Patent Description:
In the oil and gas exploration and production industry wells are constructed to provide access to subsurface hydrocarbon-bearing rock formations, with a bore being drilled from surface to intersect the hydrocarbon-bearing formation. After drilling a section of bore, metal tubing is placed in the bore and an annulus between the tubing and the wall of the drilled bore is sealed with cement. Successive bore sections are lined with smaller diameter metal tubing. The metal tubing may extend back to surface, such tubing being known as casing, or may only extend part way up the bore, such tubing being referred to as liner. A work or running string is used to support a section of liner as the liner is run into the bore, and the arrangement of supports, slips (gripping elements) and seals which secure and seal the upper end of a liner to the adjacent tubing is typically referred to as a liner hanger.

As a section of casing or liner is being lowered in the bore it is conventional to fill the tubing with drilling fluid. This prevents any imbalance between the interior of the tubing and the surrounding hydrostatic pressure as the tubing is run deeper into the fluid-filled bore.

The drilled bores may be vertical, inclined, or may include horizontal sections. For bores including extended horizontal sections it is known to "float" casing into a bore. In this technique air or low-density fluid is trapped in the lower section of the casing string to create a buoyant chamber, reducing the casing weight resting on the low side of the bore, and thus reducing drag and friction during the casing running process. Conventionally, the provision of the buoyant chamber prevents the circulation of fluid through the casing, which would otherwise be used to facilitate translation of the casing string through the bore.

<CIT> discloses methods and apparatus for creating a buoyant casing chamber between a float collar and a packer located within a casing. A length of tubing extends through the packer to the float collar such that fluid may be pumped down the casing and then through the tubing, the float collar, and a guide shoe on the distal end of the casing without disturbing the buoyant chamber. After the casing has been run to the target depth the packer is unseated and the packer and tubing removed to allow the casing to be cemented in the conventional manner.

When a section of casing or liner is being cemented in the bore the cement is pumped from surface down through the interior of the casing, or through the running string and the liner. Typically, the cement will completely fill the annulus surrounding a liner placed at the bottom or distal end of a bore and which may or may not intersect the hydrocarbon-bearing formation. Further, it is standard practice to prepare and pump a volume of cement slurry (cement, water, and chemical additives) in excess of the volume of the liner annulus to be filled to ensure the cemented volume matches or exceeds the annular volume to account for any drilled diameter excess and to ensure that the cement extends over and around the seals in the liner hanger. For intermediate liners and casing only a lower or distal section of the annulus may be filled with cement sufficient to ensure a hydraulic seal and to prevent hydrocarbon leakage from lower formations.

In conventional well casing or liner cementing operations a float shoe is provided at or adjacent the leading or distal end of the tubing, and a float collar is provided perhaps <NUM> to <NUM> feet (<NUM> to <NUM>) above the float shoe and provides a landing for cement wiper plugs; to avoid contamination by well or drilling fluid cement is pumped into the bore between bottom and top wiper plugs. The plugs provide a sliding sealing contact with the inner surface of the tubing and isolate the cement from the drilling fluid that otherwise fills the tubing. When the bottom plug lands on the float collar, continued application of hydraulic pressure from surface ruptures the bottom plug and forces the cement through the plug and the collar, into the volume between the float collar and the float shoe, and then through the float shoe and into the annulus. The cement continues to flow into and fill the annulus until the top plug lands on the bottom plug. The landing of the top plug on the bottom plug is detectable at surface, and at this point the pumping is stopped. This leaves a column of drilling fluid sitting above the top plug and a volume of cement within the distal end of the casing or liner, between the float collar and the float shoe; this volume is known as the shoe track. Typically, this volume of cement is <NUM> to <NUM> feet (<NUM> to <NUM>) long.

The provision of the shoe track minimises the risk of well fluid contamination of the cement which fills the annulus surrounding the bottom of the casing or liner, for example by leakage of well fluid past the top wiper plug. However, when the cement cures the operator is left with a solid plug of cement inside the shoe track.

In most instances the operator will choose to drill the cement out the shoe track. This requires provision of a drill bit which is only slightly smaller than the internal diameter of the casing or liner, to ensure removal of all the cement from within the tubing. If the operator is intending to extend the bore further the drill bit used to remove the cement from the shoe track may then be retrieved to surface and replaced with a slightly smaller drill bit. If the bore is not to be extended further the operator may likely still choose to remove the cement from the shoe track such that the distal end portion of the liner may be utilised to, for example, provide access to a surrounding hydrocarbon-bearing formation. Methods and apparatus for use in running bore-lining tubing are described in applicant's earlier patent applications, including <CIT>, <CIT>, <CIT>, <CIT>, <CIT>, <CIT>, <CIT>, <CIT> and <CIT> the disclosures of which are incorporated herein in their entirety.

<CIT> describes a method and apparatus for running and cementing pipe in which a jet shoe is connected to the lowermost end of a pipe to be placed in a subsea formation. The jet shoe comprises a cylindrical housing in which is arranged an inner tubular receptacle, a check valve permitting downward flow but preventing upward flow through the valve and jet tubes extending from the receptacle through the lower end of the jet shoe. The receptacle, the valve and the tubes are cemented in the housing. A stinger arranged on the lower end of a smaller diameter pipe extends into and seals in the receptacle. A closure member on the smaller pipe releasably closes off the upper end of the larger pipe. The smaller pipe and the attached larger pipe, together with a permanent guide base connected to the upper end of the larger pipe, are lowered to the ocean floor. While jetting fluid through the smaller pipe and out of the shoe, the formation ahead of the shoe is eroded until the larger pipe reaches a predetermined depth. Cement slurry is then pumped downwardly through the smaller pipe and through the jet shoe to cement the larger pipe in the subsea formation.

<CIT> describes a well casing flotation device and method. A ported float shoe and a landing collar are attached at a first end of a portion of a casing string and a sliding air trapping insert is attached at the other end. The air trapping insert includes a fluid flow passageway blocked by a plug attached by shear pins to the insert or the air trapping insert is an inflatable insert having a conduit providing a fluid passageway to the first end. The air trapping insert and float shoe form an air cavity within the string portion.

<CIT> describes a hydraulic setting and release system for run in and cementing of a work string and tubular within a borehole. The system has a small diameter pipe string extending from a release tool through a packer to within the tubular. The system forms at least one annulus between the pipe string and tubular. The pipe string includes a ported nipple and a seat subassembly downstream of the ported nipple. The pipe string allows the packer to anchor the tubular, by being inflated through the port. The pipe string also forms a flotation annulus which is sealed by, and the pipe string is supported by, a drag/seal subassembly downstream of the seat assembly. Uncoupling is accomplished after run in, displacing a cement slurry slug separated by a plug or dart using a following pump down fluid which can land on the seat and block further flow and displacement of cement slurry, and anchoring. The release tool is then actuated uncouple the drill string from the cemented tubular and removal of the drill string prior to well operation.

