Subsea chemical injection system

A subsea chemical injection system has a subsea structure, a manifold connected by jumper to the subsea structure, a coiled tubing, a disconnect mechanism affixed to the coiled tubing, and a hose extending from the disconnect mechanism to the manifold such that the chemical flowing through the coil tubing can selectively flow through the disconnect mechanism and through the hose to the subsea structure. The disconnect mechanism is adapted to selectively release from the hose. The disconnect mechanism has a connector affixed thereto. A hydraulic fluid supply is connected to the connector so as to selectively release the connector from the hose. Control lines can extend from a surface location to a control module and the disconnect mechanism for selectively delivering for receiving signals from the subsea structure.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

Not applicable.

NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT

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Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to systems for injecting chemicals, such as acid, into a subsea structure, such as a subsea tree. More particularly, the present invention relates to systems for injecting chemicals into a subsea structure in which the chemicals can be delivered by coiled tubing from a surface location. Additionally, the present invention relates to control systems used for the controlling of the operation of the subsea structure.

Over the recent past, the search for oil and gas in locations offshore has moved into progressively deeper water. Wells are now commonly drilled at depths of thousands of feet below the surface of the ocean. Additionally, wells are now being drilled in more remote offshore locations. The drilling and maintenance of deep and remote offshore wells is expensive. In an effort to reduce drilling and maintenance expenses, remote offshore wells are oftentimes drilled in clusters. A grouping of wells in a clustered subsea arrangement is sometimes referred to as a “subsea well site”. A subsea well site typically includes producing wells completed for production in at least one pay zone. In addition, a well site will often include one or more injection wells to aid in maintaining in-situ pressure for water drive and gas expansion drive reservoirs.

The grouping of subsea wells facilitates the gathering of production fluids into a local production manifold. Fluids from the clustered wells are delivered to the manifold by flowlines called “jumpers”. From the manifold, production fluids may be delivered together to a gathering and separating facility for a production line, or “riser”. For well sites that are in deeper waters, the gathering facility is typically a floating production storage and offloading vessel.

The clustering of wells also allows for multiple control lines and chemical treatment lines to extend from the ocean surface downwardly to the clustered wells. These lines are commonly bundled into one or more “umbilicals”. The umbilical terminates at an “umbilical termination assembly” at the ocean floor. A control line may carry hydraulic fluid used for controlling items of subsea equipment at subsea distribution units, manifolds and trees. Such control lines allow the actuation of safety valves and other subsea components from the surface. In addition, the umbilical may transmit chemical inhibitors to the ocean floor and then to equipment of the subsea processing system.

Often, a variety of chemicals (also referred to as “additives”) are introduced into the production wells and processing units to control, among other things, corrosion, scale, paraffin, emulsions, hydrates, hydrogen sulfide, asphaltens, inorganics and formation of other harmful chemicals. In offshore oilfields, a single offshore platform (e.g., a vessel, a semi-submersible, or a fixed system) can be used to supply these additives to several producing wells.

The equipment used to inject additives includes a chemical supply unit, a chemical injection unit, and a capillary or tubing (also referred to as a “conductor line”) that runs from the offshore platform through or along the riser and into the subsea well bore. Preferably, the additive injection system supply precise amounts of additives. It is also desirable for the systems to periodically or continuously monitor the actual amount of the additives being dispensed, determine the impact of the dispersed additives, and vary the amount of the additives as needed to maintain certain desired parameters of interest within their respectively desired ranges or at their desired values.

Coiled tubing has been increasingly used in the subsea environment. Coiled tubing can easily be placed upon large reels so that hundreds of feet of tubing can be easily deployed to the offshore location. In the past, coiled tubing has served a variety of purposes in delivering and removing fluids from the subsea environment. However, the coiled tubing has not seen great applicability in delivering and injecting chemicals into the subsea structure, such as a Christmas tree, or for the transmitting of control signals to the subsea tree. One of the problems associated with such coiled tubing is the possibility of damage created when extreme forces are applied to the tubing. Whenever the tubing would be disconnected by force from the subsea structure, damage to the subsea structure could occur and a resulting environmental event could also occur.

