Device for centering a sensor assembly in a cartridge

Abstract

An apparatus for centering a sensor assembly in a barrel includes a mandrel, a first support member, and a second support member, the support members being axially spaced apart along a central longitudinal axis of the apparatus. A plurality of arm assemblies are circumferentially spaced apart about the central longitudinal axis of the apparatus and connected between the first and second support members. Each arm assembly includes a first arm pivotally connected to the first support member by a first pivot joint having a first pivot axis, a second arm pivotally connected to the second support member by a second pivot joint having a second pivot axis, and the first and second arms are pivotally connected together via a third pivot joint having a third pivot axis. The third pivot axis is located on a first side of a plane that coincides with the central longitudinal axis of the apparatus, and at least one of the first and second pivot axes is located on an opposite second side of the plane.

Description

[0001] Corresponding applications

[0002] This application is based on the provisional specification relating to New Zealand patent application No. 766888, the entire contents of which are incorporated herein by reference. TECHNICAL FIELD

[0003] The present invention relates to apparatus for centering pairs of sensor devices in a bore such as a pipe, wellbore or cased wellbore, and in particular to apparatus for centering pairs of sensor devices in wireline logging applications. BACKGROUND

[0004] Hydrocarbon exploration and development activities rely on information acquired from sensors that capture data relating to the geological properties of the area being explored. One method for acquiring this data is through wireline logging. Wireline logging is performed in the wellbore immediately after a new section of the wellbore is drilled, known as open hole logging. These wellbores are drilled to a target depth that covers the area of interest, typically between 1000-5000 meters deep. A sensor package, also known as a "logging tool" or "tool string", is then lowered into the wellbore and under the force of gravity to the target depth of the wellbore well. The logging tool is lowered onto a wireline, which is a bundle of communication wires encased in a steel cable that is connected to the logging tool. The steel cable carries the load from the tool string, the wireline itself, the frictional forces acting on the downhole equipment and any excess tension created by sticking or sticking. Once the logging tool reaches the target depth, it is then returned through the wellbore at a controlled rate of ascent, at which point the sensors in the logging tool operate to generate and capture geological data.

[0005] Cable logging is also performed in wellbores lined with steel pipe or casing, known as cased hole logging. After a section of a wellbore is drilled, a casing is lowered into the wellbore and set in place. A cementing agent is placed in the annulus between the casing and the wellbore wall to ensure isolation between layers of permeable rock intersected by the wellbore at different depths. The cementing agent also prevents the flow of hydrocarbons in the annulus between the casing and the wellbore, which is important for the integrity and safety of the well. Oil wells are typically drilled in successive sections. A large diameter drill bit is used to "drill in" to the wellbore to drill the first section. The first section of casing is known as the conductor pipe. The conductor pipe is cemented into the new wellbore and fixed to the surface wellhead. A smaller drill bit is run through the conductor pipe and drills the surface hole to a deeper level. The surface casing string is then run in the hole to the bottom of the hole. This surface casing, typically 20 inches (nominal outer diameter (OD)), is then cemented in place by filling the annulus formed between the surface casing and the new hole and the conductor pipe. Drilling continues with a smaller drill bit size for the next interval. Similarly, an intermediate casing (e.g., 13 3 / 8 inches) is cemented into that hole section. Drilling continues with a smaller drill bit size for the next interval. A production casing (e.g., 9 3 / 8 inch outer diameter (OD)) is run to TD (total depth) and cemented in place. The final casing string (e.g., 7 inch outer diameter (OD)) is cemented in place from the previous casing string's tailpipe hanger. Thus, the tool string must traverse the casing hole and can need to enter a smaller diameter wellbore.

[0006] There are a wide variety of logging tools designed to measure various physical properties of the rock and fluids contained in the rock. Logging tools include transducers and sensors to measure properties such as resistivity, gamma ray density, sound velocity, etc. Individual logging tools are combinable and are typically connected together to form a logging tool string. Some sensors are designed to be in close contact with the borehole wall during data acquisition, while others are ideally centered in the wellbore for best results. Any device attached to the tool string needs to meet these requirements. Cable logging tool strings are typically on the order of 20 to 100 feet in length and 2 to 5 inches in diameter.

[0007] In cased wellbores, logging tools are used to evaluate the cement bond strength between the casing and the wellbore wall and the condition of the casing. There are several types of sensors, and they typically need to be centered in the casing. One such logging tool utilizes high frequency ultrasonic transducers and sensors to record circumferential measurements around the casing. The ultrasonic transducers and sensors are mounted on a spinner that is attached to the bottom of the tool. This spinner rotates and enables the sensors to record azimuthal ultrasonic reflections from the casing wall, cement sheath, and wellbore wall as the tool is slowly tripped out of the wellbore. Other tools have transducers and sensors that can record the amplitude drop or attenuation of an acoustic signal as it propagates along the casing wall. Importantly, these transducers and sensors need to be well centered in the casing to ensure that the recorded data is valid. Other logging tools that measure fluids and gas production in flowing wellbores can also require sensor centering. Logging tools are also run in production wells to determine the flow characteristics of the produced fluids. Many of these sensors also require centering to make the data valid.

[0008] In open hole (uncased wellbores), logging tools are used to scan the wellbore wall to determine formation structure dip, the size and orientation of fractures, the size and distribution of pore space in the rock, and information about the depositional environment. One such tool has multiple sensors on a pad that contacts the circumference of the wellbore to measure microresistivity. Other tools generate acoustic signals that propagate along the wellbore wall and are recorded by multiple receivers spaced along the tool and at azimuthal angles around the tool. Like the cased wellbore logging tools, the measurements of these sensors are optimized by being well centered in the wellbore.

[0009] Drilling and wireline logging operations are expensive tasks. This is primarily due to the capital cost of the drilling equipment and the special nature of the wireline logging systems. It is important to carry out and complete these activities as quickly as possible to minimize these costs. Delays in deploying the wireline logging tools should be avoided whenever possible.

[0010] One of the reasons for this delay is the difficulty in lowering the wireline logging tool to the target depth in the wellbore. The logging tool is lowered down the wellbore by the wireline under the influence of gravity. The wireline is flexible and cannot push the tool down the wellbore. Therefore, the operator at the top of the well has little control over the descent of the logging tool.

[0011] For deviated wells, the likelihood of the wireline logging tool failing to descend increases significantly. Deviated wells do not travel straight down, but rather down and to the side at an angle to the vertical. Multiple deviated wells are often drilled from a single surface location to allow exploration and production of large areas. As the wireline logging tool travels down the wellbore by the wireline under the influence of gravity, the tool string will drag along the low side or bottom of the wellbore wall as it travels down to the target depth. The friction or drag of the tool string against the wellbore wall can prevent the tool from descending to the desired depth. The long length of the tool string can further exacerbate the problem of guiding the tool string down the wellbore.

[0012] Reference Figure 1 In deviated wells, the weight of the tool string exerts a lateral force (PW) perpendicular to the wellbore wall. This lateral force creates a drag force that acts to prevent the tool string from falling into the wellbore. The axial component of the tool string weight (AW) acts to pull the tool string along the wellbore, and this force is opposed by the drag force acting in the opposite direction. As the deviation of the well increases, the axial component of the tool weight (AW) decreases and the lateral force (PW) increases. When the drag force created by the lateral force (PW) is equal to the axial component of the tool string weight (AW), the tool will not fall in the wellbore.

[0013] As the deviation of the wellbore increases, the sliding friction or drag force prevents the logging tool from falling. The practical limit is about 60° from vertical, and in these high angle wells, any device that can reduce the friction is very valuable. The drag force is the product of the lateral component of the tool weight acting perpendicular to the wellbore wall and the coefficient of friction. It is desirable to reduce the coefficient of friction to reduce the drag force. The coefficient of friction can be reduced by using low friction materials, such as Teflon. The drag force can also be reduced by using wheels.

[0014] A common device used to center logging tools is the arch spring centralizer. The arch spring centralizer contains a number of curved leaf springs. The leaf springs are attached at their ends to an attachment structure that is fixed to the logging tool. The midpoints of the curved leaf springs (or arches) are disposed to project radially outward from the attachment structure and tool string. When the arch spring centralizer is not constrained by a wellbore, the outer diameter of the arch spring centralizer is greater than the diameter of the wellbore or casing in which it is to be deployed. Once deployed in the wellbore, the arches flatten out and the flattened arches provide a centralizing force on the tool string. In deviated wells, this centralizing force must be greater than the lateral component of the tool string weight acting perpendicular to the wellbore or casing wall. Thus, greater centralizing force is required at greater well deviation. If the centralizing force is too small, the centralizer will collapse and the tool sensors will not be centered. If the centralizing force is too great, the excessive force will cause unnecessary drag that can prevent the tool from falling or cause stick-slip motion of the logging tool. Stick-slip refers to places where the tool moves up the wellbore in a series of jerks rather than at a constant velocity. Stick-slip motion will damage or possibly invalidate the measurement data acquired. The practical limit for gravity fall using arch spring centralizers is about 60 degrees from vertical. The wellbore is vertical at shallow depths and becomes deviated as the depth increases. Thus, the centralizing force required will vary within the same wellbore. Since the arch spring centralizer must be constructed for the highest deviation, the drag force is always greater than the required drag force for most of the survey interval.

[0015] With a bow spring centraliser, the centralising force is greater in a small borehole as the leaf spring has a greater deflection (more compression) than in a large borehole. Therefore, a stronger or multiple bow spring is required in larger borehole sizes. These centralisers often have a "booster" kit to apply a greater centralising force in larger boreholes or boreholes with higher deviation.

[0016] At deviations greater than 60 degrees, other methods must be used to overcome the frictional forces and enable the tool string to be lowered in the borehole. One method is to use a drive device (tractor) attached to the tool string. The tractor contains powered wheels that can be forced into contact with the borehole wall in order to drive the tool string downhole. Another method is to push the tool string downhole with a drill pipe or coiled tubing. These methods involve additional risk, more equipment and involve more time and therefore are much more costly.

