巴西专利BR112016019679B1 method and jacket for laying a column of pipe

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专利摘要:
METHOD AND SYSTEM FOR LAYING A PIPE COLUMN, AND, SHIRT. A jacket that has an outer surface covered with a fluid-absorbing coating is shielded to a pipe column (70) by inserting the folded shirt (34) into the pipe column and then, when unfolding the shirt against the pipe column . The liner may be a single-sheet, corrosion-resistant liner, kilometers long, covered with a sticky glue and a hygroscopic and / or different fluid-absorbing coating to absorb fluid cavities trapped between the tubing and the liner and inhibit corrosion and the leakage of the elongated pipe column.
公开号:BR112016019679B1
申请号:R112016019679-1
申请日:2015-02-27
公开日:2021-02-17
发明作者:Petrus Cornelis Kriesels；Boo Young Yang；Heather L. Gower
申请人:Shell Internationale Research Maatschappij B.V.；
IPC主号:

专利说明:

[0001] [001] The invention relates to the method and system for internally laying a pipe column to protect the pipe column against corrosion and / or leakage.
[0002] [002] Well boreholes for the exploration and production of oil, gas or other minerals from underground reservoir layers are typically provided with protective piping, internal lining and / or other jacket columns. These may include a pipe column recessed into an open pit section of the well bore and cemented in place. In this document, the term inner liner is typically used to indicate a pipe column that extends from the surface to the well hole, while the jacket can typically be used to indicate a pipe column that extends from a location inside a well below the well bore. Hereinafter, the term inner lining will be used primarily, but the invention is equally applicable to the shirt.
[0003] [003] The internal or jacket liner columns can be designed to withstand a variety of forces, such as collapse, explosion and traction failure, as well as chemically aggressive brines. The internal lining column is typically assembled from multiple interconnected pipe sections, which are, for example, about 10 meters long each. Inner lining connections connect adjacent pipe sections. Inner lining sections can be manufactured with male threads at each end, where shorter length inner lining couplings with female threads are used to join the individual inner lining sections together. Alternatively, pipe sections can be manufactured with male threads at one end and female threads at the other.
[0004] [004] The internal lining can be executed to protect fresh water formations, isolate a zone of lost returns or isolate layers of formation with significantly different pressure gradients. The operation during which the inner liner is placed in the well bore is commonly called “pipe laying”.
[0005] [005] Within the innermost inner liner, a well hole can typically be provided with another pipe column, typically called a production column or production pipe. In this document, the production pipeline can be assembled with other completion components to make up the production column. The production column is the primary conduit through which reservoir fluids are produced to the surface. The production column is typically assembled with completion components and piping in a configuration that fits well well conditions and the production method. The piping itself can be produced from interconnected pipe sections, in a similar way to the internal lining columns. An important function of the production column is to protect the primary wellbore tubulars, which include the liner and liner, from corrosion or erosion by the reservoir fluid.
[0006] [006] The inner surfaces of the production piping and their associated connections are often subjected to one or more of relatively high temperatures, high pressures and highly corrosive fluids. Temperatures can reach up to 175 ° C or more. Pressures can be as high as 140 MPa (1400 bars) or more. Reservoir fluids can be highly corrosive, for example, due to the combination of hydrocarbons, CO2 and / or H2S in the presence of water. The use of improved secondary and tertiary recovery methods in hydrocarbon production, such as gas injection, water flooding and chemical flooding, can further aggravate the situation.
[0007] [007] The pipe sections for well-bore tubulars, which include the inner or production tubular tubing, are usually manufactured from untreated carbon steel with varying compositions that are heat treated for varying strengths. Alternatively, the pipe sections can be specially made of stainless steel, nickel alloys, aluminum, titanium, fiberglass and other materials.
[0008] [008] The materials have different resistance to corrosion. Carbon steel, for example, has a relatively low cost, but is also more prone to corrosion than the other materials listed above.
[0009] [009] Several types of corrosion mechanisms exist, which include: erosion-corrosion (also known as impact), stress corrosion cracking, sulfide stress cracking, corrosion pitting and galvanic corrosion.
[0010] [0010] Corrosion in metals can be caused by the flow of electricity from one metal to another metal or from a part of the surface of a metal part to another part of the same metal where conditions allow the flow of electricity. In addition, a wet conductor or electrolyte must be present for this flow of energy to occur. The energy passes from a negative region to a positive region through the electrolytic medium.
[0011] [0011] The coupling or electrical contact of dissimilar metals often causes increased corrosion. This form of corrosion is generally called galvanic corrosion. Galvanic corrosion is quite prevalent and problematic, occurring in a wide variety of circumstances. For example, coupling the aluminum pipe and iron together will result in very rapid corrosion of the aluminum pipe section. The galvanic corrosion mechanism can be illustrated by considering the effect of electrically connecting zinc to platinum immersed in seawater. Under these conditions, platinum is inert and does not corrode, while zinc is attacked. The reactions that occur on the surface of zinc are the anodic oxidation of zinc to zinc ions, and the cathodic reduction of dissolved oxygen to hydroxide ions. If the electrical potentials of these two metals are measured, platinum would be found to have a positive potential, while zinc would be found to have a negative potential. As can be seen, as the potential difference increases, galvanic corrosion increases.
[0012] [0012] Obviously, from a corrosion point of view, the replacement of steel tubulars and hardware associated with materials less subject to corrosion would be highly desirable in oil and gas applications, if it were practical or economically viable. Non-metallic components such as fiberglass lining, piping, pump rods and the like are finding their way into oil field applications. However, performance limitations, which include service loads, pressures and temperatures, restrict the complete replacement of metallic hardware. On the other hand, pipe sections produced from solid corrosion resistant alloy (CRA), such as stainless steel and nickel alloy, can provide sufficient corrosion resistance. But tubular sections made from solid corrosion-resistant alloys are typically much more expensive than carbon steel. The latter can make projects unprofitable. In addition, newly developed hydrocarbon reservoirs are producing increasingly corrosive hydrocarbons, for example, which include a higher percentage of H2S, which requires higher grade Corrosion Resistant Alloys (CRAs). And higher-grade CRAs are increasingly costly. For example, compared to API P110 grade carbon steel, the same pipe section produced from CRA can be up to 5, 10 or even 25 times more expensive (when produced from 316L, SM25CRW-110/125 or CRA C22 respectively).
[0013] [0013] Several manufacturing methods have been developed to produce corrosion resistant jacketed or armored carbon steel tubular, for example, to transport oil and gas, to achieve economic advantages over solid corrosion resistant tubular alloy (CRA) such as steel stainless steel and nickel alloy. However, the use of these jacketed or armored tubulars has not gained acceptance for wellhead tubulars mainly due to the lack of a thread connection that has demonstrated adequate corrosion resistance performance.
[0014] [0014] For protection against galvanic corrosion, insulating coatings can be applied. In order for a coating to be used on tubular sections and threaded couplings to protect the metal substrate against corrosion, the coating must be resistant to attack and maintain its adhesion to the metal substrate under the harsh pit interior conditions mentioned above.
