EA042325B1 - COMPOUND - Google Patents

Description

State of the art

The present invention relates to a connection for connecting two tubular elements, to a method for connecting two elements, and to a system for connecting two tubular elements. The present invention also relates to a method, equipment and system for confirming that a connection has been made. The present invention also relates to a method and equipment for laying a pipeline terminal or flowline.

Tubular members are used to transport fluids. Such tubular elements are used in pipelines, flowlines and risers. Tubular elements can be used to transport oil and gas offshore. There are many types of tubular elements used in the offshore oil and gas industry, such as export pipelines, which can be pulled along the seabed from a wellhead for a production well or from a manifold linking several wellheads located on the seabed to an onshore facility for storage. products or refinery; risers that extend upward from a wellhead for a production well located on the sea floor to a drilling rig or buoy for connection to an offshore tanker; and flowlines connecting the subsea wellheads to the manifold. In addition, tubular elements can be used in the construction and maintenance of oil and gas wells. Examples of such tubulars used in the construction and maintenance of oil and gas wells are risers extending upwards from the well and flexible spool tubing used primarily for completion, maintenance and stimulation of wells. The tubular elements may be rigid, flexible and/or coiled.

Offshore pipelines are generally manufactured from mild steel or high strength steel in sections that are transported on a pipe-lay vessel, such as a barge or ship, to their point of use. Sections of rigid pipeline are welded together and lowered into the sea from the stern of the vessel to form a continuous pipeline that rests on the seabed. Welded piping is generally lowered from a vessel using one of three systems: S-lay, J-lay, or drum-lay.

With the S-lay system, the free end of the pipeline is placed generally horizontally on a roller bed base on the deck of the vessel, with the new section also laid horizontally and then welded to the free end. The pipeline is unloaded from the stern of the vessel along a stinger that projects back and down into the sea from the stern of the vessel. The pipeline allows for a simplified S-shape between the seabed and the ship.

When using the J-lay system, the free end of the pipeline is held at an angle that matches the depth of the water, which can be nearly vertical for greater depths. The pipeline is held at the required angle at the stern of the vessel, with a new section of pipeline placed on the base at the required angle and welded to the free end of the pipeline. The pipeline is unloaded at the required angle from the stern of the vessel. The pipeline allows for a simplified J-shape between the seabed and the vessel.

When using the drum laying system, the length of the welded pipeline is wound on a large winding drum located on the ship and unwound through the straightener and from the stern of the ship. The pipeline allows for a simplified J-shape between the seabed and the ship.

Once the pipeline is put into service, the pipeline is generally constructed to withstand internal pressures typically up to 5000 psi. inch (350 bar) as a result of fluid transport. Pipelines can have a diameter of 2 (50 mm) to 48 (1.2 m), but, in general, of the order of 8 (200 mm) to 24 (600 mm).

In the production phase of an oilfield, flowlines are a string of tubular elements that transport oil and gas from a plurality of production wellheads to a manifold and may be in the order of tens to hundreds of meters in length. The pipeline may be a string of tubular elements for transporting oil and gas from the manifold to an existing platform or towards the shore and may be in the order of kilometers in length.

Oil and gas risers generally fall into one of two categories: offshore risers and production risers. The first one is lifted across the sea from the blowout preventer located on the seabed, and the second one is pulled continuously from the seabed to the blowout preventer located on the surface platform. Risers are generally built to withstand pressures up to between 15,000 psi. inch (1050 bar) and 20,000 psi. inch (1400 bar). The risers may comprise a single string of tubulars forming a wellbore casing extension in drilled formations below the seabed, and may contain a number of additional parallel tubes to transport, among other things, fluids for throttling and killing the well. The risers are manufactured from high strength steel in sections having connections containing top and bottom threaded ends and/or with flanged connectors. Each section of a rigid riser is rigid to the point that it is

- 1 042325 self-supporting when stacked vertically in a rack, and when stacked horizontally between the ends deviates by a small amount under its own weight.

Flexible tubular members such as flexible risers are generally a composite made of several concentric layers including steel helical bands and plastic layers. Flexible risers can be built in sections and transported similarly to rigid risers, or spooled onto large winding drums and therefore have a long length with few field connections.

Flexible spool tubing used in the construction and maintenance of oil and gas wells is generally small in diameter (typically less than 3.25 inches (83 mm)) and is made of mild steel. Flexible spool tubing can be wound in the form of a spool onto winding drums.

Tubular elements such as conduits and flowlines typically require a termination. For shallow water applications, each end of the pipeline should have simple pigging heads that are removed by divers after the pipeline has been flooded, graduated and pressure tested. These heads are attached to the end of the pipe using standard flanges and are removed by divers before divers connect the ends of the pipeline to a rigid riser attached to a platform or manifold, or directly to a single wellhead. PLETs (Pipeline Terminations) are more complex and expensive terminals that are generally used at greater depths generally, but not exclusively, in order to facilitate diverless tie-ins using ROVs.

A PLET is, in general, a rigid structure designed to remain on the seabed that holds the end of a pipeline and its stub at a predetermined distance from the seabed to facilitate the following: attaching a pig launcher at one end and a pig receiver at the other end of the pipeline for a pigging cleaning tool used, among other things, for cleaning, inspection and pressure testing of the pipeline; and subsequently making connections to a piece of equipment on the seabed, such as a manifold or wellhead. The PLET makes it easy to align end devices to form a connection, as well as providing space around the connector to make the connection easier. Typically, for shallow water applications, a flange connector is provided and the diver uses a screwdriver to finalize the connection. Alternatively, if the seabed is located at greater depths, a remotely operated vehicle (ROV) may comprise a highly specialized bolting system and is used to finally secure the flange connection. A short section of coiled tubing or a shaped rigid tubular is typically used to connect a pipeline and flowline terminal to manifolds and wellheads.

Under certain circumstances, the tubulars can transport fluids that are highly corrosive to mild steel or high strength steel used in the tubular body. Such circumstances may include the following:

exploratory drilling for oil and gas in certain rock types where corrosive fluids are likely to occur, such as fluids that contain sulfur;

when transporting produced fluids that can be corrosive;

fracturing operations that may use corrosive fluids such as sea water; and in well stimulation operations, such as reverse injection for oil and gas wells, which may use sea water.

Injection fluids, produced fluids, or fluids contained in drillable zones can form highly corrosive fluids that can attack mild and high strength tubular members.

To overcome corrosion problems, such tubular members can be made with a chromium alloy instead of mild steel. However, the chromium alloy is very expensive, and if the surface of the chromium alloy tubular member is scratched, corrosion can still occur.

It is also common practice to use mild steel or high tensile steel tubular members with an internal lining, with the internal lining made of epoxy fiberglass, plastic, stainless steel or other corrosion resistant materials. Such internally lined steel tubulars can be used for lift pipes, pipelines and risers.

Corrosive fluids can be two-phase or multi-phase fluids such as oil, gas and water or sea water that has dissolved salts and air trapped in it. Sea water and other corrosive fluids are widely used in reverse injection wells. The reverse injection well may be an existing

- 2 042325 a well in a reservoir or a specially drilled well in a depleted reservoir. Reverse injection fluids are injected into the reservoir to energize and pressurize the reservoir to force all of the required oil and gas out of the reservoir through the production well.

Corrosive fluids can also be produced oils and gases, and as such, lined lift tubing and lined pipelines are often required. Such produced fluids may be single-phase or multi-phase fluids containing a combination of liquid, solids and gas.

One exemplary inner-lined tubular element is a double or double wall tubular element in which the inner wall is an inner lining tube made of a corrosion resistant material that serves as a conductor for the corrosive fluid and the outer wall or tube is designed to provide strength to withstand the internal pressures of the corrosive fluid as well as external forces such as external ambient water pressure, mechanical loading, etc. The tubular element with walls made of mild steel or high strength steel can be lined on the inside with an internal lining of high density polyethylene (HDPE), stainless steel or glass epoxy (GRE). The GRE inner lining is inserted into the steel wall tubular element and cemented into the inner wall of the steel wall tubular element. The HDPE inner liner can be pulled through the tubular element with assistance and remain in a friction fit.

Rigid tubulars are of limited length due to the conditions and constraints to which the tubulars are subjected in situ, such as storage racks and handling equipment. Thus, in the case of pipeline sections, each section typically has a length of approximately 12-24 meters, while a pipeline may be tens or hundreds of kilometers long. The diameter of the pipeline can be from 2 (54 mm) to 48 (1.22 m). The inner lining is concentric with the outer steel wall. The inner lining may be formed from extruded HDPE with a series of outer ribs to space the inner lining away from the outer steel wall, which define axial passages for transporting gases that can flow from the wellbore through the inner lining into the axial passages.

WO 2004/016977 discloses a means for connecting a pipe, comprising a seal, flanges, a threaded section and a nut, wherein the end section of the pipe is provided with a concentric pressing surface located immediately adjacent to the periphery of the pipe and is designed to receive an axial force from a pre-drilling tool. load, this force being distributed evenly or pointwise about the periphery of the end of the pipe to activate the seal located between adjacent flanges. The preload tool comprises two end sections connected to two or more rods, each rod being equipped with a hydraulic cylinder.

The inventor observed that pipelines, flowlines and risers should be completely refurbished and their components reused as soon as the pipeline is no longer needed. In this regard, the inventor observed that ease of restoration is very important in order to achieve this goal.

The inventor observed that the outside diameter of the joint should be minimized to allow insertion through tools, through holes and to reduce the amount of material used in the joint.

The inventor also noted that the joint requires a large tensile force to be applied to the joint in order to activate the seal. The inventor also observed that once the correct tensile force is applied to the joint, tightening the nut requires neither a high torque force nor a corresponding reactive grip on the non-rotating portion of the joint.

The inventor also noted that alignment of the tensioning tool is critical to improving the connection.

There is a need for a method to reduce the risk of corrosion in couplings and in threads between couplings and pipe ends.

There is a need for connecting tubular elements that can be easily detached so that the tubular element can be reused.

The inventor has also observed that it would be desirable to have a system for confirming that a connection has been properly made at the earliest opportunity.

The inventor also noted that there is a need for a terminal device that can be permanently attached to an additional connection lying underwater on the seabed.

The inventor also noted that there is a need for a terminal device that can be deployed from a vessel, such as a ship or a barge, in an efficient manner.

In some circumstances, it is desirable to insulate the conduit in order to maintain the temperature of the transported fluid. It is sometimes desirable to keep the fluid at a temperature that facilitates the flow of the fluid through the conduit. Alternatively or additionally, it is desirable to maintain a temperature at which hydrate formation is unlikely in the transported fluid.

The inventor also noted that cold spots in the pipeline must be avoided in order to maintain the temperature in the transported fluid. The inventor also noted that there is a need to insulate the connections between the pipes.

The essence of the invention

In accordance with the present invention, a system is provided for making a connection between a first tubular element and a second tubular element having matching fluid transfer ports, the connection having an axis in a common direction of flow of said fluid through it, the system comprising a connection and a tensioning tool, moreover, the connection has a first tubular end containing a first end flange having an end surface and a coupling containing a sleeve and an end stop attached to the sleeve, wherein the specified sleeve is located near the specified flange and the specified end stop is placed around the specified tubular end, and the specified coupling is made with the possibility of sliding along the specified tubular end, and the connection additionally has a second tubular end containing a second end flange having an end surface and a lock nut about and the possibility of rotation along the specified first of the tubular end, wherein the tension tool is used to apply axial tension to the specified sleeve relative to the specified second tubular end, characterized in that at least one of the specified sleeve and the specified second tubular end has a plurality of parallel peripheral grooves and the specified tension tool has a plurality of ridges, and the system comprises the steps of moving said plurality of ridges into said plurality of grooves and applying axial tension to said sleeve relative to said second tubular end.

Alternatively or additionally, the sleeve and the second tubular end comprise a plurality of ridges and the tensioning tool comprises a plurality of grooves.

The present invention also provides a connection for use in the system of the invention, and the connection has a first tubular end containing a first end flange, having an end surface and a sleeve containing a sleeve and an end stop, and the specified sleeve is located about the specified first end flange and the specified end stop is located about said first tubular end, wherein said sleeve is slidable along said tubular end, wherein the joint further has a second tubular end containing a second end flange having an end surface and a lock nut about and rotatable along said second end, characterized in that at least one of said sleeve and said second tubular end contains a plurality of annular grooves.

Perhaps the sleeve has an internal threaded section and the lock nut has a corresponding external threaded section. Optionally, the inner threaded portion and the corresponding outer threaded portion of the lock nut are sized such that they are threaded to lock the ends of the first and second tubular members together. Perhaps the sleeve is integrally formed with an end stop for a one-piece sleeve.

Perhaps the end stop is located at the distal end of the sleeve, and a plurality of grooves are located at the proximal end of the sleeve. Optionally, a body portion is provided between the plurality of grooves and the end stop, the body portion being resiliently stretched during tension with the tension tool and may remain in resilient tension after the tension tool is removed and the connection is made. Optionally, the sleeve is slidable along the first tubular end until the end stop rests against the first end flange. Optionally, the lock nut is slidable along the second tubular end until the lock nut abuts against the second end flange. Perhaps the end stop is inside the sleeve and is concentric with it. Possibly the end stop is attached to or integral with the sleeve. Optionally, the end stop has a threaded sleeve, an end stop having an external thread, and a sleeve having an internal thread at least along a portion of the inner surface.

It is possible that each groove of the plurality of grooves is a groove. The groove is a groove with rounded inner corners and a flat bottom section. In addition, the grooves may have rounded or square top corners. Perhaps the groove has a rounded cross section or a square cross section. The grooves preferably increase the net bearing surface area for preload application compared to a single surface while keeping the overall thickness of the coupling to a minimum.

The first tubular element has a wall thickness. It is possible that said first tubular end contains a proximal section with a greater wall thickness relative to the tubular element and less

- 4 042325 wall thickness of the first end flange. Possibly, the second tubular end contains a proximal section with a greater wall thickness relative to the second tubular element and a smaller wall thickness of the second end flange.

Perhaps the seal is located between the ends of the pipe and is activated by tension applied by means of a tension tool and maintained by making the connection. Possibly, the seal is an O-ring placed in a groove in one end surface of one of the flanges and protrudes from it. Possibly an O-ring gasket seal is pre-installed in a groove in one of the flanges, possibly with metal-to-metal superglue, and possibly with a flange end protector to protect the ends until finally secured. The end flange protector is removed before the connection is made.

It is possible that the ends of the pipe are integral with the tubular element that completes the conduit, flowline, or riser. Optionally, the ends of the pipe further comprise a carrier portion that has a greater wall thickness than the thickness of the tubular members constituting the conduit, flowline, or riser. Perhaps the flanges have a large wall thickness relative to the bearing sections. Possibly, the sleeve end stop is slidable and rotatable along the bearing portion of the first tubular end. Possibly, the nut is slidable and rotatable along the bearing section of the second tubular end.

In accordance with another aspect of the present invention, a connection is provided, having a first tubular end, containing a first end flange, having an end surface and a sleeve containing a sleeve and an end stop, wherein said sleeve is located near said first end flange and said end stop is located near said first tubular end, wherein said sleeve is slidable along said tubular end, wherein the joint further has a second tubular end containing a second end flange having an end surface and a lock nut near and rotatable along said second end, characterized in that the end stop is inside bushing and is concentric with it, and the end stop is threaded for the bushing. Possibly the end stop is male threaded near its outer surface and possibly the sleeve is female threaded at least along a portion of the inner surface.

In accordance with another aspect of the invention, a system is provided for making a connection between a first tubular element and a second tubular element having coinciding passage holes for transporting fluid and an axis in the general direction of flow of said fluid through it, the system comprising a connection and a tensioning tool, wherein the connection has a first tubular end containing a first end flange having an end surface and a sleeve containing a sleeve and an end stop, wherein said sleeve is placed near said first end flange and said end stop is placed around said tubular end, wherein said sleeve is slidable along said the first tubular end, and the connection further has a second tubular end containing a second end flange having an end surface and a lock nut about and the possibility of rotation along the specified second tubular end a, wherein the tensioning tool serves to apply axial tension to said sleeve relative to said second tubular end, characterized in that said tensioning tool comprises a plurality of plungers, each plunger comprising a piston and a cylinder that apply tension to stretch the sleeve by extending the piston out of the cylinder .

