Downhole tubing assembly for downhole sensing

Abstract

A method of cementing a bore-lining tubing in a drilled bore includes providing an inner tubing for location within the bore-lining tubing. The inner tubing has distal and proximal ends, and a sensor unit at the distal end of the inner tubing. The inner tubing is translated into the bore with the sensor unit being operated to determine a parameter of the bore. Fluid is then circulated through the inner tubing, the flow port, and an annulus between the bore-lining tubing and the drilled bore with the sensor unit being operated to determine a parameter of the fluid. The fluid comprises a settable material, such as cement slurry, which at least partially fills the annulus between the bore-lining tubing and the drilled bore. The inner tubing is then translated out the bore-lining tubing with the sensor unit being operated to determine a parameter of the settable material in the annulus.

Description

BACKGROUNDField

[0001] This disclosure relates to downhole operations, particularly to downhole cementing operations in which bore-lining tubing is cemented in a drilled bore.Description of the Related Art

[0002] In the oil and gas exploration and production industry, subsurface hydrocarbon-bearing rock formations may be accessed using bores drilled from land surface or sub-sea in an offshore environment. The drilled bores may be lined with metal tubing, known as casing and liner. The annulus between the tubing and the surrounding bore wall may be filled and sealed with settable material, typically cement. Operators take steps to ensure the quality of the cement annulus. There have been numerous proposals to monitor the delivery of cement into the annulus, and to identify the distribution of cement within the annulus; for example, see U.S. Patent Nos. US10,738,590, US10,539,003, US10,053,979, and US9,879,519.SUMMARY

[0003] According to an aspect of the disclosure there is provided a bore cementing method comprising:

[0004] providing a downhole tubing assembly comprising: a bore-lining tubing having distal and proximal ends; a flow port at the distal end of the bore-lining tubing; an inner tubing having distal and proximal ends, and a sensor unit at the distal end of the inner tubing;

[0005] translating the downhole tubing assembly into a drilled bore;

[0006] circulating fluid through the inner tubing, the flow port, and an annulus between the bore-lining tubing and the drilled bore; and

[0007] operating the sensor unit to determine at least one of: a parameter of the bore, and a parameter of the circulating fluid.

[0008] According to another aspect of the disclosure, there is provided a method of cementing a bore-lining tubing located in a drilled bore, the bore-lining tubing having distal and proximal ends and a flow port at the distal end, the method comprising:

[0009] providing an inner tubing having distal and proximal ends, and a sensor unit at the distal end of the inner tubing;

[0010] translating the inner tubing into the bore and into the bore-lining tubing;

[0011] circulating fluid through the inner tubing, the flow port, and an annulus between the bore-lining tubing and the drilled bore; and

[0012] operating the sensor unit to determine at least one of a parameter of the bore, and a parameter of the circulating fluid.

[0013] The sensor unit may be operated as the sensor unit is translated into the bore. The sensor unit may thus be operated to, for example, measure the diameter of the bore, sometimes referred to as the calliper of the bore.

[0014] The sensor unit may be operated as the sensor unit is being retrieved from the bore. The sensor unit may thus be operated to determine a parameter of the bore following the circulation and emplacement of the fluid in the bore, and in particular, the emplacement of the fluid in the annulus between the bore-lining tubing and the drilled bore.

[0015] Parameters of the circulating fluid determined by the sensor unit may include at least one of pressure, density, flowrate, pH, and acoustic impedance.

[0016] Parameters of the bore determined by the sensor unit may include casing collar location or bore-hole gamma ray detection. Depth correlation of the sensor unit in the bore lining tubing could include direct detection of casing collars or correlating down hole sensor data with data acquired from downhole drilling assemblies or from surface read-out data acquired from the drilling rig depth measuring devices such as supplied by NOV M / D Totco.

[0017] While circulating the fluid, the distal end of the inner tubing may be coupled to the distal end of the bore-lining tubing. Alternatively, the distal end of the inner tubing may be spaced from the distal end of the bore-lining tubing.