[0017] To reduce the resistance of the centraliser, wheels can be attached to the centre of the bow spring to contact the borehole wall. However, the fundamental problem associated with leaf spring collapse or over energising still exists.

[0018] Another known type of centraliser consists of a set of levers or arms with wheels at or near the point where the levers are pivotally connected together. There are multiple sets of lever wheel assemblies azimuthally arranged around the central axis of the device. Typically there are three to six sets. The ends of each lever set are connected to blocks that can freely slide axially on a central shaft of the centralising device. Springs are used to force the blocks to slide towards each other, thereby forcing the arms to deflect at an angle to the axis of the centraliser (and tool string) so that the wheels can extend radially outwards to apply force against the borehole wall. For this type of device, the centralising force is dependent on the type and arrangement of the energising equipment or springs. The centraliser device is typically energised by means of axial or radial springs or a combination of both. The advantage of this type of centraliser is that the resistance is reduced by the wheels rolling along the borehole wall rather than sliding.

[0019] The centraliser device can also be energised by a spring device that directly applies a radially outward force. Such a spring device can be a coil spring, a torsion spring or a leaf spring acting between the centraliser arms and the central shaft. For a leaf spring acting on hinged arms or a coil spring arranged radially from the centraliser / tool string axis, the limitations described above for the bow spring centraliser still apply. That is, the centralising force is greater in a small borehole than in a large borehole where the spring is subjected to a greater deflection in the small borehole. As the deviation increases, a greater centralising force is required. If the centralising force is too small, the centraliser will collapse and the tool sensors will not centralise. If the centralising force is too great, the excessive force will cause unnecessary resistance that can prevent the tool from being lowered or cause stick-slip motion of the logging tool.

[0020] The reference in this specification to any prior publication is not, and should not be taken to be, an acknowledgment or any form of suggestion that that prior publication forms part of the common general knowledge in the field of endeavour in any country. SUMMARY

[0021] It is an object of the present invention to address any one or more of the above mentioned problems or at least to provide the industry with an useful device for centering a sensor assembly in a barrel or pipe.

[0022] According to a first aspect of the present invention, there is provided a device for centering a sensor assembly in a barrel, the device comprising:

[0023] a mandrel;

[0024] a first support member and a second support member, the first support member and the second support member being axially spaced apart along a central longitudinal axis of the device, one or both of the first support member and the second support member being adapted for axial movement along the mandrel;

[0025] a plurality of arm assemblies, the plurality of arm assemblies being circumferentially spaced apart about the longitudinal axis of the device and connected between the first support member and the second support member, each arm assembly comprising:

[0026] a first arm pivotally connected to the first support member by a first pivot joint having a first pivot axis,

[0027] a second arm pivotally connected to the second support member by a second pivot joint having a second pivot axis, the first arm and the second arm being pivotally connected together via a third pivot joint having a third pivot axis, and

[0028] wherein the third pivot axis is located on a first side of a plane coinciding with the longitudinal axis of the device, and the first pivot axis and the second pivot axis are located radially outward of an outer diameter of the mandrel on an opposite second side of the plane, and

[0029] wherein the first pivot joint and the second pivot joint are azimuthally aligned, and the first pivot joint and the second pivot joint are azimuthally misaligned by 180 degrees from the third pivot joint.

[0030] In some embodiments, the first pivot axis and the second pivot axis do not intersect the mandrel.

[0031] In some embodiments, the third pivot joint is radially outward of the outer diameter of the mandrel.

[0032] In some embodiments, the plane is a first plane, and the first pivot joint and the second pivot joint are aligned on a second plane coinciding with the longitudinal axis of the centralizer, the second plane being orthogonal to the first plane.

[0033] In some embodiments, the plane is a first plane, and the first, second, and third pivot joints are aligned on a second plane coincident with the longitudinal axis of the centralizer, the second plane being orthogonal to the first plane.

[0034] In some embodiments, the plane is a first plane, and the first, second, and third pivot joints and / or the wheels carried by the arm assemblies to contact the wellbore wall are aligned on a second plane coincident with the longitudinal axis, the second plane being orthogonal to the first plane.

[0035] In some embodiments, each arm assembly extends or curves circumferentially around and along the longitudinal axis of the centralizer.

[0036] In some embodiments, each arm assembly extends helically around and along the longitudinal axis.

[0037] In some embodiments, the arm assemblies are circumferentially nested or intertwined around the mandrel.

[0038] In some embodiments, the arm assemblies are arranged such that the first pivot joints and first pivot axes of the arm assemblies are aligned on a first plane orthogonal to the longitudinal axis, and the second pivot joints and second pivot axes of the arm assemblies are aligned on a second plane orthogonal to the longitudinal axis.

[0039] In some embodiments, the arm assemblies are arranged such that the third pivot joints and third pivot axes are aligned on a third plane orthogonal to the longitudinal axis.

[0040] In some embodiments, the device includes one or more spring elements to bias the arm assemblies radially outward. In some embodiments, the device includes one or more spring (axial) elements acting on the first and / or second support members to bias the first and second support members axially together and the arm assemblies radially outward.

[0041] In some embodiments, the device includes one or more (radial) spring elements acting on one or more of the arm assemblies to bias the arm assemblies radially outward.

[0042] In some embodiments, the one or more spring elements are configured together at an angle (A) that:

[0043] i) is within a range between a line extending through the first and third pivot axes and the longitudinal axis, and / or

[0044] ii) is within a range between a line extending through the second and third pivot axes and the longitudinal axis,

[0045] such that each arm assembly provides a substantially constant radial force for a range of wellbore diameters.

[0046] In some embodiments, the angle (A) is maintained in a range substantially greater than 10 degrees and substantially less than 75 degrees.

[0047] i) between a line extending through the first and third pivot axes and the longitudinal axis, and / or

[0048] ii) between a line extending through the second and third pivot axes and the longitudinal axis,

[0049] is maintained in a range substantially greater than 10 degrees and substantially less than 75 degrees.

[0050] In some embodiments, the angle (A) is maintained in a range of 25 degrees to 65 degrees.

[0051] In some embodiments, the centraliser is a passive device, wherein energisation of the arm assemblies radially outwardly is provided solely by one or more spring elements of the device.

[0052] In some embodiments, the mandrel comprises a plurality of facets spaced around an outer surface of the mandrel, and the first and / or second support members have a corresponding plurality of facets spaced around an inner surface of the support members to rotationally key the first and / or second support members to the mandrel.

[0053] In some embodiments, the facets are arranged such that the mandrel has a polygonal outer surface and the first and / or second support members have a corresponding polygonal inner surface.

[0054] According to a second aspect of the application, there is provided a wireline tool string comprising one or more elongate sensor assemblies and a device for centralising the wireline tool string in a wellbore during a wireline logging operation, the device being as described in any one or more of the above.

[0055] According to a third aspect of the application, there is provided a device for centralising a sensor assembly in a wellbore, the device comprising:

[0056] a first support member and a second support member, the first and second support members being axially spaced along a longitudinal axis of the device;

[0057] a plurality of arm assemblies, the plurality of arm assemblies being circumferentially spaced around the longitudinal axis of the device and connected between the first and second support members, each arm assembly comprising:

[0058] a first arm pivotally connected to the first support member by a first pivot joint having a first pivot axis,

[0059] a second arm pivotally connected to the second support member by a second pivot joint having a second pivot axis, the first and second arms being pivotally connected together via a third pivot joint having a third pivot axis,

[0060] wherein the first and third pivot axes lie on a first side of a plane coincident with the central longitudinal axis of the device, and the second pivot axis lies on an opposite second side of the plane, and the first and second pivot joints are azimuthally offset by 180 degrees about the central longitudinal axis of the device.

[0061] In some embodiments, one or both of the first and second support members are adapted for axial movement along the longitudinal axis to allow the arm assemblies to radially extend and retract relative to the longitudinal axis.

[0062] In some embodiments, the first arm is of different length than the second arm such that the distance between the second and third pivot axes is different than the distance between the first and third pivot axes.

[0063] In some embodiments, the angle between a line extending between the first and third pivot axes and the longitudinal axis is less than the angle between a line extending between the second and third pivot axes and the longitudinal axis.

[0064] In some embodiments, each arm assembly includes a wheel to contact the wellbore wall.

[0065] In some embodiments, the wheel is rotationally coupled to the first or second arm on an axis of rotation that is perpendicular to the longitudinal axis and offset from the third pivot axis.

[0066] In some embodiments, the device includes one or more spring elements to bias the arm assemblies radially outward.

[0067] In some embodiments, the device includes one or more spring (axial) elements acting on the first and / or second support members to bias the first and second support members axially together and to bias the arm assemblies radially outward.

[0068] In some embodiments, the device includes one or more (radial) spring elements acting on one or more of the arm assemblies to bias the arm assemblies radially outward.

[0069] In some embodiments, the one or more spring elements are configured together such that the angle (A) between a line extending through the second and third pivot axes and the longitudinal axis is within a range such that each arm assembly provides a substantially constant radial force for a range of wellbore diameters.

[0070] In some embodiments, an angle (A) between a line extending through the second and third pivot axes and the longitudinal axis is maintained in a range substantially greater than 10 degrees and substantially less than 75 degrees.

[0071] In some embodiments, an angle (A) between a line extending through the second and third pivot axes and the longitudinal axis is maintained in a range of 25 degrees to 65 degrees.

[0072] In some embodiments, the plane is a first plane, and the first and second pivot joints are aligned on a second plane coincident with the longitudinal axis of the centralizer, the second plane being orthogonal to the first plane.

