Patent Application
20220298870
This application is based on the provisional specification filed in relation to New Zealand Patent Application Number 766888, the entire contents of which is incorporated herein by reference.
This invention relates to devices for use in centering sensor equipment down a bore such as a pipe, a wellbore or a cased wellbore, and in particular to devices for use in centering sensor equipment in wireline logging applications.
Hydrocarbon exploration and development activities rely on information derived from sensors which capture data relating to the geological properties of an area under exploration. One approach used to acquire this data is through wireline logging. Wireline logging is performed in a wellbore immediately after a new section of hole has been drilled, referred to as open-hole logging. These wellbores are drilled to a target depth covering a zone 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 descends under gravity to the target depth of the wellbore well. The logging tool is lowered on a wireline—being a collection of electrical communication wires which are sheathed in a steel cable connected to the logging tool. The steel cable carries the loads from the tool-string, the cable itself, friction forces acting on the downhole equipment and any overpulls created by sticking or jamming. Once the logging tool reaches the target depth it is then drawn back up through the wellbore at a controlled rate of ascent, with the sensors in the logging tool operating to generate and capture geological data.
Wireline logging is also performed in wellbores that are lined with steel pipe or casing, referred to as cased-hole logging. After a section of wellbore is drilled, casing is lowered into the wellbore and cemented in place. The cement is placed in the annulus between the casing and the wellbore wall to ensure isolation between layers of permeable rock layers intersected by the wellbore at various depths. The cement also prevents the flow of hydrocarbons in the annulus between the casing and the wellbore which is important for well integrity and safety. Oil wells are typically drilled in sequential sections. The wellbore is “spudded” with a large diameter drilling bit to drill the first section. The first section of casing is called the conductor pipe. The conductor pipe is cemented into the new wellbore and secured to a surface well head. A smaller drill bit passes through the conductor pipe and drills the surface hole to a deeper level. A surface casing string is then run in hole to the bottom of the hole. This surface casing, commonly 20″ (nominal OD) is then cemented in place by filling the annulus formed between the surface casing and the new hole and conductor casing. Drilling continues for the next interval with a smaller bit size. Similarly, intermediate casing (e.g. 13⅜″) is cemented into this hole section. Drilling continues for the next interval with a smaller bit size. Production casing (e.g. 9⅝″ OD) is run to TD (total depth) and cemented in place. A final casing string (e.g. 7″ OD) is cemented in place from a liner hanger from the previous casing string. Therefore, the tool-string must transverse down a cased-hole and may need to pass into a smaller diameter bore.
There is a wide range of logging tools which are designed to measure various physical properties of the rocks and fluids contained within the rocks. The logging tools include transducers and sensors to measure properties such as electrical resistance, gamma-ray density, speed of sound and so forth. The individual logging tools are combinable and are typically connected together to form a logging tool-string. Some sensors are designed to make close contact with the borehole wall during data acquisition whilst others are ideally centered in the wellbore for optimal results. These requirements need to be accommodated with any device that is attached to the tool-string. A wireline logging tool-string is typically in the order of 20 ft to 100 ft long and 2″ to 5″ in diameter.
In cased hole, logging tools are used to assess the strength of the cement bond 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 utilises high frequency ultrasonic acoustic transducers and sensors to record circumferential measurements around the casing. The ultrasonic transmitter and sensor is mounted on a rotating head connected to the bottom of the tool. This rotating head spins and enables the sensor to record azimuthal ultrasonic reflections from the casing wall, cement sheath, and wellbore wall as the tool is slowly winched out of the wellbore. Other tools have transmitters and sensors that record the decrease in amplitude, or attenuation, of an acoustic signal as it travels along the casing wall. It is important that these transducers and sensors are well centered in the casing to ensure that the data recorded is valid. Other logging tools that measure fluid and gas production in flowing wellbores may also require sensor centralisation.
