to a move instruction received from the user.

In some examples, the controller 906 does not receive user control instructions and carries out the decommissioning method described below autonomously. In general, the various examples of the disclosure may be implemented in hardware or special purpose circuits, software, logic, or any combination thereof. In some examples, the controller 906 may be implemented in hardware, while other aspects may be implemented in firmware or software which may be executed by a controller, microprocessor, or other computing device, although the disclosure is not limited thereto. While in some other examples, the controller 906 may be illustrated and described as block diagrams, flow charts, or using some other pictorial representation, it is well understood that these blocks, apparatus, systems, techniques, or methods described herein may be implemented in, as non-limiting examples, hardware, software, firmware, special purpose circuits or logic, general purpose hardware or controller or other computing devices, or some combination thereof.

The examples of this disclosure may be implemented by computer software executable by a data processor, such as in the processor entity, or by hardware, or by a combination of software and hardware. The data processing may be provided by means of one or more data processors. Further in this regard it should be noted that any blocks of the logic flow as in the Figures may represent program steps, or interconnected logic circuits, blocks and functions, or a combination of program steps and logic circuits, blocks, and functions.

Appropriately adapted computer program code product may be used for implementing the examples, when loaded to a computer. The program code product for providing the operation may be stored on and provided by means of a carrier medium such as a carrier disc, card, or tape.

The controller 906 in some examples may comprise a memory (not shown). The memory may be of any type suitable to the local technical environment and may be implemented using any suitable data storage technology, such as semiconductor based memory devices, magnetic memory devices and systems, optical memory devices and systems, fixed memory, and removable memory. The data processors may be of any type suitable to the local technical environment, and may include one or more of general purpose computers, special purpose computers, microprocessors, digital signal processors (DSPs) and processors based on multi core processor architecture, as non-limiting examples. Some examples of the disclosure may be implemented as a chipset, in other words a series of integrated circuits communicating among each other. The chipset may comprise microprocessors arranged to run code, application specific integrated circuits (ASICs), or programmable digital signal processors for performing the operations described above.

In some examples, the submersible 900 optionally comprises a battery 910 for providing power to the components and systems of the submersible 900. The battery 910 can be housed within the hull body 902. In other examples the submersible 900 does not comprise a battery 910 but is connected to a power supply via a power cable (not shown). The power cable can be connected to a vessel on the surface or another ROV as required. This may be preferable in the example where the submersible 900 is positioned in place by e.g. a crane or another ROV.

The hull body 902 of the submersible 900 may optionally comprise a hoisting loop 912 for connecting to a hoisting apparatus such as a crane. This allows the submersible 900 to be moved on a deck of a surface vessel or lowered into positioned on the subsea well 100.

In some examples, the controller 906 comprises one or more submodules for controlling systems on the submersible 900. As shown in Figure 9, the controller 906 is connected to a valve module 914, a pump module 918; and a perforator module 924. The controller 906 can send control instructions to each of the submodules as required. Alternatively, the controller 906 can be directly connected to the components and subsystems of the submersible 900 and no submodules are provided.

The submersible 900 can comprise a valve module 914 arranged to control one or more valves 916, 946, 948 on the submersible 900. For the purposes of clarity no communication link has been shown between the valve module 914 and the other valves 946, 948. However the valve module 914 is configured to control all the valves 916, 946, 948 on the submersible 900. The submersible 900 can further comprise a pump module 918 arranged to control a pump 920 in fluid communication with a tank 922. The submersible 900 can also further comprise a perforator module 924 arranged to control actuation of one or more perforators 926, 942.

The operation of the valves 916, 946, 948, pump 920 and perforators 926, 942 will be discussed in further detail below with reference to Figures 2 to 8 and 10.

Although not shown in Figure 9, the submersible 900 can optionally comprise further components and systems. For example the submersible 900 can comprise a manipulator arm (not shown) mounted to the hull body 902 for remote manipulation of objects near the subsea well 100. The submersible 900 can optionally comprise lights mounted on the hull body 902. b Furthermore, the submersible 900 can optionally comprise buoyancy equipment such as ballast tanks for adjusting the depth of the submersible 900.

Turning back to Figure 9, the submersible 900 will be discussed in more detail. As mentioned above, the hull body 902 comprises a tank 922. The tank 922 is arranged to house a first reservoir 928 containing a displacement fluid 932.