In the past, various patents have issued relating to injecting of fluids into subsea structures. For example, U.S. Pat. No. 5,085,277, issued on Feb. 4, 1992 to A. P. Hopper, describes a subsea well injection system in which a slurry of oil-impregnated cuttings from the use of the drilling mud are injected into the annulus of a subsea well and then into the porous formation through which the well has passed. This is accomplished using an apparatus on a guide base surrounding the subsea wellhead. The guide base includes a coupling for a pipe extending from the drilling rig, a one-way isolation valve and pipework leading to the outermost housing of the well. The outermost housing has ports to carry the slurry into the outermost annulus and inner housings also have ports to carry the slurry into the inner annuli. Interior housings also have a one-way check valve to control the injection.

U.S. Pat. No. 6,663,361, issued on Dec. 16, 2003 to Kohl et al., shows a subsea chemical injection pump for injecting chemicals into a subsea system at depths of up to 10,000 feet. This chemical injection pump employs an actuator, such as a solenoid, to power a double-acting actuator rod and plungers thereon. The pump generates low pressures and low fluid volumes.

U.S. Pat. No. 7,234,524, issued on Jun. 26, 2007 to Shaw et al., discloses a subsea chemical injection unit for additive injection and monitoring system for oilfield operations. The system monitors and controls the injection of additives into formations recovered through a subsea well. The system includes a chemical injection unit and a controller positioned at a remote subsea location. The injection unit utilizes a pump to supply one or more selected additives from a subsea or remote supply unit. The controller operates the pump to control the additive flow rates based on signals provided by sensors measuring a parameter of interest. The system includes a surface facility for supporting the chemical injection and monitoring activities.

U.S. Pat. No. 7,721,807, issued on May 25, 2010 to Stoisits et al., provides a method for managing hydrates in a subsea production line. The system has at least one producing well, a jumper for delivering produced fluids from the subsea well to a manifold, a production line for delivering produced fluids to a production gathering facility, and an umbilical for delivering chemicals to the manifold. The subsea well has been shut in so as to leave produced fluids in a substantially uninhibited state. The method generally comprises the steps of pumping a displacement fluid into the chemical injection tubing, pumping the displacement fluid through a chemical injection tubing provided in the umbilical, further pumping the displacement fluid through the manifold and into the production line, and pumping the displacement fluid through the production line so as to displace the produced fluids before hydrate formation may begin.

U.S. Pat. No. 8,133,041, issued a Mar. 13, 2012 to the Ludlow et al., provides a high-pressure pump for use in the injection of liquid chemicals into subsea oil and gas wells and adapted to be positioned in the subsea environment adjacent to the wellhead. The pump includes a piezoelectric actuator for reciprocating a plunger which acts to compress and expand the effect of volume of a pumping chamber. The pumping chamber has a valved inlet connected to a source of liquid and a valved outlet to lead the liquid to the well.

U.S. Pat. No. 8,430,169, issued on Apr. 30, 2013 to Stoists et al., provides a method for managing hydrates in a subsea line. The production system includes a host production facility, a controlled umbilical, at least one subsea production well, and a single production line. The method includes the steps of depressurizing the production line to substantially reduce a solution gas concentration in the produced hydrocarbon fluids, and then re-pressurizing the production line to urge any remaining gas in the free gas phase within the production line back into solution.

U.S. Pat. No. 8,555,914, issued on Oct. 15, 2013 to Smith et al., discloses a method for autonomous control of chemical injection systems for oil and gas wells. A control program for a positive displacement metering system measures the time required for the travel of a free piston in a cylinder of known volume to determine an average flow rate during a full stroke of the piston. The system also measures and records the inlet and outlet pressures between the fluid inlet and the outlet. The control program positions a four-way valve which may function as an adjustable metering orifice in response to the measured average flow rate and/or changes in the inlet and outlet pressures to achieve the desired flow rate. At the end of each stroke, the four-way valve is repositioned to reverse fluid flow through the metering cylinder.

