NO340186B1 - Method of drilling a wellbore in an underground formation - Google Patents

Description

The present invention relates generally to the drilling of an underground wellbore, and, more specifically, to sensors used in conjunction with nested pipe assemblies, which can drill and line a section of a wellbore without having to have an intervening trip with a drill string and a BHA to the surface.

US 2005/152749A1 describes a method for drilling a wellbore

in an underground formation, comprising: guiding a first and a second tubing string into the wellbore; drilling a first open hole section with a drill assembly while driving the first tubing string into the first open hole section; drilling a second open hole section with the drilling assembly while driving the first tubing string into the second open hole section; and connecting at least one of the first pipe string and the second pipe string to the well bore without pulling the drill assembly out of the well bore.

EP 1006260A2 discloses a drill casing having a core drill bit at its bottom end joined with a pivot drill bit on an internal bottomhole assembly driven by a mud motor. The motor can be driven to transport the sludge by an internal string.

Hydrocarbons, such as oil or gas from an oil field, are produced from well bores that intersect one or more hydrocarbon-producing reservoirs in an oil field.

The time and capital investment associated with drilling such wells has always been significant. Factors that affect the overall cost of a well include the time required to drill a well bore, the geographical accessibility of the oil field, and the complexity and/or depth of the well bore. In the discussion below, it will be clear that under many circumstances the predicted costs for drilling a particular well bore cannot be sufficiently offset by the expected production of hydrocarbons from the reservoir that the well bore drains, which makes such oil fields uneconomic to develop.

As is well known, oil field well bores are drilled by rotating a drill bit which is fed into a well bore by means of a drill string. The drill string includes a drill pipe (tubing) which at its lower end has a drill assembly (also referred to as the "bottom hole assembly" or "BHA") which carries the drill bit for drilling the wellbore. After a selected portion of the wellbore has been drilled, these "open hole" sections are usually provided with casings or with a string or section of casing. In some cases, it may be possible to drill a wellbore to the depth of the well and then supply the wellbore with casing. More often, the planned trajectory for a wellbore and the characteristics of the formation will require that sections of the wellbore be supplied with casing before successive sections of the wellbore can be drilled. For example, the wellbore may cross a number of zones, each of which may have different fluids (eg, water, gas, oil). Casing may thus be necessary to provide zone isolation; for example preventing a water zone from invading an oil zone. In addition, the drilling activity may require the use of drilling fluid that has a pressure that exceeds the fracture pressure for the "open hole" sections. The casing may thus be necessary to prevent damage to the exposed formation. Casing may also be required to maintain wellbore stability; for example to prevent the well drilling from collapsing. Drilling and placing casing according to the conventional process therefore typically requires drilling a section of the well bore, pulling the drill string and drill bit out of the well bore, running a casing into the well bore, cementing the casing in place, running the drill string back into the the hole, drilling the next section of the wellbore, etc.

Unfortunately, conventional methods of drilling and placing casing can be time-consuming, because well drilling routinely reaches depths of thousands of meters. The time required just to run the drill string into and out of the wellbore can thus require dozens of hours. During driving/hauling, no other meaningful activity usually takes place (for example, drilling or placing casing in the well bore). This idle time can be particularly disadvantageous given that rig costs can approach and exceed one hundred thousand dollars per rig. day. Multiple trips are also disadvantageous because they can delay the onset of profitable production. Furthermore, control of the well can be difficult during the time period when the drill pipe is taken out and the casing is arranged in the wellbore. Furthermore, as is well known, each trip into and out of the wellbore entails a risk that the drill string may become stuck in the wellbore, or be affected by another point of failure that requires an expensive remedial operation (for example fishing, lateral drilling, etc.).

The present invention solves these and other disadvantages of the known technique.

The objectives of the present invention are achieved by a method for drilling a wellbore of an underground formation, comprising: attaching a casing shoe bit to a first pipe and a second pipe;

guiding the first pipe and the second pipe into the wellbore;

driving a drilling tool into one of the first and second pipes;

drilling a first pilot hole with the drilling tool; and

expanding the first pilot hole by rotating the attached casing shoe drill bit as the first pipe is driven into the expanded first pilot hole;

the procedure is characterized by:

connecting the first pipe to the wellbore without pulling the drilling tool out of the wellbore;

drilling a second pilot hole with the drilling tool; and

enlarging the second pilot hole by rotating the attached casing shoe bit simultaneously with driving the second pipe into the expanded second pilot hole.

Preferred embodiments of the method are further elaborated in claims 2 to 7 inclusive.

It is discussed in one aspect systems, devices and methods that make it possible with a drill string and an associated bottom hole assembly (BHA) to drill and line successive well drilling sections without the need for intervening trips out of the wellbore. In one embodiment, a nested tubing assembly formed by two or more tubing strings is advanced into a wellbore using a drill string equipped with a BHA. Devices used in conjunction with the nested tubing assembly may include a hole expansion device for expanding the diameter of the wellbore, a BH retracting device for selectively retracting the BHA into the nested tubing assembly, a drill string extension connecting the nested tubing assembly to the BHA, a nested casing shoe bit for reaming and/or drilling the wellbore, and a nested casing hanger tool for selective interlocking of the pipe strings. Devices such as upper and lower fluid flow diverters and a cross connection can be used to actuate the above described components and to control the flow paths for cement and drilling fluid. The tubing strings in the tubing assembly may have any structure that may be connected to the wellbore, either permanently or temporarily, to provide isolation, enhance stability and/or protection for a section of a wellbore. These pipe strings can be arranged telescopically, in a "nested" manner, or in an axially stacked manner.

In an exemplary mode of operation, a nested pipe assembly composed of at least one inner and one outer pipe string is temporarily suspended or anchored just above the total depth of the well, in preparation for the drilling operation. When the next section of the well is drilled, the nested pipe assembly is fed into the drilled section during the drilling operation by means of its coupling to the drilling BHA. As soon as a selected depth is reached, the outer string of tubing is connected to the wellbore. When the next wellbore section is drilled, the remaining inner tubing string is run along with the BHA as this section is drilled, and it is connected to the wellbore after another selected depth has been reached. These steps, or variations of these steps, continue until the tubing strings making up the nested tubing assembly have been connected, temporarily or permanently, to the drilled wellbore sections.

