Patent Application
20240141735
This application is based on the provisional specification filed in relation to New Zealand Patent Application Number 794016, 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 are 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 the wireline cable down the wellbore under the force of gravity alone. The cable, being flexible, cannot 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 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 diameter wellbores, as the leaf springs have greater deflection (more compressed), than in large diameter 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. However, the limitations described above still apply. Namely, the centralising force is greater in small diameter wellbores, where the springs undergo greater deflection, than in large diameter wellbores. And 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 one 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 sleeve comprises a plurality of said axial slots and the mechanical stop comprises a plurality of said projections received in the slots, the plurality of axial slots and the plurality of projections spaced circumferentially apart around the central longitudinal axis.
In some embodiments, the one or more projections bear against the sleeve to provide the limit of axial travel.
In some embodiments, each of the one or more projections bears against an end of the corresponding said axial slot to provide the limit of axial travel.
In some embodiments, the mechanical stop comprises a ring attached to the projections, the ring extending around an outside of the sleeve to allow the sleeve to slide relative to the ring.
In some embodiments, the sleeve bears against the ring to provide the limit of axial travel
In some embodiments, the sliding support comprises an adjustment mechanism configured to set a maximum outer diameter of the device, and wherein sliding support comprises a collar mounted to the sleeve by a threaded engagement, the collar bears against the ring to provide the limit of axial travel, the sleeve and collar with threaded engagement thereby providing the adjustment mechanism.
According to another aspect of the present invention there is provided a device for centering a sensor assembly in a bore, the device comprising:
One or both supports comprise a sleeve and a collar mounted to the sleeve by a threaded engagement, the arm assemblies pivotally connected to the sleeve or collar, the sleeve and collar with threaded engagement providing the adjustment mechanism.
In some embodiments:
In some embodiments:
In some embodiments:
In some embodiments, the first and second supports each comprise a said adjustment mechanism, and
In some embodiments:
In some embodiments, the sleeve comprises one or more axial slots to receive the mechanical stop to bear against the collar.
In some embodiments, the mechanical stop comprises one or more projections extending from a central mandrel of the device, the one or more projections corresponding with the one or more slots, each projection received in a said slot.
In some embodiments, the sleeve comprises a plurality of said axial slots and the mechanical stop comprises a plurality of said projections received in the slots.
In some embodiments, the mechanical stop comprises a ring attached to the projections, the collar bearing against the ring.
In some embodiments, each projection comprises a pin and/or fastener.
In some embodiments, the adjustment mechanism comprises a locking member to lock the position of the adjustment mechanism and therefore the maximum outer diameter setting.
In some embodiments, the locking member is a threaded ring mounted to the sleeve to engage the collar by relative rotation provided for by the threaded engagement.
In some embodiments, each arm assembly comprises a first arm connected to one of the support by a first pivot joint, and second arm connected to the other one of the supports by a second pivot joint, the first and second arms coupled together.
In some embodiments, the first and second arms are pivotally connected together by a third pivot joint.
The adjustment mechanism is configured to set the maximum outer diameter of the device within a range of maximum outer diameters, between a smallest maximum outer diameter and a largest maximum outer diameter.
The device comprises one or more springs to bias the arm assemblies radially outwards.
In some embodiments, one of the support members is configured to slide axially and the other one of the support members is fixed against sliding axially, and
In some embodiments, one of the first and second support members is configured to slide axially and the other one of the first and second support members is fixed to the mandrel, the fixed support comprising a said adjustment mechanism, and wherein the sleeve of the fixed support member is fixed to or integrally formed with the mandrel.
In some embodiments, the sleeve of the fixed support member is integrally formed with the mandrel such that the collar of the fixed support member is threadingly engaged with the mandrel by the threaded engagement.
The second described aspect of the invention may have any one or more of the features of the above first described aspect of the invention.
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.
A plurality of arm assemblies (linkages) 3 are spaced circumferentially apart around a longitudinal axis 4 of the device 1. The arm assemblies 3 are configured to move axially and radially to engage the wellbore wall 102a to provide a centering force to maintain the tool string 101 in the centre of the wellbore 102. The example device 1 comprises four arm assemblies 3, however there may be three or more arm assemblies.
