MXPA05003789A

MXPA05003789A - Methods and apparatus for a subsea tie back.

Info

Publication number: MXPA05003789A
Application number: MXPA05003789A
Authority: MX
Inventors: S Headworth Colin
Original assignee: Halliburton Energy Serv Inc
Priority date: 2002-10-10
Filing date: 2002-10-10
Publication date: 2005-08-18
Also published as: BR0215902A; EP1558834A1; AU2002356558A1; EP1558834A4; NO20052257D0; NO20052257L; CA2501315A1

Abstract

A flow assurance system includes an inner pipe (70) disposed within an outer pipe (50) to assure flow through the outer pipe (50). During installation and relative axial movement with the outer pipe (50), the inner pipe (70) is nearly neutrally buoyant or fully neutrally buoyant in the fluids of the outer pipe (50) and may extend partially or completely through the outer pipe (50). The inner pipe (70) may be anchored at one end within the outer pipe (50). The inner pipe (70) is preferably composite coiled tubing that is installed using a propulsion system. The system may allow fluids to flow through the inner pipe (70) and commingle with the fluids in the outer pipe (50) or may flow fluids through the inner pipe (70) to the exterior of the outer pipe (50). Hot fluids may pass through the inner pipe (70) to maintain the temperature of the fluids flowing through the outer pipe (50) and chemicals may flow through the inner pipe (70) to condition the fluids in the outer pipe (50). Tools may be attached to the end of the inner pipe (70) for conducting flow assurance operations within the outer pipe (50).

Description

METHODS AND APPLIANCES FOR A SUBMARINE CONNECTION BACKING FIELD OF THE INVENTION The present invention relates to methods and apparatus for a submarine tie back and more particularly to a tube placed inside the flow line to carry out operations for the flow line and in a more particular way to methods to treat a flow line using the inner tube.

BACKGROUND OF THE INVENTION Submarine connection backups are flow lines that support the connection of connecting trees from productive wells in the producing field to a processing plant. The production plant processes the well fluids that are received through the flow lines of the productive wells separating the gas from the oil and eliminating the unwanted constituents such as gas and water, which at unusable hydrates form at low temperatures and pressures. . Conditioned and stabilized oil can be pumped through an export pipeline or can be transported by tanker. Typically, there is a separate gas pipeline for the gas produced. Referring now to Figure 1, there is shown a typical connection backup system including a production plant 10 on a sea platform 11 with two isolated connection backup flow lines 12, 14 extending to a manifold Underwater 16. The manifold 16 is many kilometers away from the production plant 10. There are a plurality of connection trees 18 in an oil field 20 having individual flow lines 21 extending from each tree 18 to the manifold 16 where the production from each well is mixed. The hydraulic and electrical control umbilicals 22, 24, respectively, extend from the platform 11 to the manifold 16 to control the operation of the manifold 16. In particular, the control umbilicals control the valves in the manifold 16 and in the trees 18 as well as the regulators (not shown) in the individual connection shafts 18. A pipe for injection of chemical products 26 also extends from the platform 11 to the manifold 16 and communicates with the flow lines 12, 14 for chemical treatment in the flow lines 12, 14 and in the wells. The output from each of the trees 18 goes to the manifold 16 and is then mixed to pass through the dual flow lines 12, 14 to the production plant 10 on the platform 11. The production from field 20, Of course, they are production well fluids without treatment. The production plant 10 processes the oil produced by the trees 18 eliminating, for example, any water and gas in the well fluids in such a way that only the oil that will be exported through an export pipeline 28 to the coast remains. Instead of an export pipeline, a vessel for production, storage and floating discharge (FPSO) can be used which not only processes well fluids but also stores oil and gas for discharge. It is necessary to stabilize production before it is exported either through the export pipeline 28 or the export vessel. Stabilizing oil means conditioning oil to put it in the export pipeline 28 and pumping it over a large distance. Although only field 20 is shown in figure 1, production plant 10 can also receive production from other surrounding fields, such as oil fields 30, 32. Although figure 1 shows platform 11 supported by the seabed 34, production currently occurs in deep water. Deep water is typically the place in which the depth of the water is greater than 1,000 meters. In 1,000 meters of water, the production plant 10 could be on a floating platform anchored to the ocean floor or in a boat. In deep water, the production plant 10 must be a floating plant such as a SPAR, a TLP (platform with tension legs) or an FPSO. The use of underwater flow lines to support the connection of subsea wells to a remote processing plant is an established method to develop oil and gas fields. The design and specifications of underwater flow lines are controlled by the needs of the insurance flow management. The flow assurance agency includes ensuring that unprocessed well fluids: (1) can reach the processing plant; (2) arrive at the processing plant at temperatures above critical temperatures (such as the wax appearance temperature or cloud point and the hydrate formation temperature); (3) they can be flowed again after the planned or unplanned shutdown (in particular with respect to the cleaning of obstructions caused by hydrates); (4) prevent the accumulation of hydrates, wax, asphaltene, scale, sand, and other undesirable contents in the flow line; (5) can be flowed at a range of pulse pressures, flow rates, and compositions. See "Emergence of Flow Assurance as a Technical Discipline Specific to Deepwater Technical Challenges and Integration into Subsea Systems Engineering" by Kaczmarski and Lorimer of Shell, OTC 13123 April 3, 2001. The typical methods used to achieve the very varied requirements of securing flow include using highly isolated flow lines, tube-in-tube flow lines, active heating of flow lines, and dual flow lines. However, these strategies have a high cost. Therefore, the oil industry continually tries to increase the distances of the connection backup and reduce costs. The challenge is to have longer connection backup distances while at the same time achieving acceptable costs. This has proven to be difficult for the industry, especially since submarine connection backups tend to be the strategy used for smaller oil fields (which demand lower costs). Deeper water exacerbates the difficulties of underwater connection backups with the additional disadvantage that it is much easier for hydrates to form which can block the flow lines in deep water. See "The Challenges of Deep Terror Flow Assurance; One Company's Perspective" by Walter and McMullen of BP, OTC 13075 dated April 30, 2001. Over time, the wax in the well fluids accumulates on the inner surface of the flow line unless the temperature of the well fluids is maintained above the wax appearance temperature, that is, the cloud point at which particles appear in the liquid that cause the liquid to become turbid . The wax appearance temperature varies between 10 and 48.8 ° C depending on the properties of the well fluid. It is important that the well fluids maintain a high temperature, that is to say that they are hot, as they pass through the flow line from the manifold 16 to prevent the wax from depositing in the flow lines. However, sometimes cooler temperatures can not be avoided. For example, the well fluids adjacent to the wall of the flow line are colder than the mass of the fluid passing through the central portion of the flow line. Therefore, the wax has a tendency to deposit on the inner surface of the flow line in places where the temperatures are colder, that is, below the wax appearance temperature. Other undesirable constituents of well fluids, such as asphaltene, scale, and sand, also tend to accumulate in the flow line. A submarine connection backup preferably ensures the use of a "pig" that is pumped through the flow line to remove wax, asphaltene, scale, sand and other constituents in well fluids that tend to accumulate in the flow line. "Pig" means leveler for pipeline inspection (Pipeline Inspection Gauge). Dual flow lines with an end-to-end loop are preferred to provide a complete circuit for the leveler so that the leveler can pass through the flow line from the production platform, through the back-up flow line. connection, and then back to the production platform. Scraper pig levelers run through the flow line to remove wax and other accumulations inside the flow line and run at a frequency that depends on fluids and other conditions. You can also use smart levelers to inspect the inside of a flow line. In the most typical pipeline inspection survey using intelligent levelers, the leveler flows through the flow line and the information collected by the leveler is discerned after the leveler passes through the flow line. If not all the desired information has been collected, then it is necessary to run the leveler again through the flow line, particularly through a certain area of the flow line that is of interest. It is preferred to have a system that provides information in real time "as the leveler passes through the flow line." The real-time information allows the operator to observe the information collected by the leveler in real time as the leveler passes through the flow line, this allows the operator to also control the inspection tools that are transported with, or that are part of, the intelligent leveler.The undesirable constituents of well fluids, such as wax, asphaltene, scale, and sand, can also be avoided or removed with chemical products.Current chemicals can be injected continuously into the flow lines 12, 14 through the pipe for chemical injection 26. Chemical products condition fluids well to avoid the formation of wax on the walls of the flow lines 12, 14. However, the continuous injection of chemical products It is a huge expense. A problem during the temporary interruption of production is that the well fluids by themselves gel, that is to say they become very viscous, when the well fluids reach their pour point temperature. Therefore, if well fluids fall rapidly below the temperature of the pour point, they become very viscous and it may be difficult to restart the flow. Another problem, particularly when the flow through the flow lines is suspended, is the formation of hydrates. Hydrates are a solid form of a mixture of gas and water in well fluids at a certain pressure and temperature. Hydrates can be produced from methane, carbon dioxide, nitrogen, or another gas with water in the well fluids to form a crystalline structure. Hydrates are formed instantaneously as a solid to block and close the flow line so that there is no flow. For example, if an unexpected temporary interruption occurs, the well fluids in the flow lines begin to cool. After a cooling period, the well fluids then pass to the hydrate region of temperature and pressure. The gas can accumulate at high points in the flow line and water can accumulate at low points in the flow line. However, once the flow starts again the gas and water mix to form instantly and block the flow line.

The chemistry of hydrates is very complex. This becomes even more complex due to all the different types of fluids that are produced in well fluids. Therefore, it is difficult to know exactly what types of hydrates are to be formed and the manner in which they are formed. Also, because this occurs in an underwater pipeline, it is difficult to know exactly how hydrates are formed and what causes them to form. The chemistry is much simpler if the fluids are only water and gas, but when the fluids also include oil and other chemicals such as salts, the hydrate chemistry becomes very complex. The mechanism of hydrate formation in liquids makes it complex, particularly when hydrates can be formed with gas in liquid petroleum. Hydrate problems in oil pipelines are well known in the industry. Although the system is designed for normal operation, an unexpected or unplanned event may occur that requires production to be temporarily interrupted and the flow through the flow line to stop. No matter how much or what type of insulating material is used around the flow line, once the flow stops, eventually the well fluids in the flow line reach the same temperature as the surrounding seawater, typically 4.4 at 10 ° C. Therefore, the temperature of the well fluids falls below the wax appearance temperature and the hydrate formation temperature. Therefore, it is important to take measures to maintain the temperature of the well fluids above the hydrate appearance temperature as well as above the wax appearance temperature. One method to maintain the temperature of hot well fluids produced is to isolate the flow lines. For example, the flow line can be placed inside a tube with a larger diameter to form a double concentric tube. The insulating material is placed in the annular area between the inner flow line and the outer tube. Alternatively, hot fluid can be flowed through the annular space of the double concentric tube to heat the well fluids flowing through the inner flow line. However, even if the annular space is isolated, there is a loss of heat to the seawater environment around the outer tube. Although heat loss can be reduced if the double concentric tube is buried in the seabed, there is still a loss of heat through the outer tube to the marine subsoil. It is very expensive to install and install the double concentric tube on the ocean floor. This expense is even greater when such a large pipe is laid in deep water. The size and cost of the boat for laying such a tube is extremely expensive and only a few boats are available that can handle such a large tube. Another method to maintain the temperature of the well fluids is to heat the well fluids as they flow through the flow line. There are a number of methods for active heating of flow lines in which an inner flow line is placed inside an outer tube. One strategy is to flow hot liquid, such as water, through the annular area between the flow line and the outer tube. The flow through the annular area can be continuous or it can only be used in a contingency. For example, hot liquid may be flowed after a cessation of operations to heat the inner flow line and the well fluids and to restart the flow through the flow line. Another strategy is to use a bundle of flow lines placed in a larger carrier tube that could be 101.6 cm (40 inches) in diameter. One of the inner flow lines can transport hot fluids such as hot water. The bundle of tubes can also be insulated within the carrier tube. This tube bundle is built on the coast and then towed offshore for installation. Even another strategy is the use of electric heating of the flow lines. The electric heating is placed between the inner flow line and the outer tube and then used in case of a contingency. Although it is known that a tube carrying hot liquids placed inside an outer tube has preferred thermodynamic properties, the installation of a smaller tube inside an outer tube is laborious and expensive. One method is to install the inner tube inside the outer tube as sections of the outer tube are connected for assembly, although such assembly and installation could be very expensive. In addition, the survey for oil pipeline inspection (pigging) is a normal requirement for flow lines and a leveler can not be pumped through the flow line if there is an obstruction within the flow line such as an inner tube. A leveler is a solid object that passes through the flow line when it is pushed by the flow of fluid in the flow line. Therefore, all flow lines are typically designed so that they can be pr for pipeline inspection, this being a normal design parameter. In addition, the tube inside the pipeline creates a serious issue regarding corrosion because an inner tube creates stagnation areas within the flow line that cause severe corrosion sites due to water and debris that build up and form strong electrolytes. and create galvanic cells. Therefore, no one has considered placing anything within the flow line for flow assurance because this could interfere with the passage of a leveler through the flow line. Therefore, placing an inner tube within the flow line is a complete anathema to the current flow line design because an object within the flow line means that the pipeline inspection prcan not be conducted. To mitigate against an unplanned work stoppage, chemical products, such as methanol, are flowed from the production plant 10, through the chemical products injection pipe 26, and into the interior of the flow lines 12, 14 to mix with well fluids in an attempt to prevent well fluids from forming hydrates. The volume of methanol required is a function of the percentage of water in the well fluids. As the percentage of water in the flow increases over the life of the well, the volume of methanol eventually becomes so large that it is impractical and very expensive.

