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
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
  • E21B43/121—Lifting well fluids
• • 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
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
  • E21B43/121—Lifting well fluids
  • E21B43/122—Gas lift

Definitions

• This relates to apparatus, systems and methods for use in remediation operations in the oil and/or gas industry.
• a well borehole (“wellbore”) is drilled from surface, the wellbore typically then being lined with sections of metal bore-lining tubing, commonly known as casing, which is cemented in place.
• the wellbore is then completed by installation of production equipment which facilitates the controlled ingress and transportation of production fluid, e.g. oil and/or gas, from the reservoir towards surface.
• control over fluid ingress into a wellbore is critical to its safe and efficient formation and operation and there are a number of instances during the life of a given wellbore that is desirable to prevent ingress of production fluid into the wellbore.
• operators will pump fluid (commonly known as well kill fluid) into the wellbore - more particularly into the production tubing - the density of the fluid selected so that the fluid column exerts a fluid pressure which prevents the flow of production fluids from the reservoir into the wellbore during the workover operations.
• fluid commonly known as well kill fluid
• operators may pump fluid (drilling fluid, drilling mud or the like) into the wellbore, the density of the fluid being selected so that the fluid column in the wellbore exerts a fluid pressure which prevents the flow of production fluids from the reservoir into the wellbore during the drilling process.
• fluid drilling fluid, drilling mud or the like
• One technique for this involves pumping a gas, e.g. nitrogen, into the fluid column to reduce its density and thus the hydrostatic pressure exerted on the production fluid to the point where the reservoir pressure is sufficient to urge the production fluid towards surface.
• a gas e.g. nitrogen
• coiled tubing is used successfully and extensively in many intervention operations, there is a desire to move to smaller bore tubing and associated equipment which amongst other things occupies a smaller footprint and involves reduced costs than coiled tubing.
• coiled tubing and small bore tubing have limited capacity to deliver the required volumes and flow rates to displace larger volumes of fluid, restricting the ability to perform artificial lift operations in such situations.
• One well stimulation operation involves pumping acid into the formation to improve production fluid flow and/or remove damage around the wellbore.
• acidizing operation involves pumping acid into the formation to improve production fluid flow and/or remove damage around the wellbore.
• acids are used in different applications. For example, in sandstone matrix acidizing applications, hydrofluoric acid may be used.
• hydrofluoric acid when hydrofluoric acid was initially used in well intervention operations, it was prepared by mixing ammonium bifluoride powder with acids such as hydrochloric acid , or formic acid, for example in a batch mixer in the platform operations area of the installation, e.g. platform.
• acids such as hydrochloric acid , or formic acid
• operatives would instead opt to mix aqueous solutions of ammonium fluoride and hydrochloric acid in the temporary surface pipework on the installation to create the required volume of hydrofluoric acid.
• hydrofluoric acid has a flash point in the range 94 to 100 °C.
• Concentrated solutions of hydrofluoric acid have a much lower flash point and also have the potential to produce a highly toxic gas.
• the use of chemical products, such as but not exclusively hydrofluoric acid also present challenges to well containment systems and methodologies.
• conventional containment systems are designed so that in the event of an over- pressurisation event, the pressure relief valve (PRV) at surface redirects the chemical product into a waste tank.
• PRV pressure relief valve
• the volume of chemical product to be diverted may be significant, such that the process of diverting the chemical product involves significant time and cost for the operator.
• aspects of the present disclosure relate to apparatus, systems and methods for use in remediation operations in the oil and/or gas industry. Some aspects relate to an apparatus and method for use in an artificial lift operation in an oil and/or gas wellbore. Other aspects relate to a subsea apparatus, and method for producing a chemical product suitable for use in a well intervention operation, and to a subsea assembly, chemical injection system and subsea system comprising the apparatus.
• an apparatus for use in an artificial lift operation in an oil and/or gas wellbore comprising: a tubular conveyance suitable for conveying an artificial lift fluid into a fluid column in the wellbore; a plunger member configured to partially obturate the wellbore; and a fluid communication passage configured to permit passage of the artificial lift fluid through and/or around the plunger member, wherein the pressure force acting on the area of the fluid column exposed to the fluid communication passage prevents the passage of the fluid column around and/or though the plunger as the plunger is moved towards surface, such that the plunger member displaces the fluid column towards surface on movement of the plunger member towards surface.
