NO326621B1 - Apparatus and method for expanding a rudder element - Google Patents

Description

The present invention relates to an apparatus and a method for expanding a pipe element, according to the preamble.

Conventionally, when a wellbore is created, several casings are installed in the borehole to prevent collapse of the borehole wall and to prevent unwanted outflow of drilling fluid into the formation or inflow of fluid from the formation into the borehole. The borehole is drilled in intervals whereby a casing to be installed in a lower borehole interval is sunk through a previously installed casing in an upper borehole interval. As a result of this procedure, the casing in the lower interval is of smaller diameter than the casing in the upper interval. The casings are thus in a set arrangement with casing diameters decreasing in the downward direction in the borehole. Cement annulus is provided between the outer surfaces of the casings and the borehole wall to seal the casings from the borehole wall. As a result of this set device, a relatively large borehole diameter is necessary for the upper part of the borehole. Such a large borehole diameter involves increased costs due to point casing handling equipment, large drill bits and increased volumes of drilling fluid and cuttings. Also, increased drilling rig time is involved due to the necessary cement pumping, cement hardening, necessary equipment changes due to large variations in the hole diameters drilled during the well drilling, and large volumes of cuttings drilled and removed.

Conventionally, at the surface end of the wellbore, a wellhead is formed which typically comprises a surface casing, several production and/or drilling coils, valves, and a valve tree. The wellhead typically further comprises a concentric arrangement of casing, comprising a production casing and one or more intermediate casings. The casings are typically supported using load-bearing stop wedges placed above the surface. The conventional design and construction of wellheads is expensive and complicated.

For other prior art, reference is made to US 5,984,568 and US 6,085,838.

The present invention is directed to overcoming one or more of the limitations of the existing procedures for designing boreholes and wellheads. This is achieved with the apparatus and the method as defined by the features listed in the claims.

In the following, the invention will be described in more detail with reference to the drawings, where: Figure 1 is a partial cross-sectional view illustrating the drilling of a new section of a wellbore. Figure 2 is a partial cross-sectional view illustrating the location of one embodiment of the apparatus for creating a casing within the new section of the wellbore. Figure 3 is a partial cross-sectional view illustrating the injection of a first quantity of a liquid material into the new section of the wellbore. Figure 3a is another partial cross-sectional view illustrating the injection of a first quantity of a curable liquid sealing material into the new section of the wellbore. Figure 4 is a partial cross-sectional view illustrating injection of another amount of a liquid material into the new section of the wellbore. Figure 5 is a partial cross-sectional view illustrating drilling out of a portion of the hardened curable liquid sealing material from the new section of the wellbore. Figure 6 is a cross-sectional view of an embodiment of the overlap joint between adjacent tubular parts. Figure 7 is a partial cross-sectional view of a preferred embodiment of the apparatus for creating a casing inside a wellbore. Figure 8 is a partial cross-sectional view illustrating the placement of an expanded tubular member within another tubular member. Figure 9 is a cross-sectional illustration of a preferred embodiment of an apparatus for forming a casing comprising a drillable mandrel and shoe. Figure 9a is another cross-sectional view illustrating the apparatus of Figure 9. Figure 9b is another cross-sectional view of the apparatus of Figure 9. Figure 9c is another cross-sectional view illustrating the apparatus of Figure 9. Figure 10a is a cross-sectional illustration of a wellbore comprising a pair of adjacent overlapping casing. Figure 10b is a cross-sectional illustration of an apparatus and method for creating a tied-back casing using an expandable tubular member. Figure 10c is a cross-sectional illustration of the pumping of liquid sealing material into the annular region between the tubular portion and the existing casing. Figure 10d is a cross-sectional illustration of the pressure supply to the interior of the tubular portion below the spindle. Figure 10e is a cross-sectional illustration illustrating the extrusion of the tubular portion from the spindle. Figure 10f is a cross-sectional illustration of the tie-back liner prior to drilling out the shoe and gasket. Figure 10g is a cross-sectional illustration of the completed tie-back liner created using an expandable tubular member. Figure 11a is a partial cross-sectional view illustrating the drilling of a new section of a wellbore. Figure 1b is a partial cross-sectional view illustrating the location of one embodiment of an apparatus for suspending a tubular casing within the new section of the wellbore. Figure 1c is a partial cross-sectional view illustrating the injection of a first quantity of a curable liquid sealing material into the new section of the wellbore. Figure lid is a partial cross-sectional view illustrating the introduction of a scraper arrow into the new section of the wellbore. Figure 1e is a partial cross-sectional view illustrating the injection of another quantity of curable liquid sealing material into the new section of the wellbore. Figure llf is a partial cross-sectional view illustrating the completion of the tubular liner. Figure 12 is a cross-sectional view illustrating a preferred embodiment of a wellhead system that uses expandable tubular parts. Figure 13 is a partial cross-sectional view illustrating a preferred embodiment of the wellhead system of Figure 12. Figure 14a is an illustration of the design of an embodiment of a monodiameter wellhead casing. Figure 14b is another illustration of the design of the monodiameter wellbore casing. Figure 14c is another illustration of the design of the monodiameter wellbore casing. Figure 14d is another illustration of the design of the monodiameter wellbore casing. Figure 14e is another illustration of the design of the monodiameter wellbore casing. Figure 14f is another illustration of the design of the monodiameter wellbore casing. Figure 15 is an illustration of one embodiment of an apparatus for expanding a tubular part. Figure 15a is another illustration of the apparatus of Figure 15. Figure 15b is another illustration of the apparatus of Figure 15. Figure 16 is an illustration of one embodiment of an apparatus for forming a monodiameter well casing. Figure 17 is an illustration of one embodiment of an apparatus for expanding a tubular part. Figure 17a is another illustration of the apparatus of Figure 16. Figure 17b is another illustration of the apparatus of Figure 16. Figure 18 is an illustration of one embodiment of an apparatus for forming a monodiameter well casing. Figure 19 is an illustration of another embodiment of an apparatus for expanding a tubular part. Figure 19a is another illustration of the apparatus of Figure 17. Figure 19b is another illustration of the apparatus of Figure 17. Figure 20 is an illustration of one embodiment of an apparatus for forming a monodiameter well casing. Figure 21 is an illustration of the isolation of underground zones using expandable pipes.

An apparatus and method for forming a wellbore casing in a subterranean formation is provided. The apparatus and method permit the formation of a wellbore casing in a subterranean formation by placing a tubular member and a mandrel in a new section of a wellbore, and then extruding the tubular member from the mandrel by pressurizing an internal region thereof tubular part. The apparatus and method further allow adjacent pipe parts in the wellbore and are joined together using an overlapping joint which prevents the passage of fluid and gas. The apparatus and method further allows a new tubular member to be supported by an existing tubular member by expanding the new tubular member into contact with the existing tubular member. The apparatus and method further minimizes the reduction in hole size of the wellbore casing required by the addition of new sections of wellbore casing.

An apparatus and method for forming a platform liner using an expandable pipe member is also provided. The apparatus and method allows a platform liner to be created by extruding a tubular member from a spindle by pressurizing an inner region of the tubular member. In this way, a platform lining is produced. The apparatus and method further allow adjacent tubular parts in the wellbore to be joined using an overlapping joint which prevents the passage of fluid and/or gas. The apparatus and method further allow a new tubular member to be supported by an existing tubular member by expanding a new tubular member into contact with the existing tubular member.

An apparatus and method for expanding a tubular member is also provided, comprising an expandable tubular member, spindle and a shoe. In a preferred embodiment, the inner regions of the apparatus consist of materials that allow the inner regions to be removed using a conventional drilling apparatus. In this way, in the event of a malfunction down a borehole, the device can be easily removed.

An apparatus and method for suspending an expandable tubular casing in a wellbore is also provided. The apparatus and method allow a tubular casing to be attached to an existing section of casing. The apparatus and method can also be used for joining tubular parts in general.

The apparatus and method for designing a wellhead system is also provided. The apparatus and method allows a wellhead to be formed comprising a plurality of expandable tubular members arranged in a concentric arrangement. The wellhead preferably comprises an outer casing that supports several concentric casings that use contact pressure between the inner casing and the outer casing. The resulting wellhead system eliminates many of the spools conventionally required, reducing the height of the valve tree and facilitating service work, lowering the load-bearing areas of the wellhead, resulting in a more stable system, and eliminating costly suspension systems.

An apparatus and method for forming a monodiameter wellbore casing is also provided. The apparatus and method allow the creation of a well casing in a wellbore having a substantially constant internal diameter. In this way, the operation of an oil or gas well is greatly simplified.

An apparatus and method for expanding tubular parts is also provided. The apparatus and method utilize a piston-cylinder configuration in which a pressurized chamber is used to drive a spindle for radial expansion of tubular parts. In this way, higher operating pressures can be used. Through the radial expansion process, the tubular parts are never placed in direct contact with the operating pressures. In this way, damage to the tubular parts is prevented, while also allowing controlled radial expansion of the tubular parts in a . well hole.

An apparatus and method for forming a monodiameter wellbore casing is also provided. The apparatus and method utilize a piston-cylinder configuration in which a pressurized chamber is used to drive a spindle for radial expansion of the tubular members. In this way, higher operating pressures can be used. Through the radial expansion process, the tubular part is never placed in direct contact with the operating pressures. In this way, damage to the tubular parts is prevented, while also allowing controlled radial expansion of the tubular part in a wellbore.

An apparatus and method for isolating one or more underground zones from one or more other underground zones is also provided. The apparatus and method allow a producing zone to be isolated from a non-producing zone using a combination of sealed and slotted tubing. In production mode, the information herein may be used in combination with conventional, well-known production completion equipment and methods utilizing a variety of gaskets, sealed tubes, perforated tubes, and sliding sleeves, which will be inserted into the described apparatus to permit mixing and /or isolation of the underground zones from each other.

Referring first to Figures 1 to 5, an embodiment of an apparatus and method for forming a wellbore casing within an underground formation will be described. As illustrated in Figure 1, a wellbore 100 is located in an underground formation 105. The wellbore 100 comprises an existing lined section 110 having a casing 115 and an annular outer layer of cement 120.

To extend the wellbore 100 into the underground formation 105, a drill string 125 is used in a known manner to drill out the material from the underground formation 105 to form a new section 130.

As illustrated in Figure 2, an apparatus 200 for forming a wellbore casing in a subterranean formation is then placed in the new section 130 of the wellbore 100. The apparatus 200 preferably comprises an expandable spindle or spike 205, a tubular member 210, a shoe 215, a lower cup seal 220, an upper cup seal 225, a fluid passage 230, a fluid passage 235, a fluid passage 240, seals 245, and a support part 250.

The expandable spindle 205 is connected to and supported by the support part 250. The expandable spindle 205 is preferably adapted for controllable expansion in the radial direction. The expandable spindle 205 may comprise any number of conventional commercially available expandable spindles, modified according to the information herein. In a preferred embodiment, the expandable spindle 205 comprises a hydraulic expansion tool as described in US 5,348,095, the content of which is incorporated herein by reference, modified according to the information in the present description.

The tubular member 210 is supported by the expandable mandrel 205. The tubular member 210 is expanded in the radial direction and is extruded from the expandable mandrel 205. The tubular member 210 can be fabricated from any number of conventional commercially available materials, such as, for example, Oilfield Country Tubular Goods (OCTG), 13 chrome steel tube/lining or plastic tube/lining. In a preferred embodiment, the pipe member 210 is fabricated from OCTG to maximize strength after expansion. The inner and outer diameters of the tubular part 210 can e.g. range from about 0.75 to 47 inches and from 1.05 to 48 inches. In a preferred embodiment, the inner and outer diameters of the tubular portion 210 range from about 3 to 15.5 inches and 3.5 to 16 inches to optimally produce minimum telescoping in the most common drilled wellbore sizes. The tubular part 210 preferably comprises a solid part.

In a preferred embodiment, the end region 260 of the tubular member 210 is slotted, perforated or otherwise modified to trap or delay the spindle 205 as it completes the extrusion of the tubular member 210. In a preferred embodiment, the length of the tubular member 210 is limited to minimize the possibility of bulking. For typical materials of the pipe section 210, the length of the pipe section 210 is preferably limited to between about 40 to 20,000 feet (12 to 6,000 meters) in length.

The shoe 215 is coupled to the expandable spindle 205 and the tubular member 210. The shoe 215 comprises a fluid passage 240. The shoe 215 may comprise any number of conventionally available shoes, such as e.g. Super Seal II float shoe, Super Seal II Down-Jet float shoe or a guide shoe with a sealing sleeve for a lock-down plug modified according to the information in this description. In a preferred embodiment, the shoe 215 comprises an aluminum flush shoe with a sealing sleeve for a shut-in plug available from Halliburton Energy Services of Dallas, Texas, modified according to the information herein, to optimally guide the tubular member 210 in the wellbore, optimally to produce an adequate seal between the inner and outer diameters of the overlapping joint between the pipe sections, and optimally allow complete boring of the shoe and plug after completion of the cementing and expansion operations.

In a preferred embodiment, the shoe 215 comprises one or more through and side outlet ports in fluid communication with the fluid passage 240. In this way, the shoe 215 will optimally inject curing liquid sealing material into the area outside the shoe 215 and the tubular part 210.1 a preferred embodiment, the shoe comprises 215 a fluid passage 240 having an inlet geometry that can receive a dart and/or ball seal member. In this way, the fluid passage 240 can be optimally sealed by introducing a plug, arrow and/or ball sealing elements in the fluid passage 230.

The lower cup gasket 220 is connected to and supported by the support portion 250. The lower cup gasket 220 prevents foreign material from entering the inner area of the tubular portion 210 near the expandable spindle 205. The lower cup gasket 220 may include any preferably the number of conventionally available cup gaskets, such as e.g. TP cups or Selective Injection Packer (SIP) cups modified according to the information in the present description. In a preferred embodiment, the lower cup packing 220 consists of a SIP cup packing, available from Halliburton Energy Services of Dallas, Texas, to optimally block foreign material and contain a body of lubricant.

The upper cup gasket 225 is coupled to and supported by the support member 250. The upper cup gasket 225 prevents foreign material from entering the interior area of the tubular portion 210. The upper cup gasket 225 may comprise any number of commercially available cups -packaging, such as e.g. TP cups or SIP cups modified according to the information in the present description. In a preferred embodiment, the upper cup packing 225 comprises a SIP cup, available from Halliburton Energy Services of Dallas, Texas, to optimally block entry of foreign material and to contain a body of lubricant.

The fluid passage 230 allows liquid material to be transported to and from the interior area of the tubular portion 210 below the expandable spindle 205. The fluid passage 230 is coupled to and located within the support portion 250 and the expandable spindle 205. The fluid passage 230 preferably extends from a position near the surface to the bottom of the expandable spindle 205. The fluid passage 230 is preferably located along a centerline of the apparatus 200.

The fluid passage 230 is preferably selected, in the casing run mode of operation, to transport materials such as drilling mud or formation fluids at low flow rates and pressures in the range of 0 to 3,000 gallons per minute and 0 to 9,000 psi to minimize drag on the tubing sections that being run and to minimize transient pressure exerted on the wellbore, which would cause loss of wellbore fluids and lead to collapse of the hole.

The fluid passage 235 allows liquid materials to be released from the fluid passage 230. In this way, during placement of the apparatus 200 in the new section 130 of the wellbore 100, liquid materials 255 that are forced up into the fluid passage 230 can be released into the wellbore 100 above the tubular portion 210 to thereby minimize transient pressure on the wellbore section 130. The fluid passage 235 is connected to and placed inside the support part 250. The fluid passage is further fluid-connected to the fluid passage 230.

The fluid passage 235 preferably comprises a control valve for controllable opening and closing of the fluid passage 235. In a preferred embodiment, the control valve is pressure activated to controllably minimize transient pressure. The fluid passage 235 is preferably positioned substantially orthogonally to the centerline of the apparatus 200.

The fluid passage 235 is preferably selected to conduct liquid materials at low flow rates and pressures in the range of 0 to 3,000 gallons per minute and 0 to 9,000 psi to reduce drag on the apparatus 200 during introduction into the new section 130 of the wellbore 100 and to to minimize transient pressure in the new wellbore section 130.

The fluid passage 240 allows liquid materials to be transported to and from the area outside the tubular portion 210 and the shoe 215. The fluid passage 240 is connected to and positioned within the shoe 215 in fluid communication with the interior area of the tubular portion 210 below the expandable spindle 205. The fluid passage 240 240 preferably has a cross-sectional shape which allows a plug or similar device to be placed in the fluid passage 240 to thereby block further passage of liquid materials. In this way, the inner area of the tubular part 210 below the expandable spindle 205 can be fluid-isolated from the area outside the tubular part 210. This allows the inner area of the tubular part 210 below the expandable spindle 205 to be pressurized. The fluid passage 240 is preferably located essentially along the center line of the apparatus 200.

The fluid passage 240 is preferably selected to conduct materials such as cement, drilling mud, or epoxy at flow rates and pressures ranging from about 0 to 3,000 gallons per minute and 0 to 9,000 psi to optimally fill the annulus between the tubular portion 210 and the new section 130 of the wellbore 100 with fluid materials. In a preferred embodiment, the fluid passage 240 comprises an inlet geometry that can receive a dart and/or ball seal member. In this way, the fluid passage 240 can be closed by introducing a plug, arrow and/or ball sealing element in the fluid passage 230.

The seals 245 are connected to and supported at the end portion 260 of the tubular portion 210. The gasket 250 is further positioned on an outer surface 265 of the end region 260 of the tubular portion 210. The seals 245 allow an overlapping joint between the end regions 270 of the casing 115 and the region 260 of the pipe part 210 is fluid sealed. The gaskets 245 may comprise any number of conventionally available gaskets, such as e.g. lead, rubber, Teflon or epoxy gaskets modified according to the information in the present description. In a preferred embodiment, the gaskets 245 are molded from StrataLock epoxy available from Halliburton Energy Services of Dallas, Texas, to optimally produce a load-bearing interference fit between the ends 260 of the tubular member 210 and the end 270 of the existing casing 115.

In a preferred embodiment, the gaskets 245 are chosen to optimally produce a sufficient frictional force to support the expanded tubular part 210 from the existing casing 115. In a preferred embodiment, the frictional force optimally produced by the gaskets 245 will lie in the range from 1,000 to 1 000,000 pounds (454 to 454,000 kg) to optimally support the expanded tubular section 210.

The support part 250 is connected to the expandable spindle 205, the pipe part 210, the shoe 215 and the packing 220 and 225. The support part 225 preferably comprises an annular part which has sufficient strength to carry the apparatus 200 into the new section 130 of the wellbore 100. In a preferred embodiment, the support portion 250 further includes one or more conventional centering devices (not illustrated) to assist in stabilizing the apparatus 200.

In a preferred embodiment, a quantity of lubricant 275 is provided in the annular region above the expandable spindle 205 within the interior of the tubular member 210. In this way, extrusion of the tubular member 210 from the expandable spindle 205 is facilitated. The lubricant 275 may comprise any conventional commercially available lubricant such as e.g. Lubriplate, chlorine-based lubricants, oil-based lubricants or Climax 1500 Antisieze (3100). In a preferred embodiment, the lubricant 275 comprises Climax 1500 Antisieze (3100) available from Climax Lubricants and Equipment Co. in Houston, Texas to produce optimal lubrication to facilitate the expansion process.

In a preferred embodiment, the support part 250 is thoroughly cleaned before assembly with the remaining parts of the apparatus 200. In this way, the introduction of foreign materials into the apparatus 200 is minimized. This minimizes the possibility of foreign materials blocking the various flow passages and valves in the apparatus 200.

In a preferred embodiment, before or after placing the apparatus 200 in the new section 130 of the wellbore 100, a pair of wellbore volumes are circulated to ensure that no foreign materials are in the wellbore 100 that could block the various flow passages and valves in the apparatus 200 , and to ensure that no foreign material affects the expansion process.

As illustrated in Figure 3, the fluid passage 235 is then closed, and a curable liquid sealing material 305 is pumped from a location on the surface into the fluid passage 230. The material 305 then passes from the fluid passage 230 into the interior region 310 of the tube portion 210 below the expandable spindle. 205. The material 305 then passes from the inner region 310 into the fluid passage 240. The material 305 then exits the apparatus 200 and fills the annular region 315 between the exterior of the tubular part 210 and the inner wall of the new section 130 of the wellbore 100 Continued pumping of the material 305 causes the material 305 to fill up at least part of the annulus 315.

The material 305 is preferably pumped into the annulus 315 at a pressure and a flow rate which is, for example ranging from 0 to 5,000 psi and from 0 to 1,500 gallons per minute. Optimum flow rates and operating pressures vary as a function of casing and wellbore dimensions, wellbore section lengths, available pumping equipment, and flow characteristics of the fluid being pumped. The optimum flow rate and operating pressure are preferably determined using conventional empirical methods.

The curable liquid sealant 305 may comprise any number of conventional, commercially available curable liquid sealants such as, for example, impact mix, cement or epoxy. In a preferred embodiment, the curable liquid sealing material 305 consists of a mixture of cement prepared specifically for the particular well section being drilled, from Halliburton Energy Services of Dallas, Texas, to provide optimal support for the tubing members 210 while maintaining optimal flow characteristics to minimize difficulties during the displacement of cement into the annulus 315. The optimum mixture of the mixed cement is preferably determined using conventional empirical methods.

The annular area 315 is preferably filled with material 305 in sufficient quantity to ensure that, after radial expansion of the pipe 210, the annular area 315 of the new section 130 of the wellbore 100 will be filled with material 305.

In a particularly preferred embodiment, as illustrated in figure 3a, the wall thickness and/or the outer diameter of the pipe part 210 is reduced in the area near the spindle 205 to optimally allow placement of the device 200 in place in the wellbore with tight clearances. Furthermore, in this way the initiation of the radial expansion of the pipe part 210 during the extrusion process is optimally facilitated.

As illustrated in Figure 4, as soon as the annulus 315 is sufficiently filled with material 305, a plug 405 or other similar device is introduced into the fluid passage 240, in order to fluid-isolate the inner area 310 from the annulus 315.1 is a preferred embodiment, a non -curable liquid material 306 is then pumped into the inner region 310 and pressurizing the inner region. In this way, the interior of the expanded tubular part 210 will not contain significant amounts of hardened material 305. This reduces and simplifies the cost of the entire process. Alternatively, material 305 may be used during this phase of the process. As soon as the inner region 310 comes under sufficient pressure, the tubular part 210 is extruded from the expandable mandrel 205. During the extrusion process, the expandable mandrel 205 can be raised out of the expanded part of the tubular part 210. In a preferred embodiment, during extrusion process, the spindle 205 is raised by approximately the same amount as the tubular portion 210 is expanded to keep the tubular portion 210 stationary relative to the new wellbore section 130. In an alternative preferred embodiment, the extrusion process is begun with the tubular portion 210 positioned above the bottom in the new wellbore section 130, where the spindle 205 is held stationary, allowing the tubular portion 210 to be extruded by the spindle 205 and to fall into the wellbore section 130 under gravity.

The plug 405 is preferably placed in the fluid passage 240 by inserting the plug 405 into the fluid passage 230 at a location on the surface in a conventional manner. The plug 405 preferably acts to fluidly isolate the curable liquid sealing material 305 from the non-curable liquid material 306.

The plug 405 may comprise any of several conventional devices for plugging a fluid passage, such as e.g. Multiple Stage Cementer (MSC) locking plug, Omega locking plug or wood scraper locking plug modified according to the information in this description. In a preferred embodiment, the plug 405 comprises an MSC lockout plug available from Halliburton Energy Services of Dallas, Texas.

After placing the plug 405 in the fluid passage 240, a non-curable liquid material 306 is preferably pumped into the inner region 310 at a pressure and a flow rate in the range of e.g. from 400 to 10,000 psi and 30 to 4,000 gallons per minute. In this way, the amount of curable liquid sealing material in the interior 310 of the pipe part 210 is minimized. In a preferred embodiment, after placement of the plug 405 in the fluid passage 240, the non-curable material 306 is preferably pumped into the interior region 310 at a pressure and flow rate in the range of about 500 to 9,000 psi and 40 to 3 000 gallons per minute to maximize extrusion speed.

In a preferred embodiment, the apparatus 200 is adapted to minimize stretching, cracking and friction effects on the pipe part 210 during the expansion process. These effects will depend on the geometry of the extrusion mandrel 205, the material composition of the tubular member 210 and the expansion mandrel 205, the inner diameter of the tubular member 210, the wall thickness of the tubular member 210, the type of lubricant and the breaking strength of the tubular member 210. In general, the thicker the wall thickness, the smaller the inner diameter, and the greater the breaking strength of the tubular part 210, and thus the greater the operating pressure required to extrude the tubular part 210 from the spindle 205.

For typical tube parts 210, the extrusion of the tube part 210 from the expandable spindle will begin when the pressure in the inner region 310 reaches e.g. about 500 to 9,000 psi.

During the extrusion process, the expandable spindle 205 may be lifted out of the expanded portion of the tube portion 210 by amounts in the range of e.g. from about 0 to 5 feet per second. In a preferred embodiment, during the extrusion process, the expanded mandrel 205 is raised out of the expanded region of the tube portion 210 at a rate in the range of 0 to 2 feet per second to minimize the time required for the expansion process while allowing easy control of the expansion process .

When the end region 260 of the pipe section 210 is extruded by the expandable spindle 205, the outer surface 265 of the end section 260 of the pipe section 210 will preferably contact the inner surface 410 of the end section 270 of the casing 115 to form a fluid-tight overlapping joint. The contact pressure in the overlapping joint can be in the range of e.g. from about 50 to 20,000 psi. In a preferred embodiment, the contact pressure of the overlap joint ranges from about 400 to 10,000 psi to provide optimal pressure to actuate the annular sealing members 245 and optimally provide resistance to axial movement to handle typical tensile and compressive loads.

The overlapping joint between section 410 of the existing casing 115 and section 265 of the expanded tubular portion 210 preferably provides a gas and fluid seal. In a particularly preferred embodiment, the sealing portion 245 optimally produces a fluid and gas seal in the overlapping joint.

In a preferred embodiment, the operating pressure and flow rate of the non-curable liquid material 306 is controllably reduced when the expandable spindle 205 reaches the end region 260 of the tubular member 210. In this way, the sudden release of pressure caused by the full extrusion of the tubular member 210 can of the expandable spindle 205 be minimized. In a preferred embodiment, the operating pressure is reduced in a substantially linear manner from 100% to about 10% during the end of the extrusion process, beginning when the spindle 205 is within about 5 feet of completion of the extrusion process.

Alternatively or in combination, a shock absorber is provided in the support portion 250 to absorb the shock caused by sudden release of pressure. The shock absorber can include, e.g. any commercially available shock absorber adapted for use in downhole operations.

Alternatively or in combination, a spindle capture structure is provided on the end region 260 of the tubular portion 210 to capture or at least decelerate the spindle 205.

Once the extrusion process is complete, the expandable mandrel 205 is removed from the wellbore 100.1 a preferred embodiment, either before or after removal of the expandable mandrel 205, the integrity of the fluid seal of the overlapping joint between the upper portion 260 and the tubular portion 210 and the lower portion 270 of casing 115 tested using conventional methods.

If the fluid seal of the overlapping joint between the upper part 260 of the pipe part 210 and the lower part 270 of the casing pipe 115 is satisfactory, a possibly uncured part of the material 305 inside the expanded pipe part 210 is removed in a conventional way, as e.g. by circulating the uncured material out of the interior of the expanded tubular portion 210. The spindle 205 is then withdrawn from the wellbore section 130 and a drill bit or mill when used in combination with a conventional drilling unit 505 to drill out curable material 305 within it tubular part 210. The material 305 inside the annulus 315 is then allowed to harden.

As illustrated in Figure 5, preferably any remaining hardened material 305 in the interior of the expanded pipe section 210 is then removed in a conventional manner using a conventional drill string 505. The resulting new section of casing 510 comprises the expanded pipe section 210 and an outer annular layer 505 of hardened material 305. The bottom region of the apparatus 200, comprising the shoe 215 and arrow 405, can then be removed by drilling out the shoe 215 and arrow 405 using conventional drilling methods.

In a preferred embodiment as illustrated in Figure 6, the upper part 260 of the tubular part 210 comprises one or more sealing parts 605 and one or more pressure release holes 610. In this way, the overlapping joint between the lower part 270 of the casing 115 and the upper part 260 of the pipe part 210 pressure-proof, and the pressure on the inner and outer surfaces of the pipe part 204 is equalized during the extrusion process.

In a preferred embodiment, the sealing parts 605 are located inside recesses 615 formed in the outer surface 265 of the upper part 260 of the tubular part 210. In an alternative preferred embodiment, the sealing parts 605 are banded or molded into the outer surface 265 of the upper part 260 of the pipe member 210. The pressure release holes 610 are preferably located in the last few feet of the pipe member 210. The pressure release holes reduce the operating pressure required to expand the upper portion 260 of the pipe member 210. This reduction in required operating pressure in turn reduces the speed of the spindle 205 after completion of the extrusion process. This reduction in speed in turn minimizes the mechanical shocks to the entire apparatus 200 after completion of the extrusion process.

Reference is now made to Figure 7, where a particularly preferred embodiment of the apparatus 700 for forming a casing inside a wellbore preferably comprises an expandable spindle or spike 705, an expandable spindle or spike container 710, a tubular part 715, a floating shoe 720, a lower cup seal 725, an upper cup seal 730, a fluid passage 735, a fluid passage 740, a support member 745, a body of lubricant 750, an overshoot connection 755, another support member 760, and a stabilizer 765.

The expandable spindle 705 is connected to and supported by the support part 745. The expandable spindle 705 is further connected to the expandable spindle container 710. The expandable spindle 705 is preferably adapted to controllably expand in the radial direction. The expandable spindle 705 may comprise any of several conventionally available expandable spindles, modified according to the information in the present description. In a preferred embodiment, the expandable spindle 705 comprises a hydraulic expansion tool, substantially as described in US 5,348,095, the contents of which are incorporated herein by reference, modified according to the information in the present specification.

The expandable spindle container 710 is connected to and supported by the support part 745. The expandable spindle container 710 is further connected to the expandable spindle 705. The expandable spindle container 710 can be constructed of any of several conventional commercially available materials, such as e.g. Oilfield Country Tubular Goods, stainless steel, titanium or strong steel. In a preferred embodiment, the expandable spindle container 710 is fabricated from materials of greater strength than the material from which the tubular portion 715 is fabricated. In this way, the container 710 can be fabricated from a tubular material having a thinner wall thickness than the tubular portion 210. This allows the container 710 to pass through tight clearances, thus facilitating its placement in the wellbore.

In a preferred embodiment, once the expansion process begins and the thicker, lower strength material in the tubular portion 715 is expanded, the outer diameter of the tubular portion 715 is greater than the outer diameter of the container 710.

The tubular member 715 is connected to and supported by the expandable spindle 705. The tubular member 715 is preferably expanded in the radial direction and extruded from the expandable spindle 715, substantially as described above with reference to Figures 1 to 6. The tubular member 715 may be fabricated from any of several materials, such as e.g. Oilfield Country Tubular Goods (OCTG), automotive-grade steel or plastic. In a preferred embodiment, the tubular portion 715 is fabricated from OCTG.

In a preferred embodiment, the tubular part 715 has a substantially annular cross-section. In a particularly preferred embodiment, the tubular part 715 has a substantially circular annular cross-section.

The tubular portion 715 preferably comprises an upper section 805, an intermediate section 810, and a lower section 815. The upper section 805 of the tubular portion 715 is preferably defined by the area beginning near the spindle container 710 and ending at the top section 820 of the tubular portion 715. The middle section 810 of the tubular portion 715 is preferably defined by the area that begins near the top of the spindle container 710 and ends at the area near the spindle 705. The lower section of the tubular portion 715 is preferably defined by the the area beginning near the spindle 705 and ending at the bottom 825 of the tubular portion 715.

In a preferred embodiment, the wall thickness of the upper section 805 of the pipe member 715 is greater than the wall thickness of the intermediate and lower sections 810 and 815 of the pipe member 715 to optimally facilitate the initiation of the extrusion process and to optimally allow the apparatus 700 to be placed in locations in the wellbore which have tight clearances.

The outer diameter and wall thickness of the upper section 805 of the tube part 715 can be e.g. ranging from 1.05 to 48 inches and 1/8 inch to 2 inches. In a preferred embodiment, the outer diameter and wall thickness of the upper section 805 of the pipe member 715 is in the range of about 3.5 to 16 inches and 3/8 inch to 1.5 inches.

The outer diameter of the wall thickness in the middle section 810 of the tube part 715 can e.g. range from about 2.5 to 50 inches and 1/16 inch to 1.5 inches. In a preferred embodiment, the outer diameter and wall thickness of the intermediate section 810 of the pipe member 715 is in the range of about 3.5 to 19 inches and 1/8 to 1.25 inches.

The outer diameter and wall thickness of the lower section 815 of the pipe part 715 can be in the range of e.g. about 2.5 to 50 inches and 1/16 to 1.25 inches.

In a preferred embodiment, the outer diameter and wall thickness of the lower section 810 of the tube portion 715 is in the range of about 3.5 to 19 inches and 1/8 to 1.25 inches. In a particularly preferred embodiment, the wall thickness of the lower section 815 of the tube part 715 is further increased to increase the strength of the shoe 720 when a drillable material, such as e.g. aluminum is used. The tubular part 715 preferably comprises a solid tubular part. In a preferred embodiment, the end portion 820 of the tubular portion 715 is slotted, perforated, or otherwise modified to capture or retard the spindle 705 as it completes the extrusion of the tubular portion 715. In a preferred embodiment, the length of the tubular portion 715 is limited to minimize the possibility of bulking. For typical materials of the section 715, the length of the pipe section 715 is preferably limited to be between about 40 to 20,000 feet in length.

The shoe 720 is connected to the expandable spindle 705 and the tubular part 715. The shoe 720 comprises the fluid passage 740. In a preferred embodiment, the shoe 720 further comprises an inlet passage 830 and one or more jet ports 835. In a particularly preferred embodiment, the cross-sectional shape of the inlet passage 830 is adapted to receive a locking arrow or other similar element, to block the inlet passage 830. The interior of the shoe 720 preferably comprises a body of a solid material 840 to increase the strength of the shoe 720.1 a particularly preferred embodiment, the body of solid material 840 consists of aluminum .

The shoe 720 may comprise any of several conventional, commercially available shoes, such as Super Seal II Down-Jet float shoe, or guide shoe with a sealing sleeve for a lock-down plug modified according to the information in the present description. In a preferred embodiment, the shoe 720 consists of an aluminum washdown guide shoe with a sealing sleeve for a lock-down plug, available from Halliburton Energy Services of Dallas, Texas, modified according to information in the following description, to optimize guidance of the tubular member 715 in the wellbore , optimizing the seal between the pipe member 715 and an existing wellbore casing, and optimally facilitating the removal of the shoe 720 by drilling it out after completion of the extrusion process.