[0073] In some embodiments, the plane is a first plane, and the first, second, and third pivot joints are aligned on a second plane coincident with the longitudinal axis of the centralizer, the second plane being orthogonal to the first plane.

[0074] In some embodiments, the plane is a first plane, and the first and third pivot joints and / or wheels carried by the arm assembly to contact the wellbore wall are aligned on a second plane coincident with the longitudinal axis, the second plane being orthogonal to the first plane.

[0075] In some embodiments, the second arm extends circumferentially about the longitudinal axis to position the second pivot joint on an opposite side of the plane.

[0076] In some embodiments, the second arm extends helically about and along the longitudinal axis.

[0077] In some embodiments, the centralizer is a passive device, wherein energizing of the arm assembly radially outward is provided by only one or more spring elements of the device.

[0078] In some embodiments, the device has a mandrel and the first and / or second support members are adapted to move axially along the mandrel, and the mandrel includes a plurality of facets spaced about an outer surface of the mandrel, and the first and / or second support members have a corresponding plurality of facets spaced about an inner surface of the support member to rotationally key the first and / or second support members to the mandrel.

[0079] In some embodiments, the facets are arranged such that the mandrel has a polygonal outer surface and the first and / or second support members have a corresponding polygonal inner surface.

[0080] According to a fourth aspect of the application, there is provided a wireline tool string comprising one or more elongate sensor assemblies and a device for centralizing the wireline tool string in a wellbore during a wireline logging operation, the device being as described in relation to the third aspect.

[0081] According to a fifth aspect of the application, there is provided a device for centering a sensor assembly in a cartridge, the device comprising:

[0082] a mandrel;

[0083] a first support member and a second support member axially spaced apart along a central longitudinal axis of the device, the first support member and the second support member being adapted for axial movement along the mandrel;

[0084] a plurality of arm assemblies circumferentially spaced apart around the central longitudinal axis of the device and connected between the first support member and the second support member, each arm assembly comprising:

[0085] a first arm pivotally connected to the first support member by a first pivot joint having a first pivot axis,

[0086] a second arm pivotally connected to the second support member by a second pivot joint having a second pivot axis, the first arm and the second arm being pivotally connected together via a third pivot joint having a third pivot axis, and

[0087] wherein the third pivot axis is located on a first side of a plane coinciding with the central longitudinal axis of the device, and at least one of the first pivot axis and the second pivot axis is located on an opposite second side of the plane, and wherein the first pivot axis and the second pivot axis are located radially outside an outer diameter of the mandrel, and

[0088] wherein:

[0089] (i) in case both the first pivot axis and the second pivot axis are located on the second side of the plane, the first pivot joint and the second pivot joint are azimuthally aligned, and the first pivot joint and the second pivot joint are azimuthally misaligned by 180 degrees around the central longitudinal axis of the mandrel from the third pivot joint, or

[0090] (ii) in case one of the first pivot axis and the second pivot axis is located on the second side of the plane, one of the first pivot joint and the second pivot joint is azimuthally aligned with the third pivot joint, and the first pivot joint and the second pivot joint are azimuthally misaligned by 180 degrees around the central longitudinal axis of the device.

[0091] According to a sixth aspect of the application, there is provided a device for centering a sensor assembly in a cartridge, the device comprising:

[0092] a mandrel;

[0093] a first support member and a second support member, the first support member and the second support member being axially spaced along a central longitudinal axis of the device, the first support member and the second support member being adapted for axial movement along the mandrel;

[0094] a plurality of arm assemblies, the plurality of arm assemblies being circumferentially spaced about the central longitudinal axis of the device and connected between the first support member and the second support member, each arm assembly comprising:

[0095] a first arm pivotally connected to the first support member by a first pivot joint having a first pivot axis,

[0096] a second arm pivotally connected to the second support member by a second pivot joint having a second pivot axis, the first arm and the second arm being pivotally connected together via a third pivot joint having a third pivot axis, and

[0097] wherein the third pivot axis is located on a first side of a first plane coinciding with the central longitudinal axis of the device, and at least one of the first pivot axis and the second pivot axis is located on an opposite second side of the first plane, and

[0098] wherein the first pivot axis and the second pivot axis are located radially outside an outer diameter of the mandrel, and

[0099] wherein the first pivot joint, the second pivot joint and the third pivot joint and / or wheels carried by the arm assemblies to contact the barrel wall are aligned on a second plane coinciding with the central longitudinal axis, wherein the second plane is orthogonal to the first plane.

[0100] According to a seventh aspect of the present invention, there is provided a device for centering a sensor assembly in a barrel, the device comprising:

[0101] a mandrel;

[0102] a first support member and a second support member, the first support member and the second support member being axially spaced along a central longitudinal axis of the device, one or both of the first support member and the second support member being adapted for axial movement along the mandrel;

[0103] a plurality of arm assemblies, the plurality of arm assemblies being circumferentially spaced about the central longitudinal axis of the device and connected between the first support member and the second support member, each arm assembly comprising:

[0104] a first arm pivotally connected to the first support member by a first pivot joint having a first pivot axis,

[0105] a second arm pivotally connected to the second support member by a second pivotal joint having a second pivotal axis, the first and second arms being pivotally connected together via a third pivotal joint having a third pivotal axis,

[0106] wherein the mandrel comprises a plurality of facets spaced around an outer surface of the mandrel, and the first and / or second support member has a corresponding plurality of facets spaced around an inner surface of the support member to rotationally key the first and / or second support member to the mandrel.

[0107] In some embodiments, the facets are arranged such that the mandrel has a polygonal outer surface and the first and / or second support member has a corresponding polygonal inner surface. Preferably, the polygon is a regular polygon, for example the mandrel can have a hexagonal or octagonal outer surface. In some embodiments, the outer surface of the mandrel has a facet aligned in an azimuthal direction with an adjacent first or second pivotal joint at the first or second support member. The number of facets can be equal to the number of arm assemblies. The mandrel can have a facet extending between adjacent first or second pivotal joints such that the number of facets is equal to the number of arm assemblies or twice the number of arm assemblies. For example, the centralizer comprises four arm assemblies and the mandrel comprises eight facets or an octagonal outer surface, and wherein the first and / or second support member has a corresponding octagonal inner surface, or in an alternative embodiment, the centralizer comprises three arm assemblies and the mandrel comprises six facets or a hexagonal outer surface, and wherein the first and / or second support member has a corresponding hexagonal inner surface.

[0108] The fifth, sixth and / or seventh aspects of the application can include any one or more of the features described above in relation to the first to fourth aspects of the application.

[0109] In the above seven aspects of the application, the apparatus can be adapted to centralize a wireline logging tool in a wellbore during a wireline logging operation.

[0110] Unless otherwise stated, the term "wellbore" can refer to both cased and uncased wellbores. Thus, the term "wellbore wall" can refer to the wall of the wellbore or the wall of a casing within the wellbore.

[0111] Unless otherwise stated, the term "tool string" refers to an elongate sensor package or assembly, also known in the industry as a "logging tool", and can include components other than sensors, such as guiding and orienting devices and carrier devices attached to the sensor components or tool string assemblies. The tool string can comprise a single elongate sensor assembly, or two or more sensor assemblies connected together.

[0112] Unless the context clearly requires otherwise, throughout the description and the claims, the words "comprise", "comprising", and the like are to be construed in an inclusive sense as opposed to an exclusive or exhaustive sense, that is, in the sense of "including, but not limited to".

[0113] In the foregoing description, reference has been made to specific components or whole of the application having known equivalents, then such equivalents are incorporated as if individually set forth.

[0114] The application can also be said broadly to consist in the parts, elements and features referred to or indicated in the specification of the application, individually or collectively, in any or all combinations or sub-combinations of two or more of said parts, elements or features, and where specific integers are mentioned herein which have known equivalents in the art to which the application relates, such known equivalents are deemed to be incorporated in the specification of the application by reference.

[0115] Other aspects of the application that should be considered in all its novel aspects will become apparent from the following description, given by way of example of possible embodiments thereof, and the description given with respect to the drawings that accompany the present application. BRIEF DESCRIPTION OF DRAWINGS

[0116] Reference will now be made to the drawings to discuss example embodiments of the application.

[0117] Figure 1 is a schematic illustration of a wellsite and tool string descending along a wellbore in a wireline logging operation.

[0118] Figures 2A to 2G A schematic illustration of a centralizing device (centralizer) is provided in accordance with one embodiment of the application. Figure 2A is a side view of the centralizer with the arm assemblies of the centralizer in a radially outward position corresponding to a larger wellbore diameter. Figure 2B shows the arm assemblies in a radially inward position corresponding to a smaller wellbore diameter. Figure 2C and 2D is an end view with the arm assemblies in radially outward and radially inward positions. Figure 2E and 2F is an isometric type view again showing the arm assemblies in radially outward and radially inward positions. Figure 2G is a cross-sectional view on line A-A in Figure 2A , on the centerline (longitudinal axis) of the centralizer, with the arm assemblies in a radially outward position.

[0119] Figures 2H to 2J schematic cross-sectional views on lines D-D, C-C and B-B lines as shown in Figure 2A , respectively, are provided.

[0120] Figures 3A to 3G shows Figures 2A to 2Gis a side view of the centralizer, but only one arm assembly is shown to highlight the relative position of the pivot axis of the pivot joint of the arm. Figure 3A is a side view. Figure 3B is another side view of the view Figure 3A orthogonal to Figure 3C is a cross-sectional view on the centerline (longitudinal axis) of the centralizer on line E-E in Figure 3B are cross-sectional views on lines F-F, G-G and H-H as shown in Figure 3A are isometric views. Figure 3G

[0121] Figure 4A and 4B show two centralizers that include a radially acting spring.

[0122] Figure 5A and 5B show centralizers similar to those of Figure 2A and 2G but where the rotational axis of the wheel of each arm assembly is offset from the third pivot joint. Figure 5A is a side view, while Figure 5B is an isometric view.