Logging tools are also run in producing wells to determine flow characteristics of produced fluids. Many of these sensors also require centralisation for the data to be valid.
In open hole (uncased wellbores), logging tools are used to scan the wellbore wall to determine the formation structural dip, the size and orientation of fractures, the size and distribution of pore spaces in the rock and information about depositional environment. One such tool has multiple sensors on pads that contact the circumference of the wellbore to measure micro-resistivity. Other tools generate acoustic signals which travel along the wellbore wall and are recorded by multiple receivers spaced along the tool and around the azimuth of the tool. As with the cased hole logging tools, the measurement from these sensors is optimised with good centralisation in the wellbore.
The drilling of wells and the wireline logging operation is an expensive undertaking. This is primarily due to the capital costs of the drilling equipment and the specialised nature of the wireline logging systems. It is important for these activities to be undertaken and completed as promptly as possible to minimise these costs. Delays in deploying a wireline logging tool are to be avoided wherever possible.
One cause of such delays is the difficulties in lowering wireline logging tools down to the target depth of the wellbore. The logging tool is lowered by a cable down the wellbore under the force of gravity alone. The cable, being flexible, can not push the tool down the wellbore. Hence the operator at the top of the well has very little control of the descent of the logging tool.
The chances of a wireline logging tools failing to descend is significantly increased with deviated wells. Deviated wells do not run vertically downwards and instead extend downward and laterally at an angle from vertical. Multiple deviated wells are usually drilled from a single surface location to allow a large area to be explored and produced. As wireline logging tools are run down a wellbore with a cable under the action of gravity, the tool-string will drag along the low side or bottom of the wellbore wall as it travels downwards to the target depth. The friction or drag of the tool-string against the wellbore wall can prevent to tool descending to the desired depth. The long length of a tool string can further exacerbate problems with navigating the tool string down wellbore.
With reference to
As hole deviation increases, the sliding friction or drag force can prevent the logging tool descending. The practical limit is 60° from the vertical, and in these high angle wells any device that can reduce friction is very valuable. The drag force is the product of the lateral component of tool weight acting perpendicular to the wellbore wall and the coefficient of friction. It is desirable to reduce the coefficient of friction in order to reduce the drag force. The coefficient of friction may be reduced by utilising low friction materials, such as Teflon. The drag force may also be reduced by using wheels.
A common apparatus to centralise logging tools is a bow-spring centraliser. Bow-spring centralisers incorporate a number of curved leaf springs. The leaf springs are attached at their extremities to an attachment structure that is fixed to the logging tool. The midpoint of the curved leaf spring (or bow) is arranged to project radially outward from the attachment structure and tool string. When the bow-spring centraliser is not constrained by the wellbore, the outer diameter of the bow-spring centraliser is greater than the diameter of the wellbore or casing in which it is to be deployed. Once deployed in the wellbore, the bow-springs are flattened and the flattened bow springs provide a centering force on the tool string. In deviated wells this centering force must be greater than the lateral weight component of the tool string acting perpendicular to the wellbore or casing wall. Consequently, more centering force is required at greater well deviations. If the centering force is too small the centraliser will collapse and the tool sensors are not centered. If the centralising force is too great the excessive force will induce unwanted drag which may prevent the tool descending or cause stick-slip motion of the logging tool. Stick-slip is where the tool moves up the wellbore in a series of spurts rather than at a constant velocity. Stick-slip action will compromise or possibly invalidate the acquired measurement data. The practical limit for gravity decent with using bow spring centralisers is in the order of 60 degrees from the vertical. Wellbores are vertical at shallow depths and build deviation with depth. Consequently, the centralisation force that is necessary varies within the same wellbore. As the bow spring centraliser must be configured for the highest deviations, invariably there is more drag than what is necessary over much of the surveyed interval.