The flow lines are designed to ensure that the flow in the flow line is never blocked. This is because the only solution for. A blocked flow line is to replace the flow line completely. However, a design that ensures that there is never any blockage in the flow line is very expensive. For example, making expensive boats tend to inner and outer tubes adds a substantial cost to the installation of the flow lines. The injection of chemical products must also be available and installed for the flow line. Therefore, the system must be designed for an unexpected stoppage of activities that ensures against flow blockages at that time and to avoid the expense of a new flow line. The amount of production through the flow lines also varies throughout the productive life of the producing field. It takes many years to complete and have all wells produced in a field and therefore a different number of wells could go online at different times. This causes a fluctuation in the amount of well fluids that are produced. The flow lines must be installed at the beginning after the initial wells are made to produce. Therefore, the flow of the well fluids through the flow lines changes over time. For example, it changes the amount of flow and pressure of the fluids produced, changes the amount of water in well fluids, and changes the amount of gas. Therefore, throughout the productive life of the well, there is a large range of flows and compositions of well fluids through the flow lines. The flow lines must have the capacity to cope with these changes. Even another problem found in existing systems is that the flow lines are designed to be filled with the well fluids flowing into the processing plant. However, the impulse pressure of the well fluids and the flow velocity of the fluids can vary well as the composition of the well fluids. The term "pulse pressures" refers to the reduction of the production flow rate and therefore to the flow through the flow lines. The variation in the flow velocity also causes a variation in the temperature of the well fluids. There are regulators in the trees 18 that control the amount of well fluids that are produced in each of the wells to control the production coming from the reservoir in the field 20. The collector 16 can mix different well fluids that are being produced from of different deposits in which the composition of the well fluids in the deposit may be different. All these aspects are controlled in an attempt to maximize production. Nevertheless, the flow lines have a certain size and a certain hydraulic capacity. Therefore, although the flow lines are filled with fluid, the flow velocities and pulse pressures vary and the constituents of the well fluids vary. The impulse pressures and the flow velocities are related and the arrival temperature of the fluids in the production plant is also related. The industry standard program for analyzing the flow through the flow lines is called OLGA. "This is used to analyze the flow through the flow line to achieve the appropriate flow line design. flow 12, 14, shown in figure 1, are "double flow lines" because they are basically side by side.The double flow lines allow the operator to change the amount of flow coming from the manifold 16 to the plant. production 10 by closing one of the flow lines, they also provide a wider range of flow rates, pressures, and temperatures.When one of the lines is closed, the cross-sectional flow area changes. a field deteriorates with the passage of time, finally, only one of the two flow lines can be used to transport the well fluids from the manifold 16 to the production plant 10. This is denominates "" reduction of the caudal ". The two lines provide greater flexibility in flow management and also allow for "flow reduction" as needed. In addition, one of the flow lines can be a backup, so that if one of the flow lines is blocked, the other flow line is still available for production. The double flow lines also allow round-trip probing for pipeline inspection. The two flow lines 12, 14 include valves in the manifold 16 such that production can be closed in a particular flow line 12, 14 and a leveler is sent through the line starting at platform 11 for travel from platform 11 to manifold 16. The leveler then returns through the other production flow line to platform 11.? As the production of the field matures, the production of the field is exhausted in such a way that the processing plant is no longer used completely. It is preferred to use the reserve capacity of the processing plant and in this way, it would be desirable to support the connection of the processing plant with other producing fields so that the processing plant is fully utilized. These other fields may be many kilometers away from the processing plant. Therefore, there is a need for underwater connection backup lines that extend many kilometers across the ocean floor to reach various producing fields around the processing plant and process a plurality of producing fields. It is more economical to use existing processing plants and use submarine connection backups than to build new production plants. One goal is to be able to build submarine connection backup lines that are up to 185.33 km long. The final objective is to have the production plant on the coast with flow lines for connection backup that extend from the coast to the subsea collectors. Therefore, a production plant could process production from all fields within a radius of 185.33 km. This could provide substantial cost savings in deepwater production. The present invention overcomes the deficiencies of the prior art.

BRIEF DESCRIPTION OF THE INVENTION The methods and apparatus of the present invention include an inner tube positioned within an outer tube for the purpose of securing flow through the outer tube. The inner tube can be partially or completely extended through the outer tube and can be installed inside the outer tube at any point along the length of the outer tube. In addition, the inner tube can be installed inside the outer tube without considering whether or not there are fluids passing through the outer tube. It should also be appreciated that more than one inner tube can be placed inside the outer tube. The inner tube may be either an articulated tube or preferably a continuous tube. The inner tube plus its contents are floating almost neutrally or remain floating in a completely neutral manner so that when it is in the fluids of the outer tube, the inner tube plus its contents have substantially the same density as that of the fluids in the outer tube. This substantially neutral buoyancy allows the inner tube to minimize friction against the outer tube after the inner tube is inserted and installed inside the outer tube and allows the inner tube to be installed at great distances within the outer tube. The fluids used during installation are selected to achieve neutral buoyancy. Once installed, the fluids within the fluid tubes used during installation can be changed to the fluids used during production operations. However, during production operations it is not necessary for the inner tube to be floating in a substantially neutral manner. The articulated tube may be a metal tube or it may be a tube of mixed material having segments connected to each other and friction packing techniques (snubbing) are installed. The continuous inner tube can be a metallic or mixed material extensible pipe. If it is a metal extendable pipe, the metal extendable pipe is caused to float substantially neutrally with selected fluids in and out. If it is an extensible pipe of mixed material, the extensible pipe of mixed material is designed for the required mechanical properties necessary for the assurance of flow inside the outer tube and in particular is designed to float in a substantially neutral with the fluids selected inside and outside. In a more preferred extensible composite tubing, conductive and fiber optic cables are embedded in the wall of the extensible tubing of mixed material to provide power and communication through the wall of the extensible tubing. Electrical conductors can be used to supply power to a tool attached to the end of the inner tube and the communication conductors can be used to monitor the temperature and pressure along the length of the inner tube. In addition, conductors can be used to transmit signals and data through the tube wall whether they come from a tool or other assembly connected to the end of the inner tube. The extensible pipe can be installed using techniques for extensible pipe and can be inserted and installed at any point along the outer pipe such as through the connection points on the outer pipe. Various propulsion means can be used, individually or in combination, to install the inner tube inside the outer tube. The hydrodynamics of the fluid flow in the outer tube can be used to move the inner tube in the same direction as that of the fluid flow. Alternatively, a flow restricting member, such as a leveler, can be attached to the end of the inner tube to create a pressure differential to move the inner tube into the outer tube. In a preferred embodiment, a propulsion system is used that is coupled to the outer tube to move the inner tube through the outer tube. The propulsion system can be operated electrically or hydraulically. If hydraulically operated and installed over long distances, gas pulsations (gas slugs) can be passed through the inner tube to maintain sufficient power to drive the hydraulically driven propulsion system. The propulsion system may have a segmented housing that allows the propulsion system to pass through the elbows in the outer tube. The inner tube may be anchored within the outer tube such as by a bolt mechanism or a frictional coupling in which the inner tube is frictionally engaged to the outer tube. The inner tube can be used in different types of circuits. In an open circuit, one end of the inner tube is open to fluids flowing through the outer tube so that the fluids passing through the inner tube can mix and interact with the fluids in the outer tube. In a closed circuit mode, the end of the inner tube communicates with the environment outside the outer tube whereby the fluids flowing through the inner tube do not mix or interact with the fluids in the outer tube and are allowed to flow through the inner tube and into the environment around the outer tube. In another embodiment of the closed circuit, the end of the inner tube may be connected with an external return line with respect to the outer tube. Even in another closed circuit mode, a pair of inner tubes communicating through a connection at their free end is placed with the outer tube to allow fluids to flow through an inner tube and then return through the other Inner tube. In a method of the present invention, hot liquids are pumped through the inner tube to control the temperature of the fluids flowing through the outer tube. In an open circuit, the fluids pumped through the inner tube are compatible with the fluids in the outer tube so that they can mix and interact. In a closed circuit, liquids passing through the inner tube are compatible with the environment around the outer tube. Even in another closed circuit, the hot fluids can be any available fluids that can be circulated through an inner tube and a return tube. In another method of the present invention, liquids with different densities are passed through the inner tube to cause the inner tube to move up and down inside the outer tube, whereby any areas of stagnant fluid are agitated. The inner tube can also be reciprocated within the outer tube to agitate any areas of stagnant fluid. In another method of the present invention, in an open circuit, chemicals can be pumped through the inner tube to be mixed with the fluids in the outer tube and thereby condition the fluids in the outer tube. In another embodiment using a closed circuit, the inner tube may include a series of valves that can be selectively opened to allow liquids within the inner tube to mix with the fluids in the outer tube at one or more sites as required. length of the outer tube. In another method of the present invention, a tool can be attached to the end of the inner tube to clean the inside of the outer tube. In another method of the present invention, the inner tube can be used to depressurize the fluids in the outer tube to prevent the formation of a blockage due to undesirable components of the well fluids that solidify within the outer tube. In another method of the present invention, the inner tubes can be used in an open circuit to mix chemicals with the fluids in the outer tube to allow the fluid in the outer tube to be pumped after the fluid is stopped. In another method of the present invention, a pair of inner tubes can be placed inside the outer tube in which one of the tubes passes fluids at high speed from one side of the tube to the other and the other tube is a return tube that pumps unwanted contaminants, such as sand , in the fluids coming from the outer tube. Even in another embodiment of the present invention, an inspection tool can be placed on the end of the inner tube and can be connected to the conductors in the inner tube walls in such a way that an internal inspection of the outer tube can be made in time. real. Even in another embodiment of the present invention, a first inner tube may be placed within an unbonded flexible outer tube to prevent compression of the outer flexible tube. The first inner tube may include a flexible "goose neck" at the end thereof for negotiating any curves, then a second inner tube may be inserted within the first inner tube and may be further extended through the flexible gooseneck such as that the second inner tube can be inserted into a flow line connected to the unattached flexible outer tube, even in a further method of the present invention, the inner tube can be used to transport the fluids in the outer tube in case it is In addition, the inner tube can be replaced with another inner tube having a smaller or larger diameter to adjust the flow area either through the inner tube or through the annular space formed between the inner tube. the inner tube and the outer tube The methods and apparatus of the present invention are particularly applicable to connection backings n Submarines in which the inner tube is used for a variety of flow assurance operations to ensure flow through a flow line. In particular, the inner tube can be used to either prevent or eliminate hydrates, wax, asphaltene, scale, sand, or other desirable constituents of the well fluids flowing through the flow line.

BRIEF DESCRIPTION OF THE FIGURES For a detailed description of a preferred embodiment of the invention, reference is now made to the appended figures in which: Figure 1 is a schematic view of a submarine connection backrest of the prior art. Figure 2 is an elevation outline, partially in cross section, showing an open circuit underwater connection backup of the present invention with a continuous inner tube. Figure 3 is an elevation outline, partially in cross section, showing a submarine connection backrest of the present invention with an articulated inner tube. Figure 4 is a cross-section of an extensible tube having conductors in the walls thereof in which the extensible tube is the continuous inner tube of Figure 2. Figure 5 is a diagram in elevation, partially in cross section, which shows a submarine connection backrest of the present invention with a downhole tool mounted on the end of the inner tube. Figure 6 is an elevation plan, partially in cross section, showing a submarine connection backrest of the present invention with a plurality of inner tube lengths placed in the flow line. Figure 7 is an elevation outline, partially in cross section, showing a submarine connection backrest of the present invention with a leveler attached to the end of the inner tube.

Fig. 8 is an elevation outline, partially in cross section, showing a submarine connection backrest of the present invention with a propulsion member connected to the end of the inner tube. Figure 9 is an elevation plan, partially in cross section, showing an environmental closed submarine connection backing of the present invention. Figure 10 is an elevation outline, partially in cross section, showing a closed return underwater connection backing of the present invention. Figure 11 is an elevation outline, partly in cross section, showing a submarine connection backrest of the present invention in which the inner tube has valve systems and is anchored to the manifold or at any point along the line flow. Fig. 12 is a diagram in elevation, partially in cross section, showing the formation of a hydrate formation using an inner tube of the present invention. Figure 13 is an elevation plan, partially in cross section, showing the removal of sand using one or more inner tubes of the present invention. Fig. 14 is a sectional elevation, partially in cross section, showing a submarine connection backup system having an unbonded flexible using an embodiment of the present invention. Figure 15 is a perspective view of a segmented gooseneck for use in the installation of the inner tube of the present invention. Fig. 16 is an elevation outline, partially in cross section, showing a closed return underwater connection backing of the present invention having a pair of inner tubes positioned with the flow line; and Figure 17 is a cross-section of a segment of the gooseneck shown in Figures 14 and 15. The present invention is susceptible to modalities of different shapes. In the present invention, specific embodiments of the present invention are shown in the figures, and are described in detail with the understanding that the present description should be considered as an exemplification of the principles of the invention, and that it is not intended to limit the invention. to those illustrated and described in the present invention.