[0018] According to a further aspect of the disclosure, there is provided a downhole tubing assembly comprising: a bore-lining tubing having distal and proximal ends; a flow port at the distal end of the bore-lining tubing; an inner tubing having distal and proximal ends; and a sensor unit at the distal end of the inner tubing for determining a parameter of fluid circulating through the inner tubing, the flow port, and an annulus between the bore-lining tubing and a surrounding bore wall.

[0019] According to a still further aspect of the disclosure, there is provided a downhole tubing assembly for location in a drilled bore and within a bore-lining tubing having distal and proximal ends and a flow port at the distal end of the bore-lining tubing, the downhole tubing assembly comprising: 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 bore and within a bore-lining tubing whereby the sensor unit is operable to determine at least one of: a parameter of the bore, and a parameter of fluid circulating through the inner tubing, the flow port, and an annulus between the bore-lining tubing and a surrounding bore wall.

[0020] The sensor unit may be operable to determine a parameter of the circulating fluid including at least one of the pressure, density, pH and flowrate. The sensor unit may comprise a plurality of different sensors and may be used to determine a plurality of parameters and properties of the circulating fluid. The senser unit may determine a parameter or property directly, or information gathered by the sensor unit may be subsequently analysed or interrogated to determine the parameter.

[0021] The determined parameter may be compared to a parameter of the circulating fluid that was known or was previously determined at surface. Alternatively, or in addition, the determined parameter may be compared with a bottom hole parameter predicted by modelling software or simulation, and thus may be utilised to qualify, adjust or improve the modelling or simulation. For example, modelling software or a simulation may predict a particular circulating fluid pressure at the distal end of the inner tubing, and the accuracy of the software or modelling may be determined by comparing the predicted pressure with the actual measured pressure.

[0022] The determined parameter of the circulating fluid may be transmitted from the sensor unit to surface in real time or may be stored in the sensor unit for subsequent analysis when the sensor unit has been retrieved.

[0023] The method may further comprise circulating a sealing material through the inner tubing, the flow port, and the annulus to at least partially fill the annulus with the sealing material, and translating the inner tubing and the sensor unit through the bore-lining tubing while operating the sensor unit to determine at least one parameter of the sealing material in the annulus.

[0024] The distal end of the inner tubing may be coupled to the distal end of the bore-lining tubing and the method may further comprise uncoupling the distal end of the inner tubing from the distal end of the bore-lining material,

[0025] The sensor unit may be translated through the bore-lining tubing before, during or following setting of the sealing material.

[0026] The determined parameter of the sealing material may be utilised to create or predict at least one of a cement bond log (CBL), a variable density log (VDL), and a cement bond evaluation.

[0027] The sensor unit may be operated as the tubing assembly is run into the bore to determine at least one parameter of the bore, for example the diameter or calliper of the bore.

[0028] The sensor unit may take any appropriate form and may incorporate an appropriate combination of sensors. In one example an azimuthal acoustic transponder / receiver is provided and may penetrate the bore-lining tubing and provide an indication of external fluid properties. Where the sealing material is cement, temperature sensors may detect cement hydration to provide an indication of top of cement.

[0029] The determined parameters of the sealing material in the annulus may be compared with the parameters of the circulating fluid determined via the sensor unit, and the comparison may be used to determine a corelation therebetween.

[0030] The determined parameters of the sealing material may include one or more of: thickness or radial extent of sealing material in the annulus; presence of other material in the annulus, 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 sealing material coverage in the annulus, and location of an uppermost extent or top of the sealing material in the annulus.

[0031] The circulating fluid may comprise a sequence or train of different fluids, for example one or more of a cleaning or flushing 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 flushing fluid may be used to prepare the annulus for receiving the sealing fluid. The sealing fluid may be a settable material, such as a cement slurry, and may at least partially fill the annulus. The sensor unit may identify the arrival of the physical barriers at the distal end of the inner tubing.

[0032] The sensor unit may determine parameters of the different fluids and may thus distinguish between the different fluids, and the transition from one fluid to the next fluid.