• the apparatus is configured to be run into a wellbore having a fluid column, the apparatus operable to displace a fluid column disposed in the wellbore.
• Artificial lift fluid for example but not exclusively a gas and more particularly Nitrogen gas, may be pumped or otherwise directed through the conveyance and into the fluid column, the artificial lift fluid reducing the density of the fluid column and reducing the pressure force required to displace the fluid column towards surface.
• the plunger member partially obturates the bore of the wellbore, while the fluid communication passage is configured to permit passage of the artificial lift fluid through and/or around the plunger member, the pressure force acting on the area of the fluid column exposed to the fluid communication passage preventing the passage of the fluid column around and/or through the plunger member as the plunger member is moved towards surface, such that the plunger member displaces all or substantially all of the fluid column towards surface on movement of the plunger member towards surface.
• the apparatus may be disposed above a set packer, plug or other wellbore restriction which otherwise prevents reservoir fluid pressure acting on the fluid column, and which thereby prevents the use of conventional artificial lift equipment and techniques to remove the fluid column.
• the apparatus permits an artificial lift operation to remove a fluid column disposed in a wellbore to be carried out by movement of the plunger member towards surface, without the reliance on the reservoir pressure overcoming the hydrostatic pressure of the fluid column.
• the apparatus facilitates displacement of a fluid column disposed in a wellbore by movement of the plunger member towards surface, this being provided in additional to reservoir pressure.
• the apparatus is applicable to situations where the reservoir pressure is not available (such as described above) but also to situations where the reservoir pressure is available; in such situations the apparatus assisting and/or supplementing the available reservoir pressure.
• the apparatus enhances the use of coiled tubing or smaller bore tubing to perform artificial lift operations in applications where greater volumes of fluid are to be displaced.
• the apparatus may be configured to increase the velocity of the fluid to be displaced.
• the apparatus comprises a tubular conveyance suitable for conveying an artificial lift fluid into a fluid column in the wellbore.
• the conveyance may take a number of different forms.
• the conveyance may comprise or take the form of coiled tubing.
• the conveyance comprises or takes the form of a coiled hose.
• the apparatus facilitates an artificial lift operation to displace a fluid column from the wellbore to be carried out using coiled tubing or coiled hose, without the reliance on the reservoir pressure.
• the volume of artificial lift fluid that can be supplied by coiled tubing is effective at conveying fluid to apply sufficient pressure to displace a fluid column when assisted by the reservoir pressure
• the apparatus facilitates the use of coiled tubing or smaller bore tubing such as coiled hose which otherwise have insufficient flow capacity to displace sufficiently great volumes of fluid without the assistance from the reservoir pressure.
• the apparatus comprises a plunger member configured to partially obturate the wellbore.
• the plunger member may substantially obturate the wellbore.
• the plunger member may comprise or take the form of a packer comprising one or more packing elements.
• the apparatus may be configurable between a first configuration in which the plunger member defines a radially retracted configuration and second configuration in which the plunger member defines a radially extended configuration.
• the apparatus may be configured to be run into the wellbore with the apparatus in the first, radially retracted, configuration and reconfigured to the second, radially extended, configuration to partially obturate the bore of the wellbore.
• the packer may comprise or take the form of one or more inflatable packing elements.
• the one or more inflatable packing elements may be inflated by a portion of the artificial lift fluid supplied by the tubular conveyance.
• the apparatus may comprise a valve arrangement operatively associated with the plunger member, the valve arrangement controlling access to the packing element.
• the packer may comprise or take the form of one or more expandable packing element.
• the apparatus may comprise a lock arrangement.
• the lock arrangement may be configured to retain the apparatus in the first configuration in which the plunger member defines the first, retracted, configuration.
• the lock arrangement may be configured to retain the apparatus in the second, extended, configuration in which the plunger member defines the second, extended, configuration.
• the plunger member may comprise a unitary construction.
• the plunger member may comprise a plurality of components.
• the plunger member may comprise a plurality of axial segments.
• the packing element may comprise a plurality of circumferential segments.
• the provision of a plurality of axial and/or circumferential segments facilitates the movement of the packing element through restrictions in the wellbore, without damaging the apparatus and/or the wellbore.
• the plunger member may be disposed on the tubular conveyance.