With bow spring centralisers, the centralising force is greater in small wellbores, as the leaf springs have greater deflection (more compressed), than in large wellbores. Consequently, stronger or multiple bowsprings are required in larger hole sizes. These centralisers usually have “booster” kits to impart more centering force in larger wellbores or those with higher deviations.
At deviations greater than 60 degrees other methods must be used to overcome the frictional forces and enable the tool string to descend in the wellbore. One method is to use a drive device (tractor) connected to the tool string. Tractors incorporate powered wheels that forcibly contact the wellbore wall in order to drive the tool string downhole. Another method is to push the tool string down hole with drill pipe or coiled tubing. These methods involve additional risk, more equipment and involve more time and therefore cost substantially more.
In order to reduce the centraliser drag, wheels may be attached to the centre of the bow spring to contact the wellbore wall. However, the fundamental problems associated with the collapse of the leafspring or over-powering persist.
Another known type of centraliser consists of a set of levers or arms with a wheel at or near where the levers are pivotally connected together. There are multiple sets of lever-wheel assemblies disposed at equal azimuths around the central axis of the device. There are typically between three and six sets. The ends of each lever set are connected to blocks which are free to slide axially on a central mandrel of the centraliser device. Springs are used force these blocks to slide toward each other forcing the arms to defect at an angle to the centraliser (and tool string) axis so that the wheels can extend radially outward to exert force against the wellbore wall. With this type of device, the centering force depends on the type and arrangement of the energising apparatus or springs. The centraliser device is typically energised by means of either axial or radial spring or a combination of both. The advantage of this type of centraliser is that drag is reduced by the wheels which roll, rather than slide along the wellbore wall.
A centraliser device may also be energised by spring devices that directly exert a radially outward force. Such spring devices may be coil springs, torsion springs or leaf springs acting between the centraliser arm and a central mandrel. With leaf springs acting on the hinged arms or coil springs arranged radially from the centraliser/tool string axis the limitations described above for the bow spring centraliser still apply. Namely, the centralising force is greater in small wellbores, where the springs undergo greater deflection, than in large wellbores. At increased well deviations, more centering force is required. If the centering force is too small the centraliser will collapse and the tool sensors are not centered. If the centralising force is too great the excessive force will induce unwanted drag which may prevent the tool descending or cause stick-slip motion of the logging tool.
The reference to any prior art in the specification is not, and should not be taken as, an acknowledgement or any form of suggestion that the prior art forms part of the common general knowledge in any country.
It is an object of the present invention to address any one or more of the above problems or to at least provide the industry with a useful device for centering sensor equipment in a bore or pipe.
According to a first aspect of the present invention there is provided a device for centering a sensor assembly in a bore, the device comprising:
In some embodiments, the first and second pivot axes do not intersect the mandrel.
In some embodiments, the third pivot joint is radially outside the outside diameter of the mandrel.
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 coincident with the longitudinal axis of the centraliser orthogonal to the first plane.
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 centraliser orthogonal to the first plane
In some embodiments, the plane is a first plane, and the first pivot joint, the second pivot joint, and the third pivot joint and/or a wheel carried by the arm assembly to contact the well bore wall are aligned on a second plane coincident with the longitudinal axis orthogonal to the first plane.
In some embodiments, each arm assembly extends or curves circumferentially around and along the longitudinal axis of the centraliser.
In some embodiments, each arm assembly extends helically around and along the longitudinal axis.
In some embodiments, the arm assemblies are circumferentially nested or intertwined together around the mandrel.
In some embodiments, the arm assemblies are arranged so 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.
In some embodiments, the arm assemblies are arranged so that the third pivot joints and third pivot axes are aligned on a third plane orthogonal to the longitudinal axis.
In some embodiments, the device comprises one or more spring elements to bias the arm assemblies radially outwards. In some embodiments, the device comprises one or more spring (axial) elements acting on the first support member and/or the second support member to bias the first and second support members axially together and the arm assemblies radially outwards.
