Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
  • E21B41/0007—Equipment or details not covered by groups E21B15/00 - E21B40/00 for underwater installations
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B33/00—Sealing or packing boreholes or wells
  • E21B33/02—Surface sealing or packing
  • E21B33/03—Well heads; Setting-up thereof
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B37/00—Methods or apparatus for cleaning boreholes or wells
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
  • E21B41/0099—Equipment or details not covered by groups E21B15/00 - E21B40/00 specially adapted for drilling for or production of natural hydrate or clathrate gas reservoirs; Drilling through or monitoring of formations containing gas hydrates or clathrates
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/34—Arrangements for separating materials produced by the well
  • E21B43/36—Underwater separating arrangements

Definitions

• the present invention relates to hydrate removal in subsea equipment used in the technical field of oil and gas production and transport.
• Removal of hydrates at subsea locations can be expensive, since heavy equipment may be needed to facilitate the operation, such as surface vessels, ROV’s (remotely operated vehicles), subsea cranes and winches, etc. Moreover, for some suggested solutions, the hydrate-removing equipment itself may also be expensive.
• publication US9797223B1 relates to hydrate removal at a subsea location.
• vacuum is communicated to the subsea equipment from a pressure port of a pressure modulator.
• a topside vessel is connected to and operates a subsea skid that provides the vacuum.
• the subsea skid has a storage tank into which the dissolved hydrate flows.
• a hydraulic piston is moved to provide the vacuum.
• An object of the present invention may be to provide an alternative solution for dissolving hydrates in subsea equipment.
• such an alternative solution may be less costly during use.
• the equipment needed for such an alternative solution may also be less costly in itself.
• a further object of the invention may be to provide a solution for dissolving hydrates in subsea equipment that is less complex.
• a subsea hydrate removal assembly configured for removal of hydrate inside subsea equipment.
• the subsea hydrate removal assembly comprises, at a subsea location, a tank, wherein the pressure inside the tank is lower than the pressure at the location of the hydrate inside the subsea equipment.
• the assembly further comprises a fluid jumper comprising a wet-mate connection at a first end or at a second end, or at a first end and at a second end.
• the fluid jumper constitutes at least a part of a fluid path that connects the tank and said subsea equipment. Thereby fluid communication between the inside of the tank and the hydrate inside the subsea equipment is enabled.
• the subsea hydrate removal assembly is autonomous.
• the subsea hydrate removal assembly is autonomous is meant that the assembly operates, i.e. dissolves hydrate in the subsea equipment, without any physical line to the surface.
• a vessel or other surface installation does not need to be present to operate the assembly during hydrate dissolution.
• a surface vessel can be used to install the assembly and possibly to initiate the dissolution process, and then disconnect and leave the location.
• a vessel can return to retrieve the tank and possibly install a new tank to continue to the hydrate dissolution process.
• the said fluid path constituted at least partly by the fluid jumper, connects the interior of the tank to a fluid interface, typically a part of a wet-mate connector, of the subsea equipment. From the fluid interface of the subsea equipment, there will be further fluid communication with the location inside the subsea equipment where the hydrate exists. By connecting the tank, having low pressure, to the hydrate formation inside the subsea equipment, the pressure at the hydrate location is reduced and hydrate will dissolve.
• the assembly can be pump-less.
• the assembly can be pump-less, it is meant that it operates, i.e. it dissolves hydrates inside the subsea equipment without running a pump or other equivalent powered device that is run to provide the pressure that is sufficiently low to dissolve the hydrate.
• This differs from prior art, wherein one typically will provide a vacuum, or reduced pressure, by operating a subsea pump run from the surface.
• the fluid path can be a branch-less fluid path.
• branch-less fluid path is meant that there is only a single fluid communication path between the interior of the tank and the subsea equipment. It shall be understood that more than one fluid paths may be arranged. For instance, in some embodiments, one may arrange more than one tank, wherein the respective tanks are each connected to the subsea equipment with a dedicated fluid jumper. Alternatively, one may connect a plurality of tanks in series.
• the fluid path can be continuous.
• the fluid path is continuous is meant that there are no pressure- reducing means between the interior of the tank and the subsea equipment, in particular between the interior of the tank and the fluid interface of the subsea equipment.