<CIT> describes a method of installing tubular conduits (e.g., casing, liners, sand screens) into a highly deviated borehole. A lower plug is attached at one end of a portion of a tubular conduit. This end is inserted into a borehole. After insertion of the length of conduit intended to be buoyancy-aided into the borehole, an inflatable plug insert is attached at the upper end. The inflatable plug has a built-in valve designed to enable fluid communication between the buoyancy-aided tubular section and the insertion string. A pump is attached to the built-in valve and the fluid within the section intended to be buoyancy-aided is removed, after which the built-in valve is closed. After the tubular conduit is inserted to the desired depth, the built-in valve is opened allowing the fluid above the plug insert to fill the buoyancy-aided section.

<CIT> describes an apparatus for running a liner into a wellbore comprising an inner string, a device coupled to the inner string that is operable to engage the interior of the liner and facilitates running of the liner into the wellbore, and a control mechanism operable to control fluid communication between the interior of the liner and the wellbore.

The present invention is described in the accompanying claims.

According to an aspect of the disclosure there is provided a method of locating bore-lining tubing in a drilled bore according to claim <NUM>.

The disclosure also relates to apparatus for use in the method according to claim <NUM>.

The apparatus may comprise an assembly comprising: bore-lining tubing for location in a drilled bore; an inner tubing for extending from a distal end of the bore-lining tubing to surface; a coupling at a distal end of the bore-lining tubing; a coupling at a distal end of the inner tubing for engaging and sealing with the coupling at the distal end of the bore-lining tubing; a proximal seal between the bore-lining tubing and the inner tubing; an inner annulus between the distal ends of the bore-lining tubing and the inner tubing and the proximal seal; and a volume of buoyant material retained within the inner annulus.

An aspect of the disclosure relates to running the apparatus into a drilled bore. The presence of the buoyant material may provide the apparatus with a lower effective weight and thus may facilitate running the apparatus into the bore using a facility, for example a derrick on a mobile drilling unit, that would not otherwise have the capability to safely run an equivalent bore-lining tubing into the bore.

The presence of the buoyant material may provide the assembly with a degree of buoyancy when the assembly is passing through a body of water, for example between an offshore rig and the seabed, or is passing through a fluid-filled well bore. Thus, the ambient fluid may be, for example, seawater or drilling fluid. This may reduce the effective load which must be supported by a rig or the like. This buoyancy may also reduce the friction between the bore-lining tubing and the lower side of the drilled bore as the bore-lining tubing is advanced into an inclined or horizontal bore. The buoyancy and/or friction reduction may enable the operator to extend the possible length of bore-lining tubing to be installed in any one section of the wellbore. The buoyancy and friction reduction may facilitate rotation of the assembly in the bore, which may be useful in a situation where the bore is being drilled, reamed, or cleaned as the assembly is advanced into the bore. For these applications a cutting structure, such a drill bit or reaming shoe may be mounted to the distal end of the assembly. The assembly may also be rotated without being axially translated to, for example, facilitate cleaning of the bore, or to improve distribution of cement slurry which has been pumped into annulus surrounding bore-lining tubing.

The ability to flow fluid through the inner string offers advantages. For example, the method may comprise flowing fluid through the inner tubing and into the outer annulus to facilitate translation of the bore-lining tubing into the drilled bore, or cleaning of the bore. Alternatively, or in addition, the method may comprise flowing a settable material into the outer annulus to fill the outer annulus at least partially, the settable material subsequently hardening to secure or seal the bore-lining tubing in the drilled bore.

The steps of the method may be carried out in the order as described above, or may be carried out in a different order, and some steps described above may be carried out in two or more stages and separated by other steps. For example, the bore-lining tubing may be run part way into the bore before the inner tubing is positioned in the bore-lining tubing. Fluid may be flowed through the inner tubing and into the outer annulus while the assembly is being run into the bore, and once the assembly has been run into the drilled bore to target depth.

While running the assembly into the bore the assembly may be supported by a surface structure such as a land rig, an offshore rig, a floating rig, or other mobile offshore drilling unit. The inner tubing may comprise support tubing, such as a support string. For example, a work string or a running string may extend between the surface structure and the assembly. Fluid may be flowed through the supporting tubing to the inner tubing located within the bore-lining tubing.

The method may comprise retrieving the inner tubing from the bore-lining tubing. This may involve disengagement of the coupling on the distal ends of the inner tubing from the coupling on the distal end of the bore-lining tubing. The couplings may be disengaged by relative rotation, for example the couplings may be threaded. Alternatively, the couplings may disengage, or part of one of the couplings may be configured to release or fail, on a predetermined tension or torque being applied to the inner tubing.

The method may comprise coupling the proximal end of the inner string to the proximal end of the bore-lining tubing. The coupling between the proximal tubing ends may comprise a seal and may comprise the proximal seal. The proximal coupling may be incorporated in a running tool or a hanger setting tool. The method may further comprise uncoupling the proximal end of the inner string from the proximal end of the bore-lining tubing before disengaging the distal end of the inner tubing from the distal end of the bore-lining tubing.

The method may comprise setting a hanger provided on a proximal end of the bore-lining tubing. The hanger may include grips or slips which are settable to engage a surrounding tubing, such as a previously installed casing. The hanger may include a seal which is settable to provide sealing engagement between the bore-lining tubing and surrounding tubing. The grips or slips and the seals may be set in separate operations. For example, the grips or slips may be set or activated by application of fluid pressure, which may be applied via the inner tubing. The hanger seal may be set subsequently, for example by translation or manipulation of the inner tubing relative to the bore-lining tubing and may follow the completion of a cementing operation.

The method may comprise increasing or decreasing the distance between the distal and proximal ends of the inner tubing, for example by including an extendable portion in the inner tubing, such as a telescopic portion. The method may further include configuring the inner tubing whereby torque is not transmitted from the proximal end of the tubing to the distal end of the tubing, to permit rotation of the proximal end of the tubing without corresponding rotation of the distal end of the tubing. This may be achieved, for example, by providing a telescopic portion in the inner string capable of transmitting torque when in an extended configuration but not capable of transmitting torque when in a retracted configuration.

The method may comprise displacing the buoyant material from the inner annulus or dissolving or dissipating the buoyant material in other fluid, such as the ambient fluid or other fluid present in the inner annulus.

The buoyant material may completely or partially fill the inner annulus. The buoyant material may comprise a fluid such as air, nitrogen or another gas, a liquid such as a hydrocarbon or water, or a mix of materials. The buoyant material may comprise gas-filled spheres or may comprise a low-density solid material, such as a rigid foam. The ambient fluid may comprise water, brine, drilling fluid or "mud".

