Down-the-well operations

Description

Bottom-Edge Trading Fundamentals Field

[001] This description relates to downhole operations, particularly downhole cementing operations in which wellbore liner tubing is cemented into a drilled wellbore. Description of the Related Technique

[002] In the oil and gas exploration and production industry, subterranean rock formations containing hydrocarbons can be accessed using wellbore holes drilled from the ground surface or the seabed in an offshore environment. The drilled wellbore holes may be lined with metal tubing, known as casing and liner. The annular space between the tubing and the surrounding wellbore wall may be filled and sealed with a shaping material, typically cement. Operators follow steps to ensure the quality of the cement annular space. There have been numerous proposals to monitor the dispensing of cement into the annular space and to identify the distribution of cement within the annular space; for example, see U.S. Patents Nos. US10738590, US10539003, US10053979, and US9879519. SUMMARY

[003] According to one aspect of the description, it is provided Petition 870260048543, dated 05 / 21 / 2026, page 9 / 38 2 / 30 a wellbore cementing method comprising: To provide a downhole piping assembly comprising: a wellbore lining pipe having distal and proximal ends; a flow port at the distal end of the wellbore lining pipe; an inner pipe having distal and proximal ends, and a sensor unit at the distal end of the inner pipe; to move the downhole piping assembly to a drilled wellbore; circulate fluid through the inner tubing, the flow port, and an annular space between the wellbore lining tubing and the drilled wellbore; and operate the sensor unit to determine at least one of: a wellbore parameter and a circulating fluid parameter.

[004] According to another aspect of the description, a method is provided for cementing a wellbore liner located in a drilled wellbore, the wellbore liner having distal and proximal ends and a flow port at the distal end, the method comprising: Provide an inner tube that has distal and proximal ends, and a sensor unit at the distal end of the inner tube; Petition 870260048543, dated 05 / 21 / 2026, page 10 / 38 3 / 30 Transfer the inner tubing to the wellbore and to the wellbore lining tubing; circulate flow through the inner tubing, the flow port, and an annular space between the wellbore lining tubing and the drilled wellbore; and operate the sensor unit to determine at least one of a wellbore parameter and a circulating fluid parameter.

[005] The sensor unit can be operated as the sensor unit is moved into the wellbore. The sensor unit can therefore be operated to, for example, measure the diameter of the wellbore, sometimes referred to as the wellbore gauge.

[006] The sensor unit can be operated while the sensor unit is being retrieved from the wellbore. The sensor unit can thus be operated to determine a wellbore parameter by following the circulation and placement of fluid in the wellbore and, in particular, the placement of fluid in the annular space between the wellbore lining pipe and the drilled wellbore.

[007] The circulating fluid parameters determined by the sensor unit may include at least one of the following: pressure, density, flow rate, pH and acoustic impedance.

[008] Wellbore parameters determined Petition 870260048543, dated 05 / 21 / 2026, page 11 / 38 4 / 30 by the sensor unit may include casing collar location or gamma ray detection in the unfinished well. Depth correlation of the sensor unit in the wellbore lining tubing may include direct detection of casing collars or correlation of downhole sensor data with data acquired from downhole drilling assemblies or with surface reading data acquired from drilling rig depth measurement devices, such as those supplied by NOV M / D Totco.

[009] During fluid circulation, the distal end of the inner tubing can be coupled to the distal end of the wellbore lining tubing. Alternatively, the distal end of the inner tubing can be spaced away from the distal end of the wellbore lining tubing.

[0010] According to a further aspect of the description, a downhole piping assembly is provided comprising: a wellbore lining pipe having distal and proximal ends; a flow port at the distal end of the wellbore lining pipe; an inner pipe having distal and proximal ends; and a sensor unit at the distal end of the inner pipe to determine a fluid parameter circulating through the inner pipe, the flow port and Petition 870260048543, dated 05 / 21 / 2026, page 12 / 38 5 / 30 an annular space between the wellbore lining tubing and a surrounding wellbore wall.

[0011] According to a further aspect of the description, a downhole tubing assembly is provided for location in a drilled wellbore and within a wellbore lining pipe having distal and proximal ends and a flow port at the distal end of the wellbore lining pipe, the downhole tubing assembly comprising: an inner pipe having distal and proximal ends, and a sensor unit at the distal end of the inner pipe, the downhole tubing assembly for location in a drilled wellbore and within a wellbore lining pipe through which the sensor unit is operable to determine at least one of: a wellbore parameter, and a fluid parameter circulating through the inner pipe,from the flow port and an annular space between the wellbore lining tubing and a surrounding wellbore wall.