The BHA can then be withdrawn from the wellbore or it can be left in place. In both cases, it will be understood that the reduction of the BHA's and the drill string's trips into and out of the wellbore will provide a corresponding reduction in the time required to drill and complete a wellbore.

A system for drilling a wellbore is disclosed which includes one or more sensors used in conjunction with a pipe assembly adapted to be connected to the wellbore. The pipe assembly includes at least two pipe strings which are used in a manner previously described. Formation evaluation tools and other sensors are advantageously positioned at least partially on the tubing string rather than positioned in the BHA. The length of the BHA's extent below the pipe assembly is thus correspondingly reduced. When positioning formation evaluation tools, such as tools for measuring gamma radiation, resistivity, etc., on the outside of the pipe assembly, the metal that makes up the pipe assembly will not interfere with the operation of such tools. Furthermore, sensors for measuring parameters of interest that are related to the wellbore fluids or drilling fluids can also be arranged in the pipe assembly.

In some embodiments, the tubing assembly includes a drill motor for rotating a drill bit disposed in the BHA. In such designs, the sensors can be positioned on the drill motor or in a section in the immediate vicinity of the drill motor. Additionally, in embodiments, the sensors may be separated from the wellbore wall during operation. This can happen, for example, where the sensor or sensors are positioned in the hole for the hole expansion device. This separation may impair the operation of some formation evaluation tools. Therefore, in such situations, the sensor or sensors may be positioned on extensible members that move the sensors radially toward the wellbore wall.

Examples of more important features of the invention have been summarized (albeit rather broadly), so that the detailed description of this which follows can be more easily understood, and so that the contributions to the technique which they represent can be appreciated. There are, of course, further features of the invention which will be described hereafter, and which will form the subject of the claims appended here.

For a detailed understanding of the present invention, reference should now be made to the following detailed description of the preferred embodiments, which can be seen in conjunction with the accompanying drawings, where like elements have been given like reference numbers, and where: Fig. 1 schematically illustrates a side view of an embodiment of a nested pipe assembly made in accordance with an embodiment of the present invention; Fig. 2 schematically illustrates a functional arrangement of one embodiment of a nested pipe assembly together with a bottom hole assembly; Fig. 3 illustrates a flowchart of an embodiment of a method according to the present invention; Fig. 4 shows a schematic cross-sectional view of an embodiment of a drilling assembly that includes three casing drill bits arranged in a nested telescoping relationship according to the present invention; Fig. 5 shows a schematic cross-sectional view of the drill assembly shown in fig. 4 in an extended telescoping relation; Fig. 6 shows a schematic cross-sectional view of a drilling assembly according to an embodiment of the present invention, including three casing sections and a rotating drill bit; Fig. 7 shows a schematic cross-sectional view of a drilling assembly according to an embodiment of the present invention, including a casing drill bit according to an embodiment of the present invention and three casing sections; and Fig. 8 shows a schematic cross-sectional view of sensors positioned on a drill motor positioned in a pipe assembly; Fig. 9 shows a schematic cross-sectional view of sensors positioned on extendable arms in a pipe assembly; and Fig. 10 shows a schematic cross-sectional view of sensors arranged in a section of a pipe assembly in the immediate vicinity of a drilling motor positioned in a pipe assembly.

The present invention provides in one aspect systems, devices and methods for drilling and structurally supporting two or more open sections in a single trip into the wellbore. The present invention can have embodiments of different forms. Specific embodiments of the present invention are shown in the drawings, and will be described here in detail, with the understanding that the present disclosure is to be regarded as an exemplification of the principles of the invention, and that it is not intended to limit the invention to the which is here illustrated and described.

Reference is now made to fig. 1, schematically shows an embodiment of a casing or casing assembly 10 (or "pipe assembly 10") which is arranged concentrically or in a "nested" manner. The terms "casing" and "casing" will throughout be used interchangeably to generally denote a tubular structure for providing insulation, strength, stability and protection for a section of a wellbore. These terms are not intended to identify any particular type or class of well drill pipe or to specify any particular dimensions, wall thicknesses, materials or other such characteristics. Also, although tubes generally have a circular cross-section, other cross-sectional shapes (for example, oval) may be used. In addition, although casings and casings are ordinarily cemented to provide one or more of their stated functions, any method or device that connects, temporarily or permanently, these pipes to the wellbore may be adequate for the present invention (for example the gasket located outside the casing may provide adequate zone isolation). Furthermore, although "nested" arrangements will be described here, it should be understood that other arrangements (for example, serially arranged) may also be suitable in certain applications. For example, two pipes can be axially stacked in the wellbore. After the lower pipe is connected to the well bore, the upper pipe can pass through the lower pipe while drilling the next section of the well bore. In one embodiment, the passage can be made easier by making the lower tube larger in diameter than the upper tube or by expanding the lower tube.

In the embodiment in fig. 1, the nested tubing assembly 10 includes a plurality of concentrically arranged tubing strings 12, 14, 16 that can be fed into a wellbore 18 by means of a drill string 20, which is provided with a bottom hole assembly (BHA) 100. These concentric or nested tubing strings 12, 14, 16 can independently extend apart in a telescopic manner to thereby enter and line open hole sections, for example section 22, which is formed by the BHA 100 in one embodiment the nested tubing string includes fluid flow control mechanisms which, when actuated, selectively channels cement into an annulus between the wall of the drilled wellbore and the adjacent casing. Two or more drilled wellbore sections can thus be supplied with casing and cemented with a trip of the drill string into the wellbore. In an exemplary application, the independently operable multiple concentric tubing string assembly 10 is introduced into the wellbore 18 after some surface structure, such as a surface tubing 24, a wellhead 26, and a blowout prevent stack (BOP) 28 has been set.

Reference should now be made to fig. 2, schematically showing a functional arrangement of the nested pipe assembly 10, as used in conjunction with a BHA 100. The illustrative embodiment in fig. 2 includes a BHA 100, a hole arrangement device 120, a BHA retractor 130, upper and lower fluid flow diverters 140, 180, a drill string extension 150, a nested casing shoe drill bit 160, a nested casing hanger tool 170, a nested casing cross connection 190, and a drill string 20. For for the sake of brevity, the BHA 100 is not shown in pictorial form, as the teachings of the present invention are not limited to any particular design of a BHA, and can be applied equally effectively with relatively simple top drive systems as well as with sophisticated three-dimensional rotary steerable systems.