The lower cup packing 725 is coupled to and supported by the support member 745. The lower cup packing 725 prevents foreign materials from entering the inner area of the tube portion 715 above the expandable spindle 705. The lower cup packing 725 may comprise any of several conventional and commercially available cup seals, such as TP cups or Selective Injection Packer (SlP) cups modified according to the information in the present description. In a preferred embodiment, the lower cup packing 725 consists of a SIP cup, available from Halliburton Energy Services of Dallas, Texas, to optimally provide a barrier against contamination and retain a body of lubricant.

The upper cup gasket 730 is connected to and supported by the support part 760. The upper cup gasket 730 prevents foreign materials from entering the inner area of the tube part 715. The upper cup gasket 730 may comprise any of several commercially available cup gaskets , such as e.g. TP cups or Selective Injection Packer (SlP) cups modified according to the information in the present description. In a preferred embodiment, the upper cup packing 730 consists of a SIP cup available from Halliburton Energy Services of Dallas, Texas, to optimally provide a barrier against contamination and to contain a body of lubricant.

The fluid passage 735 allows fluid materials to be transferred to and from the interior region of the tube portion 715 below the expandable spindle 705. The fluid passage 735 is fluidly coupled to the fluid passage 740. The fluid passage 735 is preferably coupled to and located within the support member 760, the support member 745, the spindle container 710, and the expandable spindle 705. The fluid passage 735 preferably extends from a position near the surface to the bottom of the expandable spindle 705. The fluid passage 735 is preferably located along the centerline of the apparatus 700. The fluid passage 735 is preferably selected to transport materials such as cement, drilling mud or epoxy with flow rates and pressures ranging from about 40 to 3,000 gallons per minute and 500 to 9,000 psi to optimally produce sufficient operating pressure to extrude the tubular portion 715 from the expandable spindle 705.

As described above with reference to Figures 1 through 6, during placement of the apparatus 700 within a new section of a wellbore, fluid materials forced up the fluid passage 735 may be released into the wellbore above the tubular portion 715. In a preferred embodiment, the device 700 further comprises a pressure release passage which is connected to and placed inside the support part 260. The pressure release passage is further in fluid connection with the fluid passages 735. The pressure release passage preferably comprises a control valve for controllable opening and closing of the fluid passage. In a preferred embodiment, the control valve is pressure activated to controllably minimize transient pressure. The pressure release passage is preferably located substantially orthogonal to the centerline of the apparatus 700. The pressure release passage is preferably selected to transport materials such as cement, drilling mud, and epoxy at flow rates and pressures in the range of about 0 to 500 gallons per minute and 0 to 1,000 psi, for to reduce drag on the apparatus 700 during insertion into a new section of borehole, and to minimize transient pressure on the new wellbore section.

The fluid passage 740 allows liquid materials to be transported to and from the area outside of the tubular portion 715. The fluid passage 740 is preferably connected to and located within the shoe 720 in fluid communication with the interior area of the tubular portion 715 below the expandable spindle 705. The fluid passage 740 preferably has a cross-sectional shape that allows a plug or other similar device to be placed in the inlet 830 of the fluid passage 740 to thereby block further passage of liquid materials. In this way, the inner area of the pipe part 715 below the expandable spindle 705 can be optimally fluid-isolated from the area outside the tubular part 715. This allows the inner area of the pipe part 715 below the expandable spindle 205 to be pressurized.

The fluid passage 740 is preferably located substantially along the centerline of the apparatus 700. The fluid passage 740 is preferably selected to transport materials such as cement, drilling mud or epoxy at flow rates and pressures in the ranges of 0 to 300 gallons per minute and 0 to 9,000 psi respectively for optimally filling an annular area between the pipe section 715 and a new section of a borehole with liquid materials. In a preferred embodiment, the fluid passage 740 comprises an inlet passage 830 having a geometry that can receive a dart and/or ball seal member. In this way, the fluid passage 240 can be closed by introducing a plug, arrow and/or ball sealing element in the fluid passage 230.

In a preferred embodiment, the apparatus 700 further comprises one or more gaskets 845 connected to and supported by the end portion 820 of the tubular portion 715. The gasket 845 is further placed on an outer surface of the end portion 820 of the tubular portion 715. The gasket 845 allows the overlapping joint between an end area of an existing casing and the end area 820 of the pipe part 715 is fluid sealed. The gasket 845 may comprise any of several conventional, commercially available gaskets such as e.g. lead, rubber, Teflon or epoxy gaskets modified according to information in the present description. In a preferred embodiment, the gasket 845 comprises gaskets cast from StrataLock epoxy available from Halliburton Energy Services of Dallas, Texas, to optimally produce a hydraulic seal and load-bearing interference fit in the overlapping joint between the tubular portion 715 and an existing casing, with optimal load-bearing capacity, to support the pipe section 715.

In a preferred embodiment, the gasket 845 is selected to produce a sufficient frictional force to support the expanded tubular portion 715 from the existing casing. In a preferred embodiment, the frictional force produced by the gasket 845 is in the range of about 1,000 to 1,000,000 pounds (454 to 454,000 kg) to optimally support the expanded tubular portion 715.

The support part 745 is preferably connected to the expandable spindle 705 and the overshoot connection 755. The support part 715 preferably comprises an annular part which has sufficient strength to carry the apparatus 700 into a new section of a wellbore. The support part 745 may comprise any of several conventional and commercially available support parts, such as e.g. steel drill pipe, coiled pipe or other high-strength pipe modified according to the information in the present invention. In a preferred embodiment, the support member 745 comprises conventional drill pipe available from various steel mills in the United States.

In a preferred embodiment, a body of lubricant 750 is arranged in the annular region above the expandable spindle container 710 inside the interior of the tubular part 715. In this way, extrusion of the tubular part 715 from the expandable spindle 705 is facilitated. The lubricant 705 may comprise any of several conventional and commercially available lubricants, such as e.g. Lubriplate, chlorine-based lubricants, oil-based lubricants, or Climax 1500 Antisieze (3100). In a preferred embodiment, the lubricant comprises 750 Climax 1500 Antisieze (3100), available from Halliburton Energy Services of Houston, Texas, to optimally provide lubrication to facilitate the extrusion process. The overhang connection 755 is connected to the support part 745 and the support part 760. The overhang connection 755 preferably allows the support part 745 to be removably connected to the support part 760. The overhang connection 755 may comprise any of several conventional and commercially available overhang connections, such as e.g. Innerstring Sealing Adapter, Innerstring Flat-Face Sealing Adapter or EZ Drill Setting Tool Stinger. In a preferred embodiment, the overshoot connector 755 comprises an Innerstring Adapter with an Upper Guide, available from Halliburton Energy Services of Dallas, Texas.

The support portion 760 is preferably connected to the overshoot connection 755 and a surface support structure (not illustrated). The support part 760 preferably comprises an annular part which has sufficient strength to carry the apparatus 700 into a new section of a wellbore. The support part 760 may comprise any of several conventional and commercially available support parts, such as e.g. steel drill pipe, coiled pipe or other high-strength pipe, modified according to information in the present description. In a preferred embodiment, the support member 760 comprises a conventional drill pipe available from steel mills in the United States.

The stabilizer 765 is preferably connected to the support part 760. The stabilizer 765 also preferably stabilizes the components of the apparatus 700 inside the pipe part 715. The stabilizer 765 preferably comprises a spherical part which has an outer diameter of about 80 to 99% of the inner diameter of the pipe part 715 for optimum to minimize buckling of the tubular portion 715. The stabilizer 765 may comprise any of several conventional and commercially available stabilizers such as e.g. EZ Drill Star Guides, packing shoes or drag blocks modified according to information in this description. In a preferred embodiment, the stabilizer 765 includes a seal adapter upper guide, available from Halliburton Energy Services of Dallas, Texas.

In a preferred embodiment, the support parts 745 and 760 are thoroughly cleaned before assembly with the remaining parts of the apparatus 700. In this way, the introduction of foreign materials into the apparatus 700 is minimized. This minimizes the possibility of foreign materials clogging the various flow passages and valves in the apparatus 700.

In a preferred embodiment, before or after placing the apparatus 700 in a new section of a wellbore, a pair of wellbore volumes are circulated through the various flow passages in the apparatus 700 to ensure that no foreign materials are in the wellbore that could clog the various flow passages and valves of the apparatus 700, and to ensure that no foreign materials interfere with the expansion spindle 705 during the expansion process.

In a preferred embodiment, apparatus 700 is operated substantially as described above with reference to Figures 1 through 7 to form a new section of casing within a wellbore.

As illustrated in Figure 8, in an alternative preferred embodiment, the method and apparatus as described herein is used to repair an existing wellbore casing 805 by forming a tubular liner 810 within the existing wellbore casing 805.1 a preferred embodiment, it no outer annular lining of cement was provided in the repaired section. In the alternative preferred embodiment, any of several materials may be used to expand the tubular casing 810 into close contact with the damaged section of the wellbore casing, such as cement, epoxy, slag mixture or drilling mud. In the alternative preferred embodiment, sealing parts 815 are preferably arranged on both ends of the pipe part to optimally produce a fluid seal. In an alternative preferred embodiment, the tubular liner 810 is formed within a horizontally positioned pipeline section, such as those used to transport hydrocarbons or water, with the liner 810 positioned in an overlapping relationship with the adjacent pipeline section. In this way, underground pipelines can be repaired without having to dig out and replace the damaged sections.

In another alternative preferred embodiment, the method and apparatus as described herein is used for directly lining a wellbore with a tubular casing 810. In a preferred embodiment, no annular outer lining of cement is arranged between the casing 810 and the wellbore. In the alternative preferred embodiment, any of several liquid materials may be used to expand the tubular liner 810 into close contact with the wellbore, such as cement, epoxy, slag mixture or drilling mud.

Reference is now made to Figures 9, 9a, 9b and 9c, where a preferred embodiment of the apparatus 900 for forming a wellbore casing comprises an expandable tubular member 902, a support member 904, an expandable spindle or spike 906, and a shoe 908. in a preferred embodiment, the design and construction of the spindle 906 and shoe 908 will permit easy removal of these elements by drilling them out. In this way, the unit 900 can be easily removed from a wellbore using conventional drilling equipment and corresponding drilling methods.

The expandable tubular portion 902 preferably comprises an upper portion 910, a middle portion 912, and a lower portion 914. During operation of the apparatus 900, the tubular portion 902 is preferably extruded from the spindle 906 by placing an inner region 966 of the tubular portion 902 under Print. The tubular part 902 preferably has a substantially annular cross-section.

In a particularly preferred embodiment, an expandable tubular portion 915 is coupled to the upper portion 910 of the expandable tubular portion 902. During operation of the apparatus 900, the tubular portion 915 is preferably extruded from the spindle 906 by placing the inner region 966 of the tubular portion 902 under pressure. The tubular part 915 preferably has an essentially ring-shaped cross-section. In a preferred embodiment, the wall thickness of the tubular part 915 is greater than the wall thickness of the tubular part 902.

The tubular member 915 may be fabricated from any of several conventional and commercially available materials, such as e.g. oil field pipe, low alloy steel, titanium or stainless steel. In a preferred embodiment, the tubular portion 915 is fabricated from oilfield tubing to optimally produce approximately the same mechanical properties as the tubular portion 902. In a particularly preferred embodiment, the tubular portion 915 has a classical breaking strength that is in the range of 40,000 to 135,000 psi, for optimally to produce approximately the same breaking strength properties as the pipe part 902. The tubular part 915 can comprise several pipe parts connected end to end.

In a preferred embodiment, the upper end part of the pipe part 915 comprises one or more sealing parts to optimally produce a fluid and/or gas seal with the existing section of a wellbore casing.

In a preferred embodiment, the combined length of pipe members 902 and 915 is limited to minimize the possibility of bulking. For typical pipe member materials, the combined length of pipe members 902 and 915 is limited to between about 40 to 20,000 feet in length.

The lower part 914 of the pipe part 902 is preferably connected to the shoe 908 with a threaded connection 968. The middle part 912 of the pipe part 902 is preferably placed in close sliding contact with the spindle 906.

The tube portion 902 can be fabricated from any of several conventional and commercially available materials such as, for example, oil field pipe, low alloy steel, titanium or stainless steel. In a preferred embodiment, the pipe part 902 is fabricated from oil field pipe to optimally produce approximately the same mechanical properties as the pipe part 915. In a particularly preferred embodiment, the pipe part 902 has a plastic breaking strength that lies in the range from about 40,000 to 135,000 psi to optimally produce approximately the same breaking strength characteristics as the pipe part 915.

The wall thicknesses of the upper, intermediate and lower parts 910, 912 and 914 of the pipe part 902 can e.g. range from about 1/16 inch to 1.5 inch. In a preferred embodiment, the wall thicknesses of the upper, intermediate, and lower portions 910, 912, and 914 of the tubular portion 912 range from about 1/8 inch to 1.25 inch to optimally produce wall thicknesses that are approximately the same as the tubular portion. 915. In a preferred embodiment, the wall thicknesses of the lower portion 914 are less than or equal to the wall thickness of the upper portion 910 to optimally produce a geometry that will fit into tight clearances down the borehole.

The outer diameter of the upper, intermediate and lower parts 910, 912 and 914 of the tube part 902 can lie in the range, e.g. from about 1.05 to 48 inches. In a preferred embodiment, the outer diameter of the upper, intermediate, and lower portions 910, 912, and 914 of the tubing portion 902 ranges from about 3.5 to 19 inches to optimally provide the ability to expand the most commonly used oil field tubing.

The length of the tube portion 902 is preferably limited to between about 2 to 5 feet to optimally provide sufficient length to contain the spindle 906 and a body of lubricant.

The pipe part 902 may comprise any of several conventional and commercially available pipe parts modified according to the information in the present description. In a preferred embodiment, the tubular portion comprises 902 Oilfield Country Tubular Goods, available from various steel mills in the United States. The pipe part 915 may comprise any of several conventional commercially available pipe parts modified according to information in the present description. In a preferred embodiment, the tubular portion comprises 915 Oilfield Country Tubular Goods available from various steel mills in the United States.

The various elements of the pipe section 902 can be connected using any of several conventional processes such as e.g. threaded connections, welding or machining from one piece. In a preferred embodiment, the different elements of the pipe part 902 are connected using welding. The pipe part 902 can comprise several pipe elements which are connected end to end. The various elements of the pipe section 915 may be connected using any of several conventional processes, such as e.g. threaded connections, welding or machining from one piece. In a preferred embodiment, the different elements of the pipe part 915 are connected using welding. The pipe part 915 can comprise several pipe elements which are connected end to end. The pipe members 902 and 915 may be joined using any of several conventional processes, such as, for example, threaded connections, welding or machining a piece.

The support part 904 preferably comprises an inner string adapter 916, a fluid passage 918, an upper guide 920, and a coupling 922. During operation of the apparatus 900, the support part 904 will preferably support the apparatus 900 during movement of the apparatus 900 inside a wellbore. The support part 904 preferably has an essentially ring-shaped cross-section.

The support member 904 may be fabricated from any of several conventional and commercially available materials, such as e.g. oil field pipes, low alloy steel, coiled pipes or stainless steel. In a preferred embodiment, the support part 904 is fabricated from low alloy steel to optimally produce high breaking strength.

The inner string adapter 916 is preferably connected to and supported by a conventional drill string support from a surface location. The inner string adapter 916 may be coupled to a conventional drill string support 971 by a threaded connection 970.

The fluid passage 918 is preferably used to transport fluids or other materials to and from the apparatus 900. In a preferred embodiment, the fluid passage 918 is fluidly coupled to the fluid passage 952. In a preferred embodiment, the fluid passage 918 is used to transport curable liquid sealing elements to and from the apparatus 900.1 a particularly preferred embodiment, the fluid passage 918 may include one or more pressure release passages (not illustrated) to release fluid pressure during positioning of the apparatus 900 within a wellbore. In a preferred embodiment, the fluid passage 918 is located along a longitudinal centerline of the apparatus 900. In a preferred embodiment, the fluid passage 918 is selected to allow transport of curable fluid materials at operating pressures in the range of about 0 to 90,000 psi.

The upper guide 920 is connected to an upper part of the support part 904. The upper guide 920 is preferably adapted to center the support part 904 inside the pipe part 915. The upper guide 920 may comprise any of several conventional guide parts, modified according to information in the present description. In a preferred embodiment, the upper guide 920 includes an inner string adapter available from Halliburton Energy Services of Dallas, Texas to optimize the routing of the apparatus 900 within the pipe section 915.

The coupling 922 connects the support part 904 to the spindle 906. The coupling 922 preferably comprises a conventional threaded connection.

The various elements of the support part 904 can be connected using several conventional processes, such as e.g. welding, threaded connections or machining from one piece. In a preferred embodiment, the various elements of the support part 904 are connected using threaded connections.

The spindle 906 preferably comprises a holder 924, a rubber cup 926, an expansion cone 928, a lower cone holder 930, a body of cement 932, a lower guide 934, an extension sleeve 936, a spacer 938, a housing 940, a sealing sleeve 942, an upper cone holder 944, a lubrication spindle 946, a lubrication sleeve 948, a guide 950, and a fluid passage 952.

The holder 924 is connected to the lubrication spindle 946, the lubrication sleeve 948, and the rubber cup 926. The holder 924 connects the rubber cup 926 to the lubrication sleeve 948. The holder 924 preferably has an essentially annular cross-section. The holder 924 may comprise any of several conventional commercially available holders, such as e.g. slotted spring pins or roller pins.

The rubber cup 926 is connected to the holder 924, the lubrication spindle 946 and the lubrication sleeve 948. The rubber cup 926 prevents the entry of foreign materials into the inner area 972 of the tube portion 902 below the rubber cup 926. The rubber cup 926 may comprise any of several conventional, commercially available rubber cups, such as e.g. TP cups or Selective Injection Packer (SlP) cups. In a preferred embodiment, the rubber cup 926 comprises a SIP cup available from Halliburton Energy Services of Dallas, Texas, to optimally block foreign materials.

In a particularly preferred embodiment, a body of lubricant is further provided in the inner region 972 of the tube part 902 to lubricate the interface between the outer surface of the spindle 902 and the inner surface of the tube parts 902 and 915. Lubricants can include any of several conventional and commercially available lubricants such as e.g. Lubriplate, chlorine-based lubricants, oil-based lubricants or Climax 1500 Antisieze (3100). In a preferred embodiment, the lubricant comprises Climax 1500 Antisieze (3100) available from Climax Lubricants and Equipment Co. in Houston, Texas, to optimally provide lubrication to facilitate the extrusion process.

The expansion cone 928 is connected to the lower cone holder 930, the body of cement 932, the lower guide 934, the extension sleeve 936, the housing 940 and the upper cone holder 944. In a preferred embodiment, during operation of the apparatus 900, the pipe members 902 and 915 are extruded from the outer surface of the expansion cone 928.1 a preferred embodiment, axial movement of the expansion cone 928 is prevented by a lower cone holder 930, the housing 940 and the upper cone holder 944. Inward radial movement of the expansion cone 928 is prevented by the body of cement 932, the housing 940 and the upper cone holder 944.

The expansion cone 928 preferably has an essentially ring-shaped cross-section. The outer diameter of the expansion cone 928 is preferably tapered to form a conformal shape. The wall thickness of the expansion cone 928 can be in the range from e.g. 0.125 to 3 inches. In a preferred embodiment, the wall thickness of the expansion cone is in the range of about 0.25 to 0.75 inches to optimally produce sufficient compressive strength with a minimum of materials. The maximum and minimum outside diameter of the expansion cone 928 can be in the range from e.g. about 1 to 47 inches. In a preferred embodiment, the maximum and minimum outer diameters of the expansion cone 928 range from about 3.5 to 19 inches to optimally produce expansion of generally available oilfield tubing.

The expansion cone 928 can be fabricated from any of several conventional, commercially available materials such as, for example, ceramic, tool steel, titanium or low alloy steel. In a preferred embodiment, the expansion cone 928 is fabricated from tool steel to optimally produce high strength and aberration resistance. The surface hardness of the outer surface of the expansion cone 928 can e.g. be in the range of about 50 Rockwell C to 70 Rockwell C. In a preferred embodiment, the surface hardness of the outer surface of the expansion cone 928 is in the range of about 58 Rockwell C to 62 Rockwell C to optimally produce high breaking strength. In a preferred embodiment, the expansion cone 928 is heat treated to optimally produce a hard outer surface and an elastic inner body to optimally produce aberration resistance and fracture toughness.

The lower cone holder 930 is connected to the expansion cone 928 and the housing 940. In a preferred embodiment, movement of the expansion cone 928 is prevented by a lower cone holder 930. The lower cone holder 930 preferably has an essentially annular cross-section.

The lower cone holder 930 can be fabricated from any of several conventional, commercially available materials such as e.g. ceramic, tool steel, titanium or low alloy steel. In a preferred embodiment, the lower cone holder 930 is fabricated from tool steel to optimally produce high strength and aberration resistance. The surface hardness of the outer surface of the lower cone holder 930 can e.g. be in the range of about 50 Rockwell C to 70 Rockwell C. In a preferred embodiment, the surface hardness of the outer surface of the lower cone holder 930 is in the range of about 58 Rockwell C to 62 Rockwell C to optimally produce high breaking strength. In a preferred embodiment, the lower cone holder 930 is heat treated to optimally produce a hard outer surface and an elastic inner body to optimally produce aberration resistance and fracture toughness.

In a preferred embodiment, the lower cone holder 930 and the expansion cone

928 designed as a unitary element in one piece to reduce the number of components and to increase the overall strength of the device. The outer surface of the lower cone holder 930 is preferably adapted to an inner surface of the pipe part 902 and 915.

The cement body 932 is placed inside the interior of the spindle 906. The cement body 932 provides an internal supporting structure for the spindle 906. The cement body 932 can also be easily drilled out using a conventional drilling device. In this way, the spindle 906 can be easily removed using a conventional drilling device.

The body of cement 932 may comprise any of several conventional and commercially available cement compositions. Alternatively, aluminium, cast iron and other drillable metallic, composite or mixed materials may be used in place of cement. The body of cement 932 preferably has an essentially ring-shaped cross-section. The lower guide 934 is coupled to the extension sleeve 936 and housing 940. During operation of the apparatus 900, the lower guide 934 will preferably assist in guiding the movement of the spindle 906 within the tubular portion 902. The lower guide 934 preferably has a substantially annular cross section.

The lower guide 934 can be fabricated from any of several conventional, commercially available materials, such as e.g. oil field pipe, low alloy steel or stainless steel. In a preferred embodiment, the lower guide 934 is fabricated from low alloy steel to optimally produce high breaking strength. The outer surface of the lower guide 934 is preferably matched with an inner surface of the pipe member 902 to form a sliding fit.

The extension sleeve 936 is connected to a lower guide 934 on the housing 940. During operation of the apparatus 900, the extension sleeve 936 will preferably help to guide the movement of the spindle 906 inside the tube part 902. The extension sleeve 936 preferably has a substantially annular cross-section.

The extension sleeve 936 may be fabricated from any of several conventional and commercially available materials, such as, for example, oil field pipe, low alloy steel or stainless steel. In a preferred embodiment, the extension sleeve 936 is fabricated from low alloy steel to optimally produce high breaking strength. The outer surface of the extension sleeve 936 is preferably matched with an inner surface of the pipe member 902 to form a sliding fit. In a preferred embodiment, the extension sleeve 936 and the lower guide 934 are formed as a unitary one-piece element to minimize the number of components and to increase the strength of the apparatus.

The spacer 938 is coupled to the sealing sleeve 942. The spacer 938 preferably includes a fluid passage 952, and is aligned with and mates with the extension tube 960 in the shoe 908. In this way, a plug or dart can be transferred from the surface through the fluid passages 918 and 952 into the fluid passage. 962. The spacer 938 preferably has an essentially ring-shaped cross-section.

Spacer 938 may be fabricated from any of several conventional, commercially available materials, such as, for example, steel, aluminum or cast iron. In a preferred embodiment, the spacer 938 is fabricated from aluminum to optimally provide drillability. The end of the spacer 938 is preferably matched with the end of the extension tube 960. In a preferred embodiment, the spacer 938 and the sealing sleeve 942 are formed as a single element in one piece to reduce the number of components and to increase the strength of the apparatus.

The housing 940 is coupled to the lower guide 934, the extension sleeve 946, the expansion cone 928, the cement body 932, and the lower cone holder 930. During operation of the apparatus 900, the housing 940 will preferably prevent radial movement of the expansion cone 928. The housing 940 preferably has a substantially annular cross section.

The housing 940 can be fabricated from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel or stainless steel. In a preferred embodiment, housing 940 is fabricated from low alloy steel to optimally produce high breaking strength. In a preferred embodiment, the lower guide 934, the extension sleeve 936 and the housing 940 are formed as a unitary element in one piece, to minimize the number of components and to increase the strength of the apparatus.

In a particularly preferred embodiment, the inner surface of the housing 940 comprises one or more protrusions to facilitate the connection between the housing 940 and the cement body 932.

The sealing sleeve 942 is connected to the support part 904, the cement body 932, the spacer 938, and the upper cone holder 944. During operation of the apparatus, the sealing sleeve 942 will preferably provide support for the spindle 906. The sealing sleeve 942 is preferably connected to the support part 904 using the coupling 922. The sealing sleeve 942 preferably has an essentially ring-shaped cross-section.

The sealing sleeve 942 can be made from any of several conventional, commercially available materials, such as e.g. steel, aluminum or cast iron. In a preferred embodiment, the sealing sleeve 942 is fabricated from aluminum to optimally produce drillability of the sealing sleeve 942.

In a particularly preferred embodiment, the outer surface of the sealing sleeve 942 comprises one or more protrusions to facilitate the connection between the sealing sleeve 942 and the cement body 932.

In a particularly preferred embodiment, spacer 938 and seal sleeve 942 are integrally formed as a one-piece element to minimize the number of components.

The upper cone holder 944 is connected to the expansion cone 928, the sealing sleeve 942 and the cement body 932. During operation of the apparatus 900, the upper cone holder 944 will preferably prevent axial movement of the expansion cone 928. The upper cone holder 944 preferably has an essentially annular cross-section.

The upper cone holder 944 can be made of any of several conventional and commercially available materials, such as, for example, steel, aluminum or cast iron. In a preferred embodiment, the upper cone holder 944 is fabricated from aluminum to optimally produce drillability of the upper cone holder 944.

In a particularly preferred embodiment, the upper cone holder 944 has a cross-sectional shape designed to provide increased rigidity. In a particularly preferred embodiment, the upper cone holder 944 has a cross-sectional shape that is substantially l-shaped to provide increased rigidity and to minimize the amount of material that would have to be drilled out.

Lubricating spindle 946 is coupled to holder 924, rubber cup 926, upper cone holder 944, lubrication sleeve 948, and guide 950. During operation of apparatus 900, lubricating spindle 946 preferably contains the body of lubricant in annular region 972 to lubricate the interface between spindle 906 and the tubular part 902. The lubrication spindle 946 preferably has an essentially annular cross-section.

The lubricator spindle 946 can be made of any of several conventional, commercially available materials such as, for example, steel, aluminum or cast iron. In a preferred embodiment, the lubrication spindle 946 is fabricated from aluminum to optimally provide drillability to the lubrication spindle 946.

The lubrication sleeve 948 is connected to the lubrication spindle 946, the holder 924, the rubber cup 926, the upper cone holder 944, the lubrication sleeve 948, and the guide 950. During operation of the apparatus 900, the lubrication sleeve 948 will preferably support the rubber cup 926. The lubrication sleeve 948 preferably has a substantially annular cross-section.

The grease sleeve 948 can be made of any conventional, commercial material, such as e.g. steel, aluminum or cast iron. In a preferred embodiment, the lubrication sleeve 948 is fabricated from aluminum to optimally provide drillability to the lubrication sleeve 948.

As illustrated in Figure 9c, the lubrication sleeve 948 is supported by the lubrication spindle 946. The lubrication sleeve 948 in turn supports the rubber cup 926. The holder 924 connects the rubber cup 926 to the lubrication sleeve 948. In a preferred embodiment, seals 949a and 949b are arranged between the lubrication spindle 946, the lubrication sleeve 948 and the rubber cup 926 to optimally seal the inner area 972 of the tube part 902.

The guide 950 is connected to the lubrication spindle 946, the holder 924, and the lubrication sleeve 948. During operation of the device 900, the guide 950 will preferably guide the device on the support part 904. The guide 950 preferably has an essentially annular cross-section.

The guide 950 can be made from any of several conventional, commercially available materials, such as, for example, steel, aluminum or cast iron. In a preferred embodiment, the guide 950 is fabricated from aluminum to optimally produce drillability in the guide 950.

The fluid passage 952 is coupled to the spindle 906. During operation of the apparatus, the fluid passage 952 will preferably conduct curable liquid materials. In a preferred embodiment, the fluid passage 952 is located about the centerline of the apparatus 900. In a particularly preferred embodiment, the fluid passage 952 is adapted to conduct curable liquid materials at pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3 000 gallons per minute to optimally generate pressures and flow rates to displace and circulate fluids during installation of the apparatus 900.

The various elements of the spindle 906 can be connected using several conventional processes, such as e.g. threaded connections, welded connections or cementing. In a preferred embodiment, the various elements of spindle 906 are connected using threaded connections and cementation.

The shoe 908 preferably comprises a housing 954, a body of cement 956, a sealing sleeve 958, an extension tube 960, a fluid passage 962 and one or more exit nozzles 964.

The housing 954 is coupled to the body of cement 956 and the lower portion 914 of the tubular member 902. During operation of the apparatus 900, the housing 954 will preferably couple the lower portion of the tubular member 902 to the shoe 908 to facilitate extrusion and positioning of the tubular member 902. The housing 954 preferably has an essentially ring-shaped cross-section.

The housing 954 can be made from any of several commercially available materials, such as e.g. steel or aluminium. In a preferred embodiment, the housing 954 is fabricated from aluminum to optimally produce drillability of the housing 954.

In a particularly preferred embodiment, the inner surface of the housing 954 comprises one or more protrusions to facilitate the connection between the body of cement 956 and the housing 954.

The body of cement 956 is coupled to the housing 954, and the sealing sleeve 958.1 In a preferred embodiment, the composition of the body of cement is chosen to allow the body of cement to be easily drilled out using conventional drilling machines and processes.

The composition of the cement body 956 may comprise any of several conventional cement compositions. In an alternative embodiment, a drillable material such as e.g. aluminum or iron is used to replace the cement body 956.

The sealing sleeve 958 is coupled to the cement body 956, the extension tube 960, the fluid passage 962 and one or more outlet nozzles 964. During operation of the apparatus 900, the sealing sleeve 958 is preferably adapted to direct a curable liquid material from the fluid passage 952 into the fluid passage 962 and then into the outlet nozzles 964 to inject the curable liquid material into an annular area outside the tube portion 902.1 a preferred embodiment, during operation of the apparatus 900, the sealing sleeve 958 further comprises an inlet geometry that allows a conventional plug or dart 974 to be inserted into the inlet of the sealing sleeve 958. In this way, the fluid passage 962 can be blocked and thus fluid-isolate the inner region 966 of the tube part 902.

In a preferred embodiment, the sealing sleeve 958 has a substantially annular cross-section. The sealing sleeve 958 can be made from any of several conventional, commercially available materials, such as, for example, steel, aluminum or cast iron. In a preferred embodiment, the sealing sleeve 958 is made of aluminum to optimally provide drillability to the sealing sleeve 958.

The extension tube 960 is connected to the sealing sleeve 958, the fluid passage 962, and one or more outlet nozzles 964. During operation of the apparatus 900, the extension tube 960 is preferably adapted to direct a curable liquid material from the fluid passage 952 into the fluid passage 962 and then to the outlet nozzles 964 to inject the curable liquid material into an annular area outside the tube portion 902.1 a preferred embodiment, during operation of the apparatus 900, the sealing sleeve 960 further comprises an inlet geometry that allows a conventional plug or arrow 974 to be inserted into the inlet of the sealing sleeve 958. In this way, the fluid passage 962 is blocked so that it fluidly isolates the inner area 966 of the tube part 902.

In a preferred embodiment, one end of the extension tube 950 is matched with one end of the spacer 938 to optimally facilitate the transfer of materials between the two.

In a preferred embodiment, the extension tube 960 has a substantially annular cross-section. The extension tube 960 can be made from any of several conventional and commercially available materials, such as, for example, steel, aluminum or cast iron. In a preferred embodiment, the extension tube 960 is fabricated from aluminum to optimally provide drillability to the extension tube 960.

The fluid passage 962 is connected to the sealing sleeve 958, the extension tube 960, and one or more exit nozzles 964. During operation of the apparatus 900, the fluid passage 962 will preferentially conduct curable liquid materials. In a preferred embodiment, the fluid passage 962 is located about the centerline of the apparatus 900. In a particularly preferred embodiment, the fluid passage 962 is adapted to conduct curable liquid materials at pressures and flow rates in the range of from about 0 to 9,000 psi and from 0 to 3,000 gallons per minute to optimally produce fluids in operationally effective quantities.

The exit nozzles 964 are connected to the sealing sleeve 958, the extension tube 960 and the fluid passage 962. During operation of the apparatus 900, the exit nozzles 964 will preferably direct curable liquid materials from the fluid passage 962 to the area outside the apparatus 900. In a preferred embodiment, the shoe 908 comprises several exit nozzles 964.

In a preferred embodiment, the exit nozzles 964 include passages carried in the housing 954 and the cement body 956 to simplify the construction of the apparatus 900.

The various elements of the shoe 908 may be connected using any of several conventional processes, such as threaded connections, cementing or machining a piece of material. In a preferred embodiment, the various elements of the shoe 908 are connected using cement.

In a preferred embodiment, the unit 900 is operated substantially as described above with reference to Figures 1 through 8 to create a new section of casing in a wellbore or to repair a wellbore casing or pipeline.

In particular, to extend a wellbore into an underground formation, a drill string is used in a known manner to drill out material from the underground formation to form a new section.

The apparatus 900 for forming a wellbore casing in a subterranean formation is then placed in the new section of the wellbore. In a particularly preferred embodiment, the apparatus 900 comprises the tubular portion 915. In a preferred embodiment, a curable liquid sealing material is pumped from a location on the surface into the fluid passage 918. The curable liquid sealing material then passes from the fluid passage 918 into the interior region 966 of the tube part 902 below the spindle 906. The curable liquid sealing material then passes from the inner region 966 into the fluid passage 962. The curable liquid sealing material then exits the apparatus 900 via the exit nozzles 964 and fills an annular area between the outside of the tubular part 902 and the inner wall of the new section of the borehole. Continued pumping of the curable liquid material causes the material to fill up at least a portion of the annular region.

