MX2008009622A

MX2008009622A - Remote plugging device for wells.

Info

Publication number: MX2008009622A
Application number: MX2008009622A
Authority: MX
Inventors: Jonathon Paul Edwards; Alexander Jeffrey Burns
Original assignee: Well Ops Sea Pty Ltd
Priority date: 2006-01-24
Filing date: 2007-01-24
Publication date: 2008-12-19
Also published as: EP1982045A1; AU2007209762A1; US20090301720A1; WO2007085047A1

Abstract

Remote cement plugging device (10) and method of use. The device has at least one means (60) for perforating at least one hole through a wall of a first well casing, and means to inject cement into an annulus between the inner well casing and a second well casing. The perforating means has at least one punch (65) actuated by compressed fluid (hydraulic, pneumatic) to form the hole(s), and thereafter the cement is delivered to the annulus between the inner and outer/intermediate casings to form the cement plug without the need to withdraw the device from the well casing.

Description

"SEALING DEVICE REMOTE WELLS FIELD OF THE INVENTION The present invention relates to the sealing of hydrocarbon wells, particularly wells subsea hydrocarbon and must remain barriers between the hydrocarbon formation and the surface to avoid contamination of oil leakage from from the well.

BACKGROUND OF THE INVENTION In the field of subsea oil and gas production, there are regulations that require maintaining barriers between the formation of oil and / or gas and the surface. During the abandonment of underwater wells, the barrier system must be maintained to ensure that any oil or residual gas in the formation does not dissipate from the well causing a potential polluting event, with the associated environmental and social impact. Barrier systems for wells overseas consist of active and passive systems, maintaining a physical barrier in the passive systems between the formation and the seabed. Therefore, active systems are designed in case of emergency or an unforeseen circumstance, the system is deployed to provide a barrier between the formation and the seabed. When a well is abandoned overseas, the use of active systems to maintain the barriers between the seabed and the formation is not adequate given that there will be no ongoing maintenance of the barrier. Furthermore, during removal of the wellhead of the subsea well a barrier that covers the annulus between the liner and the first intermediate coating is removed and needs to be replaced before cutting the wellhead. One way to maintain barriers during the abandonment of an underwater well is the use of cement. A cement seal is melted in the central housing and the cement is injected into the annulus between the center cladding and the first intermediate cladding. To pump the cement into the ring first it is necessary to provide a path for the cement to move from the central liner to the ring. This is usually done by the use of explosives in order to make perforations in the central coating that reach the ring. When an underwater well is abandoned, jack-up rigs, work barges or semi-submersibles have traditionally been used. With the use of these types of vessels, the production of perforations in the reverse through the ring is usually done through the use of explosives. There are several issues with the use of explosives relevant to safety aspects. In addition, a large stable platform must be provided in such a way that the explosives can be handled safely. Existing methods for underwater intervention and abandonment of wells have some inherent disadvantages including the use of large vessels so that can explosives used, these vessels tend to move slowly, take a relatively long time to reach the oil and gas fields overseas and are expensive to operate while they are at the station. In order to solve the related cost and time problems to reach a large operating platform in a station, the use of work barges is desired. Problems with the use of a working barge arise when explosives are used, so alternative methods and means are required to provide perforations in the lining and inject cement. Reference to any prior art in this specification is not, and should not be construed as, knowledge of some form of admission of which the prior art forms part of the general knowledge common in Australia.