In some embodiments, the device comprises one or more (radial) spring elements acting on one or more of the arm assemblies to bias the arm assemblies radially outwards.
In some embodiments, the one or more spring elements are configured together with an angle (A):
In some embodiments, an angle (A):
In some embodiments, the angle (A) is maintained in a range 25 degrees to 65 degrees.
In some embodiments, the centraliser is a passive device, with energisation of the arm assemblies radially outwards being provided by one or more spring elements of the device only.
In some embodiments, the mandrel comprises a plurality of facets spaced apart around an outer surface of the mandrel and the first and/or second support member has a corresponding plurality of facets spaced apart around an inner surface of the support member, to rotationally key the first and/or second support member to the mandrel.
In some embodiments, the facets are arranged so that the mandrel has a polygon shaped outer surface and the first and/or second support members has a corresponding polygon shaped inner surface.
According to a second aspect of the present invention there is provided a wireline logging tool string comprising one or more elongate sensor assemblies and a device for centering the wireline logging tool string in a wellbore during a wireline logging operation, the device as described in any one or more of the above statements.
According to a third aspect of the present invention there is provided a device for centering a sensor assembly in a bore, the device comprising:
In some embodiments, one or both of the first and second support members is adapted to move axially along the longitudinal axis to allow the arm assemblies to extend and retract radially with respect to the longitudinal axis.
In some embodiments, the first arm is a different length to the second arm, so that a distance between the second and third pivot axes is different to a distance between the first and third pivot axes.
In some embodiments, an angle between a line extending between the first and third pivot axes and the longitudinal axis is less than an angle between a line extending between the second and third pivot axes and the longitudinal axis.
In some embodiments, each arm assembly comprises a wheel to contact the wellbore wall.
In some embodiments, the wheel is rotationally coupled to the first arm or second arm on an axis of rotation perpendicular to the longitudinal axis and offset from the third pivot axis.
In some embodiments, the device comprises one or more spring elements to bias the arm assemblies radially outwards.
In some embodiments, the device comprises one or more spring (axial) elements acting on the first support member and/or the second support member to bias the first and second support members axially together and the arm assemblies radially outwards.
In some embodiments, the device comprises one or more (radial) spring elements acting on one or more of the arm assemblies to bias the arm assemblies radially outwards.
In some embodiments, the one or more spring elements are configured together with an angle (A) between a line extending through the second and third pivot axes and the longitudinal axis being in a range so that the arm assemblies each provide a substantially constant radial force for a range of well bore diameters.
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.
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 25 degrees to 65 degrees.
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 coincident with the longitudinal axis of the centraliser orthogonal to the first plane.
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 centraliser orthogonal to the first plane.
In some embodiments, the plane is a first plane, and the first pivot joint and the third pivot joint or a wheel carried by the arm assembly to contact the well bore wall are aligned on a second plane coincident with the longitudinal axis orthogonal to the first plane.
In some embodiments, the second arm extends circumferentially around the longitudinal axis to position the second pivot joint on the opposite side of the plane.
In some embodiments, the second arm extends helically around and along the longitudinal axis.
In some embodiments, the centraliser is a passive device, with energisation of the arm assemblies radially outwards being provided by one or more spring elements of the device only.
In some embodiments, the device has a mandrel and the first and/or second support member is adapted to move axially along the mandrel, and the mandrel comprises a plurality of facets spaced apart around an outer surface of the mandrel and the first and/or second support member has a corresponding plurality of facets spaced apart around an inner surface of the support member, to rotationally key the first and/or second support member to the mandrel.
In some embodiments, the facets are arranged so that the mandrel has a polygon shaped outer surface and the first and/or second support member has a corresponding polygon shaped inner surface.
According to a fourth aspect of the present invention there is provided a wireline logging tool string comprising one or more elongate sensor assemblies and a device for centering the wireline logging tool string in a wellbore during a wireline logging operation, the device as described in relation to the third aspect.