The inner annulus may be partially filled with further material, such as drilling fluid, having a density higher than the density of the buoyant material. The inner tubing may be initially air-filled and is then partially filled with a volume of the further material and an upper portion of the tubing left containing a volume of air to serve as the buoyant material. Alternatively, or in addition, the buoyant material may be injected or pumped into the inner annulus and may displace another material from the inner annulus. The inner annulus may be sealed while containing buoyant material at atmospheric pressure. The pressure within the inner annulus may be increased by pumping buoyant material, or another material, into the inner annulus. By increasing the pressure in the inner annulus, the bore-lining tubing may be protected against collapse due to the increasing hydrostatic pressure as the liner assembly is lowered into the fluid-filled drilled bore.

The inner tubing may be sealed to the bore-lining tubing intermediate the distal and proximal ends of the bore-lining tubing to create a sealed distal volume, for example by provision of packer or swab cup. Buoyant material may be provided in this sealed distal volume of the inner annulus. Alternatively, or in addition, the inner tubing may be sealed to the bore-lining tubing at the distal and proximal ends to create a sealed volume of similar length to the bore-lining tubing. This sealed volume may be sub-divided into multiple volumes which may contain different materials.

At least while in an initial configuration, the pressure in the inner annulus may remain substantially unaffected as fluid is pumped through the inner tubing. This may be useful in preventing ballooning of the bore-lining tubing. In the absence of the inner tubing, pumping cement slurry down through bore-lining tubing and into an outer annulus may result in a higher pressure within the bore-lining tubing, such that the tubing is radially extended. When the cementing of the tubing has been completed the tubing may radially contract, resulting a loss of sealing between the outer surface of the tubing and the surrounding cement.

The bore-lining tubing may take any appropriate form and may comprise casing or liner.

The inner tubing may take any appropriate form and may include steel drill pipe sections, steel tubing, coiled tubing, or lightweight equivalents including aluminium drill pipe, composite tubing, or hose.

A valve may be provided to permit fluid to flow out of the inner tubing and into the outer annulus, but which prevents flow from the outer annulus into the inner tubing. The valve may be mounted in the bore-lining tubing, for example in a shoe or collar at the distal end of the tubing, or the valve may be provided in a distal end of the inner tubing. One or more valves may be provided.

The buoyant material may be circulated out of the inner annulus or may be permitted to bleed from the inner annulus, or other fluid may be permitted to bleed or flow into the inner annulus and intermix with or absorb or dissipate the buoyant material. The buoyant material may travel from the inner annulus up through the bore. The buoyant material may travel up through tubing, such as a work or running string used to support the assembly in the bore or may travel up through an annulus between such a work or support string and an existing bore-lining tubing. The method may further comprise the controlled release of the buoyant material at surface; if the buoyant material is a gas or other compressible material, the material will expand as the material travels upwards and the hydrostatic pressure in the bore decreases. In the absence of careful control of the flow of fluid from the bore, the expanding buoyant material could exit the bore in a sudden and potentially dangerous manner and could displace other fluids from the bore.

The inner tubing may include at least one flow port to permit fluid communication between the inner tubing and the inner annulus. The flow port may comprise a valve. The valve may be initially closed to isolate the inner annulus from the inner tubing and may be subsequently opened. Multiple flow ports may be provided and may be opened or closed in a desired sequence.

The inner tubing coupling may latch into the bore-lining tubing coupling. The inner tubing coupling may be a male coupling and the bore-lining tubing coupling may be a female coupling. The engagement and sealing of the couplings may be achieved simply by axial translation of the inner tubing coupling relative to the bore-lining tubing coupling. The latching-in may be facilitated by the provision of an appropriate connector and seal. The inner tubing may be disconnected from the distal end of the bore-lining tubing by relative rotation or by application of an appropriate axial tension.

The inner tubing may attach to the proximal end of the bore-lining tubing via a threaded connection.

The method may comprise locating the upper or proximal end of the bore-lining tubing beneath a body of water, for example locating the upper end of a casing string at the seabed. Alternatively, or in addition, the method may comprise locating the upper or proximal end of the bore-lining tubing within the drilled bore, for example locating the upper end of a liner within a section of casing. Thus, the upper end of the liner may be located below the seabed.

The buoyant material may be selected to have a lower density than the ambient fluid and may have a lower specific gravity/relative density than the ambient fluid.

An example of the disclosure relates to a method of cementing bore-lining tubing in a drilled bore, the method comprising:.

This example may facilitate the prevention of "ballooning" of bore-lining tubing during a cementing operation due to the elevated pressure of cement slurry being delivered down through the bore-lining tubing.

This example may be usefully employed with other settable materials.

The various features described above and as recited in the attached claims may have individual utility and as such may be provided individually, or in combination with any other features described herein, or in combination with any of the features as recited in the appended claims.

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

Referring first to <FIG> of the drawings, a deep-water oil and gas well <NUM> is illustrated. Well construction operations are conducted primarily from a mobile offshore drilling unit <NUM> on the sea surface <NUM>. The well <NUM> includes a bore <NUM> which has been drilled from the seabed/mud line <NUM> in sections and lined with successively smaller bore-lining tubing sections <NUM>, <NUM>, <NUM>, <NUM>. <FIG> of the drawings illustrate steps in the installation of the final tubing section, in the form of a liner <NUM>, in the bore <NUM>.

The illustrated well <NUM> includes three casing sections <NUM>, <NUM> and <NUM> which extend back to the seabed <NUM> and serve to support the surrounding bore wall, which may include weak zones which would otherwise be liable to collapse. The casings <NUM>, <NUM>, <NUM> also isolate any water, gas or oil-bearing zones and provide support for the next casing. An annulus <NUM> surrounds each casing <NUM>, <NUM>, <NUM> and is at least partially filled with settable material, typically a cement <NUM>.

<FIG> illustrate the installation of a liner <NUM> which extends to the end of the bore <NUM>. The liner <NUM> may have a generally similar form to the casings <NUM>, <NUM>, <NUM> but does not extend back to the seabed <NUM>. In this example the liner <NUM> is ultimately sealed and secured to a distal portion of the innermost casing <NUM> with a liner hanger <NUM>. An outer annulus <NUM> between the liner <NUM> and the surrounding bore wall is sealed with cement <NUM> (<FIG>).

In the illustrated well <NUM> the first casing <NUM>, sometimes referred to as a conductor, is a <NUM>" (<NUM>) casing <NUM>, that is a casing having an external diameter of <NUM> inches (<NUM>). The casing <NUM> may have been placed by jetting, that is by providing a shoe on the lower or distal end of the casing <NUM> and pumping water through jetting nozzles internal to the shoe to displace sediment and allow the casing <NUM> to be lowered into the seabed. In other situations, the casing may have been run into a drilled bore and then sealed and secured in the bore within a cement sheath.

