Taring of sensors

Abstract

A motion sensor of an item of equipment, such as a subsea blowout preventer, is fared with respect to a reference axis of that equipment, such as a central axis of a main bore. A taring surface of a taring tool is held against a reference surface of the equipment, such as a gasket seat, in fixed relation to the reference axis. The taring tool comprises a motion sensor in fixed relation to the taring surface. A signal output of that sensor is measured relative to a corresponding signal output of the sensor on the equipment. An offset value is determined to align the signal output of the equipment sensor with the signal output of the tool sensor and is thereafter applied to the signal output of the equipment sensor.

Description

[0001] Taring of sensors

[0002] This invention relates to taring of sensor systems used to monitor motion, position or orientation of items of equipment, especially subsea equipment used in the offshore oil and gas industry. Examples of such equipment, to be described in this specification, include blowout preventers (BOPs), lower marine riser packages (LMRPs) and drilling riser adaptors, which may be installed and used together as a BOP stack atop a subsea wellhead.

[0003] Installation of a BOP or riser on a subsea wellhead requires fine adjustment of position and alignment. Usually, local sensors measure the distance and / or alignment between components to be connected subsea. In WO 2018 / 111909, for example, landing sensors detect when equipment lands on a wellhead. An alignment sensor measures the radial distance between components. WO 2023 / 092012 and US 7762338 also describe local sensors that measure relative orientation and position of incoming equipment approaching the wellhead. WO 2016 / 022029 discloses an alignment measurement tool comprising a support that is locked onto a wellhead and remains connected during the alignment phase to predict future alignment.

[0004] Simple relative positioning may not be sufficient properly to locate equipment to be mounted on a wellhead, for example because the wellhead itself may not be perfectly vertical. There is a need to improve the accuracy of measurement of axial alignment and orientation of such equipment relative to the wellbore. There is also a need to monitor the motion of subsea equipment not just during installation but afterwards as the equipment experiences movements driven by ocean dynamics and other loads during its service life and therefore accumulates fatigue. For example, motion sensor systems attached to BOPs and other subsea equipment can be used to perform wellhead integrity monitoring, enabling structural monitoring by measuring oscillatory lateral displacements and inclination expressed as roll and pitch angles.

[0005] To be useful for these purposes, motion sensors must be sensitive to very small angular changes in the orientation of the equipment to which they are attached. However, such sensitivity renders sensors vulnerable to inaccuracy due to incorrect alignment of the sensors relative to the underlying equipment or even due to incorrect alignment of a sensor chip within a housing of the sensor. In the context of a BOP stack, there is a particular need to align motion sensors with the central axis of the common bore that extends through the components of the stack. The effects of inaccurate sensor alignment are exacerbated because such sensors are typically affixed to an outer surface of the equipment and so are offset laterally by a significant distance relative to the central axis of the bore.

[0006] The central axis of the bore of a BOP stack is nominally vertical and any departure from the vertical can cause problems not only during installation of the BOP stack onto a wellhead but also in service. In particular, any angular misalignment between the axes of the bore and of a drill string received within the bore must be clearly within allowable tolerances. So, if signals from motion sensors indicate that the central axis of the bore is vertical, the bore must indeed be vertical within an acceptable margin of error.

[0007] Consequently, there is a need to tare the signals of sensor systems relative to a reference axis of the equipment to which they are attached, such as the central axis of the bore of a BOP stack. Any misalignment or offset between the sensors and the reference axis can then be compensated by applying an offset adjustment to the signals output by the sensors. It is desirable to perform accurate taring as easily as possible and to do so in a way that can be performed offshore, topside, shortly before the equipment is lowered into the water.

[0008] More generally, US 2014 / 262306 A1 describes devices and methods for testing and calibrating a subsea multi-phase flow meter prior to initiation of production operations, using a second flow meter disposed at the surface. US 2023 / 010878 A1 describes an error checker that can subtract an offset value from drill bit strain measurements, in order to output a set of strain measurements that have been zeroed to account for hydrostatic pressure-effect offset. GB 2392985 describes a method for calibrating a subsurface gravity measurement device having a tilt meter and a gravity, by using the interplay between tilt and gravity data to derive a correction parameter that can be used for calibration purposes.