U.S. Patent Publication No. 2014/0318797, published on Oct. 30, 2014 to Vangasse et al., describes a method of applying an acid wash to a subsea connection assembly in order to remove unwanted material such as marine growth and calcareous deposits. The method includes inserting a plug containing channels into a central hole in a stabplate connection. The acid wash is then injected through the plug. The plug may be carried by an operating tool arm of a remotely operated underwater vehicle.

It is an object of the present invention to facilitate the delivery of electrical power and communications to a subsea structure, such as a subsea tree.

It is another object of the present invention to provide a subsea chemical injection system that minimizes the likelihood of environmental impacts.

It is another object the present invention to provide a subsea chemical injection system that minimizes the possibility of damage to subsea hardware.

It is another object of the present invention to provide a subsea chemical injection system that facilitates emergency shutdown.

It is still a further object of the present invention to provide a subsea chemical injection system that can be easily installed and which utilizes coiled tubing.

It is another object of the present invention to provide a subsea chemical injection system which minimizes the potential for the introduction of fatigue loads to the coiled tubing and manifold assembly.

It is still further object of the present invention divided provide a subsea chemical injection system that can increase the vessel operating parameters in comparison with rigid connections.

It is another object of the present invention to provide a subsea chemical injection system which provides a conduit for the purpose of transmitting subsea chemicals and electrical signals.

It is still another object of the present invention to provide a subsea chemical injection system that facilitates the injection of chemicals into the subsea tree from a surface vessel.

BRIEF SUMMARY OF THE INVENTION

The present invention is a subsea chemical injection system that comprises a subsea structure, a manifold connected by jumper to the subsea structure, a coiled tubing, a disconnect mechanism affixed to the coiled tubing, and a hose extending from the disconnect mechanism to the manifold such that the chemical flowing through the coiled tubing can selectively flow through the disconnect mechanism and through the hose to the subsea structure. The disconnect mechanism is adapted to be selectively released from the hose.

The disconnect mechanism has a connector affixed thereto. This connector is connected to the hose. The disconnect mechanism has a hydraulic fluid supply therein. The hydraulic fluid supply is connected to the connector. The hydraulic fluid supply is actuatable so as to release the connector from the hose. The hose has a hub affixed to an end thereof. The connector has a plurality of collet segments engaged with the hub such that the hoses is in fluid communication with an interior of the connector. The connector also has another hub joined with the disconnect mechanism. An actuating piston is positioned over this hub. The actuating piston is movable in one direction so as to release the collet segments from the hub of the hose upon receipt of hydraulic fluid from the hydraulic fluid supply. The hub of the connector has a poppet resiliently mounted therein. The poppet is movable to a position sealing the interior of the connector when the collet segments are released from the hub of the hose. The hub of the hose also has a poppet resiliently mounted therein. The poppet is movable to a position sealing an interior of the hub of the hose when the collet segments are released from the hub of the hose. The disconnect mechanism also has a weak link joined to the hose.

The present invention further includes a first control line extending to the manifold, a control module positioned in the manifold, and a second line extending from the control module to the subsea structure. The first line is connected to the control module such that control signals can be transmitted to the control module. The second line allows the control module to send or receive control signals to or from the subsea tree. The first line extends along the coiled tubing. The second line extends along the jumper. The subsea structure is, in the preferred embodiment, a subsea tree that has a mandrel at a top thereof. The manifold is positioned on the mandrel.

This Section is intended to describe, with particularity, the preferred embodiment of the present invention. It is understood that modifications to this preferred embodiment can be made within the scope of the present claims. As such, this Section should not to be construed, in any way, as limiting of the broad scope of the present invention. The present invention should only be limited by the following claims and their legal equivalents.