The BHA may advantageously be of conventional design and include features such as a control unit and sensors for determining drilling direction, BHA performance and formation properties. By way of illustration only, an exemplary BHA 100 may include a drill bit 102, directional control devices 104, a drill motor 106 for rotating the drill bit 102, and a device 108 for controlling the weight of the drill bit or the axial thrust force on the drill bit 102. The direction is controlled by controlling the directional control (steering ) devices 104, which may include independently controlled stabilizers, downhole actuated knee joints, bent housings, and a bit orientation device. The BHA 100 also includes sensors for (i) determination of drill assembly conditions during drilling (drill assembly or tool parameters), (ii) determination of mud motor parameters, (ii) determination of the BHA's position, direction, inclination and orientation, (iv) determination of condition of the borehole (borehole parameters; for example, borehole temperature and pressure) (v) determination of drilling parameters, such as the weight of the drill bit, rotation speed, and (vi) determination of the wear of the drill bit, the efficiency of the drill bit and the expected remaining life of the drill bit 102. Formation evaluation sensors 112 determines the nature and condition of the formation through which the borehole is drilled. Exemplary FE tools include NMR, nuclear tools, and tools for measuring gamma rays, resistivity, permeability, porosity, etc. Suitable controllers, force application means, sensors and related systems are disclosed in US Patent Nos. 5,168,941 and 6,513,606, whose publications is incorporated herein by reference, and which is transferred to the present legal successor. Suitable BHAs include those that are rotary and/or motor driven.

Reference should now be made to fig. 1 and 2, in one embodiment the BHA 100 extends downhole from the nested tubing assembly 10 by a length sufficient to expose the formation evaluation sensors 112 (if present) to the open section 22 of the wellbore 18. Furthermore, the wellbore size drilled by the BHA 10 optimized for formation evaluation if such tools are used. Other configuration parameters and considerations depend on the particular application. In some embodiments, the outside diameter of the BHA 100 is chosen to allow at least some of the BHA 100 to be retracted into a central bore 17 in the innermost liner 16

(Fig. 1). In one mode of operation, the drill bit 102 and control assembly 104 are motor driven, and the formation evaluation tools 112 are slowly rotated by the rotation of the entire drill string 20 and the nested pipe assembly 10.

To promote advancement of the nested tubing assembly 10 downhole, one embodiment of the hole expansion device 120 utilizes a rotary, cutting action to expand the diameter of the wellbore 22. The hole expansion device 120 may act in conjunction with or independently of the casing shoe bit 160 to crush the formation. The hole expansion device 120 is located uphole for the formation evaluation tools 112 and downhole for the nested casing shoe bit 130. The hole expansion device 120 can use cutters that are arranged on extendable arms or ribs that can be opened to two or more selected and controlled diameters. The cutting structure can also be formed on a collar, stem or other similar device. In other embodiments, the hole widening device may be configured to provide a diameter or a controlled range of intersecting diameters. In applications where the hole expander 120 may need more rotational speed than is provided by the rotation of the drill string 20, a motor 122 may be used to drive the hole expander 120. The motor 122 may be, for example, a modified drill motor assembly (not shown) having an outer motor housing which drives the hole expansion device 120 and an internal shaft connected to and rotating with the primary drill string 20 and the nested pipe assembly 10. In other embodiments, the drill motor 106 may drive the hole expansion device 120 via a suitable drive shaft and casing assembly (not shown). In one embodiment, the diameter provided by the hole expansion device 120 is approximately 20% greater than the diameter of the largest unset tubing string drilled for the hole expansion device 120, and approximately equal to the diameter of the casing shoe bit 160.

In certain applications, it may be advantageous to land the nested pipe assembly 10 at the bottom of the wellbore 18 with little or no "rat hole" or open hole section below. In embodiments where the BHA 10 extends substantially from the nested pipe assembly 10, the BHA retractor 100 may be used to partially or fully retract the BHA 100 into the nested pipe assembly 10. In one embodiment, the BHA retractor 130 provides selective retraction of the BHA a 100 into the innermost bore of the nested pipe assembly 10 (for example, the bore 17) and selectively extending the BHA 100 out of the nested pipe assembly 10. The BHA retraction device 130 may include cooperating locks, splines, or other mechanical devices to connect and disconnect the BHA 100 from the nested pipe assembly 10. Alternatively, an explosively, pneumatically, hydraulically or electromechanically actuated assembly or an anchoring tool can be used. In use, the BHA retractor 130 is actuated to release the BHA 100 from the nested tubing assembly 10. Once released in this manner (the BHA 100 which has formed an open section in the wellbore (or "pilot hole"), can be retracted in the nested pipe assembly 10. This allows the other unseated liner (for example, the liner 14) of the nested pipe assembly 10 to telescope into and line the pilot hole. In some circumstances, the casing shoe bit and liner may need to be reamed before the nested tubing assembly 10 is inserted into the pilot hole. After this outer tubing string has been cemented and tested, the BHA 100 is disengaged and drilled back to an extended position. The BHA 100 can be retracted by handling the drill string 20 or by using a It should be pointed out that the BHA draw-in device 130 does not need to be included in some configurations, for example where a "rat hole" is not important or r where the BHA 100 does not extend significantly from the nested drill assembly 10.

As previously noted, embodiments of the nested tubing assembly 10 can be used to drill and case/cement a wellbore section without an intervening trip of the BHA 100 and drill string 20 to the surface. To accommodate the different fluids and different fluid flow paths associated with successive drilling and cement lines, one embodiment of the lower fluid flow diverter assembly 140 controls the flow path of the different fluids (eg clean drilling mud, return mud, cement, etc.) used in drilling - and the cementation process. The assembly 100 includes valve assemblies and flow channels that control fluid communication with the nested casing bit 160. In one configuration, the valve assembly controls the flow of return fluid so that during drilling, all return mud and cuttings are directed up the innermost annulus bore (for example, the annulus bore 17), a small stream of the clean drilling fluid is led up an outermost annulus (for example the annulus bore 19), and, during cementing, all or mainly all the fluids are led up the outermost annulus (for example the annulus bore 19). In other embodiments, different flow control regimes may be used (for example, if reverse circulation is used, then different flow rates may be necessary).