[0123] Figure 6 A chart is provided of the mechanical advantage (lever force) versus the angle of the arm assembly of a centralizer device, where the angle is the angle between the arm of the arm assembly of the centralizer and the central or longitudinal axis of the centralizer, in Figure 2A and 2B is angle A.

[0124] Figure 7 A chart is provided of the mechanical advantage (lever force), spring force, and the resulting radial force exerted by the arm assembly of a centralizer according to the present invention on the wellbore wall versus the radial deflection of the arm assembly.

[0125] Figures 8A to 8C is a schematic diagram providing a comparison between centralizer configurations. Figure 8A shows a configuration where all three pivot joints and pivot axes of each arm assembly are on one side of the plane that coincides with the longitudinal axis of the centralizer. Figure 8B shows a configuration where the third or intermediate pivot joint and pivot axis are at the respective end of the arm assembly on a first side of the plane that coincides with the longitudinal axis of the centralizer and the first and second pivot joints and pivot axes are on an opposite second side of the plane. Figure 8C ​A construction is shown in accordance with an aspect of the application having a first pivot joint and pivot axis at a first end of the arm assembly, and a third or intermediate pivot joint and pivot axis of the arm assembly on a first side of a plane coincident with the longitudinal axis of the centralizer, and a second pivot joint and pivot axis at an opposite second end of the arm assembly on an opposite second side of the plane.

[0126] Figure 9 A comparison chart of the radial force versus radial deflection characteristics of three centralizer devices is provided; a centralizer having a "proximal" pivot construction Figure 8A , a centralizer having a "distal" pivot construction Figure 8B , and a centralizer having a "hybrid" pivot construction Figure 8C .

[0127] Figures 10A to 10E An alternate centralizer device having a "distal" pivot construction is shown. Figure 10A is a side view of the centralizer with the arm assembly of the centralizer in a radially outward position corresponding to a larger wellbore diameter. Figure 10B is shown in a radially inward position corresponding to a smaller wellbore diameter. Figure 10C is a cross-sectional view on line I-I in Figure 10A of the centralizer on the centerline (longitudinal axis) of the centralizer.

[0128] Figure 10D and 10E are isometric type views again showing the arm assembly in the radially outward and radially inward positions.

[0129] Figures 10F to 10H schematic cross-sectional views on lines L-L, K-K and J-J lines as shown in Figure 10A are provided, respectively.

[0130] Figure 11A and 11B show Figures 10A to 10D the centralizer, but only one arm assembly is shown to highlight the relative positions of the pivot axes of the pivot joints of the arms. Figure 11A is a side view, while Figure 11B is an isometric view.

[0131] Figure 12A and 12B show an alternate centralizer device having a "distal" pivot construction. Figure 12A is a side view of the centralizer with the arm assembly of the centralizer in a radially outward position corresponding to a larger wellbore diameter. Figure 12B is an isometric type view again showing the arm assembly in the radially outward position.

[0132] Figures 13A to 13CAn alternative centralizer device is shown with a "distal" pivot configuration. Figure 13A is an isometric type view showing the arm assembly in a radially outward position. Figure 13B is also an isometric view, but with one spring omitted to show the polygonal mandrel. Figure 13C is a cross-sectional view through the support member and mandrel in a plane lateral to the longitudinal axis of the device.

[0133] Figures 14A to 14F An alternative centralizer device is shown with a "distal" pivot configuration with 5 arms. Figure 14A is a side view of the centralizer with the arm assembly of the centralizer in a radially outward position corresponding to a larger wellbore diameter. Figure 14B is an end view, and Figure 14C is an isometric type view showing the arm assembly in a radially outward position. Figure 14D is a side view of the centralizer with the arm assembly of the centralizer in a radially inward position corresponding to a smaller wellbore diameter. Figure 14E is an end view, and Figure 14F is an isometric type view showing the arm assembly in a radially inward position.

[0134] Figure 15 A variable pitch coil spring is shown that is configured to provide a variable spring rate. DETAILED DESCRIPTION

[0135] Figure 1 A schematic view of a wellsite 100 is provided. A logging tool string 101 is lowered down a wellbore 102 on a cable 103. The wellsite surface equipment includes a typical pulley 104 suspended from a derrick and a drawworks unit 105 for paying out and taking up the cable to and from the wellbore to deploy and retrieve the logging tool 101 from the wellbore for a wellbore wireline logging operation. The logging tool string 101 can include one or more logging tools, each carrying one or more sensors 106, coupled together to form the logging tool string 101. The cable 102 includes a plurality of wires or cables to provide power to the one or more sensors 106 and to transmit sensor data to the wellsite surface. One or more centralizer devices 1 are provided to the logging tool 101 to centralize the logging tool 101 in the wellbore 102.

[0136] Figures 2A to 2Gis a schematic view of a centralizing device 1 that would be provided with the tool string 101 or as part of the tool string 101. The centralizing device (or centralizer) includes a coupling 2 or interface at each end to connect the centralizer 1 to other components of the tool string 101. The coupling can include electrical or hydraulic connections to provide electrical and hydraulic communication between the electrical cable and the wireline logging tool and / or wireline tool. Alternatively, the centralizer device can be integral with the wireline logging tool, e.g., the outer housing of the logging tool can form the central mandrel of the centralizer. Alternatively, the centralizer device can slide over the outside of the wireline logging tool (housing), thereby avoiding any electrical or hydraulic connections with the tool string and electrical cable. The coupling or interface can be any suitable coupling or interface known in the art. A plurality of arm assemblies (linkages) 3 are spaced circumferentially around the longitudinal axis 4 of the device 1. In the illustrated embodiment, there are four arm assemblies 3, however, the centralizer can have three or more arm assemblies, e.g., five or six arm assemblies. The arm assemblies 3 are configured to move axially and radially to engage the wellbore wall 102a to provide centralizing forces to keep the tool string 101 centered in the wellbore 102.

[0137] Each arm assembly or linkage 3 includes a first arm or link 5 and a second arm or link 6. The first arm 5 is pivotally connected to a first support member 7 by a first pivot joint 9, while the second arm 6 is pivotally connected to a second support member 8 by a second pivot joint 10. The first and second arms 5, 6 are pivotally attached together by a third pivot joint 11. Each pivot joint 9, 10, 11 has a pivot pin or shaft about which the arms 5, 6 pivot about a pivot axis 9a, 10a, 11a, which is the axis of the pin or shaft. One or both support members 7, 8 are adapted for axial movement, such that each arm assembly 3 is radially moved by pivoting of the first 9, second 10, and third 11 pivot joints to engage the wellbore wall 102. One or both support members 7, 8 can axially slide on a central member or mandrel 12 of the centralizer 1. For example, the support members 7, 8 can include a collar or ring member that is co-linear with and received on the mandrel 12 for sliding thereon. Each support member 7, 8 can include multiple components assembled together about the mandrel 12.

[0138] The support members 7, 8 can be keyed to the mandrel to rotationally fix the support members to the mandrel such that the support members move axially on the mandrel without relative rotation between the support members and the mandrel. For example, one of the mandrel and support members can include a longitudinal "rail" or protrusion to engage with a corresponding longitudinal channel or slot of the other of the mandrel and support members (see, e.g., the embodiments described below with respect to Figs. 6-8). Figure 12A and 12B

[0139] ​The centralizer 1 has one or more spring elements 13 to provide a force to the arm assembly 3 to urge the arm assembly against the wellbore wall 102a to provide a centralizing force to centrally hold the centralizer 1 and associated tool string 101 within the wellbore 102. In the illustrated embodiment, both the first and second support members 7, 8 are axially movable and the centralizer 1 has an axial spring 13 acting on each support member 7, 8 to bias the support members 7, 8 axially together to bias the arm assembly 3 radially outward against the wellbore wall 102a. When one of the support members 7, 8 is fixed, the centralizer 1 has no spring acting on the fixed support. The axial spring(s) 13 can be a coil spring, as shown in the illustrated embodiment, which is collinear with the mandrel 12, or can also include a plurality of coil springs arranged circumferentially around the mandrel (spaced apart in azimuth). Those skilled in the art will appreciate that other types of springs and spring configurations can be used to power the centralizer, such as torsion springs, leaf springs, and Belleville washers. A combination of two or more spring devices can also be used, for example, one or more springs can be provided end to end to impart a non-linear spring rate to the combination. Alternatively, the pitch of the coil spring can vary over its length to provide a non-linear spring rate. The centralizer can additionally or alternatively have spring elements that directly apply a radially outward force to the arm assembly. For example, a coil spring or leaf spring can be located between the first arm and the mandrel and / or between the second arm and the mandrel to provide a radial force as shown in Figure 4A (leaf spring 15) and Figure 4B (coil spring 16). The centralizer according to the present application can have only axial springs, only radial springs, or a combination of axial and radial springs. A combination of axial and radial acting springs can be used to provide a relatively constant radial force.

[0140] Preferably, each arm assembly 3 includes a roller or wheel 14 located at or near the third pivot joint 11 to contact the wellbore wall 102a to reduce friction between the wellbore wall 102a and the tool string 101 as the tool string 101 is passed through the wellbore 102. As shown in Figure 2A the roller 14 can have a rotational axis that is collinear with the pivot axis 11a of the third pivot joint 11, or can be located adjacent to the third pivot joint 11, for example the roller can be rotatably mounted to the first arm or the second arm adjacent to the third pivot axis. Figure 5A and 5B an embodiment is shown having a similar construction to the centralizer of Figures 2A to 2G but with the roller 14 mounted to the first arm 5 adjacent to the third pivot axis 11a with the rotational axis of the roller 14 parallel to the third pivot axis.