The tensioning tool of the system of the present invention, wherein the tensioning tool comprises a structural body having a first structural end and a second structural end, at least one plunger having a fixed end and a free end, wherein the fixed end is attached to said first structural end, and said free end is movable towards and away from said second structural end, said free end having an insert for engaging the coupling sleeve.

Possibly the piston and cylinders are actuated using hydraulic fluid.

Possibly, the tensioning tool includes holding equipment for axial holding of said second tubular end relative to said cylinder and additional holding equipment for axial holding of said bushing of said first tubular end relative to said piston. Optionally, the axial retaining hardware and/or additional axial retaining hardware comprise several or more grooves in the second tubular end and a sleeve and ridges in the tensioning tool inserted into the grooves, which are preferably annular and preferably in a plane perpendicular to the axis, although they may be located under angle to it in a chevron pattern, etc. Optionally, the axial retaining hardware and/or additional axial retaining hardware comprise an annular bulge at the second tubular end and a sleeve and corresponding adjacent lugs in the tension tool.

In accordance with another aspect of the invention, a system is provided for making a connection between a first tubular element and a second tubular element having coinciding passage holes for transporting fluid and an axis in the general direction of flow of said fluid through it, the system comprising a connection and a tensioning tool, wherein the connection has a first tubular end containing a first end flange having an end surface and a sleeve containing a sleeve and an end stop, wherein said sleeve is placed near said first end flange and said end stop is located near said first tubular end, wherein said sleeve is slidable along said tubular end, wherein the connection further has a second tubular end comprising a second end flange having an end surface and a lock nut about and rotatable along said second tubular end , moreover, the tension tool serves to apply axial tension between the specified sleeve and the specified second tubular end, characterized in that the specified tension tool contains a structural body and a plurality of plungers near the hole for receiving the connection and parallel with the specified axis of the specified connection, each plunger having one end , attached to the specified structural body, and the free end, which is moved by the activation of the specified plunger and the insert located on the specified free ends of the specified plungers, containing the insert for engagement with the specified sleeve.

Plungers can be smaller and less expensive in that they apply the same preload as plungers arranged to act in compression, resulting in a more compact tensioning tool.

It is possible that the structural body of said tensioning tool contains at least a first and a second part, each part containing at least one plunger from the specified plurality of plungers, each plunger having an insert, the first and second parts being movable relative to each other to allow said the insert to engage the specified sleeve of the specified connection.

It is possible that said insert is placed in an insert holder. It is possible that the insert is radially movable in said insert holder.

Possibly, said tensioning tool contains an insert having a plurality of ridges, and said sleeve contains a plurality of grooves, while it is possible, when said insert is moved radially, said plurality of ridges engages in a plurality of grooves. Optionally, the insert holder comprises an insert plunger for moving said insert radially relative to said insert holder. Optionally, the tensioning tool further comprises a reactive insert located in a reactive insert holder attached to said structural body. It is possible that each of the first and second body parts contains at least one reaction insert. Optionally, said reactive insert is radially movable to facilitate engagement with said second tubular end. Optionally, the reaction insert is radially movable in the insert holder using a plunger.

It is possible that the insert is fixed in the specified holder for the reaction inserts in the structural housing, and the specified structural housing contains at least the first and second parts that move radially to/from the specified connection, after which the said inserts selectively engage and disengage the specified second end of the pipe of the specified connection. Possibly, the structural body contains at least the first and second parts that move radially on rails located transversely to the connection axis. When using a tension tool having first and second parts in accordance with the present invention, the present invention allows products, such as pipeline terminal equipment, to move through a tension tool located in an assembly line on a roller bed base on a ship, since the first and second parts of the tension tool can move away from each other enough for the PLET to pass through it.

Optionally, the alignment guide is provided in said structural housing, which may be radially movable or may be radially fixed. A matching guide can be used to axially align the inserts with the grooves. The matching guide may include an end stop to abut the joint portion so as to align the grooves with the ridges of the reaction inserts of the second tubular end, and may also align the ridges of the inserts with the grooves of the first tubular end of the joint. The alignment guide can also be used as an additional reaction surface for a snug fit of the connection part during tension.

It is possible that the tension tool additionally contains a rotator to tighten the lock nut of the connection. Perhaps the rotator is located at the free end of the plunger and can move with it. Perhaps the rotator is placed on the insert holder. rotator can

- 6 042325 contain a wheel with a smooth perimeter for tightening the lock nut in the area with smooth walls of the lock nut. Perhaps the smooth perimeter has a surface to facilitate increasing the contact force, such as rubber or other high friction surface. The rotator should only tighten the lock nut to low torque to lock the coupling in place. Thus, the rotator may not require either a wheel containing a splined portion to mate with a corresponding splined portion on the lock nut, or a toothed portion, or the like. in order to mate with the gear track on the lock nut.

The tensioning tool of the present invention may use plungers that apply the required tension force to preload the sleeve in compression, which can be more efficient than if the tension force to preload the sleeve is applied with tension plungers. Possibly, a tension force is applied to the connector through the inserts, which can be changed to suit the size of the connector/pipe. The preload application tools may be defined in the first and second portions, which may be opened such that the terminals may be lifted out using the crane of the lay vessel. The tension tool can be equipped with sensors so that the pipe/connector stop is in the correct location to engage the grooves with the tension tool inserts. At this point, the pipe may be held by a separate suspension block.

In accordance with another aspect of the invention, a system is provided for making a connection between a first tubular element and a second tubular element having coinciding passages for transporting fluid and an axis in the general direction of flow of said fluid through it, wherein the first and second tubular elements have a wall thickness, specified by the through hole and the outer surface, and the system contains a connection and a tension tool, and the connection has a first tubular end containing a first end flange having an end surface and a sleeve containing a sleeve and an end stop, and the specified sleeve is located near the specified flange and the specified end the stopper is placed near said first tubular end, wherein said sleeve is slidable along said tubular end, wherein the joint further has a second tubular end comprising a second end flange having th end surface, the proximal section and the lock nut about and the possibility of rotation along the specified proximal section, and a shoulder located between the second tubular end and the proximal section, and the tension tool serves to apply axial tension between the specified sleeve and the specified second tubular end, characterized in that that said tensioning tool comprises a body and a plurality of plungers near the connection receiving hole and parallel with said axis of said connection, each plunger having one end attached to said body and a free end containing engagement means for engaging said bushing, wherein said plurality of plungers serves to apply tension to said joint, said tension tool further comprising a matching guide near an opening in said tension tool to receive said joint, said matching guide being radially movable i from a retracted position allowing said connection to pass through said opening and a radially extended position to abut said shoulder of said connection to align said engagement means with said connection.

In accordance with another aspect of the invention, a system is provided for making a connection between a first tubular element and a second tubular element having coinciding passages for transporting fluid and an axis in the general direction of flow of said fluid through it, wherein the first and second tubular elements have a wall thickness, specified by the through hole and the outer surface, and the system contains a connection and a tension tool, and the connection has a first tubular end containing a first end flange having an end surface and a sleeve containing a sleeve and an end stop, and the specified sleeve is located near the specified flange and the specified end the stopper is placed near said first tubular end, wherein said sleeve is slidable along said tubular end, wherein the joint further has a second tubular end comprising a second end flange having th end surface, the proximal section and the lock nut about and the possibility of rotation along the specified proximal section, and a shoulder located between the second tubular end and the proximal section, and the tension tool serves to apply axial tension between the specified sleeve and the specified second tubular end, characterized in that that said tensioning tool comprises a body and a plurality of plungers near the connection receiving hole and parallel with said axis of said connection, each plunger having one end attached to said body and a free end containing engagement means for engaging said bushing, wherein said plurality of plungers serves to apply tension to the specified connection, while the specified tension tool additionally contains a matching guide near the hole in the specified tension

- 7 042325 nom tool for receiving the specified connection, and the structural body of the specified tension tool contains at least the first and second parts, each part contains at least one plunger from the specified plurality of plungers, and the first and second parts can move relative to each other, so as to selectively allow said connection to pass through said opening or abut said shoulder of said connection in order to align said engagement means with said connection. Optionally, the alignment guide has a portion attached to at least one of the first part of the structural body, preferably both. Possibly, the alignment guide is radially attached to the structural body.

In accordance with another aspect of the invention, a system is provided for confirming that a connection between the first and second tubular elements has been made, and the system includes a connection and a tension tool, and the connection has a first tubular end containing a first end flange having an end surface and a coupling containing a sleeve and an end stop attached to the sleeve, wherein said sleeve is placed near said flange and said end stop is placed near said first tubular end, wherein said sleeve is slidable along said tubular end, wherein the joint further has a second tubular end containing a second end flange , having an end surface and a lock nut about and the possibility of rotation along the specified second tubular end, and the tension tool serves to apply axial tension between the specified sleeve and the specified second tubular end, different said tensioning tool further comprises a camera having a field of view directed at said sleeve of said coupling to collect images of the sleeve while the sleeve is being tensioned. It is a non-contact optical technology for measuring strain in a sleeve.

Possibly the system further comprises a computer for executing an algorithm in order to estimate the relative strain in said bushing. Perhaps the algorithm is based on Digital Image Correlation (DIC) technology.

Perhaps the camera is a CCD (Charge Coupled Device) or CMOS (Complementary Metal Oxide Semiconductor) based camera.

It is possible that the sleeve sleeve is prepared by coating the outer surface of the sleeve. Possibly the coating is an ink, preferably providing a pattern that is a random, high-contrast mottled pattern that is typically created with standard spray paints. Perhaps the natural surface pattern of the sleeve may be suitable. The pattern (which may be natural or applied) is traced over the entire surface of the depicted material.

It is possible that the sleeve has a plurality of grooves along its portion and the smooth wall portion. The smooth wall area can provide the length of the sleeve within the camera's field of view for non-contact relative strain measurements.

Possibly the chamber is placed on the free end of the plunger and possibly on the insert holder. In this way, the chamber remains in a fixed known position relative to the coupling sleeve.

Possibly, the second camera is placed in the tension tool and has a field of view directed to the specified sleeve. It is possible that a light source is provided that is generally directed to a field of view identical to that of a camera. Possibly, the tensioning tool includes a chambered assembly that includes a casing containing the chamber. Perhaps the shroud also accommodates the light source. Possibly the housing also contains a second chamber.

Possibly the system further comprises the step of converting relative strain to mechanical stress using the Young's modulus of the sleeve material to provide a load score that the operator uses to judge whether or not there is sufficient load at said joint to activate and maintain compaction.

The system may include one chamber as part of a single DIC assembly, or two chambers as part of dual DIC assemblies, where the relative strain measurements may be compared with each other for redundancy and/or error checking.

The tensioning tool may be designed for use on a pipelay vessel or for subsea use.

Optionally, the system comprises the step of applying tension to said sleeve with said tensioning tool and tightening said lock nut to lock the first terminal and the additional terminal together so as to effect said connection.

Possibly the system further comprises a step of loosening and releasing the tension provided by the tension tool to collect images of the sleeve after removal.

- 8 042325

The present invention also provides a method for confirming that a connection between the first and second tubular members has been made, the method comprising the steps of capturing an image of at least a portion of a coupling sleeve of an unmade connection; application of tension in said clutch; locking the specified coupling to carry out the specified connection; loosening and releasing tension in said sleeve and capturing at least one additional image after removal; and comparing said images or data obtained from said images so as to obtain a relative strain measurement. Tension is applied axially by means of tubular elements.

Possibly, the method further comprises the step of comparing said relative strain measurement with a predetermined relative strain measurement in order to assess whether or not the connection is properly made. Possibly, the method further comprises the step of capturing yet another additional image during tension in order to evaluate the relative strain, and releasing the tension when said relative strain meets or exceeds a predetermined threshold. Possibly, the step of locking said coupling comprises the step of rotating the lock nut, preferably around the axis of said tubular elements.

It is possible that the sleeve sleeve is prepared by coating the outer surface of the sleeve.

Optionally, the method further comprises the step of converting relative strain to mechanical stress using the Young's modulus of the sleeve material in order to calculate the load score.

The present invention also provides a method for connecting a first and a second tubular element, the method comprising the steps of capturing an image of at least a portion of a sleeve sleeve of an unmade connection, applying tension in said sleeve, capturing at least one additional image while tensioning in said sleeve to to evaluate relative strain, and tension release when said relative strain satisfies or exceeds a predetermined threshold value.

Possibly, if the relative strain does not meet or exceeds a predetermined threshold, the tension continues and at least one more additional image is captured to evaluate the relative strain, and the tension is released when said relative strain satisfies or exceeds the predetermined threshold.

In accordance with another aspect of the invention, equipment is provided for supporting the end of a conduit or flowline, the equipment comprising a base with at least one raised support for supporting the end of the conduit or flowline, characterized in that the deployment frame is hinged to said base.

Possibly, the equipment further comprises a curved pipe section having first and second ends, wherein the first end is supported by, or held by, or located on said at least one raised support and has a terminal device, and said second end lags said base and contains an additional terminal device. Perhaps the curved pipe section is rigid to the extent that it maintains its curvature constant during normal use. Possibly, the curved pipe section allows for a simplified S-shape having one end supported on an elevated support lying horizontally, vertically, or at an angle therebetween, and a second end lagging from the base, preferably horizontally. Perhaps the curved pipe contains at least two sections, possibly welded together, at least one of which may be curved. Possibly, the curved section contains a straight section of the pipe, to which the specified additional terminal device is attached. The straight section may lag 10-20 m behind the frame.

Perhaps the base contains a frame consisting of a plurality of structural beams. Perhaps the beams have a square, round, oval or polygonal section. Possibly, at least one support shoe is pivotally fixed on said base.

Optionally, the end of the conduit or flowline is a first pipe end or a second pipe end of a connection of the type disclosed herein. Possibly a compound of the present invention, or any other compound, is disclosed herein.

Optionally, the equipment includes at least one articulation to facilitate the feeding of the equipment along the curved base of the stinger. The articulation can make it easier to match the back of the equipment to the curved base of the stinger.

It is possible that the equipment further comprises a shackle, boss, or other suitable connection to make it easier to pull the equipment along the stinger, preferably with a wire cable line. Possibly, the equipment comprises a base and a deployment frame hinged thereto to allow articulation in a vertical plane. Possibly a wire cable 9 042325 is attached to the deployment frame to pull the equipment along the stinger to facilitate feeding. Possibly the wire cable line is attached to the deployment frame with a brace and possibly a swivel.

This aspect of the present invention also provides a pipeline termination device comprising a base with at least one raised support to support the end of the pipeline or flowline, characterized in that the equipment further comprises an initial pipe section having a curved section and first and second ends, the first end is supported by or held by or located on said at least one raised support and has a terminal device, and said second end lags behind said base and contains an additional terminal device, wherein one of the terminal devices comprises a first end flange having an end surface and a coupling containing a sleeve and an end stop, wherein said sleeve is placed near said first end flange, and said end stop is placed near the first tubular end, wherein said sleeve is slidable along said tubular end, wherein the other end device comprises a second tubular end containing a second end flange having an end surface and a lock nut near and rotatable along said second end, wherein at least one of said sleeve and said second tubular end comprises a plurality of annular grooves.

This aspect of the present invention also provides a method for deploying a pipeline stub, wherein the pipeline stub is defined according to the invention, the method comprising the steps of connecting a stub at at least one pipeline joint to a second stub of the pipeline stub, supplying equipment with said piping along the pipe-laying vessel's stinger to its destination on the seabed.

Possibly, the method further comprises the step of pulling the pipeline terminal along the stinger using a wire cable line. Perhaps the wire cable line is placed near the sheave of the block, fixed, or on the frame, fixed on the seabed. It is possible that the wire cable line is wrapped around the driven drum on the pipelay vessel and unwinds from it. Possibly, the pipe-laying vessel has a pipe-laying line containing a base with a roller table, a tensioning tool for tensioning said connection of at least one of one of the hanger or tensioner and a pipeline stinger, the method further comprising the step of lifting said frame of said pipeline terminal onto the pipe-laying line on aft of the tensioning tool and at least one of the pipeline hanger or tensioner, wherein the straight section of said initial pipe section is in said tensioning tool.