BRIEF DESCRIPTION OF THE INVENTION Considering the above, in one aspect of the present invention a device for operations oilfields including means for drilling in a wall of a first well casing and means for injecting sealant is provided the inside of a ring between the first well liner and a second well liner, which includes at least one punch assembly, a cutting tool designed to produce a perforation in the coating and a sealant supply means, where the tool is capable of performing the perforations and supplying sealant to the ring without the need to remove the tool of the well liner. A further aspect of the present invention provides a remote sealing device for well operations, including at least one piercing means for performing at least one piercing in one or more well liners, and a sealant injection means for injecting the sealant between at least one of one or more well liners and at least one of the well liners or an additional well liner, wherein the drilling means includes at least one punch activated by pressurized fluid to perform at least one bore, and after that the sealant is supplied to the ring in order to form the seal without the need to remove the device from the well casing. In another preferred embodiment, the device and auxiliary equipment are adapted for deployment from a working barge for use in subsea applications. Another aspect of the present invention provides a remote sealing device for well operations, including at least one piercing means for performing at least one piercing through a wall of a first well liner, and an injection means for injecting a sealant within a ring between the first well liner and a second well liner, wherein the drilling means includes at least one punch activated by compressed fluid in order to perform at least the drilling, and thereafter the sealant is supplied at ring in order to form the seal without the need to remove the device from the well liner. Preferably, the sealant is cement based, or it may be an uncured medium such as drilling mud. The activation of the punch (s) by compressed fluid advantageously avoids the need for explosive charges to perform the perforation. At least one punch can be activated by hydraulic or pneumatic pressure. An at least one punch may extend into or retract at least one hydraulic or pneumatic double activation piston, which provides positive activation and retraction to help ensure that the perforator (s) is retracted so that the sealant can flow through the perforation (s). Alternatively, at least one punch may be extended by hydraulic or pneumatic pressure and retracted by at least one elastic biasing means, which simplifies the return activation means, such as by return spring (s). Preferably, there may be one or more outlets / ports for the sealant flow provided adjacent to at least one of the piercing means. This serves to ensure that the sealant flow easily reaches the perforation (s) and reduces the overall amount of cement required. At least one packer assembly may be provided, whereby, when the packer assembly or assemblies are expanded (n) to clamp the device by pressure into the well casing, for example, by pressing against an inner wall of the inner liner. from the well. Such packers can be energized by hydraulic or pneumatic pressure. Alternatively or in addition, self-energizing packers may be provided. These can expand as a result of the initial pressure coming from a supply pipe of pressurized fluid (for example, from the surface) or from a hydrocarbon that escapes through at least one perforation made by the device. The applied pressure causes the packers to seal the device inside the borehole before the sealant is pumped into the bore (s). The device may include at least one fluid pressure accumulator, preferably hydraulic or pneumatic accumulator (s), in or near the front end of the device, the fluid pressure accumulator providing at least one packer assembly in case of device failures. The fluid pressure can be supplied from the hydraulic, pneumatic supply used to activate the drilling medium. At least two of the perforation means can be spaced such that the distance between a first punch of a first perforation means and a first punch of a second perforation means is greater than a length of coupling members used to couple together portions of the well liner. One or more of the punches may have a spindle in such a manner that in case the punch is jammed, the punch and base of the punch can positively retract and an operative end of the punch break by constant stress. At least one of the punches may be attached to the piston by a quick release means, such as by a quick release ring, fastener or other retaining device. At least one elastic packer can be provided which absorbs the induced impacts on the respective punch during the drilling of the coating. Silicon rubber, rubber, nitrile, or the like, or combinations thereof, may be used. The piercing means may be adapted to perform consecutive perforations through multiple coating walls, one after the other. That is, where the well has multiple coatings one inside the other, the drilling can, for example, perform a drilling through more than one liner to place a seal (eg, cement) between the concentric coatings first and / or second and third. A further aspect of the present invention provides a method for sealing a well rising tube, including the steps for: a) inserting a remote sealing device into a riser tube; b) supplying compressed fluid to the sealing device; c) drilling at least through a first well liner using at least one respective punch activated by the compressed fluid; and d) pumping a sealant through at least one perforation into a ring between at least a first coating and a second coating or intermediate coating so as to form a seal. The method may further include the steps for performing one or more perforations with at least one respective punch, and leaving at least one punch extended to activate as a fastener for the device. Consequently, one or more punches may remain unfolded in order to hold the device. There can be significant hydrocarbon pressure in the device when a hole is drilled through the liner, and the non-retracted punch (s) can act as a second lock to hold the device in place. Also, in case the device needs to be left in the well for any reason, this clamping configuration can help keep the device in place. An accumulator may be used to provide sufficient pressure in order to keep a punch extended at least. A one-way or check valve can be used to avoid pressure loss once the hydraulic or pneumatic supply is removed from the device. The method can include the removal of at least one punch from at least one respective perforation. However, it is intended that the device be able to pump fluid around, through, or a combination thereof, of at least one punch. Hydraulic fluid can be used to activate the punch (s).