According to a fifth aspect of the present invention there is provided a device for centering a sensor assembly in a bore, the device comprising:
According to a sixth aspect of the present invention there is provided a device for centering a sensor assembly in a bore, the device comprising:
According to a seventh aspect of the present invention there is provided a device for centering a sensor assembly in a bore, the device comprising:
In some embodiments, the facets are arranged so that the mandrel has a polygon shaped outer surface and the first and/or second support member has a corresponding polygon shaped inner surface. Preferably the polygon is a regular polygon, for example the mandrel may have a hexagon or octagon shaped outer surface. In some embodiments, the outer surface of the mandrel has a facet azimuthally aligned with an adjacent first or second pivot joint at the first or second support member. The number of facets may be equal to the number of arm assemblies. The mandrel may have a facet extending 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, the centraliser comprises four arm assemblies and the mandrel comprises eight facets, or an octagonal shaped outer surface and with the first and/or second support member having a corresponding octagonal shaped inner surface, or in an alternative embodiment the centraliser comprises three arm assemblies and the mandrel comprises six facets, or a hexagonal shaped outer surface and with the first and/or second support member having a corresponding hexagonal shaped inner surface.
The fifth, sixth and/or seventh aspects of the invention may include any one or more features described above for the first to fourth aspects of the invention.
In the above seven aspects of the invention, the device may be adapted for centering a wireline logging tool in a wellbore during a wireline logging operation.
Unless the context suggests otherwise, the term “wellbore” may to refer to both cased and uncased wellbores. Thus, the term ‘wellbore wall’ may refer to the wall of a wellbore or the wall of a casing within a wellbore.
Unless the context suggests otherwise, the term “tool string” refers to an elongate sensor package or assembly also known in the industry as a “logging tool”, and may include components other than sensors such as guide and orientation devices and carriage devices attached to sensor components or assemblies of the tool string. A tool string may include a single elongate sensor assembly, or two or more sensor assemblies connected together.
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 to say, in the sense of “including, but not limited to”. Where in the foregoing description, reference has been made to specific components or integers of the invention having known equivalents, then such equivalents are herein incorporated as if individually set forth.
The invention may 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 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 invention relates, such known equivalents are deemed to be incorporated herein as if individually set forth.
Further aspects of the invention, which should be considered in all its novel aspects, will become apparent from the following description given by way of example of possible embodiments of the invention.
An example embodiment of the invention is now discussed with reference to the Figures.
Each arm assembly or linkage 3 comprises 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, and 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 axle on which the arms 5, 6 pivot about a pivot axis 9a, 10a, 11a, being an axis of the pin or axle. One or both of the support members 7, 8 are adapted to move axially, so that each arm assembly 3 is moved radially to engage the wellbore wall 102 by pivoting of the first, second and third pivot joints 9, 10, 11. One or both support members 7, 8 may slide axially on a central member or mandrel 12 of the centraliser 1. For example, the support members 7, 8 may comprise a collar or annular member colinear with and received on the mandrel 12 to slide thereon. Each support member 7, 8 may comprise a number of parts assembled together about the mandrel 12.