The tank 922 is further arranged to house a second reservoir 930 arranged to receive drilling fluid 200 from the subsea well 100. In some examples, the second reservoir 930 can optionally be preloaded with a holding fluid (not shown) before the drilling fluid 200 is transferred from the subsea well 100 to the second reservoir 930. This can be advantageous for managing operation of the submersible 900 before and after the submersible 900 is loaded with the drilling fluid 200. This is because the weight and pressure of the second reservoir 930 will be similar before and after the loading the drilling fluid 200 onto the submersible 900. The holding fluid can be seawater or another similar fluid. The holding fluid can be discharged from the second reservoir 930 as the drilling fluid 200 is transferred to the second reservoir 930 via the gas release valve 948. The holding fluid can be pumped out of the second reservoir 930 or the drilling fluid 200 can urge the holding fluid out of the second reservoir 930 as the drilling fluid 200 fills the second reservoir 930. In some examples, the displacement fluid 932 is a fluid having a density greater than the density of the drilling fluid 200. Furthermore, the displacement fluid 932 is a fluid having a density greater than seawater in the vicinity of the subsea well 100

In some examples, the drilling fluid 200 can be an oil based mud (OBM). Typically the OBM can comprise a mix of a base oil and water e.g. brine. One or more additives can be added to the OBM. In some examples, the OBM can be 80% base oil such as diesel oil, mineral oil etc and 20% brine. In this way OBM comprises hydrocarbons which can contaminate the marine environment if not removed from the abandoned or plugged subsea well 100. In some examples, the OBM comprises a density of between 1300 kg/m ³ to 1550 kg/m ³ (1 3sg to 1 .55 sg) at 50C° however, the density of the OBM can vary depending on the conditions e.g. pressure and possibly temperature exposed to the OBM. In some other examples, the OBM comprises a density of between 640 kg/m ³ to 1650 kg/m ³ (0.64 sg to 1.65 sg) Furthermore, the density of the OBM can vary depending on the composition of the OBM. For example, if the ratio of base oil to brine varies, then this will affect the density.

In some other less preferred examples, the submersible 900 and the method described below can be used together with other types of drilling fluid 200, for example water based mud etc. A water based mud may present less of a contamination risk to the marine environment, it still may be desirable to remove the water based mud from the abandoned or plugged subsea well 100. For example, the water based mud may comprise additives that can contaminate the marine environment.

The displacement fluid 932 in some examples comprises a density of greater than 1600 kg/m ³ . In some examples, the displacement fluid 932 comprises a density of between 1500 kg/m ³ to 2300 kg/m ³ . In some other examples, the displacement fluid 932 comprises a density 1500 kg/m ³ , 1600 kg/m ³ , 1700 kg/m ³ , 1800 kg/m ³ , 1900 kg/m ³ , 2000 kg/m ³ , 2100 kg/m ³ , 2200 kg/m ³ , or 2300 kg/m ³

In some examples, the displacement fluid 932 is a brine comprising a heavy salt, that is a salt solution comprising a salt with an average molecular weight heavier than sodium chloride. In some examples, the displacement fluid 932 comprises brine with a halide salt solution. In some examples, the displacement fluid 932 comprises a solution of one or more of calcium bromide, calcium chloride, sodium bromide, potassium chloride, ammonium chloride, zinc bromide.

In some examples, the specific gravity of the displacement fluid 932 is 1.6. In some examples, the displacement fluid 932 is at least 0.5sg more that the drilling fluid 200. In some other examples, the displacement fluid 932 is at least 0.2sg. 0.3sg, 0.4sg, 0.5sg, 0.6sg, 0.7sg, 0.8sg, 0.9sg or 1.0sg more that the drilling fluid 200. In further examples, the displacement fluid 932 comprises a specific gravity more that the drilling fluid 200.

In some other examples the specific gravity of the displacement fluid 932 is 1% to 10% more than the water in the vicinity of the subsea well 100. By selecting a specific gravity of the displacement fluid 932 similar to the subsea well 100, then the displacement fluid 932 reacts similar to the salt water and is easier to handle.

In some examples, one or more additives may optionally be added to the displacement fluid 932 to modify the viscosity of the displacement fluid 932. In some examples, the viscosity of the displacement fluid 932 is greater than the viscosity of the drilling fluid 200. Alternatively, the viscosity of the displacement fluid 932 is less than the viscosity of the drilling fluid 200.

By providing a displacement fluid 932 which is denser than the drilling fluid 200 e.g. OBM, the displacement fluid 932 will sink below the drilling fluid 200 when inserted into the subsea well 100. In this way, the displacement fluid 932 is arranged to displace the drilling fluid 200 from the subsea well 100.