DETAILED DESCRIPTION OF THE PREFERRED MODALITY The methods and apparatus of the submarine connection backup system of the present invention preferably include an inner tube positioned within an outer flow line. Various embodiments of the present invention provide a number of different constructions of the inner tube, each of which is used with a flow line in one of many different types of flow line facilities and production plants. The embodiments of the present invention provide a plurality of methods for using the inner tube for securing the flow of well fluids through a flow line. It should be fully recognized that the different teachings of the modalities discussed below can be employed separately or in any appropriate combination to produce the desired results in flow assurance. In particular, the system of the present invention can be used in practically any type of new or existing flow line. The references to "upwards" or "downwards" are made with the purpose of facilitating the description in which "upwards" means towards the surface of the sea and "downwards" means towards the bottom of the seabed. The application of the apparatus and methods of the present invention is described in greater detail with respect to the assurance of flow in the submarine connection backup flow lines. However, many of the modalities can find applications in other types of pipeline systems, such as exporting pipelines. Another example application includes the use of the present invention in real-time inspection in pipelines. In the following description, similar parts are marked throughout the description and figures with the same reference numbers, respectively. The figures in the drawings are not necessarily to scale. Some characteristics of the invention may be exaggerated in scale or in a somewhat schematic form and some details of conventional elements may not be shown in favor of clarity and brevity. Referring initially to FIGS. 2 and 3, there is shown an exemplary operating environment for two embodiments of the submarine connection backup system of the present invention. A production plant 40 is placed on a platform 42. In deep water, the platform 42 can be a floating platform, such as a SPAR or a platform with tensioning legs anchored to the seabed 44 by cables 46, or another type of vessel floating such as a floating production, storage and offloading vessel (FPSO). The production plant 40 processes the well fluids that are preferably produced from a plurality of fields, such as the field 48 which includes a plurality of productive wells 52 in which each has a connection shaft 54 with a line of individual flow 56 extending from each shaft 54 to a manifold 60 wherein the well fluids produced from the wells 52 are mixed to transport them to the production plant 40. It should be noted that the manifold 60 and the trees 54 they have a plurality of valves to control the flow and that the trees 54 include production control equipment, such as regulators and systems for burst prevention, to control the operation of the collector 60 and the production of the wells 52, as is well known in the technique. A submarine connection backup flow line 50 extends from a submarine manifold 60 back to the platform 42 and includes a generally horizontal portion 62 connected to, or as an integral part of, a portion of the return duct 64 that extends from the seabed 44 to the platform 42. The flow line 50 preferably has an outer layer of insulator, such as a thermotite-type insulator, and is preferably also buried under the seabed 44 for additional protection and insulation. Ideally, the flow line 50 is buried in a trench and then covered. The seabed 44 provides a natural insulator around the flow line 50 due to its thermal mass. The manifold 60 can be located many kilometers away from the production plant 40. It should be appreciated that although only one manifold and one flow line are shown for reasons of clarity, there may be a plurality of collectors and producing fields in which the well fluids are pumped to the production plant 40 for processing. The production from field 48 are production well fluids without treatment, that is, crude oil, which require processing before they are exported. The production plant 40 processes the crude produced by the wells 52 by removing, for example, any water and gas from the well fluids, so that only oil remains to be exported either through an export pipeline 58 or, in place of an export pipeline, by means of an FPSO type vessel that can be used not only to process well fluids but also to store oil and gas for unloading. To export oil in the export pipeline 58 and pump it over a large distance, it is necessary for the oil to stabilize to condition the oil for export either through the export pipeline 58 or an export vessel. The gas can be exported through a separate gas pipeline. The submarine connection backup system of the present invention includes a tube 70 positioned within the flow line 50. The lower tube 70 is part of the flow assurance for the flow line 50 and can be used for a plurality of operations of flow assurance including, but not limited to, heating the well fluids, producing the hydrostatic head pressure in the return duct 64, dispersing the chemicals in the well fluids to prevent hydrate formation or formation of wax, or to eliminate undesirable accumulation in the flow line 50 that must be removed as described in greater detail later in the present invention. The inner tube 70, for example, can have a diameter of 2.54 to 15.24 was and the production flow line 50, for example, can have a diameter between 10.16 cm and 50.8 cm for the purpose of providing the flow insurance assurance . The inner tube 70 may be positioned within the flow line 50 for flow assurance at any time during the productive life of the field 48 and may remain within the flow line 50 for a period such as hours, days, weeks, months, and years, up to, and including the complete productive life of the field 48. The time interval in which the inner tube 70 remains within the flow line 50 depends on the methods and operations that are performed using the inner tube 70 This can only be used as an emergency measure to clean the flow line 50 of obstruction or interruption and can therefore be placed in the flow line 50 for a short period of time. This can also be part of a correction effort. For example, this can be used to heat the well fluids towards the end of the flow line 50 to ensure that the well fluids reach the production plant 40 at a predetermined high temperature. The inner tube 70 can also be part of the design of the production plant 40 and can be a permanent part of the installation. The inner tube 70 can be used in existing production lines and flow lines or can be incorporated into new flow and production line installations. The inner tube 70 can be inserted any distance into the interior of the flow line 50. Therefore, it is not necessarily preferable to install the inner tube 70 over the full length of the flow line 50. Only the inner tube needs to be installed 70 a sufficient length in the flow line 50 and in a predetermined location in the flow line 50 to ensure the flow assurance and in particular to ensure that there are no interruptions of the flow line. Therefore, the optimum distance and location is determined by the flow assurance regiments of each particular field or field. For example, the inner tube 70 can be inserted at a partial distance into the flow line 70 as shown in Figure 2 or the full length of the flow line 70 can be inserted as shown in Figure 3. It could be necessary inserting the inner tube 70 only in that portion of the flow line 50 that requires flow assurance measures, for example, that portion of the flow line 50 in which the temperature of the well fluids is very low, in where the hydraulic load in the return duct 64 must be reduced, where chemicals must be dispersed within the well fluids, or where there is undesirable accumulation of wax, scale, sand, or asphaltene in the flow line 50. The inner tube 70 can be inserted and installed within the flow line 50 at any point along the flow line 50. For example, the tube 70 can be inserted into the downstream end 72 of the flow line. or 50 in the upper part of the flow return pipe 64, as shown in Figure 2; at the upstream end 74 of the flow line 50, as shown in Figure 3; or anywhere intermediate, such as in the middle portion 75 shown in Figure 6. The installation point of the inner tube 70 depends on a number of factors. Preferably, the inner tube 70 is installed from the downstream end 72 from the platform 42 where it is easier to access the inner tube 70 and the flow line 50. However, if the line 50 has 185.33 km length, preferably there will be a plurality of insertion points along the flow line 50 through which lengths of the inner tube can be inserted and installed. Also, it is possible that the inner tube can not be installed from the downstream end in an existing plant and the inner tube 70 must be inserted and installed from the upstream end 74. It should be appreciated that the inner tube 70 can be Install from a floating boat so that it can be inserted at any point along the flow line 50. One method of installation is the use of a Swift return duct (Swift Riser) described in the EUA patent 6,386,290 Bl and titled ??? System for Accessing Oil Wells ith Compliant Guide and Coiled Tubing. "The Swift return duct system is a method that allows the use of an extendable tube on a reel in the vessel in which the extendable tube is injected into the flow line The inner tube 70 can be inserted and installed within the flow line 50 whether the flow line 50 is pressurized and has well fluids that are flowing or pressurized and that no well fluids are flowing. , the well fluids may be flowing to the insertion point or in the opposite direction to the insertion point of the inner tube 70. In some cases, it is convenient to install the inner tube 70 from the manifold 60 while the well fluids are flowing whereby the flowing well fluids assist in the installation of the inner tube 70 because it is easier to insert the inner tube 70 in the direction of flow of the well fluids. it should be appreciated that a plurality of inner tubes 70 may be placed within the flow line 50, as shown in Figures 3 and 13. For example, one or more of the additional inner tubes may include electric control umbilicals, umbilicals of hydraulic control, and / or chemical product injection pipes extending from the platform 42 to the manifold 60 as described in more detail below in the present invention. Typically, the control umbilicals are a bundle of small tubes and include electrical conductors as well as fiber optic cables. Typically this beam is in armor to provide weight to the beam to make it lie on the seabed. If the umbilicals were within flow line 50, the armor for the umbilicals would not be necessary to provide them in some other way weight and protection. In a new plant, the chemical product injection pipe of the prior art facilities would typically be laid on one side of the flow line 50. This pipe for chemical injection can supply chemicals to the trees and wells or the injection of chemicals within the flow line 50 into the manifold 60. In the present invention, there may be a separate chemical injection line, such as the inner tube 71 shown in Figure 3, which also passes through of the flow line 50. If the inner tube 71 also serves as the pipe for injection of chemical products, then the end of the inner tube 71 is anchored at or near the manifold 60 to allow the inner tube 71 to be connected with the injection portals of chemical products that communicate with the collector 60 and the trees 54.