[0012] The sensor unit may be operable to determine a parameter of the circulating fluid, including at least one of pressure, density, pH, and flow rate. The sensor unit may comprise a plurality of different sensors and may be used to determine a plurality Petition 870260048543, dated 05 / 21 / 2026, page 13 / 38 6 / 30 of circulating fluid parameters and properties. The sensor unit can determine a parameter or property directly, or the information gathered by the sensor unit can be subsequently analyzed or queried to determine the parameter.

[0013] The determined parameter can be compared to a circulating fluid parameter that was known or previously determined at the surface. Alternatively, or additionally, the determined parameter can be compared to a bottomhole parameter predicted by modeling or simulation software, and can thus be used to qualify, adjust, or improve the modeling or simulation. For example, modeling software or a simulation can predict a particular circulating fluid pressure at the distal end of the inner tubing, and the accuracy of the software or modeling can be determined by comparing the predicted pressure with the actual measured pressure.

[0014] The determined parameter of the circulating fluid can be transmitted from the sensor unit to the surface in real time or can be stored in the sensor unit for subsequent analysis when the sensor unit has been recovered.

[0015] The method may further comprise circulating a sealing material through the inner tubing, Petition 870260048543, dated 05 / 21 / 2026, page 14 / 38 7 / 30 of the flow port and annular space to at least partially fill the annular space with the sealing material and translate the inner tubing and sensor unit through the wellbore lining tubing while operating the sensor unit to determine at least one parameter of the sealing material in the annular space.

[0016] The distal end of the inner tubing may be coupled to the distal end of the wellbore lining tubing and the method may further comprise uncoupling the distal end of the inner tubing from the distal end of the wellbore lining material.

[0017] The sensor unit can be moved through the wellbore lining tubing before, during, or after forming the sealing material.

[0018] The determined parameter of the sealing material can be used to create or predict at least one of a cement bond log (CBL), a variable density log (VDL), and a cement bond assessment.

[0019] The sensor unit can be operated while the pipe assembly is inserted into the wellbore to determine at least one wellbore parameter, for example, the wellbore diameter or gauge. Petition 870260048543, dated 05 / 21 / 2026, page 15 / 38 8 / 30

[0020] The sensor unit may take any suitable form and may incorporate a suitable combination of sensors. In one example, an azimuthal acoustic transponder / receiver is provided and may penetrate the well lining tubing and provide an indication of external fluid properties. When the sealing material is cement, temperature sensors may detect cement hydration to provide an indication of the cement top.

[0021] The determined parameters of the sealing material in the annular space can be compared with the parameters of the circulating fluid determined via the sensor unit, and the comparison can be used to determine a correlation between them.

[0022] The determined parameters of the sealing material may include one or more of the following: thickness or radial extent of the sealing material in the annular space; presence of other material in the annular space; presence or degree of contamination of the sealing material; degree or location of contamination of the sealing material; physical properties of the sealing material; extent of coverage of the sealing material in the annular space; and location of a higher extent or top of the sealing material in the annular space.

[0023] The circulating fluid may comprise a sequence or succession of different fluids, for example, a Petition 870260048543, dated 05 / 21 / 2026, page 16 / 38 9 / 30 or more of a cleaning or jet washing fluid, a spacer fluid, a sealing fluid, and a displacement fluid. The fluids may be separated by physical barriers, such as plugs. The cleaning or jet washing fluid may be used to prepare the annular space to receive the sealing fluid. The sealing fluid may be a shaping material, such as a fluid cement paste, and may at least partially fill the annular space. The sensor unit may identify the arrival of the physical barriers at the distal end of the inner tubing.

[0024] The sensor unit can determine parameters of different fluids and thus distinguish between different fluids and the transition from one fluid to the next.

[0025] One or more of the different circulating fluids may include tracers, detectable devices, or particles that can be carried along in the fluid. In one example of the description, tracers may be detectable by means of the sensor unit as the fluid containing the tracer units flows through the sensor unit. In another example, tracers may be detectable as the sensor unit is translated by the fluid in the annular space containing the tracers. In one example, tracers may be provided in fluids that are circulated Petition 870260048543, dated 05 / 21 / 2026, p. 17 / 38 10 / 30 for the wellbore before or after the sealing fluid, so that the detection of tracers in the sealing fluid in the annular space is indicative of contamination of the sealing fluid.

[0026] Different circulating fluids may carry different tracers, such that the detection of a particular tracer may be associated with the presence of the associated fluid. Thus, the detection of a higher tracer associated with the sealing fluid in the annular space may be an indication of the higher extent or top of the sealing fluid in the annular space. Furthermore, the detection of tracers associated with two different fluids in the same location in the annular space may be an indication of mixing or cross-contamination of the fluids. Tracers may take any appropriate form, for example, readily detectable material particles, RFID tags, or the like.