In some examples, the first reservoir 928 and the second reservoir 930 are optionally separated by a moveable barrier 934. The moveable barrier 934 is moveable within the tank 922 and adjusts the respective volumes of the first and second reservoirs 928, 930 when the moveable barrier 934 moves. The moveable barrier 934 provides a seal between the first and second reservoirs 928, 930 and the displacement fluid 932 cannot flow into the second reservoir 930. Similarly, the moveable barrier 934 prevents the drilling fluid 200 flowing into the first reservoir 928. The arrangement shown in Figure 9 illustrates a single tank 922 comprising the first and second reservoirs 928, 930 and this means that the total volume of the tank 922 can be kept smaller than if there were two separate tanks. Nevertheless, in some less preferred examples, the hull body 902 comprises a first tank (not shown) and a second tank (not shown) with fixed volumes for respectively holding the displacement fluid 932 and the drilling fluid 200.

The hull body 902 of the submersible 900 comprises a sealing mechanism 936 for engaging and sealing against the subsea well 100. The sealing mechanism 936 can comprise a deformable material 952, such as a rubber annulusb for engaging and compressing against a top surface of the wellhead 116 of the subsea well 100. Although not shown, the submersible 900 can comprise clamps or other mechanisms for positively securing the submersible 900 against the subsea well 100.

The submersible 900 comprises a fluid insertion pipe 938 in fluid communication with the first reservoir 928. The fluid insertion pipe 938 projects from the underside of the hull body 902 and is arranged to protrude in to the subsea well 100 when the submersible 900 is mounted on the subsea well 100. The fluid insertion pipe 938 is arranged to insert the displacement fluid 932 in to the subsea well 100 as discussed below with reference to Figures 2 to 8.

The fluid insertion pipe 938 comprises one or more sealing rings 940 arranged to engage an inner surface 202 of the subsea well 100. Figure 9 shows two sealing rings 940 mounted on the fluid insertion pipe 938. However, in other examples there can be single sealing ring 940 or alternatively any suitable number of sealing rings 940. The sealing rings 940 are positioned between a first perforator 926 and a second perforator 942 mounted on the fluid insertion pipe 938. The sealing rings 940 are arranged to seal against the inner surface 202 of the subsea well 100 such that the first perforator 926 and the second perforator 942 are not in fluid communication with each other when the fluid insertion pipe 938 is inserted into the subsea well 100.

The sealing rings 940 in some examples comprise a deformable material such as rubber, silicone etc. The sealing rings 940 are therefore deformable and can flex against the inner surface 202 of the subsea well 100 to improve the seal thereagainst. In some alternatively examples, the sealing rings 940 are replaced with an inflatable sealing element (not shown). The inflatable sealing element deploys once the submersible 900 is in position and provides a seal against the inner surface 202 of the subsea well 100, similar to the sealing rings 940. The inflatable sealing element may be preferable to the sealing rings 940 because the sealing rings 940 may not deform correctly or create a sufficient seal as the fluid insertion pipe 938 is inserted in to the subsea well 100.

The first and second perforators 926, 942 are arranged to perforate the walls 204 of the casing string 106 in order to create a new flow path through the upper portion 122 of the subsea well 100. The first and second perforators 926, 942 can comprises a plurality of perforators circumferentially arranged around the fluid insertion pipe 938. The perforators 926, 942 can comprise a plurality of sprung loaded rods for perforating the walls 204 of the casing strings 106. In some other examples, the perforators 926, 942 are perforating guns arranged to urge a projectile through the wall 204 of the casing string 106. Alternatively the perforators 926, 942 comprise explosive charges, such as shape charges for perforating the inner wall 204 of the casing string 106. Indeed, any suitable means can be used to perforate the inner surface 202. The perforators 926, 942 can perforate a plurality of casings in the casing string 106.

The submersible 900 comprises a drilling fluid conduit 944 connected to a drilling fluid inlet 950 and the second reservoir 930. The drilling fluid conduit 944 extends through the first reservoir 928 and the moveable barrier 934. In this way, the drilling fluid 200 can flow from the drilling fluid inlet 950, through the drilling fluid conduit 944 and into the second reservoir 930. By extending the drilling fluid conduit 944 through the first reservoir 928, the submersible 900 can be made more compact.

In some examples, the drilling fluid conduit 944 does not extend through the first reservoir 928 and extends around the outside or to the side of the first reservoir 928. This is the case whereby there are two separate tanks for the first and second reservoirs 928, 930. The drilling fluid conduit 944 is coupled to at least one drilling fluid valve 946 for selectively controlling the flow of the drilling fluid 200 into the second reservoir 930. In some examples, the drilling fluid valve 946 is a sequence of valves e.g. a double valve as shown in Figure 9. Optionally, a double valve arrangement is provided for the drilling fluid valve 946 to ensure redundancy and make sure no drilling fluid 200 leaks. Furthermore the gas release valve 948 and / or the equalising pressure valve 916 can also comprise a double valve arrangement for redundancy purposes. The drilling fluid valve 946 is also connected to the valve module 914 and configured to receive control instructions from the valve module 914.