In certain embodiments, the drill string extension 150 connects the nested casing hanger assembly 10 to the BHA 100. Much like the drill string 20, the drill string extension 150 can act as a tubular pressure-tight fluid conduit and a structural support element for the BHA 100. In one embodiment, the drill string extension 150 can interact with the BHA the retractor 130 and the nested casing hanger tool 170 to retract the BHA 100, as required (for example, during casing downhole drilling and cementing operations). Because the loads (eg, torsion and tension) applied to the drill string 20 and the drill string extension 150 can be different, these elements can be formed of different materials and have different dimensions and configurations. In certain other embodiments, the drill string extension 150 may structurally correspond to the drill string 20. In some embodiments, the drill string 20 may extend through the nested pipe assembly 10 and be directly connected to the BHA 100 without an intervening extension piece. The term "drill string" should be interpreted in its broadest possible sense, as any structure adapted to support well drilling operations, including bodies such as casing strings, casing strings, production pipes, etc.

In one embodiment, the nested casing shoe bit 160 is configured to ream and/or drill the wellbore to allow the nested tubing assembly 10 to easily advance the wellbore 18 with the BHA 100. The nested casing shoe bit 160 may be configured as a concentric shoe in several parts, which have radial and longitudinally oriented cutting elements 162, 164 positioned on an annular collar-like member at the downhole end of each pipe string 12, 14, 16 of the nested pipe assembly 10. The cutting elements 160, 162 thus go in engages with and cuts the wall of the wellbore when the casing assembly 10 rotates. The radially oriented cutting elements 162 may be configured to expand the wellbore in a rear undercut manner as the drill bit 102 and hole expansion device 120 drills forward. The longitudinally oriented drill elements 164 engage and cut an annular face of the wellbore wall as the BHA 100 drills the wellbore 18, and also after the BHA 100 is withdrawn into the inner annulus at the end of each section. The casing shoe drill bit 160 may be configured to interface with the fluid flow control tubing portion 140, to allow correct placement of cement and to regulate the flow of drilling fluids and cuttings. In some embodiments, the casing shoe drill bit 160 is formed as a plurality of concentric rings 166, 167, 168 that are configured to be cut across or otherwise disengaged from each other to allow the nested pipe assembly 10 to drill forward after the outermost section of the nested liner has been cemented or otherwise set in place. In certain embodiments, the shoe drill bit 160 is adapted to support and stabilize the lower end of the nested pipe assembly 10.

As previously described, the nested tubing assembly 10 provides two or more tubing members that can be used to line a drilled wellbore. The pipe members may be arranged in a concentric and telescopic manner, where the lower end of the nested pipe assembly 10 is attached to the nested casing shoe drill bit 160, and the upper end is connected to the nested casing hanger assembly 170. In certain embodiments, each of the individual linings 12, 14, 16 formed by a plurality of jointed pipes, which are assembled with the surface. The individual liners 12, 14, 16 can either be arranged to have essentially no annular space distance between the liners 12, 14, 16 or be dimensioned to provide specified annular space distances which can, for example, act as fluid passages. In addition, one or more of the liners 12, 14, 16 may be expandable in nature, in order to increase the available diameter of the wellbore. Furthermore, the liners 12, 14, 16 do not need to be identical in terms of length, wall thickness or materials. Nor do the liners 12, 14, 16 need to be arranged in a perfectly concentric and compact manner. Instead, in certain embodiments, one or more of the liners may protrude from an adjacent liner. Furthermore, in some embodiments, one or more of the liners 12, 14, 16 is formed either completely or partially of a material, such as a non-metallic material, which does not adversely affect the performance of the formation evaluation tools. It should be understood that, although three liners are shown, the liner assembly 10 may include as many individual liners as necessary or feasible for a given application.

In one embodiment, the casing hanger system 170 allows selective interlocking of the tubing strings 12, 14, 16, which make up the casing assembly 10. The casing hanger system 170 may be positioned at the downhole end of each nested casing 12, 14, 16 and may be configured to selectively anchor and detach the individual casings 12, 14, 16. In one embodiment, the casing hanger assembly 170 may be configured to support, at least temporarily, the weight of the tubing strings 12, 14, 16, and selectively detach the cemented or otherwise set tubing string from the remaining casing assembly 10, so that the remaining nested pipe assembly 10 can continue further down the hole. At the target depth for the next section, the outermost casing hanger tool can be returned after its casing has been cemented. The innermost casing hanger can also be made expandable, so that two or more sections of the nested pipe assembly become monoboring in nature.

Connected to the casing hanger system 170 is the upper fluid flow diverter 180, which controls selective setting and release of the casing hanger assembly, as well as performing other functions. In one embodiment, the upper fluid flow diverter includes a valve assembly adapted to sequentially release the liners, beginning with the outer liner 12. Likewise, embodiments of the nested tubing string interconnect 190 provide a mechanical bridge and a fluid bypass over the nested tubing string 10, which cooperates with the casing hanger system 170, the upper fluid flow diverter 180 and other systems described above to actuate constituent components and regulate fluid flow. For example, the cross connection 190 may include valve assemblies that channel clean drilling fluid to the BHA 100 .

The drill pipe 20 supports and carries the nested casing drill assembly 10. In some applications, the weight and inertia loads (both axial and rotational) of the nested pipe assembly 10 may be greater than conventional drilling and casing driving operations. The drill pipe 20 can thus be designed to have greater robustness than that which can be used for conventional drilling operations at equal depths. In other embodiments, a wireline carrier cable may be used to transport the BHA, the nested tubing assembly and other equipment downhole.

Reference should now be made to fig. 3, showing a flowchart 200 illustrating an exemplary application of the nested pipe assembly 10, with steps for (i) assembling the pipe assembly and the BHA (step 210), (ii) configuring/setting the equipment for drilling (step 220 ), (iii) drilling a section of a wellbore (step 230), (iii) configuring/setting the equipment for cementing and cementing (step 240), (vi) configuring/setting the equipment for drilling after cementing (step 250), and (vi) drilling another section of the wellbore (step 230). It should be noted that the BHA and drill string are pulled out of the hole in step 260, which is only after the completion of these described steps.