[0027] The method may comprise determining the degree of fluid mixing or contamination of the sealing fluid. Contamination may be detected as the sealing fluid passes through the flow port or once the sealing fluid has occupied the annular space. The degree of contamination may be indicative of seal quality and may be used to determine whether the conformal sealing fluid is capable of sealing the wellbore against the Petition 870260048543, dated 05 / 21 / 2026, page 18 / 38 11 / 30 Fluid migration from surrounding formations and prevent fluids from migrating axially through the annular space.

[0028] Laboratory-generated tests of contaminated sealing fluid samples can be used to determine the likely properties of contaminated sealing fluid in a similar manner in the downhole environment.

[0029] According to another aspect of the description, a wellbore cementing method is provided comprising: To provide a downhole piping assembly comprising: a wellbore lining pipe having distal and proximal ends; a flow port at the distal end of the wellbore lining pipe; an inner pipe having distal and proximal ends, and a sensor unit at the distal end of the inner pipe; to move the downhole piping assembly to a drilled wellbore; Run a sealing material through the inner tubing, the flow port, and an annular space between the wellbore lining tubing and the drilled wellbore to fill the annular space at least partially with the sealing material; and move the inner tubing and the sensor unit. Petition 870260048543, dated 05 / 21 / 2026, page 19 / 38 12 / 30 through the wellbore lining tubing while operating the sensor unit to determine at least one feature of the sealing material in the annular space.

[0030] According to an alternative aspect of the description, a wellbore lining method is provided comprising: To provide a downhole piping assembly comprising: a wellbore lining pipe having distal and proximal ends; an inner pipe having distal and proximal ends, and a sensor unit at the distal end of the inner pipe; and to translate the downhole piping assembly to a drilled wellbore while operating the sensor unit to determine a parameter of the drilled wellbore.

[0031] Those skilled in the art will understand that the features described above, and as set forth in the claims below, can be combined as appropriate, and that some of the features will have individual utility. BRIEF DESCRIPTION OF THE DRAWINGS

[0032] These and other aspects of the description will now be described, by way of example only, with reference to the accompanying drawings, in which: Figure 1 is a cross-sectional view of the apparatus of a Petition 870260048543, dated 05 / 21 / 2026, page 20 / 38 13 / 30 first aspect of the present description located in a well borehole; Figure 2 is a view of a sensor unit of the device in Figure 1; Figure 3 is a view of the sensor package of the unit shown in Figure 2; Figure 4 is a cross-sectional view of the apparatus in Figure 1 after the cement has been circulated into the wellbore; and Figure 5 is a cross-sectional view of an apparatus of a second aspect of the present description located in a well borehole.

[0033] To facilitate understanding, identical reference numerals have been used, whenever possible, to designate identical elements that are common to the figures. It is contemplated that elements and resources of one modality can be incorporated in a beneficial way into other modalities without the need for additional recitation. DETAILED DESCRIPTION

[0034] First, reference is made to Figure 1 of the drawings, which shows the apparatus 10 of a first aspect of the present description located in a borehole 12 that was drilled from the surface 14, which may be the seabed or the surface of the ground.

[0035] Apparatus 10 comprises a wellbore lining pipe 16 having distal ends Petition 870260048543, dated 05 / 21 / 2026, page 21 / 38 14 / 30 / lower and proximal / upper 18, 20 and a flow port 22 at the distal end 18. An inner tube 24 having distal / lower and proximal / upper ends 26, 28 extends through the wellbore lining tube 16. The distal end 26 of the inner tube is coupled to the distal end 18 of the wellbore lining tube. A sensor unit 30 is provided at the distal end 26 of the inner tube. As will be described, the sensor unit 30 can be used to determine fluid parameters circulating through the inner tube 24, the flow port 22, and an annular space 32 between the wellbore lining tube 16 and a surrounding wellbore wall 34, and subsequently to obtain a fluid profile in the annular space 32.

[0036] The drawing illustrates a wellbore lining tubing 16 in the form of a casing extending downward from a wellbore head 36 at the surface 14. The wellbore head 36 includes a flow port 38, which may incorporate a valve, to allow controlled flow of fluid to and from an upper end of an internal annular space 102. The distal end 18 of the tubing includes a shoe 40 incorporating a one-way valve, and the flow port 22 extends through the shoe 40.