• the plunger member may be configured to form part of the tubular conveyance.
• the plunger member may be configured to form part of a tool string coupled to or forming part of the tubular conveyance.
• the plunger member may be disposed around the tubular conveyance.
• the plunger member may be annular.
• the plunger member may be configured to be fixed to the conveyance such that the plunger member is withdrawn by withdrawing the conveyance.
• the plunger member may be configured to move axially relative to the conveyance.
• the apparatus comprises a flow communication passage configured to permit passage of the artificial lift fluid through and/or around the plunger member.
• the fluid communication passage may be annular.
• the fluid communication passage may be defined between the plunger member and the wall of the wellbore.
• the fluid communication passage may be defined between the plunger member and the outer surface of the tubular conveyance.
• the fluid communication passage may comprise or take the form of one or more bore through the plunger member.
• the tubular conveyance is configured to convey an artificial lift fluid into the fluid column.
• the artificial lift fluid is selected to have a lower density than the fluid column.
• the artificial lift fluid takes the form of a gas.
• the artificial lift fluid takes the form of Nitrogen gas.
• the gas may be pumped or otherwise directed into the wellbore via the tubular conveyance and may pass into the fluid column disposed in the wellbore, the gas forming bubbles in the fluid column which, due to the lower density of the gas relative to the fluid column, pass through the fluid column in an uphole direction.
• the gas reduces the density of the fluid column, reducing the force required to displace the fluid column.
• the artificial lift fluid may comprise or take the form of a liquid having a lower density than the fluid column.
• the apparatus may be configured to perform a well stimulation operation.
• the apparatus may comprise, may be coupled to or operatively associated with a well stimulation tool.
• a method for displacing a fluid column from a wellbore using the apparatus of the first aspect.
• the method may comprise performing a well stimulation treatment.
• the well stimulation treatment may be performed before the artificial lift operation.
• the well stimulation treatment may be performed immediately before the artificial lift operation. Beneficially, this facilitates reduces operational time and costs.
• the or a stimulation treatment may be performed after the artificial lift operation.
• a subsea apparatus for use in producing a chemical product suitable for use in a well intervention operation, the apparatus comprising: a mixing device located at a subsea location, comprising: a first inlet for communicating with a first reactant supply; a second inlet for communicating with a second reactant supply; a contact chamber configured to receive the first reactant from the first inlet and the second reactant from the second inlet, and to permit the first reactant and the second reactant to contact and react to form a chemical product suitable for use in a well intervention operation; and an outlet configured to receive the chemical product from the contact chamber and direct the chemical product from the mixing device.
• the apparatus provides a number of benefits over conventional techniques and equipment.
• hydrofluoric acid which is colourless, highly toxic and has calcium leaching properties, can cause painful burns, and may lead to cardiac arrest and fatality in extreme cases, with those seeking to provide first aid also at risk of exposure.
• the present apparatus obviates or at least significantly reduces the requirement to produce the chemical product at surface, such that the risk of exposure to personnel is reduced or eliminated. Producing the chemical product at a subsea location also reduces the risk of fire and/or the release of toxic gas at surface due to the relatively low flash point of some chemical products used for well intervention operations.
• the present apparatus facilitates the mixing of the reactants to be carried out subsea, such that the conduits and infrastructure involved in transporting the first and second reactants from the installation, e.g. platform or vessel, are not exposed to the chemical product itself.
• the present apparatus reduces the chemical resistance requirements of the conduits and infrastructure involved in transporting the first and second reactants from the installation.
• the present apparatus provides the ability to greatly reduce the volume of the chemical product that would be required to be purged, handled, stored and/or disposed of in the event of an emergency or other situation where the supply of the chemical product must be disconnected.
• conventional containment systems are designed so that in the event of an over-pressurisation event, the pressure relief valve (PRV) at surface redirects the chemical product into a waste tank, requiring significant storage, handling and transportation of the diverted chemical product.
• PRV pressure relief valve
• the volume of the chemical product to be diverted is significant, such that the process of diverting the chemical product involves significant time and cost for the operator.
• the present apparatus obviates or at least significantly reduces the requirement to purge, handle and/or dispose of the volume of aggressive chemical product in the full conduit length from topside to the point of disconnect, and may reduce or eliminate the requirement for specialised intervention vessels, which typically have limited availability, and permitting more use of vessels of opportunity, thus reducing cost and providing increased responsiveness for the operator.
