System and method for subsea well operation

Abstract

A system for operation on a subsea well, the system comprising at least one storage unit configured to store tubulars; a subsea mast unit comprising at least two string handling devices configured to handle a tubular string of a plurality of connected tubulars, wherein at least one of the string handling devices is configured to move vertically relative to the other of the string handling devices, and is configured to add a vertical downforce to the tubular string; and at least one handling arrangement for moving tubulars between the at least one storage unit and one of the string handling devices simultaneously with handling of the tubular string by at least one of the string handling devices. A method of lowering a tubular string into a subsea well is also provided.

Claims

1. A system for operation on a subsea well, the system comprising: at least one storage unit configured to store tubulars; a subsea mast unit comprising at least two string handling devices configured to handle a tubular string of a plurality of connected tubulars; and at least one handling arrangement for moving tubulars between the at least one storage unit and one of the string handling devices simultaneously with handling of the tubular string by at least one of the string handling devices; wherein each of the string handling devices is configured to move vertically relative to the other of the string handling devices, and is configured to add a vertical downforce to the tubular string; and wherein the vertical downforce is at least 50 kN.

2. The system according to claim 1, wherein each of the at least one storage unit is a subsea storage unit.

3. The system according to claim 1, wherein at least one of the string handling devices is configured to hold, pull and rotate a tubular string.

4. The system according to claim 1, further comprising at least one rack and pinion drive arranged to drive one of the string handling devices vertically.

5. The system according to claim 1, wherein the at least one storage unit and the mast unit are modular.

6. The system according to claim 1, further comprising a modular blow out preventer unit comprising a blow out preventer.

7. The system according to claim 1, further comprising at least one buoyant device for counteracting the weight of the mass of the system under water.

8. The system according to claim 1, wherein the system comprises two storage units and two handling arrangements for moving tubulars between a respective storage unit and one of the string handling devices simultaneously with handling of the tubular string by at least one of the string handling devices.

9. The system according to claim 8, wherein the two storage units are oppositely arranged with respect to the mast unit.

10. The system according to claim 1, wherein the at least one storage unit is configured to store tubulars in a substantially vertical orientation.

11. The system according to claim 1, wherein the system is configured to operate by means of an electrical power supply.

12. The system according to claim 1, further comprising a fluid line for fluid communication with a vessel, and a fluid connection device for establishing a fluid connection between the fluid line and the tubular string.

13. The system according to claim 1, wherein the vertical downforce is at least 100 kN.

14. The system according to claim 1, wherein the vertical downforce is at least 300 kN.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) Further details, advantages and aspects of the present disclosure will become apparent from the following embodiments taken in conjunction with the drawings, wherein:

(2) FIG. 1: schematically represents a side view of a system, a vessel and a production platform;

(3) FIG. 2: schematically represents a perspective view of the system in FIG. 1;

(4) FIG. 3: schematically represents a perspective view of the system in FIGS. 1 and 2 with buoyant devices removed;

(5) FIG. 4: schematically represents a front view of the system in FIG. 3;

(6) FIG. 5: schematically represents a side view of the system in FIGS. 3 and 4; and

(7) FIGS. 6a-6d: schematically represent front views of the system in FIGS. 3-5 in different states.

DETAILED DESCRIPTION

(8) In the following, a system for operation on a subsea well and a method of lowering a tubular string into a subsea well, will be described. The same reference numerals will be used to denote the same or similar structural features.

(9) FIG. 1 schematically represents a side view of one example of a system 10 for operation on a subsea well 12. FIG. 1 further shows a light intervention vessel 14 and a production platform 16. The system 10 is connected to a wellhead assembly 18 on a seabed 20 above a reservoir 22 containing oil or gas. The reservoir 22 may be located at a depth of up to 5000 m below the seabed 20.

(10) The vessel 14 and the production platform 16 float on a surface 24 of the sea 26. The platform 16 may alternatively be standing on the seabed 20 and reach above the surface 24.

(11) In the example in FIG. 1, system 10 is positioned subsea, i.e. in an underwater environment. The system 10 is a remotely operated heavy workover unit for use together with the light intervention vessel 14.