[0141] Each linkage or arm assembly 3 provides a mechanical advantage (mechanical leverage) between axial displacement and radial displacement to combine the axial spring element 13 to provide a radial force to the wellbore wall 102a. Since the support members 7, 8 are linked by a plurality of arm assemblies 3, the displacement of each arm assembly is equal to the axial displacement of the support members, thereby centering the centralizer and tool string within the wellbore. The mechanical advantage varies with the axial and radial position of the arm assembly 3. The mechanical advantage of the arm assembly 3 can be expressed as Fr / Fa, where Fa is the axial force provided by the axial spring element(s) 13 on the arm assembly and Fr is the resulting radial force applied to the wellbore wall 102a. As the mechanical advantage increases, the radial force transferred from the axial spring force to the wellbore wall also increases. The mechanical advantage depends on the angle A between each arm and the centerline of the device (in Figure 2A and 2B increases as the angle A increases, as shown in the graph of mechanical advantage versus angle A plotted in Figure 6 Thus, the mechanical advantage of the arm assembly 3 increases as the wellbore diameter increases. In balance with the mechanical advantage, the force provided by the spring 13 decreases as the wellbore diameter increases, since the support members 7, 8 slide axially as the wellbore diameter increases to allow the spring to decompress. Conversely, as the wellbore diameter decreases, the mechanical advantage decreases, and the axial spring force increases as the spring is further compressed by the sliding support members.

[0142] It should be understood that the angle between the arm and the centerline is defined as the angle between a line extending through the respective two ends of the arm and the longitudinal axis. For example, the angle A between the second arm 6 and the longitudinal axis 4 is the angle A between a line extending through the second pivot axis 10a and the third pivot axis 11a and the longitudinal axis 4.

[0143] Preferably, the centralizer 1 provides a relatively constant centralizing force over a range of wellbore diameters. The radial force applied by the centralizer 1 is the product of the axial spring force provided by the spring(s) 13 and the mechanical advantage of the arm assembly 3. Since the axial force increases as the mechanical advantage decreases, by optimizing the spring stiffness, spring preload, and the geometry of the mechanical arm assembly, a relatively constant radial force can be achieved for a range of wellbore diameter sizes by balancing the spring force and the mechanical advantage. Figure 7 The radial force of an axial spring centralizer is shown, which is designed to operate in casing sizes with diameters between 224 mm and 130 mm (a diameter range of 94 mm, which corresponds to a radial range of 47 mm for each arm assembly from 112 mm to 65 mm). Over this diameter range, the radial force remains in the range of about 1000 to 1500 N (224 to 336 pound force). In Figure 7The centralizing force is approximately 1250 N ± 250 N, which is considered relatively constant for the practical function of centralizing the tool string 101 in the wellbore 102.

[0144] To achieve a relatively constant radial force against the wellbore wall 102a, the angle A between the arms 5, 6 of the arm assembly 3 and the central axis 4 of the device 1 should be limited to avoid very large angles and very small angles. At large angles between the longitudinal axis 4 and the arms 5, 6 of the arm assembly 3 (angles close to 90 degrees), a small axial spring force will result in a high radial force applied to the wellbore wall 102a. High radial forces can result in greater frictional forces as the logging tool string traverses the wellbore. High frictional forces can prevent the tool string from descending under the force of gravity and can result in stick-slip, where the tool moves up the wellbore in a series of jerks rather than at a constant velocity, affecting the accuracy of the data collected. When the arms are at large angles, more radial force is required to collapse the centralizer. This makes it difficult for the centralizer to descend into smaller diameter casings (e.g., from 9 5 / 8 inch casing to 7 inch liner). The arms of the centralizer can even get stuck by the wellhead control assembly, which consists of a stack of hydraulic rams and valves for wellhead control and safety (to close in case of a blowout).

[0145] Conversely, at small angles between the longitudinal axis and the arms 5, 6 of the arm assembly 3 (angles close to 0 degrees), a large axial spring force is required to provide sufficient radial force to centralize the tool string. Furthermore, the axial displacement of the support member(s) 7, 8 is very small relative to the radial displacement (the outer diameter of the centralizer 1), which results in the centralizer device 1 being unable to centralize the tool string 101 in small diameter wellbores. For example, at an arm angle of 10 degrees, a 10 mm change in centralizer diameter (5 mm radial displacement) results in less than 1 mm of axial displacement. With such small axial movement of the support members 7, 8, the play in the pivot points 9, 10, 11, bearings and sliding support members 7, 8 results in the centralizer device being unable to centralize the tool string, as the radial displacement in one of the arm assemblies is not accurately transferred to the other arm assemblies through the support members 7, 8 and pivot joints 9, 10. This results in the device 1 being off-center, which in turn results in the tool string sensors 106 returning false data. At small arm angles, the radial force can be increased by including radial reinforcement springs as described above with reference to Figure 4A and 4B The logging tool will be off-center by a distance determined by the weight of the tool acting perpendicular to the wellbore wall and the spring stiffness of the radial springs.

[0146] Additionally or alternatively, variable stiffness springs can be axially applied to the sliding support members 7, 8 and / or radially to each arm assembly to provide increased spring force at small angles between the longitudinal axis of the arm assembly and the arms 5, 6 where the mechanical advantage is reduced, and decreased spring force at large angles between the longitudinal axis of the arm assembly and the arms 5, 6 where the mechanical advantage is increased. For example, variable pitch coil springs can be axially provided to the sliding support members 7, 8 and / or radially disposed between the arms 5, 6 and the mandrel such that as the coil spring is compressed, the spring stiffness increases. Variable pitch springs are shown in Figure 15 The variable stiffness springs can be designed such that the variable spring stiffness in combination with the variable mechanical advantage provided by the arm assemblies achieves a constant radial force for a range of wellbore diameters. However, even with variable stiffness springs, there is difficulty in centering at small angles. At small angles, large changes in wellbore diameter cause only very small changes in the axial displacement of the support members 7, 8. Thus, the deflection of one arm assembly is difficult to transfer to the other arm assemblies via the axial deflection of the support members, and the arms do not deflect uniformly. When this occurs, the device is no longer used to center the tool, and the arms act independently of one another. Extremely high precision tolerances between components are required to ensure that all of the arms deflect uniformly to achieve centering. The machining tolerances required to achieve centering at small arm angles can be impractical.

[0147] The inventors have determined that the angle between at least one arm of the arm assembly and the longitudinal axis should ideally be in the range of about 30° to 60°. For angles much below 30°, the mechanical advantage requiring high spring loads decreases, and centering is not possible due to actual component tolerances. For angles much above 60°, the mechanical advantage is too great, presenting increased sensitivity and high wellbore wall loads. Furthermore, at angles much above 60°, the tool string can not be able to pass from a larger diameter casing to a smaller diameter casing because the arms 3 of the centralizer can "hang up" on the ledge formed between the larger diameter casing and the smaller diameter casing. The angle is preferably much greater than 10 degrees and much less than 75 degrees. By way of example, Figure 7 The radial deflection in FIG. 1 involves arm angles of 26° to 57°. The angle is preferably limited to the range of 20 to 70 degrees, or more preferably to the range of 25 to 65 degrees.

[0148] By positioning the first and second pivot joints on opposite sides of a plane coincident with the longitudinal axis of the centralizer opposite the third pivot joint, while maintaining the angle between the arm assembly 3 and the longitudinal axis 4 between the usable limits, e.g., 30 degrees and 60 degrees, to achieve a relatively constant radial force, an improved range of radial motion can be achieved.

[0149] Figure 8AA schematic view of a centralizer is provided in which the first pivot joint 9 and the second pivot joint 10 are located on the same side of the plane coincident with the longitudinal axis 4 as the third pivot joint 11 (this configuration is referred to herein as a "proximal" pivot). In contrast, Figure 8C A schematic view of a centralizer is provided in which the third pivot joint 11 is located on a first side of the plane coincident with the longitudinal axis 4 of the centralizer and the first pivot joint 9 and the second pivot joint 10 are located on an opposite second side of the plane (this configuration is referred to herein as a "distal" pivot). Figure 8A and 8C This comparison between the arrangements of Figure 8C the distal pivot configuration achieves a greater radial range, and thus a centralizer provided can be used for a greater range of wellbore diameters. Thus, the distal pivot configuration is more preferable than the proximal pivot configuration in providing a centralizer suitable for a greater range of wellbore diameters. Furthermore, in order to achieve a range of arm angles of 30 to 60 degrees, Figure 8A the arms in the proximal configuration must be relatively short. Shorter arms result in a smaller axial displacement, and thus require very stiff springs to achieve the radial force required to centralize the tool string, which makes the engineering of the device more complex.

[0150] The inventors have determined that a benefit can be achieved by locating only one of the first pivot joint 9 and the second pivot joint 10 on the opposite second side of the plane coincident with the longitudinal axis of the centralizer, as shown in the schematic view of Figure 8B and as incorporated in the centralizer of Figures 2A to 2G This configuration is referred to herein as a "hybrid" side pivot. The inventors have determined that by maintaining the angle between only one of the arms 5, 6 of the arm assembly 3 and the longitudinal axis 4 within a useful range, a relatively constant radial force can be achieved for useful mechanical advantage. As shown in Figure 8C the angle between the longitudinal axis 4 and the second arm 6 having a "distal" pivot joint, i.e. a pivot joint 10 located on the opposite side of the plane coincident with the longitudinal axis from the third pivot joint 11 (angle A in Figure 2A is maintained within a useful range to achieve a sufficiently constant radial force within an improved radial range and thus bore diameter range. Figure 8B and 8C This comparison between the arrangements of Figure 8B the hybrid side pivot arrangement of Figure 8CThe distal pivot arrangement has the same radial range. However, the radial range of the hybrid side arrangement is achieved in a shorter axial length change compared to the distal pivot arrangement. Since the axial displacement of the hybrid side arrangement is less compared to the distal arrangement, the hybrid side arrangement can be designed with shorter, stiffer springs. The axial travel of the support member 7 is denoted by L2 in Figure 8B and by L3 in Figure 8C , where L2 < L3. Thus, the hybrid side arrangement achieves a shorter centralizer length, and thus a shorter toolstring length, which is a significant benefit for guiding the toolstring along the wellbore. Furthermore, this shorter length characteristic enables the hybrid side centralizer to be retrofitted to replace existing centralizers integral to toolstrings that employ a proximal arrangement, which have insufficient space to accommodate a distal arrangement. Prior art centralizers having a proximal pivot configuration are typically integral to logging tools, where the body of the logging tool forms the mandrel 12 of the centralizer, or in other words, the arm assembly 3 and support members 7, 8 of the centralizer 1 are fitted to the body of the elongate logging tool assembly. The support members 7, 8 can be fitted to a reduced diameter section of the logging tool. By removing the existing proximal centralizer and retrofitting the hybrid side centralizer spring(s) 13, support members 7, 8 and arm assembly 3, the hybrid side arrangement can be designed to fit to logging toolstrings designed for a proximal arrangement to achieve improved centralization over a greater radial range (wellbore diameter range).