DETAILED DESCRIPTION OF THE INVENTION

Referring toFIG. 1, there is shown the subsea chemical injection system10in accordance with the preferred embodiment the present invention. The subsea chemical injection system10includes a subsea structure12. The subsea structure12can be in the nature of a subsea tree. A manifold14is positioned on a mandrel13extending upwardly from the subsea structure12. The manifold14is connected by a hose16to a first disconnect mechanism20. A first coiled tubing22is connected to the disconnect mechanism20and extends upwardly toward a surface location. Another hose24is connected to the manifold14and extends outwardly therefrom. The second hose24is connected to a second disconnect mechanism26. A second coiled tubing28is also connected to the second disconnect mechanism26and extends upwardly to a surface location. A jumper30is also connected to the manifold14and will be connected to the subsea structure12. Jumper30is intended to pass fluids, along with control signals, from the manifold14and from the surface location to the subsea structure12.

In the present invention, the manifold14is intended to collect fluids and chemicals as passed therein to the hoses16and24. The manifold14will then deliver the fluid to the subsea structure12through the jumper30. Importantly, the first hose16can include an electrical line32that extends from the first disconnect mechanism20along the hose16and to the manifold14. Similarly, another electrical line34can also extend from the second disconnect mechanism26along the hose24to the manifold14. As will be described hereinafter, the manifold14can include a control module therein that is connected to the electrical lines32and34. The control module within the interior of the manifold14is intended to provide control signals to the subsea structure12and to the disconnect mechanisms20and26. Additionally, the first coiled tubing22and the second coiled tubing28can also include the electrical lines that are connected to electrical lines32and34, respectively, so that signals from the surface location can be passed to the control module or received from the control module.

The first coiled tubing22and the second coiled tubing28can be deployed from a vessel at a surface location. The first coiled tubing22terminates at the disconnect mechanism20. The second coiled tubing28terminates at the second disconnect mechanism26. The coiled tubing22and28will hang in the water column some distance above the subsea structure12. The flexible hoses16and24include an electrical flying lead that connects the disconnect mechanisms20and26to the manifold14. The manifold14ties in at least one coiled tubing and, preferably, two or more coiled tubing systems together so as to direct the fluid to the jumper30and to the subsea structure12. Electrical power and control signals are delivered to the subsea chemical injection system10, as well as the subsea structure12, via an electrical line attached to the coiled tubing22and24, through the disconnect mechanisms20and26, and into the manifold14. The necessary power and control signals required to control the subsea chemical injection system10is directed into the control module located in the manifold14. The power and signals required to control the subsea structure12is simply passed directly therethrough.

Hydraulic power is supplied to the subsea chemical injection system10via two methods. The primary method utilizes the low-pressure supply found in the production umbilical system. This low-pressure supply can be fed to the manifold14from the production umbilical by a hot stab flying lead connected to a junction plate interface unit. This junction plate interface unit is installed between the production flying lead and the subsea structure12. The second method for providing hydraulic power to the subsea chemical injection system10is through the use of accumulators located within the manifold14. These accumulators provide only limited functionality before the stored pressure will need to be recharged.

FIG. 2is a detailed view of the manifold14, along with the jumper30, the hose16, the first disconnect mechanism20and the coiled tubing22. In the embodiment of the subsea chemical injection system10shown inFIG. 2, only a single coiled tubing is connected to the manifold14for the delivery of chemicals, such as acid, to the manifold14.

In particular, inFIG. 2, it can be seen that the manifold14includes a guide funnel40at the bottom thereof. Guide funnel40can be utilized so as to properly guide the manifold14onto the upper mandrel13of the subsea structure12. Within the concept within the concept of the present invention, the manifold14can also be located on other subsea locations, such as a pile, a platform, a slab, or other structures in the vicinity to the subsea structure12.

The jumper30is connected to the manifold14such that the chemicals accumulated within the manifold14can be delivered to the subsea structure. The hose16is also connected to the mandrel14so as to pass the chemicals from the coiled tubing22into the interior of the manifold14. Importantly, the disconnect mechanism20is connected to the opposite end of the hose16from the manifold14.