[0033] One or more of the different circulating fluids may include tracers, detectable devices or particles that may be entrained in the fluid. In one example of the disclosure, the tracers may be detectable by the sensor unit as the fluid containing the tracer units flows past the sensor unit. In another example, the tracers may be detectable as the sensor unit is translated past the fluid in the annulus containing the tracers. In one example, tracers may be provided in fluids that are circulated into the bore in advance of or following the sealing fluid, such that detection of the tracers in the sealing fluid in the annulus is indicative of contamination of the sealing fluid.

[0034] The 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, detection of an uppermost tracer associated with the sealing fluid in the annulus may be an indication of the uppermost extent or top of the sealing fluid in the annulus. Further, detection of tracers associated with two different fluids at the same location in the annulus may be an indication of mixing or cross-contamination of the fluids. The tracers may take any appropriate form, for example particles of readily detectable material, RFID tags, or the like.

[0035] The method may comprise determining a degree of fluid mixing or contamination of the sealing fluid. Contamination may be detected as the sealing fluid is passing through the flow port, or once the sealing fluid has occupied the annulus. The degree of contamination may be indicative of sealing quality and may be used to determining if the set sealing fluid is likely to be capable of sealing the bore against fluids migrating from surrounding formations and preventing fluids from migrating axially through the annulus.

[0036] Testing of laboratory generated contaminated sealing fluid samples may be used to determine the likely properties of similarly contaminated sealing fluid in the downhole environment.

[0037] According to another aspect of the disclosure there is provided a bore cementing method comprising:

[0038] providing a downhole tubing assembly comprising: a bore-lining tubing having distal and proximal ends; a flow port at the distal end of the bore-lining tubing; an inner tubing having distal and proximal ends, and a sensor unit at the distal end of the inner tubing;

[0039] translating the downhole tubing assembly into a drilled bore;

[0040] circulating a sealing material through the inner tubing, the flow port, and an annulus between the bore-lining tubing and the drilled bore to fill the annulus at least partially with the sealing material; and

[0041] translating the inner tubing and the sensor unit through the bore-lining tubing while operating the sensor unit to determine at least one feature of the sealing material in the annulus.

[0042] According to an alternative aspect of the disclosure there is provided a bore-lining method comprising:

[0043] providing a downhole tubing assembly comprising: a bore-lining tubing having distal and proximal ends; an inner tubing having distal and proximal ends, and a sensor unit at the distal end of the inner tubing; and

[0044] translating the downhole tubing assembly into a drilled bore while operating the sensor unit to determine a parameter of the drilled bore.

[0045] The skilled person will appreciate that the features described above, and as recited in the claims below, may be combined as appropriate, and that some of the features will have individual utility.BRIEF DESCRIPTION OF THE DRAWINGS

[0046] These and other aspects of the disclosure will now be described, by way of example only, with reference to the accompanying drawings, in which:

[0047] FIG. 1 is a sectional view of apparatus of a first aspect of the present disclosure located in a well bore;

[0048] FIG. 2 is a view of a sensor unit of the apparatus of FIG. 1;

[0049] FIG. 3 is a view of the sensor package of the unit of FIG. 2;

[0050] FIG. 2 is a sectional view of the apparatus of FIG. 1 following the circulation of cement into the well bore, and

[0051] FIG. 5 is a sectional view of an apparatus of a second aspect of the present disclosure located in a well bore.

[0052] To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements and features of one embodiment may be beneficially incorporated in other embodiments without further recitation.DETAILED DESCRIPTION

[0053] Reference is first made to FIG. 1 of the drawings, which shows apparatus 10 of a first aspect of the present disclosure located in a well bore 12 that has been drilled from surface 14, which may be the seabed or land surface.

[0054] The apparatus 10 comprises a bore-lining tubing 16 having distal / lower and proximal / upper ends 18, 20 and a flow port 22 at the distal end 18. An inner tubing 24 having distal / lower and proximal / upper ends 26, 28 extends through the bore-lining tubing 16. The inner tubing distal end 26 is coupled to the bore-lining tubing distal end 18. A sensor unit 30 is provided at the inner tubing distal end 26. As will be described, the sensor unit 30 may be used to determine parameters of fluid circulating through the inner tubing 24, the flow port 22, and an annulus 32 between the bore-lining tubing 16 and a surrounding bore wall 34, and subsequently to obtain a log of the fluids in the annulus 32.