• the tank can comprise a plurality of sub tanks comprising sub-volumes that are interconnected to form a total tank-volume. Such a configuration enables a tank having a large volume while still having the capability of withstanding large external pressures.
• the sub-tanks can be in the form of parallel oriented pipe lengths that are fixated at respective pipe ends at respective end plates.
• the said pipe lengths can in some embodiments have been cut from one or more tubular parts.
• the tubular parts can be cut from riser pipes.
• the assembly can comprise a plurality of interconnected tanks, wherein there is fluid communication between the interiors of the interconnected tanks.
• the said tanks can then be configured in series.
• one intermediate tank will have fluid connection to two adjacent tanks, while the two other tanks only connect to the intermediate tank.
• the assembly can have a plurality of tanks, wherein the tanks are connected in parallel.
• respective tanks can connect directly to a dedicated equipment part of a second wet-mate connection, i.e. to a dedicated connection point on the subsea equipment. In other embodiments, the tanks can connect to a common connection point.
• An advantage of having dedicated connections between the respective tanks and the subsea equipment is that one reduces the drawbacks of having one fluid path, e.g. the fluid jumper, blocked.
• the assembly may in some embodiments comprise two fluid jumpers connected to one or more tanks, wherein the respective fluid jumper is connected to a respective side of the hydrate formation inside the subsea equipment.
• the hydrate inside the subsea equipment can be dissolved from opposite sides and thus faster.
• a method of removing hydrate from a subsea equipment with a subsea hydrate removal assembly comprising a tank and a fluid jumper, wherein the method comprises the following steps: a) providing, at a surface location, the tank, and the fluid jumper, wherein the fluid jumper comprises a wet-mate connection at a first end or at a second end, or at a first end and a second end; b) with a surface structure, lowering the tank to the seabed; c) with the fluid jumper, connecting the tank to the subsea equipment; d) opening a valve to provide fluid communication between the interior of the tank and the interior of the subsea equipment, thereby lowering the pressure at the location of said hydrate and dissolving the hydrate.
• the method may further comprise e) after step d), removing all physical connections between the surface structure and the subsea hydrate removal assembly.
• the method according to the second aspect of the invention may include f) after step d), disconnecting the fluid jumper from the tank, and then; g) connecting the fluid jumper to an additional tank and repeating step d).
• steps a) and b) can comprise providing two or more tanks that are interconnected, and with the surface structure lowering the two or more tanks to the seabed.
• Step a) can in some embodiments comprise providing a tank made up of a plurality of sub tanks that are interconnected with fluid communication.
• a hydrate dissolving tank configured to withstand an external pressure that is at least 20 bar above its internal pressure.
• the hydrate dissolving tank comprises a plurality of sub tanks that are fluidly interconnected with a fluid distribution arrangement.
• the sub tanks can be in the form of pipe lengths that are connected between a first end plate and a second end plate.
• Fig. 1 depicts a schematic view of a piece of subsea equipment installed on the seabed, while a surface vessel is positioned at the surface for installing a subsea hydrate removal assembly
• Fig. 2 depicts the subsea hydrate removal assembly after installation and after the surface vessel has left its surface position;
• Fig. 3 depicts a plurality of interconnected hydrate dissolving tanks connected in series
• Fig. 1 is a schematic view of a piece of subsea equipment used for hydrocarbon production, such as a subsea Xmas tree 1 arranged at the seabed 3.
• the Xmas tree 1 connects to a hydrocarbon pipeline 5 extending to for instance a manifold (not shown).
• hydrocarbons will flow through the Xmas tree 1 from a production zone in a subsea well (not shown). Flydrates may form inside the Xmas tree 1 when produced water is present in the flow from the well and if the temperature is low and the pressure is high. This can typically occur if the flow of hydrocarbons is halted.
• a surface vessel 7 is arranged at the sea surface 9.
• the task of the surface vessel 7 is to install a subsea hydrate removal assembly 50, for removal of the hydrate from the Xmas tree 1 at the seabed. Only some parts of the subsea hydrate removal assembly 50 is shown in Fig. 1 , while a complete subsea hydrate removal assembly 50 is depicted in Fig. 2.
• the Xmas tree 1 is arranged at a sea depth of at least 200, or at least 400 or 500 meters.