(12) The system 10 in FIG. 1 further comprises an umbilical 28, such as a high-voltage cable, for electrically powering the system 10 from the vessel 14. The system 10 can thus be remotely operated via the umbilical 28. The system 10 in FIG. 1 further comprises a fluid line 30. The fluid line 30 is used for fluid communication between the system 10 and the vessel 14.

(13) The system 10 further comprises a remotely operated vehicle (ROV) 32 for providing assistance to the system 10. FIG. 1 further shows one or more pumps 34 positioned on the vessel 14. The pumps 34 may alternatively be positioned subsea adjacent to the wellhead assembly 18. The vessel 14 of this example further comprises a crane 36, power supply and equipment for well return treatment.

(14) As shown in FIG. 1, the interface between the system 10 on the well 12 and the vessel 14 comprises the umbilical 28 and the fluid line 30. The only assistance by the vessel 14 may be to transport the system 10 to/from the well 12, to electrically power the system 10 through the umbilical 28 and to handle well returns through the fluid line 30. There is no rigid mechanical connection between the vessel 14 and the system 10. The system 10 can for example perform subsea snubbing without the use of a drilling riser.

(15) The production platform 16 may be disconnected from the wellhead assembly 18 prior to installing the system 10. During operation, the vessel 14 assists the system 10 via the fluid line 30, supplies power to the system 10 via the umbilical 28, and performs well return treatment.

(16) FIG. 2 schematically represents a perspective view of the system 10 in FIG. 1.

(17) As shown in FIG. 2, the system 10 comprises a subsea mast unit 38 and two subsea storage units 40a, 40b. Thus, in this example, the system 10 is a subsea system. Each storage unit 40a, 40b is configured to store tubulars 42 in a vertical orientation.

(18) The system 10 comprises a plurality of buoyant devices 44. One buoyant device 44 is connected to each storage unit 40a, 40b and two buoyant devices 44 are connected to the mast unit 38. The buoyant devices 44 counteract the weight of the mass of the system 10 under water by providing a permanent and/or adjustable buoyancy.

(19) The mast unit 38 comprises a stationary base structure 46 and a plurality of rack and pinion drives 48. FIG. 1 further shows two moving devices 50a, 50b of a handling arrangement 52a which is described below.

(20) FIG. 3 schematically represents a perspective view of the system 10 in FIGS. 1 and 2. In FIG. 3, the buoyant devices 44 are removed to improve visibility. FIG. 4 schematically represents a front view of the system 10 in FIG. 3, and FIG. 5 schematically represents a side view of the system 10 in FIGS. 3 and 4.

(21) With collective reference to FIGS. 3-5, the system 10 further comprises a blow out preventer (BOP) 54 provided in a blow out preventer unit 56. Control lines (not illustrated), such as choke, kill and flush lines, may be provided between the vessel 14 and the BOP 54. The height of the system 10 may be 20 m to 30 m, the height of the mast unit 38 may be 15 m to 25 m, the height of each storage unit 40a, 40b may be 8 m to 12 m, and the height of the BOP unit 56 may be 5 m to 10 m. The BOP unit 56 may be connected to the wellhead assembly 18 by means of standard connections of the same type as used when connecting drilling BOP's to wellheads. The connections can be established by the assistance of the ROV 32.

(22) The mast unit 38, the BOP unit 56 and the two storage units 40a, 40b form four modules. The system 10 can be transported in modules on the vessel 14 to the location. The modules can then be lowered from the vessel 14 to the well 12 with the crane 36 and installed to the wellhead assembly 18.

(23) By means of the buoyant devices 44, the system 10 can be put on the wellhead assembly 18 with light force, either by lowering the entire system 10 after being assembled just below the surface 24, or by sequentially lowering and installing the BOP unit 56, the mast unit 38 and the storage units 40a, 40b one by one. In any case, the lowering may be carried out by means of the crane 36.

(24) Once the storage units 40a, 40b have been lowered to the well 12, no handling of tubulars 42 takes place on the vessel 14. Thereby, the need for a wave compensation system onboard the vessel 14 can be avoided.