The inner tube 70 can be an articulated tube 76 as shown in Figure 3 or a continuous tube 80 as shown in Figure 2. An articulated tube 76 includes a plurality of tube lengths 78 connected to each other via the connections 82 or they are welded to each other as the articulated tube is installed. The continuous tube 80 is preferably an extensible tube, as described below in the present invention, and is preferred to avoid the multiple connections required for the articulated tube. When made to move axially within the flow line 50, it is preferred that the inner tube 70 plus its contents, taken together, float almost neutrally or completely neutrally when in the fluid contents of the flow line 50. In other words, the tube 70 plus its contents preferably has substantially the same density as that of the fluids around it in the flow line 50. The friction is a function of the weight and if the inner tube 70 becomes substantially buoyant, the weight of the inner tube 70 becomes null within the flow line 50 as it is installed. It should be appreciated that the inner tube 70 will only be buoyant in a substantially neutral manner because the buoyancy changes with the changes to the well fluids and may be different at sites other than the flow line 50. The friction between the inner tube 70 and the interior of the flow line 50 prevents the inner tube 70 from extending a great distance. The weight of the inner tube 70 acting against the inner surface 55 of the outer flow line 50 creates friction which limits the distance at which the inner tube 70 can be inserted into the outer-flow line 50. If the friction due the weight of the inner tube 70 is eliminated by the buoyancy, then this resistance has been substantially reduced. Friction not only creates a mechanical resistance in the tube if it is to be pulled into the flow line but also causes the tube to deform if the tube is forced into the pipeline. The furthest the metal extendable tube has been inserted into a horizontal well is approximately 2,743.2 meters (9,000 feet), but special wheels mounted on the tool are required. The metal extendable tube is heavy and causes greater friction against the inner surface of the flow line thus limiting the distance that the tube can travel in a horizontal flow line. The inner tube 70 has reduced utility if the inner tube 70 can only be inserted up to a few thousand meters into the horizontal portion 62 of the flow line 50. The inner tube 70 of the present invention has the advantage that it can be inserted. within a horizontal flow line a very long distance, such as 185.33 km, so that the flow line 50 itself can have a substantial length compared to the flow lines of the prior art. Therefore, preferably the inner tube 70 together with its contents is designed to float substantially neutrally. The wall of the inner tube 70 can have a bulk density that is different from the bulk density of the fluid inside. Preferably the inner tube 70 is made from a mixed material that itself bears a neutrally buoyant flow-in the flow line 50. However, the metal articulated tube or the metal extensible tube can also be make substantially buoyant by adding, for example, buoyancy to the metal tube. See patent E.U.A. No. 4,484,641, incorporated in the present invention for reference for all purposes. The potential fluids used for flow through the inner tube 70 during installation or axial movement of the inner tube 70 include, but are not limited to: (1) water; (2) seawater; (3) brine, such as calcium chloride or potassium chloride mixed with water; (4) diesel; (5) crude oil; (6) nitrogen; (7) polymeric gel; (8) gelling agent; (9) surfactant; (10) foaming agent; (11) corrosion inhibitor; (12) lubricant; (13) chemical products for dissolving or loosening the wax of the inner walls of the outer tube 50; (14) chemicals to inhibit the formation of wax or hydrates in the outer tube 50; (15) chemical products for dissolving or loosening the asphaltene of the inner walls of the outer tube 50; and (16) chemical products for dissolving or loosening the scale of the inner walls of the outer tube 50. Details regarding the use of these fluids are discussed in more detail below. The selection of the fluids for flow in and out of the inner tube 70 depends on the type of the inner tube 70 used as well as other design considerations that depend on the application. For example, the fluid inside and outside the inner tube 70 can be chosen to be the same as the bulk density of the inner tube walls. While the inner tube 70 is moved axially within the outer tube 50, the fluids can be pumped continuously through the inner tube 70. As the fluid is pumped and the inner tube 70 moves axially, the fluids in the space The annular between the inner tube 70 and the outer tube 50 will be constituted by a mixture of the original fluids in the flow line 50 and the fluids pumped through the inner tube 70. Eventually, all the fluids in the annular space can be displaced by the fluid pumped through the inner tube 70. Therefore, it can be considered that the specific gravity of the fluids inside and outside the inner tube 70 will end up being the same. The selected fluid can also be deliberately chosen to be two or more immiscible fluids that are separated into layers, under the influence of gravity, within the flow line 50 after leaving the inner tube 70. A As an example only, the immiscible fluid may comprise 50% of a fluid with a density of 0.96 kg / 1 (8 PPG) and 50% of a fluid with a density of 1438 kg / 1 (12 PPG) in such a way that The resulting fluid has a bulk density of 1.1-98 kg / 1 (10 PPG). This fluid taken together with the inner tube 70 can have a resulting bulk density of 1438 kg / 1 (12 PPG). When the fluid leaves the inner tube 70, approximately 50% of the fluid in the flow line 50 will have a density of 1438 kg / 1 (12 PPG). The fluid of 1438 kg / 1 (12 PPG), under the action of gravity, moves towards the lower parts of the flow line 50, with the condition that the flow of the annular space is substantially laminar. Therefore, the inner tube 70 will be buoyant substantially neutral in the fluid of 1438 kg / 1 (12 PPG) in the lower part of the flow line 50. The immiscible fluids can also have densities such that the inner tube 70 remains neutrally buoyant in the complete fluid outside the inner tube 70, instead of being neutrally buoyant only in the heavier density fluid outside the inner tube 70. Referring now to Figure 3, the articulated tube 76 may be metal tubing. or mixed material pipe made from sections of rigid resistance pipe that can be stacked and connected end to end so that they are inserted into the flow line 50. The sections can be connected using pipe or welded connections. The articulated tube 76 is welded or connected to each other as they are installed and the tube itself may not be extensible. The articulated tube 76 can also be segments or short sections of mixed tube that are not wound but are connected to each other. A type of articulated joint tube is described in the patent E.U.A. No. 6,003,606. With reference to Figure 3, the articulated tube 76 can be inserted and installed within the flow line 50 using a friction packing unit with friction packing techniques., well known in the field. Friction packing techniques are used when the tube 70 is not a continuous tube but an articulated tube. The friction packing unit 72 engages an articulated tube 76 and includes hydraulic pistons and cylinders to hydraulically force the tube 76 into the flow line 50. The tube 76 is then released for another stroke. Between one blow and another, another segment of articulated tube 76 is connected to the chain of tubes 76 which extends within the flow line 50. A much stronger inner tube 70 can be used if the friction packing is used to install it. because the friction packing can provide a much larger insertion force to force the tube into the flow line 50 than that which applies an injector for extensible tube. Therefore, the friction packing allows the application of a larger force on the inner tube of the chain 76 as it is forced into the flow line 50. It can be seen that the articulated tube 76 can be removed from the the flow line 50 also using friction packing techniques. Additional friction packing techniques may be used to reciprocate the tube 76 within the flow line 50. Referring now to Figure 2, the inner tube 70 is shown as an extendable tube 80. The extensible tube is a substantially continuous tube. . It should be appreciated that, depending on the necessary length of the inner tube 50, the extendable tube 80 may include a plurality of lengths 84, 86 of the extendable tube 80 connected together by appropriate connectors 88. The individual lengths 84, 86 of the extendable tube 80 they are placed on a reel 94 for insertion and installation in the flow line 50 as described in greater detail later in the present invention. It is preferred that the extendable tube 80 be buoyant substantially neutral in typical oilfield well fluids. To achieve substantial neutral buoyancy, the parameters of the extendable tube 80 and of the fluids in the submarine connection backup system can be designed to achieve substantial neutral buoyancy. For example, the composition and dimensions of the extendable tube 80 itself may have a predetermined design such as the wall thickness of the tube 80, the diameter of the tube 80, and the density of the materials constituting the extendable tube 80. In addition, the density of the fluids flowing within the flowbore 96 of the inner expandable tube 80 and the density of the fluids flowing in the flow opening 92 of the flow line 50 and in the space can also be varied. annular 90 formed between the extendable inner tube 80 and the flow line 50. All these parameters can be designed to achieve almost or completely neutral buoyancy. In addition, fluids passing through the inner expandable tube 80 can be varied for the fluid designated to cause the expandable inner tube 80 to react in a predictable manner as described later in the present invention. Of course, the extendable tube must have other properties besides buoyancy almost or completely neutral. These properties may vary with the particular installation. Therefore, in the choice of material for the extendable tube 80, said considerations may include pressure containment, tensile properties, chemical resistance, thermal resistance, pressure differentials, and other properties required for the installation. The extensible tube must also have the property of being able to withstand the differential pressures between the inside and the outside of the inner tube 70. It should be noted that the extendable tube 80 may be metal extendable tube, particularly if the metal extendable tube can be buoyant in a manner substantially neutral. The inner tube 70 of the present invention contemplates a tube that can be constructed from any material having the properties necessary to make it buoyant in a substantially neutral manner. The metal extendable tube can be a type of mixed material by including a flotation material which causes it to be a mixed material of multiple layers of different materials. For example, the metal extensible tube may have a layer of flotation material placed around it. One of the advantages of the metallic extensible tube is that it can withstand more heat than the extensible tube of mixed material. It is preferred that the extendable tube withstand any hot temperature of the well fluids because the well fluids should be as hot as possible. Because the heat is to be conducted through the expandable tube into the well fluids, the fluids flowing through the inner tube 70 will be as hot as possible. Referring now to Figure 2, an extensible tube of mixed material 80 is shown as the preferred embodiment of the inner tube 70 of the present invention. Because the extensible tube of mixed material satisfies the required characteristics, it is likely to be the material of choice. The inner tube 70 is preferably a tube of mixed material, but can be any conduit or tube that can be floated in a substantially neutral manner. In addition, the extendable tube of mixed material is convenient because it can be designed with respect to the particular mechanical properties required for the desired flow assurance operations in a particular installation. The extendable tube can be designed in many different ways that will depend on the particular project. The extensible tube of mixed material has the advantage that it can be designed for the particular installation. The extensible tube of mixed material can not only be designed to float, but the extensible tube of mixed material has other suitable properties, in specific pressure containment, traction properties, chemical resistance, thermal resistance, pressure differentials, and other properties required for the particular installation. Therefore, a tube of mixed material is more convenient than a metal tube. The extensible tube of mixed material is shown in US Patent Nos. 5,828,003; 5,908,049; 5,913,337, and 5,921,285 and in European Patent Application No. 98308760.2 filed on October 10, 1998, published on April 28, 1999, publication No. EP 0 911 483 A2, all incorporated in the present invention for reference. The lengths 84, 86 of the extendable tube of mixed material 80 can be connected by connectors such as those shown in the patent E.Ü.A. No. 5,988,702 and in the patent application E.Ü.A. Serial No. 09 / 534,685 filed March 24, 2000 and entitled "Coiled Tubing Connector", both incorporated in the present invention for reference. Referring now to Figure 4, there is shown a more preferred extensible tube 80 of mixed material, which preferably includes a tube made from a mixed material and including a waterproof impermeable coating lining 100, a layer of fiberglass 102, a plurality of conductors 104 and fiber optic cables 106 around the casing 100 and the glass layer 102 embedded in a protective resin 108, a plurality of load bearing layers 110 forming a matrix of carbon fiber, a wear layer 112, a layer of polyvinylidene fluoride (PVDF) 114, and an outer wear layer 116 formed from glass fibers. The fluid impervious casing 100 is an inner tube preferably made from a polymer, such as polyvinyl chloride or polyethylene, or any other material that can tolerate the chemicals used for the assurance of flow and temperatures of any hot liquids flowing through the flow opening 96. The casing 100 is impermeable to fluids and therefore insulates the load bearing layers 110 from the hot chemicals and / or liquids that pass through the opening of the liquid. flow 96 of the casing 100. The load carrying layers 110 are preferably a resin fiber having a sufficient number of layers to sustain the required load of the inner tube 70, in particular during installation. The fibers of the load bearing layers 110 are preferably wound in a thermosettable or curable resin. The load carrying fibers 110 provide the mechanical properties of the inner tube 70. The wear layer 112 is preferably an external load carrying layer 110. Although only one wear layer 116 is shown, additional wear layers may be required as required . The PVDF layer 114 is impervious to well fluids and insulates the load bearing layers 110. The outermost wear layer 116 is preferably the outermost layer of fiber and is a sacrificial layer. The extensible tube of mixed material is also described in the patent application E.U.A. Serial No. 09/081, 961, filed May 20, 1998 and entitled "Well System", incorporated in the present invention for reference. Referring now to Figures 2, 4, and 5, conductors 104 and fiber optic cables 106 that are housed within the wall of the mixed material tube 122 extend along the entire length of the extendable tube of material. mixed 80 and are connected to a power source 118 and a surface processor 120. Their down-hole ends can be connected to the electronic component package 124 of a downhole tool 130, described later in the present invention, to perform an operation of flow assurance within flow line 50. A standard fiber optic cable can be used for communications. The conductors 104 can provide both power and command signals to the downhole tool. In addition, the data collected by the downhole tool 130 can also be communicated in "real time" through the conductors 104 and the fiber optic cables 106 to the surface processor 120. It should be appreciated that the conductors 104 and / or the cables 106 in the wall of the inner tube 70 are only an option and that they are not required for the present invention. The optical fibers constructed in the wall 122 of the tube 80 can be used to measure the temperature and pressure along the lengths 84, 86 of the extendable tube 80. For example, light reflectometry techniques can be used to monitor the temperature along the entire length of the inner tube 70. A beam of light is sent by the fiber optic cable 106 and a device The electronic detects the reflection from the fired light to determine the temperature at any point along the length of the extendable tube 80. There are different types of light reflections and several different techniques to achieve temperature monitoring using optical fibers. One method for light reflectometry is to use Bragg gratings. Bragg grids act as separate detectors. Other light reflectometry techniques allow fully distributed measurements along the length of the fiber optic cable. You can also use light reflectometry to measure the pressure. You can use light reflectometry to measure the deformation. If the fiber optic cable 106 is wound helically around the casing 100 in the wall 122 of the extendable tube 80, as the pressure differential across the wall 122 of the extendable tube 80 causes the wall 122 it expands and contracts, the optical fibers measure the deformation caused by this pressure. The deformation measurement is then related to the pressure to obtain a pressure measurement. The extendable tube 80 may also include detectors embedded in the wall 122 of the extendable tube 80 which are spaced apart at each number of meters along their length to detect temperature, pressure or other parameters. See patent E.U.A. No. 6,004,639, incorporated in the present invention for reference. Although the extendable tube 80 is preferably an extendable tube of mixed material having optical fibers and conductors along the length thereof, it should be appreciated that the metallic extendable tube may also include optical fibers and conductors mounted on the inside or outside of the tube. metal extendable tube. The lengths 84, 86 of the extendable tube of mixed material 80 having conductors 104 and cables 106 can be connected using the connector described in the patent application E.U.A. Serial No. 09 / 534,685 filed on March 24, 2000 and entitled "Coiled Tubing Connector". Referring now to Figure 2, the extendable tube 80 can be inserted and installed within the flow line 70 using techniques for extendable tube. On the surface 45, an operational system 47 includes the power source 118, the surface processor 120, and a motorized extendable tube reel 94. The motorized reel 94 supplies the extendable tube 80 through a guide 124 and into an injector head unit 126. The injector head unit 20 supplies and directs the extendable tube 80 from the reel 94 through the devices burst protectors 128 and the stuffing box 130 and inside the return line portion of flow line 64. The injection of the extendable tube 80 is a continuous operation compared to the installation of articulated tubes. Although Figure 2 illustrates the installation of extendable tube 80 from platform 42, it should be appreciated that extendable tube 80 can be injected at any point in flow line 50 using standard extensible tube installation techniques. To reach very long distances (up to 185.33 km), the extendable tube 80 can be supplied in a plurality of different reels and then connected together using connectors, as previously described, as the pipe 80 is run inside the the flow line 50. Referring now to Figure 6, the installation of extendable tube 80 using only the injector head unit 126 will only allow the extendable tube 80 to be installed in the flow line 50 at a limited distance, particularly in cases where the extendable tube 80 is to be installed against the flow of the well fluids. It is possible that fluid can be pumped through the flow line 50 and then the inner expandable tube 80 is inserted into the fluid flow which allows the fluid to pull the expandable tube 80 through the flow line 50 to install the fluid. extendable tube 80 within flow line 50. Hydrodynamic forces can draw inner expandable tube 80 through flow line 50 to the distance required for flowability. An additional motive force may not be necessary. This installation method may not be easily used in a production flow line unless there is a second flow line for circulation. As shown in figure 6, the extendable tube 80 can be inserted and installed at any point along the flow line such as in the manifold 60 or at an intermediate location 132 along the flow line 50. The connection points can be located in "bypass" branches, such as 134, 136, in the flow line 50 and the collector 60, respectively. The branches 134, 136 include "Y" -shaped sections in the flow line 50 and the manifold 60, in which the branches 134, 136 have conduits for receiving the installation insert of the extendable tube 80 or an extendable tube length. 80. The branches 134, 136 have smooth curves for receiving and installing the extendable tube 80 in the flow line 50. These curves allow insertion through the branches 134, 136, of downhole tools, such as a tractor in the end of the extendable tube 80, as described later in the present invention. The pressure control equipment 138, 140 is included in the branches 134, 136 together with valve systems not shown. The entry point includes various components that can be found in a well head. For example, a type of pressure control equipment might look like a lubricator. It may be necessary to lift the flow line 50 from the seabed 44 to insert the inner tube 70 because it may not be possible or practical to access the flow lines in some other way. For example, the flow line 50 may be buried in the seabed 44. The branch 136 in the manifold 60 is preferred because it provides flexibility in the use of the extendable tube 80 for flow assurance. As described below in the present invention in greater detail, the outboard conduit 146 of the branch 136 may allow the liquid flowing through the extendable tube 80 to be emptied into the sea or the branch 136 to be connected to another. flow line or return line to the production plant 40. In addition, the extendable tube 80 may remain connected to the branch 136 or may be disconnected. The branch 136 also allows multiple inner tubes 70, 71. The extendable tube 80 can be inserted and installed through the branches 134, 136 in the flow line 50 and in the manifold 60 using techniques for extendable tube from a floating vessel 142. that also has a motorized reel 94 that feeds the extendable tube 80 into an injector head unit 126 using a Swift return duct 144. The Swift return duct is used to deploy the extendable tube 80 from the floating vessel 142. The return duct Swift includes a method for deploying an extendable tube or tube of mixed material in which the boat holds the extendable tube reel 80 and then pushes the tube 80 into the flow line 50 from the boat. Although the extendable tube 80 can be inserted either with the flow of the well fluids or against the flow of the well fluids, as shown in Figure 6, it is preferred to insert the extendable tube 80 with the flow of the fluids of the well. well in the flow line 50 whereby the hydrodynamics of the flow of the well fluids aids in the insertion and travel of the extendable tube 80 within the flow line 50. It is convenient to install the inner tube 70 without having to interrupt the flow through flow line 50.

Allowing the inner tube 70 to be inserted into the flow line 50 at any point provides many advantages. If the flow line 50 is blocked and the inner tube 70 is to be used to clear the blockage, this method allows the inner tube 70 to be installed close to the locking point, at any point where the blockage is located. the flow line 50, which can be many kilometers long. Furthermore, as previously described, if the submarine connection backing is to be 185.33 km long, the inner tube 70 can be installed in segments, such as the segments 148, 150, 152, shown in Figure 6. If there were a flow line of 185.33 km and assuming that the inner tube 70 can be installed only in segments of 37,066 km in length, the segments of 37,066 km of inner tube 70 can be installed at various points along the flow line 50 Typically, this would be a temporary installation that does not require the connection of the multiple segments 148, 150, 152 of the inner tube 70. However, if this is going to be a permanent installation of the inner tube 70 within the flow line 50 of 185.33 km in length, the adjacent ends of the inner tube 70 are connected to each other at the entry points to form a continuous inner tube 70 from the production plant 40 to the manifold 60 as shown in the figures s 9-11. The flow line 50 can include five entry points for the installation of the 37,066 km 5 segments of the inner tube 70. To install the extendable tube 80 at any appreciable distance within the flow line 50, such as several kilometers, it is preferable to provide impulse means. For example, any of a leveler or propulsion system can be attached to the extendable tube 80 to provide a driving force for the installation. The lower end 135 of the extendable tube 80 can be connected to the leveler or tractor by means of a disconnect assembly for connecting and disconnecting the extendable tube 80. In addition, the inner tube 70 must have the tensile strength necessary to support the necessary pull on the extensible tube of mixed material 80 by any means of impulse. One method to assist the installation of the inner tube 70 within the flow line 50 is to pump fluid through the annular space 90 formed between the inner tube 70 and the outer flow line 50. This is particularly applicable to a new installation in which a pump can be connected to the flow line 50. The fluids can then be pumped in the same direction as the direction of insertion of the inner tube 70 so that the tube 70 moves in the same direction as that of the fluids. Said moving fluid can allow for example the installation without a tractor or leveler. In a new installation, the inner tube 70 can be installed before the well fluids flow through the flow line 70. As the inner tube 70 is floating substantially neutrally, any friction caused in some other manner by the weight of the inner tube 70 when acting against the inner surface 55 of the external flow line 50. Therefore, the friction no longer limits the distance at which the inner tube 70 can be inserted into the external flow line 50. However, there are still side effects in the inner tube 70 that ultimately limit the distance at which it can be installed within the flow line 50. Any flow line 50 is to be spread across an undulating terrain which causes that has curves both upwards and downwards and to the sides because the terrain of the seabed 44 is not uniform. It is necessary for the inner tube 70 to negotiate all the curves in the flow line 50. Therefore, the inner tube 70 tends to settle on the walls of the flow line 50, particularly around the curves and elbows of the flow line. flow 50, and therefore creates winch friction. Winch friction occurs when any member moves against another member as it moves around an elbow. Therefore, due to the elbows of the flow line 50, winch friction occurs between the inner tube 70 and the wall 55 of the flow line 50. Also as previously described, hydrodynamic resistance can be presented from the fluids of well, if the well fluids are flowed against the inner tube 76 as it passes through the flow line 50. The hydrodynamic influence slows down the speed at which the inner tube 70 moves through the line 50. Referring now to Figure 7, a method for installing the inner tube 70 in view of these side effects is to attach a flow restricting element, such as a leveler 154, to the end 156 of the extendable tube 80. Fluid is pumped using a pump 158 on the platform 42 through the annular space 90 between the inner tube 70 and the flow line 50. The flow of fluid against the leveler 154 provides the driving force for driving the tub or extendable 80 within the flow line 50 creating a pressure differential through the leveler 154. The inner tube 70 with the leveler 154 is thus pumped by the flow line 50. The leveler 154 is not necessarily located in the end 156 of the extendable tube 80. In addition, it is also not necessary to have a leveler and a plurality of levelers joined along the length of the inner tube 70 could be present. Referring now to Figure 8, a propulsion system can be connected. , such as the tractor 160, to the end 156 of the extendable tube 80 to provide the driving force for inserting and installing the extendable tube 80 within the flow line 50. If the extendable tube 80 is, or is almost floating in a neutral manner in the fluid of the flow line 50, the tractor 160 can pull the extensible tube to many kilometers, possibly up to 185.33 km, through the flow line 50. A tractor will have to work against much larger forces if it is installing the inner tube 70 in the opposite direction to the flow of the well fluids in the 50 flow line. therefore, whether or not the inner tube 70 can be installed in a direction opposite to the flow will depend on the amount of driving force that the tractor 160 can achieve. One aspect is the radius of the different elbows in the flow line 50 because if the radius of curvature of the elbow is very small, it can not adapt the use of a tractor. Any curve provides a certain amount of friction and resistance to the movement of the inner tube 70 within the flow line 50. Therefore, it is important that the entry point has a very "soft" curve for the insertion of the tractor 160 and the tube 80. The entry point may include valves and pressure control equipment as previously described. During the insertion of the inner tube 70 into the flow line 50 through the branches 132, 134, the curved conduits of the branches 132, 134 within the flow line 70 have a smooth curvature to receive the end 135 of the tube interior 70 with tractor 160. Various types of tractor can be used such as the Western Well Tool tractor shown in the US patent No. 6,003,606 or the propulsion system shown in the patent E.U.A. No. 3,180,437, both incorporated in the present invention for reference. Welltec also manufactures a tractor powered both electric and hydraulic. These propulsion systems can be driven either hydraulically or electrically. An electrically powered tractor can be used if the extendable tube 80 of Figure 4 is used as the inner tube 70 because said extendable tube includes conductors 104 that transmit electrical energy downstream from the platform 42. Sufficient energy is provided for the tractor to work against any contra-flow of well fluids.