[0037] In other examples, pipe 16 may be a Petition 870260048543, dated 05 / 21 / 2026, page 22 / 38 15 / 30 conductor, a section of sheathing that is located within an existing sheathing or a lining that is located within and arranged on the existing sheathing.

[0038] The inner tubing 24 is supported by a bedding string 42, which may extend to a surface platform or vessel, such as a mobile offshore drilling vessel (not shown). The bedding string 42 is formed by drill pipe extending through the wellbore head 36. The drill pipe extends downwards through the well lining tubing 16, and most of the length of the inner tubing 24 is also formed by drill pipe. The distal / lower end portion 26 of the inner tubing 24 comprises multiple tubular elements coupled together by appropriate male and female threads, these elements including a short handling tube 50, a sliding joint 52 allowing selective torque transfer, the sensor unit 30, a subcirculating element 54 including a spherical seat 56 and an initially closed side port 57, and a snap-fit / locking connector 58.

[0039] The sliding joint 52 may be a SeaCure telescopic sliding joint system supplied by DeltaTek Global / Expro of Aberdeen and as described in US Patent No. 10,837,241, the description of which is incorporated herein. Petition 870260048543, dated 05 / 21 / 2026, p. 23 / 38 16 / 30 document in its entirety. In an extended configuration, the joint 52 allows torque transfer, such that the rotation of the internal pipe elements 24 above the joint 52 can be transferred to the pipe elements 24 below the joint 52, allowing, for example, the unscrewing of a male thread provided in the connector 58 from a female thread provided in the shoe 40. In a retracted / compressed configuration, the joint 52 does not transfer torque or rotation, allowing rotation of the internal pipe elements 24 above the joint 52 without corresponding rotation of the pipe elements 24 below the joint 52. This allows, for example, an operator to engage or disengage threaded connections associated with an installation tool and a proximal portion of the pipe 24 without affecting the coupling between the connector 58 and the shoe 40.

[0040] Reference is now also made to Figures 2 and 3 of the drawings, which illustrate the sensor unit 30 in more detail. As illustrated in Figure 2, the unit 30 comprises a power section 60, a memory section 62 and a sensor package 64. The sensor package 64 is shown in more detail in Figure 3 and comprises a power section / battery module 70, a memory unit 72, subs containing sensors for detecting tracers, pressure, temperature and pH 73, 74, 76, 78, an acoustic transmitter 80 and upper and lower acoustic receivers 82, 84. Petition 870260048543, dated 05 / 21 / 2026, page 24 / 38 17 / 30

[0041] In operation, the operator may assemble and install the wellbore lining tubing 16 into the wellbore 12, and then assemble and insert the inner tubing 24 into the tubing 16 and engage the connector 58 with the shoe 40. In other examples, particularly in offshore operations, the apparatus 10 may be assembled / mounted directly below a support vessel or rig and the inner tubing 24 may be installed in the wellbore 12 along with the wellbore lining tubing 16.

[0042] To seal and secure pipe 16 in wellbore 12, the annular space 32 is filled with forming material, in this example, cement 90, as illustrated in Figure 4 of the drawings, and the cementing process will now be described.

[0043] The placement of cement 90 in the annular space 32 involves the circulation of a sequence or succession of different fluids, in this example, a jet wash fluid 92, a spacer fluid 94, a fluid cement slurry 90, and a displacement fluid 96. The fluids are prepared at the surface and then pumped down through the bedding string and the inner string 24. First, the jet wash fluid 92 is pumped down the inner string 24 and out of the flow port 22 and into the annular space 32. It is likely that the annular space 32 was filled with drilling fluid 98 and this Petition 870260048543, dated 05 / 21 / 2026, page 25 / 38 18 / 30 is displaced by jet washing fluid 92, which also cleans and prepares the annular space 32 to receive cement 90. The jet washing fluid 92 is followed by a volume of spacer fluid 94 which assists in fluid separation and fluid displacement to prevent mixing and subsequent fluid contamination.

[0044] The fluid cement paste 90 is then pumped into the annular space 32, the volume of the fluid paste 90 being selected such that the cement 90 at least partially fills the annular space 32. The displacement fluid 96 is then pumped down the inner column 24, separated from the cement 90 by a sphere 100. The fluid circulation continues until the sphere 100 lands in the subcirculating 54, creating a perceptible increase in the fluid pressure that is being monitored and measured at the surface. The return of the relatively dense cement U-tube 90 in the annular space 32 to the inner tubing 24 is prevented by the one-way valve in the shoe 40. Continued pumping of the displacement fluid causes the side gate 57 to open, allowing continued fluid circulation via the inner annular space 102 between the wellbore lining tubing 16 and the inner tubing 24.This continuous fluid circulation can be useful for a variety of reasons, for example, to clean cement residue from... Petition 870260048543, dated 05 / 21 / 2026, page 26 / 38 19 / 30 inner column 24, perform pressure testing or pressurization of wellbore lining tubing 16 or modify the wellbore temperature to, for example, control the cement forming rate, as described in US Patent No. 11,111,755, the description of which is incorporated herein in its entirety.