A <NUM>" (<NUM>) casing <NUM> is next located in the bore <NUM>, followed by a <NUM>" (<NUM>) casing <NUM>. A <NUM>" (<NUM>) bore is drilled and under reamed beyond the end of the casing <NUM>. An <NUM>" (<NUM>) liner <NUM> is then run into and cemented in the bore <NUM>, as described in detail below.

The liner <NUM> is made up from liner sections on the deck of the drilling unit <NUM> (<FIG>). The leading or distal end of the liner <NUM> is provided with a liner shoe <NUM>, as illustrated in greater detail in <FIG>, which illustrates details of elements provided at the distal ends of the liner and an inner string <NUM>. The shoe <NUM> is a float shoe including a double check-valve <NUM> and has a coupling <NUM> incorporating a sealing face, for example a seal bore <NUM>, to allow an end coupling in the form of an adaptor or latch-in tool <NUM> mounted on the end of an inner string <NUM> to form a sealing engagement with the shoe <NUM>, as will be described. The inner string <NUM> will typically be of significantly smaller diameter than the liner <NUM>, and in this example the inner string <NUM> may have an outer diameter of <NUM>", <NUM>½" or <NUM><NUM>/<NUM>" (<NUM>, <NUM> or <NUM>). In other examples the inner string <NUM> may have any appropriate diameter, such as between <NUM><NUM>/<NUM>" and <NUM><NUM>/<NUM>" (<NUM> and <NUM>).

Once the liner <NUM> has been made up and is suspended from the slips on the deck of the drilling unit <NUM>, the liner internal volume <NUM> is partially filled with a flowable material <NUM>. The material <NUM> may be a fluid as conventionally utilised in well construction operations, such as drilling fluid or brine, or may be a lower density fluid such as a light hydrocarbon. An upper or proximal portion of the volume <NUM> is left containing a volume of air <NUM>.

The inner string <NUM> is then made up and run into the liner <NUM> (<FIG>). The distal end of the inner string <NUM> is provided with a coupling in the form of a latch-in connector <NUM>, shown in greater detail in <FIG>, which is adapted to be latched into a flow passage <NUM> in the liner shoe <NUM>, the male-form connector <NUM> including a sprung latch <NUM> which engages a corresponding profile <NUM> in the female-form shoe coupling <NUM>. Seals <NUM> provided around the leading end of the connector <NUM> engage with the shoe coupling seal bore <NUM>. The end connector <NUM> may be disengaged from the shoe <NUM> by rotating the connector <NUM> relative to the shoe <NUM>. Alternatively, the inner string <NUM> may be separated from the shoe <NUM> by applying an overpull, which shears retaining pins provided within the connector <NUM> and allows separation of distal elements of the connector <NUM>, including the latch <NUM>, from proximal elements of the connector <NUM>.

The lower or distal end of the inner string <NUM> includes ports <NUM> including burst discs or other forms of valve. The valves in the ports <NUM> are initially closed. The inner string <NUM> also includes a telescopic section <NUM>, as illustrated in a retracted configuration in <FIG>. The section <NUM> includes an outer member 149a coupled to a proximal box connection 151a and an inner member 149b coupled to a distal pin connection 151b. The outer and inner members 149a, 149b are in a sealing sliding relationship and with the inner member 149b fully retracted within the outer member 149a the inner member 149b is rotatable relative to the outer member 149a. Thus, in the retracted configuration, it is not possible to transfer torque from the upper box connection 151a to the lower pin connection 151b. However, when the telescopic section <NUM> is extended, as may occur due to gravity pulling on the lower end of the string <NUM> and as occurs when the interior of the string experiences elevated fluid pressure, for example as fluid is being pumped through the string <NUM>, complementary splined portions provided on the members 149a, 149b engage and permit the transfer of torque through the section <NUM>. As noted above, when the section <NUM> is retracted or compressed an upper portion of the string 140a is rotatable relative to a lower portion 140b. The telescopic section <NUM> may include features such as described in <CIT> and <CIT>.

The telescopic section <NUM> may be provided at any appropriate location in the inner string <NUM>.

Once the inner string <NUM> has been made up to the appropriate length within the liner <NUM> the latch-in end connector <NUM> may engage and connect and seal with the coupling <NUM> in the shoe <NUM>, simply be advancing the connector <NUM> into the coupling <NUM>. Pulling back on the string <NUM> will confirm that the connector <NUM> and shoe <NUM> are properly engaged or having set down weight may provide engagement confirmation.

The upper or proximal end of the inner string <NUM> is then coupled to the tailpipe <NUM> of a liner running tool <NUM>, illustrated in greater detail in <FIG>, which tool <NUM> includes external left-handed threads configured to cooperate with matching internal threads on the upper or proximal end of the liner <NUM> or liner hanger <NUM>. Alternatively, a J-slot arrangement may be provided to couple the tool <NUM> and the liner assembly. In other examples the liner hanger and running tool are provided as a preassembled unit. Other alternative arrangements include supplementary coupling arrangement between the running tool <NUM> and the liner <NUM>, including collets and fingers, and shear out assemblies.

The inner string <NUM> is then lowered to compress the telescopic section <NUM> such that the splined portions disengage. The upper portion 140a may now be rotated to engage the running tool <NUM> with the liner hanger <NUM> at the upper end of the liner <NUM>, without transfer of the rotation to the liner lower portion 140b.

Engaging the threads also ensures that a fluid-tight seal is created between the running tool <NUM>, the inner string <NUM> and the liner <NUM> such that the drilling fluid <NUM> and air <NUM> are trapped and isolated within an inner annulus <NUM> created between the liner <NUM> and the inner string <NUM>. This annulus <NUM> is filled the flowable material <NUM> and air <NUM>.

A running string <NUM> is then connected to the liner assembly <NUM> comprising the liner <NUM>, the inner string <NUM> and the running tool <NUM>. Once the running tool <NUM> has been coupled and sealed to the upper end of the liner <NUM>, the liner <NUM> may be hydraulically pressure tested, for example by pumping nitrogen into the inner annulus via a port <NUM> in the running tool <NUM>.

The liner assembly <NUM> is suspended from a derrick <NUM> on the drilling unit <NUM> and is then lowered into the well <NUM>, supported by the liner running string <NUM>, until the liner <NUM> reaches target depth (<FIG>). The assembly <NUM> is lowered through the seawater <NUM> between the drilling unit <NUM> and the seabed <NUM> and into the bore <NUM>, which is itself filled with fluid <NUM>. Although the Figures illustrate a vertical well, the method may also be usefully employed in an inclined well, or a well including a horizontal section. The presence of the air <NUM> in the inner annulus <NUM> provides the liner assembly <NUM> with a degree of buoyancy. This reduces the effective total weight, or hook load, experienced by the supporting apparatus on the drilling unit <NUM> when compared to a liner assembly that had been run in a conventional manner, that is filled with drilling fluid and containing no buoyant material. The capacity of the drilling unit <NUM> is thus effectively extended. In an inclined or horizontal well section the reduced effective weight of the assembly <NUM> will also reduce the friction between the assembly <NUM> and the low side of the well <NUM>, facilitating translation of the assembly <NUM> and facilitating rotation of the assembly <NUM>.