[0009] Against this background, the invention provides a method of taring an equipment sensor of an item of equipment with respect to a reference axis of that equipment. The method comprises: holding a taring surface of a taring tool against a reference surface of the equipment that is in fixed relation to the reference axis, the taring tool further comprising a tool sensor in fixed relation to the taring surface; measuring a signal output of the tool sensor relative to a corresponding signal output of the equipment sensor; determining an offset value to align the signal output of the equipment sensor with the signal output of the tool sensor; and applying the offset value to the signal output of the equipment sensor.

[0010] The equipment sensor and the tool sensor could be motion sensors or inclination sensors. The tool sensor may be in angular alignment with the reference axis when the taring tool is held against the reference surface.

[0011] The reference axis can extend along a bore of the equipment configured to carry fluids, for example as a central longitudinal axis of the bore. In that case, the reference surface suitably surrounds the bore and may lie in a plane that is perpendicular or orthogonal to the reference axis. However, the reference surface need not be orthogonal to the reference axis so long as the angle between them is known and specified with high accuracy. In embodiments to be described, the reference surface is a machined surface that provides a seat for a gasket encircling the bore.

[0012] The taring tool can be pulled against the reference surface to hold the taring surface against the reference surface, for example by being suspended from above through the bore. Alternatively, the taring tool can be pushed against the reference surface to hold the taring surface against the reference surface, for example by being pushed upwardly from below.

[0013] The taring surface can be held against the reference surface for a taring period, in which case the signal outputs of the equipment sensor and the tool sensor can be measured over that period as respective time series. The respective time series can then be compared at corresponding time stamps.

[0014] The equipment may experience motion during the taring period, for example where the taring period takes place when the equipment is aboard a floating support, such as rig, before being lowered into water. In this respect, for example, the equipment may be, or may comprise, a subsea blowout preventer or a lower marine riser package. More generally, the equipment may be configured to connect with a subsea wellhead, in which case the reference surface can be on a wellhead connector of the equipment. Conversely, the equipment may be configured to connect with a subsea riser, in which case the reference surface can be on a riser adaptor of the equipment.

[0015] The inventive concept extends to a taring tool employed in or for use in methods of the invention, the taring tool comprising at least one taring surface and a motion or inclination sensor in fixed relation to the or each taring surface. The or each taring surface may, for example, be defined by a rigid plate, which is suitably circular to fit against an annular reference surface of the equipment, and that may have at least one planar face. Mutually opposed faces of the plate can define respective taring surfaces, which may be in mutually parallel planes.

[0016] The sensor may lie on an axis disposed centrally with respect to the plate. The sensor can be mounted on a rigid shaft that extends orthogonally relative to the or each taring surface.

[0017] The inventive concept also embraces a combination of a taring tool of the invention with an item of equipment that defines a reference axis and that has a reference surface in fixed relation to the reference axis, the taring surface of the taring tool being shaped to complement the reference surface of the equipment. As noted above, the reference surface could, for example, be a machined annular surface that defines a seat for a gasket surrounding a bore of the equipment. Again, the reference axis can extend along the bore, for example as a central longitudinal axis of the bore, whereas the reference surface may surround the bore and can lie in a plane that is orthogonal to the reference axis.

[0018] Embodiments of the invention obtain measurement data from a calibrated motion sensor of a taring tool, with the aim of aligning the output of an equipment motion sensor with a reference axis, such as a main bore of the equipment. The taring tool, which may have its motion sensor mounted perpendicular to a plate, is placed with its plate mating against a taring or reference surface on the equipment.

[0019] More specifically, the taring tool can be mated to a reference surface within a wellhead connector beneath a BOP and / or on a riser adaptor, that surface being perpendicular to the central axis of a main bore of the BOP, LMRP and / or riser adaptor. The measured data is used as a reference to align coordinate systems of one or more equipment motion sensors with the central axis of the main bore. By doing this, the equipment motion sensor will report angles with reference to that central axis, significantly improving the accuracy of the absolute angle compared to conventional methods to align those sensors with the main bore.