Possibly, a wire cable line is placed near a block pulley fixed or on a frame fixed to the seabed to deploy a start end for a pipeline or flowline. The block may be attached to a pile driven towards the seabed or to an initiating block. Perhaps a wire cable line is wound around a driven drum on a pipe-laying vessel and is amenable to winding and unwinding from it.

In accordance with another aspect of the invention, a method is provided for connecting a pipeline to a subsea device, such as a manifold or a subsea wellhead tree, the method comprising the steps of providing equipment supporting an initial pipe section, the initial pipe section comprising a first terminal and a second terminal. , wherein the method further comprises the steps of connecting the second terminal device to the deployable pipeline terminal device and lowering the equipment to the seabed, axially aligning the additional terminal device with the first terminal device, wherein one of said first terminal device and the additional terminal device has a sleeve, and the other has a locking nut, and tightening one of the lock nut and the sleeve to form a joint, positioning an underwater tensioning tool near said joint, and applying tension to said sleeve with a by using said tensioning tool and tightening said lock nut to lock the first terminal and the additional terminal together so as to make said connection.

Possibly the subsea device has a flexible tubular element or a rigid tubular spool containing said additional terminal device.

Optionally, the method further comprises the step of pigging the pipeline before the first terminal docks with said additional terminal of the subsea device.

In accordance with the present invention, an underwater tensioning tool is provided comprising at least two parts, each part containing at least one plunger, said parts having a central hole for receiving a connection, the parts being able to move radially about the connection, which enables them to be clamped with each other near the junction.

- 10 042325

The present invention also provides a system for connecting the end of a pipeline or flowline on the seabed to a subsea device, the system comprising equipment having a base with at least first and second raised legs, each of which contains a saddle, said first raised leg serving to support of the first end device of the initial section (360) of the pipe, the second raised support serves to support an additional end device for connecting the coupling tubular element, and at least the first and second raised supports are spaced apart so as to allow the specified first end of the terminal device to be connected to the specified second end of said connection, and for receiving a tensioning tool for applying axial tension to the connection sleeve. Perhaps the tension tool is the tension tool in the present invention. Possibly, the tensioning tool comprises first and second parts forming a neck, wherein the first and second parts are hinged to open near said joint between said first and second raised supports to receive said joint in said neck, and close near said joint, whereupon said tension tool is activated to apply tension to said sleeve of said joint. Optionally, the raised supports are configured to support the terminal in a horizontal plane. Possibly the tensioning tool is lowered in line from the surface vessel and aligned between the raised supports by a diver or a remotely operated vehicle (ROV).

The terminal may be positioned horizontally to connect to a corresponding end node in a horizontal plane, or may be positioned vertically to connect to a corresponding end node in a vertical plane (not shown in the drawings).

In accordance with another aspect of the invention, a connection is provided, comprising first and second tubular elements having a matching bore, wherein said first tubular element is lined on the inside with an inner lining having a first flow in the annular region therebetween, said second tubular element is lined on the inside with an inner lining, having a second passage in the annular space between them, wherein said first tubular element has an end flange and the second tubular element has a corresponding end flange, characterized in that said flange and said corresponding flange contain an additional passage that connects said first passage with said second passage.

In accordance with this aspect of the invention, a system is also provided comprising a pipeline containing a plurality of connections, each connection comprising first and second tubular elements having a matching bore, said first tubular element being internally lined with an inner lining having a first flow in the annular region therebetween. , wherein said second tubular element is lined from the inside with an inner lining having a second flow in the annular space between them, wherein said first tubular element has an end flange and the second tubular element has a corresponding end flange, characterized in that said flange and said corresponding flange contain an additional flow , which connects the specified first duct with the specified second duct, and the system additionally contains a manifold to maintain a constant flow through the specified duct, at least along the section of the specified pipeline.

Possibly the duct contains a port extending through said flange and possibly an additional port extending through said corresponding flange. Possibly at least one of the flange and the corresponding flange has an annular groove to receive an o-ring, and possibly the port extends into said groove. Possibly, the connection further comprises an O-ring located in said groove. Possibly, the O-ring is bonded in such a way as to prevent the groove O-ring from falling out during the final fastening of the connection. Possibly the O-ring has a plurality of through holes through it to allow fluid to flow between adjacent flanges and possibly slots. Possibly the O-ring sits in a groove with the annulus at the back.

Possibly, the inner lining has an end section that fits into an annular cavity in said first tubular element and possibly in said second tubular element. The annular cavity has a finite depth, possibly substantially equal to the thickness of the inner lining. It is possible that the annular cavity has a smooth transition region between the inner diameter of the tubular element and the final depth. Optionally, an annular gap is provided between the end of the inner lining and the end of the annular cavity.

The inner lining may be made of HDPE (high density polyethylene), PVDF (polyvinylidene difluoride) or XLPE (cross-linked polyethylene). Perhaps the inner lining is formed by extrusion.

This aspect of the present invention also provides a method for preventing the accumulation of gases between the inner lining and the tubular element in a pipeline containing at least

- 11 042325 two tubular elements with a connection between them, an annular region between each inner lining and the corresponding tubular element, wherein at least one duct in the said annular region and the connection contains an additional duct, the method comprising the steps of allowing the fluid to flow through the specified an additional passage between said passages in said annular region between said inner linings and said tubular elements.

Possibly, the method further comprises the step of causing movement in the fluid along the passageway between the inner lining and the tubular into the manifold. Perhaps the manifold is located onshore. Perhaps the manifold is placed underwater. It is possible that the manifold is located underwater and the additional manifold is located on the shore. Perhaps a plurality of manifolds are spaced apart along the pipeline. The manifold may contain a pump. Possibly the pump is a negative displacement pump that applies a traction force to the fluid. Possibly the pump is a positive displacement pump that causes movement in the fluid. It is possible that the piping is connected to the manifold with a flange connection. Possibly the compound is the compound disclosed herein with respect to FIG. 1-3, or any other compound disclosed herein. Possibly the joint comprises an annular seal having a plurality of axial through holes therethrough and possibly positioned in a groove having a contact area for the annulus to contact so as to form a seal and an annulus between the annular seal and the groove wall to facilitate fluid flow through the connection. Optionally, a plurality of through holes are provided which extend from the annular passage into the axial passage between the inner lining and the tubular member.

The inventor noted that in lined and lined pipelines, it is important to prevent corrosion at/near joints between pipe joints in the pipeline, flowline, or riser.

The present invention also provides a pipeline containing a tubular element having a pipe end containing a flange, the flange having an outer surface, an inner surface and an end surface, the end surface having an annular groove for receiving an annular seal, the annular groove being lined on the inside with an inlay, characterized in that that the tab extends from the specified annular groove to the inner surface.

Perhaps the inlay extends along the inner surface, perhaps 25-100 mm and possibly 50-75 mm. It is possible that the pipeline is lined from the inside with an internal lining. Perhaps the inner lining overlaps the tab. Perhaps the inlay is made of stainless steel or inconel. It is possible that a compression ring is used at the flanged end of a pipeline-to-liner joint, with the compression ring covering the tab. It is possible that the inner lining is spaced apart from the inner wall of the tubular element with the ability to provide a duct for the fluid, and the through hole is placed in the flange, and the additional through hole in the specified insert is aligned with the through hole in order to connect the duct with the annular groove with the possibility of exchanging fluid , preferably so as to provide a flow through the end of the pipe and into the corresponding end of the pipe connected to it in order to provide a continuous flow along the pipeline. Optionally, the tab is formed with an annular groove in at least one end surface of the flange to provide an annular passage for the circulation of gases.

In some conduits, flowlines, or risers, it is advantageous to maintain the temperature of the transported fluid. Therefore, it is preferable to insulate the pipeline, flowline or riser. The inventor noted that it is important not to have dams in the pipeline, flowline or riser where temperature variations can not only change the temperature of the transported fluid, but can also cause the formation of hydrate crystals and/or flow patterns in the fluid.

The present invention also provides an insulated pipeline comprising first and second inner tubular elements having a concentric outer working tube and insulation in the annulus therebetween, the tubular elements having a pipe end and a connection therebetween, the connection comprising a first pipe end comprising a first hub and a first end flange having an end surface and a sleeve comprising a sleeve and an end stop attached to the sleeve, said sleeve being placed near said first end flange and said end stop being placed around said first pipe end, said sleeve being slidable along said end pipes, and the second end of the pipe contains a second hub, a second end flange having an end surface and a lock nut about and the possibility of rotation along the specified first end of the pipe, while the connection contains an insulating sheath.

Perhaps the outer working tube is welded to the hub. Perhaps the seal is located between the insulating sheath and the joint. Possibly a seal is provided on each con

- 12 042325 insulating sheath, possibly in an annular or semi-annular groove. Possibly the insulating sheath contains braids which can be fitted radially in place to the joint and possibly held in place in the joint by tapes to prevent radial separation of the braids from the joint. The insulating sheath may include a contoured inner surface that substantially coincides with the contours of the joint, including the sleeve, hubs, grooves or grooves, and the working tube. It is possible that the insulating sheath overlaps the insulated pipe in order to prevent bridging.

For the avoidance of doubt, the system, equipment, or method of the invention may comprise any of the aspects and optional features and steps set forth herein.

Brief description of the figures

For a better understanding of the present invention, reference will now be made, by way of example only, to the accompanying drawings, in which:

fig. 1 is a perspective view in section of a joint in accordance with the present invention;

fig. 2 is a cross-sectional view of the joint shown in FIG. 1, in the final stage of the connection;

fig. 3 is a side view of the joint shown in FIG. 1, in the final stage of the connection;

fig. 4 is an enlarged cross-sectional view of a joint in accordance with the present invention containing an alternative coupling;

fig. 5 is a perspective view of the BX-ring used in the connection shown in FIG. 1;

fig. 6 is an enlarged side view in cross section of the coupling sleeve of the joint shown in FIG. 1;

fig. 6A is a perspective view of the sleeve shown in FIG. 6;

fig. 7 is a perspective view of a tensioning tool according to the present invention for use in making a joint according to the present invention;

fig. 7A is a top plan view of the tension tool shown in FIG. 7;

fig. 7B is a side elevational sectional view of the tensioning tool shown in FIG. 7;

fig. 8A is a perspective view showing the first half of the tension tool shown in FIG. 7 with the connection shown in FIG. 1 between two tubular members in a tensioning tool and suspension equipment for use in controlling the deployment of a string of tubular members;

fig. 8B is a perspective view showing the first half of a further embodiment of a tension tool with the connection shown in FIG. 1 between two tubular members in a tensioning tool and suspension equipment for use in controlling the deployment of a string of tubular members;

fig. 9 is a schematic side cross-sectional view of a portion of the tensioning tool shown in FIG. 8B;

fig. 10 is a perspective view showing a portion of the sleeve shown in FIG. 6 and showing the insertion portion of the tensioning tool;

fig. 10A is a cross-sectional view showing the groove and the crest of the groove;

fig. 10B is a schematic view of a portion of the tension tool of FIG. 7 showing a rotator for tightening a joint lock nut, the rotator being attached to an insert holder;

fig. 11 is a partial sectional perspective view of a portion of the second half of the tension tool shown in FIG. 7 containing a chamber system in accordance with the present invention, with the connection placed in the tensioning tool, shown in section;

fig. 12 is a perspective view of a camera block for use in the system shown in FIG. eleven;

fig. 12A is a schematic perspective view of the camera block indicating the field of view of the camera block;

fig. 13 is a perspective view of an alternative chamber for use in the tension tool shown in FIG. eleven;

fig. 13A is a circuit diagram showing the operation stage of the camera shown in FIG. 13;

fig. 13B is a circuit diagram showing steps in the operation of the chamber shown in FIG. 13;

fig. 14 is a schematic diagram showing a prior art S-lay system for laying a pipeline on the seabed;

fig. 15 is a schematic diagram showing a prior art J-lay system for laying pipeline;

fig. 16 is a general view of the terminal device of the pipeline in accordance with this

- 13 042325 of the invention, shown with a flexible pipe connected to it;

fig. 17 is a side view of the tubing and coiled tubing terminal shown in FIG. 16;

fig. 17A is a diagram showing the final step in the method for starting a pipeline installation according to the present invention;

fig. 17B is a diagram showing an initial stage in the pipeline laying start method according to the present invention;

fig. 18 is a side view of a pipeline stub and coiled tubing with a tensioning tool of a system for connecting a pipeline to a subsea device in accordance with the present invention, showing a step in assembling a pipeline stub with coiled tubing provided with the respective stub;

fig. 19 is an end view, in partial section, of the pipeline terminal and coiled tubing with tensioning tool shown in FIG. 18;

fig. 20 is a side view of the pipeline termination and coiled tubing with tensioning tool shown in FIG. 18, the tensioning tool being shown in cross section;

fig. 21 is a schematic side cross-sectional view of a portion of lined pipeline and a connection between sections of pipeline, in accordance with a further aspect of the present invention;

fig. 21A is a cross-sectional view of a portion of the lined pipeline shown in FIG. 21;

fig. 22 is a schematic side cross-sectional view of a portion of lined pipeline and a connection between sections of pipeline, in accordance with a further aspect of the invention;

fig. 22A is a schematic view of a pipeline in accordance with the present invention, containing a pipe connection with an internal lining in accordance with the present invention;

fig. 22B is a schematic view of the end of a pipeline in accordance with the present invention terminating in an onshore manifold;

fig. 23 is a schematic cross-sectional view of a portion of a pipeline containing a pipe end in accordance with a further aspect of the invention;

fig. 24 is a schematic cross-sectional view of a portion of a conduit containing a pipe end in accordance with a still further aspect of the invention;

fig. 25A is a side cross-sectional view of a portion of an insulated conduit in accordance with another aspect of the present invention;

fig. 25B is a cross-sectional view of the insulated connection of the part shown in FIG. 25A.

Description of preferred embodiments of the invention

Referring to FIG. 1-3, a connection 1 is shown between two tubular elements 2 and 3 having substantially coinciding fluid passages 4 and 5.

Each tubular element 2 and 3 can be made from any suitable material such as mild steel, high strength steel, stainless steel, plastic material or composite materials. The tubular element may have a circular cross section. The tubular elements 2 and 3 are shown unlined on the inside, although the tubular element can also be lined on the inside with a suitable corrosion-resistant inner lining. The tubular elements 2 and 3 may be of any suitable length and may have a pipe end 6 and 7 at each end in order to connect to an adjacent tubular element at each end so as to form a column of tubular elements.

In this example, tubular members 2 and 3 are made from high strength steel, such as high carbon steel. Tubular elements 2 and 3 are completed from four sections of pipes 12 m (40 ft) long (not shown in the drawings), which can have a peripheral bevel on the outer surface of each end of the sections of the tubular element along the wall thickness of the tubular element and be welded together with butt welds in the space provided by the adjoining cones so as to form a tubular member 48 m (160 ft) long (not shown in full). Welded four sections of the tubular element contain the ends 6 and 7 of the pipe at each end. The welded four sections of tubular and pipe ends 6 and 7 may be referred to as a quadruple joint. The tubular elements 2 and 3 have an inner surface delimiting the respective through hole 4 and 5 and an outer surface defining the wall thickness 13 between them. Alternatively, the tubular element may comprise one (12 m), two (24 m, known as a double), three (36 m, known as a triple) or other suitable number of welded sections.

Connection 1 comprises first and second pipe ends 6 and 7 which are welded to tubular members 2 and 3 respectively, with peripheral butt welds 8 and 9. Welds 8 and 9 may be machined to form a smooth, continuous outer surface. The inner surface is generally smooth. Machining of welds

- 14 042325 can also improve fatigue performance. Pipe ends 6 and 7 have substantially congruent passages 10 and 11 which also substantially coincide with passages 4 and 5 to form a continuous fluid passage. It should be noted that the pipe ends 6 and 7 may alternatively be adhesively bonded to the tubular elements 2 and 3 or otherwise connected. Alternatively, the ends 6 and 7 of the pipe may be integrally formed with the tubular elements 2 and 3.