Preferably, the sealant contains cement. The retraction of at least one punch can be by hydraulic or pneumatic pressure. Alternatively, the extension of at least one punch may be by hydraulic or pneumatic pressure and the retraction by elastic tilting means. The realization of at least one perforation can be through a plurality of well lining walls, and by injecting the sealant into the ring between at least one of the plurality of walls and an additional lining wall.

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 shows an overview of a device modality. Figure 2 shows a cross section of the inlet tip and a lower packer assembly of the embodiment shown in Figure 1. Figure 3 shows a cross section of the hydraulic punch assembly of the embodiment shown in Figure 1. Figure 4 shows the lower drilling tool of Figure 1 in more detail. Figure 5 shows an alternate modality of the device. Figure 6a shows a cross-sectional view of an alternative embodiment of the device that includes hydraulic spring return pistons. Figure 6b shows a perspective view of the complete device of Figure 6a. Figure 7a is a perspective view of a drill assembly of an embodiment of the present invention. Figure 7b is a cross-sectional view of the embodiment shown in Figure 7a.

DETAILED DESCRIPTION OF THE INVENTION The invention will now be described with reference to the appended figures. Referring first to Figure 1 which shows an overview of the remote sealing device in the present referred to later as the "tool". Although cement is referred to hereinafter as the sealant, it will be appreciated that other sealants, such as drilling mud, may be employed. The construction of the tool 10 is based on modular construction methods in such a way that individual components can be replaced if damaged during an overseas campaign. Other configurations of the seen components are possible that allow the operation of the tool 10 such that the coating is pierced and cement is injected into the ring. Only a typical example is described in the following detailed description. The general inlet of the tool 10 includes an inlet tip 20 at a front end 25, designed to allow the insertion of the cement injection tool 10 into an underwater well. The inlet tip 20 is connected to a lower packer mandrel 30 having a packer assembly 40 fitted. The packer assembly 40 is designed such that when the tool 10 is inserted into the inner lining of the underwater well, the packer assembly 40 can expand and hold the tool 10 in place and seal the tool 10 in the liner. The lower packer mandrel 30 is connected to a hydraulic module 50 at the end of the first hydraulic module 52. The hydraulic module 50 consists of a set number of punch assemblies 60 with punches 65. The punch assemblies 60 are circumferentially configured around of the hydraulic module 50 and are designed in such a way that they can make perforations in the inner lining. However, it will be appreciated that at least one punch may be used to make perforations through more than one facing wall, such that the sealant may be pumped into the ring or cavity between the additional coatings, for example, between the inner liner. and intermediate, and between the intermediate cladding and an outer cladding. At the end of the second hydraulic module 54, there is a cement outlet port 75. At the end of the second hydraulic module 54 is an upper packer mandrel 80 which includes a packer assembly 90 for sealing the tool 10 within the Inner liner attached to second end 81 of upper packer mandrel 80 is a separation barrier 70. In the uppermost portion of the tool 10, there is a hydraulic hose guide 100 and elevation points 110 that connect the cement injection tool 10 by a lift cable, and hydraulic and service lines to the boat. As seen in more detail in Figure 2, the inlet tip 20 with a taper 22 at the front end thereof to allow placement of the tool in a subsea well and to guide the tool 10 into the well interior liner during the deployment of the tool 10. The inlet tip 20 has also been designed to be incorporated into a hydraulic accumulator 25. The hydraulic accumulator 25 is used to provide hydraulic pressure to the packer assemblies 40, 90 in case of a tool failure 10 that requires the abandonment of tool 10 in the well. The hydraulic accumulator 25 allows the tool 10 to act as a barrier in case the tool 10 needs to be abandoned. The inlet tip 20 can be held by a threaded portion 28 to the first end 31 of the lower packer mandrel 30. The lower packer mandrel 30 is generally hollow but could be made from a range of density materials in order to provide the desired buoyancy characteristics of the tool 10. The packer assembly 40 associated with the lower packer mandrel 30 is designed so that once it is subjected to a hydraulic pressure, the packer assembly 40 can expand and seal the inner liner . The pressure that can be applied to the packer assembly 40 is about 5000 psi, but could be higher in some applications. At the second end 32 of the lower packer mandrel 30 is a threaded portion of the packer mandrel 33 which connects the lower packer