[0020] After removing any gasket already installed against the reference surface, the reference surface is cleaned to remove any debris and checked for damage. The taring tool is then held against the reference surface for a period of time, or a taring period, after syncing a clock of the taring tool sensor with a clock of the equipment motion sensor. In this respect, where taring takes place on a floating installation vessel such as a drilling rig, the equipment is constantly moving during the taring sequence. Such motion of the equipment is excluded from the taring calculation by time-syncing the taring tool with the equipment motion sensors. The installation offset of the equipment motion sensor is then calculated such that the data measured by that sensor become identical to the data measured by the taring tool held against the reference surface at any given timestamp.

[0021] Thus, a sensor offset is calculated such that the equipment motion sensor measurements align with the taring tool measurements during the taring period. The sensor offset is added to the data stream of the equipment motion sensor to tare the equipment motion sensors. This establishes a baseline offset for the equipment motion sensor that compensates for any misalignment between the equipment motion sensor and the reference axis, such as that of the main bore extending through the BOP stack or of a drilling riser.

[0022] There is no need for direct communication between the taring tool and the equipment motion sensor as the offset is calculated in retrospect, allowing the taring tool and the equipment motion sensor to be any desired distance apart from each other.

[0023] Embodiments of the invention implement a method to improve measurement of the vertical alignment relative to a wellhead axis of equipment, such as a BOP or a riser adapter, to be mounted on a wellhead. The method comprising: identifying a reference surface that could be substantially horizontal, such as a gasket seat, in a wellhead connector to be mounted on the wellhead; preparing the reference surface, for example by removing any gasket and cleaning the surface; preparing a support such as a plate or ring; mounting an alignment sensor on the support; synchronising clocks of the alignment sensor and an equipment position sensor; mounting the support on the reference surface for a period of time; measuring a baseline alignment offset by the alignment sensor, and setting an equipment position sensor offset to a value measured by the alignment sensor.

[0024] The reference surface is not necessarily horizontal. The reference surface is normally perpendicular or orthogonal to the central longitudinal axis of a main bore of the equipment. However, such a relationship is not essential if the angle between the reference surface and the central axis is known. The alignment sensor and its support are then removed after the baseline alignment offset has been determined. The equipment position sensor offset may be used for correcting a position or alignment value of the equipment position sensor during or after connection of the equipment to the wellhead.

[0025] In summary, the invention enables a motion sensor of an item of equipment, such as a subsea blowout preventer, to be fared with respect to a reference axis of that equipment, such as a central axis of a main bore. A taring surface of a taring tool is held against a reference surface of the equipment, such as a gasket seat, in fixed relation to the reference axis. The taring tool comprises a motion sensor in fixed relation to the taring surface. A signal output of that sensor is measured relative to a corresponding signal output of the sensor on the equipment. An offset value is determined to align the signal output of the equipment sensor with the signal output of the tool sensor and is thereafter applied correctively to the signal output of the equipment sensor.

[0026] In order that the invention may be more readily understood, reference will now be made, by way of example, to the accompanying drawings in which:

[0027] Figure 1 is a schematic sectional side view of a BOP mounted conventionally on a wellhead via a wellhead connector of the BOP;

[0028] Figure 2 is a perspective view of a taring tool of the invention;

[0029] Figure 3 is a schematic side view of an offshore drilling rig carrying a BOP stack while a taring tool of the invention is being used to tare a sensor mounted on the BOP stack;

[0030] Figure 4 is a schematic sectional side view that shows the taring tool of Figure 2 held against a reference surface of the wellhead connector of Figure 1;

[0031] Figures 5a, 5b and 5c are a sequence of schematic side views that show the taring tool being used to tare a sensor mounted on a BOP, being a lower section of the BOP stack shown in Figure 4;

[0032] Figure 6 is a flow diagram that summarises the taring process illustrated in Figures 5a, 5b and 5c; Figures 7 and 8 are schematic side views that show ways in which the taring tool can be held against a reference surface of a wellhead connector;

[0033] Figures 9a, 9b and 9c are a sequence of schematic side views that show the taring tool being used to tare a sensor mounted on a LMRP of the BOP stack; and

[0034] Figures 10a, 10b and 10c are a sequence of schematic side views that show the taring tool being used to tare a sensor mounted on a riser connected to the BOP stack.

