Method of operating a subsea coiled tubing injector, and related apparatus and control device

Abstract

A method of operating a subsea coiled tubing injector with coiled tubing disposed therethrough, a subsea control device, and apparatus for controlling a coiled tubing assembly extending into a subsea well are described In various examples, the subsea control device is disposed underwater at, on, or near the subsea coiled tubing injector and the method includes using the subsea control device to control the injector, applying a downward force to the coiled tubing using the injector, dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly.

Description

[0001] METHOD OF OPERATING A SUBSEA COILED TUBING INJECTOR, AND RELATED APPARATUS AND CONTROL DEVICE

[0002] The present invention relates to the operation of subsea coiled tubing injectors, and in particular to the application of downward force to the coiled tubing using a subsea coiled tubing injector.

[0003] In connection with riserless subsea well operations, coiled tubing extends through sea from a surface vessel into a subsea well. A coiled tubing assembly comprising coiled tubing and one or more tools on an end thereof is typically run into and out of the well using a heave compensated topsides coiled tubing injector on the surface vessel and a subsea coiled tubing injector located near the entrance to the subsea wellhead at the seabed. The coiled tubing extends through both the topsides and subsea injectors which are controlled to cooperate to run the coiled tubing downward for deployment into the well or upward for retrieval out of the well. A brake can be applied in the subsea injector to grip the coiled tubing. In this system, imperfections in the heave compensation of the topsides coiled tubing injector can result in the coiled tubing experiencing variations in load or tension. This can cause significant strain and fatigue in the material of the coiled tubing. Similarly, parts of the subsea injector in engagement with the coiled tubing can be detrimentally affected by the variations in load.

[0004] According to a first aspect of the invention there is provided a method of operating a subsea coiled tubing injector with coiled tubing disposed therethrough, a coiled tubing assembly extending into a subsea well, the method comprising: using a subsea control device to control the injector, applying a downward force to the coiled tubing using the injector, dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly.

[0005] The applying of the downward force may be further dependent upon the well pressure acting upward on the coiled tubing assembly. The method may further comprise providing a model for the downward force, and the applying of the downward force may be based on the model. The model may be a constant tension or planned tension model or may comprise a constant tension or planned tension component. The model may be a model for the downward force dependent upon any of: the length extent of the coiled tubing assembly in the well; the weight of the inserted length of the coiled tubing assembly; and the well pressure acting upward on the coiled tubing assembly. The model may be a model for varying the downward force in accordance with the variation in weight of the length of the coiled tubing assembly, or the variation in length extent of the coiled tubing assembly in the well, as the coiled tubing assembly is moved downward or moved upward along the wellbore. The model may be a compensation model for applying the downward force to compensate for variation in the tension or load of the coiled tubing assembly as the coiled tubing assembly is moved downward or moved upward along the wellbore. The model may comprise: a first part for a first range of positions along the well for the downward force applied by the injector to vary with the variation in weight of the length of the coiled tubing assembly, or the variation in length extent of the coiled tubing assembly in the well, as the coiled tubing assembly is moved downward or moved upward along the wellbore; and a second part for a second range of positions further downward or downhole along the well than the first range of positions, the second range of positions being positions of further insertion and further length extent of the coiled tubing assembly in the well, for the downward force with the further insertion in the second range of positions not to vary in dependence upon the weight of the length of the coiled tubing assembly or the variation in length extent of the coiled tubing assembly in the well. In the second range of positions, the applying of the downward force may comprise applying a downward force to compensate for load or tension variations from heave motion.

[0006] The method may further comprise detecting a load imparted from the coiled tubing or a tension of the coiled tubing. The using of the subsea control device to control the injector may include applying downward force based on the detected load or tension. The using of the subsea control device to control the injector may include applying downward force to the coiled tubing to compensate for variation in load imparted from the coiled tubing or tension of the coiled tubing. The variation in load or tension may comprise variation from heave motion.

[0007] The method may further comprise determining, e.g. detecting or estimating, any one or more of: the well pressure; the length extent of the coiled tubing assembly in the well; the weight of the inserted length of the coiled tubing assembly. The method may further comprise applying the downward force using or based upon any one or more of the determined well pressure, determined length extent, or determined weight.