• a hydrate dissolving tank 10 hereinafter termed a tank, which is lowered down, on a wire 13 from the surface vessel 7, onto the seabed 3.
• the tank 10 is installed adjacent to the subsea equipment, i.e. the Xmas tree
• HCR tanks high collapse resistance
• Fig. 1 further depicts a remotely operated vehicle (ROV) 11 that may facilitate installation of the tank 10, inter alia.
• ROV remotely operated vehicle
• Fig. 2 is a schematic illustration depicting many of the same components as were shown in Fig. 1. Flowever, the surface vessel 7 is not present at the sea surface.
• the tank 10 is connected to the Xmas tree 1 with a fluid jumper, in the present embodiment in the form of a so-called FICR jumper 15.
• a fluid jumper in the present embodiment in the form of a so-called FICR jumper 15.
• the connection of the FICR jumper 15 to the FICR tank 10 and to the Xmas tree 1 can advantageously be made with assistance from the ROV 11 shown in Fig. 1.
• the tank 10 comprises a tank connection part 17a of a first wet-mate connection 17.
• the Xmas tree 1 has an equipment part 19a of a second wet-mate connection 19.
• the FICR jumper 15 comprises a first jumper part 17b of the first wet-mate connection 17.
• the FICR jumper 15 also comprises a second jumper part 19b of the second wet-mate connection 19.
• the FICR jumper 15 is thus configured to connect to the tank 10 and to the Xmas tree 1 with the first and second wet-mate connections 17, 19.
• the Xmas tree 1 comprises a hydrate valve 12, which is in fluid communication with the equipment part 19a of the second wet-mate connector 19.
• the hydrate valve 12 of the Xmas tree 1 is in form of a pressure isolation valve.
• the tank 10 comprises a hydrate valve 14 that is in fluid communication with the tank connection part 17a of the first wet-mate connector 17.
• the hydrate valve 14 of the tank 10 can also be in the form of a pressure isolation valve, i.e. a valve that is configured to withstand typical pressures that can be present inside subsea equipment as Xmas trees and the like.
• the fluid jumper or FICR jumper 15, can connect the interior of the tank 10 with the Xmas tree 1 , when the tank 10 has landed at the seabed 3.
• the equipment part 19a of the second wet-mate connector 19 constitutes a subsea equipment fluid interface. There will be fluid communication between the subsea equipment fluid interface and the hydrate that exists inside the subsea equipment (i.e. the Xmas tree 1 in the present embodiment).
• the fluid jumper, or HCR jumper 15 in the present embodiment constitutes at least a part of a fluid path between the interior of the tank 10, and the subsea equipment fluid interface (i.e. the equipment part 19a of the second wet-mate connector 19). As is shown in Fig. 2, this fluid path is branch-less in this embodiment. I.e. there is only one route or path between the interior of the tank 10 and the subsea equipment fluid interface, which is represented by the equipment part 19a of the second wet-mate connector 19.
• the fluid jumper 15 could be connected to the tank 10 at the surface before lowering the tank 10 in the sea.
• the fluid jumper 15 would then need only one wet-mate connector, for connection to the subsea equipment.
• the first jumper part 17b and the second jumper part 19b of the first and second wet-mate connectors 17, 19, located at the respective ends of the HCR jumper 15, can advantageously be in the form of hot-stabs, which are suited for operation with the ROV 11.
• the fluid jumper (HCR jumper) 15 could be connected to either the tank 10 or to the Xmas tree 1 at a surface location, hence enabling an embodiment having only one wet-mate connector.
• the two hydrate valves 12, 14, such as with the ROV 11 the volume inside the tank 10 can be communicated with the volume inside the subsea equipment, i.e. the Xmas tree 1 in the present embodiment. It will be understood that, depending on what type of component the subsea equipment is, it may be necessary to open even further valves to provide said fluid communication.
• the low pressure inside the tank 10 will thus be communicated with the hydrate inside the Xmas tree 1. Due to the lowering of the pressure, the hydrate will start to dissolve into gas and water, which will flow into the tank 10. This process will proceed as long as the pressure inside the tank 10 is sufficiently low. After some time, the amount of dissolved gas and water will increase the pressure inside the tank. If the pressure inside the tank becomes too high while non-dissolved hydrate still is present inside the subsea equipment, the process will eventually stop.