[0015] [0015] In various oil and gas applications, the steel pipe is provided with a corrosion resistant material jacket. For example, it is known to bond various epoxy-based coatings to the inside of the barrel, as well as coatings that contain polyethylene, polyvinyl chloride and other thermoplastic or thermoset materials.
[0016] [0016] Of the various polymeric coating materials, arylene sulfide polymers have gained wide acceptance, see, for example, document No. 3,354,129. In general, these polymers consist of a recurrent aromatic structure coupled in repeating units through a sulfur atom. Commercially available arylene sulfide polymers that have been used to cover oil and gas pipes and pipe couplings are polyphenylene sulfides. Polyphenylene sulfides used in oil and gas applications exhibit high melting points, excellent chemical resistance, thermal stability and are non-flammable. They are also distinguished by high hardness and good retention of mechanical properties at elevated temperatures as well as the ability to deform smoothly, thereby preventing the wear of threads, even in large thicknesses, for example.
[0017] [0017] Document No. US 3,744,530 describes pipes covered with polyphenylene sulfide, in which the polyphenylene sulfide coating also contains a filler, such as iron oxide, in an amount of between 5% to 30%.
[0018] [0018] Although pipes and couplings covered with polymer have gained wide acceptance in applications requiring corrosion protection, cracking of such coatings during installation and in use tends to limit their insulating effect, which increases the likelihood that galvanic corrosion occur. This is particularly relevant for the female part or pin end of the connections, where cracking can occur during assembly of the connection. In addition, the polymeric coatings of threaded couplings are particularly prone to cracking due to the stresses conferred during the assembly of connections. In addition to cracking, many polymers allow the diffusion of hydrogen and other light hydrocarbons through the thickness of the coating or liner, thereby allowing gas to accumulate between the layers, which, in the case of a corrosion resistant liner, could result in collapse if the pressures in the bore and the annular space become unbalanced.
[0019] [0019] Document No. JP 60 109686 A (KAWASAKI HEAVY IND LTD), deposited on June 15, 1985 (06/15/85), provides a pipe system for transporting corrosive fluids. The pipe system comprises a tubular member made of a metal prone to corrosion. Each tubular member is provided with an internal casing made of a corrosion resistant material. At each end, the tubular member and the inner casing are connected to a threaded coupling member, which is made of a corrosion resistant material. The tubular member and the jacket are connected to the threaded coupling member by a weld seam. But welding solid CRA couplings to a carbon steel pipe body, or the welding-related method, can cause problems in itself. See, for example, the description of galvanic corrosion above. In addition, the savings from using armored steel instead of solid CRA is particularly valid when the total pipe wall thickness increases. However, when the product with an outside diameter (OD) times the wall thickness (T) decreases, the cost benefit of corrosion resistant alloy armored pipe versus solid CRA pipe decreases rapidly. For example, for the pipe armored with Incoloy 825, the cost benefit is reduced to zero for tubulars that have smaller OD x T. However, the latter is typically used for production piping.
[0020] [0020] Although the use of corrosion resistant alloys for corrosion control has demonstrated superior corrosion resistance properties, they are quite costly and exhibit complex manufacturing and handling restrictions. The price of high-performance steel, such as 18-8 stainless steel, can be about 5 times more expensive than carbon steel. Nickel alloys, for example, which can also include high percentages of chromium (for example, more than 10%) and / or molybdenum, can exceed the price of carbon steel by a factor of about 20 to 30. The Nickel alloys, however, are often the material of choice in environments that contain relatively large volumes of H2S. For example, when the partial pressure of H2S exceeds 0.5 to 1 MPa (5 to 10 bars), nickel alloys may be required.
[0021] [0021] In oil field applications, polymeric coatings will be unsuitable when the partial pressures of CO2, H2S and / or water exceed a certain threshold, as these materials can permeate through the polymeric coating, which can lead to corrosion of the carbon steel base material. In addition, the temperature range over which polymeric coatings can be applied is typically limited to a maximum of about 100 to 150 degrees Celsius.
[0022] [0022] Document No. US 2007/0095532 describes an apparatus for implanting a patch comprising an internal metal tube and an external resilient sealing member. Suitably, the inner metal tube is formed from steel, preferably carbon steel. The external resilient sealing member is formed from an elastomeric material. Suitably, the patch can be from 3.048 to 304.8 m (10 to 1,000 feet) in length.
[0023] [0023] As a disadvantage, in the description of document No. US 2007/0095532, the length of the shirt patch is inherently limited by the described apparatus. The shirt patch is stapled by extending and retracting wedges attached to the apparatus, so that the weight of the shirt patch is carried by the friction that these wedges exert on the shirt. The force applied by these wedges determines the frictional force. The extension and retention wedges will have insufficient capacity to support the shirt that exceeds a certain length, such as several kilometers. In addition, in the case of a very thin jacket, the pressure that the wedges can exert before deforming the jacket is minimal, which also minimizes the frictional force. Although a thin shirt is lighter than a thicker patch, the weight of the shirt is still typically around 1.3 kg / m. This would provide a total weight of several thousand kilograms if it were to be considered to route the production pipe along the length of the well bore.
[0024] [0024] Since hydrocarbon well holes extend at increasingly deep targeted depths, for example, in the range of five to ten kilometers or more, the apparatus in document No. US 2007/0095532 would be inadequate to provide a shirt patch for the entire internal surface of the production pipe.
[0025] [0025] In addition, the apparatus of document No. US 2007/0095532 is supported by a profiling cable which, in the configuration as described, would have to run through the jacket. For longer lengths, the practical issues of threading several kilometers of profiling cable through the jacket patch, while still supporting the weight of the jacket by the profiling cable while running in the well, are unrealistic. This is supported by the exemplary shirt patch length as described in US No. 2007/0095532, which is limited to 1,000 feet (about 300 meters).
[0026] [0026] The well bore pipe jacketing method of document No. US 2010/0247794-A1 in which a polymer layer is cured down the well by actinic radiation. The liner is introduced into the unfinished well through a device attached to a profiling cable, which would thus expand the liner through a vessel or bladder in a profiling cable. The bladder will inflate along the entire length of the shirt to expand the shirt. The system is limited to the delivery of a polymer jacket. In addition, the system can only be applied for limited lengths. The manufacture of a bladder or vessel to expand the shirt will inherently limit the length of the shirt to be expanded. Providing a bladder that extends along the entire length of the production pipe will be impossible. In addition, the need to run such a vessel in the orifice will further limit its maximum length.
[0027] [0027] Document No. US 3785193 describes a sleeve expansion apparatus and a method that includes lowering and affixing a sleeve by means of a profiling cable. The shirt is crimped on an expansion tool, and hangs from it. This configuration has limitations similar to patent documents US 2007/0095532 and US 2010/0247794-A1 described above, in which the stapling of the shirt is based on friction. Friction is insufficient for longer shirt lengths, particularly for thinner shirts, given the limited frictional force that can be generated. In addition, given that the device is suspended from a profiling cable, execution on the jacket will prove impossible above a certain threshold length of the jacket, due to problems on the surface. As a result, the system of document No. US3785193 is unsuitable for production line piping along its entire length, which can be in the order of several kilometers.