[0008] The method may further comprise determining the downward force to be applied from the injector. The applying of the downward force may comprise applying the determined downward force. The determining of the downward force may comprise determining the downward force to be applied using any one or more of: the well pressure; the length extent of the coiled tubing assembly in the well; the weight of the inserted length of the coiled tubing assembly; the load from or tension of the coiled tubing assembly.

[0009] The applying of downward force may comprise communicating one or more instructions from the control device to one or more operational components of the injector.

[0010] The method may include controlling the injector to obtain or approximate a constant load or tension or a planned load or tension of the coiled tubing assembly over at least a range of positions upon advancing the coiled tubing assembly downward or upward in the well.

[0011] The control device may be disposed underwater at, on, or near the subsea injector.

[0012] The applying of the downward force to the coiled tubing may comprise adjusting any of: chain tension; traction force; and motor power. According to a second aspect of the invention, there is provided a subsea control device for controlling a subsea coiled tubing injector in a system for operating a coiled tubing assembly extending into a subsea well, the coiled tubing assembly including coiled tubing disposed through the injector, the control device being configured to produce one or more instructions for operating the subsea coiled tubing injector to apply a downward force to the coiled tubing dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly.

[0013] The subsea control device may comprise any one or more of: an input unit for receiving data from one or more detection means; a storage unit for storing either or both: one or more computer programs; detection data; and a model for the downward force dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly; a processor unit for either or both processing sensor data and executing one or more computer programs to determine, using or based on the model, instructions for applying the downward force to the coiled tubing; an output unit for outputting instructions to one or more components of the injector to apply the downward force. The subsea control device may comprise a determiner unit for determining the downward force to be applied.

[0014] According to a third aspect of the invention, there is provided apparatus for operating a coiled tubing assembly extending into a subsea well, the coiled tubing assembly including coiled tubing, the apparatus comprising: a subsea coiled tubing injector for applying downward force to the coiled tubing; and a subsea control device for controlling the injector to apply downward force to the coiled tubing dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly.

[0015] The subsea control device may be configured to be arranged underwater at, on, or near the subsea coiled tubing injector. The apparatus may further comprise at least one pressure sensor for determining the well pressure. The apparatus may further comprise at least one load detector for determining the load or tension of the coiled tubing assembly. The apparatus may further comprise at least one depth counter detector for detecting the extent of insertion of the coiled tubing assembly.

[0016] The subsea control device may have: an input for receiving any one or more of data from at least one pressure sensor, at least one load detector, at least one depth counter; a determiner for determining the downhole force to be applied and / or injector head control instructions, based on the input data and a model for the downhole force dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly; and an output for outputting the instructions to the injector.

[0017] Typically, the subsea coiled tubing injector comprises: a passageway for coiled tubing through the coiled tubing injector; and at least one coiled tubing engager device arranged adjacent to the passageway and configured to rotate in contact with an outer surface of the coiled tubing to move the coiled tubing through the coiled tubing injector and exert the downward force.

[0018] The subsea coiled tubing injector may further comprise: at least one traction member configured to push or vary a contact portion of the engager device transverse to the passageway and toward the outer surface of the coiled tubing for varying the traction against the coiled tubing and adjusting the downward force.

[0019] The engager device may comprise a chain or belt extending between first and second members along the passageway. The coiled tubing injector comprises at least one tensioner for tensioning the chain or belt between the first and second members and adjusting the downward force. The engager device may comprise a drive wheel rotatably mounted on a support member.

[0020] The subsea coiled tubing injector may further comprise at least one motor for rotating the at least one engager device and adjusting the downward force. Embodiments may be advantageous in that the downward force applied to the coiled tubing can be controlled to desired or near desired values. This in turn may reduce exposure of coiled tubing to variations in loading and / or tension. The downward force may be applied, e.g. according to a model, to achieve an intended constant tension or load on the coiled tubing and the coiled tubing injector or part thereof. If unexpected variations in load or tension arise, e.g., due to inaccurate heave compensation at surface or fluctuations in well pressure, the subsea control device can automatically operate to vary the downward force to compensate for or prevent such variations affecting the tension or load on the coiled tubing. Therefore, cyclic tensioning effects may be reduced and longevity of the coiled tubing may be improved.