(25) FIGS. 3-5 further show a tubular string 58 comprising a plurality of connected tubulars 42. The length of each tubular 42 may for example be 8 to 12 meters, such as approximately 10 meters. The ends of each tubular 42 may be threaded to be threadingly engaged with an adjacent tubular 42 or an intermediate joint member.

(26) FIGS. 3-5 shows that the system 10 of this example comprises two handling arrangements 52a, 52b. Each handling arrangement 52a, 52b is associated with one storage unit 40a, 40b. Four moving devices 50 are provided in the mast unit 38, two on each side of the tubular string 58. The handling arrangement 52a comprises three moving devices 50a, 50b, 50c and the handling arrangement 52b comprises three moving devices 50d, 50e, 50f (each moving device 50a-f may also be referred to with reference numeral “50”). Each moving device 50 comprises a gripping mechanism (not denoted) for gripping a tubular 42.

(27) The system 10 of this example further comprises two string handling devices 60a, 60b. The string handling devices 60a, 60b are provided in the mast unit 38. The string handling devices 60a, 60b are configured to handle the tubular string 58. Each string handling devices 60a, 60b is independently drivable vertically up and down along the base structure 46 by the rack and pinion drives 48. By means of the rack and pinion drives 48, each string handling device 60a, 60b can move vertically up and down and can apply a vertical downforce and a vertical upforce to the tubular string 58.

(28) Each handling arrangement 52a, 52b is configured to move tubulars 42 between the associated storage unit 40a, 40b and one of the string handling devices 60a, 60b, i.e. to the well center over the center line of the tubular string 58.

(29) The moving devices 50c, 50f associated with a respective storage unit 40a, 40b are configured to move tubulars 42 generally laterally between storage positions within the respective storage unit 40a, 40b and a handover position outside each storage unit 40a, 40b. At the handover position of each storage unit 40a, 40b, the tubular 42 can be handed over to (or received from) one of the moving devices 50a, 50b, 50d, 50e of the mast unit 38.

(30) Each storage unit 40a, 40b may comprise a fingerboard at the bottom with a plurality of upright fingers (not shown). The tubulars 42 can be held stably by being positioned over a respective finger.

(31) The moving devices 50a, 50b are configured to receive (and vice versa) tubulars 42 from the moving device 50c at the handover position outside the storage unit 40a. The moving devices 50d, 50e are configured to receive (and vice versa) tubulars 42 from the moving device 50f at the handover position outside the storage unit vb. The moving devices 50a, 50b, 50d, 50e can move tubulars 42 vertically upwards from the handover position and then laterally towards the tubular string 58.

(32) FIGS. 3-5 further show that the system 10 comprises two fluid connection devices 62a, 62b. One of the fluid connection devices 62a, 62b can be connected to the fluid line 30 and connected on top of one of the string handling device 60a, 60b. In this example, one of the fluid connection devices 62a, 62b serves as backup. In FIGS. 3-5, the fluid connection devices 62a, 62b are in a standby position outside the well center.

(33) Once the system 10 has been installed on the well 12, preparations such as pressure testing of the system 10 may be carried out. When the preparations are complete, the operations of the system 10 will start. Since the vessel 14 comprises the pumps 34 and the necessary equipment for well return treatment, assistance by the production platform 16 is not needed, which is of great advantage.

(34) A bottom hole assembly (BHA, not shown) is lowered through the BOP 54 while the well pressure is sealed off. Once the BHA is through the BOP 54, an annular will seal off the well pressure while snubbing (i.e. pushing) the tubular string 58 into the well 12.

(35) FIGS. 6a-6d schematically represent front views of the system 10 in FIGS. 3-5 in different states when the tubular string 58 is snubbed or tripped in to the well 12, e.g. for intervention work.

(36) In FIG. 6a, the moving device 50a is moving down for grabbing a tubular 42 at a handover position outside the storage unit 40a. The moving devices 50d, 50e are positioned in a pick-up/delivery position over the well center. A tubular 42 delivered by the moving devices 50d, 50e has been screwed onto the tubular string 58 by rotation of the upper string handling device 60a. To this end, one or each string handling device 60a, 60b may comprise a screwing device.