The curable liquid sealing material is preferably pumped into the annular area at pressures and flow rates that are in the area, e.g. from about 0 to 500 psi and 0 to 1500 gallons per minute. In a preferred embodiment, the curable liquid sealing material is pumped into the annular region at pressures and flow rates designed for the specific wellbore section to optimize displacement of the curable liquid sealing material without creating circulating pressures high enough that circulation may be lost and this could cause the wellbore to collapse. The optimum pressure and flow rates are preferably determined using conventional empirical methods.

The curable liquid sealant may comprise any of several conventional and commercially available curable liquid sealants, such as slag mixture, cement or epoxy. In a preferred embodiment, the curable liquid sealing material comprises blended cement designed specifically for the well section being lined, available from Halliburton Energy Services of Dallas, Texas to optimally provide support for the new pipe section while maintaining optimal flow characteristics to minimize operational difficulties during displacement of the cement in the annulus. The optimum composition of the mixed cement is preferably determined using conventional empirical methods.

The annulus is preferably filled with the curable liquid sealing material in sufficient quantities to ensure that, after radial expansion of the tubular portion 902, the annulus in the new section of the wellbore will be filled with the curable material.

As soon as the annular region is sufficiently filled with curable liquid sealing material, a plug or dart 974 or other similar device is preferably inserted into the fluid passage 962 to thereby fluid-isolate the inner region 966 of the tube portion 902 from the outer annulus. In a preferred embodiment, a non-curable liquid material is then pumped into the inner region 966 to pressurize the inner region 966. In a particularly preferred embodiment, the plug or dart 974, or similar device, is preferably introduced into the fluid passage 962 by inserting the plug or dart 974 or other similar device into the non-curable fluid material. In this way, the amount of hardened material in the interior of the tube part 902 and 915 is minimized.

As soon as the inner region 966 comes under sufficient pressure, the annular members 902 and 915 are extruded from the spindle 906. The spindle 906 may be fixed, or it may be expandable. During the extrusion process, the spindle 906 is raised out of the expanded portion of the tube portion 902 and 915 using the support portion 904. During this extrusion process, the shoe 908 is preferably substantially stationary.

The plug or dart 974 is preferably placed in the fluid passage 962 by inserting the plug or dart 974 into the fluid passage 918 at a location on the surface, in a conventional manner. The plug or arrow 974 may comprise any of several conventional and commercially available devices for plugging a fluid passage, such as, e.g. Multiple Stage Cementer (MSC) lock-down plug, Omega lock-down plug or three-scraper lock-down plug, modified according to the information in this specification. In a preferred embodiment, the plug or arrow 974 comprises an MSC lockout plug, available from Halliburton Energy Services of Dallas, Texas.

After placement of the plug or arrow 974 in the fluid passage 962, the non-curable liquid material is preferably pumped into the interior region 966 at pressures and flow rates in the range of about 500 to 9,000 psi and 40 to 3,000 gallons per minute to optimally to extrude the tubular members 902 and 915 from the spindle 906.

For typical pipe members 902 and 915, the extrusion of pipe members 902 and 915 from the expandable mandrel will begin when the pressure in the inner region 966 reaches about 500 to 9,000 psi. In a preferred embodiment, the extrusion of the pipe members 902 and 915 from the spindle 906 begins when the pressure in the inner region 966 reaches about 1,200 to 8,500 psi with a flow rate of about 40 to 1,250 gallons per minute.

During the extrusion process, the spindle 906 may be lifted out of the expanded regions of the tube members 902 and 915 by amounts in the range of e.g. from 0 to 5 feet per second. In a preferred embodiment, during the extrusion process, the mandrel 906 is raised out of the expanded regions of the tube members 902 and 915 at rates in the range of about 0 to 2 feet per second to optimally produce draw speeds sufficiently fast to permit efficient operation and allow full expansion of the pipe members 902 and 915 prior to curing of the curable liquid sealing materials, but not so rapidly that a suitable adjustment of the operating parameters during the operation is impeded.

When the upper end portion of the pipe portion 915 is extruded by the spindle 906, the outer surface of the upper end portion of the pipe portion 915 will preferably contact the inner surface of the lower end portion of the existing casing to form a fluid tight overlap joint. The contact pressure in the overlapping joint can be in the range from e.g. 50 to 20,000 psi. In a preferred embodiment, the contact pressure in the overlapped joint between the upper end of the tubing portion 915 and the existing section of wellbore casing will be in the range of 400 to 10,000 psi to optimally produce contact pressure to activate the sealing members and to produce optimal resistance so that the pipe section 915 and the existing wellbore casing will carry typical tension and compression loads.

In a preferred embodiment, the operating pressure and flow rate of the non-curable liquid material will be controllably ramped down when the spindle 906 reaches the upper end region of the pipe member 915. In this way, a sudden release of pressure caused by the completed extrusion of the pipe member 915 from the expandable spindle 906 be minimized. In a preferred embodiment, the operating pressure is reduced in a substantially linear manner from 100% to about 10% during the end of the extrusion process, which begins when the spindle 906 has completed approximately all but the last 5 feet of the extrusion process.

In an alternative preferred embodiment, the operating pressure and/or flow rate of the curable liquid sealant and/or the non-curable liquid material is controlled during all phases of operation of the apparatus 900 to minimize shock.

Alternatively, or in combination, a shock absorber is provided in the support portion 904 to absorb the shocks caused by sudden release of pressure.

Alternatively, or in combination, a spindle capture structure is provided above the support member 904 to capture or at least decelerate the spindle 906.

Once the extrusion process is complete, the spindle 906 is removed from the wellbore. In a preferred embodiment, either before or after removal of the spindle 906, the integrity of the fluid seal of the overlapped joint between the upper portion of the tubing portion 915 and the lower portion of the existing casing is tested using conventional methods. If the fluid seal of the overlapping joint between the upper regions of the pipe section 915 and the lower portion of the existing casing is satisfactory, the uncured portion of the curable liquid sealing material inside the expanded pipe section 915 is removed in a conventional manner. The curable liquid sealing material inside the annulus between the expanded pipe section 915 and the existing casing on the new section of the wellbore is then allowed to cure.

Residual hardened curable liquid sealing material in the interior of the expanded pipe members 902 and 915 is then preferably removed in a conventional manner using a conventional drill string. The resulting new section of casing preferably comprises the expanded pipe sections 902 and 915 and an outer annular layer of hardened curable liquid sealing material. The bottom portion of the apparatus 900 including the shoe 908 can then be removed by drilling out the shoe 908 using conventional drilling methods.

In an alternative embodiment, during the extrusion process, it may be necessary to remove the entire apparatus 900 from the interior of the wellbore due to a malfunction. Under this condition, a conventional drill string is used to drill out the inner sections of the apparatus 900 to facilitate the removal of the remaining sections. In a preferred embodiment, the internal elements of the apparatus 900 are fabricated from material such as e.g. cement and aluminium, which allows the use of a conventional drill string to drill out the internal components.

Specifically, in a preferred embodiment, the composition of the inner sections of the spindle 906 and the shoe 908 includes one or more of the cement body 932, the spacer 938, the sealing sleeve 942, the upper cone holder 944, the lubrication spindle 946, the lubrication sleeve 948, the guide 950, the housing 954, the cement body 965, the sealing sleeve 958 and the extension tube 960, selected to allow at least some of these components to be drilled out using conventional drilling methods and apparatus. In this way, in the event of a downhole malfunction, the apparatus 900 can be easily removed from the wellbore.

With reference to figures 10a, 10b, 10c, 10d, 10e, 10f and 10g, a method and an apparatus for creating a platform liner in a wellbore will now be described. As illustrated in Figure 10a, a wellbore 1000 placed in an underground formation 1002 comprises a first casing 1004 and a second casing 1006.

The first casing 1004 preferably comprises a tubular casing 1008 and a cement annulus 1010. The second casing 1006 preferably comprises a tubular casing 1012 and a cement annulus 1014. In a preferred embodiment, the second casing 1006 is formed by expanding a tubular part, essentially as described above with reference to figures 1 to 9c or below with reference to figures 1 la to 1 lf.

In a particularly preferred embodiment, the upper part of the pipe liner 1012 will overlap with the lower part of the pipe liner 1008. In a particularly preferred embodiment, the outer surface of the upper part of the pipe liner 1012 comprises one or more sealing parts 1016 to provide a fluid seal between the pipe liners 1008 and 1012.

Reference is now made to figure 10b. To create a platform casing extending from the lap joint between the first and second casings, 1004 and 1006, an apparatus 1100 is provided which comprises an expandable mandrel or spike 1105, a tubular member 1110, a shoe 1115, one or more cup seals 1120, a fluid passage 1130, a fluid passage 1135, one or more fluid passages 1140, seals 1145, and a support part 1150.

The expandable spindle or spike 1105 is connected to and supported by the support part 1150. The expandable spindle 1105 is preferably adapted to controllably expand in the radial direction. The expandable spindle 1105 may comprise any of several conventional, commercially available expandable spindles, modified according to the information herein. In a preferred embodiment, the expandable spindle 1105 comprises a hydraulic expansion tool, essentially as described in US 5,348,095, which description is incorporated herein by reference, modified according to the information in the present description.

The tubular member 1110 is connected to and supported by the expandable mandrel 1105. The tubular member 1105 is expanded in the radial direction and extruded from the expandable mandrel 1105. The tubular member 1110 may be made of any of several materials, such as Oilfield Country Tubular Goods, 13 chrome tubing or plastic tubing. In a preferred embodiment, the tubular member 1110 is manufactured by Oilfield Country Tubular Goods.

The inner and outer diameters of the pipe part 1110 can be in the range e.g. from about 0.75 to 47 inches and 1.05 to 48 inches. In a preferred embodiment, the inner and outer diameters of the tubing portion 1110 range from 3 to 15.5 inches and 3.5 to 16 inches, respectively, to optimally provide coverage for typical oil field casing sizes. The tubular part 1110 preferably comprises a solid part.

In a preferred embodiment, the end region of the tubular portion 1110 is slotted, perforated, or otherwise modified to trap or retard the spindle 1105 as it completes extrusion of the tubular portion 1110. In a preferred embodiment, the length of the tubular portion 1110 is limited to minimize the possibility of bulking . For typical materials of the pipeline 1110, the length of the pipe section 1110 is preferably limited to between 40 and 20,000 feet in length.

The shoe 1115 is coupled to the expandable spindle 1105 and the tubular member 1110. The shoe 1115 comprises the fluid passage 1135. The shoe 1115 may comprise any of several conventional, commercially available shoes, such as e.g. Super Seal II float shoe, Super Seal II Down-Jet float shoe and a guide shoe with a sealing sleeve for a lock-down plug modified according to the information in the present description. In a preferred embodiment, the shoe 1115 comprises an aluminum downwash guide shoe with a sealing sleeve for a side-ported lock-down plug from the existing flow port available from Halliburton Energy Services of Dallas, Texas, modified according to information herein, to optimally guide the pipe member 1100 to the overlap between the pipe member 1100 and the casing 1012, optimally fluid isolating the interior of the pipe member 1100 after the lock-down plug is set, and optimally allowing the drilling of the shoe 1115 after the completion of the expansion and cementing operations.

In a preferred embodiment, the shoe 1115 comprises one or more side outlet ports 1140 in fluid communication with the fluid passage 1135. In this manner, the shoe 1115 injects curable liquid sealant material into the area outside the shoe 1115 and the tubular portion 1110. In a preferred embodiment, the shoe 1115 comprises one or more fluid passages 1140 each having an inlet geometry that can receive a dart and/or ball seal member. In this way, the fluid passages 1140 can be closed off by introducing a plug, arrow and/or ball sealing element in the fluid passage 1130.

The cup gasket 1120 is coupled to and supported by the support member 1150. The cup gasket 1120 prevents foreign material from entering the interior region of the tube portion 1110 near the expandable spindle 1105. The cup gasket 1120 may comprise any of several conventional and commercially available cups -packaging, such as TP cups or Selective Injection Packer (SlP) cups modified according to the information in the present description. In a preferred embodiment, the cup gasket 1120 comprises a SIP cup, available from Halliburton Energy Services of Dallas, Texas, to optimally provide a barrier against contamination and to contain a body of lubricant.

The fluid passage 1130 allows liquid materials to be transported to and from the interior region of the tube portion 1110 below the expandable spindle 1105. The fluid passage 1130 is connected to and located within the support portion 1150 and the expandable spindle 1105. The fluid passage 1130 preferably extends from a position near the surface to the bottom of the expandable spindle 1105. The fluid passage 1130 is preferably located along a centerline of the apparatus 1100. The fluid passage 1130 is preferably selected to transport materials such as cement, drilling mud or epoxy at flow rates and pressures in the range of about 0 to 3,000 gallons per minute and 0 to 9,000 psi, to optimally produce sufficient operating pressure to circulate fluids in operationally effective amounts.

The fluid passage 1135 allows liquid materials to be transferred from the fluid passage 1130 to the interior of the tube portion 1110 below the spindle 1105.

The fluid passages 1140 allow liquid materials to be transported to and from the area outside the tube portion 1110 and the shoe 1115. The fluid passages 1140 are connected to and placed within the shoe 1115 in fluid communication with the interior region of the tube portion 1110 below the expandable spindle 1105. The fluid passages 1140 preferably have a cross-sectional shape that allows a plug or other similar device to be placed in the fluid passages 1140 to thereby block further passage of liquid materials. In this way, the inner area of the pipe section 1110 below the expandable spindle 1105 can be fluid isolated from the area outside the pipe section 1105. This allows the inner area of the pipe section 1110 below the expandable spindle 1105 to be pressurized.

The fluid passages 1140 are preferably located along the periphery of the shoe 1115. The fluid passages 1140 are preferably selected to transport materials such as cement, drilling mud, or epoxy at flow rates and at pressures in the range of about 0 to 3,000 gallons per minute and 0 to 9,000 psi for optimally filling the annular space between the pipe part 1110 and the pipe lining 1108 with liquid materials. In a preferred embodiment, the fluid passage 1140 comprises an inlet geometry that can receive a dart and/or ball seal member. In this way, the fluid passage 1140 can be closed off by introducing a plug, arrow and/or ball sealing element in the fluid passage 1130. In a preferred embodiment, the apparatus 1100 comprises several fluid passages 1140.

In an alternative embodiment, the base of the shoe 1115 comprises a single inlet passage connected to the fluid passage 1140, which is adapted to receive a plug or other similar device, to allow the inner region of the tube member 1140 to be fluid-isolated from the outer pipe part 1110.

The gaskets 1145 are connected to and supported by a lower end portion of the tubing portion 1110. The gasket 1145 is further positioned on an outer surface of the lower end portion of the tubing portion 1110. The gaskets 1145 allow the overlapping joint between the upper end portion of the casing 1112 and the lower end portion of the pipe part 1110 is fluid sealed.

The gaskets 1145 may comprise any of conventional commercially available gaskets such as e.g. lead, rubber, Teflon or epoxy gaskets modified according to the information in the present invention. In a preferred embodiment, the gaskets comprise 1145 gaskets cast from StrataLock epoxy available from Halliburton Energy Services of Dallas, Texas to optimally provide a hydraulic seal in the overlap joint and optimally provide load carrying capacity to withstand the range of typical tensile and compressive loads.

In a preferred embodiment, the gaskets 1145 are selected to optimally produce a sufficient frictional force to support the expanded tubular portion 1110 from the pipe liner 1008. In a preferred embodiment, the frictional force produced by the gaskets 1145 is in the range of about 1,000 to 1,000,000 pounds in tension and compression to optimally support the expanded tube portion 1110. The support portion 1150 is connected to the expanded spindle 1105, the tubular portion 1110, the shoe 1115, and the gasket 1120. The support portion 1150 preferably includes an annular portion that has sufficient strength to support the apparatus 1110 into the wellbore 1000. In a preferred embodiment, the support member 1150 further comprises one or more conventional centralizing devices (not shown) to help stabilize the pipe member 1110.

In a preferred embodiment, a quantity of lubricant 1150 is arranged in the annulus above the expandable spindle 1105 in the interior of the tubular part 1110. In this way, extrusion of the tubular part 1110 of the expanded spindle 1105 is facilitated. The lubricant 1150 may comprise any of several conventional and commercially available lubricants, such as e.g. Lubriplate, chlorine-based lubricants or Climax 1500 Antiseize (3100). In a preferred embodiment, the lubricant 1150 comprises Climax 1500 Antiseize (3100) available from Climax Lubricants and Equipment Co. in Houston, Texas, to optimally provide lubrication to the extrusion process.

In a preferred embodiment, the support part 1150 is thoroughly cleaned before assembly with the remaining parts of the apparatus 1100. In this way, the introduction of foreign materials into the apparatus 1100 is minimized. This minimizes the possibility of foreign materials clogging the various flow passages and valves in the apparatus 1100, and ensures that no foreign materials affect the expansion spindle 1105 during the extrusion process.

In a particularly preferred embodiment, the apparatus 1100 includes a gasket 1155 coupled to the bottom section of the shoe 1115 to fluidly isolate the region of the wellbore 1000 below the apparatus 1100. In this way, liquid materials are prevented from entering the area of the wellbore 1000 below the apparatus 1100. The gasket 115 may comprise any of several conventional and commercially available gaskets, such as e.g. EZ Drill Packer, EZ SV Packer or a drillable cement holder. In a preferred embodiment, the packer 1155 comprises an EZ Drill Packer, available from Halliburton Energy Services of Dallas, Texas. In an alternative embodiment, a high-gel strength pill can be placed below the platform instead of the gasket 1155. In another alternative embodiment, the gasket 1155 can be omitted.

In a preferred embodiment, before or after placing the apparatus 1100 in the wellbore 1000, a pair of wellbore volumes are circulated to ensure that no foreign materials are inside the wellbore 1000, which could clog the various flow passages and valves of the apparatus 1100, ensuring that no foreign materials affect the operation of the expansion spindle 1105.

As illustrated in Figure 10c, curable liquid sealing material 1160 is then pumped from a location on the surface into the fluid passage 1130. The material 1160 then passes from the fluid passage 1130 into the interior region of the tube portion 1110 below the expandable spindle 1105. The material 1160 then passes from the inner area of the pipe section 1110 into the fluid passages 1140. The material 1160 then exits the apparatus 1100 and fills the annulus between the exterior of the pipe section 1110 and the inner wall of the tubular liner 1008. Continued pumping of the material 1160 causes the material 1160 to fill up in at least part of the annulus.

The material 1160 can be pumped into the annulus at pressures and flow rates that are in the range from e.g. 0 to 5,000 psi and 0 to 1,500 gallons per minute. In a preferred embodiment, the material 1160 is pumped into the annulus at pressures and flow rates specifically designed for the casing sizes being run, the annulus being filled, pumping equipment available, and the characteristics of the fluid being pumped. The optimum flow rates and pressures are preferably calculated using conventional empirical methods.

The curable liquid sealant material 1160 may comprise any of several conventional, commercially available curable liquid sealant materials, such as, e.g. slag mixture, cement or epoxy. In a preferred embodiment, the curable liquid sealing material 1160 comprises blended cements specifically designed for the particular well section, available from Halliburton Energy Services of Dallas, Texas, to optimally provide proper support for the tubing section 1110 while maintaining optimal flow characteristics to minimize operational difficulties during displacement of cement into the annulus. The optimum mixture of the blended cements is preferably determined using conventional empirical methods.

The annular region may be filled with the material 1160 in sufficient amounts to ensure that, upon radial expansion of the tubular portion 1110, the annulus will be filled with the material 1160.

As illustrated in figure 10d, as soon as the annulus is sufficiently filled with material 1160, one or more plugs 1165 or other similar devices are preferably introduced into the fluid passage 1140 in order to fluid-isolate the inner areas of the tube part 1110 from the annulus outside the tube part 1110. In a preferred embodiment, a non-curable liquid material 1161 is then pumped into the inner region of the tube portion 1110 below the spindle 1115, causing the inner region to come under pressure. In a particularly preferred embodiment, the one or more plugs 1165 or other similar devices are introduced into the fluid passage 1140 with the introduction of the non-curable liquid material. In this way, the amount of curable liquid material in the interior of the tube part 1110 is minimized.

As illustrated in Figure 10e, as soon as the inner region comes under sufficient pressure, the tubular part 1110 is extruded from the expandable mandrel 1105. During the extrusion process, the expandable mandrel 1105 is raised out of the expanded part of the tubular part 1110.

The plugs 1165 are preferably placed in the fluid passages 1140 by inserting the plugs 1165 into the fluid passage 1130 at a location on the surface, in the conventional manner. The plugs 1165 may comprise any of several conventional, commercially available devices for plugging a fluid passage such as e.g. brass balls, plugs, rubber balls or arrows modified according to the information in the present description.

In a preferred embodiment, the plugs comprise 1165 low density rubber balls.

In an alternative embodiment, for a shoe 1105 having a common central inlet passage, the plugs 1165 include a single locking arrow.

After placement of the plugs 1165 in the fluid passages 1140, the non-curable liquid material 1165 is preferably pumped into the interior region of the tube portion 1110 below the spindle 1105 at pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000 gallons per minute. In a preferred embodiment, after placement of the plugs 1165 in the fluid passages 1140, the non-curable liquid material 1161 is preferably pumped into the inner region of the tube portion 1110 below the spindle 1105 at pressures and flow rates ranging from about 1,200 to 8,500 psi and 40 to 1,250 gallons per minute to optimally produce extrusion of typical pipes.

For typical tubular members 1110, extrusion of tubular members 1110 from the expandable spindle 1105 will begin when the pressure in the inner region of the tubular member 1110 below the spindle 1105 reaches, e.g. about 1,200 to 8,500 psi. In a preferred embodiment, the extrusion of the pipe member 1110 from the expandable spindle 1105 begins when the pressure in the inner region of the pipe member 1110 below the spindle 1105 reaches about 1,200 to 8,500 psi.

During the extrusion process, the expandable spindle 1105 may be lifted out of the expanded portion of the tube portion 1110 at rates ranging from about 0 to 5 feet per second. In a preferred embodiment, during the extrusion process, the expandable spindle 1105 is raised out of the expanded portion of the tube portion 1110 at an amount ranging from about 0 to 2 feet per second to optimally produce allowable adjustment of operating parameters, and optimally to ensure that the extrusion process will be completed before the material 1160 hardens.

In a preferred embodiment, at least a portion 1180 of the tube portion 1110 has an internal diameter that is smaller than the outer diameter of the spindle 1105. In this way, when the spindle 1105 expands the section 1180 of the tube portion 1110, at least a portion of the expanded section 1180 form a seal with at least the wellbore casing 1112. In a particularly preferred embodiment, the seal is achieved by compressing the gaskets 1016 between the expanded section 1180 and the wellbore casing 1012.1 a preferred embodiment, the contact pressure in the joint between the expanded section 1180 of pipe member 1110 and casing 1012 in the range of about 500 to 10,000 psi to optimally generate pressure to actuate seal member 1145 and to generate optimal resistance to ensure that the joint will withstand typical extremes of tensile and compressive loads.

In an alternative preferred embodiment, substantially the entire length of the tube portion 1110 has an internal diameter that is smaller than the outer diameter of the spindle 1105. In this manner, extrusion of the tube portion 1110 by the spindle 1105 will result in contact between substantially all of the expanded tube portion 1110 and the existing casing 1008.1 a preferred embodiment, the contact pressure of the joint between the expanded pipe section 1110 and the casings 1008 and 1012 is in the range of about 500 to 10,000 psi to optimally generate pressure to activate the sealing members 1145 and to generate optimal resistance to ensure that the joint will withstand typical extremes of tensile and compressive loads.

In a preferred embodiment, the operating pressure and flow rate of the material 1161 is controllably ramped down when the expandable spindle 1105 reaches the upper end portion of the pipe member 1110. In this way, the sudden release of pressure caused by the completed extrusion of the pipe member 1110 from the expandable spindle 1105 be minimized. In a preferred embodiment, the operating pressure of the liquid material 1161 is reduced in a substantially linear manner from 100% to about 10% during the end of the extrusion process, which begins when the spindle 1105 has completed all, as close as about 5 feet, of the extrusion process.

Alternatively, or in combination, a shock absorber is provided in the support portion 1150 to absorb shock caused by the sudden release of pressure.

Alternatively, or in combination, a spindle capture structure is provided in the upper end portion of the tube portion 1110 to capture or at least decelerate the spindle 1105.

Reference is now made to figure 10f. Once the extrusion process is complete, the expandable mandrel 1105 is removed from the wellbore 1000. In a preferred embodiment, either prior to or after removal of the expandable mandrel 1105, the integrity of the fluid seal of the joint between the upper portion of the tubing member 1110 and the upper portion of the tubular liner 1108 tested using conventional methods. If the fluid seal of the joint between the upper portion of the tube portion 1110 and the upper portion of the liner 1008 is satisfactory, the uncured portion of the material 1160 within the expanded tube portion 1110 is removed in a conventional manner. The material 1160 inside the annulus between the pipe part 1110 and the liner 1008 is then allowed to harden.

As illustrated in Figure 10f, residual hardened material 1160 in the interior of the expanded tubular portion 1110 is then removed in a conventional manner using a conventional drill string. The resulting platform liner of the casing 1170 comprises the expanded pipe member 1110 and an outer annular layer 1175 of hardened material 1160.

As illustrated in Figure 10g, the remaining portion of the apparatus 1100, comprising the shoe 1115 and gasket 1155, is then preferably removed by drilling out the shoe 1115 and gasket 1155 using conventional drilling methods.

In a particularly preferred embodiment, the apparatus 1100 will include the apparatus 900.

Reference is now made to Figures 11a to 11f. An embodiment of an apparatus and a method for hanging a tubular casing from an existing wellbore casing will now be described. As illustrated in Figure 1 la, a wellbore 1200 is located in an underground formation 1205. The wellbore 1200 comprises an existing lined section 1210 having a casing 1215 and an annular outer layer of cement 1220. To extend the wellbore 1200 into the underground formation 1205, a drill string 1225 is used in a well-known manner to drill out the material from the underground formation 1205 to form a new section 1230.

As illustrated in Figure 11b, an apparatus 1300 for forming a wellbore casing in a subterranean formation is then placed in the new section 1230 of the wellbore 100. The apparatus 1300 preferably comprises an expandable spindle or spike 1305, a tubular member 1310, a shoe 1315, a fluid passage 1320, a fluid passage 1330, a fluid passage 1335, gaskets 1340, a support part 1345, and a scraper plug 1350.

The expandable spindle 1305 is connected to and supported by the support part 1345. The expandable spindle 1305 is preferably adapted to controllably expand in the radial direction. The expandable spindle 1305 may comprise any of several conventional, commercially available expandable spindles modified according to information herein. In a preferred embodiment, the expandable spindle 1305 comprises a hydraulic expansion tool, substantially as described in US 5,348,095, which description is incorporated herein by reference, modified according to the information in the present description.

The tubular member 1310 is connected to and supported by the expandable mandrel 1305. The tubular member 1310 is preferably expanded in the radial direction and extruded from the expandable mandrel 1305. The tubular member 1310 may be fabricated from any of several materials, such as .ex. Oilfield Country Tubular Goods (OCTG), 13 chrome steel tubing/casing or plastic casing. In a preferred embodiment, the pipe part 1310 is fabricated from OCTG. The inner and outer diameters of the pipe part 1310 can lie in the range, e.g. from about 0.75 to 47 inches and 1.05 to 48 inches. In a preferred embodiment, the inner and outer diameters of the pipe portion 1310 are in the range of about 3 to 15.5 inches and 3.5 to 16 inches, to optimally provide minimum telescoping effect in the most commonly used wellbore sizes.

In a preferred embodiment, the pipe part 1310 comprises an upper part 1355, a middle part 1360, and a lower part 1365. In a preferred embodiment, the wall thickness and the outer diameter of the upper part 1355 of the pipe part 1310 are in the range of about 3/8 inch to 1.5 inch and 3.5 to 16 inch. In a preferred embodiment, the wall thickness and outer diameter of the central portion 1360 of the tube portion 1310 is in the range of about 0.625 to 0.75 inches and 3 to 19 inches.

In a preferred embodiment, the wall thickness and outer diameter of the lower portion 1365 of the tube portion 1310 is in the range of about 3/8 to 1.5 inches and 3.5 to 16 inches.

In a particularly preferred embodiment, the outer diameter of the lower portion 1365 of the tubular member 1310 is substantially smaller than the outer diameters of the upper and middle portions, 1355 and 1360, of the tubular member 1310 to optimize the design of a concentric and overlapping arrangement of wellbore -casing pipe. In this way, which will be described below with reference to figures 12 and 13, a wellhead system is optimally produced. In a preferred embodiment, the design of a wellhead system does not include the use of a curable liquid material.

In a particularly preferred embodiment, the wall thickness of the middle section 1360 of the pipe member 1310 is less than or equal to the wall thickness of the upper and lower sections 1355 and 1365 of the pipe member 1310, to optimally facilitate the initiation of the extrusion process and optimally to allow placement of the apparatus in the area of the wellbore which have narrow clearances.

The pipe part 1310 preferably comprises a solid part. In a preferred embodiment, the upper end portion 1355 of the tubular member 1310 is slotted, perforated, or otherwise modified to trap or delay the spindle 1305 as it completes the extrusion of the tubular member 1310. In a preferred embodiment, the length of the tubular member 1310 is limited to minimize the possibility of bulking. For typical materials of the portion 1310, the length of the tubular portion 1310 is preferably limited to between 40 to 20,000 feet in length.

The shoe 1315 is connected to the tubular part 1310. The shoe 1315 preferably comprises fluid passages 1330 and 1335. The shoe 1315 may comprise any of several conventional, commercially available shoes such as e.g. Super Seal II float shoe, Super Seal II Down-Jet float shoe or guide shoe with a sealing sleeve for a lock-down plug, modified according to information in this specification. In a preferred embodiment, the shoe 1315 comprises an aluminum flush-down guide shoe with a sealing sleeve for a lock-down plug available from Halliburton Energy Services of Dallas, Texas, modified according to information herein, to optimally guide the tubular member 1310 into the wellbore 1200, optimally fluid-isolating the interior of the pipe member 1310, and optimally allowing complete boring out of the shoe 1315 after completion of the extrusion and cementing operations.

In a preferred embodiment, the shoe 1315 further comprises one or more side exit ports in fluid communication with the fluid passage 1330. In this way, the shoe 1315 will preferably inject curable liquid sealing material into the area outside the shoe 1315 and the tubular part 1310.1 a preferred embodiment, the shoe 1315 comprises the fluid passage 1330 which has an inlet geometry that can receive a fluid seal member. In this way, the fluid passage 1330 can be closed by introducing a plug, arrow and/or ball sealing element in the fluid passage 1330.

The fluid passage 1312 allows liquid materials to be transported to and from the interior region of the tube portion 1310 below the expandable spindle 1305. The fluid passage 1320 is connected to and located within the support member 1345 and the expandable spindle 1305. The fluid passage 1320 preferably extends from a position near the surface to the bottom of the expandable spindle 1305. The fluid passage 1320 is preferably located along the centerline of the apparatus 1300. The fluid passage 1320 is preferably selected to transport materials such as cement, drilling mud or epoxy at flow rates and pressures ranging from about 0 to 3,000 gallons per minute and 0 to 9,000 psi to optimally generate sufficient operating pressure to circulate fluids in operationally effective amounts.

The fluid passage 1330 allows liquid materials to be transported to and from the area outside the tube portion 1310 and the shoe 1315. The fluid passage 1330 is connected to and placed within the shoe 1315 in fluid communication with the outer region 1370 of the tube portion 1310 below the expandable spindle 1305. The fluid passage 1330 preferably has a cross-sectional shape that allows a plug or other similar device to be placed in the fluid passage 1330 to thereby block further passage of fluid materials. In this way, the inner region 1370 of the tube part 1310 below the expandable spindle 1305 can be fluid-isolated from the area outside the tube part 1310. This allows the inner region 1370 of the tube part 1310 below the expandable spindle 1305 to be pressurized. The fluid passage 1330 is preferably located essentially along the center line of the apparatus 1300.

The fluid passage 1330 is preferably selected to transport materials such as cement, drilling mud or epoxy at flow rates and pressures in the range of about 0 to 3,000 gallons per minute and 0 to 9,000 psi to optimally fill the annulus between the pipe section 1310 and the new section 1230 of the wellbore 1200 with liquid materials. In a preferred embodiment, the fluid passage 1330 comprises an inlet geometry that can receive a dart and/or ball seal member. In this way, the fluid passage 1330 can be closed by introducing a plug, arrow and/or ball sealing element in the fluid passage 1320.

The fluid passage 1335 allows liquid materials to be transported to and from the area outside the tube portion 1310 and the shoe 1315. The fluid passage 1335 is connected to and located within the shoe 1315 in fluid communication with the fluid passage 1330. The fluid passage 1335 is preferably located substantially along the centerline of the apparatus 1300. The fluid passage 1335 is preferably selected to transport materials such as cement, drilling mud, or epoxy at flow rates and pressures in the range of about 0 to 3,000 gallons per minute and 0 to 9,000 psi to optimally fill the annulus between the tubing section 1310 and the new section 1230 of wellbore 1200 with liquid materials.

The gaskets 1340 are connected to and supported at the upper end portion 1355 of the pipe portion 1310. The gaskets 1340 are further placed on an outer surface of the upper end portion 1355 of the pipe portion 1310. The gaskets 1340 allow an overlapping joint between the lower end region of the casing pipe 1215 and the upper part 1355 of pipe part 1310 is fluid sealed.

The gaskets 1340 may comprise any of several conventional, commercially available gaskets, such as e.g. lead, rubber, Teflon or epoxy gaskets modified according to information in the present description. In a preferred embodiment, the gaskets comprise 1340 gaskets molded from StrataLock epoxy available from Halliburton Energy Services of Dallas, Texas, to optimally produce a hydraulic seal in the annulus of the overlapped joint while also creating optimal load-carrying capability to withstand typical tensile and compression loads.

In a preferred embodiment, the gaskets 1340 are chosen to optimally provide a sufficient frictional force to support the expanded tubular portion 1310 from the existing casing 1215. In a preferred embodiment, the frictional force produced by the gaskets 1340 is in the range of about 1,000 to 1 000,000 pounds, to optimally support the expanded pipe section 1310.

The support part 1345 is connected to the expandable spindle 1305, the pipe part 1310, the shoe 1315 and the gaskets 1340. The support part 1345 preferably comprises an annular part which has sufficient strength to carry the apparatus 1300 into the new section 1230 of the wellbore 1200. In a preferred embodiment, the support member 1345 further includes one or more conventional centering devices (not illustrated) to help stabilize the tube member 1310.

In a preferred embodiment, the support part 1345 is thoroughly cleaned before assembly with the remaining parts of the apparatus 1300. In this way, introduction of foreign materials into the apparatus 1300 is minimized. This minimizes the possibility of foreign materials clogging the various flow passages and valves in the apparatus 1300, and ensures that no foreign materials affect the expansion process.