At assembly step 210, a first pipe string and an associated casing shoe drill bit (or "first pipe part assembly), for example the radially outermost casing and the associated casing shoe drill bit, are assembled and driven into the wellbore until a selected length for this first pipe part assembly is achieved. This first tubing assembly (including the outermost casing hanger) is suspended in the wellbore from the rig's deck with conventional casing handling tools (adder cups/holding wedges, etc.). Then another string of pipe and associated casing shoe bit ("second casing assembly") is assembled and driven into the first (or previous) casing assembly using setting tools on the rig deck, until the second casing shoe bit is immediately above the first casing shoe bit. Another casing hanger assembly is assembled and driven into the borehole in the outermost casing until the first and second casing shoe bits lock together, at which point this casing hanger is temporarily set. After the second pipe string is temporarily set with an internal hanger at the top of the first pipe assembly, the rig deck setting tool is disconnected from the second pipe string to prepare for subsequent assemblies of the pipe assembly, if necessary, to form the nested pipe assembly 10 or allowing driving of the drill BHA into the innermost casing subassembly.

With the nested pipe assembly 10 assembled and hanging from the drilling rig deck, the BHA and support equipment, such as the BHA retractor, and the lower fluid flow diverter pipe section, are assembled and driven in with the setting tool and positioned inside the central bore of the nested pipe assembly 10 (for example, the BHA 100 is barely drilled for the casing shoe bit assemblies). Additional support equipment such as the upper flow diverter assembly and the nested pipe string cross connection are then assembled and the cross connection is locked into the innermost pipe string. After a first length of drill pipe is inserted above the cross connection, the drill pipe is lifted to lift the nested pipe assembly and the BHA, so that the retaining wedges connecting the nested pipe assembly to the rig deck can be released. With the nested pipe assembly now free, the assembly is lowered and suspended by means of retaining wedges on the drill pipe 20. At this point, the nested pipe assembly can be lifted out of the retaining wedges and driven into the wellbore together with drill pipe in a conventional manner. The BHA 100 and the nested pipe assembly 10 are driven in the wellbore until the casing shoe drill bit 160 and the BHA 100, which are pulled into the nested pipe assembly 10, as far as they are above the bottom of the wellbore, or still within the last pipe string.

In the configuration for drilling step 230, the BHA is disengaged from the BHA retractor and allowed to extend out of the nested tubing assembly until the hole expansion device is outside the casing shoe bit. The hole widening device is then actuated so that the cutting elements can cut a diameter to match the diameter of the outermost pipe string. Drilling fluid is then circulated to supply energy to the drill motor and initiate slow rotation of the drill bit. The BHA advances, into the formation, and the BHA locks in the fully extended position. At this point the BHA can begin drilling.

In drilling step 230, drilling begins with drilling fluid circulation maintained at flow rates suitable for operation of downhole drilling motors, and the casing shoe bit is rotated by the drill string. Drilling continues until the target depth has been reached. The length of the section being drilled is in some cases determined by the length of the pipe string to be placed in the drilled section. In some configurations, the nested pipe strings will overlap to some extent at their ends, in order to maintain structural continuity between the successive pipe strings. After the target depth has been reached, circulation of drilling fluid can be continued or stopped while the BHA is drawn into the central bore of the nested pipe assembly. Before the BHA is retracted, the hole expansion device is actuated to retract the drill arms. Depending on the configuration of the hole expansion device, the actuation can take place by means of hydraulics, it can be mechanical, electromechanical, electrical or pneumatic. The BHA retractor is then actuated to retract the BHA until the BHA is locked in the retracted position. At this point, the rotation of the drill string will cause the casing shoe bit to rotate and crush the formation. The nested pipe assembly drills forward until it reaches the target depth. Circulation of drilling fluid is continued until the drilled hole is clean and in a suitable condition for cementing.

In the cementing step 240, the lower and optionally the upper fluid flow diverter valves are first configured to form a flow path to direct cement into the annular space between the wellbore wall and the nested pipe assembly. For example, the valves are actuated to close the inner annular passage used to direct return fluid up the hole and open the fluid passage to direct cement up the annular space. Fluids can be circulated and pipes can be operated to clean this annular space. After wellbore preparation is complete, surface pumps are activated to pump the desired volume of cement, which is followed by a washing procedure to develop extrudable plugs to ensure correct placement and cleaning of the BHA. Appropriate measures to retain cement behind the pipe string include maintaining cement pressure and/or the use of locking plugs. After the cement is set, fluid flow diverter valves are cycled to enable actuation of the casing setting device, and to set the outermost casing hanger. After the casing hanger is set, the pipe string is tested as necessary for structural and hydraulic integrity. It should be understood that cement is only a suitable connecting material for connecting the pipe to the wellbore. Other bonding materials include, but are not limited to, sealants, intumescent materials, epoxies, resins, polymers, porous materials, and non-porous materials. It should also be understood that cement is only a way to connect the pipe string to the wellbore. Other methods include mechanical connection devices such as gaskets, and devices outside the casing, regardless of whether these are actuated mechanically, electrically or hydraulically, which provide strength, structural integrity and sealing can also be used. In some embodiments, a mechanical, chemical, thermal or other connection treatment of the pipe string can actually be used to connect, either permanently or temporarily, the pipe string to the wellbore.

In preparing for drilling after cementing step 250, the upper and lower fluid flow diverter valves are cycled or reconfigured to re-establish the drilling fluid flow paths. After the downhole and uphole fluid flow is established and confirmed, the BHA is disengaged and energized to drill forward a specified distance (eg a few feet). After pressure tests show that the newly cemented shoe is adequate, drilling continues until the hole expansion device can be opened to the selected diameter. Slow drilling continues until the BHA locks in the extended position. Then, before drilling can continue, the newly cemented tubing string is detached from the adjacent inner tubing string by activation of the casing hanger tool. Next, the remaining nested tubing assembly and BHA are pulled away from the bottom of the wellbore, and the interlock between the casing shoe bits on the newly cemented tubing string and the adjacent tubing string is released. With the nested tubing assembly and the BHA now free, slow rotation is established and the BHA is allowed to slowly return to the bottom of the wellbore.