The Western Well Tool tractor uses fluids that flow through the extendable tube 80 to provide power to the tractor 160. The Welltec hydraulically driven tractor includes a turbine with paddles that are made to pass by passing liquids through the turbine. The fluid that has momentum comes in contact with the paddles and then changes direction. This change of direction provides a force against the blades to spin the turbine. The liquid drives the turbine and the turbine is connected to a hydraulic pump on the tractor. The hydraulic pump is part of a closed hydraulic system in the tractor in which the closed circuit keeps the hydraulic fluid in the system clean. The Welltec tractor drives wheels on the tractor that sit on the wall of flow line 55. Each wheel has a hydraulic motor. In cases where the tractor 160 is hydraulically actuated from the fluids passing through the inner tube 70, once the tractor 160 has pulled the inner tube 70 for several kilometers, the hydraulic pressure of the fluids dissipating is dissipated. they flow through several kilometers of inner tube 70 along said large distance as it reaches tractor 160. The liquid can be pumped through inner tube 70 but this does not provide enough energy at the tailed tail end that it passes through the tractor 160 to drive the hydraulically actuated tractor. Therefore, the energy needed to operate the tractor 160 may not be sufficient by the time it reaches the tractor 160. Hydraulically operated tractors require a minimum amount of hydraulic pressure. One solution is to insert a large bubble of gas from time to time into the flow opening 96 of the inner tube 70. The gas does not have the same energy loss as that of a liquid and can transmit pressure over very long distances, especially at relatively low flow rates. The liquid loses its energy due to friction losses and the gas does not have the same degree of friction losses. The compressed gas can transmit a much greater amount of energy than the liquid. Because the gas is quite compressible, it has an immense amount of energy stored in the gas and is therefore a good vehicle for energy transmission. Therefore, this elevated pressure can be transmitted directly to the interface between the gas and the driving liquid. However, it can not transfer sufficient energy or momentum to the type of turbine typically used in these tractors. For example, if the inner tube 70 were completely filled with gas, a pressure of 351.5 kg / cm2 of gas at the inlet of the inner tube 70 could almost completely transfer the 351.5 kg / cm2 of pressure to the tractor 160 many kilometers away. At the gas / liquid interface, the gas, which has 351.5 kg / cm2 of pressure, applies a pressure of 351.5 kg / cm2 in the liquid at the gas / liquid interface. Therefore, the gas is used to drive the liquid. Alternately, large gas bubbles and liquid segments will be flowed through the inner tube 70. The gas / liquid interface can incorporate a gel in order to keep the phases separate. This layer of gel between the gas and the liquid prevents the gas from traveling through the upper part and around the liquid, where instead of transferring the force to the liquid, the gas tries to pass around the liquid. As the power fluid flows through the inner tube 70, the liquid / gas interface also moves, i.e., which means that the high pressure region also moves, such that the distance between the tractor 160 and the high pressure region becomes shorter. The net effect is that the power fluid has to travel a progressively shorter distance between the high pressure region and the tractor 160 in such a way that there is a lower pressure drop between the high pressure region and the tractor 160. way, the tractor 160 can receive sufficient energy to pull the inner tube 70 into the flow line 50. Eventually, the interface between the gas and the power fluid reaches the tractor 160. Once the gas reaches the tractor 160, the The tractor's turbine will not be able to generate enough power because the gas has a significantly lower density than the power liquid. The tractor 160 stops. However, the gas will be followed by another stretch of power fluid which by itself is also driven by the pressurized gas. Once the power liquid reaches the turbine of the tractor, and as it passes through it, the tractor 160 moves and pulls the inner tube 70. The gas and power liquid follow each other in amounts suitable for the design of the tractor turbine and the hydraulic properties of the fluids and the inner tube 70. The inner tube 70 therefore enters the stream line 50 in jets. Insertion distances of up to 185.33 km are possible using this technique in conjunction with a tractor driven by a hydraulic turbine. Because the liquid and gas passing through the flow opening 96 of the inner tube 70 finally exit the tractor 160 towards the annular space 90 between the inner tube 70 and the outer flow line 50, the introduction of the gas into the annular space 90 benefits the buoyancy of the inner tube 70 within the flow line 50. The design of the inner tube 70 will account for the buoyancy reduction due to the gas in that it still has sufficient buoyancy to install the inner tube 70. However , consider an inner tube 70 of 3.81 cm in diameter inserted into a flow line 50 of 30.48 cm in diameter. Said cross sections require more than 60 times more time to fill any given length of the annular space 90 in the flow line than the time required to fill the inner tube 70. For example, considering a flow line of 9,267 km in length and speeds of typical flow, it would take 8 hours to fill the annular space 90 in the flow line 50 and only 8 minutes to fill the flow opening 96 of the inner tube 60. Because there is a great difference in these volumes, the gas passing to the through the smaller inner tube 70 does not have a large impact on the density of the well fluids in the annular space 90. Furthermore, the fluids that are selected to operate the tractor 160 may include liquids such as drilling fluid, which has a high density, and a gas, such as nitrogen. Alternatively, a gas and a liquid can be combined with a foaming agent to create a foam as the power fluid to drive the tractor 160. For example, water can be mixed with nitrogen. You can also choose the foaming agent to have a predetermined shelf life. The useful life can be designed such that the foam is stable while being pumped through the inner tube 70. After leaving the inner tube 70, the foam is then destabilized and separated again in a liquid and gas. The inner tube 70 taken together with the foam can be selected such that they have a total bulk density so that the inner tube 70 remains buoyant in substantially or completely neutral form in the separated liquid which will be discarded in the lower parts of the line. flow under the influence of the force of gravity. It should be appreciated that the inner tube 70 can be removed from the flow line 50 using the same techniques for extensible tube. In a new installation, the inner tube 70 is preferably installed when there is no fluid flow through the flow line 50, although there is no reason why the inner tube 70 can not be installed in the flow line 50 while There is fluid flowing through the flow line. A pressurized flow line can be introduced. It is simply a matter of having the appropriate pressure control equipment installed such as the expandable tube bursting devices. Of course, there will be hydrodynamic forces acting on the inner tube 70 as it is installed while the well fluids flow through the flow line 50. This could require a tractor 160 at the end of the inner tube 70 to work against higher forces where the inner tube 70 is installed against the flow. In existing flow lines, only a sufficient bend radius is required to allow the levelers to pass through the flow line. The minimum radius of curvature for the levelers is five times the diameter of the flow line 50, that is, a 5D curvature. This is the classic minimum radius of the flow lines. Therefore, the inner tube 70 will have to negotiate these closed curvatures 5D within the flow line 50. any tractor 160 positioned at the end 135 of the inner tube 70 to install it within the flow line 50 must negotiate the 5D curvatures in the flow line 50. In the above case, the tractor assembly 160 at the end 135 of the inner tube 70 can be constructed in such a way that it can negotiate the curvatures 5D. For the tractor 160 to negotiate the curvatures 5D, the housing 162 may be constituted by segments 164 connected together by a type of universal joint 166 such that the housing 162 is bent with the bends and curves in the flow line 50. The inner tube 70 can be installed within the flow line 50 after the flow line 50 is installed on the seabed 44. During the installation of the inner tube 70 after the flow line 50 is installed, the buoyancy is substantially neutral of the inner tube 70 minimizes the force required to install the inner tube 70 within the flow line 50. The driving force will be a tractor 160, a leveler 154, or simply the hydrodynamic forces of a fluid flowing in the annular space 90. It should be noted that in a permanent installation, the inner tube 70 can be installed simultaneously with the outer flow line 50. It is possible to install the inner tube 70 with the flow line 50. Unfortunately, the cost of connecting the sections of inner tube 70 and outer flow line 50 is very high and is extremely expensive in large diameter tubes. Currently there are boats that can wind a 40.64 cm diameter tube. Therefore, the double concentric tube can be built on the coast by welding together the adjacent sections of inner tube while at the same time welding the external flow line sections and then winding the double concentric tube assembled on the inner tube. the ship. The double concentric tube could possibly also be towed towards the site and then installed. It should be appreciated that it is more practical to install the inner tube after the flow line is installed. Referring now to Figure 11, if the inner tube 70 is to remain in place in a fluid that is flowing in a direction opposite to the insertion direction of the inner tube 70, it is preferred to anchor the upstream end of the inner tube 70. An anchor 190 may be placed at the end 135 of the tube 70 to anchor the inner tube 70 relative to the flow line 50 in order to withstand the hydrodynamic forces coming from the flow in the flow line 50. The flow of fluids around the inner tube 70 within the outer flow line 50 will have an effect on the inner tube 70. An adverse behavior, such as a vibration or settling, of the inner tube 70 may occur, as the well fluids flow to the through it due to hydrodynamics. Once the inner tube is anchored, the inner tube 70 can then be tensioned within the flow line 50 by pulling against the anchor 190. These adverse conditions can be controlled by varying the tension in the inner tube 70. The control over the tension help control the behavior of the inner tube 70 and the fluid flowing around it. It would be convenient if the inner tube 70 is placed on one side of the flow line 50 because the inner tube 70 will then have a better reaction behavior when the fluid flows around the inner tube 70. It is preferred that the end upstream 135 of the inner tube 70 is anchored and that the downstream end extends through the entire flow line 50 and through the injector head unit 126 on the platform 42. If the inner tube 70 extends throughout the entire the length of the flow line 50, the upstream end 135 of the inner tube 70 is anchored at or near the manifold 60. It is preferred to anchor the upstream end 135 because if it is not anchored, the flow of the well fluid tends to push the inner tube 70 out of flow line 50. There are several types of anchoring devices. An anchor type 190 can be attached to the end of the inner tube 70 and then connected at or near the manifold 60. The anchor 190 could simply be a bolt between the end of the inner tube 70 and the flow line 50 or manifold 60 as for example, a spring-loaded bolt. A stage is one in which a hook member is installed in advance near the manifold 60 to which the end of the inner tube 70 is to be hooked, such as a crimping connection. The flow line 50 or the manifold 60 may have a plug-like connection in which the inner tube 70 is engaged in the plug. In addition, the flow line 50 may include a connector member positioned therein that is ready to receive and engage the end of the inner tube 70. The anchor 190 may be remotely releasable by mechanical devices (e.g., safety pin) , electric (for example, solenoid-operated bolt), hydraulic (pressure pulse activated), or other appropriate release device. In the case where the inner tube 70 is a retrofit within the flow line 50 and nothing to which it can be engaged is present, the anchor 190 can be carried at the end of the inner tube 70. Said anchor can be a member positioned at the end of the inner tube 70 which is driven to frictionally seat the inner surface 55 of the flow line 50. This type of anchor allows the inner tube 70 to anchor to the interior surface 55 of the flow line 50 at any point along the flow line 50. For example, a friction coupling can be used with the flow line 50. Sawed tabs (slips) that are driven to engage can also be present. in a biting manner to the inner surface 55 of the flow line 50. Any of the packer feet used in the tractors can also be used as retention devices. See, for example, the perforation retention device described in patent application E.U.A. Serial No. 09 / 485,473, filed on April 30, 2001 and titled "Borehole Retention Device". The anchor 90 can be a flexible packer or a pre-installed plug attached to the end 135 of the inner tube 70 or a pre-installed plug with the end 135 of the inner tube 70 packaged by friction in the pre-installed plug almost in the same way in which the downhole completions are made. The plug is then actuated to effect closure of the annular space 92 and allow the well fluids to flow through the inner tube 70. The annular space can then be filled with an insulating medium that can be pumped into place to isolate the tube interior 70. The insulating means may be a flowing fluid or these may be a static fluid in the annular space 90. They could be cement. It should be appreciated that a plurality of inner tubes 70, 71 may be present within the flow line 50 lying in parallel with one another in the flow line 50. Although this embodiment loses flexibility, it aids in the problem of flow reduction as described later in the present invention in greater detail. This mode is even more convenient than a 25.4 cm flow line that is inserted into an outer tube of 40.64 or 45.72 cm that has insulating material in the annular space between them. Obviously, an outer tube of 40.64 or 45.72 cm requires additional insulation which makes it much more expensive. The inner tube 70 of the present invention can be used in many operations and method related to flow assurance. The flow assurance agency may differ depending on which variation is used. The following describes some of the flow designs for use with the inner tube 70. With reference again to Figure 2, the inner tube 70 can be used in an open circuit 170. In the open circuit 170, the upstream end 135 of the inner tube 70 is opened such that any of the fluids being pumped