The first pipe end 6 has a distal end section 12 having a wall thickness that is substantially equal to the wall thickness 13 of the tubular element 2. The first pipe end 6 also has a proximal section 14 with increased wall thickness, having an outer wall with a larger diameter relative to the outer diameter of the tubular element 2 The wall thickness of the proximal portion 14 may be approximately twice the wall thickness 13 of the tubular members 2 and 3, although it may be of any suitable thickness. A shoulder 15 is formed between the outer surface of the distal portion 12 and the enlarged outside diameter of the proximal portion 14. The shoulder 15 may be bevelled. The first end 6 of the pipe also has a proximal end flange 16 with a greater wall thickness relative to the proximal portion 14 and may be approximately three times the wall thickness 13 of the tubular 2, although it may be any suitable thickness. A shoulder 16' is formed between the outer surface of the proximal portion 14 and the outer diameter of the proximal end flange 16. The shoulder 16' may be perpendicular to the pipe axis X-X or may be beveled at any suitable angle. The proximal end flange 16 has a substantially flat end surface 17 lying in a plane perpendicular to the axis X-X of the connection 1. The flat end surface 17 has a continuous groove 18 that is substantially concentric with and located between the inner and outer walls of the proximal end flange 16. The continuous groove 18 is sized and shaped to receive the first portion of the annular seal 19 while leaving the second portion protruding from the continuous groove 18. The annular seal 19 may be placed loosely in the groove or may be adhesively bonded therein with an adhesive, such as an adhesive. metal-to-metal, or may be sized to form a friction fit between them. The first pipe end 6 may be made from a single piece of material such as high strength steel.

The O-ring 19 may be an annular BX butt gasket that is generally CNC machined. The BX annular butt gasket is energized by providing axial force when making connection 1. The VX annular butt gasket can, as shown in FIG. 5 may have chamfered corners 19' although the O-ring may have a square section. The O-ring can be made from a high strength seal or stainless steel, preferably having a high chromium content. The O-ring 19 can be made of stainless steel, such as Grade 316L, or Inconel, such as Grade 825.

The first pipe end 6 has a sleeve 20 containing a sleeve 21, shown in detail in FIG. 6 and 6A. The sleeve 21 is a tubular element having a circular cross section and may be made of high strength steel. Sleeve 21 has a wall thickness defined by an inner surface with a diameter substantially equal to or slightly larger than the outer diameter of the proximal end flange 16 so that, in use, the sleeve 21 can slide over the outer surface of the proximal end flange 16. The wall thickness of the sleeve is also given by the outer surface, which may have a constant diameter, as shown in the embodiment of FIG. 4, or may have a recessed body section 21' with a slightly smaller diameter, as shown in FIG. 1-3, 6 and 6A. The sleeve 21 has internal threads 22 retracted to the internal surface along the proximal end section 23. The sleeve 21 also has internal threads 24 retracted to the internal surface along the distal end section 25. The external surface of the sleeve 21 has beveled ends 26 and 27 and a plurality 28 of parallel peripheral grooves covering the near end section 23.

Referring to FIG. 1, the sleeve 20 also includes an end stop ring 30 having an inner surface defining a diameter substantially equal to or slightly larger than the outside diameter of the proximal end portion 14 such that, in use, the end restrictor ring 30 is slidable along the proximal end portion 14. Inner surface may be smooth. The end stop ring 30 is a continuous ring having an outer surface with a diameter substantially equal to the inner diameter of the sleeve 21. The outer surface includes an external thread 31 which mates with the internal thread 24 of the end section 25 of the sleeve 21. During the construction of the joint 1, the sleeve 21 slips out of of the free end for the end 6 of the pipe along the near end flange 16, after which the end restrictive ring 30 is screwed into the sleeve 21 and remains fixed in it. It should be noted that the end stop ring 30 does not separate from the sleeve 21 at the time the connection is finally secured in the field.

To simplify assembly, the end stop ring 30 may include two semi-circular clamshell sections (not shown) which can be fitted radially in place to the proximal end section 14 of the end 6 of the pipe. The screw threads on each of the grapple portions match and align to form a continuous thread about the outer surface of the grapple. During assembly, the sleeve 21 then slides over the free end of the pipe end 6 and threads onto the clamshell portions forming the end stop ring 30.

Alternatively, as shown in FIG. 4, the end stop ring 30 may be integrally formed with the sleeve 21 such that the sleeve is formed in one section and then slips over the pipe end 6 before the pipe end is welded or otherwise attached to the tubular member 2. The sleeve shown in fig. 4 also shows an outer diameter having a constant diameter except for the distal end bevel 27' and a plurality of parallel circumferential tension grooves 28' enclosing the proximal end portion 23'.

The groove 28' is a particular type of groove, with a substantially flat bottom 29 with curved corners 29' meeting the flat bottom 29 with the substantially vertical sidewalls 29. A further example of the groove is shown in FIG. 10A, in which the groove 28' comprises a flat bottom 29 with curved corners 29' meeting the flat bottom 29 with substantially vertical side walls 29. The curved top 29' mates the side walls 29 with the substantially flat tops 28. The cross section of the groove resembles a U -shaped form.

The second end 7 of the pipe has a distal end section 40 having a wall thickness that is substantially equal to the wall thickness of the tubular element 3. The end of the distal end section 40 is welded to the end of the tubular element 3. The second end 7 of the pipe also has a proximal section 41 with increased wall thickness, having an outer wall with a larger diameter relative to the outer diameter of the tubular 3. The wall thickness of the proximal portion 41 may be approximately twice the thickness 13 of the wall of the tubular 3. A shoulder 42 is formed between the outer surface of the distal portion 12 and the enlarged outer diameter of the proximal portion 41. The shoulder 42 may be beveled. The second end 7 of the pipe also has a proximal end flange 43 with a greater wall thickness relative to the proximal section 41 and can be approximately three times the wall thickness 13 of the tubular element 3. A shoulder 44 is formed between the outer surface of the proximal section 41 and the outer diameter of the proximal end flange 43. Shoulder 44 may be perpendicular to the X-X axis of the pipe, or may be beveled at any suitable angle. The proximal end flange 43 has a substantially flat end surface 45 having a continuous groove 46 that is substantially concentric with and located between the inner and outer wall of the pipe end 6 . The continuous groove 18 is sized and shaped to receive the second portion of the annular gasket 19. The second pipe end 7 may be made from a single piece of material such as high strength steel.

The outer surface of the proximal end flange 43 of the second pipe end 7 is sized to coincide with the outer surface of the proximal end flange 16 of the first pipe end 6 so that the sleeve 20 is slidable thereon.

The lock nut 50 is essentially tubular and can be made from high strength steel. The lock nut 50 has a wall thickness defined by an inner surface with a diameter substantially equal to or slightly larger than the outer diameter of the proximal portion 41 so that, in use, the lock nut 50 can slide over the outer surface of the proximal end flange 16. The wall thickness is also specified by the outer surface , which has a male thread 51 disposed along a proximal end 52 such that, in use, the male thread 51 threads into the female thread 22 of the sleeve 20. The distal end of the lock nut 50 includes a bevel 53 and the proximal end of the lock nut 50 includes a perpendicular surface 54 , which abuts the perpendicular shoulder 44 of the proximal end flange 43. Alternatively, the proximal end of the lock nut 50 may comprise a chamfered surface to provide a corresponding chamfered contact surface if the proximal end flange 43 includes it.

A plurality of 47 parallel circumferential tension grooves is formed in the proximal portion 41 in the tension region 49 between the proximate region 48 near which the lock nut 50 is located and the shoulder 42. A plurality of at least two circumferential tension grooves in the plurality 47 may be provided. 3 to 20 parallel circumferential tension grooves in set 47, and optionally 6 to 15 and preferably 9 such grooves in set 47. Each groove may have a width of 3 to 25 mm, preferably 5 to 15 mm, and most preferably about 10 -12 mm. Each groove may have a depth of 2 to 20 mm, preferably 5 to 15 mm, and most preferably 5 to 7 mm. The grooves can be separated from each other by a distance approximately equal to the width of the groove. A plurality of 47 parallel peripheral grooves are spaced from shoulder 42 by 25-75 mm. The tension grooves may alternatively be any suitable shape of the tension groove having a profile other than the groove profile, such as a V-groove, a V-sawtooth, an oblique V-groove, a U-groove, or other suitable profile.

- 16 042325

When the connection 1 is to be finally secured, the tubular elements 2 and 3, containing the ends 6 and 7 of the pipe, are fitted on the spot to each other. The end surface 17 of the end 6 of the pipe is placed in close proximity and in axial alignment with the end surface 45 of the end 7 of the pipe. The O-ring 19 is held, for example, by metal-to-metal adhesive, in a groove 18 of the pipe end 6 which is in axial alignment with the groove 46 of the pipe end 7. A tension tool, such as the tension tool 100 shown in FIG. 7A-8A, or tension tool 100A shown in FIG. 8B is used to apply an axial force to the sleeve 20 of the first pipe end 6, with a force reaction against the second pipe end 7. The sleeve 21 of the clutch is placed under tension and can be stretched, with deformation within the values of the elastic limit. The lock nut 50 is then screwed into the socket 20 to lock the ends 6 and 7 of the pipe together, making the connection. It should be noted that the lock nut 50 is simply crimped to lock the sleeve in place. It should be noted that the axial force is not provided by tightening the lock nut 50. The force provided by the tension tool 100 is then released and the force provided by the tension in the sleeve is transferred to the lock nut, which in turn is transferred to the proximal end flange 43. The tension in the sleeve 20 remains sufficient to provide a constant force to the O-ring 19 so as to provide a fluid tight seal to prevent fluid from passing between the port 3, 5, 10, 11 and the surrounding seawater surrounding the joint. The tension in the sleeve 21 of the coupling 20 is preferably within the elastic limit values of the material of the sleeve 21, which is preferably high strength steel.

For example, the tension force provided by the tension tool 100 is approximately 20,000 kN (2,000 tons) for a connection in accordance with the present invention suitable for use in a pipeline with a diameter of 16 inches.

Tension tool 100 includes first and second halves 97 and 98. Halves 97 and 98 are nearly mirror images of each other and are structurally attached to each other in use. Fig. 8A only shows the second half 98 to show details of its parts in use. Fig. 8B is a further embodiment of the tension tool shown in FIG. 8A. Similar parts are identified by identical reference numbers. The second half 98 has a structural hull 101 seated on structural crane rails 99. The structural crane rails 99 may be part of a pipe-lay vessel (not shown) used in seabed pipeline installations. Structural body 101 has a first structural end 102 with a semicircular receiving hole 103 for receiving a tubular element 2 and 3 containing connection 1. Structural body 101 further includes a second structural end 104 with a semicircular outlet 105 to enable the tubular element 2 and 3 containing the connection 1, extend from the tensioning tool 100 into the hanger 105' of the pipe-lay barge. If the pipeline is laid at shallow depths, a tensioner (not shown) may be used instead of hanger 105'. In addition, the hanger 105' and tensioner (not shown) can be used at great depths and at shallow depths.

The first and second structural elements 102, 104 are spaced apart and engage with the skin 106 so that a cavity is defined. The skin 106 may be made of a structural material, such as structural steel, and may be a mechanically stressed element when the tension tool 100 is operated. The three double-acting hydraulic plungers 107, 108, 109 can be spaced evenly about the X-X axis by approximately 60° from each other in the second half 98. The plungers 107, 108, 109 (only two are shown in FIGS. 8A and 8B) comprise a cylinder 110, 111 attached to the first structural end 102, and an axially movable piston 112, 113 (only two are shown in FIGS. 8A and 8B) having a free end movable towards and away from the second structural end 104. An insert holder 114 is attached to the free end of the piston 112 such that the insert holder 114 is movable with the free end of the piston 112, 113. The insert holder 114 comprises a rectangular front plate 116 with an opening near joint 1, opposing at an angle slightly less than 180° near joint 1, and corresponding back plate 118, with the top plate 120 engaging the front plate 116 with the back plate 118 so that a cavity is defined that is open to si X-X.

Axially aligned top sliders 122, 123 protrude outward from the top end plate 120, which are slidable along and to opposite parallel sides of the top structural girder 124 (not shown) engaging the first structural end 102 with the second structural end 104. 124 may include integral rails 125 on each of the parallel sides, on which sliding members 122, 123 are able to slide. elements 131 and a structural crane rail 132 are provided for the side end plate 120. Thus, one structural rail 124, 129, 132 for crane beams is provided for each plunger 107, 108, 109. One structural rail 124, 1 29, 132 for crane beams is provided for each of the top, bottom, and side end plates 117, 120, 121 of the insert holder 114.

The insert 135 is placed in a hole defined between the front plate 116 and the back plate 118 and is radially fixed. One embodiment of insert 135 is shown in FIG. 10, in which a portion of the insert 135 fits in place against the sleeve 20 of the first end 6 of the pipe of the connector 1 to be pulled and locked in place so as to effect the connection 1. For clarity, in FIG. 10 does not show details of the insert holder 114, nor additional details regarding connection 1.

The outer surface of the sleeve 21 has a bevelled end 27 and a plurality of 28 parallel peripheral grooves covering the proximal end portion 23.

Insert 135 includes a body 140 that defines a segment 139 of the circle. The insert 135 is preferably made from high strength steel, but may be made from any suitable material such as stainless steel, and preferably from a material that has similar strength properties to those of the sleeve 20 and proximal portion 41 such that any expansion over the area of the grooves is equal to this in sleeve 21 and proximal section 41. It is possible that insert 135 is made of a material having stronger strength properties relative to the strength properties of sleeve 20 and proximal section 41 in such a way that, preferably, sleeve extension occurs mainly in sleeve 21. Segment 139 may oppose under an angle slightly less than 180°, although it can be opposed at any suitable angle, for example 45-180°. Segment 139 has a sleeve engaging surface 141. The sleeve engagement surface 141 has a plurality of parallel groove ridges 142, shown in detail in FIG. 10A. The number of groove ridges 142 preferably corresponds to the number of grooves 28 in the sleeve 21 such that the plurality of groove ridges 142 correspond to and fit into the plurality of grooves 28 in the sleeve 21. Each groove ridge 142 fits into the grooves 28. The groove ridges 142 may be of this size. that they fit into the grooves 28, providing little space to move between them. In particular, during tension, the sleeve 21 should stretch slightly, perhaps 0.5 mm along its length.

The groove ridge 142 is a type of ridge with a substantially flat top 143 with curved corners 144 meeting the flat top 143 with substantially vertical sidewalls 145 and a curved portion 146 joining the sidewalls 145 with the substantially flat troughs 147.

Insert 135 may be radially fixed or may be radially movable as shown in FIG. 9. The double acting hydraulic piston and cylinder 149' are configured to act radially between the back surface of the insert 135 and the side end plate 117. The front plate 116 and back plate 118 determine the direction of movement of the insert 135. It should be noted that other mechanisms can be used to to move the insert towards and away from connection 1, including, but not limited to, any suitable linear actuator such as solenoid electric actuators; and pneumatic plungers. Other mechanisms, such as a mechanical linkage, which convert rotational movement into radial movement of insert 135 relative to connection 1. It should be noted that piston and cylinder 149' may also be single acting.

One or more rotators 155 are provided on the distal surface of back plate 118 such that rotator 155 moves with insert holder 114 and thereby axially aligns with sleeve 20 in use. As shown in FIG. 10B, rotator 155 includes wheel 156 and electric motor 157 for driving wheel 156. Electric motor 157 may be electrically, hydraulically, or pneumatically powered. The wheel 156 is axially aligned and resiliently movable to sit on the lock nut 50 of connection 1 in use. In use, the wheel 156 rotates transversely to the X-X axis such that when the motor 157 is activated by the controller 158, the wheel 156 rotates to rotate the lock nut 50 along the screw threads 22, 51 relative to the sleeve 20.

The tension tool 100 also includes a reaction insert 150 to engage a plurality of 47 parallel circumferential tension grooves formed in the proximal portion 41 of the second end 7 of the pipe. The reaction insert 150 is housed in an integral insert holder 151 which is integral with the body 152 of the second structural end 104. The reaction insert 150 is radially fixed in the integral insert holder 151. The reaction insert 150 is interchangeable with a different size insert (not shown) for different size connections for different size conduits.

A replaceable end stop 160 is provided in the end stop holder 161 in the housing 152 of the second structural end 104. The end stop 160 is radially fixed in the end stop holder 161 to protrude from the insert holder 161. It is envisaged that a physical end stop may not be required, instead a sensor is used to

- 18 042325 in order to read the axial location of the grooves relative to the tension inserts 135 and reaction inserts 150.