During normal operations, the hose16serves as a conduit to transmit the subsea chemicals, electrical power, and signals from the disconnect mechanism20to the manifold14. The hose16is connected to a connector42at the disconnect mechanism20. The hose16is joined to the opposite end of the hose16from the disconnect mechanism20and is joined to the manifold14through the use of a horizontal connector44. The vertical connector42will have a unique structure, as will be described hereinafter. Additionally, a weak link46will extend between the hose16and the vertical connector42. The weak link46has a configuration such that the weak link46will break upon the application of sufficient force prior to any damage occurring to the vertical connector42, the horizontal connector44, to the manifold16or to the disconnect mechanism20.

The hose16further includes vertebrae bend restrictors at each end thereof so as to prevent damage to the hose in the proximity of the vertical connector42and the horizontal connector44. Additionally, a flotation package can be installed adjacent to the weak link46. The flotation package supports the free end of the hose16when a disconnect sequence is initiated. The hose16includes an eight-way electrical flying lead that transmits the necessary power and signals between the disconnect mechanism20and the manifold14.

The disconnect mechanism20is connected to the manifold14through the hose16. The hose16can be in the nature of a long hose. An electrical flying lead bundle will connect the electronics of the disconnect mechanism20to the manifold14. The flexible connection minimizes the potential for the introduction of fatigue loads into the coiled tubing22as well as to the manifold14. The flexible connection also increases the vessel operating parameters when compared to rigid connections to the manifold and subsea structure. The system further includes a pressure-balanced weak link46that can provide passive separation of the hose16from the disconnect mechanism20as well as isolation of contents from the environment in the unlikely event that the disconnect mechanism cannot or is not activated in a timely manner.

FIG. 3is a schematic diagram showing the functionality of the subsea chemical injection system10of the present invention. The subsea chemical injection system10includes the first disconnect mechanism20and the second disconnect mechanism26. The first coiled tubing22is illustrated as extending through the first disconnect mechanism20so as to be joined to the hose16extending from the first disconnect mechanism20to the manifold14. The second disconnect mechanism26also is joined to the second coiled tubing28. Second coiled tubing28extends through the second disconnect mechanism26and is joined to the hose24leading to the manifold14. An electrical line48is illustrated as being connected to the first disconnect mechanism20. Another electrical line50is illustrated as being connected to the second disconnect mechanism26. The electrical lines48and50will extend along the respective coiled tubing22and28such that the electrical lines48and50can be connected to a surface location. The electrical line48will pass through the interior of the first disconnect mechanism20so that another line52will pass, along with the hose16, to the manifold14. Similarly, the line54from the second disconnect mechanism26will also be connected to the manifold14. The disconnect mechanisms20and26include accumulator bottles56and58in an interior thereof. The accumulators56and58are adapted so as to provide hydraulic fluid to the respective vertical connectors42and60. The vertical connectors42and60will have a configuration similar to that shown inFIGS. 5-8herein.

The manifold14includes a control module62on an interior thereof. Control module62is connected to the electrical lines52and54therein. The control module62is also connected to a variety of other pressure sensors within the interior of the manifold14. As such, the control module62can receive signals from a surface location, can monitor the conditions within the subsea chemical injection system10, and can send control signals to the subsea tree64. The manifold14further includes another accumulator66on an interior thereof so as to provide hydraulic energy for the operation of the junction plate assembly68associated with the tree64.

The junction plate assembly68includes a variety of plates that are joined to the tree receptacle69. In particular, a valve70is provided so as to control the flow of hydraulic fluid from the tree64or from the accumulator62to the tree64. This will operate in a variety of ways, as will be described hereinafter. It can be seen that the chemicals that have flowed through the coiled tubing22and28and through the manifold14are delivered along line72to the tree64. The electrical signals from the surface location can be delivered through the control module62along line74for the operation of the tree64.