[0028] [0028] Other methods and system for expanding a jacket within a surrounding tubular column are described in international patent application in WO 98/21444 and patent application No. US 2006/052936, No. US 2007/095532 and ⍛ US 2010 / 247794.
[0029] [0029] A general problem with known piping jacketing systems and methods is that fluid cavities can be trapped between the liner and the tubing, which can result in the liner separating from the inner wall of the tubing and collapsing the liner.
[0030] [0030] There is a need for an improved system method to protect tubulars against corrosion and leakage with the use of a pipe jacket assembly that automatically removes fluid from the residual space between the jacket and the pipe, thereby inhibiting the formation of fluid cavities and / or longitudinal leakage paths between the liner and the pipe and reducing the risk of separating the liner from the inner surface of the pipe and the associated risk of subsequent collapse of the liner. SUMMARY OF THE INVENTION
[0031] - inserir um camisa dobrado que tem uma superfície externa que é pelo menos parcialmente coberta com um revestimento de absorção de fluido na coluna de tubulação; - desdobrar o camisa para expandir o camisa contra uma superfície interna da coluna de tubulação; e - induzir a revestimento a absorver o fluido preso entre uma superfície interna da coluna de tubulação e uma superfície externa do camisa expandido. [0031] The present invention, therefore, provides a method for laying a pipe column, which comprises; - inserting a folded jacket that has an outer surface that is at least partially covered with a fluid-absorbing coating on the pipe column; - unfold the jacket to expand the jacket against an internal surface of the pipe column; and - induce the coating to absorb the fluid trapped between an internal surface of the pipe column and an external surface of the expanded jacket.
[0032] [0032] The coating may comprise binding and liquid-absorbing additives, such as a sticky glue and a hygroscopic material, such as silica gel and / or a crosslinked acrylate polymer described in U.S. Patent Document No. 7,144,980 , which is generally known as a Superabsorbent Polymer (SAP) or hydrogel, which absorbs any substantial cavities of water and / or other trapped fluid and thereby increases the connection between the pipe column and the expanded jacket.
[0033] [0033] In accordance with another aspect of the invention, a system is provided for routing a pipe column into a well hole comprising a jacket, which is configured to be folded into a collapsed state in the pipe column and to be unfolded against a inner surface of the pipe column and that is at least partially covered with a fluid absorbing coating that is configured to absorb the fluid trapped between the inner surface of the pipe column and the expanded jacket.
[0034] [0034] The method and system according to the invention allows continuous shielding of an internal lining column and / or oil and / or gas well pipe kilometers long by a single sheet corrosion resistant jacket that it can be covered with hygroscopic and sticky glue to increase the bonding of the liner and inhibit corrosion and leakage from the pipe column and / or internal lining.
[0035] [0035] These and other resources, modality and advantages of the method and system according to the invention are described in the attached claims, summary and in the following detailed description of non-limiting modalities depicted in the attached drawings, in which reference reference numerals are used, which refer to the corresponding reference numerals that are depicted in the drawings.
[0036] [0036] Similar reference numerals in different Figures denote the same or similar objects. The objectives and other resources depicted in the Figures and / or described in this specification, summary and / or claims can be combined in different ways by a person skilled in the art. BRIEF DESCRIPTION OF THE DRAWINGS
[0037] [0037] The invention will now be described in more detail and by means of examples with reference to the accompanying drawings, in which: figure 1 shows a perspective view of separate layers of a shirt according to the invention; figure 2 shows a perspective view of separate layers of a shirt according to the invention; figure 3 shows a perspective view of an embodiment of a shirt of the invention; figure 4 shows a perspective view of an embodiment of a shirt according to the present invention; figure 5 shows a perspective view of another embodiment of a shirt according to the present invention; figure 6 shows a perspective view of a practical embodiment of the shirt of the invention; figure 7 shows a perspective view of a winding drum comprising the jacket according to the invention; figure 8 shows a perspective view of a cross section of a tubular which, in a first step, is provided with a jacket according to the invention; figure 9 shows a perspective view of a cross section of a tubular which, in a second step, is provided with a jacket according to the invention; figure 10 shows a perspective view of a cross section of a tubular which, in a third step, is provided with a jacket according to the invention; figure 11 shows a schematic cross-section of a well hole provided with a jacket according to the invention; figures 12 to 19 show exemplary steps of various modalities for making the composite material of the invention; figures 20 and 21 show the respective modalities of methods for making the composite jacket of the invention; figures 22 to 24 show perspective views of the respective methods for making a pipe using the composite jacket; figures 25 to 27 show cross-sectional views of the respective methods for making a pipe using the composite jacket; figure 28 shows a cross-section of an embodiment of a jacket of the invention arranged in the well bore pipe; figure 29 shows an exemplary graph of a signal to monitor the integrity of the jacket; figures 30 to 32 show consecutive steps in one embodiment of a process for making a shirt of the invention; Figure 33 shows a cross section of an embodiment of a system of the invention for introducing a jacket into a well hole; figure 34 shows a perspective view of an expander embodiment for the system of the invention; figure 35 shows a cross-section of a well hole provided with the system of the invention, as well as a step of introducing the jacket into the well hole; figures 36 to 39 show consecutive steps of an exemplary method for jacking a well-hole tubular; and Figure 40 shows a perspective view of an embodiment of a method for jacketing a well bore pipe according to the invention. DETAILED DESCRIPTION OF THE MODALITIES PICTURED
[0038] [0038] Figure 1 shows an embodiment of a composite material 10 suitable for making a thin sheet shirt in accordance with the present invention. The composite material comprises a first polymer layer 12, a second polymer layer 14 and an intermediate metal layer 16. Optionally, as shown in Figure 2, a first adhesive layer 18 can be disposed between the first polymer layer and the metal layer . A second adhesive layer 20 can be disposed between the metallic layer and the second polymer layer.
[0039] [0039] In the present document, the first and / or the second polymer layer can be a layer consisting of a single polymer, or it can be a composite layer. Each layer of polymer may, in fact, include steel, carbon or fiberglass wire and / or particles of a relatively hard material embedded in the polymer. Hard, in this document, implies to be harder or stronger than the polymer base material. The hard particulate material can serve to protect against abrasion in the inner diameter of the composite jacket of the invention.
[0040] [0040] The respective layers of composite material are connected to each adjacent layer, which forms a layer of assembled composite material 10 as shown in Figure 3. The assembled composite material can have any desired shape, such as a longitudinal strip.