[0151] Figure 9 A comparison of the radial force versus radial deflection characteristics of three centralizer devices is presented; a centralizer having a "proximal" pivot configuration Figure 8A , a centralizer having a "distal" pivot configuration Figure 8B and a centralizer having a "hybrid side" pivot configuration Figure 8C . The distal pivot configuration achieves the greatest radial deflection or range for a given radial force band, however the hybrid side achieves a significantly superior radial deflection or range to the proximal configuration, while achieving a reduction in the axial length of the centralizer compared to the distal configuration.

[0152] Figures 2A to 2G The centralizer of the hybrid side pivot configuration Figure 8BThe first pivot joint 9 and the third pivot joint 11 are located on a first side of a plane coinciding with the longitudinal axis 4 of the centralizer 1, and the second pivot joint 10 is located on an opposite second side of the plane. The first pivot joint 9 has a first pivot axis 9a, the second pivot joint 10 has a second pivot axis 10a, and the third pivot joint 11 has a third pivot axis 11a. The axial movement of the support members 7, 8 causes the arms 5, 6 to pivot about the first, second and third pivot axes. The pivot joints 9, 10, 11 are arranged such that the first pivot axis 9a and the third pivot axis 11a are located on a first side of a plane P1 coinciding with the longitudinal axis 4 of the centralizer 1, and the second pivot axis 10a is located on an opposite second side of the plane P1.

[0153] Figures 2A to 2G The relative positions of the first pivot joint 9, the second pivot joint 10 and the third pivot joint 11 in the embodiment of Figures 2H to 2J are further illustrated in the cross-sectional view of Figure 2E and 2F . The arm assemblies 3 are labelled arm assembly 3A, 3B, 3C and 3D in Figure 2F . The first pivot joint, the second pivot joint and the third pivot joint of the arm assembly 3A are identified by reference numerals 3A-9, 3A-10 and 3A-11 in the cross-sectional view of Figures 2H to 2J . The same numbering convention applies for the arm assemblies 3B, 3C and 3D.

[0154] As Figures 2H to 2JAs shown, and with reference to arm assembly 3A, first pivot joint 3A-9 and second pivot joint 3A-10 are circumferentially spaced (i.e. azimuthally offset) by 180 degrees about the longitudinal axis 4 of the centraliser. First pivot axis 9a, second pivot axis 10a and third pivot axis 11a are parallel. Preferably, first pivot axis 9a, second pivot axis 10a and third pivot axis 11a are perpendicular to the longitudinal axis 4 of the centraliser 1. First pivot joint 3A-9 and second pivot joint 3A-10 are aligned on a plane P2 which coincides with the longitudinal axis 4 of the centraliser. Plane P2 is orthogonal to plane PI. First pivot joint 3A-9 and third pivot joint 3A-11 and / or wheel 14 can be aligned on plane P2. For example, first arm 5 can be straight or otherwise shaped such that first pivot joint 3A-9 and third pivot joint 3A-11 and / or wheel 14 lie on plane P2 and are aligned circumferentially or in azimuth. First pivot joint 3A-9 and third pivot joint 3A-11 lie on a first side of plane PI and second pivot joint 10 lies on an opposite second side of plane PI. The pivot joints 9, 10, 11 are arranged such that first pivot axis 9a and third pivot axis 11a lie on a first side of plane PI and second pivot axis 10a lies on an opposite second side of the plane PI. Second arm 6 extends or curves circumferentially about and along the longitudinal axis to position second pivot joint 3A-10 and axis 10a on opposite sides of plane PI. For example, the second arm can extend helically about and along the longitudinal axis.

[0155] The lateral alignment of the pivot joints 9, 10, 11 and wheel 14 on plane P2 reduces mechanical stresses on the pivot joints, for example by reducing bending moment and thrust loads on the joints 9, 10, 11.

[0156] As shown best in Figure 2A and 2B , the arm assemblies 3 are arranged such that the first pivot joints 9 and pivot axes 9a of the arm assemblies 3 are axially aligned. That is, all of the first pivot joints 9 and axes 9a of the arm assemblies 3 are aligned on a transverse plane (a plane orthogonal to the longitudinal axis 4, for example, a first plane extending through line D-D in Figure 2A ). Similarly, the second pivot joints 10 and axes 10a are aligned on a transverse plane (for example, a second plane extending through line B-B in Figure 2A ). Preferably, the third pivot joints 11 and axes 11a are also aligned on a transverse plane (for example, a third plane extending through line C-C in Figure 2A ).

[0157] With the first and second pivot joints and their respective axes axially aligned, the arm assemblies are nested together circumferentially around the mandrel, or in other words, the arm assemblies 3 are intertwined around the mandrel 12 much like the threads in a multi-start screw are intertwined. This arrangement enables a length-reduced centralizer compared to the case where the arm assemblies, or pairs of diametrically opposed arm assemblies, are axially spaced apart along the centralizer.

[0158] The first arm can be of different length than the second arm, such that the distance between the second pivot axis and the third pivot axis is different than the distance between the first pivot axis and the third pivot axis. For example, the distance between the first pivot axis 9a and the third pivot axis 11a can be shorter than the distance between the second pivot axis 10a and the third pivot axis 11a, as shown in Figure 2A and 3A Alternatively, the distance between the first pivot axis 9a and the third pivot axis 11a can be longer than the distance between the second pivot axis 10a and the third pivot axis 11a.

[0159] Referring to Figure 3A the angle between a line extending between the first pivot axis 9a and the third pivot axis 11a and the longitudinal axis 4 is less than the angle between a line extending between the second pivot axis 10a and the third pivot axis 11a and the longitudinal axis 4. As the length of the first arm increases, the angle B decreases. However, as noted above, the angle A should remain within a preferred range (25 to 65 degrees).

[0160] In an alternative arrangement, the first arm 5 can extend or curve (e.g., helically) circumferentially around the longitudinal axis 4 such that the first pivot joint 9 and the third pivot joint 11 are circumferentially spaced apart, i.e., misaligned in azimuthal angle. The first pivot joint 9 can be located on a first side of the plane P2 and the second pivot joint 10 can be located on an opposite second side of the plane P2. Other configurations are possible, for example, the first pivot joint 9 and the second pivot joint 10 can be located on a first side of the plane P2 with the first arm 5 and the second arm 6 extending circumferentially around the longitudinal axis to position the wheel 14 on a plane (e.g., the plane P2) that coincides with the longitudinal axis 4.

[0161] According to one aspect of the present application, the centralizer as described above provides one or more of the following benefits. The centralizer achieves a relatively constant radial force over a greater range of wellbore diameters than prior art centralizers, with all of its pivot points on the same side of the longitudinal axis of the wheels in contact with the wellbore. The centralizer achieves a range of wellbore diameters comparable to devices in which the arm assembly pivot joints are located on the opposite side of the centralizer longitudinal axis from the wheels, however, the device achieves the range of diameters with a reduced axial length. The configuration of the pivot joints allows the centralizer to provide a radial centralizing force that is not so high as to cause excessive frictional forces in smaller diameter bores within the desired range of wellbores, but yet provides sufficient radial force to centrally hold the centralizer and associated tool string in larger diameter bores. By balancing the practical mechanical advantages with the axial spring force, the centralizer is allowed to centralize the tool string even in a deviated wellbore, as in a deviated wellbore the weight of the tool string and centralizer acts against the centralizing radial force provided by the centralizer. In addition, the centralizer is a passive device that is energized only by the mechanical spring members 13. No other power input is required, such as electrical or hydraulic power provided by a power unit located at the service area. Thus, the present application provides a lower cost, effective and simplified device that provides better operational reliability and accuracy of the logging data.

[0162] Figures 10A to 10E A centralizer having a "distal" pivot configuration, as discussed above with reference to Figure 8B the embodiment of FIG. 1, is shown in FIG. 2. Features of the embodiment of FIG. 2 that are the same as or similar to features of the embodiment of FIG. 1 are referenced in the drawings with the same reference numerals as in the previous drawings, and are not described again in detail. Figures 10A to 10E Features of the embodiment of FIG. 2 that are the same as or similar to features of the embodiment of FIG. 1 are referenced in the drawings with the same reference numerals as in the previous drawings, and are not described again in detail. Figures 10A to 10E Features of the embodiment of FIG. 2 that are the same as or similar to features of the embodiment of FIG. 1 are referenced in the drawings with the same reference numerals as in the previous drawings, and are not described again in detail.