[0035] As background to the invention, Figure 1 shows a wellhead connector 10 of a blowout preventer (BOP) 12 mounted atop a subsea wellhead 14 to define a common upright bore 16 that extends between and through them. As is conventional, the bore 16 is arranged to receive a drill string (not shown) that extends downwardly through a drilling riser suspended from a drilling rig at the surface. The bore 16 is further arranged to convey and constrain fluids that flow into or out of the wellhead 14 during a drilling operation.

[0036] The wellhead connector 10 comprises a skirt 18 that surrounds the wellhead 14 in concentric relation about a substantially vertical common central longitudinal axis 20 of the bore 16. The internal side of the skirt 18 and the external side of the wellhead 14 are rotationally symmetrical about that axis 20.

[0037] On its radially inner side, the skirt 18 has an internal circumferential seat formation that is vertically opposed to the upper end of the wellhead 14. The seat formation comprises a downwardly-facing machined sealing face 22 disposed radially outboard of an inner frusto-conical face 24 that is inclined inwardly and upwardly. Correspondingly, the upper end of the wellhead comprises an upwardly-facing machined sealing face 26 disposed radially outboard of an inner frusto-conical face 28 that is inclined inwardly and downwardly. The sealing faces 22, 26 are disposed in mutual opposition, spaced apart along the common axis 20 to lie in respective parallel planes that are orthogonal to that axis 20, hence being substantially horizontal.

[0038] A resilient annular gasket 30 is sandwiched between the seat formation of the skirt 18 and a contact surface at the upper end of the wellhead 14. A radially outer side of the gasket 30 has a convex section defined by opposed chamfers 32 that complement and fit between the frusto-conical inner faces of the seat formation and the wellhead 14. Between those chamfers 32, the radially outer side of the gasket 30 has a central circumferential flange 34 that is received in the gap between the opposed sealing faces 22.

[0039] The downwardly-facing sealing face 22 of the seat formation provides a planar machined reference surface that is in known, fixed relation to the nominally vertical central axis 20 of the bore 16. As will now be explained, that face 22 provides a convenient taring seat against which a taring tool 36 of the invention can be held when used to tare a position or motion sensor system mounted to or incorporated into the BOP 12. As will be explained later, other machined surfaces of other items of equipment can define taring seats for a taring tool 36 of the invention to tare position or motion sensor systems that are mounted to or incorporated into such equipment.

[0040] Figure 2 shows a taring tool 36 of the invention. The taring tool 36 comprises at least one taring surface that is shaped to be held against a taring seat of a BOP 12 or other item of equipment and a motion sensor 38 that is in known, fixed relation to the, or each, taring surface. In this example, taring surfaces of the taring tool 36 are defined by opposed major faces 40 of a rigid plate 42. Specifically, the plate 42 has at least one flat or planar face 38 and in this example has upper and lower faces 40 in mutually parallel planes, with the upper face 40 facing toward the motion sensor 38.

[0041] As is conventional, the motion sensor 38 has accelerometer and gyroscope functionality. In this example, the motion sensor 38 is mounted at the free end of a rigid shaft 44 that extends orthogonally relative to the plane of the or each taring surface defined by the plate 42. The other end of the shaft 44 is fixed to the plate 42, in this example centrally.

[0042] The plate 42 exemplified in Figure 2 is circular, centred on the longitudinal axis 46 of the shaft 44. Moreover, in this example, the plate 42 is penetrated by radially-extending apertures including slots 48 that can support radially-adjustable spacers (not shown) for aligning the plate 42 within a bore 16 of a BOP 12 or other equipment.

[0043] Figure 3 shows a taring operation in which the plate 42 of a taring tool 36 is held against the downwardly-facing sealing face 22 of the seat formation within the wellhead connector 10 of the BOP 12. For this purpose, as best appreciated in Figure 4, the gasket 30 shown in Figure 1 is removed, if previously fitted to the wellhead connector 10, to expose the sealing face 22. Then, the sealing face 22 is cleaned if necessary and inspected for damage to provide a reliable flat taring seat against which the plate 42 of the taring tool 36 can be held. Alignment of the motion sensor 38 with the central axis 20 of the bore 16 is desirable but not essential to the inventive concept in its broadest sense. In this respect, it will be noted that the diameter of the plate 42 can be smaller than the diameter of the bore 16 at the level of the sealing face 22. Indeed, positioning the motion sensor 38 within the bore 16 is not essential to the broad inventive concept, if another reference surface of an item of equipment could be suitable to define a taring seat instead. However, in-bore positioning of the motion sensor 38 is convenient and preferred because a machined surface to define a taring seat is accessible around the bore 16, and because that surface is in a known, fixed relation to the central axis 20 of the bore 16 whose orientation is most critical to measure.