[0041] [0041] Figures 4 and 5 show different examples of a method for forming the composite material in a tubular format. Figure 4 shows the first polymer layer 12 formed in a tubular shape. The metal layer 16 is provided in the form of a longitudinal strip 22 and flexes around the first layer of tubular polymer 12. After flexing, the sides 24 of the metal layer 16, which extend in an axial direction, are connected each, for example, by welding. In another embodiment, shown in Figure 5, the metallic layer 16 is provided in the form of a longitudinal strip 22. Said strip 22 is helically wound around the first layer of tubular polymer 12. The sides 24 of the strip 22 can be connected between itself, for example, by welding. Alternatively, the metallic layer can be glued to the polymer layer. The second layer of polymer 14 is applied in a similar manner, which provides a longitudinal tube 30 made of composite material 10, see Figure 6.
[0042] [0042] In an embodiment shown in Figure 6, the tool 32 can be used to model the longitudinal tube 30 of composite material in a collapsed tubular 34, which has a reduced external diameter. In the present document, the tool 32 may have created one, two or more longitudinal folds 36 that extend in the axial direction. Said collapsed composite tube may be of any suitable length and may be arranged in a winding drum 40, see Figure 7. Alternatively, the composite material, or components thereof, may be manufactured as a collapsed tubular, rather than in rounded shape and subsequently folded.
[0043] [0043] The collapsed tube 34 can be used to coat a pipe 50. In a first stage (Figure 8), the collapsed pipe 34 is arranged inside the pipe 50. In a second stage (Figure 9), the collapsed pipe 34 is expanded to a tubular shape 30 (Figure 10).
[0044] [0044] In a typical oil field application (Figure 11), a well hole 60 that extends to a formation 62 below ground level 64 can be provided. The well hole is typically provided with one or more liners or tubular inner linings, such as a conductive pipe 66, intermediate inner liner 68, and production tubing 70. In this document, production tubing is typically included in an inner production liner, which is not shown, however, to enhance the clarity. The hydrocarbons produced will be transported to the surface through the interior of the production pipeline 70. Consequently, the internal surface of the production pipeline 70 can be exposed to varying amounts of CO2 and H2S in the presence of water, all of which can be transported to the surface. along with hydrocarbons.
[0045] [0045] In one embodiment, the collapsed tube 34 is unwound and inserted through the production pipe. Preferably, tube 34 in this document extends fully to the interior end of well 72 of the production pipeline above a Side Sliding Door (SSD) and / or a Side Cavity Chuck (SPM) to be able to cover at least a substantial part of the entire length of it.
[0046] [0046] Collapsed tube 34 can, for example, be inserted into the well hole by connecting a weight to the inner end of the well and lowering said weight in the well hole until it reaches the bottom. Alternatively, the collapsed tube can be inserted into the borehole by applying pressure, or by running it as part of, or in fact, around the Spiral Tubing column or other type of execution column. The execution column can be arranged inside the collapsed composite tube 34 or even outside it.
[0047] [0047] Subsequently, the collapsed tube 34 is expanded to its expanded state. In the present document, the expanded tube 30 preferably has an outer diameter that corresponds to, or is slightly larger than the inner diameter of the tubing 70, so that the outer surface of the expanded tube engages the inner surface of the tubing 70.
[0048] [0048] A problem with conventional shielding concepts is the continuity of the shielding layer, especially in the locations of the connections between respective tubular sections. The composite jacket of the invention can be made in a factory and consequently the continuity can be completely inspected on the surface before installation in the well bore. To maintain the integrity of the composite liner during insertion into the well bore, the outer diameter of the composite liner can be provided with protective means to protect against damage during the execution, installation or connection to the inner surface of the well bore pipe. . Said means of protection can include wires comprising a material relatively resistant to damage disposed in the outer diameter of the composite jacket. The damage-resistant material may include one or more of steel, carbon or fiberglass wires.
[0049] [0049] The collapsed tube 34 can be expanded in several ways. In a first embodiment, the tube 34 can, for example, be inflated with a pressurized fluid inside it. In that case, the inner end of the well 34 of the tube is closed before inserting it into the well hole. After insertion, the surface end is cut, and then the pressurized fluid is introduced to inflate and expand the jacket. In a second embodiment, an expander cone 74, which has a larger outer diameter that is substantially similar to the inner diameter of tubing 70, can be pushed or pulled through collapsed tube 34 to expand it. The expander can be moved from the surface towards the interior end of well 72 by pumping a pressurized fluid to push the expander. Subsequently, although the tube is held in position by the weight mentioned above, an expander cone 74 can be pulled to the surface to expand tube 34. In the present document, a column, such as a spiral pipe column or a profiling cable, it may have been integrated into the composite tube 30 during its manufacture (not shown). The expander 74 can be attached to one end of said profiling column or cable before and insert the composite jacket into the well hole. Subsequently, the expander can, for example, in a collapsed form, be lowered into the well hole together with the jacket. When the composite jacket is in the correct position, the expander cone can be transferred to its expanded form and pulled to the surface with the use of said profiling column or cable. Alternatively, the expander can be propelled to the surface with the use of hydraulic pressure generated by reverse circulation of the well.
[0050] [0050] The expanded composite jacket 30 can adhere to the inner surface of the tubing 70 by various means. For example, the outer surface of the composite jacket may have been provided with an adhesive layer. Said adhesive layer can be applied to the outer surface of the collapsed tubing 34 during insertion into the well bore with the use of an adhesive applicator device 76, which can include a spray device or a roller for applying the adhesive. Said adhesive can include a heat activated adhesive, which can be activated by introducing heated fluid into the well bore or even by the elevated temperature in the well bore, which, as mentioned above, is often above 175 ° C. Alternatively, an activator that will activate the adhesive can be injected into the drilling fluid.
[0051] [0051] As shown in Figure 12, in a first step of an exemplary embodiment for manufacturing the composite material of the invention, the strips of the first polymer layer 12, the metallic layer 16 and the second polymer layer 14 are arranged one on top on the other. Optionally, the adhesive layers 18, 20 are interposed as shown in Figure 2. The assembly of the stacked strips is folded into a tubular shape along the length of the strips, as shown in Figure 4, until the opposite longitudinal sides 24, 25 of the metallic layer 16 and the opposing longitudinal sides 80, 81 of the first polymer layer engage with each other and are aligned. In the present document, the opposing longitudinal sides 84, 85 of the second polymer layer leave a longitudinal opening 86 between them, which exposes the contiguous sides 24, 25 of the metallic layer. Opening 86 may, for example, expose about 10 mm of the metal strip on each side of said contiguous sides 24, 25.
[0052] [0052] In a next step, the sides 24, 25 of the metal layer 16 will be joined by welding (schematically indicated by radius 88), for example, with the use of arc welding or laser welding or a combination of these two techniques weld, which produces weld 90. The first polymer layer 12 can be heated simultaneously to a temperature that exceeds the melting point of the respective polymer material by the heat produced during the welding of the metal layer, which leads to the welding of polymer 92. To ensure the structural integrity of welds 90, 92, mechanical force can be applied to ensure that both sides 24, 25 are engaged during the welding process.