[0045] A person skilled in the art will understand that the fluid placement illustrated in Figure 4 is merely an illustrative example. In other operations, the jet washing fluid 92 will have been circulated for an extended period and all the drilling fluid 98 will have been displaced from the annular space 32 and, in some operations, the volume of fluid cement paste 90 may be selected to completely fill the annular space 32.

[0046] In the example illustrated, the washing fluids and spacers 92, 94 and the fluid cement paste 90 include tracers 104, 106, 108 that are carried along in the fluids 90, 92, 94 during circulation and remain uniformly spaced in the fluids 90, 92, 94 once fluid circulation in the annular space 32 has been interrupted.

[0047] The sensor unit 30 operates while fluids are circulating. The unit 30 can be operated continuously, either timed or switched on and off as desired, by sending signals from the surface, for example, pressure sequences or Petition 870260048543, dated 05 / 21 / 2026, page 27 / 38 20 / 30 electrical signals, if the inner column was formed by drill pipes with wires. In this way, the parameters (flow rate, pressure, temperature and pH) of the fluids will have been detected as the fluids pass through the respective sensors 74, 76 and 78. The information gathered by the sensors will be stored in memory unit 72. Subsequently, the information can be compared with corresponding measurements obtained at the surface.

[0048] The determined parameters are also compared with the bottomhole parameters predicted by modeling or simulation software and, in this way, can be used to qualify, adjust, or improve the modeling or simulation. For example, the modeling software or a simulation can predict a particular pressure of the circulating fluid at the distal end of the inner tubing, and the accuracy of the software or modeling can be determined by comparing the predicted pressure with the actual measured pressure.

[0049] The different fluids being circulated and the contamination dislodged from the inner column 24 can mix and result in a degree of cement contamination 90. The sensors provide an indication of the degree of mixing and contamination as the fluids flow into the annular space 32. In addition, the different densities of the fluids in the wellbore 12 and the significant effect of pressure Petition 870260048543, dated 05 / 21 / 2026, pages 28 / 38 21 / 30 hydrostatic pressure can cause the flow rate through flow port 22 to be significantly different from the flow rate of the fluid being pumped to the wellbore at the surface and the flow rate of the displaced, or returned, fluid measured at the surface. This condition can be referred to as a U-pipe, and the data transmitted or retrieved from the sensors can provide the operator with useful information about this condition and facilitate improvements in fluid circulation and placement in subsequent operations.

[0050] The data obtained by the sensors also allow the operator to determine or measure the actual characteristics or rheology of the fluids at flow port 22, facilitating subsequent improvement of fluid circulation parameters to provide improved mud removal, wellbore cleaning, fluid slurry placement, and the like.

[0051] The inner string 24 is then retrieved from the wellbore 12 by extending the sliding joint 52 and rotating the inner string 24 to disengage the connector 58 from the shoe 40. The string 24 is then pulled out of the wellbore, with at least the tracer sensor 73, the acoustic transmitter 80 and the acoustic receivers 82 and 84 in operation. The azimuthal transponder / acoustic receiver array penetrates the wellbore lining tubing 16 and provides a profile of the properties of the various fluids in the annular space 32, including cement hydration, Petition 870260048543, dated 05 / 21 / 2026, pp. 29 / 38 22 / 30 thickness or radial extent of cement 90 in annular space 32, presence of other material in annular space, presence or degree of fluid contamination of cement 90; degree or location of contamination of cement 90; physical properties of cement 90, extent of cement coverage in annular space 32 and location of the highest extent of cement 90 in annular space 32.

[0052] The temperature sensor 76 can be operated to detect cement hydration, or more particularly the heat of hydration, which is the heat generated when water reacts with Portland cement during the curing process. A measured temperature drop will identify the top of the cement in the annular space 32. Furthermore, by comparing the detected temperature with a temperature model for the composition of the cement flow paste being used, the operator can determine useful information about the cement flow paste 90 at different axial locations along the length of the wellbore 12.