[0055] The drawing illustrates a bore-lining tubing 16 in the form of casing that extends downwards from a well head 36 on the surface 14. The well head 36 includes a flow port 38, that may incorporate a valve, to allow controlled flow of fluid from and into an upper end of an inner annulus 102. The tubing distal end 18 includes a shoe 40 incorporating a one-way valve, and the flow port 22 extends through the shoe 40.

[0056] In other examples the tubing 16 may be a conductor, a section of casing that is located within existing casing, or a liner that is located within and mounted to existing casing.

[0057] The inner tubing 24 is supported by a landing string 42, which may extend to a surface platform or vessel such as a mobile offshore drilling ship (not shown). The landing string 42 is formed of drill pipe which extends through the well head 36. The drill pipe extends down through the bore-lining tubing 16 and the bulk of the length of the inner tubing 24 is also formed of drill pipe. The distal / lower end portion 26 of the inner tubing 24 comprises multiple tubular elements coupled together by appropriate male and female screw threads, these elements including a handling pup joint 50, a slip-joint 52 which allows selective transfer of torque, the sensor unit 30, a circulating sub 54 including a ball seat 56 and initially closed side port 57, and a latch-in / stab-in connector 58.

[0058] The slip-joint 52 may be a SeaCure telescopic slip-joint system as supplied by DeltaTek Global / Expro of Aberdeen, and as described in U.S. Pat. No. 10,837,241, the disclosure of which is incorporated herein in its entirety. In an extended configuration the joint 52 allows transfer of torque so that rotation of the elements of the inner tubing 24 above the joint 52 may be transferred to the elements of the tubing 24 below the joint 52 allowing, for example, unscrewing of a male thread provided on 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 elements of the inner tubing 24 above the joint 52 without corresponding rotation of the elements of the tubing 24 below the joint 52. This allows, for example, an operator to engage or disengage threaded connections associated with a running tool and a proximal portion of the tubing 24 without affecting the coupling between the connector 58 and the shoe 40.

[0059] Reference is now also made to FIGS. 2 & 3 of the drawings, which illustrate the sensor unit 30 in more detail. As illustrated in FIG. 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 further detail in FIG. 3 and comprises a power section / battery pack 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.

[0060] In operation, the operator may make up and install the bore-lining tubing 16 in the bore 12 and then make up and run 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 made up / assembled directly below a support vessel or rig and the inner tubing 24 run into the bore 12 together with the bore-lining tubing 16.

[0061] To seal and secure the tubing 16 in the well bore 12 the annulus 32 is filled with settable material, in this example cement 90, as illustrated in FIG. 4 of the drawings, and the cementing process will now be described.

[0062] Locating the cement 90 in the annulus 32 involves the circulation of a sequence or train of different fluids, in this example a wash fluid 92, a spacer fluid 94, a cement slurry 90, and a displacement fluid 96. The fluids are prepared on surface and then pumped down through the landing string and the inner string 24. First, the wash fluid 92 is pumped down the inner string 24 and out of the flow port 22 and into the annulus 32. The annulus 32 is likely to have been filled with drilling fluid 98 and this is displaced by the wash fluid 92, which also cleans and prepares the annulus 32 for receiving the cement 90. The wash fluid 92 is followed by a volume of spacer fluid 94 which assists with fluid separation and fluid displacement to prevent intermixing and subsequent fluid contamination.