[0053] [0053] As shown in Figure 14, to fill the empty area 86 on the upper surface of metal 16, an additional polymer strip 94 will be inserted into opening 86, using a mechanical system. Said mechanical system can, for example, include a roller 96. To connect the strip 94 to the second layer of polymer 14 and / or to the metallic layer 16, heat can be applied using a heat source 98 such as dry air hot, infrared or microwave (Figure 15).
[0054] [0054] In an alternative embodiment, the sides 24, 25 of the metallic layer are engaged in a smooth joint (Figure 16) or superimposed joint (Figure 17). In the present document, the openings 86, 100 expose both the outside surface and the inside surface of said sides 24, 25 respectively, which are subsequently joined with the use of welding techniques, such as the techniques mentioned above, which create the weld 90 (Figure 18).
[0055] [0055] In a subsequent step (Figure 19), the openings 86, 100 are provided, for example, filled or sprayed with polymer strips 94, 102 respectively, as described above. A fixing device 104, for example, a heat source, can guarantee the connection of the strip 102 to the metallic layer 16.
[0056] [0056] Below in this document, additional details of modalities of the manufacturing process of the composite jacket of the invention are described.
[0057] a) Uma faixa de metal fina laminada com uma película de polímero ou uma película de polímero reforçada, em um lado ou em lados opostos; b) Uma faixa de metal fina coberta com polímero; c) Revestimento de polímero seguido por enrolamento de fibra de reforço ou tecido de fibra de reforço; d) Uma combinação de a), b) e c). [0057] The shirt can be manufactured as a composite strip, which can be produced by the following processes: (a) a thin strip of metal laminated with a polymer film or a reinforced polymer film on one side or on opposite sides; b) A thin metal band covered with polymer; c) Polymer coating followed by winding of reinforcement fiber or reinforcement fiber fabric; d) A combination of a), b) and c).
[0058] [0058] The first and / or second polymer layers can be applied only on one side in the composite strip manufacturing process stage. The application of a polymer layer to the other side can be applied in subsequent pipe manufacturing processes.
[0059] [0059] To improve the connection between the metal strip and the polymer film, adhesives can be added.
[0060] [0060] The polymer film can completely or partially cover each side of the metal strip according to the method of joining both longitudinal sides of the metal strip to produce a pipe.
[0061] [0061] The composite strip can be produced on a strip coil or continuously connected to the next step in the pipe manufacturing process.
[0062] [0062] Figure 20 shows a first roll of polymer film 112, a second roll of polymer film 114, a roll of metal strip 116 and the first roll of adhesive film 118 and second roll of adhesive film 120. The respective films are unwound and transferred together through the heating device 122. The heating device 122 comprises, for example, an induction heater, infrared (IR) heating elements, microwave heating elements or heating elements by ultraviolet (UV). Subsequently, the films can be passed together through compression rollers 124, to improve the connection between the respective films. In a next step, the bound films are cooled by a cooling device 126, for example, by spraying a substance 128 such as compressed air or water. The bonded composite liner strip is wound on a composite liner roll 130.
[0063] [0063] Figure 21 shows another embodiment, in which the metal strip roll 116 is unrolled. Adhesive coating devices 138, 140 subsequently apply the first adhesive layer 18 and the second adhesive layer 20, for example, by spraying. In a next step, polymer coating devices 132, 134 apply the first layer of polymer 12 and the second layer of polymer 14, for example, by spraying. The assembled composite material 10 can subsequently be transferred via a heating device 122, passed through compression rollers 124 and cooled by a cooling device 126. The bonded composite liner strip is wound into a composite liner roll 130 .
[0064] [0064] Figure 22 shows an embodiment of a composite pipe manufacturing process. The composite jacket roll 130 is unwound. A strip of composite jacket material 10 is fed with a number of rollers 140 to 158, which continuously form and flex said strip 10 into a tubular shape 30, or maintain said tubular shape. Between rollers 152 and 158, the opposite sides of strip 10, indicated by sides 24, 25 of metal layer 16, are connected by welding, as indicated by radius 88. Tool 32 collapses the tube into a collapsed tubular 34, which it has a reduced outside diameter and longitudinal folds 36. The collapsed composite tube 34 is subsequently disposed on the winding drum 40.
[0065] [0065] In the embodiment of Figure 23, the first roll of polymer film 112 is unrolled, which provides the first polymer film 12. Rollers 140 to 158 form and flex the first polymer film 12 in tubular form, and the opposite sides 80, 81 of said film are connected, for example, by welding as indicated by radius 88. A strip of metallic layer 16 is applied, helically wrapping said strip around the first layer of tubular polymer 12. Then In addition, the second polymer layer 14 is applied by the polymer coating device 132. The assembled composite tube 30 is passed through the heating device 122 to improve the connection between the respective layers and through the cooling device 126 to cooling. Subsequently, the composite tube 30 is collapsed and disposed on the winding drum 40 (not shown).
[0066] [0066] In the embodiment of Figure 24, roll 130 is unrolled, which provides a strip of composite jacket material 10. Rollers 140 to 158 flex said strip in tubular form. In this document, the opposite sides of the strip, which include all of their respective layers, are connected by welding 88. Subsequently, the composite tube 30 is collapsed and disposed in the winding drum 40 (not shown).
[0067] a) Desenrolamento em faixa de material compósito; b) Formação da dita faixa em formato tubular; c) União de lados opostos de faixa em formato tubular; d) Opcionalmente, enrolamento de uma fibra de reforço tal como fibra de carbono, fibra de vidro ou tecido de fibra de reforço na superfície externa do tubular de compósito 30 e ligação do mesmo à superfície externa da mesma; e) Formação corrugada do cano de compósito 30; e f) Resfriar o cano. [0067] In general, the composite material range 10 can 126 can be realized through the following steps: a) Unwinding in a strip of composite material; b) Formation of said strip in tubular format; c) Union of opposite sides of strip in tubular format; d) Optionally, winding a reinforcement fiber such as carbon fiber, glass fiber or reinforcement fiber fabric on the outer surface of the composite tubular 30 and connecting it to the outer surface thereof; e) Corrugated formation of the composite pipe 30; and f) Cool the pipe.
[0068] [0068] The above processes can be continuously advanced from a) to f), or batch processes can be divided into several subgroups, for example: Batch process 1: from a) to d); and Batch process 2: e) and f).
[0069] [0069] Figure 25 shows the welding of opposite sides 24, 25 of the metal layer 16 by fusion welding. The first polymer layer 12 is heated to a temperature that exceeds the melting temperature of the polymer by the heat of the melt welding, so that its sides 80, 81 are simultaneously joined during the welding of the metal layer.
[0070] [0070] Figure 26 shows the connection of the sides 24, 25 of the metal layer 16 by melt welding. The first polymer layer 12 is heated to a temperature that exceeds the melting temperature of the respective polymer by heat from melt welding, and its sides 80, 81 are simultaneously joined during the welding of the metal layer. The uncovered portion 86 of the outer surface of the metal layer 16 is covered by a polymer coating or polymer film fixation 94. Subsequently, the area covered by the polymer strip or coating 94 can be cooled after heating.
[0071] [0071] Figure 27 shows the connection of the sides 24, 25 of the metal layer 16 by laser welding. The polymer material of the second polymer layer 14 is transparent to the laser beam, and is not heated by the laser beam. During laser welding of the metal layer 16, the sides of the inner and outer polymer layers are heated by heat transferred from the metal layer and, as a result, bond.