The provision of the inner string <NUM> permits the operator to circulate fluid through the liner running string <NUM> and the inner string <NUM>, out of the shoe port <NUM> and then up through the outer annulus <NUM> between the liner <NUM> and the bore wall. This further facilitates translation of the liner assembly <NUM>. For example, the liner shoe <NUM> may include jetting ports which clear or dislodge cuttings or other debris lying on the low side of the bore <NUM>, or the fluid may be used to drive a rotating reamer shoe or the like.

Pumping fluid through the inner string <NUM> results in a higher pressure within the string <NUM> and this tends to axially extend the telescopic section <NUM>, ensuring that the end connector <NUM> is urged into the shoe <NUM> and maintaining a sealed connection.

On reaching target depth, with the float shoe <NUM> slightly off the bottom of the well <NUM>, the liner hanger <NUM> provided at the upper end of the liner <NUM> may be activated and slips <NUM> in the hanger <NUM> engage the surrounding casing <NUM>, as illustrated in greater detail in <FIG>. The slips <NUM> may be activated by landing a setting ball into a ball seat in the hanger <NUM> and then pressuring up to activate the slips <NUM>. An overpressure may then be applied to shear out the ball and seat reinstate fluid circulation. The hanger <NUM> also includes seals <NUM> which are initially inactive and are activated after the liner <NUM> has been cemented.

The sequence of operations to circulate cement into the annulus <NUM> may vary depending on the well conditions but will typically involve circulating different fluids in a "fluid-train", one example of which will be described below. While the different fluids are being circulated, the operator may rotate the liner <NUM> in the bore <NUM>, this facilitating removal of drill-cutting material from the annulus <NUM> and improving the distribution of cement in the annulus <NUM>.

The operator will typically first circulate drilling mud/fluids, the fluids passing down the running string <NUM> and the inner string <NUM> and then passing out of the liner float shoe <NUM>, before passing up through the annulus <NUM> between the liner <NUM> and the surrounding bore wall. The fluid then passes up through the running string annulus <NUM> to surface. The circulation of the drilling fluids establishes well circulation, ensures the well is completely filled with fluid, cleans the well and circulates out any drilling residue, and establishes a constant circulating temperature prior to cementing. The operator then circulates a chemical wash to circulate out the drilling fluid. The chemical may be surfactant-based, to thin, disperse and aid in drilling fluid removal, particularly within the outer annulus <NUM>. A cement spacer fluid may then be circulated to ensure a physical separation between the previously circulated drilling fluids and the cement, which may be incompatible. For example, drilling fluids are often oil-based whereas cements typically water-based. The separation of the cement and drilling fluids is particularly important in the outer annulus <NUM> and is necessary to ensure the desired set cement properties and quality.

Cement slurry 126a is then prepared on the mobile offshore drilling unit <NUM> and pumped down through the liner running string <NUM>, the liner running tool <NUM>, the inner string <NUM>, and through the flow port <NUM> in the shoe <NUM> (<FIG>). The cementing operation may be commenced without the requirement to retrieve any of the apparatus used to locate the liner <NUM> in the bore <NUM>.

The operator will have estimated the volume of cement slurry 126a required to fill the annulus <NUM> surrounding the liner <NUM> to provide a hydraulic seal around the liner <NUM> when the cement has set. The operator will typically prepare an excess of cement, for example <NUM>% of this theoretical annular volume, that is a <NUM>% excess, to accommodate, for example, washed-out or collapsed (and therefore larger volume) portions of annulus <NUM>, or losses of cement slurry 126a into porous formations. The cement 126a will typically fill the annulus to at least the level of the liner hanger <NUM> and will flow over and past the liner hanger seals <NUM>, although in other situations only a part of the annulus <NUM> may be filled, for example only a short section of cement may be provided in the annulus above the shoe <NUM>.

During the cementing operation, the drilling rig personnel will monitor the volume of cement 126a being pumped into the well <NUM> and the volume of drilling fluid being returned or displaced from the well <NUM>. As noted above, the liner <NUM> may be rotated as the cement 126a is being circulated, to facilitate mud removal and to evenly distribute of the cement around the annulus <NUM>.

The volume of cement 126a may be separated from the following displacement fluid <NUM>, which may be a drilling fluid, by a top plug <NUM> as illustrated in <FIG>, though in other examples a ball may be used. The cement 126a is thus pumped through the liner running string <NUM>, the liner running tool <NUM>, the inner string <NUM>, and the flow port <NUM> in the shoe <NUM>, until the plug <NUM> lands in the shoe coupling <NUM> and blocks the flow port <NUM>. The plug <NUM> includes a seal and a latch arrangement and is locked and sealed in the coupling <NUM>, sealing the port <NUM> and thus preventing any possibility of U-tubing, that is the dense cement slurry 126a flowing down and out of the annulus <NUM> and back through the port <NUM>.

During the cement circulating operation the air <NUM> in the inner annulus <NUM> remains at atmospheric pressure, isolated from the fluid in the well and isolated from the cement slurry 126a being pumped through the inner string <NUM>. Accordingly, there is no tendency for the liner <NUM> to balloon outwards, as may occur in a conventional operation where cement is pumped and displaced down through the liner at high pressure, and such that the liner <NUM> may then contract when the cement pumping operation is completed, and the cement slurry replaced with drilling fluid or brine at hydrostatic pressure. This contraction may lead to the creation of a small annular gap between the cement <NUM> in the outer annulus <NUM> and the outer surface of the liner <NUM> and thus have an adverse effect on the integrity of the cement seal. In the present disclosure the liner <NUM> will experience a substantially lower internal pressure while cement 126a is being pumped into the outer annulus <NUM> and will thus be more likely to radially contract under the influence of the hydrostatic pressure of the cement slurry 126a in the outer annulus <NUM>. When the cementing operation has been completed the pressure in the outer annulus <NUM> will likely decrease as the cement slurry 126a hardens and sets, while the pressure inside the liner <NUM> will increase as the inner annulus <NUM> is brought up to hydrostatic pressure, such that the wall of the liner <NUM> will tend to move radially outwards into closer contact with the surrounding sheath of set cement <NUM>.