The scraper plug 1350 is connected to the spindle 1305 inside the inner area 1370 of the pipe part 1310. The scraper plug 1350 comprises a first passage 1375 which is connected to the fluid passage 1320. The scraper plug 1350 may comprise one or more conventional, commercially available scraper plugs, such as e.g. Multiple Stage Cementer Locking Plugs, Omega Locking Plugs or Wood Scraper Locking Plugs modified according to information in this description. In a preferred embodiment, the scraper plug 1350 comprises a Multiple Stage Cementer lock-down plug available from Halliburton Energy Services of Dallas, Texas, modified in a conventional manner for releasable mounting on the expansion spindle 1305.

In a preferred embodiment, before or after placing the apparatus 1300 in the new section 1230 of the wellbore 1200, a pair of wellbore volumes are circulated to ensure that no foreign materials are inside the wellbore 1200, which could plug the various flow passages and valves in the apparatus 1300, and to ensure that no foreign materials affect the extrusion process.

As illustrated in Figure 1c, a curable liquid sealing material 1380 is then pumped from a location on the surface into the fluid passage 1320. The material 1380 then passes from the fluid passage 1320, through the fluid passage 1375, and into the interior region 1370 of the tube portion 1310 below the expandable spindle 1305. The material 1380 then passes from the inner area 1370 into the fluid passage 1330. The material 1380 then exits the apparatus 1300 via the fluid passage 1335, and fills the annulus 1390 between the outside of the pipe part 1310 and the inner wall of the new section 1230 of the wellbore 1200. Continued pumping of the material 1380 causes the material 1380 to fill up at least a portion of the annulus 1390.

The material 1380 can be pumped into the annulus 1390 at pressures and flow rates such as e.g. ranges from about 0 to 5,000 psi and 0 to 1,500 gallons per minute. In a preferred embodiment, the material 1380 is pumped into the annulus 1390 at pressures and flow rates ranging from 0 to 5,000 psi and 0 to 15,000 gallons per minute to optimally fill the annulus between the tubing section 1310 and the new section 1230 of the wellbore. 1200 with the curable liquid sealant 1380.

The curable liquid sealant material 1380 may comprise any of several conventional, commercially available curable liquid sealant materials, such as, e.g. slag mixture, cement or epoxy. In a preferred embodiment, the curable liquid sealing material 1380 comprises blended cement designed specifically for the well section being carried, which is available from Halliburton Energy Services to optimally provide support for the tubing member 1310 during displacement of the material 1380 into the annular region 1390. optimum mix of cement is preferably determined using conventional empirical methods.

The annular space 1390 is preferably filled with the material 1380 in sufficient quantities to ensure that, after radial expansion of the pipe part 1310, the annular area 1390 of the new section 1230 in the wellbore 1200 will be filled with the material 1380.

As illustrated in Figure 1d, as soon as the annulus 1390 is sufficiently filled with the material 1380, a scraper arrow 1395 or similar device is introduced into the fluid passage 1320. The scraper arrow 1395 is preferably pumped through the fluid passage 1320 by a non-curable liquid material 1381. The scraper arrow 1395 will then preferably engage the scraper plug 1350. As illustrated in figure 1e, in a preferred embodiment, contact between the scraper arrow 1395 and the scraper plug 1350 will cause the scraper plug 1350 to disengage from the spindle 1305. The scraper arrow 1395 and the scraper plug 1350 will then preferably stick in the fluid passage 1330, and thus blocking fluid flow through the fluid passage 1330, and fluid-isolating the inner region 1370 of the tube portion 1310 from the annulus 1390.1 a preferred embodiment, the non-curable liquid material 1381 is then pumped into the inner region 1370 and causes the inner region 1370 to come under pressure . As soon as the inner region 1370 is under sufficient pressure, the tube part 1310 is extruded from the expandable mandrel 1305. During the extrusion process, the expandable mandrel 1305 is raised out of the expanded part of the tube part 1310 by the support part 1345.

The scraper dart 1395 is preferably placed in the fluid passage 1320 by inserting the scraper dart 1395 into the fluid passage 1320 at a location on the surface, in a conventional manner. Scraper arrow 1395 may comprise any of several conventional, commercially available devices for plugging a fluid passage such as, for example, Multiple Stage Cementer Locking Plugs, Omega Locking Plugs or Wood Scraper Locking Plug/Arrows modified according to information in this description. In a preferred embodiment, the scraper arrow 1395 consists of a wooden blade locking plug modified to lock and seal in the Multiple Stage Cementer locking plug 1350. The wooden blade locking plug is available from Halliburton Energy Services of Dallas, Texas.

After blocking the fluid passage 1330 using the scraper plug 1330 and the scraper arrow 1395, the non-curable liquid material 1381 can be pumped into the inner region 1370 at pressures and flow rates that are in the region, e.g. from about 0 to 5,000 psi and 0 to 1,500 gallons per minute to optimally extrude tubing 1310 from spindle 1305. In this manner, the amount of curable liquid material within the interior of tubing 1310 is minimized.

In a preferred embodiment, after blocking the fluid passage 1330, the non-curable liquid material 1381 is preferably pumped into the interior region 1370 at pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000 gallons per minute to optimally provide operating pressures to maintain the expansion process at sufficient amounts to allow adjustment in the operating parameters during the extrusion process.

For typical tubular members 1310, extrusion of the tubular members 1310 from the expandable spindle 1305 will begin when the pressure in the inner region 1370 reaches e.g. about 500 to 9,000 psi. In a preferred embodiment, extrusion of the tubular member 1310 from the expandable mandrel 1305 is a function of the diameter of the tubular member, the wall thickness of the tubular member, the geometry of the mandrel, the type of lubricant, the composition of the shoe and the tubular member, and the breaking strength of the tubular member. The optimum flow rate and operating pressure are preferably determined using conventional empirical methods.

During the extrusion process, the expandable spindle 1305 may be raised out of the expanded portion of the tube portion 1310 by amounts in the range of e.g. from 0 to 5 feet per second. In a preferred embodiment, during the extrusion process, the expandable spindle 1305 is raised out of the expanded portion of the tube portion 1310 by amounts ranging from 0 to 2 feet per second to optimally provide an efficient process, optimally allowing operator adjustment of operating parameters and to ensure optimal completion of the extrusion process prior to curing of the material 1380.

When the upper end region 1355 of the tubular member 1310 is extruded from the expandable mandrel 1305, the outer surface of the upper end region 1355 of the tubular member 1310 will preferably contact the inner surface of the lower end member of the casing 1215 to form a fluid-tight overlapping joint. The contact pressure in the overlapping joint can be in the range, e.g. from about 50 to 20,000 psi. In a preferred embodiment, the contact pressure of the overlap joint is in the range of from about 400 to about 10,000 psi to optimally provide contact pressure sufficient to ensure annular sealing and to provide sufficient resistance to withstand typical tensile and compressive loads. In a particularly preferred embodiment, the sealing parts 1340 will ensure a sufficient fluid and gas seal in the overlapping joint.

In a preferred embodiment, the operating pressure and flow rate of the non-curable liquid material 1381 is controllably ramped down when the expandable spindle 1305 reaches the upper end region 1355 of the pipe member 1310. In this way, the sudden release of pressure caused by the completion of the extrusion of the tube part 1310 from the expandable spindle 1305 be minimized. In a preferred embodiment, the operating pressure is reduced in an approximately linear fashion from 100% to about 10% toward the end of the extrusion process, which begins when the spindle 1305 has completed all but about 5 feet of the extrusion process.

Alternatively, or in combination, a shock absorber is provided in the support portion 1345 to absorb the shock caused by the sudden release of pressure.

Alternatively, or in combination, a spindle capture structure is provided in the upper end region 1355 of the tube portion 1310 to capture or at least decelerate the spindle 1305.

Once the extrusion process is complete, the expandable mandrel 1305 is removed from the wellbore 1200. In a preferred embodiment, either before or after the removal of the expandable mandrel 1305, the integrity of the fluid seal of the overlapping joint between the upper region 1355 of the pipe member 1310 and the lower region of casing 1215 tested using conventional methods. If the fluid seal of the overlapping joint between the upper region 1355 of the pipe section 1310 and the lower region of the casing pipe 1215 is satisfactory, the uncured portion of the material 1380 in the expanded pipe section 1310 is removed in a conventional manner. The material 1380 inside the annulus 1390 is then allowed to harden.

As illustrated in Figure 1 lf, any remaining hardened material 1380 inside the interior of the expanded pipe 1310 is then removed in a conventional manner using a conventional drill string. The resulting new section of casing 1400 comprises the expanded tubular portion 1310 and an outer annular layer 1405 of hardened material 305. The bottom portion of the apparatus 1300, comprising the shoe 1315, can then be removed by drilling out the shoe 1315 using conventional drilling methods.

Reference is now made to Figures 12 and 13, where a preferred embodiment of a wellhead system 1500 designed using one or more of the devices and processes as described above with reference to Figures 1 to 11 f, shall be described. The wellhead system 1500 preferably comprises a conventional valve tree/drill coil assembly 1505, a thick-walled casing 1510, an annular body of cement 1515, an outer casing 1520, and an annular cement body 1525, an intermediate casing 1530, and an inner casing 1535.

The valve tree/bore coil unit 1505 may comprise any of several valve tree/bore coil units, such as e.g. SS-15 Subsea Wellhead System, Spool Tree

Subsea Production System or Compact Wellhead System, available from suppliers such as Dril-Quip, Cameron or Breda, modified according to the information in the present description. The drill coil unit 1505 is preferably operatively connected to the thick-walled casing 1510 and/or the outer casing 1520. The unit 1505 may be connected to the thick-walled casing 1510 and/or the outer casing 1520, e.g. by welding, a threaded connection or made from a single blank. In a preferred embodiment, the unit 1505 is connected to the thick-walled casing 1510 and/or the outer casing 1520 by welding.

The thick-walled casing 1510 is placed at the upper end of a wellbore 1540. In a preferred embodiment, at least a part of the thick-walled casing 1510 will extend above the surface 1545 to optimally provide easy access and attachment to the valve tree/drill coil assembly 1505. The thick-walled casing 1510 casing 1510 is preferably connected to the valve tree/casing assembly 1505, the annular body of cement 1515, and the outer casing 1520.

The thick-walled casing 1510 may comprise any of several conventional and commercially available high-strength wellbore casings, such as Oilfield Country Tubular Goods, titanium tubing or stainless steel tubing. In a preferred embodiment, the thick-walled casing comprises 1510 Oilfield Country Tubular Goods available from various foreign and domestic steel mills. In a preferred embodiment, a thick-walled casing 1510 has a breaking strength of about 40,000 to 135,000 psi to optimally provide maximum breaking, collapse, and tensile strengths. In a preferred embodiment, the thick-walled casing 1510 has a rupture strength in excess of about 5,000 to 20,000 psi to optimally provide maximum operating capacity and resistance to capacity degradation after being drilled for an extended period of time.

The annular cement body 1515 provides support for the thick-walled casing 1510. The annular cement body 1515 may be produced using any of several conventional processes for forming an annular body of cement in a wellbore. The annular cement body 1515 may comprise any of several conventional cement mixtures.

The outer casing 1520 is connected to the thick-walled casing 1510. The outer casing 1520 may be made from any of several conventional commercially available pipe parts modified according to the information in the present description. In a preferred embodiment, the outer casing 1520 comprises any of the expanded pipe parts described above with reference to figures 1 to 11f.

In a preferred embodiment, the outer casing 1520 is coupled to the thick-walled casing 1510 by expanding the outer casing 1520 into contact with at least a portion of the inner surface of the thick-walled casing 1510 using any of the embodiments of the process and apparatus described above with reference to Figures 1 to IT f. In an alternative embodiment, substantially the entire overlap of the outer casing 1520 with the thick-walled casing is in contact with the inner surface of the thick-walled casing 1510.

The contact pressure of the interface between the outer casing 1520 and the thick-walled casing 1510 can range from about 500 to 10,000 psi. In a preferred embodiment, the contact pressure between the outer casing 1520 and the thick-walled casing 1510 is in the range of about 500 to 10,000 psi to optimally activate the pressure-activated sealing members and to ensure that the lap joint will optimally withstand typical extreme tensile and compressive loads encountered during drilling and production operations.

As illustrated in Figure 13, in a particularly preferred embodiment, the upper end of the outer casing 1520 comprises one or more sealing parts 1550 which provide a gas and fluid seal between the expanded outer casing 1520 and the inner wall of the thick-walled casing 1510. The sealing parts 1550 may include any of several conventional and commercially available gaskets, such as e.g. lead, plastic, rubber, Teflon or epoxy, modified according to the information in the present description. In a preferred embodiment, the sealing members comprise 1550 gaskets cast from StrataLock epoxy available from Halliburton Energy Services, to optimally provide a hydraulic seal and a load-bearing interface fit between the pipe members. In a preferred embodiment, the contact pressure at the interface between the thick-walled casing 1510 and the outer casing 1520 is in the range of about 500 to 10,000 psi to optimally activate the sealing member 1550 and also optimally ensure that the joint will withstand the typical extreme tensile and compressive loads. during drilling and production operations.

In an alternative preferred embodiment, the outer casing 1520 and the thick-walled casing 1510 are combined in a unitary part.

The annular body of cement 1525 provides support for the outer casing 1520. In a preferred embodiment, the annular body of cement 1525 is arranged using any of the embodiments of apparatus and processes described above with reference to Figures 1 to 1 lf .

The intermediate casing 1530 may be coupled to the outer casing 1520 or the thick-walled casing 1510. In a preferred embodiment, the intermediate casing 1530 is coupled to the thick-walled casing 1510. The intermediate casing 1530 may be fabricated from any of several conventional and commercially available pipe parts, modified according to the information in the present description. In a preferred embodiment, the intermediate casing 1530 comprises any of the expandable tubular parts described above with reference to Figures 1 to 1 ff.

In a preferred embodiment, the intermediate casing 1530 is coupled to the thick-walled casing 1510 by expanding at least a portion of the intermediate casing 1530 into contact with the inner surface of the thick-walled casing 1510 using any of the processes and apparatus described above with reference to Figures 1 to 11 f. In an alternative preferred embodiment, the entire length of the overlap in the intermediate casing with the thick-walled casing 1510 is in contact with the inner surface of the thick-walled casing 1510. The contact pressure at the interface between the intermediate casing 1530 and the thick-walled casing 1510 may be in the range of about 500 to 10,000 psi. In a preferred embodiment, the contact pressure between the intermediate casing 1530 and the thick-walled casing 1510 is in the range of about 500 to 10,000 psi to optimally activate the pressure-activated sealing members and optimally ensure that the joint will withstand typical extreme tensile and compressive loads encountered during drilling and production operations.

As illustrated in Figure 13, in a particularly preferred embodiment, the upper end of the intermediate casing 1530 comprises one or more sealing parts 1560 which provide a gas and fluid seal between the expanded end of the intermediate casing 1530 and the inner wall of the thick-walled casing 1510. The sealing parts 1560 may comprise any of conventional, commercially available gaskets such as e.g. plastic, lead, rubber, Teflon or epoxy, modified according to the information in the present description. In a preferred embodiment, the sealing members comprise 1560 gaskets cast from StrataLock epoxy available from Halliburton Energy Services, to optimally form a hydraulic seal and a load-bearing interface fit between the pipe members.

In a preferred embodiment, the contact pressure of the interface between the expanded end of the intermediate casing 1530 and the thick-walled casing 1510 is in the range of about 500 to 10,000 psi to optimally activate the sealing members 1560, and also optimally to ensure that the joint will withstand typical operating extremes of tensile and compressive loads encountered during drilling and production operations.

The inner casing 1535 may be coupled to the outer casing 1520 or the thick-walled casing 1510. In a preferred embodiment, the inner casing 1535 is coupled to the thick-walled casing 1510. The inner casing 1535 may be made of any of several conventional, commercially available pipe parts, modified according to the information in the present description. In a preferred embodiment, the inner casing 1535 comprises any of the expandable pipe parts described above with reference to figures 1 to 1 ff.

In a preferred embodiment, the inner casing 1535 is connected to the outer casing 1520 by expanding at least a portion of the inner casing 1535 into contact with the inner surface of the thick-walled casing 1510 using any of the processes and apparatus described above with reference to Figures 1 to 11f. In an alternative preferred embodiment, the entire length of overlap of the inner casing 1535 with the thick-walled casing 1510 and the intermediate casing 1530 is in contact with the inner surface of the thick-walled casing 1510 and the intermediate casing 1530. The contact pressure of the interface between the inner casing 1535 and the thick-walled casing 1510 can e.g. range from about 500 to 10,000 psi. In a preferred embodiment, the contact pressure between the inner casing 1535 and the thick-walled casing 1510 ranges from about 500 to 10,000 psi to optimally activate the pressure-activated sealing members and to ensure that the joint will withstand typical extreme tensile and compressive loads commonly encountered. during drilling and production operations.

As illustrated in Figure 13, in a particularly preferred embodiment, the upper end of the inner casing 1535 comprises one or more sealing parts 1570 which provide a gas and fluid seal between the expanded end of the inner casing 1535 and the inner wall of the thick-walled casing 1510. The sealing parts 1570 may comprise any of conventional and commercially available seals such as e.g. lead, plastic, rubber, Teflon or epoxy, modified according to the information in the present description. In a preferred embodiment, the sealing members comprise 1570 gaskets cast from StrataLock epoxy available from Halliburton Energy Services, to optimally form a hydraulic seal and a load bearing interference fit.

In a preferred embodiment, the contact pressure of the interface between the expanded end of the inner casing 1535 and the thick-walled casing 1510 ranges from about 500 to 10,000 psi to optimally activate the sealing members 1570 and also optimally ensure that the joint will withstand typical operating extremes of tensile and compressive loads encountered during drilling and production operations.

In an alternative embodiment, the inner casings 1520, 1530 and 1535 may be coupled to a previously located tubular member which in turn is coupled to the outer casing 1510. More generally, the presently preferred embodiments may be used to form a concentric arrangement of tubular members .

Reference is now made to Figures 14a, 14b, 14c, 14d, 14e and 14f. A preferred embodiment of a method and apparatus for forming a mono-diameter well casing in an underground formation will now be described.

As illustrated in Figure 14a, a wellbore 1600 is located in an underground formation 1605. A first section of casing 1610 is formed in the wellbore 1600. The first section of casing 1610 comprises an annular cement outer body 1615 and a tubular section of a casing. 1620. The first section of casing 1620 may be formed in the wellbore 1600 using conventional methods and apparatus. In a preferred embodiment, the first section of casing 1610 is formed using one or more of the methods and apparatus described above with reference to Figures 1 to 13 or below with reference to Figures 14b to 17b.

The annular cement body 1615 may comprise any of several conventional, commercially available cements or other load bearing compositions. Alternatively, the body of cement 1615 may be omitted or replaced with an epoxy compound.

The tubular section of the casing 1620 preferably comprises an upper end 1625 and a lower end 1630. The lower end 1625 of the tubular section of the casing 1620 preferably comprises an outer annular recess 1635 extending from the lower end 1630 of the tubular section of the casing 1620. On this manner, the lower end of the casing section 1620 comprises a thin-walled section 1640.1 a preferred embodiment, an annular body 1665 of a compressible material is coupled to and at least partially located within the outer annular recess 1635. In this manner, the body of compressible material 1645 surrounds at least a portion of the thin-walled section 1640.

The tubular section of liner 1620 may be fabricated from any of several conventional, commercially available materials, such as Oilfield Country pipe stock, stainless steel, automotive grade steel, carbon steel, low alloy steel, fiberglass or plastic materials. In a preferred embodiment, the tubular section of liner 1620 is fabricated from Oilfield Country tubular stock available from various foreign and domestic steel mills. The wall thickness of the thin-walled section 1640 may range from about 0.125 to 1.5 inches. In a preferred embodiment, the wall thickness of the thin-walled section 1640 is in the range of 0.25 to 1.0 inches to optimally provide a breaking strength for typical operating conditions while also minimizing resistance to radial expansion. The axial length of the thin-walled section 1640 may range from about 120 to 2,400 inches. In a preferred embodiment, an axial length of the thin-walled section 1640 is in the range of about 240 to 480 inches.

The annular body of compressible material 1645 helps to minimize the radial force required to expand the tubular liner 1620 in overlap with the tubular member 1715, helps to create a fluid seal in the overlap with the tubular member 1715, and helps to create a interference fit sufficient to allow the tubing member 1715 to be supported by the casing 1620. The annular body of compressible material 1645 may comprise any of several commercially available compressible materials such as epoxy, rubber, Teflon, plastic or lead pipe. In a preferred embodiment, the annular body of compressible material includes 1645 StrataLock epoxy available from Halliburton Energy Services to optimally produce a hydraulic seal in the overlap joint, which also has elasticity to thereby minimize the radial force required to expand it tubular lining. The wall thickness of the annular body of compressible material 1645 may range from 0.05 to 0.75 inches. In a preferred embodiment, the wall thickness of the annular body of compressible material 1646 ranges from about 0.1 to 0.5 inches to optimally produce a large compressible zone, minimize the radial force required to expand the tubular liner, and providing thickness for casing strings to contact the inner surface of the wellbore after radial expansion, and to provide a hydraulic seal.

As illustrated in Figure 14b, to extend the wellbore 1600 into the subterranean formation 1605, a drill string is used in a well-known manner to drill out materials from the subterranean formation 1605 to form a new wellbore section 1650. The diameter of the new section 1650 is preferably equal to or greater than the inner diameter of the pipe section of casing 1620.

As illustrated in Figure 14c, a preferred embodiment of the apparatus 1700 for forming a monodiameter wellbore casing in a subterranean formation is then placed in the new section 1650 of the wellbore 1600. The apparatus 1700 preferably comprises a support member 1705, an expandable spindle or spike 1710 , a pipe part 1715, a shoe 1720, support wedges 1725, a fluid passage 1730, one or more fluid passages 1735, a fluid passage 1740, a first compressible annular body 1745, a second compressible annular body 1750, and a pressure chamber 1755.

The support part 1705 supports the apparatus 1700 inside the wellbore 1600. The support part 1705 is connected to the spindle 1710, the pipe part 1715, the shoe 1720, and the support wedges 1725. The support part 1075 preferably comprises a mainly hollow tubular part. The fluid passage 1730 is placed inside the support part 1705. The fluid passage 1735 forms a fluid connection between the passage 1730 and the pressure chamber 1755. The fluid passage 1740 forms a fluid connection between the fluid passage 1730 and the area outside the apparatus 1700.

The support member 1705 may be made of any of several conventional and commercially available materials, such as, for example, oilfield tubing, stainless steel, low alloy steel, carbon steel, 13 chrome steel, fiberglass or other high strength materials. In a preferred embodiment, the support member 1705 is fabricated from oilfield tubular stock available from various foreign and domestic steel mills, to optimally provide operational strength and to facilitate the use of other standard oil exploration handling equipment. In a preferred embodiment, at least a part of the support part 1705 comprises coiled pipe or a drill pipe. In a particularly preferred embodiment, the support part 1705 comprises a load shoulder 1820 to support the spindle 1710 when the pressure chamber 1755 is without pressure.

The spindle 1710 is supported by and slidably connected to the support part 1705 and the shoe 1720. The spindle 1710 preferably comprises an upper part 1760 and a lower part 1765. The upper part 1760 of the spindle 1710 and the support part 1705 together preferably define the thick chamber 1755. The lower part 1765 of the spindle 1710 preferably comprises an expansion part 1770 for radial expansion of the pipe part 1715.

In a preferred embodiment, the upper part 1760 of the spindle 1710 comprises a tubular part 1755 with an inner diameter that is larger than the outer diameter of the support part 1705. In this way, an annular pressure chamber 1755 is defined by and located between the tubular part 1755 and the support part 1705. The top 1780 of the pipe part 1775 preferably comprises a bearing and seal to seal and support the top 1780 of the pipe part 1775 against the outer surface of the support part 1705. The bottom 1785 of the pipe part 1775 preferably comprises a bearing and a seal to seal and support the bottom 1785 of the pipe part 1775 against the outer surface of the support part 1705 or the shoe 1720. In this way, the spindle 1710 will move in the axial direction when the pressure chamber 1755 comes under pressure.

The lower part 1765 of the spindle 1710 preferably comprises an expansion part 1770 for radial expansion of the tube part 1715 during pressure supply to the pressure chamber 1755. In a preferred embodiment, the expansion part is expandable in the radial direction. In a preferred embodiment, the inner surface of the lower portion 1765 of the spindle 1710 is matched with and slides relative to the outer surface of the shoe 1720. The outer diameter of the expansion portion 1770 may range from about 90 to 100% of the inner diameter of the casing 1620. In a preferred embodiment, the outer diameter of the expansion member 1770 ranges from about 95 to 99% of the inner diameter of the casing 1620. The expansion member 1770 can be made of any of several conventional and commercially available materials, such as e.g. machine tool steel, ceramic, tungsten carbide, titanium or other high strength materials. In a preferred embodiment, the expansion part 1770 is manufactured from D2 machine tool steel to optimally provide high strength and aberration resistance.

The pipe part 1715 is connected to and supported by the support part 1705 and the support wedges 1725. The tubular part 1715 comprises an upper part 1790 and a lower part 1795. The upper part 1790 of the pipe part 1715 preferably comprises an inner annular recess 1800 which extends from the upper part 1790 of the tube portion 1715. In this way, at least a portion of the upper portion 1790 of the tube portion 1715 comprises a thin-walled section 1805. The first compressible annular portion 1745 is preferably connected to and supported by the outer surface of the upper portion 1790 of the pipe section 1715 in an opposite relationship to the thin wall section 1805.

The lower portion 1795 of the tube portion 1715 preferably comprises an outer annular recess 1710 extending from the lower portion 1790 of the tube portion 1715. In this way, at least a portion of the lower portion 1795 of the tube portion 1715 includes a thin-walled section 1815. second compressible annular portion 1750 is coupled to and at least partially supported within the outer annular recess 1810 of the upper portion 1790 of the tube portion 1715 opposite the thin wall section 1815.

The tube part 1715 can be made from any of several conventional and commercially available materials, such as, for example, oil field tubing, stainless steel, low alloy steel, carbon steel, automotive grade steel, fiberglass, 13 chrome steel or other high strength materials, or high strength plastic. In a preferred embodiment, the pipe section 1715 is made from oil field pipe stock available from various foreign and domestic steel mills, to optimally provide operational strength.

The shoe 1720 is supported by and connected to the support part 1705. The shoe 1720 preferably comprises an essentially hollow tubular part. In a preferred embodiment, the wall thickness of the shoe 1720 is greater than the wall thickness of the support portion 1705 to optimally provide increased radial support to the spindle 1710. The shoe 1720 can be manufactured from any of several conventional and commercially available materials, such as oil field pipe stock, stainless steel, automotive grade steel, low alloy steel, carbon steel or high strength plastic. In a preferred embodiment, the shoe 1720 is made from oilfield tubular stock available from various foreign and domestic steel mills to optimally produce appropriate operating strength throughout the apparatus.

The stop wedges 1725 are connected to and supported by the support member 1705. The wedges 1725 removably support the pipe member 1715. In this way, during radial expansion of the pipe member 1715, the stop wedges 1725 help to hold the pipe members 1715 in a substantially stationary position by preventing upward movement of the pipe member 1715.

The stop wedges 1725 may comprise any of several conventional and commercially available wedges, such as e.g. RTTS Gasket Tungsten Carbide Mechanical Wedges, RTTS Gasket Braided Type Mechanical Wedges, or Model 3L Retrievable Bridge-Plug Tungsten Carbide Upper Mechanical Wedges. In a preferred embodiment, the stop wedges comprise 1725 RTTS packing tungsten carbide mechanical wedges available from Halliburton Energy Services. In a preferred embodiment, the stop wedges 1725 are adapted to support axial forces in the range of about 0 to 750,000 pounds.

The fluid passage 1730 conducts liquid materials from a location on the surface into the interior of the support part 1705, the pressure chamber 1755 and the area outside the apparatus 1700. The fluid passage 1730 is fluidly coupled to the pressure chamber 1755 at the fluid passage 1735. The fluid passage 1730 is fluidly coupled to the area outside the apparatus 1700 at the fluid passage 1740.

In a preferred embodiment, the fluid passage 1730 is adapted to conduct liquid materials such as e.g. cement, epoxy, drilling mud, slag mixture, water or drilling gases. In a preferred embodiment, the fluid passage 1730 is adapted to conduct liquid material at flow rates and pressures in the range of about 0 to 3,000 gallons per minute and 0 to 9,000 psi to optimally produce flow rates and operating pressures for the radial expansion processes.

The fluid passages 1735 conduct liquid materials from the fluid passage 1730 to the pressure chamber 1755. In a preferred embodiment, the fluid passage 1735 is adapted to conduct liquid materials such as e.g. cement, epoxy, drilling mud, water or drilling gases. In a preferred embodiment, the fluid passage 1735 is adapted to conduct liquid materials at flow rates and pressures ranging from about 0 to 500 gallons per minute and 0 to 9,000 psi to optimally produce operating pressures and flow rates for the various expansion processes.

The fluid passage 1740 conducts liquid materials from the fluid passage 1730 to the area outside the apparatus 1700. In a preferred embodiment, the fluid passage 1740 is adapted to conduct liquid materials such as e.g. cement, epoxy, drilling mud, water or drilling gases. In a preferred embodiment, the fluid passage 1740 is adapted to conduct liquid materials at flow rates and pressures in the range of 0 to 3,000 gallons per minute and 0 to 9,000 psi to optimally produce operating pressures and flow rates for the various radial expansion processes.

In a preferred embodiment, the fluid passage 1740 is adapted to receive a plug or other similar device to seal the fluid passage 1740. In this way, the pressure chamber 1755 can be pressurized.

The first compressible annular body 1745 is connected to and supported by the outer surface of the upper portion 1790 of the pipe section 1715. In a preferred embodiment, the first compressible annular body 1745 is positioned opposite the thin-walled section 1805 of the pipe section 1715.

The first compressible annular body 1745 helps to minimize the radial force required to expand the tubular member 1715 in overlap with the casing 1620, helps to create a fluid seal in overlap with the casing 1620, and helps to create an interference fit that is sufficient to allow the pipe member 1715 to be supported by the casing 1620. The first compressible annular body 1745 may comprise any of several commercially available compressible materials, such as epoxy, rubber, Teflon, plastic or hollow lead pipes. In a preferred embodiment, the first compressible annular body comprises 1745 StrataLock epoxy available from Halliburton Energy Services to optimally produce a hydraulic seal, and compressibility to minimize the radial expansion force.

The wall thickness of the first compressible annular body 1745 may range from 0.05 to 0.75 inches. In a preferred embodiment, the wall thickness of the first compressible annular body 1745 is in the range of about 0.1 to 0.5 inches to optimally (1) produce a large compression zone, (2) minimize the required radial expansion force, (3) to transfer the radial force to the casings. As a result, in a preferred embodiment, the overall outer diameter of the tube portion 1715 is approximately equal to the overall inner diameter of the tube portion 1620.

The second compressible annular body 1750 is connected to and at least partially supported inside the outer annular recess 1810 of the pipe part 1715. In a preferred embodiment, the second compressible annular body 1750 is positioned opposite the thin-walled section 1815 of the pipe part 1715.

The second compressible annular body 1750 helps to minimize the radial force required to expand the tubular member 1715 in overlap with another tubular member, helps to create a fluid seal in the overlap of the tubular member 1715 with another tubular member, helps to create an interference fit sufficient to allow another pipe member to be supported by the pipe member 1715. The second compressible annular body 1750 may comprise any of several commercially available compressible materials, such as epoxy, rubber, Teflon, plastic or hollow lead pipes. In a preferred embodiment, the first compressible annular body includes 1750 StrataLock epoxy available from Halliburton Energy Services to optimally produce a hydraulic seal in the overlap joint, and compressibility that minimizes the radial expansion force.

The wall thickness of the second compressible annular body 1750 may range from about 0.05 to 0.75 inches. In a preferred embodiment, the wall thickness of the second compressible annular body 1750 is in the range of about 0.1 to 0.5 inches to optimally produce a large compressible zone, and to minimize the radial force required to expand the tube portion 1715 below later radial expansion operations.

In an alternative embodiment, the outer diameter of the second compressible annular body 1750 is adapted to provide a seal against its surrounding formation thereby eliminating the need for an outer cement annular body.

The pressure chamber 1755 is fluidly connected to the fluid passage 1730 at the fluid passage 1735. The pressure chamber 1755 is preferably adapted to receive liquid material, such as e.g. drilling mud, water or drilling gases. In a preferred embodiment, the pressure chamber 1755 is adapted to receive liquid materials at flow rates and pressures in the range of about 0 to 500 gallons per minute and 0 to 9,000 psi, to optimally produce expansion pressure. In a preferred embodiment, during the pressure supply to the pressure chamber 1755, the operating pressure of the pressure chamber is in the range of about 0 to 5,000 psi to optimally generate expansion pressure while minimizing the possibility of a catastrophic failure due to overpressure.

As illustrated in figure 14d, the apparatus 1700 is preferably placed in the wellbore 1600 with the pipe part 1715 placed in an overlapping relationship with the casing pipe 1620.1 a particularly preferred embodiment, the thin wall sections 1640 and 1805 of the casing pipe 1620 and the pipe part 1725 are placed in an opposite overlapping relationship. In this way, radial expansion of the tube portion 1725 will compress the thin-walled sections 1640 and 1805, and the annular compressible portions 1645 and 1745, into close contact.

After placing the apparatus 1700, a liquid material 1825 is pumped into the fluid passage 1730. The liquid material 1825 may comprise any of several conventional, commercially available materials, such as, for example, water, drilling mud, drilling gas, cement or epoxy. In a preferred embodiment, the liquid material comprises a hardenable liquid sealing material such as e.g. cement, to form an outer annular body around the expanded tube part 1715.

The liquid material 1825 can be pumped into the fluid passage 1730 at operating pressures and flow rates such as e.g. ranges from 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The liquid material 1825 that is pumped into the fluid passage 1730 passes through the fluid passage 1740 and outside the apparatus 1700. The liquid material 1825 fills the annulus 1830 between the outside of the apparatus 1700 and the inner wall of the wellbore 1600.

As illustrated in Figure 14e, a plug 1835 is then inserted into the fluid passage 1730. The plug 1835 attaches to the inlet of the fluid passage 1740 and fluid isolates and blocks the fluid passage 1730.

A liquid material 1840 is then pumped into the fluid passage 1730. The liquid material 1840 may comprise any of several conventional and commercially available materials, such as e.g. water, drilling mud or drilling gases. In a preferred embodiment, the liquid material 1825 comprises a non-curable liquid material such as e.g. drilling mud or drilling gases, to optimally create pressure in the pressure chamber 1755.

