Patent Application
20190186213
The present invention relates to an offshore coiled tubing system for running a coiled tubing into a subsea well offshore, comprising a well comprising a well tubular metal structure having a top and an inner face, a blowout preventer (BOP) arranged in the top of the well tubular metal structure, and a sluice having a top part for entering of coiled tubing, the BOP being arranged between the well tubular metal structure and the sluice, the sluice having a sealing unit arranged in the top part of the sluice for sealing around the coiled tubing; a vessel comprising a deck, a coiled tubing reel comprising coiled tubing, the coiled tubing having a first end, and a first driving unit for assisting in driving the coiled tubing into/from the well, the first driving unit being configured to be movable in relation to the deck to compensate for heave motion of the vessel; and a second driving unit for assisting in driving the coiled tubing into/from the well. The present invention also relates to an offshore coiled tubing method.
Coiled tubing has many uses in relation to a hydro-carbon containing subsea well. Coiled tubing (CT) is usually transported to the subsea well W on a vessel V where the coiled tubing is coiled around a reel R arranged on the deck D of the vessel, as shown in
A coiled tubing injector is a delicate system with many moving parts. It is critical for correct deployment and retrieval of the coiled tubing to working depth without causing physical damage to the coiled tubing pipe. A subsea injector is a marinised version of a standard injector head. Positioning at the seabed leaves the coiled tubing injector out of reach for ad hoc maintenance if required, except for a few functions that can be exercised using an ROV (remotely operated vehicle). Inability to operate the injector controls may result in the CT having to be cut and left in the well. The subsea injector is a heavy piece of machinery of approximately 10 tonnes that needs to be deployed through the water column for each run in the well. Positioned at the top of the sluice, it introduces an additional bending moment to the sluice and the wellhead connectors.
It is an object of the present invention to wholly or partly overcome the above disadvantages and drawbacks of the prior art. More specifically, it is an object to provide an improved offshore coiled tubing system which has a smaller risk of the CT being left in the well if failing, and/or is easier to repair/maintain while the CT can still be operated in the well.
The above objects, together with numerous other objects, advantages and features, which will become evident from the below description, are accomplished by a solution in accordance with the present invention by an offshore coiled tubing system for running a coiled tubing into a subsea well offshore, comprising:
Furthermore, the second driving unit may be connected to the first end of the coiled tubing.
In addition, the second driving unit may have an outer diameter which is smaller than an inner diameter of the BOP, or the lubricator or the sluice.
In another embodiment, the second driving unit moves along with the coiled tubing.
The offshore coiled tubing system may be a riserless coiled tubing system.
Moreover, the second driving unit may be configured to be moved into the well tubular metal structure together with the coiled tubing.
The second driving unit may be moved with the same speed as that with which the coiled tubing is being driven.
Furthermore, the second driving unit while driving the coiled tubing may be positioned inside the BOP and/or inside the well tubular metal structure. Hence, the second driving unit operates within the BOP and/or within the well tubular metal structure.
Also, the second driving unit may comprise several projectable parts configured to engage the inner face of the well tubular metal structure.
Furthermore, the projectable parts may each comprise a wheel on an arm, and each wheel may comprise a motor, such as a hydraulic or electrical motor.
The arm may be projectable by means of pressurised fluid.
Moreover, the first driving unit may be configured to drive the coiled tubing by engaging an outer face of the coiled tubing, and the second driving unit may be configured to drive the coiled tubing by engaging the inner face of the well tubular metal structure.
In addition, the second driving unit may be configured to provide a tension in the coiled tubing.
The sluice may be a riser or a lubricator.
The sealing unit may be a stripper or a tandem (dual) stripper.
The present invention also relates to an offshore coiled tubing method for running a coiled tubing into a well offshore, comprising:
Furthermore, the driving of the coiled tubing into the well tubular metal structure by means of the second driving unit may be performed by moving the second driving unit together with the coiled tubing into the well tubular metal structure.
Moreover, the driving of the coiled tubing into the well tubular metal structure by means of the second driving unit may be performed by providing the second driving unit with several projectable parts configured to engage the inner face of the well tubular metal structure.
Additionally, the step of driving the coiled tubing into the well tubular metal structure by means of the second driving unit may comprise adjusting the speed according to a predetermined tension in the coiled tubing.
Further, the step of driving the coiled tubing into the well tubular metal structure by means of the second driving unit may comprise pulling the coiled tubing forward in the well.
By having the second driving unit pulling the coiled tubing forward in the well, the second driving unit provides a certain tension in the coiled tubing to keep the coiled tubing substantially straight.
The invention and its many advantages will be described in more detail below with reference to the accompanying schematic drawings, which for the purpose of illustration show some non-limiting embodiments and in which:
All the figures are highly schematic and not necessarily to scale, and they show only those parts which are necessary in order to elucidate the invention, other parts being omitted or merely suggested.
By having the second driving unit 16 as a movable part in relation to the BOP 6 inside the lubricator or sluice 7, the well 2 or the BOP 6, the second driving unit does not have to be controlled in relation to the first driving unit as in known solutions. When the second driving unit moves along with the coiled tubing, the first and second driving units do not have to be controlled very accurately as in the known solutions, where the second driving unit is arranged in the top of the well on top of the BOP. This is due to the fact that when entering the well, the second driving unit provides the tension in the coiled tubing and the first driving unit can thus just let the coiled tubing roll around it into the well, and likewise when retracting the coiled tubing from the well, the first driving unit pulls and the second driving unit provides no force at all. Thus with the present solution, the first and the second driving units need not be controlled simultaneously and in relation to each other.