[0021] Any of the various aspects of the invention may have one or more further features as described in relation to any other aspect of the invention wherever described herein.

[0022] There will now be described, by way of example only, embodiments of the invention with reference to the accompanying drawings, in which:

[0023] Figure 1 is an overview representation of a coiled tubing deployment system;

[0024] Figure 2 is a flow diagram of steps in a method of controlling the subsea coiled tubing injector of the system of Figure 1 ;

[0025] Figure 3 is model for injector-applied downward force against depth; and

[0026] Figure 4 is a schematic representation of apparatus including the subsea coiled tubing injector and the control device for controlling the coiled tubing injector.

[0027] With reference to Figure 1 , a coiled tubing deployment system 1 is generally depicted. The system 1 can be provided for deployment of coiled tubing from a floating vessel or other floating platform (not shown) at the sea surface with various topsides equipment 2 arranged on the vessel. The topsides equipment includes coiled tubing reel 11 , topsides coiled tubing injector 12, gooseneck 13, topsides funnel 14, and suspension system 15. The suspension system 15 in this case comprises a passive heave compensator 16 which is suspended on hoist line 17 which in turn is passed over a support on a handling tower (not shown) of the vessel. The passive heave compensator 16 is connected to the topsides coiled tubing injector 12 through connecting members 18. As the vessel heaves, the passive heave compensator 16 extends and / or an active heave compensator spools the hoist line 17 in / out for allowing the topsides coiled tubing injector 12 to move up or down along the handling tower relative to the vessel to maintain its position spatially, e.g. relative to seabed, despite the heave motion of the vessel. The suspended topsides coiled tubing injector 12 is typically arranged above a moon pool of the vessel. Coiled tubing 10 is spooled from the reel 11 and is passed over the gooseneck 13 and through the topsides coiled tubing injector 12. A hydraulic power unit 19 is provided for operating the topsides injector 12.

[0028] The coiled tubing 10 extends through the topsides coiled tubing injector 12 and the topsides bend restrictor funnel 14 and into the sea toward and through subsea equipment 3 into the subsea well 4.

[0029] The well 4 includes subsea wellhead 5 upon which is provided subsea equipment 3, which in upward succession from the wellhead 5 includes well control package 6, lubricator 8, and subsea stripper 9. The lubricator 8 has an interior which is openable and closable to well pressure by upper and lower valves. The lubricator 8 is used for accommodating one or more tools 101 on the end of the coiled tubing 10 therein. The lubricator 8 provides for sluicing the one or more tools 101 into and out of the wellbore 4w. The subsea stripper 9 is connected to an upper end of the lubricators and is used for sealing around the coiled tubing 10 and against the interior of the lubricator 8, including against the pressure from the wellbore 4w to which the interior of the lubricator 8 is exposed when using the one or more tools 101 in the well. The subsea coiled tubing injector 32 is disposed above the subsea stripper 9. As can be seen in Figure 1 , the coiled tubing 10 in the sea passes through the subsea coiled tubing injector 32 and then through the various units on the subsea well 4, into the wellbore 4w of the well. The wellbore 4w comprises a high-pressure region, generally increasing in pressure with well depth. Coiled tubing assembly 1001 extending into the well 4 includes the one or more tools 101 and the inserted length 10i of coiled tubing. The subsea coiled tubing injector 32 and the topsides coiled tubing injector are together used to run the coiled tubing 10 into the well or out of the well.

[0030] As the coiled tubing assembly 1001 extends into the well 4 and along wellbore 4w, the length extent and weight of the inserted coiled tubing assembly 1001 in the wellbore varies, i.e. it increases with depth or length along the wellbore. The well pressure acts against the coiled tubing assembly 1001 in the well tending to push the coiled tubing assembly 1001 out of the well. The subsea coiled tubing injector 32 is used to apply downward force to the coiled tubing varying inversely with the length extent and weight of the inserted coiled tubing assembly 1001 in the wellbore, i.e. downward force reduces with depth or length along the wellbore, although this is typically reduced downward with depth to no less than a predefined minimum downward force. The coiled tubing injector 32 is controlled to apply a downward force to the coiled tubing 10 depending upon the weight and / or insertion extent of the coiled tubing assembly 1001. The coiled tubing assembly 1001 can thus be controlled so the load or tension of the coiled tubing assembly 1001 or coiled tubing 10i is constant or controlled to planned values of tension or load during operations. This can be useful for reducing strain, wear and / or damage to coiled tubing.