The liquid material 1840 can be pumped into the fluid passage 1730 at operating pressures and flow rates, e.g. ranging from 0 to 9,000 psi and 0 to 500 gallons per minute. In a preferred embodiment, the liquid material 1840 is pumped into the fluid passage 1730 at operating pressures and flow rates ranging from about 500 to 5,000 psi and 0 to 500 gallons per minute to optimally produce operating pressures and flow rates for radial expansion.

The liquid material 1840 that is pumped into the fluid passage 1730 passes through the fluid passage 1735 and into the pressure chamber 1755. Continued pumping of the liquid material 1840 pressurizes the pressure chamber 1755. The pressure input in the pressure chamber 1755 causes the spindle 1710 to move relative to the support member 1705 in sealing as indicated by the arrows 1845. In this way, the spindle 1710 will cause the tube member 1715 to expand in the radial direction.

During the radial expansion process, the tubular portion 1715 is prevented from moving in an upward direction by the stop wedges 1725. A length of the tubular portion 1715 is then expanded in the radial direction through pressure supply to the pressure chamber 1755. The length of the tubular portion 1715 that is expanded during the expansion process will be proportional to the stroke length of the spindle 1710. After the completion of a stroke, the operating pressure of the pressure chamber 1755 will be reduced, and the spindle 1710 falls to its rest position with the tube part 1715 supported by the spindle 1715. The position of the support part 1705 can be adjusted throughout the radial expansion process to keep the overlapping relationship between the thin-walled sections 1640 and 1805 of the casing 1620 and the casing 1715. The stroke of the spindle 1710 is repeated as necessary, until the thin-walled section 1805 of the casing 1715 is expanded into the thin-walled section 1640 of the casing 1620.

In a preferred embodiment, during the last stroke of the spindle 1710, the stop wedges 1725 are placed as close as possible to the thin-walled section 1805 of the tubular member 1715 to minimize slippage between the tubular member 1715 and the casing 1620 at the end of the radial expansion process. Alternatively or additionally, the outer diameter of the first compressible annular portion 1745 is selected to ensure sufficient interference fit with the casing 1620 to prevent axial displacement of the tubular portion 1715 during the final stroke. Alternatively or additionally, the outer diameter of the second compression-shaped body 1750 is large enough to provide an interference fit with the inner walls of the wellbore 1600 at an earlier point in the radial expansion process to prevent further axial displacement of the pipe member 1715.1 this final alternative, the interference fit is preferably chosen to allow expansion of the pipe section 1715 by pulling the spindle 1710 out of the wellbore 1600, without having to add pressure to the pressure chamber 1755.

During the radial expansion process, the areas under pressure of the apparatus 1700 are limited to the fluid passages 1730 with the support part 1705 and the pressure chamber 1755 inside the spindle 1710. No fluid pressure acts directly on the pipe part 1715. This allows the use of operating pressures that are higher than the pipe part 1715 could normally withstand.

As soon as the pipe member 1715 is fully expanded from the mandrel 1710, the support member 1705 and the mandrel 1710 are removed from the wellbore 1600. In a preferred embodiment, the contact pressure between the deformed thin wall sections 1640 and 1805, and compressible annular members 1645 and 1745, is in the range of about 400 to 10,000 psi to optimally support the tubular member 1715 using the casing 1620. In this manner, the tubular member 1715 is radially expanded into contact with the casing 1620 by applying pressure to the interior of the fluid passage 1730 and the pressure chamber 1755.

As illustrated in Figure 14f, in a preferred embodiment, as soon as the pipe member 1715 is fully expanded in the radial direction at the spindle 1710, the support member 1705 and the spindle 1710 are removed from the wellbore 1600. In a preferred embodiment, the annular body of curable liquid material is then allowed to harden to form a rigid outer annular body 1850. In the case where the pipe member 1715 is slotted, the curable liquid material will preferentially penetrate and surround the expanded pipe member 1715.

The resulting new section of wellbore casing 1855 comprises the expanded tubular section 1715 and the rigid outer annular body 1850. The overlap joint 1860 between the casing 1620 and the expanded tubular section 1715 comprises the deformed thin wall sections 1640 and 1805, and the compressible annular bodies 1645 and 1745. The inner diameter of the resulting combined wellbore casings is essentially constant. In this way, a monodiameter wellbore casing is formed. This process of expanding overlapping pipe sections having thin-walled end regions with compressible annular bodies in contact can be repeated for the entire length of the wellbore. In this way, a monodiameter wellbore casing can be produced for thousands of feet in a subterranean formation.

Reference is now made to Figures 15, 15a and 15b, where an embodiment of the apparatus 1900 for expanding a tubular part will be described. The apparatus 1900 preferably comprises a drill pipe 1905, an inner string adapter 1910, a sealing sleeve 1915, an inner sealing spindle 1920, an upper sealing head 1925, a lower sealing head 1930, an outer sealing spindle 1935, a load spindle 1940, an expansion cone 1945, a spindle starter 1950, a mechanical wedge body 1955, mechanical stop wedges 1960, drag blocks 1965, casing 1970, and fluid passages 1975, 1980, 1985 and 1990.

The drill pipe 1905 is connected to the inner string adapter 1910. During operation of the apparatus 1900, the drill string 1905 supports the apparatus 1900. The drill pipe 1905 preferably mainly comprises one or more hollow pipe parts. The drill pipe 1905 can be made from any of several conventional, commercially available materials, such as, for example, oil field drill pipe, fiberglass or coiled pipe. In a preferred embodiment, the drill pipe 1905 is made of coiled pipe to facilitate placement of the apparatus 1900 in non-vertical wellbores. The drill pipe 1905 may be coupled to the inner string adapter 1910 using any of several conventional and commercially available mechanical couplings, such as e.g. drill pipe couplings, OCTG specialty type box and pin couplings, a ratchet-lock type coupling or a standard box and pin coupling. In a preferred embodiment, the drill pipe 1905 is removably connected to the inner string adapter 1910 with a drill pipe coupling.

The drill pipe 1905 preferably comprises a fluid passage 1975 which is adapted to guide liquid materials from a location on the surface into the fluid passage 1980. In a preferred embodiment, the fluid passage 1975 is adapted to guide liquid materials such as e.g. cement, drilling mud, epoxy or lubricant at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The inner string adapter 1910 is connected to the drill string 1905 and the sealing sleeve 1915. The inner string adapter 1910 preferably comprises a substantially hollow tubular part or parts. The inner string adapter 1910 can be made from any of several conventional, commercially available materials such as oil field pipe stock, low alloy steel, carbon steel, stainless steel or other high strength materials. In a preferred embodiment, the inner string adapter 1910 is manufactured from oil field tubular stock to optimally produce mechanical properties closely matched to the drill string 1905.

The inner string adapter 1910 may be coupled to the drill string 1905 using any of several conventional and commercially available mechanical couplings, such as drill pipe couplings, oil field tubing specialty type threaded couplings, ratchet-lock type plug couplings, or a standard threaded connection. In a preferred embodiment, the inner string adapter 1910 is removably coupled to the drill string 1905 with a drill pipe coupling. The inner string adapter 1910 may be coupled to the seal sleeve 1915 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing special type threaded coupling, ratchet type plug couplings, or a standard threaded connection. In a preferred embodiment, the inner string adapter 1910 is removably coupled to the seal sleeve 1915 with a standard threaded connection.

The inner string adapter 1910 preferably comprises a fluid passage 1980 which is adapted to guide liquid materials from the fluid passage 1975 into the fluid passage 1985. In a preferred embodiment, the fluid passage 1980 is adapted to guide liquid materials such as e.g. cement, drilling mud, epoxy, or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The sealing sleeve 1915 is connected to the inner string adapter 1910 and the inner sealing spindle 1920. The sealing sleeve 1915 preferably mainly comprises one or more tubular parts.

The sealing sleeve 1915 can be made from any of several conventional, commercially available materials such as e.g. oil field pipe stock, carbon steel, low alloy steel, stainless steel or other high strength materials. In a preferred embodiment, the sealing sleeve 1915 is made from oilfield tubular goods to optimally produce mechanical properties which are mainly adapted to the other components of the apparatus 1900.

The sealing sleeve 1915 may be coupled to the inner string adapter 1910 using any of several conventional, commercially available mechanical couplings such as drill pipe couplings, oilfield tubing special threaded couplings, ratchet-lock type plug-in coupling, or a standard threaded connection. In a preferred embodiment, the sealing sleeve 1915 is removably coupled to the inner string adapter 1910 with a standard threaded connection. The sealing sleeve 1915 may be coupled to the inner sealing spindle 1920 using any of several conventional and commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty types threaded connection, or a standard threaded connection. In a preferred embodiment, the seal sleeve 1915 is removably coupled to the inner seal spindle 1920 by a standard threaded connection.

The sealing sleeve 1915 preferably comprises a fluid passage 1985 which is adapted to guide liquid materials from the fluid passage 1980 into the fluid passage 1990. In a preferred embodiment, the fluid passage 1985 is adapted to guide liquid materials such as e.g. cement, drilling mud, epoxy or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The inner sealing spindle 1920 is connected to the sealing sleeve 1915 and the lower sealing head 1930. The inner sealing spindle 1920 preferably comprises one or more essentially hollow tubular parts. The inner seal spindle 1920 may be made of any of several conventional, commercially available materials, such as, for example, oilfield tubular goods, stainless steel, low alloy steel, carbon steel or other similar high strength materials. In a preferred embodiment, the inner seal spindle 1920 is made of stainless steel to optimally produce mechanical properties similar to the other components of the apparatus 1900, while providing a smooth outer surface to support gaskets and other moving parts that can operate with minimum wear, corrosion and corrosion.

The inner seal spindle 1920 may be coupled to the seal sleeve 1915 using any of several conventional, commercially available mechanical couplings such as, for example, drill pipe coupling, oilfield-pipeline specialty pipe threaded connection, or a standard threaded connection. In a preferred embodiment, the inner seal spindle 1920 is removably coupled to the seal sleeve 1915 by a standard threaded connection. The inner seal spindle 1920 may be coupled to the lower seal head 1930 using any of several conventional commercially available mechanical couplings such as drill pipe coupling, oilfield pipe specialty type threaded connection, ratchet-lock type plug connections with standard threaded connections. In a preferred embodiment, the inner seal spindle 1920 is removably coupled to the lower seal head 1930 by a standard threaded coupling connection.

The inner seal spindle 1920 preferably comprises a fluid passage 1990 which is adapted to guide liquid materials from the fluid passage 1985 into the fluid passage 1995. In a preferred embodiment, the fluid passage 1990 is adapted to guide liquid materials such as e.g. cement, drilling mud, epoxy or lubricant at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The upper sealing head 1925 is coupled to the outer sealing spindle 1935 and the expansion cone 1945. The upper sealing head 1925 is also movably coupled to the outer surface of the inner sealing spindle 1920 and the inner surface of the casing 1970. In this way, the upper sealing head 1925, the outer sealing spindle 1935 and the expansion cone 1945 reciprocate in the axial direction. The radial clearance between the inner cylindrical surface of the upper seal head 1925 and the outer surface of the inner seal spindle 1920 can e.g. be in the range of about 0.025 to 0.05 inches. In a preferred embodiment, the radial clearance between the inner cylindrical surface of the upper seal head 1925 and the outer surface of the inner seal spindle 1920 is in the range of about 0.005 to 0.1 inches to optimally provide clearance for pressure seal placement. The radial clearance between the outer cylindrical surface of the upper sealing head 1925 and the inner surface of the casing 1970 can e.g. range from about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer cylindrical surface of the upper seal head 1925 and the inner surface of the casing 1970 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 1945 as the expansion cone 1945 moves upwardly inside in the casing 1920.

The upper sealing head 1925 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The upper seal head can be made from any of several conventional commercially available materials, such as e.g. oil field tubular goods, stainless steel, machine tool steel or similar high-strength materials. In a preferred embodiment, the upper seal head 1925 is manufactured from stainless steel to optimally produce high strength and smooth outer surfaces that are resistant to wear, corrosion and corrosion.

The inner surface of the upper sealing head 1925 preferably comprises one or more annular sealing parts 2000 for sealing the interface between the upper sealing head 1925 and the inner sealing spindle 1920. The sealing part 2000 may comprise any of several conventional commercially available annular sealing parts, such as e.g. o-rings, polypack seals or metal spring-energized seals. In a preferred embodiment, the sealing part comprises 2000 polypak gaskets available from Parker Seals, to optimally produce a seal for a long axial movement.

In a preferred embodiment, the upper seal head 1925 includes a shoulder 2005 for supporting the upper seal head 1925 on the lower seal head 1930. The upper seal head 1925 may be coupled to the outer seal spindle 1935 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, or a standard threaded connection. In a preferred embodiment, the seal head 1925 is removably coupled to the outer seal spindle 1935 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the upper sealing head 1925 and the outer sealing spindle 1935 comprises one or more sealing parts 2010 for fluid sealing of the interface between the upper sealing head 1925 and the outer sealing spindle 1935. The sealing parts 2010 may comprise any of several conventional, commercially available sealing parts such as e.g. o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing part 2010 comprises polypak gaskets from Parker Seals, to optimally produce a seal for a long axial ironing movement.

The lower seal head 1930 is coupled to the inner seal spindle 1920 and the load spindle 1940. The lower seal head 1930 is also movably coupled to the inner surface of the outer seal spindle 1935. In this way, the upper seal head 1925 and the outer seal spindle 1935 will reciprocate in axial direction. The radial clearance between the outer surface of the lower sealing head 1930 and the inner surface of the outer sealing spindle 1935 can e.g. range from about 0.025 to 0.05 inches. In a preferred embodiment, the radial clearance between the outer surface of the lower seal head 1930 and the inner surface of the outer seal spindle 1935 is in the range of about 0.005 to 0.010 inches to optimally produce a tight tolerance that accommodates the installation of pressure seal rings.

The lower seal head 1930 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The lower seal head 1930 may be fabricated from any of several conventional and commercially available materials, such as oil field pipe material, stainless steel, machine tool steel and other similar high strength materials. In a preferred embodiment, the lower seal head 1930 is manufactured from stainless steel to optimally produce high strength and resistance to wear, corrosion and corrosion.

The outer surface of the lower sealing head 1930 preferably comprises one or more annular sealing parts 2015 to seal the interface between the lower sealing head 1930 and the outer sealing spindle 1935. The sealing parts 2015 may comprise any of several conventional, commercially available annular sealing parts, such as e.g. o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing part 2015 includes polypak gaskets available from Parker Seals, to optimally produce a seal for a long axial stroke.

The lower seal head 1930 may be coupled to the inner seal spindle 1920 using any number of conventional commercially available mechanical couplings, such as drill pipe couplings, oil field pipe specialty type threaded connections, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the lower seal head 1930 is removably coupled to the inner seal spindle 1920 by a standard threaded connection.

In a preferred embodiment, the mechanical connection between the lower sealing head 1930 and the inner sealing spindle 1920 comprises one or more sealing parts 2020 for fluid sealing of the interface between the lower sealing head 1930 and the inner sealing spindle 1920. The sealing part 2020 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing part 2020 comprises polypak gaskets available from Parker Seals, to optimally produce a seal for a long axial movement.

The lower seal head 1930 may be coupled to the load spindle 1940 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connections, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the lower seal head 1930 is removably coupled to the load spindle 1940 by standard threaded connection. In a preferred embodiment, the mechanical coupling between the lower seal head 1930 and the loading spindle 1940 comprises one or more sealing members 2025 for fluid sealing of the interface between the lower sealing head 1930 and the loading spindle 1940. The sealing member 2025 may comprise any of several conventional, commercially available sealing parts such as e.g. o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing parts 2025 comprise polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial movement.

In a preferred embodiment, the lower seal head comprises a throat passage 2040 which is fluidly coupled between the fluid passages 1990 and 1995. The throat passage 2040 is preferably of reduced size, and adapted to receive and engage with a plug 2045 or other similar device. In this way, the fluid passage 1990 is fluid-isolated from the fluid passage 1995. In this way, the pressure chamber 2030 is pressurized.

The outer sealing spindle 1935 is coupled to the upper sealing head 1925 and the expansion cone 1945. The outer sealing spindle 1935 is also movably coupled to the inner surface of the casing 1970 and the outer surface of the lower sealing head 1930. In this way, the upper sealing head 1925, the outer sealing spindle 1935 and the expansion cone 1945 reciprocating in the axial direction. The radial clearance between the outer surface of the outer sealing spindle 1935 and the inner surface of the casing 1970 can e.g. range from about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer surface and the outer seal spindle 1935 and the inner surface of the casing 1970 is in the range of about 0.025 to 0.125 inches to optimally produce maximum piston surface area to maximize the radial expansion force. The radial clearance between the inner surface of the outer sealing spindle 1935 and the outer surface of the lower sealing head 1930 can e.g. range from about 0.025 to 0.05 inches. In a preferred embodiment, the radial clearance between the inner surface of the outer seal spindle 1935 and the outer surface of the lower seal head 1930 ranges from about 0.005 to 0.010 inches to optimally provide a minimum opening for seal elements to cover and seal.

The outer sealing spindle 1935 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The outer seal spindle 1935 may be made of any of several conventional, commercially available materials, such as, for example, low alloy steel, carbon steel, 13 chrome steel or stainless steel. In a preferred embodiment, the outer sealing spindle 1935 is made of stainless steel to optimally produce maximum strength and maximum wall thickness and at the same time also provide resistance to corrosion, tearing and corrosion.

The outer seal spindle 1935 may be coupled to the upper seal head 1925 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, standard threaded connections, or welding. In a preferred embodiment, the outer seal spindle 1935 is removably coupled to the upper seal head 1925 by a standard threaded connection. The upper seal spindle 1935 may be coupled to the expansion cone 1945 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, or standard threaded connection, or welding. In a preferred embodiment, the outer seal spindle 1935 is removably coupled to the expansion cone 1945 by a standard threaded connection.

The upper seal head 1925, the lower seal head 1930, the inner seal spindle 1920, and the outer seal spindle 1935 together define a pressure chamber 2030. The pressure chamber 2030 is fluidly coupled to the passage 1990 via one or more passages 2035. During operation of the apparatus 1900, the plug 2045 is in contact with the throat passage 2040 to fluid-isolate the fluid passage 1930 from the fluid passage 1995. The pressure chamber 2030 is then pressurized, which in turn causes the upper seal head 1925, the outer seal spindle 1935 and the expansion cone 1945 to reciprocate in the axial direction. The axial movement of the expansion cone 1945 in turn expands the casing 1970 in the radial direction.

The load spindle 1940 is coupled to the lower seal head 1930 and the mechanical sliding body 1955. The load spindle 1940 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The load spindle 1940 can be made of any of several conventional, commercially available materials, such as, for example, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the load spindle 1940 is manufactured from oil field pipe stock to optimally produce high strength.

The load spindle 1940 may be coupled to the lower seal head 1930 using any of several conventional commercially available mechanical couplings such as drill pipe couplings, oil field tubing specialty type threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the load spindle 1930 is removably coupled to the lower seal head 1930 by a standard threaded connection. The load spindle 1940 may be coupled to the mechanical slide 1955 using any of several conventional, commercially available mechanical couplings such as drill pipe coupling, oilfield pipe specialty type threaded connection, welding, amorphous banding or a standard threaded coupling connection. In a preferred embodiment, the load spindle 1940 is removably coupled to the mechanical slide 1955 by a standard threaded coupling connection.

The loading spindle 1940 preferably comprises a fluid passage 1995 which is adapted to guide liquid materials from the fluid passage 1990 to the area outside the apparatus 1900. In a preferred embodiment, the fluid passage 1995 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The expansion cone 1945 is coupled to the outer sealing spindle 1935. The expansion cone 1945 is also removably coupled to the inner surface of the casing 1970. In this way, the upper sealing head 1925, the outer sealing spindle 1935, and the expansion cone 1945 will reciprocate in the axial direction. The reciprocation of the expansion cone 1945 causes the casing 1970 to be expanded in the radial direction.

The expansion cone 1945 preferably comprises an annular part having essentially cylindrical inner and conical outer surfaces. The outer radius of the outer conical surface may range from about 2 to 34 inches. In a preferred embodiment, the outer radius of the outer conical surface ranges from about 3 to 28 inches to optimally produce cone dimensions for the typical range of tubular parts.

The axial length of the expansion cone 1945 can be e.g. in ranges from about 2 to 8 times the largest outer diameter of the expansion cone 1945. In a preferred embodiment, the axial length of the expansion cone 1945 is in ranges from about 3 to 5 times the largest outer diameter of the expansion cone 1945 to optimally produce stability and centralization of the expansion wife 1945 during the expansion process. In a preferred embodiment, the angle of attack of the expansion cone 1945 ranges from about 5 to 30 degrees to optimally balance frictional forces with the desired amount of radial expansion. The angle of attack of the expansion cone 1945 will vary as a function of the operating parameters for the particular expansion operation.

The expansion cone 1945 may be made of any of several conventional, commercially available materials, such as, for example, machine tool steel, ceramic, tungsten carbide, nitride steel or other similar high strength materials. In a preferred embodiment, the expansion cone 1945 is manufactured from D2 machine tool steel to optimally produce high strength and resistance to corrosion, wear, tear and corrosion. In a preferred embodiment, the outer surface of the expansion cone 1945 has a surface hardness in the range of about 58 to 62 Rockwell C to optimally produce high strength and resist wear and tear.

The expansion cone 1945 may be coupled to the outer seal spindle 1935 using any of several conventional and commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, welding, amorphous banding, or a standard threaded coupling connection. In a preferred embodiment, the expansion cone 1945 is coupled to the outer seal spindle 1935 using a standard threaded coupling connection to optimally provide coupling strength for the typical operating load conditions that also allows easy replacement of the expansion cone 1945.

The spindle starter 1950 is connected to the casing 1970. The spindle starter 1950 comprises a tubular section of casing having a reduced wall thickness compared to the casing 1970. In a preferred embodiment, the wall thickness of the spindle starter is about 50 to 100% of the wall thickness of the casing 1970. In this way, the initiation of the radial expansion of the casing 1970 is facilitated, and the insertion of the larger diameter spindle starter 1950 into the wellbore and/or the casing is facilitated.

The spindle starter 1950 may be coupled to the casing 1970 using any of several conventional commercial mechanical couplings. The spindle starter 1950 can have a wall thickness in the range from e.g. 0.15 to 1.5 inches. In a preferred embodiment, the wall thickness of the spindle starter 1950 is in the range of about 0.25 to 0.75 inches to optimally produce high strength with a small overall profile. Spindle starter 1950 can be made from any of several conventional, commercially available materials such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength material. In a preferred embodiment, the spindle-starter 1950 is made of oilfield tubular stock of high strength but lower wall thickness than the casing 1970 in order to optimally produce a thin-walled container with approximately the same breaking strength as the casing 1970. The mechanical sliding body 1955 is connected to the loading spindle 1970, the mechanical wedges 1960, and the drag blocks 1965. The mechanical sliding body 1955 preferably comprises a tubular part having an inner passage 2050 in fluid communication with the passage 1995. In this way, liquid materials can be directed from the passage 2050 to an area outside the apparatus 1900.

The mechanical slide 1955 may be connected to the load member 1940 using any of several conventional mechanical connections. In a preferred embodiment, the mechanical slide 1955 is removably coupled to the load spindle 1940 using a standard threaded connection to optimally provide high strength and to allow easy replacement of the mechanical slide 1955. The mechanical slide 1955 can be coupled to the mechanical wedges 1955 using any of several conventional mechanical couplings. In a preferred embodiment, the mechanical sliding body 1955 is removably coupled to the mechanical arrows 1955 using threaded and sliding steel retainers to optimally provide high strength couplings and also allow easy replacement of the mechanical wedges 1955. The mechanical sliding body 1955 can be coupled to the drag blocks 1965 using any of several conventional mechanical linkages. In a preferred embodiment, the mechanical slide body 1955 is removably connected to the drag blocks 1965 using threaded connections and sliding steel retaining rings to optimally provide great strength and also to allow easy replacement of the drag blocks 1965.

The mechanical wedges 1960 are coupled to the outer surface of the mechanical sliding body 1955. During operation of the apparatus 1900, the mechanical wedges 1960 will prevent upward movement of the casing 1970 and the spindle starter 1950. In this way, during the axial reciprocation of the expansion cone 1945 , the casing 1970 and the spindle starter 1950 are held in an approximately stationary position. In this way, the spindle starter 1950 and the casing 1970 are expanded in the radial direction by the axial movement of the expansion cone 1945.

The mechanical wedges 1960 may comprise any of several conventional commercially available mechanical wedges, such as RTSS Gasket, Tungsten Carbide Mechanical Wedges, RTSS Gasket Light-Type Mechanical Wedges or Model 3L Retractable Bridge-Plug Tungsten Carbide Upper Mechanical Wedges. In a preferred embodiment, the mechanical keys 1960 comprise RTTS packing tungsten carbide mechanical keys available from Halliburton Energy Services, to optimally provide resistance to axial movement of the casing 1970 during the expansion process.

The drag blocks 1965 are coupled to the outer surface of the mechanical slide body 1955. During operation of the apparatus 1900, the drag blocks 1965 will prevent upward movement of the casing 1970 and the spindle starter 1950. Thus, during the axial reciprocation of the expansion cone 1945, the casing 1970 becomes and the spindle starter 1950 held in an approximately stationary position. In this way, the spindle starter 1950 and the casing 1970 are expanded in the radial direction by the axial movement of the expansion cone 1945.

The drag blocks 1965 may comprise any of several conventional, commercially available mechanical wedges, such as RTTS Gasket Tungsten Carbide Mechanical Keys, RTTS Gasket Light Type Mechanical Keys or Model 3L Retrievable Bridge Plug Tungsten Carbide Upper Mechanical Keys. In a preferred embodiment, the drag blocks 1965 include RTTS packing tungsten carbide mechanical wedges available from Halliburton Energy Services, to optimally provide resistance to axial movement of the casing 1970 during the expansion process. The casing 1970 is connected to the spindle starter 1950. The casing 1970 is further removably connected to the mechanical wedges 1960 and the drag blocks 1965. The casing 1970 preferably comprises a tubular part. The casing 1970 can be made of any conventional, commercially available material such as e.g. slotted pipes, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the casing 1970 is manufactured from oil field pipe stock available from various foreign and domestic steel mills, to optimally produce high strength. In a preferred embodiment, the upper end of the casing 1970 comprises one or more sealing members located around the exterior of the casing 1970.

In operation, the apparatus 1900 is placed in a wellbore with an upper end of the casing 1970 positioned in an overlapping relationship within an existing wellbore casing. In order to minimize transient pressure within the borehole during placement of the apparatus 1900, the fluid passage 1975 is preferably equipped with one or more pressure release passages. During placement of the apparatus 1900 in the wellbore, the casing 1970 is supported by the expansion cone 1945.

After placing the apparatus 1900 in the wellbore in an overlapping relationship with an existing section of wellbore casing, a first fluid material is pumped into the fluid passage 1975 from a surface location. The first fluid material is directed from the fluid passage 1975 to the fluid passages 1980, 1985, 1990, 1995 and 2050. The first fluid material will then exit the apparatus and fill the annulus between the outside of the apparatus 1900 and the inner walls of the borehole.

The first liquid material may comprise any of several conventional, commercially available materials, such as e.g. drilling mud, water, epoxy or cement. In a preferred embodiment, the first liquid material comprises a curable liquid sealing material such as e.g. cement or epoxy. In this way, a wellbore casing with an outer layer of a curable material can be formed.

The first liquid material can be pumped into the apparatus 1900 at operating pressures and flow rates that are in the range of e.g. 0 to 4,500 psi and 0 to 3,000 gallons per minute. In a preferred embodiment, the first liquid material is pumped into the apparatus 1900 at operating pressures and flow rates ranging from about 0 to 4,500 psi and 0 to 3,000 gallons per minute to optimally produce operating pressures and flow rates for typical operating conditions.

At a preferred point in the injection of the first liquid material such as e.g. after the annular area outside the apparatus 1900 is filled to a predetermined level, a plug 2045, arrow or other similar device is introduced into the first liquid material. The plug 2045 presses into the throat passage 2040, to thereby fluid-isolate the first passage 1990 from the fluid passage 1995.

After placement of the plug 2045 in the throat passage 2040, another fluid material is pumped into the fluid passage 1975 to add pressure to the pressure chamber 2030. The second fluid material may comprise any of several conventional, commercially available materials, such as e.g. water, drilling gases, drilling mud or lubricant. In a preferred embodiment, the second liquid material comprises a non-curable liquid material such as e.g. water, drilling mud or lubricant, to minimize frictional forces.

The second liquid material can be pumped into the apparatus 1900 at operating pressures and flow rates in the range from e.g. 0 to 4,500 psi and 0 to 4,500 gallons per minute. In a preferred embodiment, the second liquid material is pumped into the apparatus 1900 at operating pressures and flow rates ranging from 0 to 3,500 psi and 0 to 1,200 gallons per minute to optimally produce expansion of the casing 1970.

The pressure in the pressure chamber 2030 causes the upper seal head 1925, the outer seal spindle 1935 and the expansion cone 1945 to move in the axial direction. As the expansion cone 1945 moves in the axial direction, the expansion cone 1945 pulls the spindle starter 1950 and the drag blocks 1965 with it, which sets the mechanical keys 1960 and stops further axial movement of the spindle starter 1950 and the casing 1970. In this way, the axial movement of the expansion cone 1945 radially expand the spindle starter 1950 and casing 1970. As soon as the upper seal head 1925, outer seal spindle 1935 and expansion cone 1945 complete an axial stroke, the operating pressure of the second fluid is reduced and the drill string 1905 is raised. This causes the inner seal spindle 1920, the lower seal head 1930, the load spindle 1940 and the mechanical slide 1955 to move upwards. This releases the mechanical keys 1960 and allows the mechanical keys 1960 and thrust blocks 1965 to move upwardly inside the spindle starter and housing 1970. As the lower seal head 1930 contacts the upper seal head 1925, the second fluid is again pressurized , and the radial expansion process continues. In this manner, the starter spindle 1950 and housing 1970 are radially expanded through repeated axial strokes of the upper seal head 1925, outer seal spindle 1935, and expansion cone 1945. Throughout the radial expansion process, an upper end of the casing 1970 is preferably held in an overlapping relationship with an existing section of wellbore casing.

At the end of the radial expansion process, the upper end of the casing 1970 is expanded into close contact with the inner surface of the lower end of the existing wellbore casing. In a preferred embodiment, the sealing members arranged on the upper end of the casing 1970 form a fluid seal between the outer surface of the upper end of the casing 1970 and the inner surface of the lower end of the existing wellbore casing. In a preferred embodiment, the contact pressure between the casing 1970 and the existing section of wellbore casing ranges from about 400 to 10,000 psi to optimally produce contact pressure to activate the sealing members, produce optimal resistance to axial movement of the expanded casing 1970, and to optimally support typical tension and compression loads.

In a preferred embodiment, as the expansion cone 1945 approaches the end of the casing 1970, the operating flow rate of the second fluid material is reduced to minimize shock to the apparatus 1900. In an alternative embodiment, the apparatus 1900 includes a shock absorber to absorb shock created by the completion of the radial expansion of the casing 1970.

In a preferred embodiment, the reduced operating pressure of the second fluid material ranges from about 100 to 1,000 psi as the expansion cone 1945 approaches the end of the casing 1910 to optimally produce reduced axial movement and velocity of the expansion cone 1945. In a preferred embodiment, the operating pressure of the second liquid material is reduced during the return stroke of the apparatus 1900 to ranges of about 0 to 500 psi to minimize resistance to the movement of the expansion cone 1945. In a preferred embodiment, the stroke length of the apparatus 1900 ranges from about 10 to 45 feet for optimally producing equipment lengths that can be handled with typical oil rig equipment and at the same time minimizing a frequency at which the expansion cone 1945 must be stopped so that the apparatus 1900 can be reset for further expansion operations.

In an alternative embodiment, at least a portion of the upper seal housing 1925 includes an expansion cone for radial expansion of the spindle starter 1950 and casing 1970 during operation of the apparatus 1900 to increase the surface area of the casing 1970 affected during the radial expansion process. In this way, the operating pressures can be reduced.

In an alternative embodiment, the mechanical wedges are placed at an axial location between the seal sleeve 1915 and the inner seal spindle 1920 to facilitate operation and assembly of the apparatus 1900.

Upon completion of radial expansion of the casing 1970, if necessary, the first fluid material is allowed to solidify within the annular region between the outside of the expanded casing 1970 and the inner wall of the wellbore. In the case where the expanded casing 1970 is slotted, the hardened liquid material will preferably penetrate into and surround the expanded casing. In this way, a new section of wellbore casing is formed inside a wellbore. Alternatively, the apparatus 1900 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, the apparatus 1900 may be used to directly line the interior of a wellbore with casing, without the use of an outer annular layer of curable material. Alternatively, the apparatus 1900 may be used to expand a tubular support member into a hole.

During the radial expansion process, in areas of the apparatus 1900 that are under pressure limited to the fluid passages 1975, 1980, 1985 and 1990, and the pressure chamber 2030. No fluid pressure acts directly on the spindle starter 1950 and the casing 1970. This allows the use of operating pressures that are higher than the spindle starter 1950 and casing 1970 would normally withstand.

Reference is now made to Figure 16, where a preferred embodiment of an apparatus 2100 for forming a monodiameter wellbore casing will be described. The apparatus 2100 preferably comprises a drill pipe 2105, an inner string adapter 2110, a sealing sleeve 2115, an inner sealing spindle 2120, stop wedges 2125, upper sealing head 2130, lower sealing head 2135, outer sealing spindle 2140, loading spindle 2145, expansion cone 2150, and casing 2155.

The drill pipe 2105 is connected to the inner string adapter 2110. During operation of the apparatus 2100, the drill pipe 2105 supports the apparatus 2100. The drill pipe 2105 preferably comprises one or more hollow tubular parts. The drill pipe 2105 can be made from any of several conventional, commercially available materials, such as e.g. oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the drill pipe 2105 is made of coiled pipe to facilitate placement of the apparatus 1900 in non-vertical wellbores. The drill pipe 2105 may be coupled to the inner string adapter 2110 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type connection, or a standard threaded connection. In a preferred embodiment, the drill pipe 2105 is removably connected to the inner string adapter 2110 by a drill pipe connection.

The drill pipe 2105 preferably comprises a fluid passage 2160 which is adapted to guide liquid materials from a location on the surface into the fluid passage 2165. In a preferred embodiment, the fluid passage 2160 is adapted to guide liquid materials, such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The inner string adapter 2110 is connected to the drill string 2105 and the sealing sleeve 2115. The inner string adapter 2110 preferably comprises one or more hollow tubular parts. The inner string adapter 2110 can be made from any of several conventional, commercially available materials, such as oilfield tubular goods, low alloy steel, carbon steel, stainless steel and other similar high strength materials. In a preferred embodiment, the inner string adapter 2110 is manufactured from stainless steel to optimally produce high strength, low friction and resistance to corrosion and wear.