[0163] In the embodiment of FIG. 2, the centralizer 20 includes a first support member 7 and a second support member 8, and a plurality of arm assemblies 3 connected between the first and second support members. Axial movement of one or both support members 7, 8 under the action of the spring(s) 13 causes the arm assemblies 3 to move radially to engage the wellbore wall 102 by pivoting the first, second and third pivot joints 9, 10, 11, as described above for the previous embodiments. Figures 10A to 10E However, in the embodiment of FIG. 3, the centralizer 20 includes a first support member 7 and a second support member 8, and a plurality of arm assemblies 3 connected between the first and second support members. Axial movement of one or both support members 7, 8 under the action of the spring(s) 13 causes the arm assemblies 3 to move radially to engage the wellbore wall 102 by pivoting the first, second and third pivot joints 9, 10, 11, as described above for the previous embodiments.

[0164] Figures 10A to 10E ​In this configuration, each arm assembly 3, including the first arm 5 and the second arm 6, is configured such that the third pivot joint 11 is located on a first side of plane P1 coinciding with the longitudinal axis 4 of the device, and the first pivot joint 9 and the second pivot joint 10 are located on opposite second sides of plane P1. The positioning of the pivot joints 9, 10, and 11, as described and illustrated, positions the third pivot axis 11a on the first side of plane P1 and the first pivot axis 9a and the second pivot axis 10a on opposite second sides of plane P1 (“far-side” pivot arrangement). The longer arm length achieves a greater radial range under relatively constant radial forces, as referenced above. Figures 8A to 8C and 9.

[0165] like Figures 10F to 10H As shown, the first and second pivot joints are aligned in azimuth. The first and second pivot joints are circumferentially spaced (misaligned in azimuth) from the third pivot joint around the longitudinal axis 4, preferably by 180 degrees, as shown. The first pivot axis 9a, the second pivot axis 10a, and the third pivot axis 11a are parallel. Preferably, the first pivot axis 9a, the second pivot axis 10a, and the third pivot axis 11a are perpendicular to the longitudinal axis 4 of the centering device 20. The first pivot joint 3A-9 and the second pivot joint 3A-10 are aligned on a plane P2 that coincides with the longitudinal axis 4 of the centering device. Plane P2 is orthogonal to plane P1. The first pivot joint 3A-9, the second pivot joint 3A-10, and the third pivot joint 3A-11 and / or the wheel 14 are aligned on plane P2. The third pivot joint 3A-11 is located on the first side of plane P1, and the first pivot joint 9 and the second pivot joint 10 are located on the opposite second side of plane P1. The pivot joints 9, 10, and 11 are arranged such that the third pivot axis 11a is located on the first side of plane P1, and the first pivot axis 9a and the second pivot axis 10a are located on the opposite second side of plane P1. Figure 11A and 11B The positions of pivot joints 9, 10, 11 and pivot axis lines 9a, 10a, 11a are further clarified, with only one arm assembly 3 shown.

[0166] exist Figures 10A to 10E In the embodiments, the lateral alignment of pivot joints 9, 10, 11 and wheel 14 on plane P2 reduces mechanical stress on the pivot joints, for example by reducing bending moment and thrust loads on joints 9, 10 and 11.

[0167] The arm assembly extends circumferentially around and along the longitudinal axis 4 of the centralizer 20. The first arm 5 extends circumferentially around and along the longitudinal axis 4 between the first pivot axis 9 and the third pivot axis 11a, while the second arm 6 extends circumferentially around and along the longitudinal axis 4 between the third pivot axis 11a and the second pivot axis 10a to position the first and second pivot joints 9, 10 on opposite sides of the plane PI from the third pivot joint 11. For example, the first and second arms, and thus the arm assembly 3, can extend helically around and along the longitudinal axis.

[0168] In Figures 10A to 10E embodiments, the arm assembly 3 is arranged such that the first pivot joint 9 and pivot axis 9a of the arm assembly 3 are axially aligned, i.e. all of the first pivot joints 9 and axes 9a of the arm assembly 3 are aligned in a transverse plane (a plane that is orthogonal to the longitudinal axis 4, which for example extends in a first plane through line L-L in Figure 10A the cross-sectional view of FIG. 1). Similarly, the second pivot joint 10 and axis 10a are aligned in a transverse plane (e.g. aligned in a second plane that extends through line J-J in Figure 10A the cross-sectional view of FIG. 1). Preferably, the third pivot joint 11 and axis 11a are also aligned in a transverse plane (e.g. aligned in a third plane that extends through line K-K in Figure 10A the cross-sectional view of FIG. 1).

[0169] With the axial alignment of the first and second pivot joints and their respective axes, the arm assemblies are circumferentially nested around the mandrel, or in other words, the arm assemblies 3 are intertwined around the mandrel 12 much like the threads in a multi-start thread are intertwined. This arrangement enables a length-reduced centralizer compared to the case where the arm assemblies, or pairs of diametrically opposed arm assemblies, are axially spaced apart along the centralizer.

[0170] By positioning the first and second pivot joints 9, 10 (and their respective axes 9a, 10a) radially outward of the outer diameter of the central mandrel 12 of the centralizer, the first and second pivot axes are positioned as far away from the longitudinal axis 4 and the third pivot axis as possible. This provides a longer arm 5, 6 and greater radial range (wellbore diameter range) for a given angular range (A) between the first and second arms 5, 6 and the longitudinal axis 4 of the device. As best shown in the cross-sectional view of FIG. 1, the first and second pivot axes 9a, 10a do not intersect the mandrel 12. The third pivot joint is also positioned radially outward of the outer diameter of the mandrel for the full radial range of motion of the arm assembly, i.e. the third pivot joint is outside the outer diameter of the mandrel even when the arm assembly is in the radially innermost position as shown in FIG. 1. The third pivot joint does not intersect the mandrel 12 even in the radially innermost position. Figure 10C Figure 10B ​​

[0171] Similarly, such as Figure 2A , 2B As shown in 2G, in the previously described embodiment, the second pivot joint 10 and axis 10a are located radially outside the outer diameter of the center mandrel 12 of the centerer. The second pivot axis does not intersect the mandrel 12. The first pivot joint 9 and axis 9a are also located outside the outer diameter of the mandrel 12. The first pivot axis does not intersect the mandrel 12.

[0172] Figure 12A and 12B Another embodiment of the centering device 21 is shown, which has a "distal" pivot configuration similar to that described above. Figures 10A to 10E Similar to embodiment 20, however, additionally includes support members 7, 8 keyed to the mandrel 12 to rotatably secure the support members 7, 8 to the mandrel 12 such that the support members 7, 8 can move axially on the mandrel 12 without relative rotation between the support members 7, 8 and the mandrel 12. The mandrel 12 includes longitudinal "tracks" or protrusions 17 to engage corresponding longitudinal channels or slots in the respective support members 7, 8. Figure 12B 18). Those skilled in the art will understand that the male / female aspects of the keyway arrangements 17, 18 between the support members 7, 8 and the spindle 12 can be reversed, i.e., the support members 7, 8 may include longitudinal “tracks” or protrusions 17 to engage corresponding longitudinal channels or slots 18 in the spindle 12. The keyway arrangements 17, 18 ensure that the first pivot joint 9, the second pivot joint 10, and the third pivot joint 11 and the wheel 14 are in a plane coinciding with the longitudinal axis of the centerer (e.g., 18). Figures 2H to 2J and Figures 10F to 10H Keep aligned on plane P2).

[0173] Figure 12A and 12B Embodiment 21 also includes mechanical stops 19 to set the maximum diameter of the centering device 21. Each stop 19 restricts the axial movement of the corresponding support member 7, 8 to limit the radial outward movement of the arm assembly 3. When the centering device 21 enters a large-diameter section of the wellbore, such as a flushing section, the mechanical stops 19 prevent the arm assembly 3 from extending radially beyond the desired range to avoid difficulties, for example, when the centering device 21 enters a small-diameter (or nominal diameter) section of the wellbore from a large-diameter flushing section. Those skilled in the art will understand that other methods can be used to limit the maximum diameter of the centering device 21. For example, each support member 7, 8 may include a "buffer" such that contact between the buffers of the support members spaces the support members apart by a distance corresponding to the maximum radial position of the arm assembly.

[0174] Figure 13A Another embodiment of the centering device 22 is shown, which has a "distal" pivot configuration similar to that described above. Figures 10A to 10EEmbodiments 20 are similar, but additionally include the support members 7, 8 keyed to the mandrel 12 to rotationally fix the support members 7, 8 to the mandrel 12 so that the support members 7, 8 move axially on the mandrel 12 without relative rotation between the support members 7, 8 and the mandrel 12. The mandrel 12 of the centralizer is typically hollow to accommodate wiring, and the external wellbore pressure in the wellbore can be very high, for example 30,000 psi (pounds per square inch). Keyway grooves on the mandrel 12 would cause a "stress riser" (local increase in stress) in the mandrel 12, which can cause the mandrel to collapse under pressure. To reduce the increased stress in the mandrel, the support members 7, 8 can be provided with keyways, while the mandrel has corresponding keys or rails as in Figure 12A and 12B Embodiments. However, the necessary radial height of the keyways can be difficult to accommodate in the support members 7, 8, and / or the radial height of the keys on the mandrel requires a substantial amount of additional machining of the material in the manufacture of the mandrel. To address these issues, in some embodiments and as shown in Figure 13A , the keying of the support members to the mandrel is provided by the mandrel having a plurality of facets (flat surfaces) spaced around the outer surface of the mandrel. Each facet extends at least a portion of the length of the mandrel over which the first and / or second support members move. The support members 7, 8 have a corresponding plurality of spaced facets around the inner surface of the support members to rotationally key the support members to the mandrel, preventing rotation, and allowing the support members to slide or move axially on the mandrel. Each facet can be tangent to a circular arc centered on the central longitudinal axis of the mandrel / device.

[0175] Providing the mandrel with a faceted surface avoids the stress riser caused by keyway grooves on the mandrel, and the radial height required to accommodate the keyways on the support members is less.