[0063] The cement slurry 90 is then pumped into the annulus 32, the volume of slurry 90 being selected such the cement 90 will at least partially fill the annulus 32. The displacement fluid 96 is then pumped down the inner string 24, separated from the cement 90 by a ball 100. The circulation of the fluids is continued until the ball 100 lands in the circulating sub 54, creating a noticeable increase in the fluid pressure being monitored and measured at surface. U-tubing of the relatively dense cement 90 in the annulus 32 back into the inner tubing 24 is prevented by the one-way valve in the shoe 40. Continued pumping of the displacement fluid causes the side port 57 to open, allowing continued circulation of fluid via the inner annulus 102 between the bore-lining tubing 16 and the inner string 24. This continued circulation of fluid may be useful for a number of reasons, for example clearing cement residue from the inner string 24, pressure testing or pressurisation of the bore-lining tubing 16, or modifying the bore temperature to, for example, control the cement setting rate, for example as described in U.S. Pat. No. 11,111,755, the disclosure of which is incorporated herein in its entirety.

[0064] The skilled person will understand that the fluid placement illustrated in FIG. 4 is merely an illustrative example. In other operations, the wash fluid 92 will have been circulated for an extended period and all the drilling fluid 98 will have been displaced from the annulus 32, and in some operations, the volume of cement slurry 90 may be selected to completely fill the annulus 32.

[0065] In the illustrated example, the wash and spacer fluids 92, 94, and the cement slurry 90, include tracers 104, 106, 108 which are entrained in the fluids 90, 92, 94 during circulation and remain uniformly spaced in the fluids 90, 92, 94 once fluid circulation in the annulus 32 has halted.

[0066] The sensor unit 30 is operating as the fluids are circulated. The unit 30 may be operated continuously, may be timer operated, or may be turned on and off as desired by sending signals from surface, for example pressure sequences or electrical signals if the inner string has been formed of wired drill pipe. Thus, the parameters (flowrate, pressure, temperature and pH) of the fluids will have been detected as the fluids pass through the respective sensors 74, 76, 78. The information gathered by the sensors will be stored in the memory unit 72. Subsequently, the information may be compared with corresponding measurements taken at surface.

[0067] The determined parameters are also compared with bottom hole parameters predicted by modelling software or simulation, and thus may be utilised to qualify, adjust or improve the modelling or simulation. For example, the modelling software or a simulation may predict a particular circulating fluid pressure at the distal end of the inner tubing, and the accuracy of the software or modelling may be determined by comparing the predicted pressure with the actual measured pressure.

[0068] The different fluids being circulated, and contamination dislodged from the inner string 24, may comingle and result in a degree of contamination of the cement 90. The sensors provide an indication of the degree of comingling and contamination as the fluids flow into the annulus 32. Further, the different densities of the fluids in the bore 12, and the significant effect of hydrostatic pressure, may lead to the flowrate through the flow port 22 being significantly different from the flowrate of fluid being pumped into the bore at surface, and the flowrate of displaced fluid, or returns, measured at the surface. This condition may be referred to a U-tubing, and the data transmitted or retrieved from the sensors may provide an operator with useful information on this condition and facilitate improvements in fluid circulation and placement in subsequent operations.

[0069] The data obtained by the sensors also allows the operator to determine or measure the actual characteristics or rheology of the fluids at the flow port 22, facilitating subsequent improvement of fluid circulation parameters to provide improved mud removal, bore cleaning, slurry placement, and the like.

[0070] The inner string 24 is then retrieved from the bore 12 by extending the slip-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 hole, with at least the tracer sensor 73, the acoustic transmitter 80 and the acoustic receivers 82, 84 operating. The azimuthal acoustic transponder / receiver arrangement penetrates the bore-lining tubing 16 and provides a log of properties of the various fluids in the annulus 32, including cement hydration, thickness or radial extent of the cement 90 in the annulus 32, presence of other material in the annulus, presence or degree of fluid contamination of the cement 90; degree or location of contamination of the cement 90; physical properties of the cement 90, extent of cement coverage in the annulus 32, and location of an uppermost extent of the cement 90 in the annulus 32.

[0071] The temperature sensor 76 may be operated to detect cement hydration, or more particularly the heat of hydration, that is the heat generated when water reacts with Portland cement during the curing process. A measured drop in temperature will identify the top of the cement in the annulus 32. Further, by comparing the detected temperature with a temperature model for the cement slurry composition being used, the operator may determine useful information on the cement slurry 90 at different axial locations along the length of the bore 12.