[0031] The subsea coiled tubing injector 32 includes a passageway 33 for coiled tubing 10 through the coiled tubing injector. In addition, the coiled tubing injector 32 includes two coiled tubing engager devices 34 each arranged adjacent to the passageway 33 on opposite sides of the passageway. The engager device 34 has an endless chain or belt 35 that is arranged upon and extends between first and second rotary members 36a, 36b along the passageway. A tensioner 37 is provided for tensioning the chain or belt. The tensioner 37 acts upon the second rotary member 36b and moves this away from the first rotary member 36a along the passageway for varying the tension of the chain or belt between the first and second members. The first rotary member 36a is further connected to a motor 38 for driving the rotation of the rotary member 36a and thereby also driving the chain or belt. The section of the belt or chain facing the passageway 33 is arranged in contact with the outer surface of the coiled tubing 10. The belt or chain section provides traction against the coiled tubing. Traction members 39 are configured to push the contacting portion of the belt or chain transverse to the passageway 33 and toward the outer surface of the coiled tubing for obtaining or varying desired traction against the coiled tubing.

[0032] Through the pushing force of the traction member 39, the tensioning of the belt or chain by the tensioner 37, and / or the drive force of the motor 38 the subsea coiled tubing injector 32 can provide traction and adjustably apply downward force to the coiled tubing, i.e. toward downhole.

[0033] The belt or chain 35 can rotate in contact with an outer surface of the coiled tubing to move the coiled tubing through the coiled tubing injector. Rotation in the sense of arrows A urges the coiled tubing toward the well. Rotation in the opposite sense can be used to facilitate movement of the coiled tubing out of the well.

[0034] The downward force exerted upon the coiled tubing 10 by the subsea coiled tubing injector 32 is controlled during the operation of the coiled tubing assembly 1001 within the subsea well 4 and / or during the insertion and / or retrieval of the coiled tubing assembly into or from the well. It can in that regard also be appreciated that when coiled tubing 10 is being run out of the well 4, the subsea coiled tubing injector 32 can be applied simultaneously to exert downward force. Nonetheless, the downward force applied by the subsea coiled tubing injector 32 is important and can be used as can be appreciated to attain a desired tension or load behaviour of the coiled tubing under operations and under run-in or run-out that also can compensate for unexpected load or tension variation events.

[0035] To this end, the system also includes a load or tension detector for detecting the load or tension of the coiled tubing and using the detected load or tension in the controlling of the coiled tubing to apply the downward force. The system also includes a pressure sensor detecting well pressure. The system also includes a depth counter for detecting the extent of insertion and / or length extent of the inserted coiled tubing assembly 1001 in the well. The system 1 is also provided with a model for the downward force dependent upon the length extent of the coiled tubing assembly in the well and / or the weight of the inserted length of the coiled tubing assembly and / or the well pressure. The coiled tubing injector 32 is controllable in accordance with the model. Through measurement of the load and / or tension also spurious variations in the load, e.g. due to heave motions, e.g. due to imperfect compensation topsides, can be removed or reduced or compensated for and not just the variation or increase in weight and length of the inserted length with depth. Through determination of the pressure and / or weight of the inserted length and / or the length extent in the well appropriate values of the for the downward force may be obtained for compliance with the model and / or intended behaviour in terms of load and / or tension etc.

[0036] Figure 2 illustrates a method 1000 of operating the subsea coiled tubing injector 32 with coiled tubing 10 disposed therethrough, the coiled tubing assembly 1001 extending into the subsea well 4. The method comprises steps S1 to S4.

[0037] At S1 , a control device is provided for controlling the subsea injector. The control device is arranged subsea at near or on the subsea injector, facilitating speed of control and response. For example, the control device is incorporated in a control module which is physically attached to the structure of the injector.

[0038] At S2, the well pressure and / or the weight of the inserted length and / or the length extent in the well is determined. A pressure sensor is used to monitor well pressure. A depth counter is used to monitor the amount of insertion of the coiled tubing assembly. Using the known geometry of the inserted equipment, the weight of the inserted length can be determined.