The second reservoir 930 is in fluid communication with a gas release valve 948 for venting gas captured by the submersible 900 when mounted on the subsea well 100. The gas release valve 948 is also connected to the valve module 914 and configured to receive control instructions from the valve module 914.

The first reservoir 928 is in fluid communication with at equalising pressure valve 916. The equalising pressure valve 916 is arranged to permit equalising of the pressure in the first reservoir 928 and / or the second reservoir 930 when the submersible 900 changes depth. The equalising pressure valve 916 is also connected to the valve module 914 and configured to receive control instructions from the valve module 914.

The method of removing the waste drilling fluid 200 will now be discussed in reference to Figures 2 to 8 and 10. Figures 2 to 8 show a sequence of schematic side views of a submersible 900 interacting with the subsea well 100. Figure 10 shows a flow diagram of a method of using the submersible 900. For the purposes of clarity various features of the submersible 900 as shown in Figure 9 are not shown in Figures 2 to 8.

The subsea well 100 as shown in Figure 2 is the upper portion 122 of the subsea well 100 above the plugs 118, 120 as indicated in the dotted box A in Figure 1 . In the upper portion 122 of the subsea well 100, the void 206 between the casing string 106 and the conductor pipe 104 comprises the drilling fluid 200 e.g. OBM. In some situations, the upper portion 122 of the subsea well 100 can also comprise gas 208. The gas 208 is natural gas that has escaped from the subsea well 100 and is caught by the well head 116.

The submersible 900 in Figure 2 is being positioned on the subsea well 100. As mentioned above, the submersible 900 can manoeuvre itself or the submersible 900 can be lowered by another ROV or a crane on a vessel. As the submersible 900 is deployed and lowered, the drilling fluid valve 946 is opened such that the pressure is equalised in the tank 922. The submersible 900 is lowered onto the subsea well 100 until the sealing mechanism 936 engages and seals against an upper surface 300 of the well head 116 as shown in step 1000 of Figure 10.

The submersible 900 in Figure 3 has engaged the well head 116 and a seal between the subsea well 100 and the submersible 900 has been formed. The second reservoir 930 can optionally comprise a holding fluid as described above. The holding fluid in some examples is a small amount of brine as shown in Figure 3. The brine in the second reservoir 930 can prevent a vacuum forming between the pump 920 and the moveable barrier 934 in the first reservoir 928. This prevents the moveable barrier 934 becoming stuck in position between the first and second reservoirs 928, 930. The brine in the second reservoir 930 can also help lubricate the moveable barrier 934.

After the submersible 900 is mounted on the subsea well 100, the fluid insertion pipe 938 protrudes into the upper portion 122 subsea well 100.

As the fluid insertion pipe 938 protrudes into the subsea well 100, the sealing rings 940 engage the inner surface 202 of the subsea well 100. Accordingly, the sealing rings 940 are arranged to seal against the inner surface 202 of the subsea well 100 such that the first perforator 926 and the second perforator 942 are not in fluid communication with each other.

In this way, the sealing rings 940 create a lower isolated well portion 302 and an upper isolated well portion 304 as indicated in Figure 3.

The controller 906 sends a control instruction to the perforator module 924. The perforator module 923 then actuates the perforators 926, 942. The perforators 926, 942 fire and these create a first set of perforations 400 in the wall 202 of the lower isolated well portion 302 and a second set of perforations 402 in the wall 202 of the upper isolated well portion 304. In some examples, the second set of perforations 402 in the wall 202 of the upper isolated well portion 304 are optionally positioned as close as possible to the wellhead 116. This means that more of the drilling fluid 200 can be successfully transferred to the second reservoir 930. The first set and second set of perforations 400, 402 in the wall 202 of the casing string 106 allow for a new flow path. The first set and second set of perforations 400, 402 are best shown in Figure 4. In some examples, the first set and second set of perforations 400, 402 are a circumferential set of holes.

The second set of perforations 402 located in the upper isolated well portion 304 are adjacent to the gas pocket and the gas 208 flows via the drilling fluid inlet 950 and the drilling fluid conduit 944 into the second reservoir 930. Depending on the subsea well 100, the gas pocket may not be present. Accordingly, there may not be any gas 208 which needs to be vented via the gas release valve 948.