[0072] [0072] In a practical embodiment, the composite material of the present invention comprises a unique combination of polymer-metal-polymer layers. The composite material can have a total thickness in the range of about 150 µm to about 2 mm, typically about 1 mm or less. Each polymer layer in the polymer-metal-polymer composite material can be the same.
[0073] [0073] In one embodiment, the first and second layers of polymer have a thickness in the range of about 50 µm to 500 µm. The polymer layers can comprise a base polymer selected from the group of thermoplastics such as PEEK (polyetheretherketone), PI (polyimide), PPS (polyphenylene sulfide), PEI (polyetherimide), PMMA (Polymethylmetacylate), PVDF ( polyvinylidene fluoride), PA (polyamide), PVC (polyvinyl chloride) and PE (Polyethylene), and thermoset plastics such as epoxy, phenolic, melamine, unsaturated polyester and polyurethane. Said base polymer may comprise a reinforcement, which may be a mixture of one or more of: short carbon fiber, PTFE, graphite, nano-oxide particle which has a diameter below 20 nm. The blend can comprise additives to enhance the bond with the reinforcement.
[0074] [0074] The metal layer can have a thickness in the range of 50 µm to 500 µm. The metal may comprise one or more of aluminum alloy (Al), nickel alloy (Ni), titanium alloy (Ti), stainless steel. To improve the bond with the polymer layers, if necessary, chemical treatment can be applied.
[0075] [0075] Disconnection is a major problem for conventional polymer shields, in general. Well fluids can permeate in the polymer shield and expand when the well cycles to a lower pressure, thus pushing the shield away from the carbon steel base pipe wall. This problem is specifically avoided in the composite jacket of the present invention, including an impermeable metallic layer, preferably produced from corrosion resistant alloy, between the well-hole fluids and the bonding agent in the jacket shield outer diameter. of composite. In addition, the disconnection problem can be avoided in the inner diameter of the metallic layer, making the polymer layer on that side (for example, the first polymer layer) fully permeable, thus avoiding pressure build-up.
[0076] [0076] As shown in Figure 28, when jacket 34 is applied to well bore tubing 70, the metal layer 16 of jacket 34 can, on the surface, be electrically connected to tubing 70. Electrical circuit 200 may include wires electrical devices 202, 204 and electrical measuring device 206. Device 206 may be a voltage meter, a current meter or a resistivity meter.
[0077] [0077] Figure 29 shows an exemplary output of the monitoring device 206 (geometric axis y) in time (geometric axis x). In a stable state, in which the jacket 34 is properly applied to the pipe 70, the output signal 210 of meter 206 will be within a predetermined bandwidth. An average value 212 of the signal will be substantially constant. If the jacket 34 fails, an electrically conductive fluid 214, such as brine or water, can allow electrical contact between the metallic layer 16 of the jacket and the well bore tubing 70. Due to the electrical contact, indicated by event 216 in the Figure 29, the average value of signal 210 will decrease, indicating jacket failure for the well bore team on the surface. In the event of a liner failure, the operation of applying a liner to the well bore tubing can be repeated, which provides a second liner layer 34 for the inner surface of the tubing to restore corrosion resistivity.
[0078] [0078] In an alternative embodiment, a shirt can be comprised of any suitable material. The material can be a composite material as described above, a single layer metallic material, a single layer polymer material or any combination thereof.
[0079] [0079] The shirt 220 can be provided as a laminated material 222 in a first step, shown in Figure 30.
[0080] [0080] In a second step, shown in Figure 31, the opposite sides 224, 226 of the laminated material 222 can be flexed upwards and towards each other, indicated by arrows 228 and 230. When sides 224, 226 are they engage, they can be interconnected. The interconnection can be made by welding, by welding device 232.
[0081] [0081] The resulting shirt, shown in Figure 32, can be flat. Jacket 220, as shown in Figure 32, can be wound. The winding drum 130 can be ready for transport to a well hole.
[0082] [0082] A modality of application of the liner in a well hole is shown in Figure 33. The winding drum 130 comprising the coiled liner 220 is arranged in a drilling rig 240.
[0083] [0083] In a first step, one end of the jacket 220 is provided with a plug 244. The plug 244 has a dimension substantially equal to an internal diameter of the well hole pipe to the jacketed one. In the example as shown in Figure 33, the jacket will be disposed on the inner surface of the production pipeline 70. The production pipeline is arranged within an internal production liner 69. The plug 244 will substantially plug the internal fluid passage of the pipeline. production 70.
[0084] [0084] In a second step, the plug 244, which has a jacket 220 attached to it, is introduced at the top end of the well hole tubular 70 (Figure 33).
[0085] [0085] In a second stage, a folding unit 246 is installed (Figure 33). Said folding unit may comprise one or more rollers 248 for folding the liner 220 in a predetermined manner. Said predetermined shape can be a C shape in cross section.
[0086] [0086] In a third stage, plug 244, which includes folded jacket 250 that is attached to it, is pumped down the well. In this document, a fluid, such as water or drilling fluid, can be pumped into wellbore tubular 70 through inlet 252. Any fluid below plug 244 can be pumped out of the borehole through annular space 254 between piping 70 and internal lining 69, and through outlet 256 (Figures 33 and 35).
[0087] [0087] When the plug has reached a predetermined location in the well hole, for example, the inner well end 260 of the pipe 70, the jacket 220 is affixed to the surface and the folding assembly 246 is removed.
[0088] [0088] Referring to Figure 35, the liner 220 is then cut on the surface, which creates a free end above orifice 262. The end above orifice 262 of the liner is opened. The open end 262 is attached using suitable connection means 264.
[0089] [0089] In a next step, an expansion tool 270 is inserted at the end above open hole 262 of the liner 220. The expansion tool 270 can be pumped into the liner 220 to unfold the liner and press the unfolded liner in engagement with the internal surface of the 70 well bore pipe (Figure 37). In one embodiment (Figure 34), the expansion tool may have a front section 272 that provides a nose or tip to guide the expander through the jacket. A medium section can be provided with a 274 ridge that has a diameter close to the inner diameter of the 70 well bore pipe. The ridge diameter can, for example, be in the range of about 99% to 99.9% of the diameter inside of the borehole pipe. An end 276 may have a smaller diameter, to allow recovery of the expansion tool.
[0090] [0090] Optionally, the expander can be recovered on the surface after expanding the jacket. In this document, the rear end 276 of the expansion tool can be attached to the profiling cable to retrieve the tool. In one embodiment, the expander may collapse to simplify recovery.
[0091] [0091] In one embodiment, seals can be applied to the shirt in selected locations along the shirt (Figure 38). For example, one or more seal rings 280 can be inserted into the well bore pipe 70 and positioned at pre-selected locations along said pipe. For example, a seal ring 280 may be positioned at or near the inner well end 260 of the well bore pipe. Another sealing ring can be positioned at a top end of the jacket. Thus, the one or more seal rings 280 will provide an additional barrier, which prevents well bore fluids from entering between the liner 220 and the inner surface of the well bore pipe 70.
[0092] [0092] Upon recovery of the expansion tool, the expander can expand the one or more seal rings 280 in their respective locations. The expanded sealing ring 280 will be forced into the borehole tubing, creating a sealing section 282 due to residual internal compression stresses (Figure 39). The latter can be considered as self-fixing, a metal fabrication technique in which a pressure vessel is subjected to pressure, which causes internal portions of the part to yield and which results in said residual internal compression stresses.