[0053] The profile obtained by tracer sensor 73 will also identify the location of tracers 104, 106, 108, and this information is used to identify the location of cement, washing fluids and spacer 90, 92, 94 in annular space 32. The presence of tracers 104, 106 mixed with tracer 108 in cement 90 can be used to identify if there has been any contamination of cement 90 by Petition 870260048543, dated 05 / 21 / 2026, pages 30 / 38 23 / 30 other fluids 92, 94. Alternatively, or additionally, a lower than expected concentration of cement tracers 108 in a portion of the wellbore that should be completely filled with cement 90 will indicate cement contamination or a lower than expected volume of cement 90.

[0054] The tracer sensor 73 will be selected based on the shape of the tracers 104, 106, and 108 present. For example, if the tracers 104, 106, and 108 are radioactive, such as soluble tracers or sand or glass microspheres coated with radioactive material, a gamma ray spectral profile obtained by sensor 73 can be compared with the gauge profile, that is, the profile obtained by operating sensor 73 as the sensor unit 30 is being inserted into the wellbore 12. The concentration of tracers 104, 106, and 108 present in the fluids is known, such that variations detected in the concentration of tracers present in the fluid placed in the annular space 32, particularly at the boundaries between the fluids, are indicative of fluid contamination.

[0055] The inner column 24 may remain in the wellbore 12 until the cement 90 has formed, but typically column 24 will be recovered relatively quickly after the cement 90 has been pumped into the annular space 32. Thus, the profile obtained by sensors 80, 82 and 84 Petition 870260048543, dated 05 / 21 / 2026, pages 31 / 38 24 / 30 will relate to uncured cement, in contrast to a conventional cement profiling operation, which is performed subsequently, once the cement in the annular space has cured and hardened. However, the profile obtained using apparatus 10 of the present description will provide equivalent information about cement 90 and will provide a significant time saving, since a separate subsequent profiling operation is not required.

[0056] The data retrieved from the various sensors will provide a clear indication of any parts of the annular space 32 that have not been filled with the expected volume of cement 90, or that contain cement mixed with or contaminated with other fluids or materials. By comparing with laboratory-generated cement 90 samples with similar levels of contamination, the operator can predict the likely properties of the contaminated cement when the cement is formed in the annular space 32. If the operator identifies that the quality of the contaminated cement formed is likely to compromise the integrity or safety of the wellbore, additional measures can be taken, for example, tamping the cement to inject additional cement into selected parts of the annular space 32.

[0057] Reference is now made to Figure 5 of the drawings, a cross-sectional view of apparatus 110 of a second aspect of the present description located in a well borehole. Petition 870260048543, dated 05 / 21 / 2026, pages 32 / 38 25 / 30 112.

[0058] Apparatus 110 is similar to apparatus 10 described above in many respects, but features a simplified inner column 124, omitting a sliding joint and a shoe connector arrangement. Because the inner annular space 202 is closed, except for the shoe flow port 122, and the fluids pumped through the inner column 124 are denser than the drilling fluid filling the annular space 202, the fluids flowing from the distal end 126 of the inner column will flow through the flow port 122 and into the outer annular space 132.

[0059] The sensor unit 130 may include operable sensors to generate a wellbore 112 gauge profile as the unit 130 is lowered into the wellbore 112. Such a profile identifies the diameter of the wellbore 112 and the presence of instability in the wellbore wall and in washouts (large diameter areas). The data can be transmitted to the surface, allowing the operator to optimize the operating fluid pumping schedule and the fluid rheology to be adapted to account for the fluid's orifice cleaning capabilities, optimize fluid cement slurry placement, and fluid interface mixing.

[0060] A person skilled in the art will understand that the methods and devices described above are merely examples. Petition 870260048543, dated 05 / 21 / 2026, pages 33 / 38 26 / 30 illustrative of the present description. In other examples, other types of sensors may be provided; for example, tracers may be magnetic materials that can be detected by magnetometers due to the distortion of the Earth's magnetic fields. Tracers may include elements that have a high neutron cross-section and become radioactive upon activation by neutrons, such as boron or cadmium, or upon activation by gamma rays. Such tracers may be activated by a pulsed neutron generator or by a radioactive source. Tracers may be passive and produce a return signal when excited by an acoustic or electromagnetic interrogation signal. Active tags may include transceivers that transmit acoustic or electromagnetic return signals in response to receiving an interrogation signal.Tracers can be acoustic tags that transmit different frequencies and, in this way, facilitate the differentiation of the dosed fluids.

[0061] The sensor unit may include other types or forms of sensors, measuring, for example: fluid capacitance; fluid conductivity; fluid resistivity; fluid ion measurement or fluid optical properties. The operator will select sensors that are appropriate for the local conditions, the fluid properties or parameters to be determined, the fluids present, and the form or Petition 870260048543, dated 05 / 21 / 2026, pages 34 / 38 27 / 30 nature of the data you want to obtain.