• the mixing device may take a number of different forms.
• the mixing device may take the form of a unitary construction.
• the mixing device may comprise a modular construction.
• one or more of the first inlet, second inlet, contact chamber and/or outlet may take the form of a separate component configured for coupling to at least one other of the first inlet, second inlet, contact chamber and/or outlet.
• the mixing device may comprise or take the form of a connector.
• the mixing device may comprise or take the form of a t-piece connector.
• the mixing device may comprise or take the form of a y-piece connector.
• the mixing device may comprise or take the form of an eductor.
• the apparatus may comprise, may be configured for coupling to, or may be operatively associated with a disconnect module suitable for selectively de-coupling the mixing device from the well.
• the disconnect module may comprise or take the form of a quick disconnect device. More particularly, but not exclusively, the disconnect module may comprise or the take the form of an emergency quick disconnect (EQD) module.
• the disconnect module and the mixing device may form an assembly for location subsea together.
• the mixing device may be disposed on the disconnect module.
• disconnect module and the mixing device may be configured for deployment subsea separately and connected together at a subsea location.
• this facilitates retrofitting the apparatus to existing disconnect modules, further reducing the amount of infrastructure to be deployed, retrieved and/or purged after a given operation.
• the mixing device may be configured for coupling to the disconnect module.
• the mixing device may be configured for directly coupling to the disconnect module.
• the mixing device may be configured for coupling to the disconnect module via a conduit, such as a flow line, jumper or the like.
• the apparatus reduces the volume of the chemical product that would be required to be purged, handled and stored in the event of an emergency or other situation where the supply of the chemical product must be disconnected, since the volume of the chemical product at the point of disconnect is restricted to that present in the mixing device, the disconnect module and, where applicable, the conduit coupling the mixing device and the disconnect module.
• the mixing point is just upstream of the disconnect module, thus minimising the volume of the chemical at risk of being released, greatly reducing the risk of negatively impacting the surrounding environment.
• the apparatus may be coupled to, or may be operatively associated with a shutdown module. More particularly, but not exclusively, the shutdown module may comprise or the take the form of an emergency shutdown (ESD) module.
• the apparatus comprises a mixing device comprising a first inlet for communicating with a first reactant supply and a second inlet for communicating with a second reactant supply.
• the first reactant may take the form of a fluid.
• the first reactant may take the form of a liquid.
• the first reactant may take the form of ammonium fluoride.
• the first reactant may take the form of a gas.
• the second reactant may take the form of a fluid.
• the second reactant may take the form of a liquid.
• the second reactant may take the form of an acid. Any suitable acid may be used.
• the second reactant may take the form of hydrochloric acid.
• the second reactant may take the form of formic acid.
• the apparatus may comprise a fluid conduit (“first subsea fluid conduit”) for supplying the first reactant to the first inlet.
• the first subsea fluid conduit may be configured for location on a reel.
• the apparatus may comprise a fluid conduit (“second subsea fluid conduit”) for supplying the second reactant to the second inlet of the mixing device.
• the second subsea fluid conduit may be configured for location on a reel, which may be the same reel as described above with respect to the first subsea fluid conduit.
• a subsea assembly comprising the apparatus of the third aspect
• the assembly may comprise or take the form of a subsea module for deployment subsea.
• the assembly may comprise or may be mounted on a skid for deployment subsea together.
• the assembly may comprise or may be operatively associated with a disconnect module, such as the disconnect module described above.
• the assembly may comprise or may be operatively associated with a shutdown module, such as the shutdown module described above.
• a chemical injection system comprising the apparatus of the third aspect or the assembly of the fourth aspect.
• the chemical injection system may comprise, may be coupled to, or may be operatively associated with a shutdown module. More particularly, but not exclusively, the shutdown module may comprise or the take the form of an emergency shutdown (ESD) module.
• ESD emergency shutdown
• the chemical injection system may comprise, may be configured for coupling to, or may be operatively associated with a disconnect module suitable for selectively de-coupling the mixing device from the well.
• the disconnect module may comprise or take the form of a quick disconnect device. More particularly, but not exclusively, the disconnect module may comprise or the take the form of an emergency quick disconnect (EQD) module.