The arm assemblies 3 are pivotally coupled between two supports, a first support 7 and a second support 8. Each arm assembly or linkage comprises a first arm or link 5 pivotally connected to one of the supports 7, 8 by a first pivot joint 11 having a first pivot axis 11a, and a second arm or link 6 pivotally connected to the other one of the supports 7, 8 by a second pivot joint 12 having a second pivot axis 12a. The first and second arms 5, 6 are pivotally coupled together and in the illustrated example are pivotally attached via a third pivot joint 13 having a third pivot axis 13a. One or both of the supports 7, 8 are configured to move/slide axially along a longitudinal axis 4 of the device 1 to cause the arm assemblies 3 to move radially to engage the wellbore wall by pivoting of the first and second arms 5, 6 about the respective first 11a, second 12a and third 13a pivot axes. One or both supports 7, 8 may slide axially on a central member or mandrel 10 of the centraliser or on a body of the tool string. The axial movement of the support or supports 7, 8 moves the arm assemblies 3 between a minimum outside diameter with the arm assemblies 3 in a radially inward position as shown in
Each arm assembly 3 carries a roller or wheel 14 (herein wheel) to contact the wellbore wall to reduce friction between the wellbore wall 102a and the tool string 101 as the tool string 101 traverses the well bore 102. The wheel 14 is located at or adjacent the third pivot joint 13. The wheel 14 may have a rotational axis colinear with the pivot axis 13a of the third pivot joint 13 as shown in the figures or may be located adjacent the third pivot joint 13, for example the wheel may be rotationally mounted to the first arm 5 or the second arm 6 adjacent the third pivot joint 13.
Springs are provided to bias the arm assemblies 3 radially outwards against the wellbore wall 102a, to center the centraliser 1 and connected tool string in the wellbore. For example, the device may comprise leaf springs to bias the arms assemblies 3 radially outwards. A radially acting spring may be provided to one or more arm assemblies or each arm assembly. The radial spring or leaf spring may be mounted to a support 7, 8 to act between the support 8 and the arm assembly 3 to provide a radial outward force to the arm assembly 3. By example, the embodiment of
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 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. A centraliser according to the present invention may have only axial springs, only radial springs, or a combination of both axial and radial springs. A combination of both axial and radially acting springs may be used to provide a relatively constant radial force. Any known spring arrangement may be provided to power the radial outward movement of the arms of a centraliser according to the present invention, the above-described arrangements are by way of example only.
In a centraliser according to the present invention one or both supports 7, 8 is a support assembly comprising an adjustment mechanism to set a maximum diameter of the centraliser 1 within a range of maximum outer diameters, i.e. between a smallest maximum outer diameter and a largest maximum outer diameter.
The radial extremities of the centraliser provided by the wheels 14 together present or define the outer diameter of the centraliser—the radial extremities of the centraliser provided by the wheels lie on a circle, and the diameter of the circle is the outer diameter of the device. The springs provide a radial force to the arm assemblies 3 with the wheels 14 at the maximum outer diameter so that the centraliser supports the sensor assembly with the wheels at the maximum outer diameter as it traverses along a bore.
The adjustment mechanism prevents the arm assemblies 3 extending radially outside a desired diameter range, to avoid for example difficulties with inserting the device 1 into a bore or passing from a larger diameter to a smaller diameter section of the wellbore or passing through a wellhead control assembly.
The adjustment mechanism may be configured to allow the maximum outer diameter to be set to be equal to or slightly less than a maximum nominal wellbore diameter, thus avoiding the requirement to press the arms radially inwards against the spring force to thereby avoid a higher friction force when passing along a nominal section of the wellbore.
With reference to
In the example of
A fixed support may comprise an adjustment mechanism to set the maximum outer diameter of the device 1. Where a support 7, 8, does not slide axially on the mandrel, the ‘sleeve’ is fixed to the mandrel, for example the sleeve as described herein may be fixed against sliding by grub screws engaged between the sleeve and mandrel, or the sleeve may be integrally formed with the mandrel, in which case the collar may be threadingly engaged with the mandrel. The other support is a sliding support and may be with or without an adjustment mechanism.
In a sliding support 7, 8 as illustrated, axial movement of the support on the mandrel to move the arms radially outwards is limited by a mechanical stop 15 on the mandrel. The support 7, 8 bears against the stop 15 when the arm assemblies are at the maximum outer diameter. The mechanical stop 15 therefore defines the maximum outer diameter of the device 1.