Once pumping of the cement 126a into the annulus <NUM> has been completed the operator continues to apply pressure within the inner string <NUM> to open the ports <NUM>, thus providing access to the inner annulus <NUM>. The pressure in the inner annulus <NUM> and the pressure in the inner string <NUM> will then equalise. This will result in the air <NUM> in the annulus <NUM> being compressed and reducing markedly in volume, and potentially being substantially dissolved into the drilling fluid that fills the annulus <NUM>.

The liner hanger running tool <NUM> is then mechanically disengaged from the liner hanger <NUM>, for example by rotation of the running tool <NUM> relative to the liner assembly; the fluid seal between the running tool <NUM> and the liner hanger/liner assembly is maintained. The liner hanger seals <NUM> for sealing the upper end of the outer annulus <NUM> may then be activated. In one example a push-pull test is carried out, with weight being applied to the liner hanger <NUM> via the running tool <NUM> to activate the seals <NUM> and bed-in the liner hanger slips <NUM>. Tension is then applied to the liner hanger <NUM>, and further secures the seals <NUM> and the slips <NUM>.

The liner running tool <NUM> includes a port provided with a valve <NUM> which permit control of flow between the inner annulus <NUM> and the running string annulus <NUM>. If the valve <NUM> is closed, fluid may be pumped into the inner annulus <NUM> through the lower port <NUM> to conduct a pressure test of the liner <NUM>. This will result in the further pressurisation of the air <NUM> and the volume of the air <NUM> will further decrease. With the valve <NUM> open, fluid may be circulated from surface down through the running string <NUM> and the inner string <NUM> and out of the port <NUM> to circulate the air <NUM> out of the inner annulus <NUM> (<FIG>). Alternatively, and as illustrated in <FIG>, with the BOP seal rams <NUM> engaging the running string <NUM> and sealing the upper end of the annulus <NUM>, fluid may be reverse circulated from surface through the BOP kill line <NUM> and into the annulus <NUM> between the running string <NUM> and the casing <NUM>, and through the running tool valve <NUM>, to displace the air <NUM> through the ports <NUM> and up through the inner string <NUM> and the running string <NUM>. Further, any excess cement 126a which had spilled over the upper end of the liner <NUM> and into the annulus <NUM>, and may be sitting above the running tool <NUM>, is flushed through the valve <NUM> into the inner annulus <NUM> and ultimately carried to surface through the inner string <NUM> and the running string <NUM>. The entrained cement may be separated from the circulating fluid at surface. Further reverse circulation of fluid through the inner annulus <NUM> will also flush any residual cement 126a in the string <NUM> out of the well <NUM>.

Air <NUM> which is displaced out of the inner annulus <NUM> will pass up through the fluid in the running string annulus <NUM>, or alternatively up through the inner string <NUM> and the running string <NUM>. While the elevated pressure experience in the bore <NUM> may result in the air <NUM> initially being subject to substantial compression and dissolving in the other fluid present in the bore <NUM>, the air <NUM> will expand as it moves upwards towards the surface and hydrostatic pressure decreases. The operator will take appropriate steps to control and contain the air <NUM> using the well control systems of the mobile offshore drilling unit <NUM>, for example a sub-sea blow-out preventer (BOP) provided on the seabed <NUM> will seal in the well <NUM> and choke and kill lines may be used to direct flow into and out of the well, and a surface manifold and choke on the unit <NUM> will be used to control, separate, and divert flow at surface.

The operator will then continue to circulate drilling fluid, for example circulating two or three times the well volume, to ensure that all the air has been dispersed and removed from the well <NUM>, before releasing the BOP seal rams <NUM>.

In alternative examples the port <NUM> may feature a different valve arrangement. For example, the port <NUM> may include a valve which opens in response to a predetermined sequence of pressure pulses or a predetermined flow sequence, such as on/off/on/off. In another example the port <NUM> may include a valve which operates in response to surface deployed communication, such as RFID tags which may be pumped into the inner string <NUM> when it is desired to change the configuration of the valve to open or close the port <NUM>.

When the operator is ready to retrieve the liner running assembly, the liner running string <NUM> is manipulated to disengage the liner running tool <NUM> from the liner hanger <NUM> and the upper end of the liner <NUM>. The liner running string <NUM> is then raised to extend the telescopic section <NUM> in the inner string <NUM>, allowing torque to be transferred between the inner string portions 140a, 140b, to disengage the couplings <NUM>, <NUM> between the inner string <NUM> and the liner shoe <NUM>. Alternatively, the couplings <NUM>, <NUM> may be separated by application of a predetermined tension or pull.

Once the cement <NUM> has set, any further operations, for example perforating the liner <NUM>, may be carried out immediately. There is no requirement to drill out a plug of cement, or the associated plugs and float collar, from the distal end of the liner <NUM>, as would be the case with a conventional liner cementing operation. This provides for a considerable saving in time, reduces the equipment required to be provided on the drilling unit <NUM>, and avoids the potential for damage to the liner <NUM> and the cement <NUM> from the drilling operation.

Reference is now made to <FIG> of the drawings, which illustrates a deep-water oil and gas exploration well <NUM>. The well <NUM> shares many features with the well <NUM> described above and, in the interest of brevity, some of the common features will not be described again in any detail. Common features may be labelled with the same reference numerals, incremented by <NUM>.

As with the first example, the illustrated well construction operations are being conducted primarily from a mobile offshore drilling unit <NUM> on the sea surface <NUM>. The well <NUM> includes a bore <NUM> which has been drilled from the seabed/mud line <NUM> in sections and lined with successively smaller bore-lining tubing sections <NUM>, <NUM>, <NUM>, <NUM>.

The illustrated well <NUM> includes three casing sections <NUM>, <NUM> and <NUM> which extend back to the seabed <NUM>. An annulus <NUM> surrounds each casing <NUM>, <NUM>, <NUM> and is at least partially filled with cement <NUM>. The Figures illustrate the installation of a liner <NUM> which extends to the end of the bore <NUM>. The liner <NUM> is sealed and secured to a distal portion of the innermost casing <NUM> with a liner hanger <NUM>. An outer annulus <NUM> between the liner <NUM> and the surrounding bore wall will be sealed with cement <NUM>.

The liner <NUM> is made up from liner sections on the deck of the drilling unit <NUM> (<FIG>). The leading or distal end of the liner <NUM> is provided with a liner shoe <NUM>. The shoe <NUM> is a float shoe including a double check-valve <NUM> and has a coupling including a sealing face to allow an end adaptor or latch-in coupling tool <NUM> on the end of an inner string <NUM> to form a sealing engagement with the shoe <NUM>, as will be described.

Once the liner <NUM> has been made up and is suspended from the slips on the deck of the drilling unit <NUM>, the inner string <NUM> is made up and run into the liner <NUM>, the string <NUM> being provided with a packer <NUM>. The inner string <NUM> includes a latch-in coupling or connector <NUM> which is latched into a coupling provided in a flow passage <NUM> in the liner shoe <NUM>.