[0044] In this example, the upper face 40 of the plate 42 is presented to the sealing face 22 and consequently the motion sensor 38 is positioned above the plate 42 within the bore 16 of the wellhead connector 10. However, in principle, the tool 36 could instead be inverted to present the lower face 40 of the plate 42 to the sealing face 22, in which case the motion sensor 38 would be positioned beneath the plate 42 and could possibly lie outside the bore 16 of the wellhead connector 10.

[0045] In the example shown in Figure 3, the taring operation is performed when the BOP 12 is aboard a drilling rig 50 floating at the surface 52 of the sea, before the BOP 12 is lowered though a moonpool 54 beneath a derrick 56 of the rig 50 and from there onto a wellhead at the seabed beneath. The rig 50 is held on station by thrusters 58 under the control of a dynamic positioning system but nevertheless will experience sea-driven motion. Such motion of the rig 50 and hence of the BOP 12 is determined during a taring operation and compensated for.

[0046] In this example, the BOP 12 is a lower portion of a BOP stack 60 whose upper portion comprises a lower marine riser package (LMRP) 62 surmounted by a riser adaptor 64 that provides a connection to a drilling riser via a flex joint. The BOP stack 60 can be assembled aboard the rig 50 using a crane 66 or other lifting apparatus and then lowered to the seabed as a unit via the moonpool 54, with the drilling riser being assembled progressively as the BOP stack 60 is lowered.

[0047] Turning next to Figures 5a to 5c, these drawings show a taring tool 36 of the invention being used to tare a motion sensor system 68 that is mounted on or incorporated into the BOP 12 of the BOP stack 60. In these drawings, the motion sensor system 68 is shown as being misaligned or angularly offset relative to the central axis 20 of the bore 16 of the BOP 12. Thus, the motion sensor system 68 requires taring to compensate for that misalignment as otherwise it would report the orientation of the BOP 12 incorrectly with respect to that axis 20.

[0048] In Figure 5a, the plate 42 of the taring tool 36 is about to be applied to the downwardly- facing sealing face 22 within the wellhead connector 10 of the BOP 12. At this stage, the motion sensor 38 of the taring tool 36 is not yet aligned with the central axis 20 of the bore 16. In Figure 5b, the plate 42 of the taring tool 36 is now applied to the sealing face 22 so that the motion sensor 38 of the taring tool 36 is now aligned with, hence at least parallel to, the central axis 20. In Figure 5c, taring is complete, allowing an angular compensation value to be applied to the signals reported from the motion sensor system 68. That compensation value corresponds to the angular offset of the motion sensor system 68 away from representing parallelism with the central axis 20.

[0049] As the response of the motion sensor system 68 to motion is measured over a period of time, any motion of equipment with such a system during a taring period, for example due to sea-driven motion of a rig 50, must be recognised and allowed for. Indeed, conveniently, such motion of the rig 50 and hence of equipment aboard the rig 50 can be exploited by the invention. In this respect, Figure 6 shows the step at 70 of time-syncing the motion sensor system 68 of the BOP 12 with the motion sensor of the taring tool 36, for example by synchronising clocks of the respective components. Then, or previously, the taring tool 36 is mounted to the taring seat exemplified by the sealing face 22 within the wellhead connector 10 at step 72.

[0050] Once the taring tool 36 is mounted to the taring seat and time-syncing has been completed, data from the motion sensor system 68 of the BOP 12 and from the motion sensor 38 of the taring tool 36 is sampled at step 74. This generates respective time series, namely Ssensor derived from data measured by the motion sensor system 68 of the BOP 12 during a series of movements of the BOP 12 and Stool being the response of the motion sensor 38 of the taring tool 36 during the same series of movements of the BOP 12. Each time series includes data from the accelerometers of the respective motion sensors with respect to the X, Y and Z axes, hence Ax(t), Ay(t) and Az(t), and from the gyroscopes of the respective motion sensors with respect to the X, Y and Z axes, hence Gx(t), Gy(t) and Gz(t). Then, at step 76, the time series Ssenso / -and Sroo / are used to estimate the angular offset of the motion sensor system 68 away from representing parallelism with the central axis 20. In this way, an appropriate angular compensation value can be applied to the signals reported from the motion sensor system 68 as described above with reference to Figure 5c.