For clarity,FIG. 4illustrates the subsea chemical injection system10of the present invention with the various flow paths illustrated by heavier lines. For example, the injection flow path80serves to inject chemicals to the tree64. In particular, the chemical injection will flow through the second coiled tubing28, through the second disconnect mechanism26, along line24through the interior of the manifold14, and along line72to the tree64. It can be seen that the control module62is cooperative with the injection path80so as to control the flow of fluids therethrough. There is another injection flow path84that passes through the first coiled tubing22, through the first disconnect mechanism20, through hose16and into the manifold14. This flow path84further joins with a pipe86formed in the manifold14so that the fluid can be delivered to the tree64along conduit72.

The hydraulic fluid flow path88is illustrated as extending between the tree64and the manifold14. Hydraulic fluid flow path will pass along a line92that extends from the junction plate90to the manifold14. The control module62is connected to a valve94that is connected to the hydraulic fluid path88. A first communications path100is illustrated as extending to the control module62. First communications path100extends along the electrical line50so as to be connected to the electronics associated with the second disconnect package26. The first communications path100further will extend so as to be joined with the manifold14and to the control module62. As such, the communications path of receiving signals from the control module62at the surface location and for delivering control signals from the surface location to the second disconnect mechanism26and to the manifold62is established by the first communications path100. The subsea tree communications path102is illustrated as extending through the manifold14and to the tree64. The subsea tree communications path102will pass through the first disconnect mechanism20and is joined to the control module62within the manifold14. Control module62has a connection104with line74so as to allow the direct communication from the surface location to the subsea tree64along path102.

The subsea chemical injection system of the present invention has a robust subsea control system in order to facilitate safe operation. The control module62is located within the manifold14. In addition, each of the disconnect mechanisms20and26also contains a control unit. The control unit in the disconnect mechanisms20and26simply activate the vertical connector in order to disconnect the disconnect mechanism from the manifold14. Hydraulic power to the subsea control system is primarily supplied from the production umbilical via the junction plate interface unit90. Electrical power and signals are supplied from top side control equipment such as laptop computers and power transformers. The laptops communicate with the control module via the electrical lines that are affixed to the coiled tubing22and28.

The control module62and the manifold14includes a pressure-balanced oil-filled housing that includes the electrical boards, solenoids, and directional control valves. The control module16is non-retrievable independently from the manifold. The control module is configured so as to operate the gate valves in the manifold, monitor injection manifold piping pressure, monitor stored accumulator pressure in the disconnect mechanism, activate commanded emergency “disconnect” sequences, bleed low-pressure hydraulics to the subsea tree64without bleeding umbilical hydraulic pressure, and pass-through power and signals in order to facilitate control of the subsea tree.

The junction plate assembly90is used to supply the injection manifold and its control system hydraulic pressure from the production umbilical. This interface unit is installed so as to be connected to the subsea tree. This junction plate interface unit simply acts as a bridging plate that allows the low-pressure hydraulics to be rerouted to the injection manifold14via a hot stab/flying lead. The low-pressure supply will enter the junction plate assembly90and is directed to the manifold14by operating small ROV-controlled three-way valves. The outlet to the injection manifold14can be bypassed by simply operating the three-way valves back to the normal position. A dummy hotstab would also be inserted into the receptacle so as to create a double barrier isolation. All other lines (i.e. high-pressure lines, chemical lines, etc.) can be connected directly coupler-to-coupler without any bypass loop.

The system of the present invention can operate under five different operational modes: (1) normal operation; (2) system shutdown; (3) system shutdown with active disconnect; (4) passive disconnect; and (5) loss of communications.

Under normal upper conditions, the subsea chemical injection system10monitors and reports the piping pressure of the manifold14, the disconnect mechanism and the disconnect mechanisms20and26. Independent operation is allowed to operate the gate valves as required to isolate one coiled tubing riser from the other, circulate through the coiled tubing risers, or isolate the subsea tree. As previously described, hydraulic pressure operates the branch outlet valves and can be supplied by either of the accumulators56,58and66or from the production umbilical via the junction plate assembly90.