The lower or distal end of the inner string <NUM> includes a port <NUM> including a burst disc, or other form of selectable valve. The inner string <NUM> also includes a telescopic section <NUM>. When the telescopic section <NUM> is extended, as may occur due to gravity pulling on the lower end of the string <NUM> and as occurs when the interior of the string experiences elevated fluid pressure, complementary splined portions engage and permit the transfer of torque through the section <NUM>. However, when the section <NUM> is retracted or compressed an upper portion of the string 240a is rotatable relative to a lower portion 240b. The telescopic section <NUM> may include features such as described in <CIT>, <CIT> and <CIT>.

The upper or proximal end of the inner string <NUM> is then coupled to a liner running tool <NUM> which includes external left-handed threads configured to cooperate with matching internal threads on the upper or proximal end of the liner <NUM>.

The inner string <NUM> is then lowered to compress the telescopic section <NUM> such that the splined portions disengage. The upper portion 240a may now be rotated to set the packer <NUM> to form a sealing barrier within the inner annulus <NUM> between the inner string <NUM> and the liner <NUM> and thus divide this inner annulus <NUM> into an upper portion 252a and a lower portion 252b. The lower portion 252b is filled with air <NUM>. After setting the packer <NUM> the upper portion 252a is filled with fluid <NUM> (<FIG>). In other examples the packer could be set by reciprocation, rotation, or pressure.

The inner string <NUM> is lowered to engage the running tool <NUM> with the upper end of the liner <NUM>, without transfer of the rotation to the liner lower portion 240b. A fluid-tight seal is created between the running tool <NUM>, the inner string <NUM> and the liner <NUM> such that the drilling fluid <NUM> and air <NUM> are trapped and isolated within the inner annulus <NUM>.

A running string <NUM> is then connected to the liner assembly <NUM> and the liner assembly <NUM> is lowered into the well <NUM>, suspended from a derrick <NUM> on the drilling unit <NUM> and supported by the liner running string <NUM>, until the liner <NUM> reaches target depth (<FIG>). The assembly <NUM> is lowered through the seawater <NUM> between the drilling unit <NUM> and the seabed <NUM> and into the bore <NUM>, which is itself filled with fluid <NUM>. The presence of the air <NUM> in the inner annulus lower portion 252b provides the liner assembly <NUM> with a degree of buoyancy. As with the first example, this reduces the effective total weight, or hook load, experienced by the supporting apparatus on the drilling unit <NUM> when compared to a liner assembly that had been filled with drilling fluid and contains no buoyant material. Further, in an inclined or horizontal well section the buoyancy introduced by the air <NUM> in the lower inner annulus 252b reduces the effective weight of the assembly <NUM> and reduces the friction between the assembly <NUM> and the low side of the well <NUM>, facilitating axial translation and rotation of the assembly <NUM>.

The provision of the inner string <NUM> permits the operator to circulate fluid through the liner running string <NUM>, the inner string <NUM>, and the outer annulus <NUM>.

On reaching target depth the liner hanger <NUM> provided at the upper end of the liner <NUM> is activated and slips <NUM> in the hanger <NUM> engage the surrounding casing <NUM>.

The liner <NUM> is then cemented in a similar manner to the liner <NUM> described above. Given the reduced effective weight of the assembly <NUM>, and the reduced friction between the assembly <NUM> and the surrounding bore wall, it is possible to rotate the liner <NUM> as cement slurry 226a is circulated up the outer annulus <NUM>, which improves the quality of the bond formed between the liner <NUM> and the surrounding cement <NUM>.

Once the desired volume of cement 226a has been pumped into the well <NUM> a displacement fluid <NUM> separated from the cement 226a by a top plug and/or ball <NUM>. The cement 226a is thus pumped through the liner running string <NUM>, the liner running tool <NUM>, the inner string <NUM>, and the flow port <NUM> in the shoe <NUM>, until the ball <NUM> lands in and blocks the flow port <NUM>. The ball <NUM> is locked in the port <NUM> thus preventing any possibility of U-tubing, that is the dense cement slurry 226a flowing down and out of the annulus <NUM> and back through the port <NUM>.

Once the desired amount of cement 226a has been pumped into the bore <NUM> the liner hanger seals <NUM> may be set to provide a fluid-tight seal between the upper end of the liner <NUM> and the surrounding casing <NUM>.

A further increase in pressure in the inner string <NUM> opens the port <NUM>. Fluid may then be pumped into the distal volume 252b and the air <NUM> compressed. The liner running tool <NUM> also includes a port provided with a valve <NUM> which controls flow into and from the proximal portion 252a of the inner annulus <NUM>.

When the operator is ready to retrieve the liner running assembly, the liner running string <NUM> is rotated to disengage the liner running tool <NUM> from the upper end of the liner <NUM>. The liner running string <NUM> is then raised further to unset the packer <NUM> within the inner annulus <NUM>, allowing the compressed air <NUM> in the distal volume 252b to mix with the fluid <NUM> in the proximal volume 252a.

Fluid from the volume <NUM> above the assembly <NUM> may be reverse circulated through the inner annulus <NUM>, through the flow-passage <NUM> and back up the inner-string <NUM> to surface. This reverse circulation removes any entrapped air and circulates the well <NUM> back to a single fluid.

To facilitate safe displacement of the air <NUM> out of the well <NUM>, and prior to retrieving the liner running assembly, the well control system of the mobile offshore drilling unit <NUM> is utilised to control the flow of fluid from the well <NUM>. This could involve use of the sub-sea blow-out preventer to seal in the well <NUM>, including the running string annulus <NUM>, choke and kill lines to direct and control flow into and out of the well <NUM>, and the surface manifold and choke to control, separate and divert well fluid flow at surface.

The liner running string <NUM> is then raised further to extend the telescopic section <NUM> in the inner string <NUM>, allowing torque to be transferred between the inner string portions 240a, 240b, to disengage the bottom end of the inner string <NUM> from the liner shoe <NUM>. The running string <NUM>, running tool <NUM> and inner string <NUM> may then be retrieved to surface.

In the example described above the liner assembly <NUM> is run into the bore <NUM> with a portion of the inner annulus 252b filled with air <NUM> at atmospheric pressure. The skilled person will appreciate that this will result in an imbalance of pressure acting on the liner <NUM> as the assembly is run deeper into the bore <NUM> and the surrounding hydrostatic pressure increases. The upper or proximal portion of the inner annulus 252a is filled with substantially incompressible drilling fluid <NUM> which will support the corresponding portion of the liner <NUM>. Clearly, the skilled person will ensure that the liner <NUM> surrounding the air-filled portion of the inner annulus 252b is selected to withstand the expected hydrostatic pressure forces and temperature-related expansion forces that will result in pressure changes.