Drilling now continues in much the same way as in step 230, i.e. that circulation of drilling fluid is maintained at flow rates suitable for driving downhole drilling motors, and that the casing shoe drill bit is rotated by means of the drill string to which it is connected. Drilling continues until the target depth has been reached.

The above steps are repeated until the innermost pipe assembly has been cemented and the casing hanger set and tested. Preparations are then made to pull the BHA and drill string out of the wellbore. First, the lower fluid flow diverter valve is configured or cycled to the drill position, and the upper fluid flow diverter valve is cycled to the drill string. Then the setting tool, which anchors or connects the BHA and the drill string to the cemented pipe string, is actuated to dislodge the cemented pipe string so that the BHA can be pulled out of the lower casing. After the BHA is driven out of the wellbore in step 260, the next nested tubing assembly (if required) is assembled and fed into the wellbore.

In another embodiment, a single casing string can be driven into a wellbore at the same time as the drilling assembly is driven. For example, in an offshore well, after the top of the casing has passed under the wellhead, the casing can be temporarily suspended below the wellhead. The drill string is then released and driven to full depth to drill the next section of the hole. After the total depth for this drill section is reached, the drill string is pulled back into the vicinity of the suspended casing, and relocked. After locking, the liner is driven to the bottom and cemented. The drill string is then pulled and the process can be repeated. Thus, generally speaking, a casing string is stored in the wellbore by being suspended in the wellhead or from a subsea stack. This will eliminate the need for the liner to be attached to the drill string during the drilling operation, but allows the drill assembly to wash and clear the liner shortly after a section has been drilled.

The above listing of equipment, devices, systems and steps should not be understood as a mandatory combination to practice one or more of the teachings according to the present invention. Instead, the equipment, devices, systems and steps are described only to illustrate desirable adaptations of the teachings of the present invention to situations that may be encountered in various applications. For example, in certain embodiments, a BHA may be connected to a pipe, such as a casing string, having a diameter sufficient to allow the BHA to move therethrough. In such an arrangement, the BHA may be adapted to be retrieved from the wellbore via a wireline (or other suitable umbilical).

In a similar way, tools and devices that are not described above can in certain cases be used to facilitate the drilling and completion activity. For example, in some applications the wellbore fluid pressure gradients may be such that the open wellbore section formed by the BHA may be prone to fracture or damage. A device for managing wellbore pressure and for controlling the effects of equivalent circulating density (ECD) is an active differential pressure device (APD device), such as a jet pump, turbine or centrifugal pump , in fluid communication with the returning fluid. The ECD device creates a differential pressure above the device, which changes the pressure below or downhole for the device. The APD device can be driven by means of a propulsion engine, a turbine, an electric motor or a hydraulic motor. The APD device may be positioned close to the open section of the hole (eg, downhole or adjacent to the nested tubing assembly) to reduce the pressure in the open section of the hole. Suitable methods and devices for controlling wellbore pressure are described in US patent no. 6,648,081 and US patent no. 6,415,877 and described in US applications entitled "Active Controlled Bottomhole Pressure System & Method", serial number 10/783,371 filed on 20 February 2004 , and US application entitled "Subsea Wellbore Drilling System for Reducing Bottom Hole Pressure", serial number 10/716,106, filed November 17, 2003, which are hereby incorporated by reference for all purposes.

In many cases, the size of the surface pipe, wellhead and BOP will determine the maximum diameter for the concentric tubing string casing assembly. Also, the length of the surface pipe will likely determine the maximum length of the first concentric (or nested) assembly to be run. Additional nested pipe assemblies can be run. The diameter and length of these successive nested pipe assemblies will be determined by the sizes of the previous casing/casings and the total depth of the wellbore at the time the successive nested pipe assemblies are run. It should be understood that at least the diameter of such nested pipe assemblies is the diameter during drive-in or withdrawal in the wellbore, and not necessarily the set diameter (which may for example be larger due to expansion).

It is to be understood that the terms casing and casing are to be interpreted broadly, to include any devices or mechanisms that provide one or more of the wellbore's stability, zone isolation and protection against formation damage/fracturing. Furthermore, it shall be understood that the expression "single trip" or "reduced trip" shall be interpreted as including any procedure where there is not a complete trip (either into or out of the well), corresponding to each drilling stage or each cement stage. For example, the present invention includes methods and devices that use one trip to line two open well sections and another trip to cement both well sections, which nevertheless provides a reduction and corresponding saving of a full trip. Further other corresponding permutations can also be used in connection with the present invention, such as a partial trip out of the well.

It should be noted that the present teaching can be applied to both offshore and land-based wells. Moreover, the differences in equipment for application and land and offshore can provide cases where modifications of the described designs can be advantageously used. For example, as is known, a riser is often used in an offshore application to, in the form of an umbilical, connect a subsea wellhead to a surface facility (eg floating platform). In certain embodiments, a nested pipe assembly can be formed in the riser and then transported into the wellbore.

In addition, as previously pointed out, cement is only one of several methods and devices for connecting a pipe to the wellbore. Other devices such as inflatable gaskets or gels can in some applications be used to connect a pipe to the wellbore. Moreover, the connection of the pipe to the wellbore does not have to be

permanently (for example for the life of the well). A connection may be adequate if, for example, it holds the pipe for a time long enough for a subsequent pipe to be connected to the wellbore. A wellbore can thus have certain sections where inflatable gaskets are used to connect the pipe to the wellbore, and other sections where cement is used to connect the pipe to the wellbore. An advantage of such an arrangement is that a cement column does not need to be formed throughout the entire well drilling.

In yet another aspect of the present invention, at least two casing drill bits of different diameters and having associated casing sections may be assembled to form a drill assembly for drilling into subterranean formations, wherein radially adjacent casing sections are selectively releasably attached to each other, and where the at least two casing drill bits and casing sections are arranged in a telescoping relationship. Such a configuration can reduce the time required to arrange the casing sections attached to each major and minor casing bit in the borehole.

For example, as shown in FIG. 4 and 5, the drilling assembly 911 may include a first casing bit 916 and a second casing bit 914, where the first casing bit 916 is disposed within the first casing bit 914. The first casing bit 916 may be attached to a casing section 908, and the second casing bit 914 may be attached to a casing section 906. The casing sections 906 and 908 can thus be configured in a telescoping relationship, i.e. they can be extended from or into each other. As shown in fig. 4, the casing section 908 is attached to the casing section 906 by brittle members 918. The brittle members 918 may be configured to transmit torque, axial force, or weight-on-bit (WOB), or both between the casing sections 906 and 908. Other structures for transferring forces between the casing sections 906 and 908 can of course be used.