System shutdown condition occurs whenever a controlled shutdown of the subsea chemical injection system10and the subsea tree64is required. A shutdown command is generated from the control system at a surface location and sent to the control module62of the manifold14. The control module then closes the gate valves within the manifold14and bleeds the hydraulics to the subsea tree. Another simple command from a laptop computer can be utilized so as to open up the system in order to allow normal operation to occur.

The condition of system shutdown with active disconnect involves a controlled shutdown of the subsea chemical injection system and the subsea tree64as well as an active disconnect of the disconnect mechanisms20and26. The shutdown command is generated from a laptop computer at a surface location and delivered to the control module62of the manifold14. The control module then closes the gate valves within the manifold14, bleeds the hydraulics to the subsea tree, and sends an electronic signal to the disconnect mechanisms20and26to carry out the active disconnect sequence. Once the vertical connector is actuated, as will be described hereinafter, the internal poppets will engage with and seal the bore so as to prevent fluid flow to the environment. The upper part of the hose will include a flotation block that maintains the ejected hub elevation above the mudline and adjacent subsea equipment. After an active disconnect, the coiled tubing risers and the disconnect mechanisms can be recovered to the surface. Additionally, the hoses16and24can also be recovered to the surface for inspection and reinstallation on to the disconnect mechanisms.

Under the passive disconnect condition, the disconnect mechanisms20and22can be operated to separate the disconnect package from the hose in order to mitigate environmental issues. This scenario is envisioned if the active disconnect is not activated in a timely manner or fails to release the hose from the disconnect mechanism. The passive disconnect method simply relies on the hose and disconnect package experiencing a determined amount of tension before the weak link separates below the vertical connector. A steel tension wire is connected to the vertical connector and then pulls out the electrical flying lead from the disconnect mechanism so as to allow the disconnect bracket mechanism to be fully disconnected from the hose and the manifold14. As with the active disconnect operation, the coiled tubing risers, disconnect mechanisms and the hose bundles can be recovered at the surface for inspection and reinstallation.

In the event of a loss of communications, the control module62of the manifold14will deenergize the control valve so as to allow hydraulic pressure to the gate valves and the subsea tree to vent to the seawater. As a result, all valves will be closed so as to bring the system to a fail-safe condition.

The subsea chemical injection system10of the present invention is designed to facilitate a local shutdown of the subsea tree62by bleeding the low-pressure supply to the tree. However, this action must be isolated to the subsea tree64so as to lead the production umbilical to service the other subsea tree. The control module62and the manifold14gives the operator proper control by directing the low-pressure fluid supply from the tree64to the manifold14and back to the tree64. This bypass is accomplished by installing the junction plate assembly90in the manner described hereinabove. When required to bleed the low-pressure supply, the control module62will quickly shift the valve so as to allow only the supply to the subsea tree64to vent. The umbilical supply will be blocked so as to prevent a loss of pressure in the umbilical.

Referring toFIG. 5, there is shown the vertical connector42that is used to connect the hose16to the disconnect package20. In particular, the vertical connector42is illustrated as having a connector body100that has a hub102suitable for connection to the coiled tubing22or to the disconnect mechanism20. The connector42is used so as to connect with an outboard hub104that is suitable for connecting with the hose16and/or the weak link46. The connector body100has an outer sleeve106that is slidably and controllably positioned over the exterior of the connector body100. A channel108formed through the wall of the outer sleeve106and includes a conduit110that is connected to a source of hydraulic fluid. As such, in order to allow the sliding action of the actuating piston112, hydraulic fluid can be introduced through the conduit110so as to cause the outer sleeve106to move from the position shown inFIG. 5to the positions shown inFIG. 6-8.

A lock ring114is in abutment with the end of the outer sleeve106. When the outer sleeve106moves in relation to the connector body100, the lock ring114will also move. There are a plurality of collet members116positioned within the interior of the lock ring114. Each of the collet members116has an outer surface with a particular shape which can cause the actions of locking and releasing created by the vertical connector42in accordance with the present invention. Additionally, the lock ring114also has an interior shape which bears against the outer surface of the collet members116so as to facilitate the movement of the collet members116between the locking position and the release position.