• the tank 10 does not need any connection to the surface during this process.
• the surface vessel 7 shown in Fig. 1 needs only to be present when installing the tank 10, and when retrieving the tank 10. This is advantageous because the hydrate removal may take significant time, and offshore vessels are costly to operate.
• the tank 10 has an inner volume that is insufficient for dissolving all of the hydrate inside the subsea equipment, it can be replaced with another tank. Of course, one may also retrieve the tank 10 to surface, empty it, and then lower it back down for further dissolution of the hydrate.
• the two or more tanks 10 can be interconnected, while one tank 10 can connect to the subsea equipment.
• Fig. 3 Such a configuration is shown in Fig. 3, where three tanks 10 are connected in series, while one of the tanks can connect to the subsea equipment (not shown in Fig. 3).
• the tank 10 may be connected to a battery driven pre set vacuum pump (not shown) that could restore vacuum when the pressure threshold is reached. For instance, if it is required to have an absolute pressure below 10 bar to dissolve the hydrate, the vacuum pump may start when the pressure reaches 10 bar and restore an absolute pressure of about 1 bar.
• a tank filling level sensor connected to the tank 10 to ensure that the pump does not start when the fluid level inside the tank 10 is above a threshold.
• the tank 10 can comprise a pressure transmitter and/or pressure gauge to enable pressure monitoring of the pressure inside the tank. With such means, the pressure inside the tank 10 can be monitored both when the tank is located subsea and when the tank 10 has been recovered back to surface.
• Such pressure monitoring can be with visual indicators (observed by ROV) and/or, via subsea mounted data logger and/or via signal transmission to a device on surface in vicinity of the well.
• the tank 10 must not only be designed for high external pressure. It must also withstand high internal pressure that can occur when the tank has been recovered back to surface.
• the hydrate valve 14 of the tank 10 will be closed before the HCR jumper 15 is removed to prevent potential spill of hydrocarbons to the environment during retrieval of the tank 10.
• Fig. 4 shows a perspective view of a tank 10 that is suited for being used when removing hydrate in the manner discussed above.
• the tank 10 comprises a plurality of sub tanks, which in the shown embodiment are in the form of pipe lengths 101.
• the pipe lengths 101 are fixed between a first end plate 103 and an oppositely arranged second end plate 105.
• a flange arrangement 107 which connects a lifting interface 109 to the first end plate 103.
• the lifting interface 109 can typically be connected to the wire 13 mentioned above (cf. Fig. 1).
• the tank 10 further comprises a fluid distribution arrangement 111.
• the purpose of the fluid distribution arrangement 111 is to fluidly connect the sub tanks to each other, such that the volume of the tank 10 comprises the volume of all the sub tanks 101.
• the fluid distribution arrangement 111 comprises a plurality of fluid sub connections 113 that each fluidly connect to the respective sub tanks 101.
• the fluid sub connections 113 are interconnected with a collector pipe 115.
• Fig. 5 shows an embodiment that is similar to the embodiment shown in Fig. 2.
• two fluid jumpers 15 connect to the subsea equipment 1 at two locations, i.e. at two equipment parts 19a of second wet-mate connections 19.
• the possibility to do this will depend on the configuration of the subsea equipment. I.e., it must be possible to provide fluid communication to respective sides of the hydrate formation.

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• Life Sciences & Earth Sciences (AREA)
• Engineering & Computer Science (AREA)
• Geology (AREA)
• Mining & Mineral Resources (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Environmental & Geological Engineering (AREA)
• Fluid Mechanics (AREA)
• Physics & Mathematics (AREA)
• Geochemistry & Mineralogy (AREA)
• Chemical & Material Sciences (AREA)
• Materials Engineering (AREA)
• Organic Chemistry (AREA)
• Lubricants (AREA)
• Filling Or Discharging Of Gas Storage Vessels (AREA)
• Cleaning In General (AREA)

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• 2021
  • 2021-05-05 NO NO20210561A patent/NO346842B1/en unknown
• 2022
  • 2022-05-02 WO PCT/NO2022/050099 patent/WO2022235165A1/en not_active Ceased
  • 2022-05-02 BR BR112023022909A patent/BR112023022909A2/pt unknown
  • 2022-05-02 EP EP22799191.6A patent/EP4334569A4/de active Pending

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