[0039] At S3, a model is provided for the downward force. The downward force to be applied using the subsea injector is determined in accordance with the model, and control instructions are produced accordingly. The downward force to be applied is further determined for removing varying load and / or tension components in the coiled tubing resulting for example from motions of heave, such components as may be monitored using load or tension detector, e.g. a load cell on the coiled tubing injector. At S4, instructions are sent to operating parts of the subsea injector, which are adjusted to apply the downward force, according to the instructions. The steps are repeated on an ongoing basis depending on the detected position of the coiled tubing assembly, i.e. extent or weight of inserted length of the coiled tubing assembly in the well, and / or the detected load. Through removing load variation components due to heave, cyclic loading of the coiled tubing can be reduced. Furthermore, through application of downward force to the coiled tubing using the injector, the loading of the coiled tubing is controlled to desired values or pattern, e.g. constant or controllably varied, dependent upon the extent or weight of the inserted length of the coiled tubing for example to counter the effect of increasing load with increasing length or weight in well over at least a certain range of distance in the well.

[0040] Figure 3 illustrates an example model for the downward force for the coiled tubing injector dependent upon the length extent of the coiled tubing assembly in the well and / or the weight of the inserted length of the coiled tubing assembly and / or the well pressure. The model is in the form of graph 500 of force versus extent of insertion of the coiled tubing into the well, including a curve 520 which shows the desired downward force to be applied to the coiled tubing using the subsea injector 32 versus the depth of insertion of the coiled tubing assembly 1001. The downward force in practice applied from the injector 32 may be adjusted to account for possible detected variations in load or tension in the coiled tubing 10 e.g. from heave motions. The curve 530 illustrates the weight of the inserted length of coiled tubing assembly 1001 extending from the subsea injector. As the coiled tubing assembly 1001 is inserted further into the well, the length of the coiled tubing assembly 1001 from the subsea coiled tubing injector 32 becomes greater, and the weight of the coiled tubing assembly 1001 increases. Therefore, the weight of the coiled tubing assembly 1001 contributes increasingly with depth against the upward well pressure, and the downward force thus required from the subsea coiled injector 32 is therefore correspondingly (see curve 520) reduced so that the load or tension is maintained constant in this part of the graph.

[0041] The model of Figure 3 can be considered to have two main components 501 , 502. The first component is applicable over a first range of insertion depths in the well and the second is applicable over a second range of insertion depths, which are depths of insertion further downhole along the well than the first range of depths. The model over the first range of depths provides as described above for the downward force applied by the injector to be varied dependent upon the length extent of the coiled tubing assembly in the well and / or the weight of the inserted length of the coiled tubing assembly. However, the model also defines a minimum downward force indicated by curve 540. At point P onwards, the downward force is reduced to near or equal to the minimum downward force 540. Thus, the model over the second range of depths provides that the downward force applied by the injector (curve 520) with the further insertion in the second range of positions does not to vary in dependence upon the weight of the length of the coiled tubing assembly and / or the variation in length extent of the coiled tubing assembly in the well, and in the second range of positions of component 502 of the model, the applying of the downward force comprises applying a downward force to compensate for load or tension variations from heave motion. The downward force from the injector does not fall below the minimum downward force, and in component 501 is ramped down toward the minimum downward force at point P from initial values far exceeding that.

[0042] A theoretical required downward force can be defined which is equal to the force generated by the pressure in the well acting on the coiled tubing diametrical cross section. The force of well pressure will try to expel the coiled tubing assembly out of the well. The theoretical required downward force can be calculated using the coiled tubing diameter cross sectional area multiplied by the maximum expected wellhead shut in pressure. The minimum downward force is a safety margin downward force above the theoretical required force. The downward force from the injector is not less than the minimum downward force. A maximum downward force to be applied by the injector can be defined equal to the theoretical downward force plus the minimum downward force, as indicated by the curve 520 of the downward force of the subsea injector of part 501 of the model. The weight of the coiled tubing assembly 1001 in the well in effect reduces / increases the acting maximum downward force that the subsea injector 34 applies to the coiled tubing. The adjustment to the injector, e.g. to adjust the chain tension and traction pressure, is automatic through the control of the control device 50, 600.