mandrel 30 with the hydraulic module 50 at the end of the first hydraulic module 52. The hydraulic module 50 is the module which contains active hydraulic components and the tooling required to perform the drilling through the inner well liner. The hydraulic module 50 includes at least one hydraulic punch assembly 60, through which there can be as many as ten or more hydraulic punch assemblies 60. The spacing and orientation of the hydraulic punch assemblies 60 is such that the perforations can be made to through the inner lining in different locations around the circumference of the inner lining and in different positions vertically along the inner lining. In a preferred embodiment, the punch assemblies 60 are spaced apart such that the distance between a first punch 62 and the second punch and the subsequent punch 65 is greater than the length of the non-shown coupling members normally used to couple together sections. Well coating. This works in such a way that when the tool 10 is inserted into an inner liner the perforations can still be made even if a punch assembly 60 is located behind a coupling member, the remaining punch assemblies 60 will not coincide with the members of coupling and therefore will be able to pierce the inner lining. At the second end of the upper punch mandrel 82 there is a separation barrier 70. The separation barrier 70 is designed in such a way that if the device needed to be abandoned in the well due to unforeseen circumstances, the well would remain sealed in a manner such that the contents of the well do not leak. The separation barrier 70 has hydraulic lines and coupling check valves connected in such a manner that in the case of a separation event, the hydraulic pressure in the packer assemblies 40 90 remains constant, thus ensuring that the packer assemblies 40 90 hold firmly in place against the inner lining. The separation barrier 70 is designed to have insurance bolts to take a predetermined load. These securing bolts are designed to have sufficient strength so that the tool 10 can be removed from the inner lining even with residual cement surrounding the hydraulic module 50 that could come off in case the tool 10 should be abandoned. A typical separation load is 25 tons but this load could vary depending on the application of the tool 10. The separation barrier 70 also includes a check valve in the sealant pipe that can be activated by hydraulic pressure or activated automatically (by example, by pressure activated by springs). This check valve can be located in the upper packer mandrel 80. The check valve can be a normally closed check valve that is activated by hydraulic pressure or pneumatic pressure. The tool can be provided with a certain number of pipes that communicate with the boat (not shown). These pipes will include hydraulic, control, monitoring and bypass pipes. These pipes allow the tool 10 to be operated from the vessel and parameters such as the pressure in the well can be monitored. Referring now to Figure 3, the hydraulic punch cylinder assemblies 60 include two hydraulic pistons 61 capable of supporting at least 5000 psi or more, although the upper pressure limit may vary depending on the expected loads required to perform the drilling. The hydraulic pistons are fitted with punches 65 used to perforate the inner lining. The double-way piston is selected to ensure that the punch 65 can be retracted once a perforation has been made in the inner liner. The hydraulic punch assembly of the two-way type includes a hydraulic feed 69 to provide hydraulic pressure in order to retract the piston. The punch 65 is made of stainless steel and is used to make perforations in the inner lining. The punch 65 is designed with a separating shaft 66 such that in case the punch 65 is stuck in the perforation made in the inner lining the hydraulic piston 61 can positively retract and the punch 65 can be sheared. The punch 65 is held within the punch piston assemblies with a quick release ring 67. This quick release ring can be removed to allow field extraction and punch replacement 65 in situations where multiple wells are abandoned and required the replacement of a punch 65. In the case of punches used to hold the device, preferably these would be punches without separation, such that the punches remain extended to hold the device in place. Behind the quick release ring 67 is an elastic packer 68 which acts to absorb the induced shock on the punch 65 when the perforations are made. The elastic packer 68 can be manufactured from a wide range of materials capable of absorbing shock loads. Preferred materials are ultra-high molecular weight synthetic materials, such as PEEK, UHMPE, HFPE or Nylon, etc. or other dense synthetic materials stable to water. In an alternate embodiment, the hydraulic pistons 61 are not two-way hydraulic pistons but use cement pressure or formation to retract the hydraulic pistons 61 once the perforations have been made. In a possible variation, the use of spring-activated hydraulic pistons can be implemented when the tool 10 is intended to be abandoned in the well.