When used, tension insert 135, reaction insert 150, and end stop 160 are selected for line diameter and connection 1. It is contemplated that one tension tool 100 is used to permanently secure and break connections in a range of sizes, preferably including, but not limited to , connections for use in pipelines with a diameter of 2 to 16 inches (50-400 mm). Tension insert 135, reaction insert 150, and end stop 160 are installed in respective holders 114, 151, 161 in tension tool 100.

The controller 181 controls a valve (not shown) to permit hydraulic fluid to flow from the hydraulic power unit 180 through a hydraulic circuit (not shown) to/from the cylinders 110, 111 of the plungers 107, 108, 109 in the second half 98 of the tensioning tool 100 and respective plungers (not shown) in the first half 97 to fully retract their respective pistons 112, 113.

The first end 6 of the pipe of the first tubular element 2 is placed on the base of the pipe-laying vessel. The second end 7 of the pipe of the second tubular element 3 is fed and moved in such a way that the first end 6 of the pipe is axially aligned with the second end 7 of the pipe. All end protectors are removed either on the extended roller table base (known as pipe-lay) or in the storage rack, before the pipeline joints are located in the pipe-lay. The end surface 17 and end surface 45 are positioned abutting each other, after which the seal 18 is inserted into the groove 46. A shear pin SP (FIG. 4) is placed between the end stop 30 of the coupling 20 and the proximal portion 14 of the first pipe end 6 to maintain the axial location couplings 20.

Alternatively, the shear pin is not placed between the sleeve 20 and the first end 6 of the pipe, and therefore no shear pin is used. From FIG. 1, it should be noted that the sleeve 20 slides towards the second end 7 of the pipe such that the proximal end portion 23 slides over the end flanges 16 and 43. The lock nut 50 slides along the proximal portion 41 towards the first end 6 of the pipe such that the male thread 51 of the lock nut 50 engages the internal threads 22 of the box 20. The threaded joint is set loosely by turning the lock nut 50 relative to the box 20 hand-tight, with a predetermined number of turns, so that the axial location of the box is known. The connected tubular elements 2 and 3 can then move along the base into the tension tool 100.

The two halves 97 and 98 of the tensioning tool 100 are fitted in place to the connection 1 radially, on either side of the connection. Each half 97, 98 can be slidable along transverse structural crane rails 99 towards and away from connection 1. Connection 1 is axially aligned such that shoulder 42 abuts end stop 160. This aligns reaction inserts 150 with a plurality of grooves 47 in the second end of the 7th pipe. The crests 142 of the grooves of the tensioning insert 135 are thereby aligned with the known position of the grooves 28. The two halves 97 and 98 move towards each other along the crane beams 99 in such a way that the crests of the grooves of the reaction inserts 150 are inserted into the plurality of grooves 47 at the second end 7 of the pipe, and the ridges 142 of the grooves of the take-up insert 135 are inserted into the grooves 28. The two halves 97 and 98 are then fixed together near the connection 1 in such a way that the semicircular inlet and outlet holes 103 and 105 of the second half 98 oppose the corresponding semicircular inlet and outlet holes 173 and 175 of the first half 97 to form completely round inlets and outlets. The ability to attach the two halves 97 and 98 to each other provides a positive indicator that the groove ridges 142 and (not shown) are properly engaged with their respective grooves 28 and 51.

Alternatively, the tension insert 135 is radially movable on and is initially set to its radially retracted positions on its respective displacement mechanisms 149 (not shown). The controller 181 controls a valve (not shown) to permit hydraulic fluid to flow from the hydraulic power unit 180 through a hydraulic circuit (not shown) to/from the cylinders 110, 111 of the plungers 107, 108, 109 in the second half 98 of the tensioning tool 100 and of the respective plungers (not shown) in the first half 97 to fully retract their respective pistons 112, 113 and move the insert 135 into alignment with the grooves 28 in the sleeve 20. The tension inserts 135 in the first and second halves 97, 98 are then radially moved by their respective a moving mechanism 149 to engage the sleeve 20. A plurality of ridges 142 of parallel peripheral tension grooves of the tension insert 135 engage with a plurality of parallel peripheral tension grooves 28 of the sleeve 20 of the first end 6 of the pipe.

The curved corners 144 of the groove ridge 142 and the curved corners 29' of the groove 28 make it easier to guide the groove ridge 142 into the groove 28. The curved corners 144 and 29' make it easier to align the plurality of groove ridges 144 with the plurality of grooves 28.

- 19 042325

The degree of stretch of the transfer mechanism 149 is used as a positive indicator so that the ridges 28 of the grooves properly engage with the grooves 28 of the sleeve 20.

The six plungers 107, 108, 109) and (not shown) the first and second halves 97, 98 of the tension tool 100 are now activated using the controller 181 to activate the hydraulic power unit 180 to cause hydraulic working fluid to flow through the hydraulic circuit so to extend pistons 112, 113 (not shown) simultaneously and uniformly, which moves the insert holders 114 relative to the structural body 101, moving the coupling 20, shearing the shear pins SP until the end stop ring 30 of the coupling 20 abuts the shoulder 16' end flange 16 of the end 6 of the pipe. The reaction inserts 150 are axially attached to the structural body 101 such that the engagement of the reaction inserts 150 with the proximal portion 41 of the pipe end 7 prevents the pipe end from moving relative to the sleeve 20 of the pipe end 6 . The free end of the pistons 112, 113 and associated insert holders 114 continues to move, with a preload force applied to the O-ring 19 between the two tube end surfaces 18 and 45, until the O-ring 19 is fully activated and becomes functional for its intended purpose. nominal pressure. This is indicated by meeting or exceeding the hydraulic pressure indicated by the pressure reading on the display 182. If the seal 19 is of the type that is activated by internal fluid pressure or other means, a preload is applied to the end surfaces 18 and 45. The free end of the piston 112, 113 can continue to move the sleeve 20, stretching the sleeve 21. The rotator 155 is then activated to screw the lock nut 50 into the threads 22 of the sleeve 20, locking the tubulars 2 and 3 together and making connection 1.

Hydraulic pressure is released from six plungers 107-109 (not shown). This transfers the tension in the bushing 21, provided from six plungers 107, 108, 109 (not shown), into connection 1. The bushing 21 may be stretched in the tensioning procedure by perhaps about 0.5 mm. An activation force of approximately 20,000 kN (a force of approximately 2,000 tons) may be required to activate seal 19 at connection 1 in a 16-inch pipeline. The first and second halves 97 and 98 slide apart on the crane beams 99 away from connection 1. Alternatively, the shifting mechanism 149' is activated to retract the inserts 135, 150. The six plungers 107, 108, 109 (not shown) are then fully are drawn in by removing hydraulic working fluid from cylinders 110, 111 or by pumping hydraulic fluid from hydraulic power unit 180 to the back of the piston in cylinder 110, 111.

Referring to FIG. 8B, tension tool 100A is shown generally similar to tension tool 100, except for the details of reaction inserts 150' and replaceable end stop 160'. This embodiment of the tensioning tool allows the tubular elements to move axially in the tensioning tool 100A without the need to separate the first and second halves 97 and 98 during the first connection 1 and subsequent connections, with the pipeline passing through the tensioning tool 100A axially through the holes 103 and 105. Identical reference numbers used in FIG. 8A are used to designate similar parts in the tension tool 100A.

Tensioning tool 100A includes a radially movable insert 135 in an insert holder 114. Tension tool 100A also includes a reaction insert 150' in each half 97 and 98 to engage a plurality of 47 parallel circumferential tension grooves formed in the proximal portion 41 of the second end 7 of the pipe. The reaction insert 150' is housed in an integral insert holder 151' which is integral with the body 152 of the second structural end 104. The reaction insert 150' is radially movable within the cavity 153' of the integral insert holder 151' using a transfer mechanism (not shown) similar to the transfer mechanism 149 described for moving the insert 135 in the insert holder 114. The reaction inserts 150' comprise a plurality of ridges of parallel circumferential tension grooves (not shown) which must be suitable to engage the plurality 47 of parallel circumferential tension grooves.

Tensioning tool 100A also has a replaceable end stop 160' provided in end stop holder 161' defining a cavity 162' in body 152 of second structural end 104. End stop 160' is radially movable in end stop holder 161' to selectively protrude from the cavity. 162'. The replaceable end stop 160' is movable within the cavity 162' using a transfer mechanism (not shown) similar to the transfer mechanism 149 described for moving the insert 135 in the insert holder 114.

When used, tension insert 135, reaction insert 150, and end stop 160 are selected for line diameter and connection 1. It is contemplated that one tension tool 100A is used to permanently secure and break connections of a range of sizes, preferably including, but not limited to, connections for use in 20 042325 pipelines with a diameter of 2 to 16 inches (50-400 mm). A larger tensioning tool using similar but larger elements can be used for sizes up to diameter

48. Tension insert 135, reaction insert 150, and end stop 160 are installed in the respective tension tool 100A.

The two halves 97 and 98 of the tensioning tool 100A are secured to each other such that the semi-circular inlets and outlets 103 and 105 of the second half 98 oppose the respective semi-circular inlets and outlets 173 and 175 of the first half 97 to form fully circular inlets and outlets. In this embodiment, the tubular members and the associated first and second tubular ends 6 and 7 move axially through the tension tool 100A. It is not necessary to move the two halves away from each other during the final fastening and breaking of the plurality of connections. However, the two halves can move away from each other to allow a PLET or other large device in the conduit to pass between them.

Tension insert 135, reaction insert 150, and end stop 160 move to their radially retracted positions using their respective displacement mechanisms 149 (not shown). Hydraulic fluid is allowed to flow from the hydraulic power unit 180 through a hydraulic circuit (not shown) to/from the cylinders 110, 111 of the plungers 107, 108, 109 in the second half 98 of the tensioning tool 100 and the corresponding plungers (not shown) in the first half 97 to fully retract their respective pistons 112, 113.

The first end of the tubular member 3 is inserted into the tension tool 100A, while the second end lies in the inlet end of the tension tool 100A. The second end contains the second end 7 of the pipe. The additional tubular element 2 is fed and moved in such a way that the first end 6 of the tube is axially aligned with the second end 7 of the tube. All end fuses are removed. The end surface 17 and end surface 45 are positioned abutting each other, after which the seal 18 is inserted into the groove 46. A shear pin SP is placed between the end stop 30 of the coupling 20 and the proximal portion 14 of the first pipe end 6 to maintain the axial location of the coupling 20.

Alternatively, the shear pin SP is not used. From FIG. 1, it should be noted that the sleeve 20 slides towards the second end 7 of the pipe such that the proximal end portion 23 slides over the end flanges 16 and 43. The lock nut 50 slides along the proximal portion 41 towards the first end 6 of the pipe such that the male thread 51 of the lock nut 50 engages the internal threads 22 of the box 20. The threaded joint is set loosely by turning the lock nut 50 relative to the box 20 with a predetermined number of turns so that the axial location of the box is known. The connected tubular members 2 and 3 can then move along the base into the tension tool 100.

The end stop 160' in the second half 98 and the corresponding end stop (not shown) in the first half 97 now move radially towards the tubular 3 to the point where the end stop is very close to the tubular 3 but should prevent the proximal end portion 41 from passing. 7 pipes. The partially completed connection 1 now moves with the tubulars 2 and 3 through the receiving opening 103, 173 until the shoulder 42 from the second end 7 of the tube abuts the end stop 160.

The reaction inserts 150' in the first and second halves 97, 98 are radially moved by their respective moving mechanism (not shown) so as to engage a plurality of ridges of parallel peripheral tension grooves (not shown) with a plurality of 47 parallel peripheral tension grooves of the second pipe end 7.

The tension inserts 135 in the first and second halves 97, 98 are radially moved by their respective movement mechanism 149 to engage the sleeve 20. A plurality of ridges 142 of parallel peripheral tension grooves of the tension insert 135 engage with a plurality of parallel peripheral tension grooves 28 of the sleeve 20 of the first end 6 of the pipe.

The curved corners 144 of the groove ridge 142 and the curved corners 29' of the groove 28 make it easier to guide the groove ridge 142 into the groove 28. The curved corners 144 and 29' make it easier to align the plurality of groove ridges 144 with the plurality of grooves 28.

The six plungers 107, 108, 109 (not shown) of the first and second halves 97, 98 of the tension tool 100A are now activated by activating the hydraulic power unit 180 to allow hydraulic working fluid to flow through the hydraulic circuit so as to extend the pistons 112, 113 (not shown) simultaneously and uniformly, which moves the insert holders 114 relative to the structural body 101, moving the sleeve 20 until the end stop ring 30 of the sleeve 20 abuts the shoulder 16' of the end flange 16 of the pipe end 6. The reaction inserts 150 are axially attached to the structural body 101 such that the engagement of the reaction inserts 150' with the proximal portion 41 of the pipe end 7 prevents the pipe end from moving relative to the sleeve 20 of the pipe end 6. The free end of the pistons 112, 113 and associated insert holders 114 continues to move with the application of a preload force against the O-ring 19 between the two end surfaces 18 and 45 of the pipe until the O-ring 19 is fully activated and becomes functional. for its intended nominal pressure. This is indicated by meeting or exceeding the hydraulic pressure indicated by the pressure reading on the display 181. If the seal 19 is of the type that is activated by internal fluid pressure or other means, a preload is applied to the end surfaces 18 and 45. The free end of the piston 112, 113 can continue to move the sleeve 20, stretching the sleeve 21. The rotator 155 is then activated to screw the lock nut 50 into the threads 22 of the sleeve 20, locking the tubulars 2 and 3 together and making connection 1.

Hydraulic pressure is released from six plungers 107-109 (not shown). The transfer mechanism 149, 149' is activated to retract the tension inserts 135, the reaction inserts 150' and the end stop 160'. Six plungers 107, 108, 109 (not shown) are retracted by removing hydraulic fluid from cylinders 110, 111 or by pumping hydraulic fluid from hydraulic power pack 180 to the back of the piston in cylinder 110, 111. This transfers tension from six plungers 107, 108, 109 (not shown) into connection 1. Sleeve 21 can be stretched in the tensioning procedure, perhaps by about 0.5 mm. An activation force of approximately 20,000 kN (2000 tons) may be required to activate the seal at joint 1 for a 16" pipeline.

In order to confirm that sufficient force is applied to ensure a seal between pipe ends 6 and 7; to indicate that the seal 19 is properly activated; and to make sure that there is sufficient residual force in the joint 1 after the six plungers 107, 108, 109 (not shown) release their force from the joint, the present invention provides the following system as an example.

As best shown in FIG. 11, the camera system 200 includes at least one camera 201 located on a steel threshold 202 welded to the proximal surface of the front plate 116 of the insert holder 114. The chamber 201 must move in conjunction with the insert holder 114 and therefore the chamber must axially align with the sleeve 21 of the sleeve 20 when in use. The camera 201 is directed to the smooth surface portion 205 of the sleeve 21 between the proximal end portion 23 and the end stop ring 30.

Camera 201 may be of the type marketed under the StrainMaster™ brand by LaVision Inc. The camera 201 may be a high definition CCD or CMOS camera. The camera 201 is connected to the computer 203. The digital images captured by the camera 201 are sent to the computer 203 for processing. The computer uses digital image correlation (DIC) to evaluate the stretch caused in the material of the samples.

The smooth surface portion 205 may be prepared by roughening the surface or by applying a spray paint that creates a pattern. The pattern is preferably a random, high contrast, mottled pattern, such as a pattern rendered by spray paint. An example of such a pattern 210 is shown in FIG. 13A, which is shown to be sprayable with spray paint can 212. The pattern shown in FIG. 13A also shows the black spot 211, which is here simply given as a visual indicator of stretch, which should be taken into account from FIG. 13B, but is not a mandatory step for the purposes of the present invention. Alternatively, the smooth surface portion 205 may have a sufficient pattern for itself without the need for a pattern.