In some examples, the gas 208 is vented out of the second reservoir 930 via the gas release valve 948 as shown in Figure 4. The gas release valve 948 can optionally be connected to a gas vent line (not shown) and the gas can be captured by a surface vessel. Alternatively, the gas 208 can be vented directly into the sea.

Once the gas 208 has been vented, the displacement fluid 932 can be inserted into the subsea well 100. In Figure 5, the submersible 900 begins to insert the displacement fluid 932 into the subsea well 100 from the first reservoir 928 as shown in step 1002 in Figure 10. Since the displacement fluid 932 is heavier than the drilling fluid 200, the displacement fluid 932 flows underneath the drilling fluid 200.

In some examples, the displacement fluid 932 is optionally inserted by the pump 920 in a smooth manner in order to reduce the turbulence in the displacement fluid 932, Accordingly, the displacement fluid 932 comprises a laminar flow when the displacement fluid 932 is inserted into the subsea well 100. By ensuring that the displacement fluid 932 undergoes laminar flow, the amount that the displacement fluid 932 mixes with the drilling fluid 200 will be limited or completely prevented and flow underneath the waste drilling fluid 200. If the displacement fluid 932 does not undergo laminar flow, then the submersible 900 may have to wait for the displacement fluid 932 to settle and move to the bottom of the upper portion 122 of the subsea well 100.

The displacement fluid 932 flows through the first set of perforations 400 and up though the void 206 between the casing string 106 and the conductor pipe 104. This means that the level of the drilling fluid 200 rises up in the subsea well 100 and the displacement fluid 932 displaces the drilling fluid 200 as shown in step 1004 in Figure 10.

In some examples, the controller 906 optionally issues a control instruction to the pump module 918 to actuate the pump 920. The pump 920 pumps the displacement fluid 932 out of the first reservoir 928 and through the fluid insertion pipe 938 into the subsea well 100. In some less preferred examples, the submersible 900 does not have a pump and the flow of the displacement fluid 932 into the subsea well 100 is due to the hydrostatic pressure of the displacement fluid 932.

As the displacement fluid 932 starts to fill up the upper portion 122 of the subsea well 100, the drilling fluid 200 is forced into the drilling fluid inlet 950 and the waste drilling fluid 200 flows through the drilling fluid conduit 944 into the second reservoir 930. Accordingly, the drilling fluid 200 is transferred into the second reservoir 930 as shown in step 1006 in Figure 10.

As the displacement fluid 932 empties from the first reservoir 928 and the drilling fluid 200 fills the second reservoir 930, the moveable barrier 934 moves in a direction towards the fluid insertion pipe 938 as shown in Figure 6. Figure 6 shows the transfer of the drilling fluid 200 to the submersible 900 part way through.

As the drilling fluid 200 is transferred to the submersible 900, some seawater can be captured between the drilling fluid 200 and the displacement fluid 932. A first portion 600 of seawater adjacent to the fluid insertion pipe 938 will be overpressured due to the pumped displacement fluid 932 urging the first portion 600 of seawater against the sealing rings 940. A second portion 602 of seawater between the waste drilling fluid 200 and the displacement fluid 932 will be underpressured. The presence of the first portion 600 of overpressurised seawater and the second portion 602 of under pressurised seawater respectively either side of the sealing rings 940 advantageously improves the seal against the inner surface 202.

In Figure 7 all of the drilling fluid 200 has been transferred from the subsea well 100 to the second reservoir 930. The pump 920 has stopped and the drilling fluid valve 946 is closed. The submersible 900 can then be detached from the subsea well 100. As the submersible 900 rises to the surface, the equalising pressure valve 916 is opened to depressurise the tank 922. In some examples, a portion of the displacement fluid 932 can be left in the first reservoir 928 when the submersible 900 rises to the surface and the equalising pressure valve 916 is opened so that no drilling fluid 200 is expelled into the marine environment. Furthermore, the equalising pressure valve 916 is open so that advantageously there is no pressurised fluid (or only low pressurised fluid) in the tank 922 once the submersible 900 is back on surface. This improves the tank 922 integrity and ensures that the hull body 902 does not burst, deform, or is damaged in any other way.

Figure 8 shows the displacement fluid 932 in the subsea well 100 after the submersible 900 has been removed. The displacement fluid 932 will settle over the plugs 118, 120.

The drilling fluid 200 can then be processed and removed remote from the subsea well 100 without contaminating the marine environment.

In another example, two or more examples are combined. Features of one example can be combined with features of other examples.

Examples of the present disclosure have been discussed with particular reference to the examples illustrated. However it will be appreciated that variations and modifications may be made to the examples described within the scope of the disclosure.