Importantly, inFIG. 5, it can be seen that there is an interior bore118formed inside the connector body100. A spring120is resiliently mounted in the interior bore118of the connector body100. A poppet122is located within the interior bore118of the connector body100and has a surface which can bear against an inner wall of the connector body. Similarly, the outboard hub104has an interior passageway124that has a spring126mounted therein. Spring126is configured so as to bear against the poppet128. Poppet128has a surface that is designed to seal in relation to the shoulder formed on the wall of the interior passageway124of the outboard hub104.

FIG. 5shows the vertical connector42in the locked position. As can be seen, the end130of the collet members116have an interior shoulder that bears against an exterior shoulder at the end of the outboard hub104. This locking configuration is accomplished by the bearing end132of the lock ring104strongly urging against the exterior of the end portion130of the collet members116. In this locking configuration, there is no hydraulic fluid introduced into the interior of the outer sleeve106. As such, the actuating piston112will be in its uppermost position and bearing against a shoulder formed on the connector body100. Also, in this configuration, the end of the poppet122is illustrated as bearing against the end of the poppet128. This will resiliently urge the shoulders of the poppets122and128away from their seated position. As a result, fluid is able to flow through the interior bore118of the connector body100and through the interior passageway124of the outboard hub104.

FIG. 6illustrates the vertical connector42in an unlocked position. As can be seen, hydraulic fluid has been introduced through the channel108so as to cause the actuating piston112to move away from the shoulder of the connector body100. This movement of the actuating piston112will cause the lock ring114to also move downwardly. As a result, the inner surface of the lock ring114will bear against the back portion140of the collet members116such that the end portion130of the collet members116releases from the shoulder at the end of the outboard hub104. As a result, the collet members116will no longer grasp the outboard hub104. However, at this stage, the poppet122still bears against the end of the poppet128. The ends of the connector body100and the outboard hub104still bear against each other.

InFIG. 7, it can be seen that the actuating piston112has moved further away from the shoulder142of the connector body100. This causes the collet members116to further urge the outboard hub104away from the end of the connector body100. As such, it can be seen that a separation space144occurs between the ends of the connector body100and the outboard hub104. This is the release position. As can also be seen there is a small space146between the ends of the poppets122and128. Since there is a space146, the spring120will urge the poppet122into strong abutment with the inner wall of the interior base118of the connector body100. As a result, the interior of the connector body100is sealed by the poppet122. Similarly, the spring126will urge the poppet128against the shoulder on the inner wall of the interior passageway124of the outboard hub104. As a result, the interiors of the connector body100and the outboard hub104are sealed. When the connector100of the vertical connector42is released from the outboard hub104of the hose16, the poppets122and128prevent spillage or leakage of fluid into the subsea environment.

FIG. 8shows how the hose16and the outboard hub104have been released from the vertical connector42associated with the coiled tubing22. In particular, coiled tubing22is shown as joined to the inboard hub102of the connector body100. The collet members116are in the fully released position, as shown inFIG. 7. As a result, the weight associated with the outboard hub106and the hose16will cause the outboard hub104to separate, by action of gravity, from the interior of the lock ring114. In this configuration, the poppet122will be in a sealed relationship with the fluid passageway of the connector body100so as to prevent any liquid within the vertical connector42from releasing into the marine environment. Similarly, it can be seen that the poppet128is in sealed relationship with the inner wall of they interior passageway of the outboard hub104. Once again, this serves to prevent any release of contaminants from the interior of the hose16into the marine environment.

In order to install the outboard hub104of the hose16into the vertical connector42, it is only necessary to reverse the steps illustrated inFIGS. 5-7herein. In this manner, the vertical connector42it can easily engage with the outboard hub104of the hose16in order to create the requisite sealed fluid tight relationship therebetween.