(37) The lower string handling device 60b has released its grip of the tubular string 58 and moves upwards. The upper string handling device 60a clamps around the tubular string 58 and applies a vertical downforce 64 to the tubular string 58. The tubular string 58 is thereby snubbed into the well 12 against the pressure of the reservoir 22. The moving devices 50 of the handling arrangements 52a, 52b thus operate simultaneously with the string handling devices 60a, 60b.

(38) In FIG. 6b, the moving device 50a has gripped a tubular 42 at the handover position outside the storage unit 40a. The moving device 50d has gripped the top of the tubular string 58. The moving device 50e has released its grip on the tubular string 58. The upper string handling device 60a continues to push the tubular string 58 downwards and the lower string handling device 60b continues to move upwards along the tubular string 58.

(39) In FIG. 6c, the moving devices 50a, 50b lift a tubular 42 vertically from the storage unit 40a. The moving device 50d moves down together with the tubular string 58 while gripping the tubular string 58. The moving device 50e moves down towards the handover position outside the storage unit vb. The lower string handling device 60b grips the tubular string 58. After this, the upper string handling device 60a releases its grip on the tubular string 58. The snubbing is thereby continued without interruption by the addition of the vertical downforce 64 by means of the lower string handling device 60b.

(40) In FIG. 6d, the moving devices 50a, 50b have reached the top of the mast unit 38 and will initiate lateral movement of the tubular 42 into the well center on top of the tubular string 58. The moving device 50d has moved further down while gripping the tubular string 58 but will soon release its grip. The moving device 50e has reached the handover position outside the storage unit vb. The upper string handling device 60a has moved further upwards along the tubular string 58. The lower string handling device 60b has snubbed the tubular string 58 further down into the well 12.

(41) The two handling arrangements 52a, 52b thus move tubulars 42 from the respective storage units 40a, 40b to the tubular string 58. Each tubular 42 is vertically oriented all the way from the storage unit 40a, 40b to the tubular string 58. The tubulars 42 are moved by the handling arrangements 52a, 52b from two sides of the mast unit 38. This increases speed of the tripping and provides redundancy.

(42) Since the string handling devices 60a, 60b are always positioned over the well center during operation of the system 10, i.e. over the BOP 54, the snubbing does not have to be interrupted for collecting tubulars 42 by means of the string handling devices 60a, 60b. Rather, the string handling devices 60a, 60b and the handling arrangements 52a, 52b work in parallel. This enables continuous, or substantially continuous, snubbing.

(43) In normal drilling into the well 12 by means of the production platform 16, there is typically a large vertical downforce due to the weight of the long drill string from the surface 24 and into the well 12. This weight of the drill string overcomes the vertical upforce on the drill string from the reservoir pressure.

(44) Since the system 10 is positioned on the seabed 20, the weight of the tubular string 58 is relatively low and many times insufficient to overcome the vertical upforce on the tubular string 58 from the reservoir pressure. However, since each string handling device 60a, 60b is configured to add a vertical downforce 64 to the tubular string 58, subsea snubbing into the well 12 is enabled.

(45) During the lowering of the tubular string 58 into the well 12, the reservoir pressure initially generates a great upward force on the tubular string 58. At least one of the string handling devices 60a, 60b overcomes this force from the reservoir pressure by adding a vertical downforce 64 to the tubular string 58. The fluid connection devices 62a, 62b remain in the standby position during the lowering of the tubular string 58.

(46) Since each string handling device 60a, 60b is vertically movable and can add a vertical downforce 64 to the tubular string 58, the lowering of the tubular string 58 can be continuous, or substantially continuous. The system 10 can for example provide a tripping speed of 900 m/hour. Thereby, the system 10 enables subsea snubbing with the same speed as prior art coil tubing technologies, but also avoids disadvantages with coil tubing, for example buckling.

(47) As the lowering of the tubular string 58 continues, the weight of the tubular string 58 will increase as further tubulars 42 are connected to the tubular string 58. The weight of the tubular string 58 will eventually overcome the vertical upforce on the tubular string 58 from the reservoir pressure. This state may be referred to as a tubular string float state.