[0072] The log obtained by the tracer sensor 73 will also identify the location of the tracers 104, 106, 108, and this information is used to identify the location of the cement, wash and spacer fluids 90, 92, 94 in the annulus 32. The presence of tracers 104, 106 comingled with the tracers 108 in the cement 90 may be used to identify whether there has been any contamination of the cement 90 by the other fluids 92, 94. Alternatively, or in addition, a lower than expected concentration of cement tracers 108 in a portion of the bore that was expected to be completely filled with cement 90 will indicate cement contamination or a lower than expected volume of cement 90.

[0073] The tracer sensor 73 will be selected based on the form of tracers 104, 106, 108 present. For example, if the tracers 104, 106, 108 are radioactive, such as soluble tracers or sand or glass beads coated with radioactive material, a spectral gamma ray log obtained by the sensor 73 may be compared with the calliper log, that is the log obtained by operating the sensor 73 as the sensor unit 30 is being run into the bore 12. The concentration of the tracers 104, 106, 108 present in the fluids is known, such that detected variations in the concentration of the tracers present in the fluid emplaced in the annulus 32, particularly at the boundaries between the fluids, are indicative of fluid contamination.

[0074] The inner string 24 may remain in the bore 12 until the cement 90 has set, but typically the string 24 will be retrieved relatively quickly after the cement 90 has been pumped into the annulus 32. Thus, the log obtained by the sensors 80, 82, 84 will relate to uncured cement, in contrast to a conventional cement logging operation which is carried out subsequently, once the cement in the annulus has cured and hardened. However, the log obtained using the apparatus 10 of the present disclosure will provide equivalent information on the cement 90, and provides a significant saving of time, as a separate subsequent logging operation is not required.

[0075] The data retrieved from the various sensors will provide a clear indication of any parts of the annulus 32 that have not been filled with an expected volume of cement 90, or which contain cement mixed or contaminated with other fluids or materials. By comparison with laboratory generated samples of cement 90 with similar levels of contamination the operator may predict the likely properties of the contaminated cement when the cement has set in the annulus 32. If the operator identifies that the quality of the set contaminated cement is likely to compromise the integrity or safety of the bore, additional measures may be taken, for example a cement squeeze to inject addition cement into selected parts of the annulus 32.

[0076] Reference is now made to FIG. 5 of the drawings, a sectional view of apparatus 110 of a second aspect of the present disclosure located in a well bore 112.

[0077] The apparatus 110 is similar to the apparatus 10 described above in many respects, but features a simplified inner string 124, omitting a slip joint and a shoe connector arrangement. As the inner annulus 202 is closed, apart from the shoe flow port 122, and the fluids being pumped down the inner string 124 are denser than the drilling fluid that fills the annulus 202, fluids flowing from the inner string distal end 126 will flow through the flow port 122 and into the outer annulus 132.

[0078] The sensor unit 130 may include sensors operable to generate a calliper log of the bore 112 as the unit 130 is lowered into the bore 112. Such a log identifies the diameter of the bore 112, and the presence of instability in the bore wall and washouts (large diameter areas). The data may be transmitted to surface, allowing the operator to optimise the operational fluid pumping schedule and fluid rheology to be tailored to take account of fluid hole-cleaning capabilities, optimise cement slurry placement, and fluid interface mixing.

[0079] The skilled person will understand that the methods and apparatus described above are merely illustrative examples of the present disclosure. In other examples, other forms sensors may be provided, for example the tracers may be magnetic materials that could be detected by magnetometers due to distortion of the Earth's magnetic fields. The tracers may include elements that have a high neutron cross section and become radioactive upon neutron activation, such as boron or cadmium, or on activation by gamma rays. Such tracers could be activated by a pulsed neutron generator or by a radioactive source. The 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. The tracers may be acoustic tags which transmit different frequencies and thus facilitate in the differentiation of the dosed fluids.