[0176] In embodiments shown in Figure 13A , the facets are arranged to provide the mandrel with a polygonal outer surface, while the support members 7, 8 have a corresponding polygonal inner surface to rotationally key the support members to the mandrel, preventing rotation, and allowing the support members to slide or move axially on the mandrel. Figure 13B A centralizer 22 is shown with one spring 13 omitted to show the facets and polygonal outer surface of the mandrel 12, with the support member 8 sliding on the mandrel. Figure 13C The facets and polygonal outer surface of the mandrel, and the corresponding polygonal inner surface of the support member 8, are shown. The mandrel is also provided with a polygonal outer surface for the first support member 7, partially obscured by the spring. In Figure 13AIn the illustrated embodiment, the polygon is an octagon, however those skilled in the art will appreciate that other polygons are possible, with more or less than eight facets. It is contemplated that the mandrel and the support member(s) can have at least two facets (e.g. diametrically opposed) to key the mandrel and the support member(s) together. However, in preferred embodiments, the outer surface of the mandrel has facets that are azimuthally aligned with the adjacent first or second pivot joint at the first or second support member. Alternatively or additionally, the mandrel can have facets that extend between adjacent first or second pivot joints, such that the number of facets is equal to the number of arm assemblies or twice the number of arm assemblies. For example, in the illustrated embodiment comprising four arms, the mandrel comprises eight facets, or an octagonal outer shape. For example, a centralizer comprising three arm assemblies can have a mandrel with a hexagonal outer surface, and wherein the first and / or second support member has a corresponding hexagonal inner surface.

[0177] In the illustrated embodiment, a portion of the mandrel between the first and second support members has a larger outer cross-section than the faceted portion of the mandrel to provide a mechanical stop to set a maximum diameter for the centralizer. Each stop limits axial movement of the respective support member 7, 8 to limit radial outward movement of the arm assemblies.

[0178] The faceted surface(s) of the mandrel and the support member(s) enable keying of the support member(s) to the mandrel, while being more robust, and also requiring less material to be machined from a blank during manufacture of the mandrel. Those skilled in the art will appreciate that a centralizer having the hybrid side configuration described above, or any other lever arm type of centralizer, can also have the faceted mandrel and support member described above to key the support member(s) to the mandrel. Figures 13A to 13C The faceted mandrel and support member described above to key the support member(s) to the mandrel.

[0179] Those skilled in the art will appreciate that a mandrel having a polygonal outer surface has a cross-section with a constant polygonal outer profile that extends for at least a portion of the length of the mandrel. Likewise, a support member having a polygonal inner surface also has a cross-section with a constant polygonal inner shape that extends for a length of the support member.

[0180] Figures 14A to 14F Another embodiment of a centralizer 23 is shown, having a "distal" pivot configuration similar to the above-described embodiment 20, but with five arm assemblies 3 that are pivotally coupled to the mandrel 1 at first pivot joints 5 and second pivot joints 6. Figures 10A to 10E Figure 14C and 14F ​The centering device is referred to as 3A through 3E. The centering device must have at least three arm assemblies in order to center the tool string. However, preferably, the number of arm assemblies is increased to the maximum number of arm assemblies that can be practically installed around the mandrel 12. The inventors have determined that five arm assemblies is the optimal number of robotic arm assemblies, which is the maximum number of arm assemblies that can be practically installed around the mandrel, for use in centering tool strings in a wellbore.

[0181] The present application has been described with respect to centering a tool string in a wellbore during a wireline logging operation. However, the centering device according to the present application can be used to center sensor assemblies in a tube in other applications, such as centering a camera in a pipe for inspection purposes.

[0182] While the application has been described by way of example and in terms of the possibilities and embodiments thereof, it is to be understood that it is not to be limited thereto and that modifications or improvements can be made without departing from the spirit and scope of the appended claims.

Claims

1. An apparatus for centering a sensor assembly in a barrel, the apparatus comprising: a mandrel; first and second support members axially spaced apart along a central longitudinal axis of the apparatus, one or both of the first and second support members adapted for axial movement along the mandrel; a plurality of arm assemblies circumferentially spaced apart about the central longitudinal axis of the apparatus and connected between the first and second support members, each arm assembly comprising: a first arm pivotally connected to the first support member by a first pivot joint having a first pivot axis, a second arm pivotally connected to the second support member by a second pivot joint having a second pivot axis, the first and second arms pivotally connected together via a third pivot joint having a third pivot axis, and wherein the third pivot axis lies on a first side of a plane coincident with the central longitudinal axis of the apparatus, and the first and second pivot axes lie radially outward of an outer diameter of the mandrel on an opposite second side of the plane, and wherein the first and second pivot joints are azimuthally aligned, and the first and second pivot joints are azimuthally misaligned by 180 degrees from the third pivot joint.

2. The apparatus of claim 1, wherein, the first and second pivot axes do not intersect the mandrel.

3. The apparatus of claim 1 or 2, wherein, the third pivot joint is radially outward of the outer diameter of the mandrel.

4. The apparatus of claim 1, wherein, the plane is a first plane, and the first and second pivot joints are aligned on a second plane coincident with the central longitudinal axis, the second plane being orthogonal to the first plane.

5. The apparatus of claim 1, wherein, the plane is a first plane, and the first, second, and third pivot joints and / or wheels carried by the arm assemblies to contact a wall of the barrel are aligned on a second plane coincident with the central longitudinal axis, the second plane being orthogonal to the first plane.

6. The apparatus of claim 1, wherein, each arm assembly circumferentially extends or curves around and along the central longitudinal axis.

7. The apparatus of claim 1, wherein, the arm assemblies are circumferentially nested or intertwined around the mandrel.

8. The apparatus of claim 1, wherein, the apparatus comprises one or more spring elements to bias the arm assemblies radially outward.

9. The apparatus of claim 1, wherein, the apparatus comprises one or more axial spring elements acting on the first and / or second support members to bias the first and second support members axially together and radially outwardly bias the arm assemblies.

10. The apparatus of claim 9, wherein, the one or more axial spring elements are angularly configured together, the angle: i) within a range between a line extending through the first and third pivot axes and the central longitudinal axis, and / or ii) within a range between a line extending through the second and third pivot axes and the central longitudinal axis, such that the arm assemblies each provide a substantially constant radial force for a range of barrel diameters.

11. The apparatus of claim 1, wherein, the angle: i) between a line extending through the first and third pivot axes and the central longitudinal axis, and / or ii) between a line extending through the second and third pivot axes and the central longitudinal axis, the angle is maintained in a range greater than 10 degrees and less than 75 degrees.

12. The apparatus of claim 1, wherein, the mandrel comprises a plurality of facets spaced around an outer surface of the mandrel, and the first and / or second support member has a corresponding plurality of facets spaced around an inner surface of the support member to rotationally key the first and / or second support member to the mandrel.

13. The apparatus of claim 12, wherein, the facets are arranged such that the mandrel has a polygonal outer surface and the first and / or second support member has a corresponding polygonal inner surface.

14. An apparatus for centering a sensor assembly in a barrel, the apparatus comprising: a first support member and a second support member axially spaced along a central longitudinal axis of the apparatus; a plurality of arm assemblies circumferentially spaced about the central longitudinal axis of the apparatus and connected between the first and second support members, each arm assembly comprising: a first arm pivotally connected to the first support member by a first pivot joint having a first pivot axis, a second arm pivotally connected to the second support member by a second pivot joint having a second pivot axis, the first and second arms being pivotally connected together via a third pivot joint having a third pivot axis, wherein the first and third pivot axes lie on a first side of a plane coincident with the central longitudinal axis of the apparatus, while the second pivot axis lies on an opposite second side of the plane, and the first and second pivot joints are azimuthally offset by 180 degrees about the central longitudinal axis of the apparatus.

15. The apparatus of claim 14, wherein, an angle between a line extending through the first and third pivot axes and the central longitudinal axis is less than an angle between a line extending through the second and third pivot axes and the central longitudinal axis.

16. The apparatus of claim 14, wherein, each arm assembly includes a wheel to contact a wall of the barrel, and wherein the wheel is rotationally coupled to the first or second arm on an axis perpendicular to the central longitudinal axis and offset from an axis of rotation of the third pivot joint.

17. The apparatus of any one of claims 14 to 16, wherein, the apparatus includes one or more radial spring elements arranged to directly apply a radially outward force to the arm assemblies to bias the arm assemblies radially outward.

18. The apparatus of any one of claims 14 to 16, wherein, the apparatus includes one or more axial spring elements acting on the first and / or second support members to axially bias the first and second support members together and to radially outwardly bias the arm assemblies.

19. The apparatus of claim 18, wherein, The one or more axial spring elements are configured together such that the angle between a line extending through the second and third pivot axes and the central longitudinal axis is within a range such that each arm assembly provides a substantially constant radial force for a range of wellbore diameters.

20. The apparatus of claim 14, wherein, The angle between a line extending through the second and third pivot axes and the central longitudinal axis is maintained within a range greater than 10 degrees and less than 75 degrees.

21. The apparatus of claim 14, wherein, The plane is a first plane, and the first and third pivot joints and / or wheels carried by the arm assembly to contact the wall of the barrel are aligned on a second plane coincident with the central longitudinal axis, the second plane being orthogonal to the first plane.

22. The apparatus of claim 14, wherein, The device has a mandrel and the first and / or second support members are adapted to move axially along the mandrel, and the mandrel comprises a plurality of facets spaced around an outer surface of the mandrel, and the first and / or second support members have a corresponding plurality of facets spaced around an inner surface of the support member to rotationally key the first and / or second support members to the mandrel.

23. The apparatus of claim 22, wherein, The facets are arranged such that the mandrel has a polygonal outer surface and the first and / or second support members have a corresponding polygonal inner surface. The facets are arranged such that the mandrel has a polygonal outer surface and the first and / or second support members have a corresponding polygonal inner surface.

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