[0062] The different sensors can be operated in a continuous mode, that is, during the activation of the device, during fluid circulation and while the device is being driven out of the wellbore, or only during predetermined stages of an operation, providing the operator with a wide range of useful information.

[0063] The sensor unit may be operable to provide depth correlation, which can be used to confirm the depth of data obtained from other sensors. Suitable sensors for providing depth correlation may include casing collar locators (CCLs) or gamma ray sensors. Casing collar locators provide direct detection of casing collars in well casing tubing, while data obtained from gamma ray sensors can be compared to previously obtained gamma ray profiles. Alternatively, or additionally, downhole sensor data may be correlated with surface readings from drilling rig depth measurement devices, such as those provided by NOV M / D Totco.

[0064] The provision of an unfinished well gauge sensor provides the operator with useful information in planning the cementing operation and, in addition to or as an alternative Petition 870260048543, dated 05 / 21 / 2026, pages 35 / 38 28 / 30 to the spectral gamma ray sensor described above, the gauge sensor can be a density, sonic, unfinished well geometry, imaging, or ultrasonic imaging tool.

[0065] A person skilled in the art will understand that the various aspects of the description provide the operator with a range of information that is not otherwise available or that requires additional procedures, such as performing cement profiles after the cement has formed in the wellbore. This provides the operator with information that can be used to, for example, improve or modify current or subsequent cementing operations, or to optimize existing operational models or designs. The real-time information available to the operator allows any operational defects or failures to be studied, evaluated, and overcome or avoided in subsequent operations.

[0066] Reference numerals: apparatus10 wellbore12 surface14 wellbore lining tubing16 distal / lower end of wellbore lining tubing18 proximal / upper end of wellbore lining tubing Petition 870260048543, dated 05 / 21 / 2026, pages 36 / 38 29 / 30 wellbore hole 20 flow port 22 inner tubing 24 distal / lower end of inner tubing 26 proximal / upper end of inner tubing 28 sensor unit 30 annular space 32 wellbore wall 34 wellhead 36 flow port 38 shoe 40 seating column 42 short handling tube 50 sliding joint 52 subcirculator 54 ball seat 56 side port 57 snap-in / locking connector 58 power section 60 memory section 62 sensor package 64 power section / battery module 70 memory unit 72 subtracer 73 subpressure 74 Petition 870260048543, dated 05 / 21 / 2026, pages 37 / 38 30 / 30 temperature substation 76 pH substation 78 acoustic transmitter 80 upper and lower acoustic receivers 82 cement 90 jet washing fluid 92 spacer fluid 94 displacement fluid 96 drilling fluid 98 sphere 100 internal annular space 102 tracers 104, 106 108 apparatus 110 wellbore 112 shoe flow port 122 inner column 124 sensor unit 130 outer annular space 132 inner annular space Petition 870260048543, dated 05 / 21 / 2026, page 38 / 38

Claims

1. A downhole tubing assembly for location in a drilled wellbore and within a wellbore lining tubing having distal and proximal ends and a flow port at the distal end of the wellbore lining tubing, the downhole tubing assembly characterized in that it comprises: an inner tubing having distal and proximal ends, and a sensor unit at the distal end of the inner tubing, the downhole tubing assembly for location in a drilled wellbore and within a wellbore lining tubing whereby the sensor unit is operable to determine at least one of: a wellbore parameter;a fluid parameter circulating through the inner tubing, the flow port, and an annular space between the wellbore lining tubing and a surrounding wellbore wall, and a fluid parameter in the annular space between the wellbore lining tubing and the surrounding wellbore wall.

2. Wellbore tubing assembly according to claim 1, characterized in that the sensor unit is operable to determine a parameter of a sealing fluid that has been circulated in the annular space between the wellbore lining tubing and the surrounding wellbore wall.

3. A wellbore tubing assembly according to claim 2, characterized in that the sensor unit is operable to determine a parameter of fluid cement slurry that has been circulated in the annular space between the wellbore lining tubing and the surrounding wellbore wall.

4. A downhole piping assembly according to claim 3, characterized in that the sensor unit is operable to determine at least one of the presence of contamination in the sealing fluid and the degree of contamination in the sealing fluid.

5. Wellbore liner assembly according to claim 1, characterized in that the sensor unit comprises at least one of: an operable sensor for detecting tracers in fluid that has been circulated in the annular space between the wellbore liner and the surrounding wellbore wall; an azimuthal acoustic transponder / receiver; and a temperature sensor.