The inner string adapter 2110 may be coupled to the drill string 2105 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type connection, ratchet-lock type connection or standard threaded connection. In a preferred embodiment, the inner string adapter 2110 is removably connected to the drill string 2105 by a drill pipe connection. The inner string adapter 2110 can be connected to the sealing sleeve 2115 using any of several conventional, commercially available mechanical connections such as, for example, drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection, or standard threaded connection. In a preferred embodiment, the inner string adapter 2110 is removably coupled to the seal sleeve 2115 by a standard threaded connection.

The inner string adapter 2110 preferably comprises a fluid passage 2165 which is adapted to guide liquid materials from the fluid passage 2160 into the fluid passage 2170. In a preferred embodiment, the fluid passage 2165 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricant at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The sealing sleeve 2115 is connected to the inner string adapter 2110 and the inner sealing spindle 2120. The sealing sleeve 2115 preferably comprises one or more hollow pipe parts. The sealing sleeve 2115 can be made from any of several conventional, commercially available materials, such as, for example, oilfield tubular goods, low alloy steel, carbon steel, stainless steel and other similar high strength materials. In a preferred embodiment, the sealing sleeve 2115 is manufactured from stainless steel to optimally produce high strength, low friction on the surface, and resistance to corrosion, wear, tear and corrosion.

The sealing sleeve 2115 may be coupled to the inner string adapter 2110 using any of several conventional, commercially available mechanical couplings, such as a standard threaded connection, oil field pipe specialty type threaded connection, welding, amorphous banding, or a standard threaded connection. In a preferred embodiment, the sealing sleeve 2115 is removably coupled to the inner string adapter 2110 by a standard threaded connection. The seal sleeve 2115 may be coupled to an inner seal spindle 2120 using any of several conventional, commercially available mechanical couplings, such as a standard threaded connection, oil field pipe specialty type threaded connection, welding, amorphous banding, or a standard threaded connection. In a preferred embodiment, the seal sleeve 2115 is removably coupled to the inner seal spindle 2120 by a standard threaded connection.

The sealing sleeve 2115 preferably comprises a fluid passage 2170 which is adapted to guide liquid materials from the fluid passage 2165 into the fluid passage 2175. In a preferred embodiment, the fluid passage 2170 is adapted to guide liquid materials, such as e.g. cement, epoxy, water, drilling mud or lubricant at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The inner sealing spindle 2120 is connected to the sealing sleeve 2115, the wedges 2125, and the lower sealing head 2135. The inner sealing spindle 2120 preferably comprises one or more hollow tubular parts. The inner seal spindle 2120 can be made of any of several conventional, commercially available materials, such as, for example, oil field tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength material. In a preferred embodiment, the inner seal spindle 2120 is manufactured from stainless steel to optimally produce high strength, low friction surfaces, and corrosion and wear resistance.

The inner seal spindle 2120 may be coupled to the seal sleeve 2115 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, or standard threaded connection. In a preferred embodiment, the inner spindle 2120 is removably coupled to the sealing sleeve 2115 by a standard threaded connection. The standard threaded connection provides high strength and allows easy replacement of components. The inner seal spindle 2120 may be coupled to the splines 2115 using any of several conventional, commercially available mechanical couplings, such as welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the inner spindle 2120 is removably coupled to the wedges 2125 by a standard threaded connection. The inner seal spindle 2120 may be coupled to the lower seal head 2135 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the inner seal spindle 2120 is removably coupled to the lower seal head 2135 by a standard threaded connection.

The inner seal spindle 2120 preferably comprises a fluid passage 2175 which is adapted to guide liquid materials from the fluid passage 2170 into the fluid passage 2180. In a preferred embodiment, the fluid passage 2175 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The wedges 2125 are coupled to the outer surface of the inner seal spindle 2120. During operation of the apparatus 2100, the wedges 2125 will preferably hold the casing 2155 in an approximately stationary position during the radial expansion of the casing 2155. In a preferred embodiment, the wedges 2125 are activated by using the fluid passage 2185 to direct pressurized fluid material to the wedges 2125.

The wedges 2125 may comprise any of several commercially available hydraulic wedges, such as RTTS gasket tungsten carbide hydraulic wedges or model 3L removable bridge plug hydraulic wedges. In a preferred embodiment, the wedges 2125 comprise RTTS packing tungsten carbide hydraulic wedges available from Halliburton Energy Services, to optimally resist axial movement of the casing 2155 during the expansion process. In a particular preferred embodiment, the wedges comprise a fluid passage 2190, pressure chamber 2195, return spring 2200, and wedge parts 2205.

The wedges 2125 may be coupled to the inner sealing spindle 2120 using any of several conventional mechanical couplings. In a preferred embodiment, the wedges 2125 are removably connected to the outer surface of the inner seal spindle 2120 by a threaded connection, to optimally provide interchangeability of parts.

The upper seal head 2130 is coupled to the outer seal stem 2140 and expansion cone 2150. The upper seal head 2130 is also movably coupled to the outer surface of the inner seal stem 2120 and the inner surface of the casing 2155. In this way, the upper seal head 2130 will reciprocate in the axial direction. The radial clearance between the inner cylindrical surface and the upper seal head 2130 and the outer surface of the inner seal spindle 2120 can lie e.g. ranging from about 0.025 to 0.05 inches. In a preferred embodiment, the radial clearance between the inner cylindrical surface of the upper seal head 2130 and the outer surface of the inner seal spindle 2120 is in the range of about 0.005 to 0.010 inches to optimally produce a pressure seal. The radial clearance between the outer cylindrical surface of the upper seal head 2130 and the inner surface of the casing 2155 can e.g. be in the range of about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer cylindrical surface of the upper seal head 2130 and the inner surface of the casing 2155 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 2130 during axial movement of the expansion cone 2130.

The upper seal head 2130 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The upper seal head 2130 may be fabricated from any of several conventional, commercially available materials, such as, for example, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the upper sealing head 2130 is made of stainless steel to optimally provide great strength, corrosion resistance and a low-friction surface. The inner surface of the upper sealing head 2130 preferably comprises one or more annular sealing parts 2210 to seal the interface between the upper sealing head 2130 and the inner sealing spindle 2120. The sealing parts 2210 may comprise any of several conventional, commercially available annular sealing parts, such as e.g. o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing portion 2210 includes polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

In a preferred embodiment, the upper seal head 2130 comprises a shoulder 2215 to support the upper seal head 2130 on the lower seal head 2135.

The upper seal head 2130 may be coupled to the outer seal spindle 2140 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the upper seal head 2130 is removably coupled to the outer seal spindle 2140 by a standard threaded connection. In a preferred embodiment, the mechanical connection between the upper seal head 2130 and the outer seal spindle 2140 comprises one or more sealing members 2220 for fluid sealing of the interface between the upper seal head 2130 and the outer sealing spindle 2140. The sealing member 2220 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2220 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The lower seal head 2135 is coupled to the inner seal spindle 2120 and the load spindle 2145. The lower seal head 2135 is also movably coupled to the inner surface of the outer seal spindle 2140. In this way, the upper seal head 2130, outer seal spindle 2140 and expansion cone 2150 will reciprocate in the axial direction. The radial clearance between the outer surface of the lower seal head 2135 and the inner surface of the outer seal spindle 2140 can e.g. be in the range of about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between the outer surface of the lower seal head 2135 and the inner surface of the outer seal spindle 2140 is in the range of about 0.0025 to 0.05 inches to optimally provide minimum radial clearance.

The lower seal head 2135 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The lower seal head 2135 may be made of any of several conventional, commercially available materials, such as oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the sealing head 2135 is manufactured from stainless steel to optimally produce high strength, corrosion resistance, and a low friction surface. The outer surface of the lower sealing head 2135 preferably comprises one or more annular sealing parts 2225 to seal the interface between the lower sealing head 2135 and the outer sealing spindle 2140. The sealing part 2225 may comprise any of several conventional, commercially available annular sealing parts, such as e.g. o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2225 polypak gaskets available from Parker Seals to optimally provide sealing over a long axial stroke.

The lower seal head 2135 may be coupled to the inner seal spindle 2120 using any of several conventional, commercially available mechanical couplings, such as e.g. drill pipe coupling, oil field tubing specialty type threaded coupling, welding, amorphous banding, or standard threaded connection. In a preferred embodiment, the lower seal head 2135 is removably coupled to the inner seal spindle 2120 by a standard threaded connection. In a preferred embodiment, the mechanical connection between the lower seal head 2135 and the inner seal spindle 2120 comprises one or more sealing members 2230 for fluid sealing of the interface between the lower seal head 2135 and the inner sealing spindle 2120. The sealing members 2230 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets, metal spring-energized gaskets. In a preferred embodiment, the sealing part 2230 comprises polypak gaskets available from Parker Seals, to optimally provide sealing over a long axial stroke.

The lower seal head 2135 may be coupled to the load spindle 2145 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding, or standard threaded connection. In a preferred embodiment, the lower seal head 2135 is removably coupled to the load spindle 2145 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the lower seal head 2135 and the loading spindle 2145 comprises one or more sealing members 2235 for fluid sealing of the interface between the lower sealing head 1930 and the loading spindle 2145. The sealing members 2235 may comprise any of several conventional, commercially available sealing members such like for example. o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the seal members 2235 comprise polypak gaskets available from Parker Seals to optimally produce a seal for a long axial stroke.

In a preferred embodiment, the lower seal head 2135 comprises a throat passage 2240, fluid-coupled between the fluid passages 2175 and 2180. The throat passage 2240 is preferably of reduced size, and is adapted to receive and engage with a plug 2245, or other similar device. In this way, the fluid passage 2175 is fluid-isolated from the fluid passage 2180. In this way, the pressure chamber 2250 is pressurized.

The outer sealing spindle 2140 is coupled to the upper sealing head 2130 and the expansion cone 2150. The outer sealing spindle 2140 is also movably coupled to the inner surface of the casing 2135 and the outer surface of the lower sealing head 2135. In this way, the upper sealing head 2130, outer sealing spindle 2140, and expansion cone 2150 reciprocating in the axial direction. The radial clearance between the outer surface of the outer sealing spindle 2140 and the inner surface of the casing 2135 can lie in the range e.g. from 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer surface of the outer seal spindle 2140 and the inner surface of the casing 2155 is in the range of about 0.025 to 0.125 inches, to optimally provide stabilization of the expansion cone 2130 during the expansion process. The radial clearance between the inner surface of the outer liner spindle 2140 and the outer surface of the lower seal head 2135 can be in the range of e.g. 0.005 to 0.125 inch. In a preferred embodiment, the radial clearance between the inner surface of the outer seal spindle 2140 and the outer surface of the lower seal head 2135 is in the range of about 0.005 to 0.010 inches to optimally provide minimal radial clearance.

The outer seal spindle 2140 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The outer seal spindle 2140 can be made of any of several conventional, commercially available materials, such as, for example, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the outer seal spindle 2140 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The outer seal spindle 2140 may be coupled to the upper seal head 2130 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the outer seal spindle 2140 is removably coupled to the upper seal head 2130 by a standard threaded connection. The upper seal spindle 2140 may be coupled to the expansion cone 2150 using any of several conventional, commercially available mechanical couplings such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the outer seal spindle 2140 is removably coupled to the expansion cone 2150 by a standard threaded connection.

The upper seal head 2130, the lower seal head 2135, the inner seal spindle 2120, and the outer seal spindle 2140 together define a pressure chamber 2250. The pressure chamber 2250 is fluidly coupled to the passage 2175 via one or more passages 2255. During operation of the apparatus 2100, the plug 2245 engages with throat passage 2240 to fluidly isolate fluid passage 2175 from fluid passage 2180. The pressure chamber 2250 is then pressurized, which in turn causes the upper seal head 2130, the outer seal spindle 2140 and the expansion cone 2150 to reciprocate in the axial direction. The axial movement of the expansion cone 2150 will in turn expand the casing 2155 in the radial direction.

The load spindle 2145 is connected to the lower seal head 2135. The load spindle 2145 preferably comprises an annular part which has essentially cylindrical inner and outer surfaces. The load spindle 2145 may be fabricated from any of several conventional, commercially available materials, such as, for example, oil field tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength material. In a preferred embodiment, the load spindles 2145 are manufactured from stainless steel to optimally produce high strength, corrosion resistance and low friction surfaces.

The load spindle 2145 may be coupled to the lower seal head 2135 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the load spindle 2145 is removably connected to the lower seal head 2135 by a standard threaded connection to optimally provide high strength and allow easy replacement of the load spindle 2145.

The loading spindle 2145 preferably comprises a fluid passage 2180 which is adapted to guide liquid materials from the fluid passage 2180 to the area outside the apparatus 2100. In a preferred embodiment, the fluid passage 2180 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The expansion cone 2150 is coupled to the outer sealing spindle 2140. The expansion cone 2150 is also movably coupled to the inner surface of the casing 2155. In this way, the upper sealing head 2130, the outer sealing spindle 2140 and the expansion cone 2150 will reciprocate in the axial direction. Reciprocation of the expansion cone 2150 causes the casing 2155 to expand in the radial direction.

The expansion cone 2150 preferably comprises an annular portion having substantially cylindrical inner and conical outer surfaces. The outside radius of the outer conical surface can range from about 2 to 34 inches. In a preferred embodiment, the outer radius of the outer conical surface ranges from about 3 to 28 inches to optimally produce cone dimensions that are optimal for typical casing. The axial length of the expansion cone 2150 may range from about 2 to 6 times the largest outer diameter of the expansion cone 2150. In a preferred embodiment, the axial length of the expansion cone 2150 may range from about 3 to 5 times the largest outer diameter of the expansion cone 2150 to optimally produce stability and centralization of the expansion cone 2150 during the expansion process. In a particularly preferred embodiment, the maximum outer diameter of the expansion cone 2150 is between about 90 and 100% of the inner diameter of the existing wellbore to which the casing 2155 will be joined. In a preferred embodiment, the angle of attack of the expansion cone 2150 is in the range of about 5 to 30 degrees to optimally balance frictional forces and radial expansion forces. The angle of the optimum expansion cone 2150 will vary as a function of the particular operating conditions of the expansion operation.

The expansion cone 2150 can be made from any of several conventional and commercially available materials, such as machine tool steel, nitride steel, titanium, tungsten carbide, ceramic or other similar high strength materials. In a preferred embodiment, expansion cone 2150 is manufactured from D2 machine tool steel to optimally produce high strength and resistance to wear and tearing. In a particularly preferred embodiment, the outer surface of the expansion cone 2150 has a surface hardness in the range of about 58 to 62 Rockwell C to optimally provide resistance to wear.

The expansion cone 2150 may be coupled to the outer seal spindle 2140 using any of several conventional and commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the expansion cone 2150 is coupled to the outer seal spindle 2140 using a standard threaded connection to optimally provide high strength and to allow easy replacement of the expansion cone 2150.

The casing 2155 is removably connected to the wedges 2125 and the expansion cone 2150. The casing 2155 preferably comprises a tubular part. The casing 2155 may be made of any of several conventional and commercially available materials, such as slotted pipes, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the casing 2155 is manufactured from oil field pipe stock available from various foreign and domestic steel mills, to optimally produce high strength.

In a preferred embodiment, the upper end 2260 of the casing 2155 comprises a thin wall section 2265 and an outer annular sealing portion 2270. In a preferred embodiment, the wall thickness of the thin wall section 2265 is about 50 to 100% of the regular wall thickness of the casing 2155. in this way, the upper end 2260 of the casing 2155 can be easily expanded and deformed into close contact with the lower end of an existing section of wellbore casing. In a preferred embodiment, the lower end of the existing section of casing also comprises a thin wall section. In this manner, the radial expansion of the thin-walled section 2265 of the casing 2155 into the thin-walled section of the existing wellbore casing will result in a wellbore casing having a substantially constant internal diameter.

The annular sealing member 2270 may be made of any of several conventional, commercially available sealing materials, such as, for example, epoxy, rubber, metal or plastic. In a preferred embodiment, the annular sealing member 2270 is made of StrataLock epoxy to optimally provide compressibility and resistance to wear. The outer diameter of the annular sealing member 2270 is preferably in the range of about 70 to 95% of the inner diameter of the lower section of the wellbore casing to which the casing 2155 is to be connected. In this way, after expansion, the annular seal member 2270 will preferably produce a fluid seal and also preferably produce sufficient frictional force with the inner surface of the existing section of well casing during radial expansion of the casing 2155, to support the casing 2155.

In a preferred embodiment, the lower end 2275 of the casing 2155 comprises a thin-walled section 2280 and an outer annular sealing portion 2285. In a preferred embodiment, the wall thickness of the thin-walled section 2280 is about 50 to 100% of the regular wall thickness of the casing 2155. In this way , the lower end 2275 of the casing 2155 can be easily expanded and deformed. Furthermore, in this way, another section of casing can be easily connected to the lower end 2275 of the casing 2155 using a radial expansion process. In a preferred embodiment, the upper end of the second section of casing also comprises a thin wall section. In this way, the radial expansion of the thin-walled section of the upper end of the second casing into the thin-walled section 2280 of the lower end of the casing 2155 will result in a wellbore casing having a substantially constant internal diameter.

The annular sealing member 2285 can be made from any of several conventional, commercially available sealing materials, such as, for example, epoxy, rubber, metal or plastic. In a preferred embodiment, the annular seal member 2285 is fabricated from StrataLock epoxy to provide optimal compressibility and wear resistance. The outer diameter of the annular sealing member 2285 is preferably in the range of 70 to 95% of the inner diameter of the lower section of the existing wellbore casing to which the casing 2155 is connected. In this manner, the annular seal member 2285 will preferably provide a fluid seal and also preferably provide sufficient frictional force with the inner wall of the wellbore during radial expansion of the casing 2155 to support the casing 2155.

During operation, the apparatus 2100 is preferably located in a wellbore with the upper end 2266 of casing 2155 positioned in an overlapping relationship with the lower end of existing wellbore casing. In a particularly preferred embodiment, the thin wall section 2265 of the casing 2155 is positioned in an opposite overlapping relationship with the thin wall section and outer annular seal portion of the lower end of the existing section of wellbore casing. In this manner, the radial expansion of the casing 2155 will compress the thin wall sections and annular compressible portions of the upper end 2266 of the casing 2155 and the lower end of the existing wellbore casing into close contact. During the placement of the apparatus 2100 in the wellbore, the casing 2155 is supported by the expansion cone 2150.

After positioning the apparatus 2100, a first liquid material is pumped into the fluid passage 2160. The first liquid material may comprise any of several conventional, commercially available materials, such as, for example, drilling mud, water, epoxy or cement. In a preferred embodiment, the first liquid material comprises a curable liquid sealing material such as e.g. cement or epoxy, to produce a hardenable outer annular body around the expanded casing 2155.

The first liquid material may be pumped into the fluid passage 2160 at operating pressures and flow rates in the range of, e.g., from about 0 to 4,500 psi and 0 to 3,000 gallons per minute. In a preferred embodiment, the first liquid material is pumped into the fluid passage 2160 at operating pressures and flow rates in the range of about 0 to 3,500 psi and 0 to 1,200 gallons per minute to optimally produce operating efficiency.

The first liquid material pumped into the fluid passage 2160 passes through the fluid passages 2165, 2170, 2175, 2180 and then outside the apparatus 2100. The first liquid material then fills the annulus between the outside of the apparatus 2100 and the inner walls of the wellbore.

The plug 2245 then leads into the fluid passage 2160. The plug 2245 engages in the neck passage 2240 and fluid-isolates and blocks the fluid passage 2175. In a preferred embodiment, a couple of volumes of non-curable liquid material are pumped into the fluid passage 2160 to remove any curable liquid materials contained within and to ensure that none of the fluid passages are blocked.

A second liquid material is then pumped into the fluid passage 2160. The second liquid material may comprise any of several conventional, commercially available materials, such as, for example, drilling mud, water, drilling gases or lubricants. In a preferred embodiment, the second liquid material comprises a non-curable liquid material, such as e.g. water, drilling mud or lubricants, to optimally deliver pressure to the pressure chamber 2250 and minimize frictional forces.

The second liquid material can be pumped into the fluid passage 2160 at operating pressures and flow rates in the area, e.g. from 0 to 4,500 psi and 0 to 4,500 gallons per minute. In a preferred embodiment, the second liquid material is pumped into the fluid passage 2160 at operating pressures and flow rates in the range of 0 to 3,500 psi and 0 to 1,200 gallons per minute, to optimally produce operating efficiency.

The second liquid material pumped into the fluid passage 2160 passes through the fluid passages 2165, 2170 and 2175 into the pressure chamber 2195 of the wedges 2125, and into the pressure chamber 2250. Continued pumping of the second liquid material provides pressure to the pressure chambers 2195 and 2250.

The supply of pressure to the pressure chambers 2195 causes the wedge members 2205 to expand in the radial direction and engage the inner surface of the casing 2155. The casing 2155 is then preferably held in a substantially stationary position.

The pressure input to the pressure chamber 2250 causes the upper seal head 2130, the outer seal spindle 2140 and the expansion cone 2150 to move in the axial direction relative to the casing 2155. In this way, the expansion cone 2150 will cause the casing 2155 to expand in the radial direction.

During the radial expansion process, the casing 2155 is prevented from moving in an upward direction by the wedges 2125. A length of the casing 2155 is then expanded in the radial direction through the pressure in the pressure chamber 2250. The length of casing 2155 that is expanded during the expansion process will be proportional to the stroke length of the upper seal head 2130, the outer seal spindle 2140, and the expansion cone 2150.

After the completion of the stroke, the operating pressure of the second fluid is reduced, and the upper seal head 2130, outer seal spindle 2150, and expansion cone 2150 fall to their rest positions with the casing 2155 supported by the expansion cone 2150. The position of the drill pipe 2105 is preferably adjusted throughout the radial expansion process to maintain the overlap ratio between the thin-walled sections of the lower end of the existing wellbore casing and the upper end of the casing 2155. In a preferred embodiment, the stroke of the expansion cone 2150 is repeated as necessary, to the thin-walled section 2265 of the upper end 2260 of casing 2155 is expanded into the thin-walled section of the lower end of the existing wellbore casing. In this way, a wellbore casing comprising two adjacent sections of casing having a substantially constant inner diameter is formed. This process can be repeated for the entire wellbore to produce a wellbore casing that is several thousand feet in length and has a substantially constant internal diameter.

In a preferred embodiment, during the final stroke of the expansion cone 2150, the stop wedges 2125 are positioned as close as possible to the thin-walled section 2265 of the upper end of the casing 2155 to minimize slippage between the casing 2155 and the existing wellbore casing at the end of the radial expansion process. Alternatively, or in addition, the outer diameter of the annular seal member 2270 is selected to ensure sufficient interference fit with the inner diameter of the lower end of the existing casing to prevent axial displacement of the casing 2155 during the final stroke.

Alternatively or additionally, the outer diameter of the annular seal member 2285 is selected to provide an interference fit with the inner wall of the wellbore at an earlier point in the radial expansion process to prevent further axial displacement of the casing 2155. In this final alternative, the interference fit is preferably chosen to prevent expansion of the casing 2155 by pulling the expansion cone 2150 out of the wellbore, without having to add pressure to the pressure chamber 2250.

During the radial expansion process, pressurized areas in the apparatus 2100 are limited to the fluid passages 2160, 2165, 2170 and 2175, the pressure chambers 2195 with the stop wedges 2125 and the pressure chamber 2250. No fluid pressure acts directly on the casing 2155. This allows the use of operating pressures higher than that the casing 2155 would normally withstand. Once the casing 2155 is fully expanded from the expansion cone 2150, the remaining parts of the apparatus 2100 are removed from the wellbore. In a preferred embodiment, the contact pressure between the deformed thin wall sections and the compressible annular portions of the lower end of the existing casing and the upper end 2260 of the casing 2155 is in the range of about 500 to 40,000 psi to optimally support the casing 2155 at use of the existing wellbore casing.

In this manner, the casing 2155 is radially expanded into contact with an existing section of casing by pressurizing the internal fluid passages 2160, 2165, 2170 and 2175 and the pressure chamber 2250 of the apparatus 2100.

In a preferred embodiment, as necessary, the annular body of curable liquid material is then allowed to harden to form a rigid outer annular body around the expanded casing 2155. In the case where the casing 2155 is slotted, the cured liquid material will preferably penetrate and surround the expanded casing 2155. The resulting new section of wellbore casing includes the expanded casing 2155 and the rigid outer annular body. The overlapping joint between the pre-existing well casing and the expanded casing 2155 includes the deformed thin wall sections and the compressible outer annular bodies. The internal diameter of the resulting combined wellbore casing is essentially constant. In this way, a monodiameter wellbore casing is formed. This process of expanding overlapping tubular members having thin-walled end regions with compressible annular bodies into contact can be repeated for the entire length of the wellbore. In this way, a monodiameter wellbore casing can be designed for thousands of feet in an underground formation.

In a preferred embodiment, as the expansion cone 2150 approaches the upper end of the casing 2155, the operative flow rate of the second fluid is reduced to minimize shock to the apparatus 2100. In an alternative embodiment, the apparatus 2100 includes a shock absorber to absorb the shock created by the completion of the radial expansion of casing 2155.

In a preferred embodiment, the reduced operating pressure of the second fluid material ranges from about 100 to 1,000 psi as the expansion cone 2130 approaches the end of the casing 2155 to optimally produce reduced axial movement and velocity of the expansion cone 2130.1 a preferred embodiment, the operating pressure becomes of the second liquid material reduced during the return stroke of the apparatus 2100 to the range of about 0 to 500 psi to minimize resistance to the movement of the expansion cone 2130 during the return stroke. In a preferred embodiment, the length of the return stroke for the apparatus 2100 is in the range of 10 to 45 feet to optimally produce rig lengths that can be handled by conventional oil rig equipment, and also to minimize the frequency at which the expansion cone 2130 must be stopped in order for the apparatus 2100 to reset.

In an alternative embodiment, at least a portion of the upper seal head 2130 includes an expansion cone for radial expansion of the casing 2155 during operation of the apparatus 2100 to increase the surface area of the casing 2155 affected during the radial expansion process. In this way, the operating pressures can be reduced.

Alternatively, the apparatus 2100 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, the apparatus 2100 can be used to directly line the interior of a wellbore with casing, without the use of an outer annular layer of curable material. Alternatively, the apparatus 2100 can be used to expand a tubular support member in a hole.

Reference is now made to Figures 17, 17a and 17b, where another embodiment of an apparatus 2300 for expanding a tubular part will be described. The apparatus 2300 preferably comprises a drill pipe 2305, an inner string adapter 2310, a sealing sleeve 2315, a hydraulic sliding body 2320, hydraulic stop wedges 2325, an inner sealing spindle 2330, an upper sealing head 2335, a lower sealing head 2340, a loading spindle 2345, an outer sealing spindle 2350, a expansion cone 2355, a mechanical slide 2360, mechanical stop wedges 2365, drag blocks 2370, casing 2375, fluid passages 2380, 2385, 2390, 2395, 2400, 2405, 2410, 2415 and 2485, and a spindle starter 2480.

The drill pipe 2305 is connected to the inner string adapter 2310. During operation of the apparatus 2300, 2305 supports the apparatus 2300. The drill pipe 2305 preferably comprises one or more hollow tubular parts. The drill pipe 2305 can be made from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the drill pipe 2305 is made of coiled pipe to facilitate placement of the apparatus 2300 in non-vertical well holes. The drill pipe 2305 may be coupled to the inner string adapter 2310 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, or a standard threaded connection. In a preferred embodiment, the drill pipe 2305 is removably connected to the inner string adapter 2310 by a drill pipe coupling.

The drill pipe 2305 preferably comprises a fluid passage 2380 which is adapted to guide liquid materials from a location on the surface into the fluid passage 2385. In a preferred embodiment, the fluid passage 2380 is adapted to guide liquid materials such as e.g. cement, water, epoxy, drilling mud or lubricant at an operating pressure and flow rates in the range of about 0 to 9,000 psi and 0 to 5,000 gallons per minute to optimally produce operating efficiency.

The inner string adapter 2310 is connected to the drill string 2305 and the sealing sleeve 2315. The inner string adapter 2310 preferably comprises one or more essentially tubular parts.

The inner string adapter 2310 can be made from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the inner string adapter 2310 is manufactured from stainless steel to optimally produce high strength, corrosion resistance and low friction surfaces.

The inner string adapter 2310 may be coupled to the drill string 2305 using any of several conventional, commercially available mechanical couplings such as, for example, drill pipe coupling, oil field tubing specialty threaded connection, or a standard threaded connection. In a preferred embodiment, the inner string adapter 2310 is removably connected to the drill pipe 2305 by a drill pipe coupling. The inner string adapter 2310 may be coupled to the sealing sleeve 2315 using any of several conventional, commercially available mechanical couplings, such as a drill pipe coupling, oil field tubing specialty threaded connection, or a standard threaded connection. In a preferred embodiment, the inner string adapter 2310 is removably coupled to the sealing sleeve 2315 by a standard threaded connection.

The inner string adapter 2310 preferably comprises a fluid passage 2385 which is adapted to guide liquid materials from the fluid passage 2380 into the fluid passage 2390. In a preferred embodiment, the fluid passage 2385 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud, drilling gases, or lubricants with operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The sealing sleeve 2315 is connected to the inner string adapter 2310 and the hydraulic sliding body 2320. The sealing sleeve 2315 preferably comprises one or more hollow tubular parts.

The sealing sleeve 2315 can be made from any of several conventional, commercially available materials, such as oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the sealing sleeve 2315 is manufactured from stainless steel to optimally produce high strength, corrosion resistance, and low friction surfaces.

The sealing sleeve 2315 may be coupled to the inner string adapter 2310 using any of several conventional, commercially available mechanical couplings, such as drill pipe couplings, oilfield pipe, specialty threaded connections, or standard threaded connections. In a preferred embodiment, the sealing sleeve 2315 is removably coupled to the inner string adapter 2310 by a standard threaded connection.

The sealing sleeve 2315 may be coupled to the hydraulic slide 2320 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection or a standard threaded connection. In a preferred embodiment, the sealing sleeve 2315 is removably connected to the hydraulic sliding body 2320 by a standard threaded connection.

The sealing sleeve 2315 preferably comprises a fluid passage 2390 which is adapted to guide liquid materials from the fluid passage 2385 into the fluid passage 2395. In a preferred embodiment, the fluid passage 2315 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, with operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The hydraulic sliding body 2320 is connected to the sealing sleeve 2315, the hydraulic stop wedges 2315, and the inner sealing spindle 2330. The hydraulic sliding body 2320 preferably comprises one or more hollow tubular parts.

The hydraulic slide body 2320 may be made of any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other high strength materials. In a preferred embodiment, the hydraulic sliding body 2320 is made of carbon steel to optimally provide high strength at low cost.

The hydraulic slide body 2320 may be coupled to the seal sleeve 2315 using any of several conventional, commercially available mechanical couplings such as drill pipe coupling, oil field tubing specialty threaded coupling, or a standard threaded coupling. In a preferred embodiment, the hydraulic sliding body 2320 is removably connected to the sealing sleeve 2315 by a standard threaded connection. The hydraulic slide 2320 may be coupled to the stop wedges 2325 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the hydraulic sliding body 2320 is removably connected to the stop wedges 2325 by a standard threaded connection.

The hydraulic slide 2320 may be coupled to the inner seal spindle 2330 using any of several conventional, commercially available mechanical couplings such as drill pipe coupling, oil field pipe specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the hydraulic slide 2320 is removably coupled to the inner seal spindle 2330 by a standard threaded connection.

The hydraulic sliding body 2320 preferably comprises a fluid passage 2395 which is adapted to guide liquid materials from the fluid passage 2390 into the fluid passage 2405. In a preferred embodiment, the fluid passage 2395 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The hydraulic sliding body 2320 preferably comprises fluid passage 2400 which is adapted to guide liquid materials from the fluid passage 2395 into the pressure chamber 2420 of the hydraulic stop wedges 2325. In this way, the stop wedges 2325 are activated after applying pressure from the fluid passage 2395 to contact the inner surface of the casing 2375. In a preferred embodiment, the fluid passage 2400 is adapted to conduct liquid materials such as e.g. water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The stop wedges 2325 are connected to the outer surface of the hydraulic sliding body 2320. During operation of the apparatus 2300, the stop wedges 2325 are activated after applying pressure in the fluid passages 2395 to contact the inner surface of the casing 2375. In this way, the stop wedges 2325 will hold the casing 2375 in an approximately stationary position.

The stop wedges 2325 preferably comprise the fluid passages 2400, the pressure chambers 2420, spring bias 2425, and wedge parts 2430. The stop wedges 2325 may comprise any of several conventional, commercially available hydraulic wedges, such as RTTS gasket tungsten carbide hydraulic wedges or model 3L removable bridge plug hydraulic wedges. In a preferred embodiment, the wedges 2325 comprise RTTS packing tungsten carbide hydraulic wedges available from Halliburton Energy Services to optimally resist axial movement of the casing 2375 during the radial expansion process.

The inner sealing spindle 2330 is connected to the hydraulic sliding body 2320 and the lower sealing head 2340. The inner sealing spindle 2330 is connected to the hydraulic sliding body 2320 and the lower sealing head 2340. The inner sealing spindle 2330 preferably comprises one or more essentially hollow tubular parts. The inner seal spindle 2330 can be made from any of several conventional, commercially available materials, such as, for example, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the inner seal spindle 2330 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The inner seal spindle 2330 may be coupled to the hydraulic slide using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding, or a standard threaded connection. In a preferred embodiment, the inner seal spindle 2330 is removably coupled to the hydraulic slide body 2320 with a standard threaded connection. The inner seal spindle 2330 may be coupled to the lower seal head 2340 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding, or a standard threaded connection. In a preferred embodiment, the inner seal spindle 2330 is removably coupled to the lower seal head 2340 by a standard threaded connection.

The inner seal spindle 2330 preferably comprises a fluid passage 2405 which is adapted to guide liquid materials from the fluid passage 2395 to the fluid passage 2415. In a preferred embodiment, the fluid passage 2405 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The upper seal head 2335 is coupled to the outer seal stem 2345 and expansion cone 2355. The upper seal head 2335 is also movably coupled to the outer surface of the inner seal stem 2330 and the inner surface of the casing 2375. In this way, the upper seal head 2335 will reciprocate in the axial direction. The radial clearance between the inner cylindrical surface of the upper seal head 2335 and the outer surface of the inner seal spindle 2330 can e.g. be in the range of about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between the inner cylindrical surface of the upper seal head 2335 and the outer surface of the inner seal spindle 2330 is in the range of about 0.005 to 0.01 inch to optimally provide minimum clearance. The radial clearance between the outer cylindrical surface of the upper seal head 2335 and the inner surface of the casing 2375 can e.g. be in the range of about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer cylindrical surface of the upper seal head 2335 and the inner surface of the casing 2375 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 2355 during the expansion process.