[0093] [0093] The jacket can be pumped down the well relatively easily, as described above. The jacket is relatively thin, for example, 1 mm or less. The thickness of the jacket can be in the range of about 200 to 800 µm, for example, about 0.5 mm. The folded jacket 250 will, as a result, have a much smaller diameter than the inner diameter (ID) of the well hole tubular. The production piping ID is typically 4 to 5 inch (about 10 to 15 cm) in length. The folded jacket 254, by comparison, may, in its collapsed state, have a diameter of less than 3 inches (7.5 cm), for example, 2 to 3 inches (5 to 7.5 cm). As a result, the engagement between the liner and tubing 70 is minimal. Therefore, the friction is also relatively low, which allows the shirt to be easily executed.
[0094] [0094] Figure 40 shows a drilling site 300. A truck 302 carrying a winding drum 130 and corresponding winding mechanisms 304 is arranged at site 300. The jacket 220 is unwound into a flat shape 306 and oriented along a guiding structure 308 in the well bore 310. The folding mechanism 246 bends the sleeve into a C-shaped 312. The C-shaped sleeve is introduced into the well-bore pipe 70.
[0095] [0095] More inside the well, or in a subsequent step, the shirt 220 can expand in format. The jacket can expand from a partially expanded shape 314 to a tubular shape 320. The expansion process can occur partially due to the elasticity of the shirt. Alternatively or additionally, the jacket can be expanded by introducing pressurized fluid and / or by moving an expander through the jacket, as described above.
[0096] [0096] The jacket of the present invention can be any jacket suitable for particular indoor pit conditions. The shirt may have one or more metallic layers. The one or more metallic layers can be combined with one or more polymeric layers, as described above. The one or more layers of polymer can be applied to one or more layers of metal in any suitable manner, for example, by spray coating or extrusion coating. The modalities described above in this document provide examples, but alternative methods for making the shirt can be used as well.
[0097] [0097] The liner material of the present invention and its application to jack pipe in a borehole provides a relatively low cost option while providing the superior corrosion resistance properties of solid CRA pipe or high performance steel. As the liner material can be applied to the piping after it is installed in the well bore, the internal surfaces of the threaded connectors between pipe sections will also be effectively protected against corrosion. The latter allows the use of conventional relatively low cost threaded connectors, such as API approved carbon steel connectors.
[0098] [0098] The savings in production piping, compared to the required solid CRA piping, can exceed 80%. The jacket added is relatively thin, thus minimally limiting the internal diameter of the unfinished well. The invention allows the rehabilitation of old wells in the case of acidification, increase in water cuts, etc.
[0099] [0099] The present invention is not limited to the modalities described above, in which several modifications are conceivable within the scope of the appended claims. For example, the resources of the respective modalities can be combined.
[0100] [00100] It will be understood that the method and the system according to the invention can be used to insert a leak-inhibiting and corrosion-resistant jacket of kilometers of length down well along at least a substantial part of the length of a pipeline. production of oil and / or gas from just above a Sliding Side Door (SSD) or Side Cavity Chuck (SPM) to just below a Lower Surface Safety Valve (SSSV). The shirtless upper and lower sections of the production pipe column above the SSSV and below the SSD and / or the SPM can be produced from a corrosion resistant alloy (CRA).
[0101] [00101] If the jacket is installed inside a column of production tubing, the expander to expand and unfold the jacket cannot be attached to a profile cable or Spiral Tubing (CT) assembly but can be delivered at the bottom of the pipe column by the shirt itself. The driving force for pushing the expander upward through the pipe column can be the hydraulic pressure of circulation of the well through the annular space between the pipe column and the surrounding liner of the well.
[0102] [00102] The jacket expander can be designed to self-adjust its outer circumference for variations in the internal width of the surrounding pipe column. Since the pipe column is not plastically deformed, production variations remain, and the expander and jacket must be able to adjust to the variation (difference of up to about 4 mm in internal diameter for a commonly produced production column applied). This can be achieved with the use of a spring beam and / or a rubber expander.
[0103] [00103] The expander can also be configured to preserve a residual compression force between the expanded jacket and the surrounding pipe column after expansion of the jacket, to ensure that despite the elastic relaxation and spring return in the jacket, an interference fit mechanics is achieved without plastically deforming the surrounding pipe column.
[0104] [00104] The top seal will be adjusted on the surface, also on a special pipe joint intended for this purpose.
[0105] [00105] If the liner is installed inside an internal lining column or vertical or sloped piping, the liner can be provided with metal for metal seals surrounding an upper and lower end of the liner to ensure that no production fluid between the production pipe and the jacket. The bottom end seal can be locked to a locking joint on the pipe column.
[0106] [00106] The corrosion resistant jacket can be manufactured from a corrosion resistant alloy (CRA), such as C22 nickel alloy, like a flattened pipe kilometers long with a wall thickness between 0.3 and 0, 7 mm. The curved inner surfaces of the flattened and folded shirt can be provided with a thick oil gel or lubricant to prevent the collapse of curves and the creation of vertical leak paths.
[0107] [00107] Protective coatings with a thickness of a number of micrometers, such as an abrasion resistant layer inside the jacket to protect it against profiling cable interventions and the fluid adsorption coating on the outside, can be applied during fabrication and before folding the jacket and store the folded and flattened jacket in a winding drum.
[0108] [00108] The fluid-absorbing coating will ripple in contact with water and / or other fluids trapped between the expanded jacket and the tubing column and thereby absorb any free water that may remain in the annular space between the jacket and the column of internal lining or surrounding piping, and to prevent any separation of the shirt from the surrounding shirt and the creation of leakage trajectories. The removal of water and other liquid cavities from the residual space between the expanded jacket and the vertical or inclined pipe column is particularly relevant, since even small isolated and axially and circumferentially spaced water cavities and / or other liquids can, aided by vibration and temperature fluctuations, slowly migrate downward and coalesc in larger water and / or liquid cavities that can completely envelop a lower part of the jacket and result in jacket collapse and / or its separation from the pipe. In such a case, isolated gas cavities can accumulate in a similar manner and migrate as enlarged, optionally annular gas cavities, upwards towards an upper end of the pipe column.
[0109] [00109] The fluid-absorbing coating may comprise a cross-linked acrylate polymer, which is generally known as a Superabsorbent Polymer (SAP) or hydrogel or, in a dry state, as "mud powders", which can absorb an amount of water fresh water up to 500 times its own weight in fresh water, and a slightly saline amount of water up to 50 times its own weight.
[0110] [00110] Superabsorbent Polymers (SAPs) are described in US Patent Document No. 7,144,980 and are commonly produced by polymerization of acrylic acid mixed with sodium hydroxide in the presence of an initiator to form a sodium salt of polyacrylic acid ( sometimes called sodium polyacrylate). This SAP is the most common type of SAP produced today.
[0111] [00111] The fluid-absorbing coating may also comprise a sticky glue and / or other adhesive to firmly bond the liner to the pipe column or inner liner and further inhibit the collapse and / or separation of the thin sheet liner from the liner column. piping or surrounding lining.