through the inner tube 70 flow to the flow opening 92 of the flow line 50. The fluids leaving the inner tube 70 are mixed with the fluids in the flow line 50 and interact with the well fluids traveling upstream. The open circuit 170 is typically used to mix fluids with the well fluids in the flow line 50 to condition the well fluids. If the open circuit 170 is used, then the fluids flowing through the inner tube 70 to interact with the well fluids should ensure that the mixing of the fluid with the well fluids does not present a problem with the well fluids. For example, it may not be appropriate for water to mix with well fluids due to the hydrate problem. A preferred fluid could be stabilized crude ie well fluids that have been processed in the production plant 40. The processed crude is heated and recirculated through the inner tube 70 and back to the annular space 90 between the inner tube 70 and the flow line 50. Referring now to Figure 9, the inner tube 70 can be used in an environmentally closed circuit 172. In the closed circuit 172, there is an anchoring component with an outlet in the mandrel 60 for joining and anchoring the upstream end 135 of the inner tube 70. In the closed circuit 172, hot seawater is flowed through the inner tube 70 and out of an outlet, such as the branch 136, into the open environment or seawater due that the fluid flowing through the inner tube 70 is in any way seawater. This is a variation to the open circuit 170 in the sense that the inner tube 70 is not open to the flow line 50 but is open to the seawater environment. In the closed circuit 172, the end 135 of the inner tube 70 is connected to a connection 176 which is a pre-installed internal connection point for the inner tube 70 at the far end of the flow line 50. The connection point 176 it can be connected to the anchor 190. The connection point and the anchor point can be combined. Once the inner tube 70 is installed in the flow line 50 and connected to the connection point 176, this connection point directs the fluid exiting the upstream end 135 of the inner tube 70 and includes a conduit 180 from the end 135 of the inner tube 70 to another conduit that directs the fluids from the inner tube 70 to a location outside the flow line 50. The conduit may be provided with a valve. The connection 176 is preferably a releasable connection. The connection point 176 can be a branch 136 in the shape of ¾Y "communicating with the outer flow line 50, such that the fluids pumped through the inner tube 70 do not mix with the fluids in the flow line 50. In the system shown in Figure 9, the "Y" shaped branch 136 opens into the open sea, Therefore, any fluids flowing through the inner tube 70 in the environmental closed circuit 172 flow towards the In some cases it may be desirable to have a closed circuit 172 in which the flow in the inner tube 70 does not mix with the flow in the flow line 50. The environmental closed circuit 172 allows hot liquids compatible with the liquid to be pumped. sea water through the inner tube 70 and thrown into the sea In the preferred embodiment, hot sea water is pumped through the inner tube 70 and then ejected into the open sea, however, the inner tube 70 is EC rred with regard to well fluids. The fluid through the inner tube 70 can flow into the sea or flow into another line of fluids returning to the production plant. With reference now to figure 10, the inner tube 70 can be used in a closed return circuit 174. In the closed return circuit 174, the end 135 of the inner tube 70 is connected to a connection 176. However, the conduit 180 coming from the connection 176 is connected to a return line 182 that extends back to the platform 42. The closed return circuit 174 is particularly useful in cases where the fluid passing through the inner tube 70 is not sea water and is a fluid that can not be thrown into the seawater environment 178. Instead of to discharge the fluid to the seawater environment, it passes to a return duct that returns the fluid to the production plant 40. For example, fluids can be circulated continuously for heating in the closed-loop return system. and return to the point of origin of the pumped heating fluids, such as the production plant 40. Referring now to Figure 16, another modality of the return closed circuit 176a is shown in this one. The return pipe is another inner pipe 183 placed inside the flow line 50 with the inner pipe 70. The two inner pipes 70, 183 are connected at their downstream end 185 so that the fluids can be circulated from the floor of the plant. production 40 to the downstream end 185 of the tubes 70, 183 and then back to the production plant 40, all within these two inner tubes 70, 183 which are both placed within the flow line 50. The inner tubes 70, 183 can be joined together and inserted into the flow line 50 simultaneously during installation. Another alternative is to install all the electric and hydraulic control umbilicals within the flow line 50. In cases where the extendable tube 80 shown in Fig. 4 is used, the electric and hydraulic control umbilicals can be passed with the conductors through the wall of the extendable tube 80. The conductors in the walls of the tube 80 may have connectors at the end of the tube 80 which are connected to all the control systems that control the shafts 18 through the connection 176. Therefore , the extendable tube 80 can be used both for flow assurance and for providing the necessary control umbilicals for the manifold 60 and the shafts 54. Alternatively, an inner tube 70 for flow assurance and other inner tubes can be present, such as the inner tube 71, for the control umbilicals. Referring now to Figures 2 and 9-10, in order to maintain the high temperature of the well fluids flowing from the manifold 60 to the production plant 40, the inner tube 70 can be used to heat the flowing well fluids. through the annular space 90 between the inner tube 70 and the outer flow line 70. During the flow of fluids in the flow line 50, hot liquid is pumped through the inner tube 70 to provide thermal feed to the fluids, typically the Fluids in the flow line are well fluids, which flow through the 50 flow line. Said flow assurance operation will probably be for long-term use. From the thermodynamic point of view it is more appropriate to place a smaller tube inside the flow line instead of placing a larger tube around the flow line. The hot liquids pumped through the inner tube 70 may be hot crude oil or hot water or other practical and available liquid. Hot crude oil is most likely for open circuit systems 170, as shown in Figure 2, where the hot crude oil is to be mixed with the well fluids flowing in the 50 flow line. Seawater is the most likely hot liquid for an environmental closed loop system 172, such as the one shown in Figure 9, in which the fluid is not mixed with the flow in the flow line 50 but can be throw into sea water 178. Other fluids can be used that can not be mixed with well fluids or seawater with the closed return circuit. 174, as shown in Figures 10 and 16. The hot fluids are pumped particularly through the inner tube 70 to heat the well fluids before restarting the flow after a cessation of operations. After a prolonged interruption of the flow in the flow line 50, the well fluids tend to cool and need to be reheated before restarting the flow. It is more preferred to have the inner tube 70 extend into the main flow line 50 along its entire length as shown in Figures 9-11. One embodiment includes an inner tube 70 having a diameter of 10.16 cm, within the main flow line having a diameter of 30.48 cm. Hot water is flowed through the 10.16 cm inner tube 70 to maintain the temperature during the flow conditions and to reheat the flow line 50 to prepare it for restart after a prolonged stop. It is most preferred that the closed return loop 174, shown in FIG. 10, or the closed circuit 174a, shown in FIG. 16, have a flow line 50 of 30.48 cm with an inner tube 70 of 10.16 cm and 2.54. cm of thermotite-type insulation around flow line 50 of 30.48 centimeters, buried at 0.9144 meters depth and circulate hot water through the inner tube 70 of 10.16 cm and back to the production platform 42. The previous system is effective in terms of costs, certainly significantly (hundreds of millions of dollars) less expensive than those of the prior art and the thermal efficiency of heating coming from the circulation of hot water is much higher than in the prior art. The thermal efficiency is adequate because the hot water flow is presented within the 30.48 cm flow line 50 and all the heat conducted outside the 10.16 cm inner tube 70 goes to the well fluids. The double concentric tube of the prior art having a 50.8 cm outer carrier tube loses much of its heat to surrounding seawater and seabed instead of conducting heat into the well fluids. In addition, the prior art requires much more energy. Also, the reheat time after a prolonged interruption can be 12 days for the 50.8 cm carrier tube system of the prior art compared to two days for the 10.16 cm inner tube system of the present invention, again significantly less energy required by the 10.16 cm inner tube system. A leveller for removing wax or hydrates is no longer necessary because the inner tube 70 can provide enough heat to heat the well fluids in the flow line 50 thereby maintaining the temperature of the well fluids at a minimum temperature to avoid the formation of hydrates or the accumulation of wax. Therefore a leveler is no longer required because there is little or no accumulation. If a flow assurance operation is necessary, a downhole chemical tool or products could be used as described later in the present invention. Referring now to Figure 11, in cases where the inner tube 70 lies at the bottom of the flow line, such as at 192, stagnation areas begin to occur because said areas are out of the way of the main flow of the well fluids. The main flow through the center of the flow line 50 does not pass through the dead areas 192 and causes the stagnation of the fluids. Water tends to accumulate at these low points and the electrolytic action causes corrosion of the flow line. In order to avoid pooling and accumulation of water / electrolyte in the stagnation areas at the sites 192, the inner tube 70 can be moved periodically back and forth with the flow line 50 using the extensible tube or tubing techniques. friction packing, previously described, in order to agitate and empty the regions of fluid stagnation. Another way to agitate the stagnation areas is to move the inner tube 70 in a direction normal to the axis of the flow line 50. This can be achieved by pumping pulsations (slugs) of fluids of different density through the inner tube 70 to cause sections of the inner tube 70 float and sink alternately. It is not necessary that the inner tube 70 has to be moved very far from the inner surface 55 of the flow line 50 to agitate the stagnant areas and cause the well fluids flowing through the flow line 50 to be coupled with stagnant fluids and remove them by flowing them. The inner tube 70 can be caused to move through the flow line 50 although well fluids are present flowing in the flow line 50 or even if the flow is suspended because the wells are temporarily closed. Several pulsations of fluids could be pumped through the inner tube to cause a wave movement in the inner tube 70 due to a change in the buoyancy of the inner tube 70 within the flow line 50. Such fluids include water, drilling fluids, gas, chemical products, methanol, glycol, or any of the other typical oil field fluids that may be available. Each of the fluids provides a different range of densities to change the buoyancy of the inner tube 70. For example, a gas pulsation of hundreds of meters in length can be introduced into the inner tube 70. This can deliberately alter the buoyancy of the tube. interior 70 within the exterior flow line 50. Referring now to Figure 2 showing an open circuit 170, during the flow of well fluids in the flow line 50, chemical products, such as methanol, can be pumped the inner tube 70 to be mixed with the well fluids in the flow line 50. Chemicals may be necessary for a variety of reasons to condition the fluids in the flow line 50, including inhibition of corrosion, inhibition of wax , and prevention of hydrate formation. As distinguished from the prior art, the chemicals are injected into the flow line 50 through the inner tube 70 instead of through an external chemical injection pipe, such as the pipe 26 shown in FIG. Figure 1. There are many reasons why chemical products can be injected into the well fluids through the inner tube 70 and into the flow line 50. Referring now to Figures 9 and 10, for example, consider a cessation of unplanned well operations so that the well fluids no longer flow through the flow line 50 and are cooled. The pumping capacity is lost and there is no circulation through the flow line 50. In a closed circuit 172 or 174, hot water can be flowed through the inner tube 70. In the circuit 172, the hot water can flow through the inner tube 70 and into the seawater environment and heating the well fluids in the flow line 50. In the circuits 174 and 174a, hot water can be circulated through the inner tube 70 to heat the fluids of well. In these closed circuits, the inner tube 70 is not blocked by the formation of hydrates because it is not open to be mixed with the well fluids and therefore circulation is possible because it is not blocked. Because the inner tube 70 is filled only with seawater, it will never be blocked by hydrates. Therefore, even when the well fluids can solidify around the inner tube 70 in the flow line 50, this will not prevent the flow of water through the inner tube 70. In the open circuit 170, all are cooled, both the well fluids in the flow line 50 as the fluids in the inner tube 70, which allows hydrates to form. Therefore, the inner tube 70 no longer functions because there is already no flow through the inner tube 70. Therefore, the closed circuits 172, 174 are preferred because the inner tube 70 is connected to an outside environment. . Alternatively, after the cessation of operations, the hydrates are not formed immediately, and it could take 12 to 20 hours for the well fluids to cool before the hydrates are formed. The cooling time depends on the amount of insulating material around the flow line 50. Therefore, there is a window of opportunity during this cooling time to prevent the formation of hydrates before the actual formation of hydrates occurs. flow line 50. Referring now to Figure 2, an action that can be taken in an open circuit 170 during the cooling time is to flow chemicals through the inner tube 70 and into the flow line 50 so that mix with well fluids and avoid the formation of hydrates. The chemicals can flow out of the free end 135 upstream of the inner tube 70 so that the chemicals are mixed with the well fluids in the 50 flow line. The chemicals condition the flow of the well fluids so that the well fluids do not solidify, that is, they do not form hydrates. For example, methanol prevents the formation of hydrates. Therefore, after an unplanned shutdown, methanol can be pumped through the inner tube 70 and mixed with the well fluids to prevent the well fluids from forming hydrates and blocking the flow line 50.