The upper seal head 2335 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The upper seal head 2335 can be made from any of several conventional, commercially available materials such as, for example, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the upper sealing head 2335 is made of stainless steel to optimally provide high strength, corrosion resistance and a low friction surface. The inner surface of the upper sealing head 2335 preferably comprises one or more annular sealing parts 2435 to seal the interface between the upper sealing head 2335 and the inner sealing spindle 2330. The sealing parts 2435 may comprise any of several conventional, commercially available annular sealing parts, such as e.g. o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2435 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

In a preferred embodiment, the upper seal head 2335 includes a shoulder 2440 to support the upper seal head on the lower seal head 1930.

The upper seal head 2335 may be coupled to the outer seal spindle 2350 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the upper seal head 2335 is removably coupled to the outer seal spindle 2350 by a standard threaded connection. In a preferred embodiment, the mechanical connection between the upper seal head 2335 and the outer seal spindle 2350 comprises one or more sealing parts 2445 for fluid sealing of the interface between the upper seal head 2335 and the outer sealing spindle 2350. The sealing parts 2445 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing rings comprise 2445 polypak gaskets available from Parker Seals to optimally provide sealing for long axial strokes.

The lower seal head 2340 is coupled to the inner seal spindle 2330 and the load spindle 2345. The lower seal head 2340 is also movably coupled to the inner surface of the outer seal spindle 2350. In this way, the upper seal head 2335 and the outer seal spindle 2350 will reciprocate in axial direction. The radial clearance between the outer surface of the lower seal head 2340 and the inner surface of the outer seal spindle 2350 can be e.g. ranging from about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between the outer surface of the lower seal head 2340 and the inner surface of the outer seal spindle 2350 is in the range of about 0.005 to 0.010 inches to optimally provide minimal radial clearance.

The lower seal head 2340 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The lower seal head 2340 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe fittings, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the lower seal head 2340 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces. The outer surface of the lower sealing head 2340 preferably comprises one or more annular sealing parts 2450 to seal the interface between the lower sealing head 2340 and the outer sealing spindle 2350. The sealing parts 2450 may comprise any of several conventional, commercially available annular sealing parts such as e.g. o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2450 polypak gaskets available from Parker Seals to optimally provide sealing for a long axial stroke.

The lower seal head 2340 may be coupled to the inner seal spindle 2330 using any of several conventional, commercially available mechanical couplings such as drill pipe coupling, oil field pipe specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the lower seal head 2340 is removably coupled to the inner seal spindle 2330 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the lower seal head 2340 and the inner seal spindle 2330 comprises one or more sealing parts 2455 for fluid sealing of the interface between the lower sealing head 2340 and the inner sealing spindle 2330. The sealing parts 2455 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypack or metal spring-energized gaskets. In a preferred embodiment, the sealing rings comprise 2455 polypak gaskets available from Parker Seals, to optimally provide sealing over a long axial stroke.

The lower seal head 2340 may be coupled to the load spindle 2345 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe stock specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the lower seal head 2340 is removably coupled to the load spindle 2345 by a standard threaded connection. In a preferred embodiment, the mechanical connection between the lower seal head 2340 and the loading spindle 2345 comprises one or more sealing members 2460 for fluid sealing of the interface between the lower sealing head 2340 and the loading spindle 2345. The sealing members 2460 may comprise any of several conventional, commercially available sealing members which e.g. o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2460 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

In a preferred embodiment, the lower seal head comprises a throat passage 2465 which is fluidly coupled between the fluid passages 2405 and 2415. The throat passage 2465 is preferably of reduced size, and is adapted to receive and engage with a plug 2470 or other similar device. In this way, the fluid passage 2405 is fluid isolated from the fluid passage 2415. In this way, the pressure chamber 2475 is pressurized.

The outer seal stem 2350 is coupled to the upper seal head 2335 and the expansion cone 2355. The outer seal stem 2350 is also movably coupled to the inner surface of the casing 2375 and the outer surface of the lower seal head 2340. In this way, the upper seal head 2335, outer sealing spindle 2350 and expansion cone 2355 reciprocate in the axial direction. The radial clearance between the outer surface of the outer sealing spindle 2350 and the inner surface of the casing 2375 can be in the range of e.g. from 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer surface of the outer seal spindle 2350 and the inner surface of the casing 2375 is in the range of about 0.025 to 0.175 inches to optimally provide stabilization for the expansion cone 2355 during the expansion process. The radial clearance between the inner surface of the outer seal spindle 2350 and the outer surface of the lower seal head 2340 can be e.g. ranging from about 0.0025 to 0.375 inches. In a preferred embodiment, the radial clearance between the inner surface of the outer seal spindle 2350 and the outer surface of the lower seal head 2340 is in the range of about 0.005 to 0.010 inches to optimally provide minimal clearance.

The outer seal spindle 2350 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The outer seal mandrel 2350 may be fabricated from any of several conventional, commercially available materials, such as, for example, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the outer seal spindle 2350 is made of stainless steel to optimally produce great strength, corrosion resistance and low friction surface.

The outer seal spindle 2350 may be coupled to the upper seal head 2335 using any of several conventional, commercially available mechanical couplings, such as drill pipe couplings, oil field tubing specialty threaded connection, welding, amorphous banding, or a standard threaded connection. In a preferred embodiment, the outer seal spindle 2350 is removably coupled to the upper seal head 2355 by a standard threaded connection. The outer seal spindle 2350 may be coupled to the expansion cone 2355 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the outer seal spindle 2350 is removably coupled to the expansion cone 2355 by a standard threaded connection.

The upper seal head 2335, the lower seal head 2340, the inner seal spindle 2330, and the outer seal spindle 2350 together define a pressure chamber 2475. The pressure chamber 2475 is fluidly coupled to the passage 2405 via one or more passages 2410. During operation of the apparatus 2300, the plug 2470 engages with neck passage 2465 to fluid-isolate fluid passage 2415 from fluid passage 2405. Pressure chamber 2475 is then pressurized, which in turn causes upper seal head 2335, outer seal spindle 2350 and expansion cone 2355 to reciprocate in the axial direction. The axial movement of the expansion cone 2355 will in turn expand the casing 2375 in the radial direction.

The load spindle 2345 is connected to the lower seal head 2340 and the mechanical sliding body 2360. The load spindle 2345 preferably comprises an annular part having essentially cylindrical inner and outer surfaces. The load spindle 2345 can be made from any of several conventional, commercially available materials, such as oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the load spindle 2345 is manufactured from stainless steel to optimally produce high strength, corrosion resistance and low friction surfaces.

The load spindle 2345 may be coupled to the lower seal head 2340 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the load spindle 2345 is removably coupled to the lower seal head 2340 by a standard threaded connection. The load spindle 2345 may be coupled to the mechanical slide 2360 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the load spindle 2345 is removably coupled to the mechanical slider 2360 by a standard threaded connection.

The loading spindle 2345 preferably comprises a fluid passage 2415 which is adapted to guide a liquid material from the fluid passage 2405 to the area outside the apparatus 2300. In a preferred embodiment, the fluid passage 2415 is adapted to guide liquid materials, such as cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The expansion cone 2355 is coupled to the outer seal spindle 2350. The expansion cone 2345 is also movably coupled to the inner surface of the casing 2375. In this way, the upper seal head 2335, outer seal spindle 2350 and expansion cone 2355 will reciprocate in the axial direction. The reciprocation of the expansion cone 2355 causes the casing 2375 to expand in the radial direction.

The expansion cone 2355 preferably comprises an annular portion having essentially cylindrical inner and conical outer surfaces. The outside radius of the outer conical surface may range, for example, from about 2 to 34 inches. In a preferred embodiment, the outer radius of the outer conical surface ranges from about 3 to 28 inches to optimally provide radial expansion of typical casings. The axial length of the expansion cone 2355 may be in the range of from about 2 to 8 times the largest outside diameter of the expansion cone 2355. In a preferred embodiment, the axial length of the expansion cone 2355 is in the range of from about 3 to 5 times the largest outside diameter of the expansion cone 2355 for optimally providing stability and centralization of the expansion cone 2355 during the expansion process. In a preferred embodiment, the angle of attack of the expansion cone 2335 is in the range of about 5 to 30 degrees to optimally provide frictional forces with radial expansion forces. The optimum angle of attack for the expansion cone 2355 will vary as a function of the operating parameters for the particular expansion operation.

The expansion cone 2355 can be made from any of several conventional, commercially available materials, such as machine tool steel, nitride steel, titanium, tungsten carbide, ceramic or other similar high strength materials. In a preferred embodiment, the expansion cone 2355 is manufactured from D2 machine tool steel to optimally produce high strength, aberration resistance and tear resistance. In a particularly preferred embodiment, the outer surface of the expansion cone 2355 has a surface hardness in the range of about 58 to 62 Rockwell C to optimally provide high strength, aberration resistance, and tear resistance.

The expansion cone 2355 may be coupled to the outer seal spindle 2350 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the expansion cone 2355 is coupled to the outer seal spindle 2350 using a standard threaded connection to optimally provide high strength and to allow easy replacement of the expansion cone 2355.

The spindle starter 2480 is coupled to the casing 2375. The spindle starter 2480 comprises a section of casing that has reduced wall thickness compared to the casing 2375. In a preferred embodiment, the wall thickness of the spindle starter 2480 is about 50 to 100% of the wall thickness of the casing 2375. In this way, the initiation of the radial expansion of the casing 2375 is facilitated, and the placement of the apparatus 2300 in a wellbore casing and wellbore is facilitated.

The spindle starter 2480 may be coupled to the casing 2375 using any of several conventional mechanical couplings. The spindle starter 2480 can have a wall thickness in the range from e.g. 0.15 to 1.5 inches. In a preferred embodiment, the wall thickness of the spindle starter 2480 is in the range of about 0.25 to 0.75 inches to optimally provide high strength in a minimal profile. The spindle starter 2480 may be made of any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the spindle starter 2480 is made from oilfield tubular stock with a higher strength than the casing 2375, but with a smaller wall thickness than the casing 2375 to optimally produce a thin-walled container that has approximately the same breaking strength as the casing 2375.

The mechanical sliding body 2460 is coupled to the load spindle 2345, the mechanical stop wedges 2365, and the drag blocks 2370. The mechanical sliding body 2460 preferably comprises a tubular portion having an internal passage 2485 fluidly coupled to the passage 2415. In this way, liquid materials can be directed from the passage 2484 to an area outside the device 2300.

The mechanical slide 2360 may be coupled to the load spindle 2345 using any of several conventional mechanical linkages. In a preferred embodiment, the mechanical sliding body 2360 is removably connected to the load spindle 2345 using threads and sliding steel retaining rings to optimally produce a high strength attachment. The mechanical slide 2360 may be coupled to the mechanical stop wedges 2365 using any of several conventional mechanical linkages. In a preferred embodiment, the mechanical sliding body 2360 is removably connected to the mechanical stop wedges 2365 using threads and steel sliding retaining rings to optimally provide a high strength attachment. The mechanical slider 2360 may be connected to the drag blocks 2370 using any of several conventional mechanical connections. In a preferred embodiment, the mechanical sliding body 2360 is removably connected to the drag blocks 2365 using threads and steel sliding retaining rings to optimally produce a high strength attachment.

The mechanical stop wedges 2365 are coupled to the outer surface of the mechanical sliding body 2360. During operation of the apparatus 2300, the mechanical stop wedges 2365 will prevent upward movement of the casing 2375 and the spindle starter 2480. In this way, during axial reciprocation of the expansion cone 2355, the casing becomes 2375 and the spindle starter 2480 held in a substantially stationary position. In this way, the spindle starter 2480 and the casing 2375 are expanded in the radial direction by the axial movement of the expansion cone 2355.

The mechanical stop wedges 2365 may comprise any of several conventional, commercially available mechanical wedges, such as RTTS Gasket Tungsten Carbide Mechanical Wedges, RTTS Gasket Braid Type Mechanical Wedges or Model 3L Retrievable Bridge Plug Tungsten Carbide Upper Mechanical Wedges. In a preferred embodiment, the mechanical stop wedges 2365 RTTS packing comprise tungsten carbide mechanical wedges available from Halliburton Energy Services, to optimally provide resistance to axial movement of the casing 2375 during the expansion process.

The drag blocks 2370 are coupled to the outer surface of the mechanical sliding body 2360. During operation of the apparatus 2300, the drag blocks 2370 will prevent upward movement of the casing 2375 and the spindle starter 2480. In this way, during the axial reciprocation of the expansion cone 2355, the casing 2375 and the spindle starter 2480 held an essentially stationary position. In this way, the spindle starter 2480 and the casing 2375 are expanded in the radial direction by the axial movement of the expansion cone 2355.

The drag blocks 2370 may comprise any of several conventional, commercially available mechanical wedges, e.g. RTTS gasket mechanical drag blocks or model 3L removable bridge plug drag blocks. In a preferred embodiment, the pull blocks 2370 RTTS packing comprise mechanical pull blocks available from Halliburton Energy Services to optimally resist axial movement of the casing 2375 during the expansion process.

The casing 2375 is connected to the spindle starter 2480. The casing 2375 is further removably connected to the mechanical stop wedges 2365 and drag blocks 2370. The casing 2375 preferably comprises a tubular part. Casing 2375 can be made from any of several conventional, commercially available materials, such as slotted pipes, oil pipe stock, carbon steel, low alloy steel, stainless steel or other similar high strength materials. In a preferred embodiment, the casing 2375 is manufactured from oil field pipe stock available from various foreign and domestic steel mills, to optimally provide high strength. In a preferred embodiment, the upper end of the casing 2375 comprises one or more sealing parts located around the outside of the casing 2375.

In operation, the apparatus 2300 is placed in a wellbore with the upper end of the casing 2375 placed in an overlapping relationship within an existing wellbore casing. To minimize transient pressure within the borehole during placement of the apparatus 2300, the fluid passage 2380 is preferably equipped with one or more pressure release passages. During placement of the apparatus 2300 in the wellbore, the casing 2375 is supported by the expansion cone 2355.

After placing the apparatus 2300 inside the wellbore in an overlapping relationship with an existing section of wellbore casing, a first liquid material is pumped into the fluid passage 2380 from a surface location. The first fluid material is directed from the fluid passage 2380 to the fluid passages 2385, 2390, 2395, 2405, 2415 and 2485. The first fluid material will then exit the apparatus 2300 and fill the annulus between the outside of the apparatus 2300 and the inner walls of the borehole.

The first liquid material may comprise any of several conventional, commercially available materials, such as e.g. epoxy, drilling mud, slag mixture, cement or water. In a preferred embodiment, the first liquid material comprises a curable liquid sealing material, such as e.g. slag mixture, epoxy or cement. In this way, a wellbore casing is formed which has an outer annular layer of a curable material.

The first liquid material can be pumped into the apparatus 2300 at operating pressures and flow rates in the range from e.g. about 0 to 4,500 psi and 0 to 3,000 gallons per minute. In a preferred embodiment, the first liquid material is pumped into apparatus 2300 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons per minute to optimally provide operating efficiency.

At a predetermined point in the injection of the first liquid material, such as e.g. after the annular area outside the apparatus 2300 is filled to a predetermined level, a plug 2470, arrow or other similar device is inserted into the first liquid material. The plug 2470 attaches to the throat passage 2465, so that it fluid-isolates the fluid passage 2405 from the fluid passage 2415.

After placing the plug 2470 in the throat passage 2465, another liquid material is pumped into the fluid passage 2380 to add pressure to the pressure chamber 2475. Other liquid materials may include any of several conventional, commercially available materials, such as water, drilling gases, drilling mud or lubricants. In a preferred embodiment, the second liquid material comprises a non-curable liquid material, such as e.g. water, drilling mud or lubricant.

The second liquid material may be pumped into the apparatus 2300 at operating pressures and flow rates in the range of, e.g., from about 0 to 4,500 psi and 0 to 4,500 gallons per minute. In a preferred embodiment, the second liquid material is pumped into the apparatus 2300 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons per minute to optimally produce operating efficiency.

The supply of pressure to the pressure chamber 2475 causes the upper seal head 2335, the outer seal spindle 2350, and the expansion cone 2355 to move in the axial direction. The pressure supply to the pressure chamber 2475 also causes the hydraulic stop wedges 2325 to expand in the radial direction and hold the casing 2375 in an approximately stationary position. Furthermore, as the expansion cone 2355 moves in the axial direction, the expansion cone 2355 will pull the spindle starter 2480 and the drag blocks 2370 with it, which sets the mechanical stop wedges 2365 and stops further axial movement of the spindle starter 2480 and casing 2375. In this way, the axial movement of the expansion cone 2355 radially expand the spindle starter 2480 and casing 2375.

As soon as the upper seal head 2335, the outer seal spindle 2350 and the expansion cone 2355 complete an axial stroke, the operating pressure of the second fluid is reduced. The reduction in the operating pressure for the second liquid material triggers the hydraulic stop wedges 2325. The drill string 2305 is then raised. This causes the inner seal spindle 2330, the lower seal head 2340, the load spindle 2345 and the mechanical slide 2360 to move upwards. This releases the mechanical stop wedges 2365 and allows the mechanical stop wedges 2365 and drag blocks 2370 to move inside the spindle starter 2480 and casing 2375. As the lower seal head 2340 contacts the upper seal head 2335, the second fluid is again pressurized, and the radial expansion process continues. In this manner, the spindle starter 2480 and the casing 2375 are radially expanded through repeated axial strokes of the upper seal head 2335, the outer seal spindle 2350 and the expansion cone 2355. Throughout the radial expansion process, the upper end of the casing 2375 is preferably held in an overlapping relationship with an existing section of wellbore casing.

At the end of the radial expansion process, the upper end of casing 2375 is expanded into close contact with the inner surface of the lower end of the existing wellbore casing. In a preferred embodiment, the seal portion at the upper end of the casing 2375 forms a fluid seal between the outer surface of the upper end of the casing 2375 and the inner surface of the lower end of the existing wellbore casing. In a preferred embodiment, the contact pressure between the casing 2375 and the existing section of wellbore casing is in the range of about 400 to 10,000 psi to optimally provide contact pressure, activate the sealing members, and withstand typical tensile and compressive loading conditions.

In a preferred embodiment, as the expansion cone 2355 approaches the upper end of the casing 2375, the operating pressure of the second fluid material is reduced to minimize shock to the apparatus 2300. In an alternative embodiment, the apparatus 2300 includes a shock absorber to absorb the shock created by the completion of the radial expansion of the casing 2375.

In a preferred embodiment, the reduced operating pressure of the second fluid material is in the range of about 100 to 1,000 psi as the expansion cone 2355 approaches the end of the casing 2375, to optimally produce reduced axial movement and velocity of the expansion cone 2355.1 a preferred embodiment, becomes the operating pressure of the second liquid material reduced during the return stroke of the apparatus 2300 to ranges from about 0 to 500 psi to minimize resistance to movement of the expansion cone 2355 during the return stroke. In a preferred embodiment, the stroke length of the apparatus 2300 ranges from about 10 to 45 feet to optimally produce equipment that can be handled by typical oil rig equipment and minimize the frequency at which the expansion cone 2355 must be stopped to allow the apparatus 2300 to reset.

In an alternative embodiment, at least a portion of the upper seal head 2335 includes an expansion cone for radial expansion of the spindle starter 2480 and casing 2375 during operation of the apparatus 2300, to increase the surface area of the casing 2375 affected during the radial expansion process. In this way, the operating pressure can be reduced.

In an alternative embodiment, the mechanical stop wedges 2365 are located at an axial location between the seal sleeve 2315 and the inner seal spindle 2330 to optimize the construction and operation of the apparatus 2300.

Upon completion of radial expansion of the casing 2375, the first liquid material is allowed to harden within the annulus between the outside of the expanded casing 2375 and the inner walls of the wellbore. In the case where the casing 2375 is slotted, the hardened fluid material will preferentially penetrate and surround the expanded casing 2375. In this way, a new section of wellbore casing is formed inside a wellbore. Alternatively, the apparatus 2300 may be used to join a first section of a pipeline to an existing section of pipeline. Alternatively, the apparatus 2300 can be used to directly line the interior of a wellbore with casing, without the use of an outer annular layer of curable material. Alternatively, the apparatus 2300 may be used to expand a tubular support member into a hole.

During the radial expansion process, the pressurized areas of the apparatus 2300 are limited to the fluid passages 2380, 2385, 2390, 2395, 2400, 2405 and 2410, and the pressure chamber 2475. No fluid pressure acts directly on the spindle starter 2480 and the casing 2375. This allows the use of operating pressures such as is higher than what the spindle starter 2480 and casing 2375 will normally withstand.

Reference is now made to Figure 18, where a preferred embodiment of an apparatus 2500 for forming a monodiameter wellbore casing will be described. The apparatus 2500 preferably comprises a drill pipe 2505, an inner string adapter 2510, a sealing sleeve 2515, a hydraulic sliding body 2520, hydraulic stop wedges 2525, an inner sealing spindle 2530, upper sealing head 2535, lower sealing head 2540, outer sealing spindle 2545, load spindle 2550, expansion cone 255 casing 2560, and fluid passages 2565, 2570,2575,2580,2585,2590,2595 and 2600.

The drill pipe 2505 is connected to the inner string adapter 2510. During operation of the apparatus 2500, the drill pipe 2505 will support the apparatus 2500. The drill pipe 2505 preferably comprises one or more essentially hollow tubular parts. The drill pipe 2505 can be made from any of several conventional, commercially available materials, such as, for example, oil field tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength material. In a preferred embodiment, drill pipe 2505 is made of coiled pipe to facilitate placement of apparatus 2500 in non-vertical wellbore. The drill pipe 2505 may be coupled to the inner string adapter 2510 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded coupling, or a standard threaded connection. In a preferred embodiment, the drill pipe 2505 is removably connected to the inner string adapter 2510 by a drill pipe coupling. A drill pipe coupling offers the advantages of high strength and easy disassembly.

The drill pipe 2505 preferably comprises a fluid passage 2565 which is adapted to guide liquid materials from a place on the surface into the fluid passage 2570.1 a preferred embodiment, the fluid passage 2565 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricant, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The inner string adapter 2510 is connected to the drill string 2505 and the sealing sleeve 2515. The inner string adapter 2510 preferably comprises one or more essentially hollow tubular parts.

The inner string adapter 2510 can be made from any of several conventional, commercially available materials, such as oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the inner string adapter 2510 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The inner string adapter 2510 may be coupled to the drill string 2505 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oilfield tubing specialty type threaded connection, or a standard threaded connection. In a preferred embodiment, the inner string adapter 2510 is removably connected to the pipe string 2505 by a drill pipe coupling. The inner string adapter 2510 may be coupled to the sealing sleeve 2515 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, ratchet type threaded connection or a standard threaded connection. In a preferred embodiment, the drill string adapter 2510 is removably coupled to the seal sleeve 2515 by a standard threaded connection.

The inner string adapter 2510 preferably comprises a fluid passage 2570 which is adapted to guide liquid materials from the fluid passage 2565 into the fluid passage 2575. In a preferred embodiment, the fluid passage 2570 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The sealing sleeve 2515 is connected to the inner string adapter 2510 and the hydraulic sliding body 2520. The sealing sleeve 2515 preferably comprises one or more essentially hollow tubular parts.

The sealing sleeve 2515 can be made from any of several conventional, commercially available materials, such as oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the sealing sleeve 2515 is made of stainless steel to optimally provide high strength, corrosion resistance, and low friction surfaces.

The sealing sleeve 2515 may be coupled to the inner string adapter 2510 using any of several conventional, commercially available mechanical couplings, such as drill pipe couplings, oil field tubing specialty type threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the sealing sleeve 2515 is removably coupled to the inner string adapter 2510 by a standard threaded connection. The seal sleeve 2515 may be coupled to the hydraulic slide 2520 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the sealing sleeve 2515 is removably connected to the hydraulic sliding body 2520 by a standard threaded connection. The sealing sleeve 2515 preferably comprises a fluid passage 2575 which is adapted to guide liquid materials from the fluid passage 2570 into the fluid passage 2580. In a preferred embodiment, the fluid passage 2575 is adapted to guide liquid materials, such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The hydraulic sliding body 2520 is connected to the sealing sleeve 2515, the hydraulic stop wedges 2525 and the inner sealing spindle 2530. The hydraulic sliding body 2520 preferably comprises one or more essentially hollow tubular parts. The hydraulic slide body 2520 can be made from any of several conventional, commercially available materials, such as, for example, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the hydraulic sliding body 2520 is made of carbon steel to optimally provide high strength.

The hydraulic slide 2520 may be coupled to the seal sleeve 2515 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oilfield tubing specialty type threaded connection, ratchet-lock type connection or standard threaded connection. In a preferred embodiment, the hydraulic sliding body 2520 is removably connected to the sealing sleeve 2515 by a standard threaded connection. The hydraulic slide 2520 may be coupled to the stop wedges 2525 using any of several conventional, commercially available mechanical couplings, such as threaded connection or welding. In a preferred embodiment, the hydraulic sliding body 2520 is removably connected to the stop wedges 2525 by a threaded connection. The hydraulic slide 2520 may be coupled to the inner seal spindle 2530 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oilfield tubing specialty type threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the hydraulic slide 2520 is removably coupled to the inner seal spindle 2530 by a standard threaded connection.

The hydraulic sliding body 2520 preferably comprises a fluid passage 2580 which is adapted to guide liquid materials from the fluid passage 2575 into the fluid passage 2590. In a preferred embodiment, the fluid passage 2580 is to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The hydraulic sliding body 2520 preferably includes fluid passages 2585 which are adapted to guide liquid materials from the fluid passage 2580 into the pressure chamber of the hydraulic stop wedges 2525. In this way, the stop wedges 2525 are activated by applying pressure to the fluid passage 2585, into contact with the inner surfaces of the casing 2560. In a preferred embodiment, the fluid passages 2585 are adapted to conduct liquid materials, such as e.g. water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The stop wedges 2525 are coupled to the outer surface of the hydraulic sliding body 2520. During operation of the apparatus 2500, the stop wedges 2525 are activated by applying pressure to the fluid passage 2580, to contact the inner surface of the casing 2560. In this way, the stop wedges 2525 will hold the casing 2560 in an essentially stationary position.

The stop wedges 2525 preferably comprise fluid passages 2585, pressure chambers 2605, spring bias 2610, and sliding parts 2615. The stop wedges 2525 may comprise any of several conventional, commercially available hydraulic stop wedges, such as RTTS gasket tungsten carbide hydraulic stop wedges or model 3L removable bridge plug with hydraulic stop wedges. In a preferred embodiment, the stop wedges 2525 comprise RTTS packing tungsten carbide hydraulic wedges available from Halliburton Energy Services to optimally resist axial movement of the casing 2560 during the expansion process.

The inner sealing spindle 2530 is connected to the hydraulic sliding body 2520 and the lower sealing head 2540. The inner sealing spindle 2530 preferably comprises one or more essentially hollow tubular parts. The inner seal spindle 2530 can be made from any of several conventional, commercially available materials, such as, for example, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the inner seal spindle 2530 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The inner seal spindle 2530 may be coupled to the hydraulic slide body 2520 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oilfield tubing specialty type threaded coupling, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the inner seal spindle 2530 is removably coupled to the hydraulic slide body 2520 by a standard threaded connection. The inner seal spindle 2530 may be coupled to the lower seal head 2540 using any of several conventional, commercially available mechanical couplings, such as oil field tubing specialty type threaded connection, drill pipe coupling, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the seal spindle 2530 is removably coupled to the lower seal head 2540 by a standard threaded connection.

The inner seal spindle 2530 preferably comprises a fluid passage 2590 which is adapted to guide liquid materials from the fluid passage 2580 into the fluid passage 2600. In a preferred embodiment, the fluid passage 2590 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The upper seal head 2535 is coupled to the outer seal stem 2545 and expansion cone 2555. The upper seal head 2535 is also removably coupled to the outer surface of the inner seal stem 2530 and the inner surface of the casing 2560. In this way, the upper seal head 2535 will reciprocate in the axial direction. The radial clearance between the inner cylindrical surface of the upper seal head 2535 and the outer surface of the inner seal spindle can be in the range of e.g. from about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between the inner cylindrical surface of the upper seal head 2535 and the outer surface of the inner seal spindle 2530 is in the range of about 0.005 to 0.01 inch to optimally provide minimal radial clearance. The radial clearance between the outer cylindrical surface of the upper seal head 2535 and the inner surface of the casing 2560 can be e.g. ranging from 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer cylindrical surface of the upper seal head 2535 and the inner surface of the casing 2560 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 2535 during the expansion process.

The upper seal head 2535 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The upper seal head 2535 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the upper sealing head 2535 is made of stainless steel to optimally provide great strength, corrosion resistance and low friction surfaces. The inner surface of the upper sealing head 2535 preferably comprises one or more annular sealing members 2620 to seal the interface between the upper sealing head 2535 and the inner sealing spindle 2530. The sealing members 2620 may comprise any of several conventional, commercially available annular sealing members such as . o-rings, polypak gaskets, or metal energized gaskets. In a preferred embodiment, the sealing parts 2620 comprise polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

In a preferred embodiment, the upper seal head 2535 includes a shoulder 2625 to support the upper seal head 2535, outer seal spindle 2545, and expansion cone 2555 and the lower seal head 2540.

The upper seal head 2535 may be coupled to the outer seal spindle 2545 using any of several conventional commercially available mechanical couplings, such as oilfield pipeline specialty threaded connection, pipeline coupling, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the upper seal head 2535 is removably coupled to the outer seal spindle 2545 with a standard threaded connection. In a preferred embodiment, the mechanical coupling between the upper seal head 2535 and the outer seal spindle 2545 comprises one or more sealing members 2630 for fluid sealing of the interface between the upper seal head 2535 and the outer seal spindle 2545. The sealing members 2630 may comprise any of several conventional , commercially available sealing parts, such as o-rings, polypak gaskets or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2630 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The lower seal head 2540 is coupled to the inner seal stem 2530 and the load stem 2550. The lower seal head 2540 is also movably coupled to the inner surface of the outer seal stem 2545. In this way, the upper seal head 2535, outer seal stem 2545 and expansion cone 2555 will reciprocate in the axial direction.

The radial clearance between the outer surface of the lower seal head 2540 and the inner surface of the outer seal spindle 2545 may range from about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between the outer surface of the lower seal head 2540 and the inner surface of the outer seal spindle 2545 is in the range of about 0.005 to 0.01 inches to optimally provide minimum radial clearance.

The lower seal head 2540 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The lower seal head 2540 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the lower seal head 2540 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces. The outer surface of the lower sealing head 2540 preferably comprises one or more annular sealing members 2635 to seal the interface between the lower sealing head 2540 and the outer sealing spindle 2545. The sealing members 2635 may comprise any of several conventional, commercially available annular sealing members, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2635 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The lower seal head 2540 may be coupled to the inner seal spindle 2530 using any of several conventional, commercially available mechanical couplings, such as drill pipe couplings, oil field tubing specialty threaded connection, or a standard threaded connection. In a preferred embodiment, the lower seal head 2540 is removably coupled to the inner seal spindle 2530 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the lower seal head 2540 and the inner seal spindle 2530 comprises one or more sealing members 2640 for fluid sealing of the interface between the lower seal head 2540 and the inner sealing spindle 2530. The sealing members 2640 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing members 2640 comprise polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The lower seal head 2540 may be coupled to the load spindle 2550 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the lower seal head 2540 is removably coupled to the load spindle 2550 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the lower seal head 2540 and the loading spindle 2550 comprises one or more sealing members 2645 for fluid sealing of the inner surface between the lower sealing head 2540 and the loading spindle 2550. The sealing members 2645 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2645 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

In a preferred embodiment, the lower seal head 2540 comprises a throat passage 2650 fluidly coupled between the fluid passages 2590 and 2600. The throat passage 2650 is preferably of reduced size, and adapted to receive and engage with a plug 2655 or other similar device. In this way, the fluid passage 2590 is fluid isolated from the fluid passage 2600. In this way, the pressure chamber 2660 is pressurized.

The outer seal stem 2545 is coupled to the upper seal head 2535 and expansion cone 2555. The outer seal stem 2545 is also movably coupled to the inner surface of the casing 2560 and the outer surface of the lower seal head 2540. In this way, the upper seal head 2535, outer sealing spindle 2545 and expansion cone 2555 reciprocate in axial direction. The radial clearance between the outer surface of the outer sealing spindle 2545 and the inner surface of the casing 2560 can e.g. be in the range of about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer surface of the outer seal spindle 2545 and the inner surface of the casing 2560 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 2535 during the expansion process. The radial clearance between the inner surface of the outer seal spindle 2545 and the outer surface of the lower seal head 2540 can e.g. be in the range of about 0.005 to 0.01 inch. In a preferred embodiment, the radial clearance between the inner surface of the outer seal spindle 2545 and the outer surface of the lower seal head 2540 is in the range of about 0.005 to 0.01 inch to optimally provide minimal radial clearance.

The outer seal spindle 2545 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The outer seal spindle 2545 may be made of any of several conventional, commercially available materials, such as, for example, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the outer seal spindle 2545 is made of stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The outer seal spindle 2545 may be coupled to the upper seal head 2535 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, welding, amorphous banding, or a standard threaded connection. In a preferred embodiment, the outer seal spindle 2545 is removably coupled to the upper seal head 2535 with a standard threaded connection. The outer seal spindle 2545 may be coupled to the expansion cone 2555 using any of several conventional, commercially available couplings, such as drill pipe coupling, oilfield pipe specialty type threaded connection, welding, amorphous banding, or a standard threaded connection. In a preferred embodiment, the outer seal spindle 2545 is removably coupled to the expansion cone 2555 by a standard threaded connection.

The upper seal head 2535, the lower seal head 2540, the inner seal spindle 2530, and the outer seal spindle 2545 together define a pressure chamber 2660. The pressure chamber 2660 is fluidly coupled to the passage 2590 via one or more passages 2595. During operation of the apparatus 2500, the plug 2655 engages with throat passage 2650 to fluidly isolate fluid passage 2590 from fluid passage 2600. Pressure chamber 2660 is then pressurized, which in turn causes upper seal head 2535, outer seal spindle 2545 and expansion cone 2555 to reciprocate in the axial direction. The axial movement of the expansion cone 2555 in turn expands the casing 2560 in the radial direction.

The load spindle 2550 is connected to the lower seal head 2540. The load spindle 2550 preferably comprises an annular part which has essentially cylindrical inner and outer surfaces. The load spindle 2550 can be made from any of several conventional, commercially available materials, such as oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the load spindle 2550 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The load spindle 2550 may be coupled to the lower seal head 2540 using any of several conventional, commercially available mechanical couplings, such as oil field tubing, drill pipe coupling, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the load spindle 2550 is removably coupled to the lower seal head 2540 with a standard threaded connection.