[0043] It can be appreciated in this model that the load or tension in the coiled tubing in the first part 501 of the model can be maintained substantially constant through the adjustment to the downhole force from the injector as the length extent and weight of the coiled tubing assembly increases into the well. In variants, other models can be used for the downward force for example according to other desired load / tension behaviour sought for the coiled tubing. The curve 520 in other examples can be another curve of desired and / or predefined form. Such other models may provide for smooth increases or decreases in tension, for example whereby cyclic or sudden changes in tension or load occur. It can further be appreciated that the model in practice can be provided in many forms, e.g. mathematical relationships, functions, look up tables, or the like. The model may in certain variants be updatable or adjusted during operations.

[0044] Figure 4 shows apparatus 2000 including an example subsea control device 600 arranged on or near the subsea coiled tubing injector 32. The subsea control device 600 is provided in practice in a subsea control module 50. The subsea control device 600 is used for controlling the subsea coiled tubing injector 32. The control device 600 has an input unit 601 for receiving load data from load sensor 304 and insertion extent data from depth counter 305. The load sensor 304 is used for monitoring the load or tension of the coiled tubing 10 passed through the injector 32. The depth counter 305 is used for detecting the extent of insertion of the coiled tubing assembly 1001 in the well. For example, a depth count of 100 units could indicate that the coiled tubing extends to a depth of 100 m in the well, such that the length and weight of the inserted coiled tubing assembly can be determined. The controller 600 further includes a memory unit 602 used for storing: detection data, parameter or system data, a model for the downhole force, one or more computer programs for determining the downward force using a model for the downhole force. The control device 600 further includes a determiner 603 comprising a microprocessor for processing the data and / or executing the one or more computer programs and / or determining the downward force to be applied by the injector to the coiled tubing assembly and / or producing one or more instructions for operating one or more operational components 306 of the injector, e.g. motor, tensioner, etc., for producing the appropriate downward force based on the model and the detection data. The control device 600 further includes an output unit 604 for outputting the instructions for the operational components 306. The instructions are communicated to the operational components 306 which then apply the downward force to the coiled tubing in the injector 32. The instructions provide for example the change to operating settings of the components of the injector to achieve the desired downward force in accordance with the model and / or to compensate for variations in load or tension such as coming about from heave motion due to imperfections in heave compensation topsides.

Claims

CLAIMS1 . A method of operating a subsea coiled tubing injector with coiled tubing disposed therethrough, a coiled tubing assembly extending into a subsea well, the method comprising: using a subsea control device to control the injector, applying a downward force to the coiled tubing using the injector, dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly.

2. A method as claimed in claim 1 , wherein the applying of the downward force is further dependent upon the well pressure acting upward on the coiled tubing assembly.

3. A method as claimed in claim 1 or 2, which further comprises providing a model for the downward force, the applying of the downward force being based on the model.

4. A method as claimed in claim 3, wherein the model is a constant tension or planned tension model or comprises a constant tension or planned tension component.

5. A method as claimed in claim 3 or 4, wherein the model is a model for the downward force dependent upon any of: the length extent of the coiled tubing assembly in the well; the weight of the inserted length of the coiled tubing assembly; and the well pressure acting upward on the coiled tubing assembly.

6. A method as claimed in any of claims 3 to 5, wherein the model is a model for varying the downward force applied by the injector with the variation in weight of the length of the coiled tubing assembly, or the variation in length extent of the coiled tubing assembly in the well, as the coiled tubing assembly is moved downward or moved upward along the wellbore.

7. A method as claimed in any of claims 3 to 6, wherein the model is a compensation model for applying the downward force to compensate forvariation in the tension or load of the coiled tubing assembly as the coiled tubing assembly is moved downward or moved upward along the wellbore.

8. A method as claimed in any of claims 3 to 7, wherein the model comprises: a first part for a first range of positions along the well for the downward force applied by the injector to vary with the variation in weight of the length of the coiled tubing assembly, or the variation in length extent of the coiled tubing assembly in the well, as the coiled tubing assembly is moved downward or moved upward along the wellbore; and a second part for a second range of positions further downward along the well than the first range of positions, the second range of positions being positions of further insertion and further length extent of the coiled tubing assembly in the well, for the downward force with the further insertion in the second range of positions not to vary in dependence upon the weight of the length of the coiled tubing assembly or the variation in length extent of the coiled tubing assembly in the well; and wherein in the second range of positions, the applying of the downward force comprises applying a downward force to compensate for load or tension variations from heave motion.