(48) When the tubular string 58 is lowered further after having reached the tubular string float state, the slip bowls of the string handling devices 60a, 60b will add a vertical upforce to (i.e. hold the weight of) the tubular string 58 instead of pushing the tubular string 58.

(49) The tubular string 58 may be lowered to a problem area in the well 12 without adding any flow or pressurized fluid inside the tubular string 58. The problem area may be an area where sand and salt has stopped oil or gas production, e.g. by clogging perforations. When the BHA with intervention tools has reached the depth of the problem area, the lowering of the tubular string 58 is stopped and preparations for the intervention will start. One of the fluid connection devices 62a, 62b is connected on top of the upper string handling device 60a. This connection is handled by the mast unit 38.

(50) The upper string handling device 60a is then operated as a topdrive and rotates the tubular string 58. At the same time, the pumps 34 on the vessel 14 is driven to pump salt water from the sea 26, through the fluid line 30 and through the tubular string 58 in order to clean the problem area from sand. This operation corresponds to a normal drilling operation but with pumped water instead of drilling mud.

(51) During the intervention, the fluid connection device 62a is connected on top of the string handling device 60a. If a further tubular 42 needs to be added to the tubular string 58, the fluid connection device 62a is moved laterally out of the well center, the further tubular 42 is lifted into the well center and attached to the tubular string 58, the string handling device 60a is moved upwards to the top of the further tubular 42, and the fluid connection device 62a is then again connected on top of the string handling device 60a.

(52) Alternatively, the further tubular 42 can be connected to the tubular string 58 between the two string handling devices 60a, 60b. In this case, the system 10 may comprise a third string handling device (not shown) below the two string handling devices 60a, 60b for holding the tubular string 58 when the upper string handling device 60a make up the connection between the further tubular 42 and the fluid connection device 62a and the lower string handling device 60b make up the connection between the further tubular 42 and the tubular string 58.

(53) In any case, the fluid connection device 62a on top of the string handling device 60a can maintain a fluid connection between the tubular string 58 and the fluid line 30 while the tubular string 58 is rotated.

(54) An inspection of the well 12 may then be carried out in order to see if the intervention has been successful or if any additional intervention operation is needed. The same intervention may be performed again, or a different intervention may be performed, for example by perforating the well with explosives in order to establish new channels for flow of gas or oil.

(55) After completion of the intervention, the tubular string 58 is tripped out from the well 12. The procedure of tripping out the tubular string 58 may be reverse, or substantially reverse, to the trip-in procedure. The tubular string 58 is thus broken up and tubulars 42 are stored in the storage units 40a, 40b.

(56) The system 10 can finally be disconnected from the wellhead assembly 18. The system 10 can be lifted back onto the vessel 14, either as one single unit or as separate units, and transported to another location. Alternatively, the system 10 can be suspended from the vessel 14 below the surface 24 and in this submerged state be transported to the next location, e.g. if the next location is relatively close.

(57) The well returns transported through the fluid line 30 to the vessel 14 are cleaned onboard the vessel 14. Thus, together with the surface utilities from the vessel 14 provided through the umbilical 28 and the fluid line 30, the system 10 can repair and optimize the well 12 without any assistance from the production platform 16 and with low or little environmental impact. After the workover, the subsea well 12 ready for increased production can be handed over to the production platform 16.

(58) With the snubbing and wireline capabilities, the system 10 provides a flexible and cost-effective alternative for keeping the well 12 at maximum production. Due to the subsea operation of the system 10, with assistance from the vessel 14 only through the umbilical 28 and the fluid line 30, it is possible to carry out operations on the well 12 with minimum influence by weather conditions. For example, the light vessel 14 does not require a wave compensation system. The repeated connection of rigid tubulars 42 to the tubular string 58 reduces the risk for buckling of the tubular string 58. Problem areas deeper into the well 12 can thereby be reached. Furthermore, the need to control bending cycles, as in coil tubing, can be avoided.

(59) While the present disclosure has been described with reference to exemplary embodiments, it will be appreciated that the present invention is not limited to what has been described above. For example, it will be appreciated that the dimensions of the parts may be varied as needed. Accordingly, it is intended that the present invention may be limited only by the scope of the claims appended hereto.