The camera 201 photographs at least one image of the pattern before the six plungers 107, 108, 109 (not shown) extend, an example of such a first image is shown in FIG. 13B and is assigned link number 215. The first image 215 is transmitted to the computer 203. The camera 201 then photographs additional images of the pattern on the smooth surface portion 205 as the plungers extend and the load increases, such as the second image 216 and the third image. 217. These additional images are also transmitted to the computer 203. The pattern changes as the smooth surface portion 205 is pulled out, as can be seen visually by changing the shape of the black dot 211, which changes to a black oval 218 in the third image 217. The computer 203 uses algorithms in order to perform correlation of digital images in order to accurately estimate the stretch in terms of relative strain in the axial direction. A relative strain accuracy of 10 µm can be obtained. The camera 201 is preferably capable of capturing 5 megapixel images using a 25-75mm lens. Thus, the system measures axial tension while generating a full 2D or possibly 3D view (with two cameras pointing at the same area) in order to create a complete strain diagram.

At least one additional camera 220 is similarly positioned in the first half 97, indicated by a dotted line, for the tension tool 100, and is focused on the other side of the sleeve 21 in the smooth surface area 206 of the sleeve 21 between the proximal end section 23 and the end limit ring 30. At least one additional chamber 220 is likewise placed on a threshold 221 welded to the proximate surface of the front plate (not shown) of the insert holder (not shown).

The at least one additional chamber 220 provides redundancy to the first chamber 201 and should also indicate whether or not there are imperfections in the sleeve 21 by comparing the results from the first and second chambers 201, 220. Such imperfections may represent a crack in the sleeve 21.

The load provided by the six plungers can be calculated from a Young's modulus calculation requiring the Young's modulus factor of the material used in the sleeve and the actual relative strain reading provided from the first and second chambers 201, 220. Under most circumstances, it is contemplated that the sleeve 21 is made of high strength steel. Alternatively, the required relative strain in the sleeve 21 may be calculated from the required force (e.g., 20,000 kN) in advance and compared with the actual strain reading obtained from the first chamber 201 and compared with the reading from the second chambers 220.

After the desired strain ratio is reached, and after the hydraulic pressure reading is reached as explained above, the lock nut 50 is tightened to lock the sleeve 20 in place. Six plungers 107, 108, 109 (not shown) retract. The final image (not shown) is obtained from the first and second cameras and sent to the computer 203. The final images are compared with the first image 211 to see if relative deformation remains or not and therefore the residual force in the joint is higher than the required force (for example, in 20000 kN (2000 t)). If the answer is yes, the pipeline can be deployed through the hanger 105' (or tensioner) and a new tubular and connection (not shown) added to the tubular 2.

A camera block 230 for use in system 200 is shown in FIG. 12. The chamber block 230 is a replacement for the chamber 201 or may be used in addition to the chamber 201 in the system 200. Thus, it is preferable to mount the chamber block 230 on the holder 114 for the inserts of the tension tool 100. The chamber block 230 comprises two chambers 231 and 232 located on either side of the body 233 and directed at an angle to each other so that the field of view 234, 235 of each merges and intersects at a distance in front of the body 233. Each camera 231, 232 may have identical or different focal lengths, but it is preferable to use an identical focal length between 25 and 75 mm. The light source 236 is placed between the cameras 231 and 232 and directed to provide light in the area in which the field of view 234, 235 of both cameras intersect.

Cameras 231 and 232 can be used in stereo to generate two images that are used to create a three-dimensional representation of the relative strain exhibited in the smooth surface portion 205 of sleeve 21. Alternatively, each camera 231, 232 can be used in mono to capture each image, and each image is processed separately to obtain a two-dimensional representation, which is separately analyzed by the computer 203 using DIC algorithms to obtain relative deformation in the X-X axial direction, thereby leading to redundancy in the system as well as cross-validation for measuring relative strain. A second chamber block (not shown), of the same type as the chamber block 230, may be located in the other half 97, 98 on its insert holder and guided to the opposite side of the sleeve 21 in the smooth surface portion 205.

A pipeline termination (PLET) is required at the ends of the pipeline in deep water applications. For example, when drilling an oil or gas well at great depths, the well is drilled and prepared for production. The wellhead is located at the top of the well on the seabed, in which valves are located to control the flow of fluids from the well. A flowline may be used to connect a wellhead to a manifold that has additional flowlines coming from a variety of other wells. The pipeline is connected to the manifold to transport oil and gas from the manifold to the onshore production facility. Alternatively, the pipeline may come directly from one wellhead. Alternatively, the riser may transport the produced fluids upward directly from each well or manifold to a floating production storage facility.

A termination is required at each end of a pipeline or flowline at great depths, which is known as a pipeline termination (PLET) and a flowline termination (FLET).

Fig. 14 shows a known S-lay system for laying a pipeline 302. A pipe-lay vessel 300 floats on a sea surface 301 while laying the pipeline 302 on the seabed 303. The free end 304 of the pipeline 302 is placed generally horizontally on the vessel 300 on an elongated roller bed base 306, while the new section of pipeline 305 is also laid horizontally on the elongated base 306 and in coaxial alignment with the free end 304 of the pipeline 302. The new section of pipeline 302 is welded to the free end 304. The pipeline is unloaded from the stern 307 of the vessel 300 along the stinger 310, which protrudes back and down into the sea from the stern 307 of the vessel 300. The conduit 302 allows for a simplified S-shape between the seabed 303 and the vessel 300.

Fig. 15 shows a known J-lay system for laying pipeline 332. Pipelay vessel 330 floats on sea surface 331 while laying pipeline 332 on seabed 333. Free end 334 of pipeline is held at a predetermined angle at the stern of vessel 330, with a new section of pipeline placed on base at the same pre-set angle. The preset angle is set to match the depth of the water (at greater depths it should be nearly vertical). The new pipeline section is welded to the free end of the pipeline. The pipeline is unloaded at a predetermined angle from the stern of the vessel. The pipeline allows a simplified J-shape between the seabed 333 and the ship 330 if the preset angle is relatively steep.

After conduit 302, 332 is put into service, conduit 302, 332 is typically constructed to transport fluids with internal pressures up to 5000 psi. inch (350 bar). Conduits 302, 332 may have a diameter of 2 (50 mm) to 48 (1.2 m), but in general, on the order of 8 (200 mm) to 24 (600 mm) and often 12 (300 mm) or 16 ( 400 mm).

Fig. 16 shows a pipeline terminal (PLET) in accordance with an aspect of the present invention for use in the method of an aspect of the present invention. A PLET in accordance with the present invention is generally identified by reference number 400. The PLET is shown connected to coiled tubing 352.

PLET 400 comprises a base frame 401 composed of hollow section, preferably box section or round section, and possibly mild steel or high strength steel, welded together. Hollow section elements can be any suitable material such as aluminum, stainless steel, or carbon fiber. The carrier frame 401 includes a pair of parallel longitudinal members 402 and 403 lying substantially parallel to the general direction of conduit 302. The pair of parallel longitudinal members 402, 403 are interlocked by means of cross members 404-407 lying substantially transverse thereto. In this example, four such longitudinal members are provided, although there may be any suitable number sufficient to form a rigid base frame 401. A cross member 407 extends through the first end 408 of the base frame 401 and has an opening formed to receive a curved section of pipe 302 The opening is sized to fit into the initial section 360 of the pipe. An end device 351 is provided at the end of the initial section 360 of the pipe. Terminal device 351 may be any device disclosed herein and is preferably of the type according to the present invention, an embodiment of which is shown with reference to FIG. 1-3. The cross member 407 may be circular in cross section with an additional circular member 409 positioned substantially centrally between the longitudinal members 402, 403 and positioned to have an axis through itself substantially parallel to the longitudinal members 402, 403. The bead 410 extends upward from the cross member 405. A saddle 410' is placed at the upper end of the bead 410 to support the end of the initial pipe section 360. The initial section 360 of the pipe may be welded, bolted with pads, or otherwise attached to the saddle 410'. The initial pipe section 360 forms a simplified S-shape having one end supported on a saddle 410' and a second end passing through an opening in the cross member 407, trailing the frame 401 approximately 5 to 25 m and preferably 10 to 20 m, and having an additional terminal device 361 for connection with the pipeline 302.

An additional bead 410a extends upward from the cross member 404. A saddle 410a' is placed at the upper end of the bead 410 to support the end of the additional pipe 352.

Connection 350 made between PLET and conduit 352 is preferably of the type shown herein with reference to FIG. 1-3 and the parts indicated by reference number are the parts that appear in the embodiment of FIG. 1-3.

The left and right support shoes 411 and 412 are hinged to the respective longitudinal members 402 and 403 by hinges 413 and 414, preferably three hinges 413, 414 on each side, but there may be any suitable number. Each support shoe includes a frame consisting of parallel sides and cross members 415, 416 and 417, 418, with cross braces 420 extending between them.

The deployment frame 430 is hinged to the second end of the carrier frame 401 to form an articulation. The deployment frame 430 includes parallel longitudinal members 432 and 433 having a first end containing a hinge 435 and 436 to articulate with respective longitudinal members 402 and 403 of the carrier frame 401. The parallel longitudinal members 432 and 433 are engaged by the transverse members 440 and 441 and element 442 at the second end.

Fork member 442 comprises two box-section members 443, 444 intersecting at

- 24 042325 a plate 445 having a central through hole to receive a clevis pin 446. A tubular guide 450 extends upward from a transverse member 441 to guide a pipe 352. The tubular guide 450 includes two vertical posts 451 and 452 having flared tops to facilitate pipe guidance 352 between them.

At the beginning of the pipeline, the PLET may need to connect the pipeline to the subsea equipment. The method of laying the pipeline is shown in Fig. 17A and 17B. Fig. 17A shows a manifold 460 connected to conduit 302 using a PLET 400 of the invention connected to a coiled tubing manifold 352.

The initial pipe section 360 forms part of the PLET 400. The initial section 360 includes a first termination 351 (such as the first pipe end 6) of the connector 350, a simplified S-shaped twisted tubular 355, a straight section of the tubular 356, and a second termination 361 (such as second end 7 of the pipe) welded to the free end of the straight section of the tubular element 356. The straight section of the tubular element 356 lags approximately 10-20 m behind the frame 401.

As shown in FIG. 17B, the elongated roller bed base 306 is placed along the deck of the vessel, with the tensioning tool 100, tensioner (not shown) and hanger located between the aft end of the elongated roller bed base 306 and stinger 310. In use, the hanger prevents the deployable conduit from falling off the aft end of the ship 300. A tensioner (not shown) maintains tension in a pipeline suspended in the water between the ship and the seabed. The tensioner may comprise a plurality of endless belts located near the pipeline to be deployed. Hangers and tensioners are known in the art.

The tensioning tool 100 is opened by moving the first and second parts 97 and 98. The tensioner (not shown) and hanger are both opened or moved outside the pipe-laying line if they are not needed.

The base shoes 411 and 412 are folded up about their respective hinges 413, 414 to allow for a substantially vertical position and are each locked in place by a pin passing through aligned through holes in bosses (not shown) between the base shoes 411 and 412 and longitudinal members 402 and 403.

A deck crane (not shown) is used to lift the PLET 400 onto the stinger 310 such that the frame 401 is placed aft of the tensioner (not shown), hanger and tensioning tool 100. As the PLET 400 is lowered, a straight section of tubular element 356 fits into, enters or passes through a slot in the open tensioner, hanger and tensioning tool 100.

A double, triple, or quadruple splice according to the present invention is moved from a storage rack (not shown) into an elongated roller base 306 and inserted into a tensioning tool 100 to be axially aligned with a straight section of tubular 356 PLET 400. The tubing section termination is fitted in place to the terminal device 361 PLET 400. The tensioning tool 100 makes the connection between them. The hanger and tensioner close near the straight pipe section 356.

One end of the wire rope 465 wraps around a powered winding drum 466 located on the vessel 300 and the opposite end wraps around a pulley block 467 located on the seabed in close proximity to the manifold 460. The block may be attached to a pile (not shown) driven by a direction of the seabed, or to the initiating block. Wire rope 465 wraps around pulley block 467 and travels back to vessel 300 to be connected to pulley 446 on deployment frame 430. Powered winding drum 466 controls the rate of deployment of conduit 302, possibly at a constant tension, as PLET 400 advances. This preferably maintains the correct tension. in the pipeline as it is laid. The articulated PLET extends along the elongated base 306 and along the stinger 310 as shown in FIG. 17V. Additional pipeline sections 305 are added, one at a time, as the PLET is deployed. It should be noted that the stinger 310 follows a curved path. The articulated PLET 400 more closely follows the curve in the 310 curved stinger.

Preferably, the tubing sections stored in the pipe-lay vessel's storage racks are approximately 49.5 m long and are made up of four 12 m long pipes welded together to form a 48 m tubular element with a plug connector on one end and a female connector at the opposite end, so as to form a quadruple joint approximately 49.5 m long; approximately 38 m in length, made up of three 12 m pipes welded together to form a 36 m long tubular element with a male connector at one end and a female connector at the opposite end to form a triple joint of approximately 37 m. .5 m; or a length of approximately 25.5 m, and they are assembled from two pipes 12 m long, welded together to form a tubular element 24 m long with a plug connector at one end and a female connector at the opposite end, so as to form a 25 042325 make a double joint with a length of approximately 25.5 m.

The wire cable line 465 is extended until the PLET 400 sinks to the seabed 303 adjacent to the manifold 460. The shoes 411 and 412 fold out about their respective hinges 413, 414 so that they lie in a substantially horizontal plane on the seabed. This can be done by the ROV removing pins (not shown) located between the support shoes 411 and 412 and the longitudinal members 402 and 403.

Pipelay vessel 300 continues to lay pipeline 302 using the S-lay method until the predetermined destination is reached.

The predetermined destination may be land. The tension tool 500 can be used to make beach and land connections by hanging the tension tool 500 from a crane.

Alternatively, the predetermined destination may be subsea and provide the end of the pipeline with an additional PLET 400. Thus, an additional PLET 400 is required. The additional PLET 400 should be placed on an elongated base 306 with the reaming end 430 facing the bow of the vessel 300 and the first tube end 6 seated on the saddle 410'. Wireline, such as wireline 465 (sometimes referred to as salvage and recovery wireline) is connected to bracket 446 to provide tension to the conduit as PLET 400 is deployed. The PLET 400 slides along the elongated base 306 and then along the curved base of the stinger 310 with the articulated PLET 400 following the contour of the curved base of the stinger 310. the cable line 465 maintains the correct tension in the pipeline as it falls towards the seabed 303. The wire cable line 465 is disconnected from the bracket 446.

After that, the stage of cleaning the pipeline with pigs and testing the pipeline is performed. Pig cleaning and testing equipment (not shown) comprising a pig launcher and a pig receiver may include a termination device in accordance with the present invention to facilitate connection to either end of a pipeline via a PLET(S) 400. After the pipeline has been pigged and being tested, subsea equipment such as manifolds or wellheads 460 may be connected to the PLET 400 and/or an additional PLET.

The manifold or wellhead 460 has a coiled tubing 352 or a rigid tubular spool has a connector 350 termination 353 at the free end. The rigid tubing bobbin is generally pre-shaped to facilitate alignment with the connector in the PLET. The rigid tube bobbin may be preformed into an L- or Z-shape.

The ROV picks up the free end of the flexible tubing 352 and places it in the tubular guide 450 and seats the free end on the seat 410a'. A crane located on the surface vessel may be used to facilitate lifting of the coiled tubing 352. A diver or ROV may smoothly slide the sleeve 20 of the first end 6 of the coiled tubing 352 over the end flange 43 of the second end 7 of the tubing and may twist lock nut 50 into sleeve 20 to provide a non-rigid connection. At shallow depths, eg less than 150 m, a diver may be used to perform the above steps instead of the ROV. If a rigid tubing spool (not shown) is used instead of flexible tubing, the same procedure is followed.

The subsea stringing tool 500 is then lowered from the lay vessel 300 or a support vessel (not shown). The tension tool possibly performs the steps of sliding the sleeve 20 of the first pipe end 6 for the flexible pipe 352 along the end flange 43 of the second pipe end 7 .

An underwater tensioning tool 500 is shown in FIG. 18-19 near connection 350 on PLET 400. Subsea tension tool 500 is generally similar to tension tool 100 shown in FIG. 7 and 8 as described in this document. Structural body 501 is generally similar to structural body 101, although it takes the form of a cylinder with a circular cross section. Structural body 501 has first and second halves 502 and 503 hinged about hinge 504.