The support members 7, 8 may be keyed to the mandrel to rotationally fix the support members to the mandrel so 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 the support member may comprise a longitudinal ‘rail’ or projection to engage a corresponding longitudinal channel or slot in the other one of the mandrel and support member (see for example the embodiment of
The centraliser 1 has one or more spring elements 13 to provide a force to the arm assemblies 3 to force the arm assemblies against the wellbore wall 102a to provide a centralising force to maintain the centraliser 1 and therefore the associated tool-string 101 centrally within the wellbore 102. In the illustrated embodiment, both of the first and second support members 7, 8 move axially, and the centraliser 1 has an axial spring 13 acting on each support member 7, 8 to bias the support members 7, 8 axially together to thereby bias the arm assemblies 3 radially outwards against the wellbore wall 102a. Where one of the support members 7, 8 is fixed, the centraliser 1 is without a spring acting on the fixed support. The axial spring(s) 13 may be coil springs that are colinear with the mandrel 12 as shown in the illustrated embodiment or may include a plurality of coil springs arranged circumferentially (azimuthally spaced apart) around the mandrel. Those skilled in the art will understand that other types of springs and spring configurations may be used to power the centraliser such as torsion springs, leaf springs and Belleville Washers for example. A combination of two or more spring devices may also be used, for example one or more springs may be provided end-to-end to impart a combined non-linear spring rate. Alternatively, the pitch of the coil spring may vary over its length to provide a non-linear spring rate. The centraliser may additionally or alternatively have spring elements that exert a radially outwards force directly to the arm assemblies. For example, a coil or leaf spring may be located between the first arm and the mandrel and/or between the second arm and the mandrel to provide a radially acting force, as shown in
Preferably each arm assembly 3 comprises a roller or wheel 14 located at or adjacent 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 traverses the well bore 102. The roller 14 may have a rotational axis colinear with a pivot axis 11a of the third pivot joint 11 as shown in
Each linkage or arm assembly 3 provides a mechanical advantage (mechanical leverage) between the axial displacement and the radial displacement to provide, in combination with the axial spring element 13, a radial force to the wellbore wall 102a. As the support members 7,8 are linked by multiple arm assembles 3, each arm assembly is displaced equally with support member axial displacement, thereby centralising the centraliser and toolstring in the wellbore. The mechanical advantage changes with the axial and radial position of the arm assembly 3. The mechanical advantage of the arm assembly 3 may 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 increases. The mechanical advantage is dependent on the angle between each arm and the centreline of the device (angle A in
It is to be understood that the angle between an arm and the central axis is defined as an angle between a line extending through the pivot axes at respective 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 and third pivot axes 10a, 11a and the longitudinal axis 4.
Preferably the centraliser 1 provides a relatively constant centering force over a range of wellbore diameters. The radial force applied by the centraliser 1 is a product of the axial spring force provided by spring(s) 13 and the mechanical advantage of the arm assembly 3. Since the axial force increases as the mechanical advantage decreases, a relatively constant radial force can be achieved for a range of well bore diameter sizes by optimising the spring rate, spring preload and arm assembly geometry, to balance the spring force and mechanical advantage.
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 an arm 5, 6 of the arm assembly 3 (angles approaching 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 friction as the logging tool string traverses the wellbore. High friction may prevent the tool string descending under gravity and may result in stick-slip where the tool moves up the wellbore in a series of spurts rather than a constant velocity, impacting the accuracy of the data collected. When the arms are at large angles, greater radial force is required to collapse the centraliser. This make it very difficult for the centraliser to descend into a smaller diameter casing (e.g. from 9⅝ in casing to 7 in liner). The centraliser arms may even become caught in the wellhead control assembly which consists of a stack of hydraulic rams and valves for well control and safety (close in a blowout).