Figure 4 shows the hydraulic module 50 of the lower drilling tool of Figure 1 in more detail. The module that contains active hydraulic components and the tooling required to perform the drilling through the inner well liner. The hydraulic module includes at least one punch assembly ???? ^ μ ???? 60 and one of the cement feed outlets 75. Figure 5 shows an alternate embodiment of the device including the first lower drilling assemblies 60a and second 60b, and the upper drilling assemblies first 60c and second 60d. These are connected by a cable link 110 of variable length "D" to suit a particular application. The upper cup packer 112a and the lower washer packer 112b are provided. These work to provide a seal between the device and the lining wall in order to prevent the cement from flowing past the packer. They also provide a pressure seal if there is presence of hydrocarbons after drilling, otherwise there would be leaks. Upper and lower perforation supply ports 114. These ports provide cement respectively to the upper and lower sections of the device.

Figures 6a and 6b show a further embodiment including hydraulic activating punches individually activated by spring 65a-65d. The punches are hydraulically extended to create perforations through the inner liner of the well, and are biased by spring pressure toward the folded position shown in the figures. Figures 7a and 7b show one of the hydraulic drilling assemblies 60. Figure 7 is a perspective view of the punch assembly 65. In a cross-sectional view, Figure 7b of the assembly 60, with the hydraulic piston 61b retracted into the body. 61a of the assembly. The punch 65 is held in place by a screw adjusting ring 120 analogous to the quick release ring in Figure 3. The set screws 122a and 122b hold the hydraulic cylinder 61a within the skin 124. A hydraulic release shackle is provided. 116 (analogous to the separation system described above), which allows the device to be fully decoupled, that is, in case the device becomes unrecoverable from the well. Monitoring wells and ringhole pressure purge are provided. In operation, the cement injection tool 10 extends from a vessel 1 and with the help of divers or an ROV is placed inside the inner lining of an underwater well. Once the cement injection tool 10 descends and is placed, hydraulic pressure is applied by forcing the packer assemblies 40, 90 to secure the cement injection tool 10 against the inner lining walls. Afterwards, the packers ensure that there are no leaks. Subsequently, hydraulic pressure is applied to each punch assembly 60 resulting in turn a series of perforations made in the inner lining. Then, all ring pressure is purged in a controlled manner either towards the sea or towards a tank in the vessel. Ideally, the piercing punch will result in multiple perforations made in the inner liner, the perforations being evenly distributed around the circumference and along the inner lining. Once the perforations in the inner lining have been made, a cement inhibitor is injected to inhibit the setting of the cement in openings and joints surrounding the packer assemblies and the punch assemblies. The inhibitor is injected through the cement injection port 54, then moved down to the hydraulic section of the hydraulic module 50. After the inhibitor has been injected, the cement is injected through the cement injection port 54 and it flows around the hydraulic module 50 and through the perforations made in the inner liner inside the ring between the inner liner and the first intermediate lining. Once the cement is injected into this ring and the pressure is tested, the packer assemblies are released and the injection tool 10 is removed. The punch assembly 60 includes the hydraulic section designed specifically for this application, which includes a double activation hydraulic piston 61 (positive displacement and retraction piston). This is designed in such a way that the punch 65 can be forcedly retract from the inner lining in case of problems. The punch 65 is inserted into a hydraulic ring and held in place by a shock absorbing ring 66 and a punch holder member 67. Variations and modifications to the tool 10 are still within the scope of the invention. the invention.