Therefore, during operation, torque and WOB may be applied to casing bit 914 through casing section 906. Alternatively, torque and WOB may be applied to casing bit 914 by means of casing section 908 and through fragile elements 918. As can be understood, when casing bits 914 and 916 are structurally coupled to each other, torque WOB or both can be transferred between them. In addition, the fluid ports or openings between each of the casing drill bits 914 and 916 can be connected, so that drilling fluid can be delivered through the interior of the casing drill bit 916 to the casing drill bit 914. Alternatively, drilling fluid can be delivered through the annulus 924, while the ports or openings in the casing drill bit 916 can be plugged or blocked. Thus, many options are possible for the delivery of drilling fluid or other fluids (for example, cement) to any of the casing drill bits 914 and 916.

As shown in fig. 5, a casing section 904 may be provided at a first depth. The casing bit 914 can then be brought to drill past the casing bit 912 and continue drilling to a different depth. When it reaches another depth, torque, WOB, or both can be applied to cause the fragile elements 918 to fail or break. Alternatively, a fragile element can be caused to fail by selective detonation of a pyrotechnic agent, an explosive agent, or both. Furthermore, the fragile element may be formulated to be selectively soluble when exposed to a chemical agent (for example, hydrochloric acid or hydrofluoric acid). For example, a first fragile element may fail when exposed to a first chemical agent, and a second fragile element, which is relatively immune to the first chemical agent, may fail when exposed to a second chemical agent. The casing drill bit 916 can thus be used to drill through the casing drill bit 914 and to a third depth. In other words, fig. 5 shows the drill assembly 911 in an extended telescoping relationship. The present invention is of course not limited to any specific number of casing drill bits which are configured in a telescoping relationship. Instead, a drilling assembly according to the present invention may include one or more casing drill bits which are arranged at least partially inside one or more other casing drill bits in a telescoping relationship.

It should also be understood that the present invention is not limited to a smaller casing bit or casing section being positioned at least partially within another casing bit for configuration in a telescoping relationship. Instead, more specifically, one casing bit or casing section may be disposed within another casing section, which may be attached to another, larger casing bit, for configuration in a telescoping relationship.

Alternatively, an assembly of two or more casing sections configured in a telescoping relationship may be drilled into a subterranean formation by means of a drilling tool disposed at its leading end. Specifically, as shown in FIG. 6, which illustrates a drilling assembly 933, casing sections 904, 906 and 908 can be connected together by, for example, locking casing sections 904, 906 and 908 together to form an assembly that can be drilled into a formation using a conventional drilling tool 934 which is arranged at the forward end, in the direction of drilling, of the drilling assembly 933, the drilling tool 934 having a diameter that exceeds the diameter of the largest casing section 904. The drilling tool 934 may comprise a rotary drill bit, a reamer, a reaming assembly, or a casing drill bit, without limitation. The drilling tool 934 can advance into the formation by rotation and displacement of the casing sections 904, 906 and 908. However, it is preferred that the drilling tool 934 can be structurally connected to the innermost casing section 908, so that the drilling tool 934 can continue to drill into the formation despite for the casing sections 904 or 906 to be arranged inside the borehole. A downhole motor may optionally be positioned between the innermost casing section 908 and the drilling tool 934 .

As the drill assembly progresses into the formation, radially adjacent smaller casing sections can be unlocked from radially adjacent larger casing sections, and extended therefrom. Fragile elements (not shown) as described here above (Fig. 4), can of course structurally connect the casing sections 904, 906 and 908 to each other. Forces may be applied to cause such fragile elements to fail, or flammable or explosive components may be used to cause fragile elements to fail. Furthermore, the fragile element may be formulated to be selectively soluble when exposed to one or more selected chemical agents. However, the telescoping relationship between the casing sections 904, 906 and 908 may provide an advantage in reducing the drive-in/withdrawal operations for arranging the casing sections 904, 906 and 908 inside the borehole.

In addition, an assembly of two or more casing sections configured in a telescoping relationship may be drilled into a subterranean formation by means of a casing drill bit disposed at its forward end. As shown in fig. 7, a drill assembly 944 that includes casing sections 904, 906 and 908 can be drilled into a formation using a casing drill bit 946 of the present invention. However, the casing bit 946 may be primarily coupled to the innermost casing section 908, as shown by the radially extending flange 948 and attachment surface 947, so that the casing bit 946 may continue to drill into the formation despite the casing sections 904 or 906 being disposed within the wellbore, as well as being separated from the casing section 908.

As previously discussed, formation evaluation (FE) tools typically cannot be positioned inside a casing, because the metal in the casing can significantly impair the FE tools' ability to examine the drilled formation. Accordingly, in previously described embodiments, formation evaluation tools are positioned in a pipe section of the BHA, which is below the casing string to expose the FE tools to the formation. Previously described embodiments also utilized non-metallic casing sections which allow the FE tools to examine the adjacent formation through the walls of these non-metallic casing sections.

In still other embodiments, formation evaluation tools are drilled on the outside of the casing string. FE tools outside the casing can measure various parameters of interest related to the formation without interference from the metal in the casing string. It should be understood that the length of the BHA extending out of the casing string is reduced by carrying the FE tools in the casing assembly instead of in the BHA. Also, in some embodiments, the drill motor and/or hole expansion device is also positioned within the casing assembly, to further reduce the length of the BHA that extends below the casing assembly.

Exemplary embodiments are discussed below. Reference should now be made to fig. 8, where a casing shoe 1000 of a casing string 1010 is shown, which by means of a locking assembly 1012 is removably connected to an inner casing string 1014, which is telescopically arranged inside the casing string 1010. The inner casing string 1014 is provided with a drilling motor 1020, formation evaluation - (FE) tool 1030, which is mounted on the drilling motor 1020, and a hole expansion device 1050 that is positioned uphole for the FE tools 1030. A shaft assembly 1024 that rotates a drill bit 1026 is connected to a rotor 1022 in the drilling motor 1020. To rotate the hole expansion device 1050, the casing string 1010 may be rotated, or an optional motor (not shown) may be used. By positioning the FE tools 1030 on the drill motor 1020, the length of the BHA that extends below the casing shoe 1000, which is generally represented by the shaft assembly 1024 and the drill bit 1026, is shortened. In addition, as should be appreciated, additional length savings are achieved by mounting or integrating the FE tools 1030 on a housing 1028 of the drill motor 1020 instead of using a separate tubing section for the FE tools 1030.