[0051] Figures 7 and 8 show ways in which the taring surface of the taring tool 36 can be held against the taring seat of the BOP 12. In Figure 7, the taring tool 36 is pushed up from below, for example using jacks or springs 78. Conversely, in Figure 8, the taring tool 36 is pulled up from above, for example using a chain or wire 80 extending along the common bore of the BOP 12 and the other components of the BOP stack 60, including the LMRP 62 and the riser adaptor 64. In each case, the pulling or pushing system can react against the BOP stack 60 or against a rig 50 or other structure that supports the BOP stack 60.

[0052] Figures 9a to 9c show a taring tool 36 of the invention being used to tare a motion sensor system 68 that is mounted on or incorporated into the LMRP 62 of the BOP stack 60. In Figure 9a, the plate 42 of the taring tool 36 is about to be applied to the downwardly- facing sealing face 22 within the wellhead connector 10 of the BOP 12. At this stage, the motion sensor 38 of the taring tool 36 is not yet aligned with the central axis 20 of the bore 16. In Figure 9b, the plate 42 of the taring tool 36 is now applied to the sealing face 22 so that the motion sensor 38 of the taring tool 36 is now aligned with, hence at least parallel to, the common central axis 20 of the BOP 12 and the LMRP 62. In Figure 9c, taring is complete, allowing an angular compensation value to be applied to the signals reported from the motion sensor system 68. Again, that value corresponds to the angular offset of the motion sensor system 68 away from representing parallelism with the central axis 20.

[0053] Finally, Figures 10a to 10c show a taring tool 36 of the invention being used to tare a motion sensor system 68 that is mounted on or incorporated into the riser adaptor 64 atop the BOP stack 60. In this respect, the riser adaptor 64 has an upwardly-facing circumferential machined sealing face 82 on its radially inner side. That sealing face 82 lies in a plane that is orthogonal to the central longitudinal axis 84 of the riser, providing a flat taring seat against which a taring surface of the taring tool 36 can be held

[0054] In Figure 10a, the plate 42 of the taring tool 36 is about to be applied to the sealing face 82 of the riser adaptor 64. At this stage, the motion sensor 38 of the taring tool 36 is not yet aligned with the central longitudinal axis 84 of the riser. In Figure 10b, the plate 42 of the taring tool 36 is now applied to the sealing face 82 so that the motion sensor 38 of the taring tool 36 is now aligned with, hence at least parallel to, the central longitudinal axis 84 of the riser. In Figure 10c, taring is complete, allowing an angular compensation value to be applied to the signals reported from the motion sensor system 68. That value corresponds to the angular offset of the motion sensor system 68 away from representing parallelism with the central longitudinal axis 84 of the riser.

[0055] Many other variations are possible within the inventive concept. For example, it is preferred for simplicity, but not essential, that the taring seat of an item of equipment lies in a plane orthogonal to a bore that is surrounded by that seat. Another surface around, beside or facing into a bore, could in principle be used as a taring seat against which a taring tool could be held during a taring operation. Such a surface could be a side wall of the bore that lies parallel to, or at a known angle to, a longitudinal axis of the bore.

[0056] Whilst the origin and central concept of the invention lies in taring of motion sensor systems by measuring the response of a taring tool sensor to motion over a period of time, the broader inventive concept could be extended to taring of inclination sensors, which could, in principle, be performed by a taring tool instantaneously.

Claims

Claims1 . A method of taring an equipment sensor of an item of subsea equipment for use in the offshore oil and gas industry with respect to a reference axis of that subsea equipment, the method comprising: holding a taring surface of a taring tool against a reference surface of the subsea equipment that is in fixed relation to the reference axis, the taring tool further comprising a tool sensor in fixed relation to the taring surface; measuring a signal output of the tool sensor relative to a corresponding signal output of the equipment sensor; determining an offset value to align the signal output of the equipment sensor with the signal output of the tool sensor; and applying the offset value to the signal output of the equipment sensor.