Conversely, at small angles between the longitudinal axis and an arm 5, 6 of the arm assembly 3 (angles approaching 0 degrees), a large axial spring force is required to provide sufficient radial force to centralise the tool string. Additionally, axial displacement of the support member(s) 7, 8 is very small relative to the radial displacement (outer diameter of the centraliser 1) which causes the centraliser device 1 to fail in its ability to centralise the tool string 101 in small diameter well bores. For example, at an arm angle of 10 degrees, a change in the centraliser diameter of 10 mm (5 mm radial displacement) results in an axial displacement of less than 1 mm. With such a small axial movement of the support members 7, 8 clearances in pivot points 9, 10, 11, bearings and the sliding support members 7, 8 causes the centraliser device to fail to centralise the tool string since the radial displacement of one of the arm assemblies is not transferred sufficiently accurately to other arm assemblies through the support members 7, 8 and pivot joints 9, 10. This results in the device 1 running off centre which in turn can cause the tool string sensors 106 to return erroneous data. At low arm angles the radial force may be increased by including radial booster springs as described above with reference to
Additionally or alternatively, a variable rate spring may be applied axially to the sliding support members 7, 8 and/or radially to each arm assembly, to provide an increased spring force at small angles between the longitudinal axis and an arm 5, 6 of the arm assembly where the mechanical advantage is reduced, and a decreased spring force at large angles between the longitudinal axis and an arm 5, 6 of the arm assembly where the mechanical advantage is increased. For example, a variable pitch coil spring may be provided axially to the sliding support members 7, 8, and/or radially between an arm 5, 6 and the mandrel, so that the spring rate increases as the coil spring is compressed. A variable pitch spring is illustrated in
The inventor has identified 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 lower than 30°, there is a decreased mechanical advantage requiring high spring loads and a resulting inability to centralise due to practical component tolerances. For angles much higher than 60°, the mechanical advantage is too great presenting increases sensitivity and high wellbore wall loading. Additionally, at angles much greater than 60°, the tool string may not be able to pass from a larger diameter casing to a smaller diameter casing as the arms 3 of the centraliser may get ‘hung up’ on the ledge formed between the larger and smaller diameter casing. The angle is preferably much greater than 10 degrees and much less than 75 degrees. By way of example, the radial deflection in
An improved radial range of movement may be achieved by locating the first and second pivot joints on an opposite side of a plane coincident with the longitudinal axis of the centraliser to the third pivot joint, while maintaining the angle between the arm assembly 3 and the longitudinal axis 4 between useful limits, for example 30 and 60 degrees, to achieve a relatively constant radial force.
The inventor has determined that a benefit may be achieved by locating only one of the first and second pivot joints 9, 10 on the opposite second side of a plane coincident with the longitudinal axis of the centraliser, as shown in the schematic representation of
The centraliser of
The relative positions of the first, second and third pivot joints 9, 10 and 11 in the embodiment of
As shown in
The lateral alignment of the pivot joints 9, 10, 11 and wheel 14 on plane P2 reduces mechanical stress on the pivot joints, for example by reducing bending moments and thrust loads on the joints 9, 10, 11.
As best shown in
With the first and second pivot joints and their respective axes axially aligned, the arm assemblies are circumferentially nested together 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 achieves a reduced length centraliser, compared to if the arm assemblies or diametrically opposed arm assembly pairs were spaced axially along the centraliser.
The first arm may have a different length to the second arm, so that a distance between the second and third pivot axes is different to a distance between the first and third pivot axes. For example, a distance between the first and third pivot axes 9a, 11a may be shorter than a distance between the second and third pivot axes 10a, 11a, as shown in
With reference to
In an alternative arrangement, the first arm 5 may extend or curve circumferentially around the longitudinal axis 4 (for example helically), so that the first pivot joint 9 and the third pivot joint 11 are circumferentially spaced apart, i.e. azimuthally misaligned. The first pivot joint 9 may located on a first side of the plane P2, and the second pivot joint 10 may be located on an opposite second side of the plane P2. Other configurations are possible, for example, the first and second pivot joints 9 and 10 may be located on a first side of plane P2 with the first and second arms 5, 6 extending circumferentially around the longitudinal axis to position the wheel 14 on a plane (e.g. plane P2) coincident with the longitudinal axis 4.