The subsea tensioning tool 500 is lowered onto the wireline 499 from a crane (not shown) of the lay vessel 300 or a support vessel (not shown). An optional battery power unit 550 is also lowered along with the subsea tensioning tool 500 to provide pressurized hydraulic fluid to power the subsea tensioning tool 500. Alternatively, the subsea tensioning tool 500 contains pressurized hydraulic fluid via a detachable umbilical (not shown) engaging underwater tensioning tool 500 with auxiliary vessel.

The first and second halves 502 and 503 move about the hinge 504 to provide an opening therebetween which allows the two halves 502 and 503 to descend over connection 350. tool 500. The first and second halves 502 and 503 are locked together with a latch 520.

As can be seen from the cross-sectional view in FIG. 19 and 20, the subsea tension tool 500 has six plungers 507-512 to tension connection 350 in a manner similar to that described for connection 1 above. Plungers 507-512 (similar to plungers 107-109) are supplied with power from battery power pack 550. An additional small power pack (not shown) may be provided to supply power to the rotator (similar to rotator 135) to rotate lock nut 50 of connector 350.

The subsea tension tool 500 may also include an underwater chamber (similar to chamber 201) and may have a chamber assembly (similar to chamber assembly 230) as well as an additional chamber (similar to chamber 220) to confirm that the correct tension is being applied to the coupling. 20 connections 350.

The spacing of the bead 410, 410a provides space for the subsea tension tool 500 to enter near the joint 350. This makes it easier to align the plurality of 28 grooves of the sleeve 21 of the joint 350 with the inserts (similar to the inserts 135) of the subsea tension tool 500. It also facilitates the alignment of the plurality of 47 grooves of the end 7 connection pipes 350 with inserts (similar to inserts 150) of the subsea tensioning tool 500. After axial alignment, inserts 135 and 150 move radially in their respective insert holders (similar to insert holders 114 at the free end of the piston 111 and insert holders 153 in the structural housing 101, respectively ) into engagement with its respective plurality of grooves 28 and 47.

Plungers 507-512 are activated to apply a high tension force to the sleeve 20. The rotator is then activated to drive the lock nut 50 into the end of the sleeve 20 to lock the first end 6 of the pipe to the second end 107 of the pipe 1, making the connection. The pressurized hydraulic fluid in the plungers 507-512 and in the plungers providing radial force to the inserts is now vented and the inserts retract radially and the plungers retract axially.

The chambers are used to ensure that the correct tension is applied during tensioning and also to ensure that there is sufficient tension in the sleeve 20 to ensure that the O-ring 19 between pipe ends 6 and 7 remains activated, to provide a seal between them.

Once the connection has been made with the correct tension applied to the sleeve 20, the latch 520 of the subsea tension tool 500 is released, the tension tool 500 is pulled away from the PLET 400 using a crane on the support vessel, dragging in line 499.

Before the tension tool is retracted, the chambers can be used to make sure that a small amount of elastic tension occurs in the sleeve 21 of the clutch 20.

It is contemplated that the PLET 400 may include skid plates or skis (not shown) that facilitate movement of the PLET on the seafloor due to expansion and contraction along the length of the pipeline due to temperature variations.

Pipelines are often made from materials that are wear resistant and inexpensive, such as mild steel or high strength steel. However, such materials may be exposed to corrosive fluids flowing through pipelines. The use of materials other than mild steel and high strength steel for body and piping connections may be considered, but is often prohibitively expensive. For example, the cost of materials, such as high-quality stainless steel, is currently about 30 times higher than the price of high-strength steel. Accordingly, the use of mild or high-strength steel that is internally lined with an internal lining that does not corrode or has improved corrosion resistance, such as a corrosion resistant alloy (CRA), is becoming popular.

Fig. 21 shows a portion of a lined conduit 600 comprising a joint 601 and a tubular member 602 extending therefrom. Connection 601 is generally similar to connection 1 shown in FIG. 1-3, but with parts such as the sleeve 20 and lock nut 50 not shown for clarity.

Connection 601 has parts generally similar to those of connection 1 shown in FIG. 1-3 and are identified by identical reference numbers in the 600th sequence.

Connection 601 contains the first end 606 of the pipe and the second end 607 of the pipe.

The first end of the pipe 606 has a hollow steel tubular body 612 with substantially constant inside and outside diameters. The hollow steel tubular body 612 may be on the order of 12-48 meters in length, although it may be longer or shorter. The hollow steel tubular member 612 may have a diameter on the order of 2 (50 mm) to 48 (1200 mm). The first end 606 of the pipe has a proximal end section 614 having a larger outer diameter and an end flange 616 with an even larger outer diameter.

The second pipe end 607 likewise has a hollow steel tubular body (not shown) with substantially constant inside and outside diameters. Hollow steel tubular body

- 27 042325 may have a length of the order of 12-48 m, although it may be longer or shorter. The hollow steel tubular member 612 may have a diameter on the order of 2 (50 mm) to 48 (1200 mm). The second end 607 of the pipe has a proximal end portion 641 having a larger outer diameter and an end flange 643 with an even larger outer diameter.

Tubular cases 612 (not shown) are internally lined with an inner lining 670. The inner lining 670 is made of high density polyethylene (HDPE), although PVDF, XPLE (PEX), medium density polyethylene, fiberglass, carbon fiber, metal, or other form of plastic may be provided. . The inner lining 670 has a smooth inner wall defining a passageway 604 for the fluid to be conveyed through conduit 600 and connections 601. As shown in FIG. 21A, the inner lining 670 has a series of small parallel axial ribs 671 protruding from the outer surface 672. The series of small parallel axial ribs 671 may be arranged in accordance with the overall flow of fluid through the bore 610 or may follow a helical or helical path. During manufacture, the inner lining 670 may be formed by extruding HDPE through it. A sequence of small parallel axial ribs can be formed as a single unit by having notches therein. The inner lining 670 is then slid or pulled into the bore of the hollow steel tubular body 612. The inner lining 670 may remain in the bore 604 offset from the inner surface of the hollow steel tubular 612 as an interference fit. Alternatively, an expanding seal cavity (not shown) or a cleaning scraper (not shown) can be used to push the inner lining 670 against the inner surface of the hollow steel tubular 612, permanently deforming the inner lining 670 and locking it in place. A series of small parallel axial fins 671 define a small passageway 673 through which gas can flow. It should be noted that the ribs 671 may be continuous from one end of the inner lining to the other. The ribs 671 may take a helical, helical, linear, or other shape as long as a continuous gas flow path 673 is provided between the outer surface 672 of the inner lining 670 and the inner surface of the hollow steel tubular 612.

It has been found that gases, such as hydrogen sulfide, can permeate the inner lining or otherwise flow into the passages 673 formed between the inner lining 670 and the hollow steel tubular 612.

At each end of the inner liner 670, the end portion 674 expands to permanently reside in a slot 675 formed at the end 606 of the pipe. Slot 675 preferably resides in proximal end portion 614 and is spaced from end surface 617 by proximal end region 676 and is defined by a shoulder 677 having an inner diameter substantially identical to that of hollow steel tubular 612. Shoulder 677 may include a square outer corner or a curved edge. , as shown. The groove 675 may alternatively be located anywhere in the end section 606 of the pipe. The groove has a final depth portion 681 having a depth approximately equal to the thickness of the inner lining 670 and has a smooth transition region 680 between the inner diameter of the hollow steel tubular 612 and the final depth. The square end surface 678 of the inner lining 670 sits within the end depth portion of the groove 675 681 with an annular gap 679 provided between the square edge surface 678 of the inner lining 670 and the shoulder 677. The end compression ring 685 of the inner lining is inserted into the proximal end region with a friction fit. The end compression ring 685 of the inner lining may be slightly enlarged and inserted under compression. The end compression ring 685 of the inner lining can be reduced in size, inserted and extended towards the inner wall 676 with a scraper cleaning tool or the like. (not shown). The inner lining end compression ring 685 has a wedge-shaped region 686 on the outer surface that has a plurality of parallel circumferential grooves that lie opposite the end portion 675 of the inner lining 670. surfaces 617. The end compression ring 685 of the inner lining may be from 50 to 200 mm and preferably about 135 mm long. A fillet weld may be provided between the proximal end 688 of the end compression ring 685 of the inner lining and the inner wall 676 of the end 606, 607 of the pipe. The arrangement of inner lining 670, slot 675, compression ring 685 should be such that when the compression ring 685 is fully inserted, the small flow channels 673 in the inner linings 670 are not compressed too much so that gas can escape. Treated pipeline joints must be subjected to a performance test by gas flow through small passages 673 from end to end before the joints are sent offshore.

The tube end 606 has an end surface 617 that is generally flat with an annular groove 618 in its central portion extending around the bore 610 for

Groove 618 has a rear wall 683 substantially parallel to end surface 617 and a pair of side walls flared outward from rear wall 683 to end surface 617 forming a frustoconical groove 618 to receive an O-ring 619 .

The O-ring 619 may be a square ring (as shown in FIG. 21) or may be of the type shown in FIG. 5, having bevelled edges to form frustoconical ends that fit into slot 618. Note that O-ring 619 fits into slot 618 so that an annular cavity 687 is defined. The annular cavity 687 is still present when the connection is fully made. . A seal is created in which the corners or chamfers 19' of the o-ring intersect with the tapered surfaces 684 and 684' defining the annular groove 683. The o-ring 618 includes a plurality of through holes 690 extending from the front surface 691 to the rear surface 692. up to six such through holes spaced evenly about the periphery of the annular seal 619, although any suitable number may be used depending on the diameter of the pipe and the expected flow of fluid through it.

A plurality of through holes 682 are formed in the first end 606 of the tube between the back wall 683 of the slot 618 and the shoulder 677 to provide a fluid path between the annulus 679 and the annular cavity 687 in the slot 618 behind the O-ring 619. Preferably, four to six such through holes 683 are evenly spaced about the periphery of the first end 606 of the pipe. The through holes may have a diameter of 0.5 to 5 mm and may have a diameter of 3 mm.

In use, connection 601 is made as described with reference to FIG. 1-3 with significant force being applied to actuate O-ring 619. Corrosive fluid may flow through lined conduit 600. Some fluid, such as hydrogen sulfide, may migrate between the inner lining 670 and the hollow steel tubulars 612 in the axial passage 673 and may move very slowly in the passage. If a pressure differential occurs in the inner lining 670 between the flow channels 673 and the passage holes 610, the inner lining 670 may collapse. It may be advantageous to remove gases that form in increased quantities in the flow channels 673.

In accordance with this aspect of the present invention, the fluid is allowed to flow in a small axial passage 673 into the annular gap 679, through the through holes 682 into the annular cavity 683, through the through holes 690 in the sealing ring 619 and into the corresponding annular cavity 687' in the second end 607 of the pipe , through the respective through holes 682' into the respective annular gap 670' and into the respective passage 673' between the proximal section 641 of the steel body of the pipe end 607 and the inner lining 670'. This allows equalization of pressure in connection 601 and provides axial flow between the flow 673 in the connected tubular elements.

Lined conduit 700 shown in FIG. 22 is generally the same as lined piping except for the connection type, which is a standard flanged connection rather than the connection type shown in FIG. 1-3.

The first end of the pipe 706 has a hollow steel tubular body 712 with substantially constant inside and outside diameters. The hollow steel tubular body 712 may be on the order of 12-48 meters in length, although it may be longer or shorter. The hollow steel tubular member 712 may have a diameter on the order of 2 (50 mm) to 48 (1200 mm). The end flange 616 has a much larger outside diameter with multiple through holes, each of which accepts a threaded bolt 795 that has a head 796 at one end and receives a threaded nut 797 at the other.

The second end of the tube 707 likewise has a hollow steel tubular body 712' with substantially constant inside and outside diameters. The hollow steel tubular body 712' may also be on the order of 12-48 m long, although it may be longer or shorter. The hollow steel tubular member 612 may have a diameter on the order of 2 (50 mm) to 48 (1200 mm). The second end of the tube 707 has a much larger outer diameter end flange 643 with a plurality of through holes in it evenly spaced around the periphery of the tubular member 712'.

The tubular bodies 712 and 712' are lined on the inside with an inner lining 770 (not shown). The 770 inner lining is made of high density polyethylene (HDPE), although medium density polyethylene, fiberglass, metal, or other form of plastic may be provided. Inner lining 770 has a smooth inner wall defining a passageway 704 for fluid to be transported through conduit 700. Inner lining 770 has a series of small parallel axial ribs protruding from the outer surface, which is similar to inner lining 670 and shown in FIG. 2. The inner lining 770 may remain in the bore offset from the inner surface of the hollow steel tubular 712 as an interference fit. Alternatively, an expanding seal cavity (not shown) or a cleaning scraper (not shown) can be pulled

- 29 042325 through the conduit 700 to expand the inner lining 770, pushing it against the inner surface of the hollow steel tubular element 712, permanently deforming the inner lining 770 and fixing it in place. Sequences of small parallel axial ribs define a small passageway through which gas can flow. It should be noted that the ribs may be continuous from one end of the inner lining to the other. The ribs may take a helical or other form, provided that a continuous gas flow path is provided between the outer surface of the inner lining 770 and the inner surface of the hollow steel tubular 712.

At each end of the inner liner 770, the end portion 774 expands to permanently reside in a slot 775 formed at the end 706 of the pipe. Slot 775 is spaced from end surface 717 by proximal end region 776 and is defined by shoulder 777 having an inner diameter substantially identical to that of hollow steel tubular 712. Shoulder 777 may include a square outside corner or curved edge as shown. The groove 775 has a finite depth portion 781 having a depth approximately equal to the thickness of the inner lining 670 and has a smooth transition region 780 between the inner diameter of the hollow steel tubular 712 and the final depth. The square end surface 778 of the inner lining 770 sits within the region 781 of the final depth of the groove 775 with an annular gap 779 provided between the square edge surface 778 of the inner lining 770 and the shoulder 777. The end compression ring 785 of the inner lining is inserted into the near end region 776 with a friction fit and can slightly increase in size and inserted with compression. The end compression ring 785 of the inner lining has a wedge-shaped region 786 on the outer surface that has a plurality of parallel circumferential grooves that lie opposite the end portion 775 of the inner lining 770. surface 718. A fillet weld may be provided between the proximal end 788 of the end compression ring 785 of the inner lining and the inner wall 776 of the end 706, 707 of the pipe. The end compression ring of the inner lining may have a length of 50 to 200 mm, and preferably a length of about 135 mm. The arrangement of inner lining 770, slot 775, compression ring 785 should be such that when the compression ring 785 is fully inserted, the small flow channels 773 in the inner linings 770 are not compressed too much so that gas can escape. Treated pipeline joints must be subjected to a performance test by gas flow through small passages 773 from end to end before the joints are sent offshore.

The tube end 706 has an end surface 717 that is generally flat with an annular groove 718 in its central portion extending around the bore 710 to receive a portion of the O-ring 719. The groove 718 has a back wall 783 substantially parallel to the end surface 717, and a pair of sidewalls flared outwardly from rear wall 783 to an end surface 717 forming a frustoconical groove 718 to receive an O-ring 719.

O-ring 718 may be a square ring (as shown in FIG. 21) or may be of the type shown in FIG. 5 having chamfered edges to form frustoconical ends that fit into slot 718. Note that O-ring 719 fits into slot 718 so that cavity 787 is defined. An annular cavity 787 remains when the connection is complete. The annular seal 718 includes a plurality of through holes 690 extending from the front surface 791 to the rear surface 792. Preferably, four to six such through holes are provided, evenly spaced about the periphery of the annular seal 719, although any suitable number may be used, depending on the diameter. pipe and the expected flow of fluid through it.

A plurality of through holes or ports 782 are formed in the first end of the tube 706 between the back wall 783 of the slot 718 and the shoulder 777 to provide a fluid path between the annulus 779 and the annular cavity 787 in the slot 718 behind the O-ring 719. Preferably, four to six of these The through holes 783 are evenly spaced about the periphery of the first end of the pipe 706. The through holes may have a diameter of 0.5 to 5 mm and may have a diameter of 3 mm.

In use, connection 701 is made by tightening nuts 797 and bolts 795 with significant force to activate O-ring 719. Corrosive fluid may flow through lined conduit 700. Some fluid, such as hydrogen sulfide, may migrate between the inner lining 770 and the hollow steel tubulars 712 in the axial flow and may move very slowly in the flow. If a pressure differential occurs across the inner lining 770, the inner lining 770 may collapse.