• EQD emergency quick disconnect
• the chemical injection system may comprise, may be coupled to, or may be operatively associated with an injection module. More particularly, but not exclusively, the injection module may comprise or take the form of a subsea injection manifold.
• At least part of the chemical injection system may be located at surface, e.g. on a surface installation such as a vessel, platform or the like.
• the first reactant supply may comprise or take the form of one or more tank.
• the first reactant supply may be disposed at surface.
• the second reactant supply may comprise or take the form of one or more tank.
• the second reactant supply may be disposed at surface, e.g. on the surface vessel.
• the chemical injection system may comprise one or more pump (“first pump”) for directing the first reactant to the first inlet of the mixing device.
• the first pump may be disposed at surface, e.g. on the surface installation.
• the chemical injection system may comprise a fluid conduit system (“first surface fluid conduit system) for communicating the first reactant to the first pump and/or the first subsea fluid conduit.
• the chemical injection system may comprise one or more pump (“second pump”) for directing the second reactant to the second inlet of the mixing device.
• the second pump may be disposed at surface, e.g. on the surface installation.
• the chemical injection system may comprise a fluid conduit system (“second surface fluid conduit system) for communicating the second reactant to the second pump and/or the second subsea fluid conduit.
• second surface fluid conduit system for communicating the second reactant to the second pump and/or the second subsea fluid conduit.
• the first reactant e.g. ammonium fluoride
• the second reactant e.g. hydrochloric acid
• the first pump and the second pump are exposed only to the first and second reactants respectively and are not exposed to the chemical product for injection.
• the first and second pumps may be configured to direct the first and second reactants at different flow rates.
• the first pump may be configured to direct the first reactant, e.g. ammonium fluoride, at 1 Barrel per minute and the second pump may be configured to direct second reactant, e.g. hydrchloric acid, at 6 Barrels per minute.
• the flowrates may be varied as required.
• the properties of the chemical product to be injected may be controlled.
• the concentration of the chemical product to be injected may be varied. The variation of flow rates ensure an efficient mixing process at the point where the reactants meet.
• the chemical injection system may comprise or may be coupled to one or more waste tank.
• the waste tank may be located at surface, e.g. on the surface installation.
• the chemical injection system may comprise or may be coupled to one or more waste tank for the first reactant.
• the chemical injection system may comprise or may be coupled to one or more waste tank for the second reactant.
• the chemical injection system may comprise or may be coupled to one or more waste tank for the chemical product.
• the one or more waste tanks do not receive the chemical product, rather the one or more waste tanks will only receive one of the first or second reactants, thereby obviating the risks and costs described above.
• a subsea system comprising at least one of the subsea apparatus of the third aspect, the subsea assembly of the fourth aspect and the chemical injection system of the fifth aspect.
• a seventh aspect there is provided a method of producing a chemical product suitable for use in a well intervention operation, using the subsea apparatus of the third aspect, the subsea assembly of the fourth aspect and the chemical injection system of the fifth aspect.
• Figure 1 shows a diagrammatic view of an apparatus for use in an artificial lift operation in an oil and/or gas wellbore, in a first configuration
• Figure 2 shows the apparatus shown in Figure 1 in a second configuration
• Figure 3 shows an enlarged view of the apparatus shown in Figure 1 ;
• Figure 4 shows a cross-sectional view of the apparatus shown in Figure 1;
• FIG. 5 shows the apparatus shown in Figures 1 and 2, in use
• Figure 6 shows an alternative apparatus for use in an artificial lift operation in an oil and/or gas wellbore
• Figure 7 shows an alternative apparatus for use in an artificial lift operation in an oil and/or gas wellbore
• Figure 8 shows an alternative apparatus for use in an artificial lift operation in an oil and/or gas wellbore
• Figure 9 shows an alternative apparatus for use in an artificial lift operation in an oil and/or gas wellbore
• Figure 10 shows an alternative apparatus for use in an artificial lift operation in an oil and/or gas wellbore.
• Figure 11 shows a diagrammatic view of a subsea system including a chemical injection system for injecting a chemical product into a subsea wellbore;
• Figure 12 shows a schematic view of the chemical injection system of the subsea system shown in Figure 11 ;
• Figure 13 shows an enlarged view of a subsea apparatus for producing the chemical product for use in the chemical injection system shown in Figures 11 and 12.