权利要求:
Claims (15)
[0001]
Method for laying a pipe column (70), comprising: - insert a folded jacket (250) in the pipe column (70); - unfold the liner (220) to expand the liner against an internal surface of the pipe column; and characterized by the fact that it comprises: - the folded jacket (250) has an outer surface that is at least partially covered with a fluid-absorbing coating; and - inducing the liner (14, 94) to absorb the fluid trapped between an inner surface of the pipe column and an outer surface of the expanded jacket.
[0002]
Method according to claim 1, characterized in that the coating comprises binding and liquid-absorbing additives.
[0003]
Method according to claim 2, characterized in that the additives comprise a sticky glue and a hygroscopic material, which absorbs any substantial cavities of water and / or other trapped fluid, and increases the connection between the pipe column and the expanded shirt.
[0004]
Method according to any one of claims 1 to 3, characterized by the fact that the step of inserting the jacket into the pipe column comprises: - providing an end of the shirt with a plug (244); - insert the plug (244) into the pipe column (70); and - pump the plug (244) through the pipe column (70) until the plug has reached a predetermined location.
[0005]
Method according to any one of claims 1 to 4, characterized in that the step of expanding the jacket comprises: - unfold one end of the jacket (220); - fix the unfolded end of the jacket inside the pipe column; and - pump an expansion tool (270) and / or a pressurized fluid through the inside of the jacket (220).
[0006]
Method according to claim 5, characterized by the fact that the pipe column (70) is a pipe or internal lining column in an oil and / or gas production well and the jacket expansion step comprises: - insert a tool column carrying an unexpanded expansion cone (270) in the folded jacket (250), - insert the folded jacket (250) together with the tool column in the piping column; - expand the expansion cone to press a lower end of the jacket against a lower part of the pipe column; and - pull the tool column and the expansion cone expanded through the jacket to the earth's surface, thereby expanding the jacket.
[0007]
Method according to any one of claims 1 to 6, characterized in that it comprises the step of: - inserting one or more sealing rings (280) in the expanded jacket; and - expand the one or more sealing rings in engagement with the liner.
[0008]
Method according to any one of claims 1 to 6, characterized in that the jacket is made of a composite material comprising: - at least one polymer layer (12); and - at least one metallic layer (16) disposed on the polymer layer.
[0009]
Method according to claim 8, characterized in that the jacket additionally comprises reinforcement cables selected from the group of steel, carbon and fiberglass cables.
[0010]
Method according to any one of claims 1 to 9, characterized in that the coating comprises an adhesive and the method further comprises applying the coating to an external surface of the jacket before inserting the jacket in the pipe column.
[0011]
Method according to claim 10, characterized in that the coating is applied using a coating applicator device that includes at least one of a spray device (132, 134) or a roller (96) to apply the coating. jacket to shirt.
[0012]
Method according to claim 10, characterized in that the coating comprises a heat activated adhesive.
[0013]
Jacket (220) for driving a pipe column (70) into a well hole, configured to be folded in a collapsed state in the pipe column (70) and to be unfolded against an internal surface of the pipe column and characterized by the fact that it is, at least partially, covered with a fluid-absorbing coating (14, 94) which is configured to absorb the fluid trapped between the inner surface of the pipe column and the expanded jacket.
[0014]
Jacket according to claim 13, characterized in that the coating comprises binding and liquid absorption additives.
[0015]
Jacket according to claim 14, characterized in that it is made of a corrosion-resistant ductile metal with a wall thickness of less than 1 mm and the additives comprise a sticky glue and a hygroscopic material.

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同族专利:

公开号 | 公开日

AU2017225087A1|2017-09-28|

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CN106104135B|2018-03-02|

US10316628B2|2019-06-11|

AU2015222095B2|2017-06-15|

CN108662355A|2018-10-16|

GB2539816B|2020-08-19|

WO2015128454A1|2015-09-03|

US20160362968A1|2016-12-15|

AU2017225087B2|2019-04-18|

GB2539816A|2016-12-28|

AU2015222095A1|2016-08-18|

US20190257180A1|2019-08-22|

CA2938915A1|2015-09-03|

US10858918B2|2020-12-08|

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法律状态:
2020-03-10| B06U| Preliminary requirement: requests with searches performed by other patent offices: suspension of the patent application procedure|

2020-12-01| B09A| Decision: intention to grant|

2021-02-17| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 27/02/2015, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

申请号 | 申请日 | 专利标题

EP14157013|2014-02-27|

EP14157013.5|2014-02-27|

PCT/EP2015/054115|WO2015128454A1|2014-02-27|2015-02-27|Method and system for lining a tubular|

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