2. The method of Claim 1 , wherein the tool sensor is in angular alignment with the reference axis when the taring tool is held against the reference surface.

3. The method of Claim 1 or Claim 2, wherein the reference axis extends along a bore of the subsea equipment.

4. The method of Claim 3, wherein the reference axis is a central longitudinal axis of the bore.

5. The method of Claim 3 or Claim 4, wherein the reference surface surrounds the bore.

6. The method of Claim 5, wherein the reference surface lies in a plane orthogonal to the reference axis.

7. The method of Claim 5 or Claim 6, wherein the reference surface is a gasket seat.

8. The method of any of Claims 3 to 7, wherein the taring tool is pulled against the reference surface to hold the taring surface against the reference surface.

9. The method of Claim 8, wherein the taring tool is suspended from above through the bore to hold the taring surface against the reference surface.

10. The method of any of Claims 1 to 7, wherein the taring tool is pushed against the reference surface to hold the taring surface against the reference surface.

11. The method of Claim 10, wherein the taring tool is pushed upwardly from below to hold the taring surface against the reference surface.

12. The method of any preceding claim, wherein the equipment sensor and the tool sensor are motion sensors.

13. The method of Claim 12, comprising holding the taring surface against the reference surface for a taring period and measuring the signal outputs of the equipment sensor and the tool sensor over that period as respective time series.

14. The method of Claim 13, comprising comparing the respective time series at corresponding time stamps.

15. The method of Claim 13 or Claim 14, wherein the subsea equipment experiences motion during the taring period.

16. The method of Claim 15, wherein the taring period takes place aboard a floating support such as rig before the subsea equipment is lowered into water.

17. The method of Claim 16, wherein the subsea equipment is, or comprises, a subsea blowout preventer or a lower marine riser package.

18. The method of any preceding claim, wherein the subsea equipment is configured to connect with a subsea wellhead and the reference surface is on a wellhead connector of the subsea equipment.

19. The method of any preceding claim, wherein the subsea equipment is configured to connect with a subsea riser and the reference surface is on a riser adaptor of the subsea equipment.

20. A taring tool for taring an equipment sensor of an item of subsea equipment for use in the offshore oil and gas industry, the taring tool comprising at least one taring surface and a motion or inclination sensor in fixed relation to the or each taring surface.

21. The tool of Claim 20, wherein the or each taring surface is defined by a rigid plate that has at least one planar face.

22. The tool of Claim 21 , wherein mutually opposed faces of the plate define respective taring surfaces.

23. The tool of Claim 22, wherein the mutually opposed faces of the plate are in mutually parallel planes.

24. The tool of any of Claims 21 to 23, wherein the plate is circular.

25. The tool of any of Claims 21 to 24, wherein the sensor lies on an axis disposed centrally with respect to the plate.

26. The tool of any of Claims 20 to 25, wherein the sensor is mounted on a rigid shaft that extends orthogonally relative to the or each taring surface.

27. The method of any of Claims 1 to 19, employing a taring tool as defined in any of Claims 20 to 26.

28. In combination, a taring tool as defined in any of Claims 20 to 26 with the item of subsea equipment that defines a reference axis and that has a reference surface in fixed relation to the reference axis, the taring surface of the taring tool being shaped to complement the reference surface of the subsea equipment.

29. The combination of Claim 28, wherein the subsea equipment is, or comprises, a subsea blowout preventer or a lower marine riser package.

30. The combination of Claim 28 or Claim 29, wherein the subsea equipment is configured to connect with a subsea wellhead and the reference surface is within a wellhead connector of the subsea equipment.

31. The combination of any of Claims 28 to 30, wherein the subsea equipment is configured to connect with a subsea riser and the reference surface is within a riser adaptor of the subsea equipment.

32. The combination of any of Claims 28 to 31 , wherein the reference axis extends along a bore of the subsea equipment.

33. The combination of Claim 32, wherein the reference axis is a central longitudinal axis of the bore.

34. The combination of Claim 33, wherein the reference surface surrounds the bore.

35. The combination of any of Claims 28 to 34, wherein the reference surface lies in a plane orthogonal to the reference axis.

36. The combination of any of Claims 28 to 35, wherein the reference surface is a gasket seat.

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