• the apparatus 10 comprises a tubular conveyance 14 suitable for conveying an artificial lift fluid F (shown in Figure 2) into the fluid column C and a plunger member 16.
• the tubular conveyance 14 takes the form of a coiled hose.
• the tubular conveyance 14 may alternatively take the form of coiled tubing, drill pipe or other tubular.
• the plunger member 16 forms part of a tool string 18 which is weighted to facilitate deployment of the apparatus 10 into the wellbore 12.
• the plunger member 16 takes the form of an inflatable packer having an inflatable packing element 20 defining a chamber 22.
• the chamber 22 receives a portion of the artificial lift fluid F to inflate the inflatable packing element 20 and thereby reconfigure the apparatus 10 from a first configuration in which the plunger member 16 defines a radially retracted, configuration (as shown in Figure 1) to a second configuration in which the plunger member 16 defines a radially extended configuration (as shown in Figure 2).
• Access to the chamber 22 is controlled by a valve arrangement 24.
• the apparatus 10 is configured to be run into the wellbore 12 and activated to reconfigure the apparatus 10 from the first configuration to the second configuration.
• Artificial lift fluid F in the form of Nitrogen gas N2 is pumped or otherwise directed through the conveyance 14 and into the fluid column C, the artificial lift fluid reducing the density of the fluid column C and reducing the pressure force required to displace the fluid column C towards surface.
• the plunger member 16 substantially obturates the bore of the wellbore 12, while providing a fluid communication passage 26 configured to permit passage of the artificial lift fluid F around the plunger member 16, the fluid pressure force Fp from the artificial lift fluid F acting on the area Ap of the fluid column C exposed to the fluid communication passage 26 preventing the passage of the fluid column C around the plunger member 16 as the plunger member 16 is moved towards surface (as shown in Figure 5), such that the plunger member 16 displaces all or substantially all of the fluid column C above the apparatus 10 towards surface on movement of the plunger member 16 towards surface.
• the apparatus 10 permits an artificial lift operation to remove a fluid column C disposed in a wellbore 12 to be carried out by movement of the plunger member 16 towards surface, without the reliance on the reservoir pressure Pr.
• Figure 6 shows an alternative apparatus 110 to that shown in Figures 1 to 5.
• the apparatus 110 is similar to the apparatus 10 and like components are represented by common reference signs incremented by 100.
• the apparatus 110 comprises a tubular conveyance 114 suitable for conveying an artificial lift fluid F’ into the fluid column C and a plunger member 116.
• the tubular conveyance 114 takes the form of a coiled tubing.
• the tubular conveyance 14 may alternatively take the form of coiled hose, drill pipe or other tubular.
• the plunger member 116 takes the form of an inflatable packer having a plurality of inflatable packing elements 120 each defining a chamber 122.
• the chambers 122 receive a portion of the artificial lift fluid F to inflate the inflatable packing element 120 and thereby reconfigure the apparatus 110 from a first configuration in which the plunger member 116 defines a radially retracted, configuration to a second configuration in which the plunger member 116 defines a radially extended configuration (as shown in Figure 6).
• Access to each of the chambers 122 is controlled by a valve arrangement 124 (one of which is references in Figure 6 for clarity).
• the plunger member 116 is capable of adapting or conforming to the shape of the wellbore 12 as the apparatus 110 is withdrawn from the wellbore 12.
• various modifications can be made without departing from the scope of the claimed invention.
• Figure 7 shows an alternative apparatus 210.
• the apparatus 210 is similar to the apparatus 110 and like components are represented by common reference signs incremented to 200.
• the plunger member 216 takes the form of an inflatable packer having a plurality of interconnected segments 220 defining a common chamber 222.
• the plunger member 216 is able to conform to permit the apparatus 210 to pass through restrictions in the wellbore 12.
• Figure 8 shows an alternative apparatus 310.
• the apparatus 310 is similar to the apparatus 10 and like components are represented by common reference signs incremented by 300.
• the plunger member 316 takes the form of a double skin bladder. In use, the plunger member 316 is able to conform to permit the apparatus 310 to pass through restrictions in the wellbore 12.
• Figure 9 shows an alternative apparatus 410.
• the apparatus 410 is similar to the apparatus 10 and like components are represented by common reference signs incremented to 400.