Referring now to Figure 11, another alternative is to include a series of valves 194 spaced apart along the length of the inner tube 70 at predetermined locations. Using in particular the extendable tube 80 described with respect to Figure 4, the valves 194 can be controlled remotely whereby one or more of the valves 194 can be opened at predetermined locations to allow the chemicals passing through the inner tube 70 pass into annular space 90 and mix with well fluids. In addition, the valves 194 may be periodically opened along the length of the inner tube 70 to condition the well fluids. Also, the inner tube 70 can be filled with chemical products, so that if an unscheduled closure is present, all the valves 194 are opened automatically to allow the chemicals to pass into the annular space 90 and mix with well fluids to prevent the formation of hydrates. See patent application E.U.A. Serial No. 09 / 377,982 filed on August 20, 1999 and entitled "Electrical Surface Activated Downhole Circulating Sub". It should be appreciated that downhole technology can be used for these valves such as gas lift mandrels, spring loaded valves, and end side bags.

Alternatively, the inner tube 70 may be porous along the entire length of the inner tube 70. The porosity allows the inner tube 70 to introduce chemicals into the inner tube 50 along the entire length of the inner tube 70. without having to axially move the inner tube 70 with respect to the flow line 50, or have flow in the flow line 50. The chemicals can be filtered through the porous walls of the inner tube 70 when the inner tube 70 is pressurized with the chemical. For example, this may be useful in cases where an unplanned flow interruption occurs through the flow line 50 and the fluids are cooled to a point at which there is a risk that carbohydrate blockages occur. An inhibitor chemical such as glycol or methanol can be introduced through the porous inner tube 70 along the entire length in the flow line 50 in sufficient quantities to "dose" the fluids of the flow line and prevent formation of hydrates. The inner tube 70 can be made porous by deliberately introducing small holes (pinholes) formed mechanically along its length or by the material properties of the walls of the inner tube 70. For example, a tube of mixed material consisting of fibers and epoxy type resins are naturally porous to liquids. The degree of porosity is designed such that it conforms to the length of the inner tube 70 so that it is possible for the chemicals to completely reach the end of the inner tube 70. Preferably, the inner tube 70 is preinstalled in the line of flow 50. When there is an unplanned flow stop in the flow line 50, the fluids can be easily dosed with a chemical along the entire length of the flow line 50 using a small pump that supplies the chemicals to the interior porous tube 70. Once the pressure in the inner tube 70 is greater than the pressure outside it, the chemicals are filtered through the walls of the inner tube 70 as planned. Flow in the annular space 90 is not required. In fact, the flow in the annular space 90 may not even be possible due to the blockage. It is also not necessary to move the inner tube 70 axially relative to the flow line 50. Referring now to Figure 2, undesirable solids may form in the flow line 50. Initially, the hot fluids passing through the inner tube 70, heat the well fluids that tend to inhibit the lining of the walls 55 of the flow line with wax, incrustation, asphaltene, or other undesirable solids. However, assuming that solids have been formed in the wall 55 of the flow line 50, the inner tube 70 can be passed along the interior of the flow line 50 while chemicals are injected through the open end 135 of the inner tube 70 to remove any accumulation around the inside of the flow line and in this way remove the solids. Referring now to Figure 5, a variety of tools 130 can be attached to the end 135 of the inner tube 70 to effect flow assurance operations. Said tools can be any of the tools in the inventory of the extensible tube tooling. The tool 130 is a substitute for the leveler and is secured at the end 135 of the inner tube 70 and pushed or pulled through the flow line 50. For example, if it were necessary to clear the interior of the flow line 50, a tool can be attached to the end 135 of the inner tube 70 and the inner tube 70 is passed through the flow line 50 with the tool 130 cleaning the interior 55 of the flow line 70. Such tools can be used to assist in the removal of wax, incrustation, asfalteno, sand or other undesirable. See also the patent application E.ü.A. Serial No. 09 / 504,569 filed on February 15, 2000, and entitled "Recirculatable Ball-Brop Relay Device for Lateral Oilwell Drilling Applications", incorporated herein by reference, which can release the tool 130 down the extendable tube 80. A tool 130, such as a tube cleaner leveler, can be attached to the end 135 of the inner tube 70 and mechanically clean the walls 55 of the flow line 50 instead of cleaning them with chemicals. Leveling pipe cleaners can be used to clean harmful ones such as wax, scale or asphaltene. Another tool can be a cleaning tool with jets that provide forced fluid against the interior 55 of the flow line 50 to clean it. Other tools, such as drill holes, can be used in the inner tube 70 to clean the solids and to remove wax and other solid accumulations in the 50 flow line. Any of a complete variety of downhole tools can be used. The formation of hydrates requires low temperature and high pressure. If well fluids can be maintained at a high enough temperature, even at high pressure, hydrates do not form. Alternatively, even if well fluids have a low temperature, if the pressure is kept low enough hydrates are not formed. The correct temperature and pressure must be present for hydrates to form. In normal operation, the heat of the well fluids is maintained in the flow line such that the well fluids reach the production plant 40 at a temperature high enough that the hydrates do not form. If hydrates are formed in the flow line 50, the hydrates can block the flow through the flow line 50. Therefore, one solution is to maintain the temperature of the well fluids by flowing, for example, hot fluid to through the inner tube 70. Another solution is to condition the well fluids by pumping chemicals through the inner tube 70. Any of these operations can also be used to restart the flow in the flow line. The depressurization of the flow lines is the normal method for melting the hydrates for the flow lines used in shallow water. However, this strategy is more difficult to achieve in the deep water flow lines due to the pressure caused by the hydrostatic head in the return duct portion 204 of the flow line 50. Referring now to Figure 12, a hydrate formation 198 is shown to block flow through a flow line 200 in a deepwater facility. The flow line 200 includes a horizontal portion 202 and a return duct portion 204. One method for removing the hydrates is to "depressurize" the 200 flow line. Typically, the pressure has to be less than 14.06 kg / cm2 to avoid The formation of hydrate A problem with depressurization is that there is a hydrostatic head on the well fluids in the flow line 200 due to the return duct 204 that extends from the seabed 44 to the production plant. the depth of the seabed 44 to the production plant 40 is very high, a substantial load is placed in the well fluids in the horizontal portion 202 of the flow line 200. This load puts substantial pressure on the well fluids. The loading of the well fluids provides sufficient pressure to maintain the pressure of the well fluids within the pressure region for hydrate formation. hydrate formation pressure, it is necessary to depressurize the well fluids and therefore it is necessary to remove the pressure of the hydrostatic head. As shown in Figure 12, the inner tube 70 can be used as a tube for depressurization. Any liquid in the inner tube 70 is removed so that the inner tube 70 only has gas inside it. As an example, consider that an unplanned closure occurs and that the installation has an open circuit 170 and that oil has been flowed stabilized by the inner tube 70. Consider that this is the cooling time after the unexpected closure. Gas is pumped through the inner tube 70 because the gas can be pumped through the inner tube 70 over a distance of 9,267 km in 8 minutes. Therefore, the gas can pass through the inner tube 70 in a relatively short time interval. The gas that passes through a larger tube obviously takes a much longer time. The gas passing through the inner tube 70 can push the liquid out of the return duct portion 204 of the flow line 50. Once the liquids of the inner tube 70 have been displaced by the gas, the liquid can be depressurized. gas. This causes the liquids remaining in the flow line 50 to flow back into the inner tube 70. However, because some of the liquids have been displaced out of the return duct portion 204 of the flow line 50, the liquid interface in the return duct 204 will be smaller. This eliminates or reduces the pressure on the well fluids in the flow line 50 because there is now a lower load. This method will be successful if the volume of the fluids in the inner tube 70 is equal to or greater than the volume that needs to be displaced from the return duct 204 to reduce the load in the return duct 204 to a level low enough to melt the hydrates in the 50 flow line. The elimination of the load puts the well fluids out of the hydrate pressure region and allows the heat from the sea water to melt the hydrates over time. Eventually hydrates become gas and water. However, the return duct 204 may be connected to a flow line 200 that is 37.07 km long and the well fluids in the 37.07 km length of the flow line are now cold. These also have water and gas mixed with oil. Now that the hydrates have been removed, it is necessary to make the well fluids flow again through the 200 flow line. To start the flow, it is necessary to re-pressurize the well fluids. Unfortunately, when the well fluids are re-pressurized, hydrates are formed again. Therefore, even after the load is removed to depressurize the hydrates, the re-initiation of the fluids can simply re-generate the hydrates again. The present invention solves this problem because once the depressurization occurs and the hydrate formation is melted to a liquid, the inner tube 70, as an open circuit 170, can now be made to move inside or outside the line of flow 50 and chemical products can be passed through the inner tube 70 as it moves through the flow line 200. This leaves a trail of chemicals along the length of the 200 flow line as that the inner tube 200 moves through the flow line 200. The chemicals are mixed with the well fluids. The inner tube 70 meters the well fluids with methanol or glycol or some other chemical to prevent the formation of hydrates as the well fluids are re-pressurized to start the flow again through the flow line 200. This then allows the well fluids to be re-pressurized without the formation of hydrates so that the well fluids can begin to flow. This is a good example of a short-term use of the present invention. The inner tube 70 can then be placed in its "normal" operating position for flow and the flow can be restarted without the risk of re-forming hydrates. When the flow begins, hot liquid and chemicals can be injected through the inner tube 70. Hydrates may have formed in the flow line 200 before the insertion of the inner tube 70. In this case, the hydrates can be melted by depressurization and the fluids in the flow line 50 can then be conditioned with an appropriate hydrate inhibiting chemical that is pumped through the inner tube 70 as it moves into the flow line 50. In a new facility , a permanent inner tube 70 can be installed and this can be retracted from the flow line 200 to condition the well fluids with chemicals so that no hydrates are formed when the flow is restarted. This method and the method for eliminating hydrate formation by heating the well fluids are related in that in the latter method, the inner tube 70 is already in the flow line 200 and in this method, the inner tube 70 is inserted inside. of the return duct 204 and down into the flow line 202 to distribute the chemicals to prevent hydrate formation. Sometimes, solids such as sand are introduced into the flow lines. The ability to remove the sand is based on having a sufficient flow velocity and "hold-up" to transport and empty the sand out of the flow line. Currently there are a number of fluids in the prior art designed to transport solids. These fluids can be used in conjunction with the inner tube 70. To assist in the removal of solids, the inner tube 70 can be moved through the flow line 50 while the "fluid for transportation" is being pumped. Fluids for transportation must have a minimum viscosity to suspend and carry the sand. Referring now to Figure 13, with reversed circulation using the inner tube 70, the velocity through the inner tube 70 must be rapid, but the re-circulation through the annular space 90 with the largest cross-sectional area and volume substantially decelerates the speed of the fluid that re-circulates. To solve this problem, a second inner tube 210 is installed. The second inner tube 210 is inserted into the flow line 50 together with the first inner tube 70. The second inner tube 210 is inserted using the same means used to insert the tube. first interior tube 70. The high velocity flow passes through the first inner tube 70 to activate the sand and then returns through the second inner tube 210 instead of through the annular space 90 of the flow line 50. second inner tube 210 is smaller and has a higher speed than the annular space 90 of the flow line 50 and acts as a good carrier for the sand. Both inner tubes 70, 210 travel in the same direction within the flow line 50. However, the flow in the inner tubes 70, 210 is in opposite directions, one flows into the flow line 50 and the other flows from the flow line 50 to recover the sand. If only the annular space 90 of the flow line 50 is used, the return flow does not have sufficient velocity to draw the sand. With the second inner tube 210, no flow occurs through the annular space 90 of the flow line 50. The first inner tube 70 with the high velocity fluid lifts the sand and the second tube 210 sucks the sand. Referring again to Figure 5, the tool 130 can be an inspection tool for inspecting the flow line 50. If the tool 130 is mounted on the end 156 of the extensible material tube 80 shown in Figure 4 with conductors , including both electric and data transmission conductors, the data can be transmitted back to the processor 118 through the conductors. Preferably, the conductors are optical fibers. Furthermore, it is preferable that the flow is not stopped through the flow line 50. With the tool 130 connected to the expandable tube shown in Fig. 4, the signal conduction cables on the walls of the extendable tube 80 can be connected to the A set of instruments, well known in the art, which can then be used for real-time internal inspection of the flow line 50 by simply moving the inner tube 70 to the appropriate position along the flow line 50 to allow the inspection of any part of flow line 50. Such instrumentation may include video cameras, calipers, collar locators, gamma ray measuring devices, magnetic resonance devices, sonic devices, radioactive source devices, pressure meters, meters of temperature, flow meters, resistivity meters, densitometers, and the like. The tool 130 may be similar to a drill-hole type downhole assembly in which the instrumentation is used for inspection. The inspection tool 130 to inspect the flow line 50 or to act on the flow line 50 is attached to the end 135 of the inner tube 70. By being attached to the inner tube 70, the tool 130 can be moved forward and back inside the flow line 50 as it sends readings in real time to the processor 118. Therefore, if the tool 130 does not take the appropriate measurements, the operator has control over the tool 130 and can make the tool 130 130 return and again perform any inspection of a particular section of flow line 50. For example, a second inspection could include changing (turning up) the resolution of the instruments or some other way to vary the actual time of the inspection . The inner tube 70 may have to negotiate portions of the flow line 50 that are made from unbonded flexible (such as those manufactured by Weellstream). An unbonded flexible has a low compression capacity. If extendable tube is inserted through the unbonded flexible, the tension placed on the extendable tube appears as compression in the flexible. You can apply 45,360 kg (one hundred thousand pounds) in the extendable tube. Flexible can take only 4,536 kg (10,000 pounds) of compression. This is because the flexible ones are made from interlaced layers of complete metal layers. Likewise, the flexible ones not joined by themselves have a radius of curvature, as for example, the chain form that is formed when an unbonded flexible hangs between two points or when it is wrapped around an arch. As discussed previously, a 5D curvature will not allow an existing tractor to pull an inner tube or an existing injector to push an inner tube through said curvature. The use of a tractor may not be appropriate through such configuration due to potential damage to the unbound flexible as well as the ability of the tractor to maneuver through bends in the unbonded flexible. Therefore there are a number of unique problems that are encountered when a portion of the flow line includes unbound flexible, including the compression capacity of the flexible, the closed 5D curvature and the winch friction created. In such case the following method and apparatus of the present invention can be used. First, an inner tube is introduced into the unbound flexible flow line using an extendable tube injector or friction gasket assembly. This inner tube is preferably an extensible tube of mixed material. This extensible tube of mixed material has sufficient diameter to provide sufficient resistance to axial curvature to allow the extendable tube injector to cause the inner tube to travel a substantial distance along the unbound flexible flow line. This inner tube is the first tube inserted. This is only long enough to travel the relatively short distance of the unbound flexible flow line. At least far enough to pass difficult areas such as chain shapes in flexible unattached. At the end of an unbonded flexible, a very closed curvature may be present in the flow line such as arc or a curve at the top of a platform or a hybrid submarine return duct system. An inner tube with a large diameter having a high resistance to axial bending will probably have a minimum radius of curvature insufficient to negotiate said closed curvature (which may have a radius of 5 times the diameter of the flow line - which is the radius of typical curvature for the leveling application). This can determine the maximum distance that the first inner tube can travel. The first inner tube has a flange or similar assembly at one end to allow it to join and seal in the flow line at the end of the expandable pipe injector. Second, a second inner tube is then introduced into the first inner tube. This second inner tube is of smaller diameter and is designed to travel a greater distance in the flow line than that of the first inner tube. It also has a much smaller minimum radius of curvature so that it can negotiate a 5D curvature. In such a case, it is possible that an extendable tube injector can not provide the driving force to the second inner tube to move it through the remote closed curve due to the well known deformation phenomenon. Therefore, a driving force can be applied to the second inner tube by pumping a fluid through the first inner tube in the annular space between it and the second inner tube so that the hydrodynamic forces generated by the fluid provide the driving force. The annular space between the first and second inner tubes can be adjusted in accordance with the hydrodynamic properties of the pumped fluid and the desired degree of motive power. Return the flow through the annular space formed between the second inner tube and the unbound flexible flow line. Said method of application of motive force avoids the buckling phenomenon. Controlling the pumping pressure and the flow velocity of the pump can control the motive power. Both inner tubes can be removed using an extendable tube injector or a friction packing unit. Referring now to Figures 14, 15 and 17, there is an FPSO 220 floating on the surface of water 222 offshore over 1,000 meters. A tower return duct 224 extends from the seabed 226 to an upper end 228, which is approximately 40 meters below the surface of the water 222. There is at least one flow line 230 extending from the FPSO 220 to the upper end 228 of the tower return duct 224. A number of flow lines 232 are present which are connected to the lower end of the tower return duct 224. The tower return duct 224 may include a beam of return ducts, such as the return duct 238, which extends towards the upper end 228. The tower return duct 224 may also have a central structural member 234. The bundle includes a plurality of return ducts, such as the return duct 238, for production having diameters that They vary from 10.16 cm to 40.64 centimeters. The beam also includes other pipelines, including pipelines for injection of chemicals and umbilicals. Buoyancy blocks can be attached to tower return duct 224 including a buoyancy tank at upper end 228. Lower end 236 is anchored. The flow lines 232 are connected to the lower end of one of the tubes constituting the tower return duct 224. The flow lines 230 extending from the FPSO 220 to the upper end of the tower return duct 228 are flexible not united The unattached flexible 230 hangs in an underwater arc that hangs between the FPSO 220 and the upper end of the return pipe of tower 224. A type of non-attached flexible is that developed by Wellstream. A 5D stainless steel elbow 240 communicates the unbonded flexible 230 with the upper end 228 of the tower return duct 224 and communicates the upper end 228 with the return duct 238. A 5D elbow allows a leveler to be sent through the flexible 230 from the FPSO 220 to the bottom of the tower return duct 236 because all the elbows have a curvature of at least 5D. However, there is a concern that if a hydrate formation occurs in one of the flow lines 232, there is no flow assurance solution to eliminate the blockage. As previously described, an inner tube can not be inserted through the unbonded flexible 230 due to the compressibility of the flexible; an inner tube with a tractor can not negotiate closed 2D curvature 240 and winch friction prevents the inner tube from passing through these flow lines. With reference still to Figures 14, 15 and 17, there is shown an apparatus and methods of the present invention that overcomes these problems. A flexible gooseneck 250 is attached to the front end 244 of a casing pipe, such as the extendable tube of mixed material 242. The flexible gooseneck 250, which is best shown in Figures 15 and 17, includes a plurality of rollers 252 mounted on the inside of the gooseneck 250 in which the plurality of rollers are positioned within individual sections 254, 256 of the gooseneck with the sections 254, 256 being connected by a type of universal joint (not shown) allowing section 254 is flexed with respect to section 256. This allows the gooseneck 250 to negotiate the curvature 5D of arch 240. Segments 254, 256 are articulated to allow the gooseneck 250 of the articulated composite material tube. it can be inserted through the flexible 230 and so that it negotiates the curvature of the arc 240. The rollers 252 on the gooseneck 250 overlap. One pair will be slightly interleaved with respect to the other pair of rollers. Therefore, no matter where the inner tube 70 is positioned with respect to the rollers 252, it will engage at least one roller. The universal joint can allow one segment to be positioned at a slight angle with respect to the other segment. The extendable tube of composite material 242 with the flexible gooseneck 250 at its front end 244 is inserted into the flexible 230 from the FPSO 220 and passed through the flexible 230 towards the arch 240 using techniques Normal for extensible tubing with an injector head unit. By way of example, it is assumed that flexible 230 can have a diameter of 20.32 cm and coating tube 242 can have a diameter of 10.16 cm. The extendable tube of mixed material 242 is inserted and pushed from the boat 220 until the gooseneck 250 passes through the curvature in the bow 240. The extendable tube of mixed material 242 does not move around the closed curvature of the bow 240. Therefore, the liner tube 242 and the gooseneck 250 now coat the flexible 230 and the arc 240. Next, an inner tube 70, such as an extendable tube 80, is inserted into the extendable tube of mixed material. . The extensible tube of mixed material 242 resists the compression forces caused by the insertion of the inner tube 70. The inner tube also passes through the segmented gooseneck 250 passing between the rollers 252 which help the inner tube to negotiate the curvature of the arch. 240. These rollers 252 eliminate the winch friction during the insertion of the inner tube 70. The extensible tube of mixed material 242 prevents the inner tube 70 from buckling as it passes through the flexible 230. The inner diameter of the tube extensible of mixed material 242 has a tight fit with the outside diameter of the inner tube 70 passing therethrough. The tighter the adjustment, the greater the compression force that can be applied to the inner tube 70 because the tighter fit prevents the inner tube 70 from buckling. The mixed material flexible tube 242 also protects the flexible 230 against compression caused by the injection of the inner tube 70. Furthermore, the extensible tube of mixed material 242 also fulfills the function of introducing the gooseneck of the flexible 250 through of the curvature of the arc 240. The inner tube 70 then passes until it reaches the tower return duct 224 to a point 258 in which the tower return sector 224 is connected to the flow line 232. The inner tube 70 can pass within the flow line 232 if the tube is bent between the return duct tower 224 and if the flow lines 232 are sufficiently "favorable". The inner tube 70 can have, for example, a diameter of 2.54 cm. The diameter is determined by the size required to negotiate the curvature 66 around the arch 240. The inner tube 70 can be 3.81 cm in diameter, an extensible tube of mixed material of 3.81 cm in diameter has a flow opening of 1,905 cm. The internal diameter of the 10.16 cm mixed material expandable tube 242 is small enough to prevent the inner tube 70 with 3.81 cm diameter from buckling. To insert and install the inner tube 70 into the extensible material tube 242, the inner tube 70 has to be forced through the extensible material tube 242 using an injector head unit. To help insert the inner tube 70 into the extensible tube of mixed material 242, a fluid can be introduced into the annular space 262 between the extensible tube of mixed material 242 and the inner tube 70. The introduction of the inner tube 70 into a fluid which passes through the annular space 262 assists in the insertion of the inner tube 70 and also tends to prevent buckling. Also, the insertion will be much easier because there is fluid in the annular space 262 between the two tubes of mixed material 242, 70. The fluid then returns through the annular space 264 formed between the extensible tube of mixed material 242 and the Inner tube 70. In the later life of oil fields, it is often desired that the flow line system be able to work with lower flow rates and lower reservoir impulse pressures. This is known as "flow reduction". It is also desirable to avoid the "risk of under-recovery of reserves" in cases where the wells can not be produced optimally because the flow line can not handle a total production. Therefore, it is preferred to balance the flow line to optimally produce reserves in the field. The objective is to optimize the cross-sectional flow area of the flow line in accordance with the preferred amount of production of the well fluids. Therefore, it is desirable to change the cross-sectional area of the flow line through the useful life of an oil field to be suitable for production from the reservoir. It is necessary to fine-tune the cross-sectional area with respect to production. It may be preferred to have more than one flow line. This allows one of the flow lines to be closed when production occurs during the life of the field. In addition, the initial inner tube 70 having a first diameter can be replaced with a new inner tube having a larger second diameter to thereby reduce the flow area 92 of the annular space of the flow line 50. This area 92 of the smaller annular space is then adjusted more adequately to the reduced production from the field. Additional variations can be adjusted in the production parameters by making and fluids through the same inner tube 70. There is even more flexibility if there is more than one inner tube 70 within the flow line 50 which allows it to be closed to the flow, or possibly removable, one of the inner tubes 70. Another aspect of the production involves the separation of gas from the liquids of the production fluids. This step is typically effected on the production platform 40 after the fluids have traveled through the outer tube 50. However, a porous inner tube 70, such as the one discussed above as an alternative embodiment in Figure 11, can be used, to separate the gas from the liquids. For example, the inner tube 70 can be emptied or filled with a fluid at a lower pressure than that of the fluids in the annular space 90. As the fluids flow through the flow line 50, the gas at a higher pressure it can be filtered through the walls and into the interior of the porous inner tube 70. The material characteristics of the inner tube 70 can be designed according to the necessary application and the materials of the fluids in the line of flow 50. In addition, the fluids can also flow through the inner tube 70 while the gas is separated in the annular space 90 through the porous walls of the inner tube 70. Separating the gas from the other production fluids while it is in the flow line 50 saves the time and expense involved with the use of heavy equipment on platform 40. Although preferred embodiments of this invention have been described and shown, modifications can be made to those skilled in the art without departing from the scope or teachings of this invention. invention. The embodiments described in the present invention are for example only and are not limiting. Many variations and modifications of the system and apparatus are possible and are within the scope of the invention. Accordingly, the protective field is not limited to the embodiments described in the present invention, but is limited only by the following claims, the scope of which should include all equivalents of the subject of the claims.