Reference should now be made to fig. 9, where a casing shoe 1100 of a casing string 1110 is shown, which by means of a locking assembly 1112 is removably connected to an inner pipe string 1114 which is telescopically arranged inside the casing string 1110. The inner pipe string 1114 is provided with than a drilling motor 1120, FE tools 1130 mounted on extendable members 1140, and a hole expansion device 1150 positioned downhole for the FE tools 1130. The casing string 1110 can be rotated or an optional motor (not shown) can be used to rotate the hole expansion in direction 1150. A shaft assembly 1124 that rotates a drill bit 1126 is connected to a rotor 1122 in the drill motor 1120. Because the FE tools 1130 are mounted uphole for the hole expansion device 1150, an annular space 1152 can separate the casing string 1110 from the wellbore wall 1154. Because many formation evaluation sensors operate optimally when they is positioned close to the wellbore wall 1154, the extensible members 1140 are used to to move the FE tools 1130 radially outward to the wellbore wall 1150. The means 1140 can be pads or arms that can be moved using preloading means, such as springs, hydraulic power, or electromechanical devices, such as an electric motor.

Reference should now be made to fig. 10, where there is shown a casing shoe 1200 of a casing string 1210, which by means of a locking assembly 1212 is removably connected to an inner pipe string 1214, which is telescopically arranged inside the casing pipe string 1210. The inner pipe string 1214 is provided with a drilling motor 1220 , FE tools 1230 mounted uphole for the drilling motor 1220, and a hole expansion device 1240 is positioned uphole for the FE tools 1230. The casing string 1210 can be rotated, or an optional motor (not shown) can be used to rotate the hole expansion device 1240. Unlike the embodiment on fig. 8, the FE tools 1230 are positioned in a pipe section 1250 separately from the drill motor 1220.

Although the FE tools, such as the FE tools 1230, are shown positioned on an inner string of the telescoping tube assembly, it should be understood that each tube comprising a telescoping tube assembly may include a set of FE tools. For example, in FIG. 10, another FE tool 1300 may be positioned on the casing string 1210 in addition to the FE tools 1230 on the inner string 1214.

However, it should be understood that the teachings of the present invention are not limited to formation evaluation sensors and tools. FE tools are only illustrative of the tools, devices and equipment that are conventionally positioned in a BHA, and can in certain cases contribute to the overall length of a BHA. In other embodiments, devices positioned on the casing include tools and sensors used for adaptive downhole control and for forming a closed-loop drilling system. Adaptive control may include an outermost casing release mechanism, flow isolation, vibration damping, etc. In addition to sensors, devices such as actuators may be positioned on or within a casing body. These actuators, along with the sensors, can be used to activate devices such as an expandable escaper built on the outermost casing as soon as the casing is on the bottom.

It should be understood that the FE tools 1030, 1130, 1230 are described as "on", "outside" or "outside" the casing string in a functional sense only. This means that the FE tools do not need to be physically on the outside of the casing string. Instead, the FE tools can be partially or fully embedded in a non-metallic section of a casing string (for example, a section made of carbon fiber) or in a way that allows the FE tools to "look outside" the casing string. Furthermore, it must be understood that sensors other than FE tools can be used in accordance with the available teachers. For example, casing-mounted sensors may be directed inward to measure parameters of interest that are related to wellbore fluids, drilling fluids, produced formation fluids, or other items of interest. Other suitable sensors may include pressure transducers, seismic sensors, temperature sensors and other known devices that measure parameters of interest during drilling and after drilling, for example during completion activity such as cementing and during production.

Transmission of power and data between the sensors outside the casing and downhole processors and/or surface processors and power supplies can be established using suitable power and data buses (not shown). Devices such as inductive couplings and electrical slip rings can be used to transmit power/data over rotating interfaces. In addition, telemetry arrangements using fixed link through pipe, fiber optic cables, electrical cables, mud pulse telemetry, acoustics, short jump, radio telemetry, electromagnetism, etc. can be used to transmit data along the BHA and casing string and to and from the surface.

Although the foregoing disclosure is directed to the preferred embodiments of the invention, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope of the attached requirements shall be covered by the preceding publication.

Claims (7)

1. A method of drilling a wellbore (18) in an underground formation, comprising: attaching a casing shoe bit (160) to a first pipe (12) and a second pipe (14); guiding the first pipe (12) and the second pipe (14) into the wellbore (18); driving a drilling tool (934) into one of the first and second pipes (12, 14); drilling a first pilot hole with the drilling tool (934); and expanding the first pilot hole by rotating the attached casing shoe drill bit (160) as the first pipe (12) is driven into the expanded first pilot hole; the method is characterized by: connecting the first pipe (12) to the well bore (18) without pulling the drilling tool (934) out of the well bore (18); drilling a second pilot hole with the drilling tool (934); and expanding the second pilot hole by rotating the attached casing shoe bit (160) simultaneously with driving the second pipe (14) into the expanded second pilot hole. 2. Method according to claim 1, characterized in that it further comprises pulling the drilling tool (934) out of the wellbore (18) after the connection step. 3. Method according to claim 1, characterized in that one of the first pipe (12) and the second pipe (14) is connected to the wellbore (18) by using one of (i) a connection material, (ii) a mechanical connection device, and (iii) a connection treatment. 4. Method according to claim 1, characterized in that it further comprises connecting the second pipe to the wellbore (18). 5. Method according to claim 1, characterized in that it further comprises assembling the first pipe (12) and the second pipe (14) in the wellbore (18) to form a telescopic pipe assembly. 6. Method according to claim 1, characterized in that it further comprises retraction of the drilling tool (934) into one of the first pipe (12) and the second pipe (14). 7. Method according to claim 1, characterized in that it further comprises positioning at least one tool (934) at least partially on one of the first pipe (12) and the second pipe (14) to determine at least one parameter of interest.