• the plunger member 416 comprises one or more fins 28.
• the fins 28 minimise or at least reduce the potential for fluid to drop out in the annular area Ap.
• Figure 10 shows an alternative apparatus 510.
• the apparatus 510 is similar to the apparatus 10 and like components are represented by common reference signs incremented to 500.
• the apparatus 510 can be used in situations where the reservoir pressure Pr is available, the apparatus 510 assisting the reservoir pressure Pr.
• other aspects of the present disclosure relate to a subsea apparatus and method for producing a chemical product suitable for use in a well intervention operation, and to a subsea assembly, chemical injection system and subsea system comprising the apparatus.
• subsea system generally depicted at 1010, including a subsea wellbore 1012 which communicates with a formation FOR containing an oil and/or gas reservoir R.
• the subsea wellbore 1012 directs the oil and/or gas (“production fluid”) from the reservoir R and permits tools and equipment to be run downhole.
• Production fluid oil and/or gas
• subsea wellhead 1014 which amongst other things includes a valve arrangement 1016 in the form of a subsea Christmas tree.
• the subsea system 1010 includes a chemical injection system, generally denoted 1018, configured to inject a chemical product into the formation FOR as part of a well intervention operation.
• the chemical injection system 1018 is operable to perform a well stimulation operation in the form of an acidizing operation, whereby the chemical product in the form of an acid and more particularly hydrofluoric acid is injected into the formation FOR.
• the chemical injection system 1018 is configured to produce the chemical product to be injected into the formation at a subsea location.
• the chemical injection system 1018 comprises, is coupled to or is operatively associated with an injection manifold 1020 disposed on the seabed S and which is coupled to the wellhead 1014 (more particularly the Christmas tree valve arrangement 1016 of the wellhead 1014) via a fluid conduit 1022 in the form of a jumper.
• the injection manifold 1020 is operable to control the flow and distribution of fluid flow to/from the wellhead 1014.
• An emergency shutdown (ESD) module 1024 is disposed on the seabed S and is coupled to the injection manifold 1020 via a second fluid conduit 1026 in the form of a jumper.
• the emergency shutdown (ESD) module 1024 is operable, via one or more actuated valve, to permit the flow path into and/or from the wellbore 1012 to be isolated remotely.
• the emergency shutdown (ESD) module 1024 communicates with a controller 1028 via control line 1030 disposed on reel 1032 (the controller 1028, control line 1030 and reel 1032 are shown in Figure 12).
• a quick disconnect (EQD) module 1034 is also disposed on the seabed S and is coupled to the emergency shutdown (ESD) module 1024 via a fluid conduit 1036. As shown in Figure 11 , the quick disconnect (EQD) module 1034 is coupled to surface vessel V via an apparatus 1040 for producing the chemical product to be injected into the formation F and which in turn is coupled to a down line arrangement 1038. In the illustrated system 1018, the down line arrangement 1038 includes two down lines formed by fluid conduits 1050,1058. In use, the quick disconnect (EQD) module 1034 permits the apparatus 1040, fluid conduits 1050,1058 and vessel V to be disconnected from the emergency shutdown (ESD) module 1024, and thus the wellbore 1012 when required. However, it will be understood that while the illustrated system 1018 includes or is coupled to an EQD and ESD, in other embodiments or examples, one or both of the EQD and ESD may not be required.
• the chemical injection system 1018 further comprises subsea apparatus 1040 for producing the chemical product to be injected into the formation FOR.
• the subsea apparatus 1040 forms part of an assembly 1042 which includes the quick disconnect (EQD) module 1034 for deployment subsea together.
• the apparatus 1040 and quick disconnect (EQD) module 1034 may alternatively be deployed subsea separately.
• the subsea apparatus 1040 comprises a mixing device 1044 configured for location at a subsea location.
• the mixing device 1044 comprises a first inlet 1046 for communicating with a first reactant supply 1048 on surface vessel V via subsea fluid conduit 1050 and surface conduit system 1052 and a second inlet 1054 for communicating with a second reactant supply 1056 on surface vessel V via subsea fluid conduit 1058 and surface conduit system 1060.
• the mixing device 1044 further comprises a contact chamber 1062 configured to receive the first reactant from the first inlet 1046 and the second reactant from the second inlet 1054, and to permit the first reactant and the second reactant to contact and react at a subsea location to form the chemical product for injection into the formation FOR.