A centraliser according to one aspect of the present invention as described above provides one of more of the following benefits. The centraliser achieves a relatively constant radial force for a larger range of wellbore diameters compared to prior art centralisers with all pivot points on the same side of the longitudinal axis as the wheel in contact with the wellbore. The centraliser achieves a wellbore diameter range comparable to a device with the arm assembly pivot joints on an opposite side of the centraliser longitudinal axis to the wheel, however, achieves the diameter range with a reduced axial length device. The configuration of the pivot joints allows a centraliser to provide a radial centering force that is not so high as to result in excess friction in smaller diameter bores within the desired wellbore range, yet provides sufficient radial force to maintain the centraliser and associated tool string centrally within larger diameter bores. A balancing of the practical mechanical advantage together with an axial spring force allows for a centraliser that can centre the tool string even in deviated wellbores where the weight of the tool string and centraliser acts against the centralisation radial force provided by the centraliser. Furthermore, the centraliser is a passive device, with energisation being provided by the mechanical spring components 13 only. No other power input, such as electrical or hydraulic power provided from service located power units is required. The invention therefore provides a lower cost, effective, and simplified device that provides improved operational reliability and accuracy of logged data.
In the embodiment of
However, in
As shown in
In the embodiment of
The arm assemblies extend or curve circumferentially around and along the longitudinal axis 4 of the centraliser 20. The first arm 5 extends or curves circumferentially around and along the longitudinal axis 4 between the first pivot axis 9 and the third pivot axis 11a, and the second arm 6 extends or curves 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 and 10 on the opposite side of the plane P1 to the third pivot joint 11. For example, the first and second arms and therefore arm assemblies 3 may extend helically around and along the longitudinal axis.
In the embodiment of
With the first and second pivot joints and their respective axes axially aligned, the arm assemblies are circumferentially nested together 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 achieves a reduced length centraliser, compared to if the arm assemblies or diametrically opposed arm assembly pairs were spaced axially along the centraliser.
A greater radial range is further achieved by positioning the first and second pivot joints 9, 10 (and their respective axes 9a, 10a) radially outside an outside diameter of the central mandrel 12 of the centraliser, to position the first and second pivot axes as far from the longitudinal axis 4 and the third pivot axis as possible. This provides for a longer arm 5, 6 and greater radial range (well bore diameter range) for a given range of angle (A) between the first and second arm 5, 6 and the longitudinal axis 4 of the device. As best shown in the cross section of
Similarly, as shown in
The embodiment 21 of
However, the necessary radial height of the keyway may be difficult to accommodate in the support members 7, 8 and/or the radial height of the key on the mandrel requires significant additional machining of material in the manufacture of the mandrel. To address these issues, in some embodiments and as shown in
Providing a multi-faceted surface to the mandrel avoids a stress riser caused by a keyway in the mandrel and requires less radial height for a keyway to be accommodated in the support members.
In the illustrated embodiment of
In the illustrated embodiment, a portion of the mandrel located between the first and second support member has a larger outer cross section than the faceted portions of the mandrel to provide mechanical stops to set a maximum diameter for the centraliser. Each stop limits axial movement of the respective support member 7, 8, to limit the radial outward movement of the arm assemblies.
The facetted surface(s) of the mandrel and support member(s) achieves keying of the support member(s) to the mandrel while being stronger and also requiring less material to be machined from a stock material during manufacture of the mandrel. One skilled in the art will appreciate a centraliser with a mixed side configuration as described above or any other lever arm type centraliser may also have a facetted mandrel and support members as described with reference to
One skilled in the art will understand that a mandrel with a polygon shaped outer surface has a cross section with a constant polygon outer shape extending for at least a portion of the length of the mandrel. Likewise, a support member with a polygon shaped inner surface has a cross section with a constant polygon inner shape extending for a length of the support member.
The invention has been described with reference to centering a tool string in a wellbore during a wireline logging operation. However, a centralising device according to the present invention may be used for centering a sensor assembly in a bore in other applications, for example to center a camera in a pipe for inspection purposes.
Although this invention has been described by way of example and with reference to possible embodiments thereof, it is to be understood that modifications or improvements may be made thereto without departing from the spirit or scope of the appended claims.
| Number | Date | Country | Kind |
|---|---|---|---|
| 766888 | Aug 2020 | NZ | national |
| 17/091839 | Nov 2020 | US | national |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/NZ2021/050123 | 8/5/2021 | WO |