In other examples the operator may pressurise the inner annulus <NUM>, <NUM>, for example by pumping material into the annulus after the annulus volume has been sealed by the running tool <NUM>, <NUM>. For example, the operator may pump air or an inert gas, such as nitrogen, into the volume.

It will be apparent to the skilled person that many of the elements of the various well constructions described above may be modified or omitted. For example, a packer, swab cup or the like may be provided in the inner annulus of the first example to separate the drilling fluid from the air. In a variation of the second example multiple packers may be provided, allowing three or more separate volumes to be provided within the annulus <NUM>. The location of the buoyant material within the inner annulus may also be varied as desired.

The skilled person will appreciate that there are a variety of liner hangers available from a variety of different suppliers, and that the liner hanger setting steps and procedures described above are only provided by way of example.

In the above examples the buoyant material comprises air. In other examples the buoyant material may comprise another gas, such as nitrogen, a liquid such as a low specific gravity/density oil, or a solid material such as rigid foam or gas-filled spheres. The buoyancy provided by the buoyant material may be enhanced by maintaining the buoyant material at a relatively low pressure, such as the examples described above where air is retained within an inner annulus and maintained at or close to atmospheric pressure. In other examples the buoyant material may be pressurised or may be at the same pressure as the surrounding ambient fluid but be selected to have a lower specific gravity/relative density than the ambient fluid.

The examples described above feature a telescopic section <NUM>, <NUM>, serving as a slip joint, which may be extended by internal pressure. As noted above, this may be useful in ensuring that the latch-in end connector <NUM>, <NUM> remains in sealing contact with the shoe <NUM>, <NUM>, however in other examples a pressure neutral telescopic section may be provided, that is the section does not tend to extend in response to pressure differentials.

The examples described above reduce the effective weight of the liner assembly supported by the derrick on the drilling unit. This may permit a drilling unit to be used to install bore-lining tubing that would otherwise exceed the safe working capabilities of the unit or derrick. Thus, rather than being forced to source a more expensive mobile drilling unit with a higher weight-handling capacity, or having to separately run and install two liners, an operator may install a relatively long liner in a single run. Further, operators will sometimes run casing or liner into a well with the assistance of gravity, but if a problem arises the operator may be unable to pull the casing or liner back out of the well. The operator may thus be forced to install the casing or liner short of target depth. By using the present disclosure to reduce the effective weight of the casing or liner assembly, it is more likely that the operator will retain the capability to retrieve the casing or liner and resolve the problem that is preventing the tubing being run to target depth.

The examples described above feature double check-valves in the liner shoes. In other examples single valves may be provided, or the shoes may be configured to auto-fill. In other examples the inner string may engage with a coupling provided in a float collar, rather than in a float shoe, to allow provision of a short shoe track. Such a float shoe <NUM> is illustrated in <FIG> and includes a coupling <NUM> to engage with a coupling (such as the coupling <NUM> described above) provided on an inner string, and a single check valve <NUM>.

The examples include latch-in connectors at the distal ends of inner string. In other examples the connectors may simply be sealing connectors.

In the above examples the liner internal volumes are part-filled with air and part-filled with liquid. In other examples the liner internal volume may remain entirely filled with ambient air, that is no liquid is placed in the volume.

The running tools <NUM>, <NUM> described above are provided with valves <NUM>, <NUM>, and these valves may be accessible via ROV. In other examples the liners will be installed through a riser connecting the drilling unit to the wellhead, and the running tools will not be ROV accessible, and thus will not be provided with such valves. In such a situation circulation, whether conventional or reverse, may be established once the running tool has been picked up above the hanger element and a flow path is opened between the running tool annulus and the inner annulus.

The examples described above relate to the placing of a liner in a pre-drilled hole. Aspects of the disclosure may also be useful in drilling-with buoyant casing operations, where a cutting structure, such as a drill bit, is provided on the distal end of a casing or liner string and the cutting structure is used to form the bore that the casing or liner will line; there is no requirement to retrieve a drill string to surface and then separately make up and run in the bore-lining tubing. <FIG> is a sectional view of the distal end of a casing for such an application. The casing <NUM> includes a float collar <NUM> including a single check valve <NUM> and a drill bit <NUM> is provided on the end of the casing <NUM>, rather than a non-cutting shoe. The collar <NUM> includes a coupling arrangement <NUM> for cooperating with a corresponding coupling provided on the distal end of the inner string.

The presence of the buoyant material in the casing <NUM> greatly reduces its overall weight and facilitates rotation of the casing <NUM> to rotate the bit <NUM>, and reduces the friction experienced as the casing <NUM> is advanced through the drilled bore <NUM>. Further, the direct coupling of the distal end of the inner string to the distal end of the casing <NUM> facilitates circulation of drilling fluid during well cleaning and the drilling operation.

Further, the drawings illustrate methods being utilised in deep-water applications, with operations being conducted from a mobile offshore drilling unit. The skilled person will recognise that the methods and apparatus described may also be utilised in shallower water, and indeed in land wells, and may be conducted from platforms, drill ships, or land rigs.

Claim 1:
A method of locating bore-lining tubing in a drilled bore, the method comprising:
selecting a buoyant material having a density lower than the density of an ambient fluid;
locating the buoyant material in a bore-lining tubing (<NUM>);
locating an inner tubing (<NUM>) within the bore-lining tubing (<NUM>), with the inner tubing (<NUM>) extending from a distal end of the bore-lining tubing (<NUM>) to a proximal end of the bore-lining tubing (<NUM>) and defining an inner annulus (<NUM>) between the inner tubing (<NUM>) and the bore-lining tubing (<NUM>);
coupling and sealing the distal end of the inner tubing (<NUM>) to the distal end of the bore-lining tubing (<NUM>) by engaging a coupling (<NUM>) on the inner tubing (<NUM>) with a coupling (<NUM>) on the bore-lining tubing (<NUM>);
sealing the inner tubing (<NUM>) to a portion of the bore-lining tubing (<NUM>) spaced from the distal end thereof to isolate a portion of the inner annulus (<NUM>) between the distal end and the sealing location;
retaining a volume of the buoyant material within the isolated portion of the inner annulus (<NUM>);
running an assembly comprising the inner tubing (<NUM>) and the bore-lining tubing (<NUM>) and containing the volume of buoyant material into a drilled bore (<NUM>);
flowing fluid through the inner tubing (<NUM>) and into an outer annulus (<NUM>) surrounding the bore-lining tubing (<NUM>), and
opening a port (<NUM>) in a distal end of the inner tubing (<NUM>) and flowing fluid into the inner annulus (<NUM>) defined between the inner tubing (<NUM>) and the bore-lining tubing (<NUM>) via the port (<NUM>).