Claims

NOVELTY OF THE INVENTION Having described the invention as antecedent, the content of the following claims is claimed as property CLAIMS 1. A remote sealing device for well operations, characterized in that it includes at least one piercing means for performing at least one piercing through one or more well liners, and sealant injection means for injecting sealant between at least one one of one or more well casings and at least one of the well casings or an additional well casing, where the drilling means includes at least one punch activated by pressurized fluid to perform at least one drilling, and subsequently the sealant It is sent to the ring to form the seal without the need to remove the device from the well casing. A device according to claim 1, characterized in that at least one punch is activated by hydraulic or pneumatic pressure. A device according to claim 1 or 2, characterized in that at least one punch is extended and retracted by at least one hydraulic or pneumatic dual activation piston. 4. A device according to claim 1 or 2, characterized in that at least one punch extends by hydraulic or pneumatic pressure and is folded back by at least one means of elastic inclination. A device according to claim 4, characterized in that at least one elastic inclination means includes at least one return spring. A device according to any of the preceding claims, characterized in that it includes an outlet for the flow of sealant provided adjacent to at least one perforation means. A device according to any of the preceding claims, characterized in that it includes at least one packer assembly where, when the device is inserted into the well, at least one packer assembly is expanded in order to hold the device by pressure against a perforation of the well liner. A device according to claim 7, characterized in that it includes a fluid pressure accumulator provided within or proximate to a leading tip of the device, the accumulator providing fluid pressure to at least one packer assembly in case of device failure. A device according to claim 7 or 8, characterized in that at least one packer assembly is activated by compressed or pressurized fluid. A device according to claim 9, characterized in that the compressed fluid is a hydraulic or pneumatic supply. A device according to any of the previous claims, characterized in that at least one punch includes a separation axis in such a way that in case the punch is stuck in the perforation made, the punch and an operative end of the sheared punch are positively retracted. . A device according to any of the preceding claims, characterized in that at least one perforation means includes at least one elastic shock-absorbing packer induced in the respective punch when the coating is perforated. A device according to claim 12, characterized in that at least one elastic packer is formed from silicon rubber, rubber, nitrile, PEEK, UHMPE, HFPE, nylon, other ultra-high density synthetic material, or the like, or combinations thereof. A device according to any one of the preceding claims, characterized in that the perforation means is configured to perforate consecutively through a plurality of well facing walls, and the sealant is configured to be injected between at least one of the walls of the well. coating and an additional coating wall. 15. A method for sealing a riser tube, characterized in that it includes the steps for: a) inserting a remote sealing device into a riser tube; b) supply pressurized fluid to the sealing device; c) performing at least one perforation through at least one first well facing wall using at least one respective punch activated by the fluid; and d) pumping a sealant through at least one perforation into a ring between at least a first coating wall and an outer or intermediate coating to form a seal. 16. A method according to claim 15, characterized in that the sealant contains cement or drilling mud. A method according to claim 15 or 16, characterized in that it includes the step for retracting at least one punch by hydraulic or pneumatic pressure, or by using at least one means of elastic inclination. 18. A method according to any of claims 15 to 17, further characterized in that it includes the steps for clamping at least one of at least one extended punch after drilling the coating. A method according to any of claims 15 to 18, characterized in that it includes the steps to perform at least one piercing through a plurality of well-lining walls, and to inject the sealant into the ring between at least one of the plurality of walls and an additional covering wall. A method according to any of claims 15 to 19, characterized in that it includes the steps for using at least one packer to provide an initial seal between the device and the inner lining against the leakage of hydrocarbons before pumping the sealant within at least a perforation.