In accordance with this aspect of the present invention, fluid is allowed to flow into

- 30 042325 a small axial flow into the annular gap 779, through the through holes 782 into the annular cavity 783, through the through holes 790 in the sealing ring 719 and into the corresponding annular cavity 787' in the second end of the pipe 707, through the corresponding through holes 782' into the corresponding annular gap 770' and into a corresponding passageway 773' between the proximal section 741 of the steel body of the pipe end 707 and the inner lining 770'. This allows pressure equalization at connection 671 and axial flow between the inner linings 770, 770' and the steel tubulars 712, 712'.

Fig. 22A shows conduit 600 in accordance with the present invention, although this aspect of the invention is also applicable to conduit 700 in accordance with the present invention.

Conduit 600 extends from a first pipeline end 690a located on the seabed 689a adjacent to a wellhead 691a terminating in a subsea manifold 692a to a second onshore pipeline end 693a 688a terminating in an onshore manifold 694a. An additional short section of tubing 699a is extended from the subsea manifold 692a to the wellhead 691a. An additional short section of pipeline 688a extends from onshore manifold 694a to a storage facility or refinery (not shown).

The onshore manifold 694a includes a shroud 694b with a flow port 694c through it to transport fluids, such as oil, from pipeline 600 to the manifold and to a short pipeline section 688a leading to a refinery or onshore product storage facility (not shown). The pump 695a is fluidly connected to a tube 697a associated with a through hole 682b in the wall 694b of the onshore manifold 694a, which leads to an annular slot 646a. An O-ring 619a, similar to O-ring 619, is housed partly in an annular groove 646a and partly in an annular groove 683 in an end flange 716 constituting a portion of the pipe end 606. Pipe end 606 is welded or otherwise attached to lined tubular 612 of lined conduit 600 . The flange contains a number of bolts near the end 606 of the pipe, which are included in the casing 694b of the onshore manifold 694a to secure the lined conduit 600 to the onshore manifold 694a. The bolts are tightened about the annular seal 619a to bridge the gap between the flange 716 and the manifold wall 694b to force the annular seal 619a against the slot wall 646a and against the slot wall 683 to form a seal between the lined conduit 600 and the onshore manifold 694a. A plurality of axial through holes 690a are located near the O-ring 619a. Preferably, one to twelve axial through holes 619a are provided near the annular seal to allow passage between an annular passage 687 formed between the sealing ring 619a and the groove wall 683, and into a plurality of through holes in the flange 716 into the passage 673 between the inner lining 670 and the steel a tubular member 612 through which a fluid, such as a gas, can flow.

In use, pump 695a is activated and controlled by computer 699. The pump is preferably a variable speed pump that can apply negative pressure to tube 697a to force fluid through passageway 673 into through holes 682a, in O-ring 619 through axial through holes 690a to a shore manifold 694a and a holding tank 696b and vent the gases to atmosphere or entrapment in a gas storage vessel (not shown). The pump 695a preferably draws fluid from the passage 673 between the steel tubular 612 and the inner lining 670 at low speed so as to prevent increased gas formation in the conduit 600 between the inner lining 670 and the steel tubular 612.

The subsea manifold 692a may include an additional pump and fluid supply to replace the fluid, which will generally be a gas, such as hydrogen sulfide, that percolates through the inner lining into the conduit 673.

Referring to FIG. 23 shows a pipe end 800 generally similar to the pipe end 600 shown in FIG. 21 for use in a joint, such as joint 1, possibly for use with a pipe with an internal lining. Similar to pipe end 606, pipe end 806 is shown without certain parts, such as sleeve 20. Like parts are identified by like reference numbers in the 800th sequence.

The end of the pipe 800 includes a tubular member 802, which may be on the order of 12 to 48 meters in length, welded or otherwise attached to a hollow steel tubular member 812 having matching bores 804, 810 and similar wall thicknesses. The pipe end 806 also has a thicker wall proximal end portion 814 and a thicker wall flange 816. The tubular member 802 and the pipe end 806 are internally lined with a continuous inner lining 870 having ribs on the outer surface to define an axial flow 873. The recessed portion 876 of the pipe end 806 has an enlarged inner diameter. An 887 stainless steel compression end ring is provided in the end section

- 31 042325 end 806 of the pipe to protect the end section from corrosive fluids flowing through the through hole 810. The compression ring 887 has a distal conical section 885 containing external peripheral rings to capture the end of the inner lining in the recessed section 876. Annular flow channel 879 is limited by a recessed section 876 with an increased internal diameter, the end of the inner lining 870, the compression end ring 887 and the end wall 877 section 876 of the groove. A plurality of through holes 882 are drilled or otherwise formed in the end flange 816 fluidly connecting the annular flow channel 879 to the annular flow channel 887 in the annular groove 883.

The annular groove 883 has a substantially perpendicular annular end wall 883b and inner and outer annular wedge-shaped walls 883a. The annular groove 883 is lined on the inside with an insert 883c. An annular seal 819a is seated in an annular groove with seal edges engaging tab 883c on inner and outer annular wedge wall 883a defining an annular flow passage 887. Tab 883c includes through holes that are aligned with through holes 882 to allow flow from through hole 882 into the annular flow channel 887 and forward through the axial through holes 890a in the annular seal 819a. It is possible that the tab and O-ring are made of stainless steel. Possibly the inlay grade is Inconel 625 and may be 3mm thick.

Possibly or alternatively, tab 883a has a surface portion 817a that extends from slot 883 along a recessed inner surface portion 817 of flange 816 to a bore 810, preferably recessed the same thickness as the tab such that the tab is in a plane identical to the plane of the outer surface portion. 817. Optionally, additional section 817b enters bore 810 flush with the inner surface of steel pipe end 806 so that it sits under compression ring 885. Perhaps end compression ring 885 overlaps section 817b of tab 883a, and possibly fillet weld applied between section 817b of tab 883c and end 888 of end compression ring 885.

In use, an additional pipe end (not shown) that is similar to pipe end 806 is fitted in place to pipe end 806, and the annular groove at the pipe end is aligned with the annular seal 819a, sits in the annular groove 883, or is temporarily retained in the annular groove 883 with separate drops of glue that are near the O-ring 819a, being careful not to block the through holes 882 due to the glue. A turnbuckle (not shown) is tensioned using a tensioning tool, such as the tensioning tool 100 shown in FIG. 7-10 and a nut (not shown) is screwed into a sleeve (not shown) to make the connection as described with reference to FIG. 1-6.

Fig. 24 shows a further embodiment of a pipe end 906 according to the present invention in a lined pipeline, generally referred to using reference numeral 900. Pipe end 906 is generally similar to pipe end 6 shown in FIG. 1 for use in a connection such as connection 1, except for use with lined conduit 900. The pipe end 906 is shown without certain parts, such as the sleeve 20 or the nut 50. Like parts are identified by like reference numbers in the nine hundredth sequence.

The end of the pipe 900 includes a tubular member 902, which may be on the order of 12 to 48 meters in length, welded or otherwise attached to a hollow steel tubular member 912 having matching bores 904, 910 and similar wall thicknesses. The pipe end 906 also has a thicker wall proximal end portion 914 and a thicker wall flange 916. The tubular member 902 and pipe end 906 are internally lined with a continuous inner lining 970 that may or may not have ribs on the outer surface with the ability to define an axial flow 973. The inner lining 970 may have neither axial ribs nor axial flow if they are not needed. , for example, in water injection applications for drilling or tertiary recovery from oil and gas wells. If an inner lining with ribs and ducts 973 is used, then a through hole 982 (shown with a broken line) similar to 682, 782, 882 must be provided between the duct 973 and the annular groove 987. Alternatively, if the duct is not required through the connection 1 between the joints pipe 900, then a through hole 982 is not required and should not be drilled or otherwise formed in the flange 916.

The annular groove 983 has a substantially perpendicular annular end wall 983b and inner and outer annular wedge-shaped walls 983a. The annular groove 883 is lined on the inside with an insert 983c. An annular seal 919a is seated in an annular groove with seal edges engaging tab 983c on inner and outer annular wedge walls 983a defining an annular flow path 987. Tab 983c includes through holes, if necessary, that are aligned with the through holes 982 to provide flow from the through hole 982 into the annular flow channel 987 and forward through the axial through

- 32 042325 holes 990a in the O-ring 919a, if necessary. It is possible that the tab and O-ring are made of stainless steel. Possibly the inlay class 983c is Inconel 625 and may be 3mm thick.

Possibly or alternatively, tab 983a has a surface portion 917a that extends from slot 983 along a recessed inner surface portion 917 of flange 816 to a bore 810, preferably recessed the same thickness as the tab such that the tab is in a plane identical to the plane of the outer surface portion. 917. Optionally, the additional section 917b enters the bore 910 flush with the inner surface of the steel pipe end 906 such that it sits under the inner lining 970 with an overlap of perhaps 50-75 mm. The inner lining 970 ends in the same plane as the surface 917 or slightly recessed therefrom.

It should be noted that the lined pipeline may comprise a coating of corrosion resistant material instead of a separate insertable lined line. The coating may be in the form of paint, enamel, gelcoat, and the like. and is used to cover the additional section 917b of the tab 983.

Fig. 25A shows compound 1001 in accordance with the present invention. Connection 1001 connects the first joint of the insulated pipe 1002 to the second joint of the insulated pipe 1003. The insulated pipe 1002 and 1003 may be referred to as a pipe within a pipe. The insulated pipe 1002 includes a steel inner tubular 1002c, which may be identical to tubular 2 shown in connection 1. The inner tubular 1002c may be carbon steel, have a CRA inner lining, an inner lining, or an HDPE inner lining. The outer concentric tube 1002b, which may be referred to as the work tube, has a larger inner diameter relative to the outer diameter of the steel inner tubular member 1002c providing an annulus therebetween that may be of any suitable size in order to receive the thermal insulation material 1002a such as airgel. Typically, the annulus has a width of 10 to 50 mm.

A portion of the first tubular 1012 of the first pipe end 1006 is welded to the steel inner tubular 1002c. Also shown are a larger diameter hub 1014, an even larger diameter flange 1016, and a sleeve 1020 having a sleeve 1021 slidably positioned about the flange 1016 and an end stop 1030 positioned near the proximal end portion 1014.

The outer concentric tube 1002b has an end that fits onto the hub 1014 and the end of the working tube 1002b is welded to the hub 1014.

Similarly, the inner tubular member 1003c may be made of carbon steel, have a CRA inner liner, an inner liner, or an HDPE inner liner. The outer concentric tube 1003b, which may be referred to as the work tube, has a larger inner diameter relative to the outer diameter of the steel inner tubular member 1003c providing an annulus therebetween that may be of any suitable size in order to receive the thermal insulation material 1003a such as airgel. Typically, the annulus has a width of 10 to 50 mm.

A larger diameter hub 1041, an even larger diameter flange 1043, and a nut 1050 are slidably positioned about the hub 1014.

The outer concentric tube 1003b has an end that fits onto the hub 1041 and the end of the working tube 1003b is welded to the hub 1041.

An insulating sheath 1001a is provided near connection 1. The ends 1001b and 1001c of the insulating sheath overlap the insulation 1002a so as to prevent bridging as a result of cold. The overlap may be between 25 and 200 mm and may be between 50 and 75 mm. Ends 1001b and 1001c may include bevels. The insulating shell 1001a optionally contains a rigid foam, preferably with a large number of pores in it, trapping air or water to improve thermal insulation. It is possible that the thermal insulation provided by the insulating sheath 1001a has a μ value of 0.3 to 3, and preferably 0.5 to 2.5, and currently about 2.0.

The rigid foam insulation sheath 1001a is preferably formed in two identical braids 1001aa (only a portion of one braid is shown in FIGS. 25A and 25B) which are fitted radially in place to joint 1 after joint 1 is finally secured. The radial ends 1001I intersect to provide a continuous layer of insulation near the joint. A seal 1001d and 1001e, such as an elastomeric O-ring, is provided between the insulating sheath 1001a and the outer tube 1002b and 1003b in a small annular groove at each end of the insulating sheath 1001a. Alternatively, the seal 1001d and 1001e is not a continuous seal extending 360° around the perimeter of the working tube 1002b, but may extend 180° and may include an elastomeric seal recessed and adhesively secured in a small groove in each braid so that when two braids are adjusted on site to connection 1,

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Claims (4)

a full 360° seal is set to prevent the ingress of surrounding seawater and the movement of water between the joint 1 and the insulating sheath 1001a. A band 1001f and 1001g, such as a steel or plastic band, is placed at each end of the insulation shell 1001a and secured to radially hold the grapples in the joint 1001a. The outer surface 1001h of the insulating shell 1001a takes the form of a cylinder with smooth walls. The inner surface 1001I has end portions which are substantially smooth walled cylinders in which the seals are located. The inner surface 1001I also has a middle portion that practically adheres to the contours of joint 1. The contours can prevent axial movement of the insulating sheath 1001a relative to joint 1. The contours and seals 1001d and 1001e can also improve insulation by preventing movement of surrounding seawater between the insulating material and joint 1 . Alternatively, the outer surface 1001h may follow the contours of the parts of connection 1, which provides a more consistent insulation depth. In use, the connection is finally secured as described above with reference to FIG. 1-13B on a ship, such as the ship shown in FIG. 14. The vessel contains an elongated base with a roller table, on which the free end of the pipeline rests, and new joints, such as quadruple joints, are connected to the free end. It may be referred to as a pipe-laying line. A pair of half-braids 1001aa (not shown) of insulating sheath 1001a are fitted radially in place to joint 1 on either side of joint 1. Tapes 1001f and 1001g are placed near opposite ends of insulating sheath 1, which may be located above or in close proximity to seals 1001d and 1001e. The straps 1001f and 1001g can be tensioned with a tensioner and fastened together to hold braids 1001aa (not shown) in connection 1. Such a tensioner and anchoring device may be similar to that used in a turnbuckle. Tapes 1001f and 1001g hold the insulating sheath 1001a in place during installation of conduit 900 and during maintenance of conduit 900. Tapes 1001f and 1001g are preferably made of stainless steel. Tapes 1001f and 1001g may be located on the surface of the insulating sheath or in a shallow circumferential groove (not shown) in the outer surface of the insulating sheath such that the tapes 1001f and 1001g lie flush with the outer surface 1001h of the insulating sheath. It should be noted that tubular members are described herein as conveying fluid. The definition of fluid is intended to include any fluid material such as oil and gas, but for the avoidance of doubt is also intended to include non-viscous and viscous fluids, multi-phase fluids, fluids with solids and fluid material, fluids, which exhibit both Newtonian and non-Newtonian characteristics, and plasma. CLAIM 1. A system for making a connection between the first tubular element and the second tubular element, having matching through holes for transporting fluid, and the connection has an axis in the general direction of flow of the specified fluid through it, and the system contains a connection (1) and a tension tool (100 ), wherein the connection has a first tubular end (6) containing a first end flange (16) having an end surface (17) and a sleeve (20) containing a sleeve (21) and an end stop (30) attached to the sleeve (21) , wherein said sleeve (21) is located near said flange (18) and said end stop (30) is located near said tubular end (6), wherein said sleeve (20) is slidable along said tubular end (6), wherein the connection additionally has a second tubular end (7) containing a second end flange (43) having an end surface (45) and a lock nut (50) located near and slidably along said first tubular end (7), wherein the tensioning tool (100) serves to apply axial tension to said sleeve (20) relative to said second tubular end (7), characterized in that at least one of said sleeve (21) and said second tubular end (7) has a plurality of parallel circumferential grooves (23, 47) and said tensioning tool (100) has a plurality of ridges (142), the system being configured to move said ridges (142) into said grooves (23, 47) and applying axial tension to said sleeve (20) relative to said second tubular end (7). 2. The system according to claim 1, in which the sleeve (20) contains a section (22) with an internal thread and the lock nut contains a corresponding external threaded section (52). 3. The system according to claim 1 or 2, in which the end stop (30) is located at the distal end of the sleeve (21) and the plurality of grooves is located at the proximal end of the sleeve (21), while between the end stop (30) and the plurality of grooves a section is provided (21') body. 4. The system according to claims 1, 2 or 3, in which the clutch (20) is made with the possibility of sliding along -