[0080] The sensor unit may include other sensor types or forms, 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 that are to be determined, the fluids present, and the form or nature of the data it is desired to obtain.

[0081] The different sensors may be operated continuously, that is during tripping in of the apparatus, during fluid circulation, and while the apparatus is tripped out of the bore, or only during predetermined stages of an operation, providing the operator with a wide range of useful information.

[0082] The sensor unit may be operable to provide depth correlation, which may be utilised 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 the casing collars in the bore-lining tubing, while data obtained from gamma ray sensors may be compared to previously obtained gamma-ray logs. Alternatively, or in addition, down hole sensor data may be correlated with surface read-outs from the drilling rig depth measuring devices such as those supplied by NOV M / D Totco.

[0083] The provision of a borehole calliper sensor provides the operator with information useful in planning the cementing operation, and in addition to or as an alternative to the spectral gamma ray sensor described above, the calliper sensor may be a density, sonic, borehole geometry, imaging, or ultrasonic imaging tool.

[0084] The skilled person will appreciate that the various aspects of the disclosure provide the operator with a range of information that is not otherwise available, or requires additional procedures, such as running cement logs after the cement has set in the bore. This provides the operator with information that may be used to, for example, improve or modify current or subsequent cementing operations, or to optimise existing models or operational designs. The real-time information available to the operator allows any operational shortcomings or failures to be studied and evaluated and overcome or avoided in subsequent operations.REFERENCE NUMERALSapparatus 10

[0086] well bore 12

[0087] surface 14

[0088] bore-lining tubing 16

[0089] bore-lining tubing distal / lower end 18

[0090] bore-lining tubing proximal / upper end 20

[0091] flow port 22

[0092] inner tubing 24

[0093] inner tubing distal / lower end 26

[0094] inner tubing proximal / upper end 28

[0095] sensor unit 30

[0096] annulus 32

[0097] bore wall 34

[0098] well head 36

[0099] flow port 38

[0100] shoe 40

[0101] landing string 42

[0102] handling pup joint 50

[0103] slip-joint 52

[0104] circulating sub 54

[0105] ball seat 56

[0106] side port 57

[0107] latch-in / stab-in connector 58

[0108] power section 60

[0109] memory section 62

[0110] sensor package 64

[0111] power section / battery pack 70

[0112] memory unit 72

[0113] tracer sub 73

[0114] pressure sub 74

[0115] temperature sub 76

[0116] pH sub 78

[0117] acoustic transmitter 80

[0118] upper and lower acoustic receivers 82, 84

[0119] cement 90

[0120] wash fluid 92

[0121] spacer fluid 94

[0122] displacement fluid 96

[0123] drilling fluid 98

[0124] ball 100

[0125] inner annulus 102

[0126] tracers 104, 106, 108

[0127] apparatus 110

[0128] well bore 112

[0129] shoe flow port 122

[0130] inner string 124

[0131] sensor unit 130

[0132] outer annulus 132

[0133] inner annulus 202

Claims

1. A downhole tubing assembly comprising:an inner tubing having distal and proximal ends located within a bore-lining tubing and forming an inner annulus, anda sensor unit at the distal end of the inner tubing, whereby the sensor unit is operable to determine at least one of:a parameter of a bore;a parameter of fluid circulating through the inner tubing, the flow port, and an outer annulus between the bore-lining tubing and a surrounding bore wall, anda parameter of fluid in the outer annulus between the bore-lining tubing and the surrounding bore wall.

2. The downhole tubing assembly of claim 1, wherein the sensor unit is operable to determine a parameter of a sealing fluid that has been circulated into the outer annulus between the bore-lining tubing and the surrounding bore wall.

3. The downhole tubing assembly of claim 2, wherein the sensor unit is operable to determine a parameter of cement slurry that has been circulated into the outer annulus between the bore-lining tubing and the surrounding bore wall.

4. The downhole tubing assembly of claim 3, wherein 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. The downhole tubing assembly of claim 1, wherein the sensor unit comprises at least one of: a sensor operable to detect tracers in fluid that has been circulated into the outer annulus between the bore-lining tubing and the surrounding bore wall; an azimuthal acoustic transponder / receiver, and a temperature sensor.