Claims

NOVELTY OF THE INVENTION Having described the present invention considers as novelty and therefore property is claimed as contained in the following: CLAIMS 1. - An apparatus for securing the flow of fluids through an outer tube, the apparatus comprising: an inner tube extending through the outer tube and having a flow opening adapted for the flow of fluids within said inner tube. 2. The apparatus according to claim 1, characterized in that said inner tube is an articulated tube. 3. The apparatus according to claim 1, characterized in that said inner tube is a continuous tube. . - The apparatus according to claim 3, characterized in that the continuous tube is extendable tube. 5. The apparatus according to claim 4, characterized in that the extendable tube is metal extendable tube. 6. - The apparatus according to claim 4, characterized in that said extendable tube is or extensible of mixed material. 7. The apparatus according to claim 6, characterized in that said extensible tube of mixed material includes conductors passing through the wall of said extensible tube of mixed material. 8. The apparatus according to claim 1, characterized in that during the installation and relative axial movement with the outer tube, said inner tube remains floating almost neutrally or is floating substantially neutrally within the fluid in the outer tube. . - The apparatus according to claim 1, which also includes fluids flowing through said inner tube that affect the fluids flowing through the outer tube. 10. - The apparatus according to claim 8, characterized in that said inner tube taken together with the fluids therein has substantially the same density as the fluids flowing in the outer tube. 11. - The apparatus according to claim 8, characterized in that said inner tube has the same density of the fluids inside the inner tube as well as the fluids outside the inner tube. 12. - The apparatus according to claim 8, characterized in that the fluids in the inner tube are immiscible, the fluids outside the inner tube are immiscible, and the inner tube floats in a substantially or substantially neutral manner within minus one of the non-miscible fluids outside the inner tube. 13. The apparatus according to claim 1, characterized in that the inner tube extends less than the entire length of the outer tube. 14. - The apparatus according to claim 1, characterized in that the inner tube extends along the entire length of the outer tube. 15. - The apparatus according to claim 1, characterized in that the inner tube includes an anchor that holds the inner tube inside the outer tube. 16. - The apparatus according to claim 15, characterized in that the anchor frictionally engages the outer tube. 17. - The apparatus according to claim 1, which also includes a connection in the outer tube to install the inner tube inside the outer tube. 18. - The apparatus according to claim 17, characterized in that the connection can be located at any point along the outer tube. 19. The apparatus according to claim 1, which also includes a propulsion system connected to the inner tube that drives the inner tube inside the outer tube. 20. The apparatus according to claim 19, characterized in that the propulsion system is an electrically or hydraulically powered tractor. 21. - The apparatus according to claim 20, characterized in that the tractor includes a housing in segments. 22. The apparatus according to claim 17, characterized in that the tractor is hydraulically driven by a power fluid that is flowed through the inner tube. 23. The apparatus according to claim 22, characterized in that the power fluid is a foam. 24. The apparatus according to claim 1, characterized in that one end of the inner tube is open inside the outer tube and allows the fluids to flow through the inner tube and mix and interact with the fluids in the outer tube. 25. - The apparatus according to claim 1, characterized in that the inner tube extends externally with respect to the outer tube and allows the fluids flowing through the inner tube to flow through and out of the outer tube. 26. - The apparatus according to claim 1, characterized in that the inner tube extends externally with respect to the outer tube and is connected to a return pipe. 27. - The apparatus according to claim 1, which also includes a return tube placed inside the outer tube together with the inner tube, the return tube and the inner tube have ends that communicate to allow circulation through the inner tube and return tube. 28. - A method for maintaining the temperature of fluids flowing through an outer tube, comprising: extending an inner tube into an outer tube; flowing hot fluids through the inner tube; and heating the fluids flowing through the outer tube. 29. The method according to claim 28, characterized in that the hot fluids flow through an open end of the inner tube and are mixed with the fluids in the outer tube. 30. - The method according to claim 28, characterized in that the hot fluids pass through an inner tube with an open end of the inner tube that extends externally with respect to the outer tube so that they pass towards the exterior of the outer tube. 31. - The method according to claim 28, characterized in that the inner tube extends towards an exterior of the outer tube and is connected to a return pipe to provide fluid circulation through the inner tube and the return pipe. 32. - A method for removing stagnant fluids in an outer tube with fluids flowing from one side to another thereof, comprising: extending an inner tube through the outer tube; flowing fluids through the inner tube; and varying the density of the fluids flowing through the inner tube causing the inner tube to move with respect to the outer tube. 33. - A method for treating fluids flowing through an outer tube, comprising: extending an inner tube into the outer tube; and flowing chemicals through the inner tube and out of an open end of the inner tube to be mixed with the fluids flowing through the outer tube. 34. - A method for treating fluids flowing through an outer tube, comprising: extending an inner tube through the outer tube; to flow chemical products through the inner tube; and selectively opening valves in the wall of the inner tube to mix the chemicals with the fluids at predetermined locations along the outer tube. 35. A method for treating fluids flowing through an outer tube, comprising: extending an inner tube through the outer tube; to flow chemical products through the inner tube; and allowing the chemicals to filter through pores in the inner tube wall along the length of the inner tube so that the chemicals are mixed with the fluids outside the inner tube. 36. A method for removing accumulated solids in a tube that has fluids flowing from one side to another thereof, comprising: passing an inner tube through the outer tube; discharging chemicals through an open end of the inner tube; and mix the chemicals with the fluids in the outer tube to remove the solids. 37. A method for depressurizing a submarine flow line connected to a return duct extending to the surface of the water, comprising: extending an inner tube through the return duct; passing gas through the inner tube and out of an open end of the inner tube into the return duct; and force the fluids in an annular space between the inner tube and the return duct towards the surface of the water. 38. A method for removing sand from an outer tube, comprising: passing a first and a second outer tube through the outer tube; flowing fluids in a high speed direction through the first inner tube and inside the outer tube; and pumping fluids in an opposite direction through the second inner tube to draw the sand into the second inner tube. 39.- A method for separating gas from liquids in an outer tube comprising: extending an inner tube through the outer tube, the inner tube includes pores extending through the wall of the inner tube; and allowing the gas in the outer tube to pass through the pores of the inner tube and into the inner tube. 40.- A method for separating gas from liquids in an inner tube comprising: extending the inner tube through an outer tube, the inner tube including pores extending through the inner tube wall; and allowing the gas in the inner tube to pass through the pores of the inner tube and into the inner tube. SUMMARY OF THE INVENTION A flow assurance system includes an inner tube (70) positioned within an outer tube (50) to ensure flow through the outer tube (50). During installation and relative axial movement with the outer tube (50), the inner tube (70) floats almost neutrally or floats completely neutrally in the fluids of the outer tube (50) and can be partially or completely extended through of the outer tube (50). The inner tube (70) may be anchored at one end inside the outer tube (50). The inner tube (70) is preferably an extendable tube of mixed material which is installed using a propulsion system. The system may allow fluids to flow through the inner tube (70) and to mix with the fluids in the outer tube (50) or may allow the fluids to flow through the inner tube (70) to the outside of the tube outside (50). The hot fluids can pass through the inner tube (70) to maintain the temperature of the fluids flowing through the outer tube (50) and the chemicals can flow through the inner tube (70) to condition the fluids in the outer tube (50). Tools can be attached to the end of the inner tube (70) to effect the flow assurance operations inside the outer tube (50).