9. A method as claimed in any preceding claim, which further comprises detecting a load imparted from the coiled tubing or a tension of the coiled tubing, and the using of the subsea control device to control the injector includes applying downward force based on the detected load or tension.

10. A method as claimed in any preceding claim, wherein the using of the subsea control device to control the injector includes applying downward force to the coiled tubing to compensate for variation in load imparted from the coiled tubing or tension of the coiled tubing.11 . A method as claimed in claim 10, which the variation in load or tension comprises variation from heave motion.

12. A method as claimed in any preceding claim, which further comprises determining, e.g. detecting or estimating, any one or more of: the well pressure; the length extent of the coiled tubing assembly in the well; the weight of the inserted length of the coiled tubing assembly, and applying the downward force using or based upon any one or more of the determined well pressure, determined length extent, or determined weight.

13. A method as claimed in any preceding claim, which further comprises determining the downward force to be applied from the injector, and the applying of the downward force comprises applying the determined downward force.

14. A method as claimed in claim 13, wherein the determining of the downward force comprises determining the downward force to be applied using any one or more of: the well pressure; the length extent of the coiled tubing assembly in the well; the weight of the inserted length of the coiled tubing assembly; the load from or tension of the coiled tubing assembly.

15. A method as claimed claim 13 or 14, wherein the applying of downward force comprises communicating one or more instructions from the control device to one or more operational components of the injector.

16. A method as claimed in any preceding claim, which includes controlling the injector to obtain or approximate a constant load or tension or a planned load or tension of the coiled tubing assembly over at least a range of positions upon advancing the coiled tubing assembly downward or upward in the well.

17. A method as claimed in any preceding claim, wherein the control device is disposed underwater at, on, or near the subsea injector.

18. A subsea control device for controlling a subsea coiled tubing injector in a system for operating a coiled tubing assembly extending into a subsea well, the coiled tubing assembly including coiled tubing disposed through the injector, the control device being configured to produce one or more instructions for operating the subsea coiled tubing injector to apply a downward force to thecoiled tubing dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly.

19. A subsea control device comprising any one or more of: an input unit for receiving data from one or more detection means; a storage unit for storing either or both: one or more computer programs; detection data; and a model for the downward force dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly; a processor unit for either or both processing sensor data and executing one or more computer programs to determine, using or based on the model, instructions for applying the downward force to the coiled tubing; an output unit for outputting instructions to one or more components of the injector to apply the downward force.

20. A subsea control device as claimed in claim 18 or 19, comprising a determiner unit for determining the downward force to be applied.

21. Apparatus for operating a coiled tubing assembly extending into a subsea well, the coiled tubing assembly including coiled tubing, the apparatus comprising: a subsea coiled tubing injector for applying downward force to the coiled tubing; and a subsea control device for controlling the injector to apply downward force to the coiled tubing dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly.

22. Apparatus as claimed in claim 21 , wherein the subsea control device is configured to be arranged underwater at, on, or near the subsea coiled tubing injector.

23. Apparatus as claimed in claim 21 or 22, further comprising at least one pressure sensor for determining the well pressure.

24. Apparatus as claimed in any of claims 21 to 23, further comprising at least one load detector for determining the load or tension of the coiled tubing assembly.

25. Apparatus as claimed in any of claims 21 to 24, further comprising at least one depth counter detector for detecting the extent of insertion of the coiled tubing assembly.

26. Apparatus as claimed in any of claims 21 to 25, wherein the subsea control device has: an input for receiving any one or more of data from at least one pressure sensor, at least one load detector, at least one depth counter; a determiner for determining the downhole force to be applied and / or injector head control instructions, based on the input data and a model for the downhole force dependent upon either or both: the length extent of the coiled tubing assembly in the well; and the weight of the inserted length of the coiled tubing assembly; and an output for outputting the instructions to the injector.

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