• An outlet 1064 receives the chemical product from the contact chamber 1062 and directs the chemical product from the mixing device 1044 via a fluid conduit 1066 in the form of a jumper.
• the apparatus 1040 provides a number of benefits over conventional techniques and equipment. For example, the apparatus 1040 obviates or at least significantly reduces the requirement to produce the chemical product at surface, such that the risk of exposure to personnel is reduced or eliminated.
• Producing the chemical product at a subsea location also reduces the risk of fire and/or the release of toxic gas at surface due to the relatively low flash point of some chemical products used for well intervention operations.
• the present apparatus also facilitates the mixing of the reactants to be carried out subsea, such that the conduits and infrastructure involved in transporting the first and second reactants from the installation, in the illustrated system 1010 the vessel V, are not exposed to the chemical product itself.
• the apparatus 40 reduces the chemical resistance requirements on the conduits and infrastructure involved in transporting the first and second reactants from the installation.
• the apparatus 1040 provides the ability to greatly reduce the volume of the chemical product that would be required to be purged, handled, stored and/or disposed of in the event of an emergency or other situation where the supply of the chemical product must be disconnected.
• the present apparatus obviates the requirement to purge, handle and/or dispose of the volume of aggressive chemical product in the full conduit length from topside to the point of disconnect, and may reduce or eliminate the requirement for specialised intervention vessels, which typically have limited availability, and permitting more use of vessels of opportunity, thus reducing cost and providing increased responsiveness for the operator.
• the fluid conduits 1050,1058 which couple the first and second inlets to the respective reactant supplies 1048, 1056 on the surface vessel V are disposed around and deployable subsea from a common reel 1068. While in the illustrated system 1018, the fluid conduits 1050,1058 are disposed on a common reel 1068, it will be understood that the fluid conduits 1050,1058 may alternatively be disposed on separate reels.
• the chemical injection system 1018 can be represented as two distinct subsystems: a subsea subsystem including the apparatus 1040, EQD module 1034, emergency shutdown (ESD) module 1024 and injection manifold 1020, together with their associated fluid conduits 1022, 1026, 1036 and 1066 and other components disposed subsea; and a surface subsystem which will be described in more detail below.
• the surface subsystem and subsea subsystem are coupled by the fluid conduits 1050,1058.
• the first reactant source 1048 takes the form of one or more Ammonium Fluoride tank (one tank is shown in Figure 12) which is coupled to the reel 1068 via the conduit system 1052.
• a pump 1070 in the form of a jetting unit is operable to pump the first reactant, in this case Ammonium Fluoride, from the first reactant source 1048 through conduit system 1052 and conduit 1050 to the first inlet 1046 of the mixing device 1044.
• the second reactant source 1056 takes the form of one or more hydrochloric acid tank (three hydrochloric acid tanks are shown in Figure 12) which are coupled to the reel 1068 via conduit system 1060.
• the second reactant is hydrochloric acid
• the second reactant may be any other suitable material, such as formic acid, or another acid.
• a pump 1072 in the form of a triplex pump is operable to pump the second reactant, in this case hydrochloric acid , from the source 1056 through conduit system 1060 and conduit 1058 to the second inlet 1054 of the mixing device 1044, where it contacts and reacts with the first reactant (e.g. ammonium fluoride) from source 1048 to produce the chemical product for injection into the wellbore 1012.
• the chemical injection system 1018 further comprises one or more tank 1074 (one tank 1074 is shown in Figure 12) for storing seawater.
• the chemical injection system 1018 further comprises one or more tank 1076 (one tank 1076 is shown in Figure 12) for storing ammonium chloride.
• the chemical injection system 1018 further comprises one or more waste tank 1078. While in the illustrated system
• one waste tank 1078 is shown for the hydrochloric acid, it will be recognised that the system 1018 may comprise a plurality of waste tanks for the hydrochloric acid. Although not shown, the system 1018 may also comprise one or more waste tank for the ammonium fluoride.

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• 2021
  • 2021-04-12 WO PCT/GB2021/050884 patent/WO2022219293A1/en active Application Filing
  • 2021-04-12 EP EP21719238.4A patent/EP4323622A1/de active Pending

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