Furthermore, by the present solution of having the second driving unit within the well and not on top of the BOP, the second driving unit is much smaller than the known subsea injector and does not result in a large bending moment on the top of the well, i.e. on top of the BOP and the lubricator or sluice.
In addition, the second driving unit 16 can easily be repaired just by pulling the coiled tubing 1 to surface as the second driving unit will follow and can then easily be accessed and repaired.
By sluice is meant a chamber in which e.g. a tool is provided and pressure tested and thereafter let into the well when the chamber has approximately the same pressure as the well. The sluice may have further means for changing the fluid inside the chamber. Thus, the sluice may be a lubricator or a small riser.
By having the second driving unit 16 as a movable part in relation to the BOP 6 inside the lubricator or sluice 7, the well 2 or the BOP 6, the second driving unit can be made less complex and less large, and the offshore coiled tubing system has a smaller risk of the coiled tubing 1 being left in the well if failing, since the system is easier to repair. The coiled tubing 1 can therefore still be operated in the well even though the second driving unit 16 needs repairing.
Coiled tubing is “bendable” tubing which is capable of being coiled around the reel on the deck without losing its properties by such coiling. Coiled tubing is therefore not as rigid as drill pipe and cannot hold a straight shape in the water like drill pipe can. There is therefore a need for driving units to keep the coiled tubing in a straight line in the sea, so that it does not bend too much due to current and its own mass, hence preventing damage caused by such bending. There is also a need for driving units ensuring that the coiled tubing is not stretched too much due to the heave in the vessel. The second driving unit 16 is capable of providing such straight shape of the coiled tubing together with the first driving unit 15 even though the second driving unit is moving in relation to the BOP.
The second driving unit 16 is connected to the first end 14 of the coiled tubing 1 and thus pulls in the CT 1 while moving forward in the well tubular metal structure 3 of the well 2 together with the CT 1. The second driving unit 16 is thus moving with the same speed as the coiled tubing. The second driving unit 16 is thus configured to provide a tension in the coiled tubing 1, so that the coiled tubing 1 is kept substantially straight between the vessel and the second driving unit 16.
By having the second driving unit 16 arranged in front of the coiled tubing 1 while pulling it downwards, the coiled tubing is kept substantially straight over a longer part, as the coiled tubing is also kept straight at the part being in the well 2 and not just between the vessel and the top of the well as in the known solutions where the second driving unit is arranged in the top of the riser above the BOP.
In
The arm 19 of the second driving unit 16 is projectable by means of pressurised fluid, e.g. from a second pump in the second driving unit 16. The second pump may be driven directly or indirectly by means of the pressurised fluid supplied in the CT in the same way as the wheels. The arms may, in another embodiment, be driven by gears and motor in the body of the second driving unit 16.
In yet another embodiment, the second driving unit 16 may be a crawler-type where a first part and a second part are movable in relation to each other. The first part has projectable parts engaging the inner face of the well tubular metal structure while the second part with retracted projectable parts 17 moves in relation to the first part and then engages the inner face, after which the projectable parts 17 of the first part are retracted, and then the first part moves towards the second part and in this way crawls forward in the well like a worm. In yet another embodiment, the second driving unit may have a chain drive or caterpillar track like the traction units of a tank.
The first driving unit 15 of
The sluice 7 is configured to be pressurised to obtain substantially the same pressure as in the well 2 before opening the BOP 6, and thus pressure testing such equipment and BOP, sluice/lubricator and stripper connections before they are lowered into the well. Therefore, the sluice 7 comprises a sealing unit 9 in the top part 8 for sealing the sluice 7 from its surroundings, e.g. the sea and the hydrostatic pressure. In
The invention also relates to an offshore coiled tubing method for driving a coiled tubing 1 into a well 2 offshore, comprising positioning a vessel 10 of the above mentioned offshore coiled tubing system 100, connecting the second driving unit 16 to the first end 14 of the coiled tubing 1, introducing the second driving unit 16 and part of the coiled tubing 1 into the sluice 7, then pressurising the sluice 7 for providing a pressure inside the sluice, said pressure being substantially equal to a pressure in the well tubular metal structure 3, and subsequently driving the coiled tubing 1 into the well tubular metal structure by means of the second driving unit 16.
The driving of the coiled tubing 1 into the well tubular metal structure 3 by means of the second driving unit 16 is performed by moving the second driving unit together with the coiled tubing 1 into the well tubular metal structure. The driving of the coiled tubing into the well tubular metal structure by means of the second driving unit 16 is in
By fluid or well fluid is meant any kind of fluid that may be present in oil or gas wells downhole, such as natural gas, oil, oil mud, crude oil, water, etc. By gas is meant any kind of gas composition present in a well, completion, or open hole, and by oil is meant any kind of oil composition, such as crude oil, an oil-containing fluid, etc. Gas, oil, and water fluids may thus all comprise other elements or substances than gas, oil, and/or water, respectively.
By a casing or well tubular metal structure is meant any kind of pipe, tubing, tubular, liner, string etc. used downhole in relation to oil or natural gas production.
The second driving unit 16 may be a downhole tractor having projectable arms having wheels, wherein the wheels contact the inner surface of the casing/well tubular metal structure for propelling the tractor and a tool forward in the casing. A downhole tractor is any kind of driving tool capable of pushing or pulling tools in a well downhole, such as a Well Tractor®.
Although the invention has been described in the above in connection with preferred embodiments of the invention, it will be evident for a person skilled in the art that several modifications are conceivable without departing from the invention as defined by the following claims.
| Number | Date | Country | Kind |
|---|---|---|---|
| 17208706.6 | Dec 2017 | EP | regional |
| 18152553.6 | Jan 2018 | EP | regional |