6. Wellbore pipe assembly according to claim 1, characterized in that the sensor unit is operable to measure the wellbore diameter as the sensor unit is translated into the wellbore.

7. Well bottom piping assembly, according to Petition 870250081266, dated 10 / 09 / 2025, page 54 / 67 3 / 8 with claim 1, characterized in that the sensor unit is operable to determine at least one of temperature, pressure, density, flow rate, pH and acoustic impedance of fluid circulating through the inner column.

8. Wellbore liner assembly according to claim 1, characterized in that it further comprises a wellbore liner having distal and proximal ends and a flow port at the distal end of the wellbore liner.

9. Wellbore tubing assembly according to claim 8, characterized in that the distal end of the inner tubing is coupled to the distal end of the wellbore lining tubing.

10. Method for cementing a wellbore lining pipe into a drilled wellbore, the wellbore lining pipe having distal and proximal ends and a flow port at the distal end, the method characterized in that it comprises: providing an inner pipe having distal and proximal ends, and a sensor unit at the distal end of the inner pipe; translating the inner pipe into the wellbore lining pipe. Petition 870250081266, dated 10 / 09 / 2025, page 10.55 / 67 4 / 8 wellbore lining and to the wellbore; circulate flow through the inner tubing, the flow port, and an annular space between the wellbore lining tubing and the wellbore, the fluid comprising a forming material; fill at least partially the annular space between the wellbore lining tubing and the drilled wellbore with the forming material; translate the inner tubing out of the wellbore lining tubing, and operate the sensor unit to determine at least one of: a wellbore parameter and a fluid parameter.

11. Method according to claim 10, characterized in that it further comprises operating the sensor unit as the inner tubing is translated out of the wellbore lining tubing and determining at least one parameter of the forming material in the annular space.

12. Method according to claim 11, characterized in that at least one parameter of the forming material in the annular space comprises a degree of contamination of the forming material.

13. Method, according to claim 11, characterized in that it further comprises at least one of: circulating an initial fluid before the forming material and determining the degree of contamination related to the mixing of the initial fluid and the material carried in the initial fluid with the forming material, and determining the properties of a test sample of a contaminated forming material to determine the properties of the contaminated forming material in the annular space.

14. Method according to claim 10, characterized in that it further comprises at least one of: determining a parameter of the fluid circulating through the distal end of the inner tubing, wherein the parameter includes at least one of temperature, pressure, density, flow rate, pH and acoustic impedance, and determining a degree of contamination of the forming material circulating through the distal end of the inner tubing.

15. Method according to claim 14, characterized in that it comprises determining the rheology of the fluid circulating through the distal end of the inner tubing and thereby determining the wellbore cleaning properties of the circulating fluid.

16. Method, according to claim 14, characterized in that it further comprises comparing the determined parameter of the fluid circulating through the distal end of the inner tubing with a corresponding parameter of the circulating fluid as the fluid is pumped into the inner tubing.

17. A method according to claim 10, characterized in that it further comprises at least one of operating the sensor unit as the inner tubing is translated into the wellbore lining tubing and determining at least one wellbore parameter, and operating the sensor unit as the inner tubing is translated into the wellbore lining tubing and determining a wellbore diameter profile.

18. Method according to claim 10, characterized in that it further comprises: operating the sensor unit as the inner tubing is translated into the wellbore to determine a wellbore parameter; operating the sensor unit as the fluid is circulated to determine at least one of temperature, pressure, density, flow rate, pH and acoustic impedance of the fluid passing through the distal end of the inner tubing; and operating the sensor unit as the inner tubing is translated out of the wellbore lining tubing to determine a parameter of the forming material in the annular space.

19. Method according to claim 10, characterized in that it further comprises: coupling the distal ends of the inner tubing and the wellbore lining tubing and, after circulating the fluid, uncoupling the distal ends of the inner tubing and the wellbore lining tubing.

20. Method for cementing a wellbore lining pipe into a drilled wellbore, the wellbore lining pipe having distal and proximal ends and a flow port at the distal end, the method characterized in that it comprises: providing an inner pipe having distal and proximal ends, and a sensor unit at the distal end of the inner pipe; transferring the inner pipe into the wellbore lining pipe and into the wellbore; circulating flow through the inner pipe, the flow port and an annular space between the wellbore lining pipe and the drilled wellbore, the fluid comprising a shaping material; filling at least partially the annular space between the wellbore lining material and the wellbore. Petition 870250081266, dated 10 / 09 / 2025, page.59 / 67 8 / 8 borehole with forming material, and translate the inner tubing out of the wellbore lining tubing while operating the sensor unit to determine a parameter of the forming material in the annular space.

Images