6. The downhole tubing assembly of claim 1, wherein the sensor unit is operable to measure the diameter of the bore as the sensor unit is translated into the bore.

7. The downhole tubing assembly of claim 1, wherein the sensor unit is operable to determine at least one of temperature, pressure, density, flowrate, pH, and acoustic impedance of fluid circulating through the inner string.

8. The downhole tubing assembly of claim 1, further comprising a bore-lining tubing having distal and proximal ends and a flow port at the distal end of the bore-lining tubing.

9. The downhole tubing assembly of claim 8, wherein the distal end of the inner tubing is coupled to the distal end of the bore-lining tubing.

10. A method of cementing a bore-lining tubing in a drilled bore, the bore-lining tubing having distal and proximal ends and a flow port at the distal end, the method comprising:providing an inner tubing having distal and proximal ends, and a sensor unit at the distal end of the inner tubing;translating the inner tubing into the bore-lining tubing and into the bore;circulating fluid through the inner tubing, the flow port, and an annulus between the bore-lining tubing and the bore, the fluid comprising a settable material;at least partially filling the annulus between the bore-lining tubing and the drilled bore with the settable material;translating the inner tubing out of the bore-lining tubing, andoperating the sensor unit to determine at least one of: a parameter of the bore, and a parameter of the fluid.

11. The method of claim 10, further comprising operating the sensor unit as the inner tubing is translated out of the bore-lining tubing and determining at least one parameter of the settable material in the annulus.

12. The method of claim 11, wherein the at least one parameter of the settable material in the annulus comprises a degree of contamination of the settable material.

13. The method of claim 11, further comprising at least one of: circulating an initial fluid in advance of the settable material and determining the degree of contamination relating to mixing of the initial fluid and material entrained in the initial fluid with the settable material, and determining properties of a test sample of a contaminated settable material to determine the properties of the contaminated settable material in the annulus.

14. The method of claim 10, further comprising at least one of: determining a parameter of fluid circulating through the distal end of the inner tubing, and wherein the parameter includes at least one of temperature, pressure, density, flowrate, pH, and acoustic impedance, and determining a degree of contamination of the settable material circulating through the distal end of the inner tubing.

15. The method of claim 14, further comprising determining the rheology of the fluid circulating through the distal end of the inner tubing and thereby determining bore-cleaning properties of the circulating fluid.

16. The method of claim 14, further comprising 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 being pumped into the inner tubing.

17. The method of claim 10, further comprising at least one of operating the sensor unit as the inner tubing is translated into the bore-lining tubing and determining at least one parameter of the bore, and operating the sensor unit as the inner tubing is translated into the bore-lining tubing and determining a diameter profile of the bore.

18. The method of claim 10, further comprising:operating the sensor unit as the inner tubing is translated into the bore to determine a parameter of the bore;operating the sensor unit as the fluid is circulated to determine at least one of the temperature, pressure, density, flowrate, pH, and acoustic impedance of the fluid passing through the distal end of the inner tubing, andoperating the sensor unit as the inner tubing is translated out of the bore-lining tubing to determine a parameter of the settable material in the annulus.

19. The method of claim 10, further comprising: coupling the distal ends of the inner tubing and the bore-lining tubing and, after circulating the fluid, uncoupling the distal ends of the inner tubing and the bore-lining tubing.

20. A method of cementing a bore-lining tubing in a drilled bore, the bore-lining tubing having distal and proximal ends and a flow port at the distal end, the method comprising:providing an inner tubing having distal and proximal ends, and a sensor unit at the distal end of the inner tubing;translating the inner tubing into the bore-lining tubing and into the bore;circulating fluid through the inner tubing, the flow port, and an annulus between the bore-lining tubing and the drilled bore, the fluid comprising a settable material;at least partially filling the annulus between the bore-lining material and the drilled bore with the settable material, andtranslating the inner tubing out of the bore-lining tubing while operating the sensor unit to determine a parameter of the settable material in the annulus

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