In the illustrated example of
Again with reference to
In the illustrated embodiment, an adjustment mechanism is provided at each support 7, 8. In such an example, the threaded engagement at the first or second support 7, 8 may be a right-hand thread and the threaded engagement at the other one of the first and second support may be a left-hand thread, so that adjustment of the maximum outer diameter may be made by rotating the arm assemblies 3 about the mandrel or tool/longitudinal axis 4 of the centraliser. The collar 22 at each support 7, 8, rotates on the threaded engagement relative to the sleeve 21 together with the arm assemblies 3. The sleeves 21 may remain rotationally fixed to the mandrel 10. Once the maximum outer diameter is set, the set position of the collars 22 on the respective sleeves 21 may be locked by the locking member 24 at one or both supports 7, 8. The sleeves 21 may be keyed to the mandrel 10 to prevent relative rotation therebetween. For example, in
The centraliser 201 is configured as a slip over device to fit on the outside of a wireline logging tool. The centraliser 201 comprises six arm assemblies 203 azimuthally spaced apart around the centraliser. The arm assemblies 203 each comprise an arm 205 extending circumferentially around the longitudinal axis so that the first pivot joint 211 and the second pivot joint 212 are on opposite sides of a plane coincident with the longitudinal axis, as described in U.S. Pat. No. 10,947,791.
In the illustrated example, only one of the two supports 207, 208 comprises an adjustment mechanism. The support 207 comprising an adjustment mechanism comprises a sleeve 221 and a collar 222 mounted to the sleeve by a threaded engagement, the sleeve and collar providing the adjustment mechanism. The sleeve 221 is configured to slide axially along the longitudinal axis 4 of the device. The threaded engagement provides relative axial movement between the collar 222 and sleeve 221 to adjust an axial position of the respective pivot joint 211 of the arm assemblies 203 along the longitudinal axis 4 to correspondingly set the maximum outside diameter of the device 201.
Axial travel of the support 207 is limited by a mechanical stop 215, to define the outer diameter of the device 201. In contrast to the earlier embodiment 1, the arm assemblies 203 are pivotally connected to the sleeve 221, and the collar 222 bears against the mechanical stop 215 to define the maximum axial travel of the support 207 along the longitudinal axis 4. The relative axial movement of the collar 222 on the sleeve 221 provided for by the threaded engagement 223 adjusts the axial position of the sleeve 221 and the respective pivot joints 211 of the arm assemblies 203 relative to the mechanical stop 215 to correspondingly set the maximum outside diameter of the device 201 within the desired diameter range. The adjustment mechanism therefore provides for an adjustable mechanical stop relative to the arm assemblies.
In the illustrated embodiment, and with reference to
In the illustrated embodiment, the mechanical stop 215 further comprises a ring 227 attached to the projections 226, e.g. by fasteners 228. The axial slots extend fully through the sleeve in a radial direction, i.e. from an internal diameter of the sleeve to an outside diameter of the sleeve. The projections extend through the slots and the ring is attached to the projections on the outside of the sleeve to extend around an outside of the sleeve 221 such that the sleeve may slide relative to the ring 227 (and mandrel 210). The collar 222 engaged with the sleeve 221 via the threaded engagement bears against the ring 227 (as shown in
The illustrated embodiment comprises three axial slots and three corresponding projections received in the slots. However, one skilled in the art will appreciate one, two, three or more slots and corresponding projections may be provided. For example, in a further alternative arrangement, the sleeve may comprise one slot 225 and the stop 215 a corresponding projection 226, 228. The projection(s) 226, 228 may bear directly against the collar 222, i.e. the mechanical stop 215 may be without ring 227.
The axial slots 225 may be open through an end of the sleeve as shown in
The adjustment mechanism comprises a locking member 224 to lock the position of the adjustment mechanism and therefor the maximum outer diameter setting. Like in the earlier embodiment, the locking member is a ring 224 threadingly engaged to the sleeve 221 to engage the collar 222 to fix the axial position of the collar 222 on the sleeve 221. Other locking members/arrangements are possible, such as a radial pin received through aligned holes in the collar and sleeve, with a series of pin holes spaced apart along the sleeve to provide for different diameter settings.
While the embodiment of
The mechanical stop arrangement 215 described with reference to
In
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 |
|---|---|---|---|
| 794016 | Nov 2022 | NZ | national |