The load spindle 2550 preferably comprises a fluid passage 2600 which is adapted to guide liquid materials from the fluid passage 2590 to the area outside the apparatus 2500. In a preferred embodiment, the fluid passage 2600 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, at operating pressures and flow rates in the area from e.g. about 0 to 9,000 psi and from 0 to 3,000 gallons per minute.

Expansion cone 2555 is coupled to outer seal spindle 2545. Expansion cone 2555 is also movably coupled to the inner surface of casing 2560. In this manner, upper seal head 2535, outer seal spindle 2545 and expansion cone 2555 will reciprocate in the axial direction. The reciprocation of the expansion cone 2555 causes the casing 2560 to expand in the radial direction.

Expansion cone 2555 preferably comprises an annular part which has essentially cylindrical inner and conical outer surfaces. The outer radius of the outer conical surface can e.g. be in the range of about 2 to 34 inches. In a preferred embodiment, the outer radius of the outer conical surface is in the range from about 3 to 20 to optimally provide radial expansion for the widest variety of casing. The axial length of the expansion cone 2555 can e.g. be in the range of from 2 to 8 times the largest outside diameter of the expansion cone 2555. In a preferred embodiment, the axial length of the expansion cone 2555 is in the range of from about 3 to 5 times the largest diameter of the expansion cone 2555 to optimally provide stabilization and centralization of the expansion cone 2555 during the expansion process. In a particularly preferred embodiment, the maximum outer diameter of the expansion cone 2555 is between about 95 to 99% of the inner diameter of the existing wellbore with which the casing 2560 is to be joined. In a preferred embodiment, the angle of attack of the expansion cone 2555 is in the range of about 5 to 30 degrees to optimally balance frictional forces and radial expansion forces. The optimum angle of attack for expansion cone 2555 will vary as a function of the particular operational features of the expansion operation.

Expansion cone 2555 can be made from any of several conventional, commercially available materials, such as e.g. machine tool steel, nitride steel, titanium, tungsten carbide, ceramic or other similar high strength materials. In a preferred embodiment, expansion cone 2555 is manufactured from D2 machine tool steel to optimally provide high strength, and resistance to wear and tearing. In a particularly preferred embodiment, the outer surface of expansion cone 2555 has a surface hardness in the range of about 58 to 62 Rockwell C to optimally provide high strength and wear resistance.

Expansion cone 2555 may be coupled to outer seal spindle 2545 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the expansion cone 2555 is connected to the outer seal spindle 2545 using a standard threaded connection to optimally provide high strength and easy replacement of the expansion cone 2555.

The casing 2560 is removably connected to the stop wedges 2525 and the expansion cone 2555. The casing 2560 preferably comprises a tubular part. Casing 2560 can be made from any of several conventional, commercially available materials, such as slitted pipe, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the casing 2560 is manufactured from oil field pipe stock available from various foreign and domestic steel mills, to optimally provide high strength using standardized materials.

In a preferred embodiment, the upper end 2665 of the casing 2560 comprises a thin-walled section 2670 and an outer annular sealing portion 2675. In a preferred embodiment, the wall thickness of the thin-walled section 2670 is about 50 to 100% of the regular wall thickness of the casing 2560. In this way , the upper end 2665 of the casing 2560 can easily be radially expanded and deformed into close contact with the lower end of an existing section of wellbore casing. In a preferred embodiment, the lower end of the existing section of casing also comprises a thin-walled section. In this way, the radial expansion of the thin-walled section 2670 of the casing 2560 into the thin-walled section of the existing casing will result in a wellbore casing having a substantially constant internal diameter.

The annular sealing member 2675 may be made of any of several conventional, commercially available sealing materials, such as, for example, epoxy, rubber, metal or plastic. In a preferred embodiment, the annular seal member 2675 is made of StrataLock epoxy to optimally provide compressibility and resistance to wear. The outer diameter of the annular sealing member 2675 is preferably in the range of 70 to 95% of the inner diameter of the lower section of the wellbore casing to which the casing 2560 is joined. In this way, after radial expansion, the annular seal member 2670 will optimally produce a fluid seal and also preferably optimally provide a sufficient frictional force with the inner surface of the existing section of casing during the radial expansion of the casing 2560 to support the casing 2560.

In a preferred embodiment, the lower end 2680 of the casing 2560 comprises a thin-walled section 2685 and an outer annular sealing portion 2690. In a preferred embodiment, the wall thickness of the thin-walled section 2685 is about 50 to 100% of the regular wall thickness of the casing 2560. In this way , the lower end 2680 of the casing 2560 can be easily expanded and deformed. Also, in this way, another section of casing can be easily connected to the lower end 2680 of the casing 2560 using a radial expansion process. In a preferred embodiment, the upper end of the second section of casing also comprises a thin-walled section. In this manner, the radial expansion of the thin-walled section of the upper end of the second casing into the thin-walled section 7685 of the lower end of the casing 2560 will result in a wellbore having a substantially constant internal diameter.

The annular sealing member 2690 can be made from any of several conventional, commercially available sealing materials, such as, for example, rubber, metal, plastic or epoxy. In a preferred embodiment, the annular seal member 2690 is made of StrataLock epoxy to optimally provide compressibility and wear resistance. The outside diameter of the annular seal portion 2690 is preferably in the range of about 70 to 95% of the inside diameter of the lower section of the existing wellbore casing to which the casing 2560 is connected. In this way, after radial expansion, the annular seal member 2690 will preferably provide a fluid seal, and also preferably provide sufficient frictional force with an inner wall of the wellbore during radial expansion of the casing 2560 to support the casing 2560.

During operation, the apparatus 2500 is preferably placed in a wellbore with an upper end 2665 of the casing 2560 placed in an overlapping relationship with the lower end of an existing wellbore casing. In a particularly preferred embodiment, the thin-walled section 2670 of the casing 2560 is placed in an opposite overlapping relationship with the thin-walled section and outer annular sealing portion of the lower end of the existing section of wellbore casing. In this manner, the radial expansion of the casing 2560 will compress the thin-walled sections and annular compressible portions of the upper end 2665 of the casing 2560 and the lower end of the existing wellbore casing into close contact. During the placement of the apparatus 2500 in the wellbore, the casing 2560 is supported by the expansion cone 2555.

After positioning the apparatus 2500, a liquid material is pumped into the fluid passage 2565. The first liquid material may comprise any of several conventional, commercially available materials, such as, for example, cement, water, slag mixture, epoxy or drilling mud. In a preferred embodiment, the first liquid material comprises a hardenable liquid material, such as e.g. cement, epoxy or slag mixture, to optimally produce a hardenable outer annular body around the expanded casing 2560.

The first liquid material may be pumped into the fluid passage 2565 at operating pressures and flow rates in the range of about 0 to 4,500 psi and 0 to 3,000 gallons per minute. In a preferred embodiment, the first liquid material is pumped into the fluid passage 2565 at an operating pressure and flow rates in the range of about 0 to 3,500 psi and 0 to 1,200 gallons per minute to optimally provide operating efficiency.

The first liquid material pumped into the fluid passage 2565 passes through the fluid passages 2570, 2575, 2580, 2590, 2600 and then outside the apparatus 2500. The first liquid material then preferably fills the annular area between the outside of the apparatus 2500 and the inner walls of the wellbore.

The plug 2655 is then inserted into the fluid passage 2565. The plug 2655 is fixed in the neck passage 2650 and fluidly isolates and blocks the fluid passage 2590.1 a preferred embodiment, a couple of volumes of non-curable liquid material are then pumped into the fluid passage 2565 to remove any curable liquid materials present there, and to ensure that none of the fluid passages are blocked.

A second liquid material is then pumped into the fluid passage 2565. The second liquid material may comprise any of several conventional, commercially available materials, such as, for example, water, drilling gases, drilling mud or lubricant.* In a preferred embodiment, the second liquid material comprises a non-curable liquid material, such as e.g. water, drilling mud or lubricant, to optimally supply pressure to the pressure chamber 2660 and to minimize friction.

The second liquid material can be pumped into the fluid passage 2565 at operating pressures and flow rates in the range from e.g. about 0 to 4,500 and psi and 0 to 4,500 gallons per minute. In a preferred embodiment, the second liquid material is pumped into the fluid passage 2565 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons per minute, to optimally provide operating efficiency.

The second liquid material pumped into the fluid passage 2565 passes through the fluid passages 2570, 2575, 2580, 2590 and into the pressure chambers 2605 of the stop wedges 2525 and into the pressure chamber 2660. Continued pumping of the second liquid material adds pressure to the pressure chambers 2605 and 2660.

The pressure supply to the pressure chambers 2605 causes the stop wedges 2525 to expand in the radial direction and grip the inner surface of the casing 2560. The casing 2560 is then preferably held in a substantially stationary position.

The pressure input to the pressure chamber 2660 causes the upper seal head 2535, the upper seal spindle 2545 and the expansion cone 2555 to move in an axial direction relative to the casing 2560. In this way, the expansion cone 2555 will cause the casing 2560 to expand in the radial direction, starting at the lower end 2685 of casing 2560.

During the radial expansion process, the casing 2560 is prevented from moving upward by the stop wedges 2525. A length of the casing 2560 is then expanded in the radial direction through the pressure supply to the pressure chamber 2660. The length of casing 2560 that is expanded during the expansion process will be proportional to the stroke length of the upper seal head 2535, the outer seal spindle 2545, and the expansion cone 2555.

After the completion of a stroke, the operating pressure of the second fluid is reduced and the upper seal head 2535, outer seal spindle 2545 and expansion cone 2555 fall to their rest positions with the casing 2565 supported by the expansion cone 2555. The position of the drill pipe 2505 is preferably adjusted throughout the radial expansion process to maintain the overlapping relationship between the thin-walled sections of the lower end of the existing wellbore casing and the upper end of the casing 2560. In a preferred embodiment, the beating of the expansion cone 2555 is then repeated as necessary, until the thin-walled sections 2670 of the upper end 2665 of the casing 2560 is expanded into the thin-walled section of the lower end of the existing wellbore casing. In this way, a wellbore casing is formed comprising two adjacent sections of casing having an approximately constant internal diameter. This process can then be repeated for the entire wellbore to provide a wellbore casing several thousand feet in length, with an essentially constant internal diameter.

In a preferred embodiment, during the final stroke of the expansion cone 2555, the stop wedges 2525 are positioned as close as possible to the thin-walled section 2670 of the upper end 2665 of the casing 2560 to minimize slippage between the casing 2550 and the existing wellbore casing at the end of the radial expansion process. Alternatively, or in addition, the outer diameter of the annular seal member 2675 is selected to ensure sufficient interference fit with the inner diameter of the lower end of the existing casing to prevent axial displacement of the casing 2560 during the final stroke. Alternatively or additionally, the outer diameter of the annular sealing member 2690 is chosen to provide an interference fit with the inner walls of the wellbore at an earlier point in the radial expansion process, to prevent further axial displacement of the casing 2560.1 this last option, the interference fit is preferably chosen to allow expansion of the casing 2560 by pulling the expansion cone 2555 out of the wellbore, without having to pressurize the pressure chamber 2660.

During the radial expansion process, the areas of the apparatus 2500 that are under pressure are preferably limited to the fluid passages 2565, 2570, 2575, 2580, and 2590, the pressure chambers 2605 in the stop wedges 2525, and the pressure chamber 2660. No fluid pressure acts directly on the casing 2560. This allows the use of operating pressures that are higher than casing 2560 would normally withstand.

As soon as the casing 2560 is fully expanded by the expansion cone 2555, the other parts of the apparatus 2500 must be removed from the wellbore. In a preferred embodiment, the contact pressure between the deformed thin wall sections and the compressible annular portions of the lower end of the existing casing and the upper end 2665 of the casing 2560 is in the range of about 400 to 10,000 psi to optimally support the casing 2560 in use of the existing wellbore casing.

In this manner, the casing 2560 is radially expanded into contact with the existing section of casing with pressure supplied to the internal fluid passages 2565, 2570, 2575, 2580 and 2590, the pressure chambers of the detents 2605 and the pressure chamber 2660 of the apparatus 2500.

In a preferred embodiment, as necessary, the annular body of curable liquid material is then allowed to harden to form a rigid outer annular body around the expanded casing 2560. In the case where the casing 2560 is slotted, the cured liquid material will preferably penetrate into and surround the expanded casing 2560. The resulting new section of wellbore casing includes the expanded casing 2560 and the rigid outer annular body. The overlapping joint between the preexisting wellbore casing and the expanded casing 2560 includes the deformed thin wall sections and the compressible outer annular bodies. The internal diameter of the resulting combined wellbore casing is essentially constant. In this way, a monodiameter wellbore casing is formed. The process of expanding the overlapping tubular members having thin-walled end regions with compressible annular bodies for contact can be repeated for the entire length of the wellbore. In this way, a monodiameter wellbore casing can be arranged for several feet in a subterranean formation.

In a preferred embodiment, as the expansion cone 2555 approaches the upper end 2665 of the casing 2560, the operating pressure in the other fluid materials is reduced to minimize shock to the apparatus 2500. In an alternative embodiment, the apparatus 2500 includes a shock absorber to absorb shock created by the completion of the radial expansion of the casing 2560.

In a preferred embodiment, the reduced operating pressure of the second fluid material is in the range of about 100 to 1,000 psi as the expansion cone 2555 approaches the end of the casing 2560 to optimally produce reduced axial movement and velocity of the expansion cone 2555.1 a preferred embodiment, the operating pressure becomes of the second liquid material reduced during the return stroke of the apparatus 2500 to the range of about 0 to 500 psi to minimize resistance to movement of the expansion cone 2555 during the return stroke. In a preferred embodiment, the stroke length of the apparatus 2500 is in the range of 10 to 45 feet to optimally produce rig lengths that can be easily handled using typical oil rig equipment and also minimize the frequency at which the apparatus 2500 must be reset.

In an alternative embodiment, at least a portion of the upper seal head 2535 includes an expansion cone for radial expansion of the casing 2560 during operation of the apparatus 2500 to increase the surface area of the casing 2560 affected during the radial expansion process. In this way, the operating pressures can be reduced.

Alternatively, the apparatus 2500 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, the apparatus 2500 can be used to directly line the interior of a wellbore with casing without the use of an outer annular layer of curable material. Alternatively, the apparatus 2500 can be used to expand a tubular support member in a hole.

Reference is now made to figures 19, 19A and 19B, where another embodiment of the apparatus 2700 for expanding a pipe part will be described. The apparatus 2700 preferably comprises a drill pipe 2705, an inner string adapter 2710, a sealing sleeve 2715, a first inner sealing spindle 2720, a first upper sealing head 2725, a first lower sealing head 2730, a first outer sealing spindle 2735, a second inner sealing spindle 2740, another upper seal head 2745, another lower seal head 2750, another outer seal stem 2755, a load stem 2760, an expansion cone 2765, a stem starter 2770, a mechanical slide body 2775, mechanical stop wedges 2780, drag blocks 2785, casing 2790, and fluid passages 2795,28050, 280 , 2810, 2815,2820,2825, and 2830.

The drill pipe 2705 is connected to the inner string adapter 2710. During operation of the apparatus 2700, the drill pipe 2705 supports the apparatus 2700. The drill pipe 2705 preferably comprises one or more substantially hollow pipe parts. The drill pipe 2705 can be made from any of several conventional, commercially available materials, such as, for example, oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the drill pipe 2705 is made of coiled pipe to facilitate placement of the apparatus 2700 in non-vertical well holes. The drill pipe 2705 may be coupled to the inner string adapter 2710 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, or a standard threaded connection. In a preferred embodiment, the drill pipe 2705 is removably connected to the inner string adapter 2710 by a drill pipe coupling to optimally produce great strength and easy disassembly.

The drill pipe 2705 preferably comprises a fluid passage 2795 which is adapted to guide liquid materials from a location on the surface into the fluid passage 2800.1 a preferred embodiment, the fluid passage 2795 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The inner string adapter 2710 is connected to the drill string 2705 and the sealing sleeve 2715. The inner string adapter 2710 preferably mainly comprises one or more mainly hollow pipe parts. The inner string adapter 2710 can be made from any of several conventional, commercially available materials, such as oil field pipe stock, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the inner string adapter 2710 is manufactured from stainless steel to optimally produce high strength, corrosion resistance and low friction surfaces.

The inner string adapter 2710 may be coupled to the drill string 2705 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, or a standard threaded connection. In a preferred embodiment, the inner string adapter 2710 is removably connected to the drill pipe 2705 by a standard threaded connection, to optimally provide high strength and easy disassembly. The inner string adapter 2710 may be coupled to the sealing sleeve 2715 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the inner string adapter 27 in 0 is removably coupled to the seal sleeve 2715 by a standard threaded connection.

The inner string adapter 2710 preferably comprises a fluid passage 2800 which is adapted to conduct liquid materials from the fluid passage 2792 into the fluid passage 2805. In a preferred embodiment, the fluid passage 2800 is adapted to conduct liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The sealing sleeve 2715 is connected to the inner string adapter 2710 and the first inner sealing spindle 2720. The sealing sleeve 2715 preferably comprises one or more essentially hollow pipe parts. The sealing sleeve 2715 can be made from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the sealing sleeve 2715 is made of stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The sealing sleeve 2715 may be coupled to the inner string adapter 2710 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the sealing sleeve 2715 is removably coupled to the inner string adapter 2710 with a standard threaded coupling. The seal sleeve 2715 may be coupled to the first inner seal spindle 2720 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the seal sleeve 2715 is removably coupled to the inner seal spindle 2710 with a standard threaded connection.

The sealing sleeve 2715 preferably comprises a fluid passage 2802 which is adapted to guide liquid materials from the fluid passage 2800 into the fluid passage 2805. In a preferred embodiment, the fluid passage 2802 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricant at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The first inner sealing spindle 2720 is connected to the sealing sleeve 2715 and the first lower sealing head 2730. The first inner sealing spindle 2720 preferably comprises one or more essentially hollow tubular parts. The first inner seal spindle 2720 can be made from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the first inner seal spindle 2720 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The first inner seal spindle 2720 may be coupled to the seal housing 2715 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, welding, amorphous banding, or a standard threaded connection. In a preferred embodiment, the first seal spindle 2720 is removably coupled to the seal sleeve 2715 with a standard threaded connection. The first inner seal spindle 2720 may be coupled to the first lower seal head 2730 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, welding, amorphous banding, or a standard threaded connection. In a preferred embodiment, the first inner seal spindle 2720 is removably coupled to the first lower seal head 2730 with a standard connection.

The first inner seal spindle 2720 preferably comprises a fluid passage 2805 which is adapted to guide liquid materials from the fluid passage 2802 into the fluid passage 2810. In a preferred embodiment, the fluid passage 2805 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The first upper seal head 2725 is coupled to the first outer seal stem 2735, the second upper seal head 2745, the second outer seal stem 2755, and expansion cone 2765. The first upper seal head 2725 is also movably coupled to the outer surface of the first inner seal stem 2720 and to the inner surface of the casing 2790. In this way, the first upper seal head 2725 will reciprocate in the axial direction. The radial clearance between the inner cylindrical surface of the upper seal head 2725 and the outer surface of the first inner seal spindle 2720 can be in the range of e.g. about 0.0025 to 0.05 inch. In a preferred embodiment, the radial clearance between the inner cylindrical surface of the upper seal head 2725 and the outer surface of the first inner seal spindle 2720 is in the range of about 0.005 to 0.125 inches to optimally provide minimal radial clearance. The radial clearance between the outer cylindrical surface of the first upper seal head 2725 and the inner surface of the casing 2790 can e.g. ranging from about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer cylindrical surface of the first upper seal head 2725 and the inner surface of the casing 2790 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 2765 during the expansion process.

The first upper seal head 2725 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The first upper seal head 2725 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the first upper seal head 2725 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces. The inner surface of the first sealing head 2725 preferably comprises one or more annular sealing members 2835 to seal the interface between the first upper sealing head 2725 and the first inner sealing spindle 2720. The sealing members 2835 may comprise any of several conventional, commercially available annular sealing members, which e.g. o-rings, polypak gaskets and metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2835 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

In a preferred embodiment, the first upper seal head 2725 comprises a shoulder 2840 to support the first upper seal head 2725 on the first lower seal head 2730.

The first upper seal head 2725 may be coupled to the first outer seal spindle 2735 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the first seal head 2725 is removably coupled into the first outer seal spindle 2735 with a standard threaded connection. In a preferred embodiment, the mechanical connection between the first upper seal head 2725 and the first outer seal spindle 2735 comprises one or more parts 2845 for fluid sealing of the interface between the first upper seal head 2725 and the first outer seal spindle 2735. The sealing parts 2845 may comprise any of several conventional, commercially available sealing parts, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2845 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

The first lower sealing head 2730 is coupled to the first inner sealing spindle 2720 and the second inner sealing spindle 2740. The first lower sealing head 2730 is also movably coupled to the inner surface of the first outer sealing spindle 2735. In this way, the first upper sealing head 2725 and the first outer seal spindle 2735 reciprocating in the axial direction. The radial clearance between the outer surface of the first lower seal head 2730 and the inner surface of the first outer seal spindle 2735 can be in the range of e.g. about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between the outer surface of the first lower seal head 2730 and the inner surface of the first outer seal spindle 2735 is in the range of about 0.005 to 0.01 inches to optimally provide minimal radial clearance.

The first lower seal head 2730 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The first lower seal head 2730 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the first lower seal head 2730 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces. The outer surface of the first lower sealing head 2730 preferably comprises one or more annular sealing members 2850 to seal the interface between the first lower sealing head 2730 and the first outer sealing spindle 2735. The sealing members 2850 may comprise any of several conventional, commercially available annular sealing members, like for example. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2850 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

The first lower seal head 2730 may be coupled to the first inner seal spindle 2720 using any of several conventional commercially available mechanical couplings, such as oilfield tubing specialty threaded connection, welding, amorphous banding, or standard threaded connection. In a preferred embodiment, the lower seal head 2730 is removably coupled to the first inner seal spindle 2720 by a standard threaded connection. In a first embodiment, the mechanical coupling between the first lower seal head 2730 and the first inner seal spindle 2720 comprises one or more sealing members 2855 for fluid sealing of the interface between the first seal head 2730 and the first inner seal spindle 2720. The sealing members 2855 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2855 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

The first lower seal head 2730 may be coupled to the second inner seal spindle 2740 using any of several conventional, commercially available mechanical couplings, such as oilfield pipe specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the lower seal head 2730 is removably coupled to the second inner seal spindle 2740 with a standard threaded connection. In a preferred embodiment, the mechanical coupling between the first lower sealing head 2730 and the second inner sealing spindle 2740 comprises one or more sealing parts 2860 for fluid sealing of the interface between the first lower sealing head 2730 and the second inner sealing spindle 2720. The sealing parts 2860 may comprise any of several conventional, commercially available sealing parts, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2860 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

The first outer seal stem 2735 is coupled to the first upper seal head 2725, the second upper seal head 2745, the second outer seal stem 2755, and the expansion cone 2765. The first outer seal stem 2735 is also movably coupled to the inner surface of the casing 2790 and the outer surface of the first lower seal head 2730. In this way, the first upper seal head 2725, the first outer seal spindle 2730, the second upper seal head 2745, the second outer spindle 2755 and the expansion cone 2765 will reciprocate in the axial direction. The radial clearance between the outer surface of the first outer sealing spindle 2735 and the inner surface of the casing 2790 can e.g. be in the range of 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer surface of the first seal spindle 2735 and the inner surface of the casing 2790 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 2765 during the expansion process. The radial clearance between the inner surface of the first outer seal spindle 2735 and the outer surface of the first lower seal head 2730 can e.g. be in the range of about 0.0025 to 0.05 inch. In a preferred embodiment, the radial clearance between the inner surface of the first outer seal spindle 2735 and the outer surface of the first lower seal head 2730 is in the range of about 0.005 to 0.01 inches to optimally provide minimum radial clearance.

The outer seal spindle 2735 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The first outer seal mandrel 2735 may be fabricated from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, a first outer seal spindle 2735 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The first outer seal spindle 2735 may be coupled to the first upper seal head 2725 using any of several conventional commercially available mechanical couplings, such as oil field pipe, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the first outer seal spindle 2735 is removably coupled to the first upper seal head 2725 with a standard threaded connection. The first outer seal spindle 2735 may be coupled to the second upper seal head 2745 using any of several conventional commercially available mechanical couplings, such as oilfield pipe specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the first outer seal spindle 2735 is removably coupled to the second upper seal head 2745 with a standard threaded connection.

The second inner sealing spindle 2740 is connected to the first lower sealing head 2730 and the second lower sealing head 2750. The second inner sealing spindle 2740 preferably comprises one or more essentially hollow tubular parts. The second inner seal spindle 2740 may be made of any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the inner seal spindle 2740 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The second inner seal spindle 2740 may be coupled to the first lower seal head 2730 using any conventional commercially available mechanical coupling, such as oilfield pipe specialty threaded connection, welding, amorphous banding or standard threaded connection. In a preferred embodiment, the second inner seal spindle 2740 is removably coupled to the first lower seal head 2740 with a standard threaded connection. The mechanical connection between the second inner sealing spindle 2740 and the first lower sealing head 2730 preferably comprises sealing parts 2860.

The second inner seal spindle 2740 may be coupled to the second lower seal head 2750 using any of several conventional, commercially available mechanical couplings, such as oilfield pipe specialty threaded connection, welding, amorphous banding or a standard threaded connection. In a preferred embodiment, the second inner seal spindle 2720 is removably coupled to the second seal head 2750 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the second inner sealing spindle 2740 and the second lower sealing head 2750 comprises one or more sealing parts 2865. The sealing parts 2865 may comprise any of several conventional, commercially available gaskets, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2865 polypak gaskets available from Parker Seals.

The second inner seal spindle 2740 preferably comprises a fluid passage 2810 which is adapted to guide liquid materials from the fluid passage 2805 into the fluid passage 2815. In a preferred embodiment, the fluid passage 2810 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The second upper seal head 2745 is coupled to the first upper seal head 2725, the first outer seal spindle 2735, the second outer seal spindle 2755, and the expansion cone 2765. The second upper seal head 2745 is also movably coupled to the outer surface of the second inner seal spindle 2740 and the inner surface of the casing 2790. In this way, the upper seal head 2745 will reciprocate in the axial direction. The radial clearance between the inner cylindrical surface of the second upper seal head 2745 and the outer surface of the second inner seal spindle 2740 can be in the range of e.g. 0.0025 to 0.05 inch. In a preferred embodiment, the radial clearance between the inner cylindrical surface of the second upper seal head 2745 and the outer surface of the second inner seal spindle 2740 is in the range of about 0.005 to 0.01 inch to optimally provide minimum radial clearance.

The radial clearance between the outer cylindrical surface of the second upper seal head 2745 and the inner surface of the casing 2790 can e.g. be in the range of about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer cylindrical surface of the second upper seal head 2745 and the inner surface of the casing 2790 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization of the expansion cone 2765 during the expansion process.

The second upper seal head 2745 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The second upper seal head 2745 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the second upper seal head 2745 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces. The inner surface of the second upper sealing head 2745 preferably comprises one or more annular sealing members 2870 to seal the interface between the second upper sealing head 2745 and the second inner sealing spindle 2740. The sealing members 2840 may comprise any of several conventional, commercially available annular sealing members, like for example. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2870 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

In a preferred embodiment, the second upper seal head 2745 comprises a shoulder 2875 to support the second upper seal head 2745 on the second lower seal head 2750.

The second upper seal head 2745 may be coupled to the first outer seal spindle 2735 using any of several conventional commercially available mechanical seals, such as drill pipe connection, oil field tubing specialty threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the second upper seal head 2745 is removably coupled to the first outer seal spindle 2735 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the second upper sealing head 2745 and the first outer sealing spindle 2735 comprises one or more sealing parts 2880 for fluid sealing of the interface between the second upper sealing head 2745 and the first outer sealing spindle 2735. The sealing parts 2880 may comprise any of several conventional, commercially available sealing parts, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing rings comprise 2880 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The second upper seal head 2745 may be coupled to the second outer seal spindle 2755 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, or a standard threaded connection. In a preferred embodiment, the second upper seal head 2745 is removably coupled to the second outer seal spindle 2755 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the second upper sealing head 2745 and the second outer sealing spindle 2755 comprises one or more sealing parts 2885 for fluid sealing of the interface between the second upper sealing head 2745 and the second outer sealing spindle 2755. The sealing parts 2885 may comprise any of several conventional, commercially available sealing parts, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2885 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

The second lower seal head 2750 is coupled to the second inner seal spindle 2740 and the load spindle 2760. The second lower seal head 2750 is also movably coupled to the inner surface of the second outer seal spindle 2755. In this way, the first upper seal head 2725, the first outer seal spindle 2735, the second upper seal head 2745, the second outer seal spindle 2755, and the expansion cone 2765, reciprocally in the axial direction. The radial clearance between the outer surface of the second lower seal head 2750 and the inner surface of the second outer seal spindle 2755 can e.g. be in the range of about 0.0025 to 0.05 inch. In a preferred embodiment, the radial clearance between the outer surface of the second lower seal head 2750 and the inner surface of the second outer seal spindle 2755 is in the range of about 0.005 to 0.01 inch to optimally provide minimal radial clearance.

The second lower seal head 2750 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The second lower seal head 2750 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the second lower seal head 2750 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces. The outer surface of the second lower seal head 2750 preferably comprises one or more annular parts 2890 to seal the interface between the second lower seal head 2750 and the second outer seal spindle 2755. The seal parts 2890 may comprise any of several conventional, commercially available annular seal parts, like for example. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2890 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

The second seal head 2750 may be coupled to the second inner seal spindle 2740 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, ratchet-lock type threaded connection, or standard threaded connection. In a preferred embodiment, the second lower seal head 2750 is removably coupled to the inner seal spindle 2740 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the second lower sealing head 2750 and the second inner sealing spindle 2740 comprises one or more sealing parts 2895 for fluid sealing of the interface between the second sealing head 2750 and the second sealing spindle 2740. The sealing parts 2895 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2895 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The second lower seal head 2750 may be coupled to the load spindle 2760 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the lower seal head 2750 is removably coupled to the load spindle 2760 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the second lower seal head 2750 and the loading spindle 2760 comprises one or more sealing members 2900 for fluid sealing of the interface between the second lower sealing head 2750 and the loading spindle 2760. The sealing members 2900 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 2900 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

In a preferred embodiment, the lower seal head 2750 comprises a throat passage 2905 fluidly coupled between the fluid passages 2810 and 2815. The throat passage 2905 is preferably of reduced size, and adapted to receive and engage with a plug 2910 or other similar device. In this way, the fluid passage 2810 is fluid isolated from the fluid passage 2815. In this way, the pressure chambers 2915 and 2920 are pressurized. The use of multiple pressure chambers in the apparatus 2700 allows the effective driving force to be multiplied. Although illustrated using a pair of pressure chambers, 2915 and 2920, the apparatus 2700 can be further modified to use additional pressure chambers.

The second outer seal stem 2755 is coupled to the first upper seal head 2725, the first outer seal stem 2735, the second upper seal head 2745, and the expansion cone 2765. The second outer seal stem 2755 is also movably coupled to the inner surface of the casing 2790 and the outer surface of the second lower seal head 2750. In this way, the first upper seal head 2725, the first outer seal spindle 2735, the second seal head 2745, the second seal spindle 2755, and the expansion cone 2765, will reciprocate in the axial direction.

The radial clearance between the outer surface of the second outer sealing spindle 2755 and the inner surface of the casing 2790 can e.g. be in the range of about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer surface of the second outer seal spindle 2755 and the inner surface of the casing 2790 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 2765 during the expansion process. The radial clearance between the inner surface of the second outer seal spindle 2755 and the outer surface of the second lower seal head 2750 can e.g. be in the range of about 0.0025 to 0.05 inch. In a preferred embodiment, the radial clearance between the inner surface of the second outer seal spindle 2755 and the outer surface of the second seal head 2750 is in the range of about 0.005 to 0.01 inches to optimally provide minimal radial clearance.

The second sealing spindle 2755 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The second outer seal mandrel 2755 may be fabricated from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the outer seal spindle 2755 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The second outer seal spindle 2755 may be coupled to the second upper seal head 2745 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the second outer seal spindle 2755 is removably coupled to the second upper seal head 2745 by a standard threaded connection. The second outer seal spindle 2755 may be coupled to the expansion cone 2765 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the second outer seal spindle 2755 is removably coupled to the expansion cone 2765 by a standard threaded connection.

The load spindle 2760 is connected to the second lower seal head 2750 and the mechanical sliding body 2755. The load spindle 2760 preferably comprises an annular part having essentially cylindrical inner and outer surfaces. The load spindle 2760 may be fabricated from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the load spindle 2760 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The load spindle 2760 may be coupled to the second lower seal head 2750 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the load spindle 2760 is removably coupled to the second lower seal head 2750 by a standard threaded connection. The load spindle 2760 may be coupled to the mechanical slider 2775 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the load spindle 2760 is removably coupled to the mechanical slider 2775 by a standard threaded connection.

The load spindle 2760 preferably comprises a fluid passage 2815 which is adapted to guide liquid materials from the fluid passage 2810 to the fluid passage 2820. In a preferred embodiment, the fluid passage 2815 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The expansion cone 2765 is coupled to the second outer sealing spindle 2755. The expansion cone 2765 is also movably coupled to the inner surface of the casing 2790. In this way, the first upper sealing head 2725, first outer sealing spindle 2735, second upper sealing head 2745, second outer sealing spindle 2755 and expansion cone 2765, reciprocating in the axial direction. The reciprocation of the expansion cone 2765 causes the casing 2790 to expand in the radial direction.

The expansion cone 2765 preferably comprises an annular part which has essentially cylindrical inner and conical outer surfaces. The outer radius of the outer conical surface can e.g. be in the range from 2 to 34 inches. In a preferred embodiment, the outer radius of the outer conical surface ranges from about 2 to 28 inches to optimally provide expansion cone dimensions that accommodate the typical area of casing. The axial length of expansion cone 2765 can e.g. be in the range of from about 2 to 8 times the largest outer diameter of expansion cone 2765. In a preferred embodiment, the axial length of expansion cone 2765 is in the range of from about 3 to 5 times the largest outer diameter of expansion cone 2765 to optimally provide stabilization and centralization of the expansion cone 2765.1 a preferred embodiment, the angle of attack for the expansion cone 2765 is in the range from about 5 to 30 degrees to optimally balance friction forces and radial expansion forces.

The expansion cone 2765 may be fabricated from any of several conventional, commercially available materials, such as, for example, machine tool steel, nitride steel, titanium, tungsten carbide, ceramic or other similar high strength materials. In a preferred embodiment, the expansion cone 2765 is manufactured from D2 machine tool steel to optimally provide high strength and resistance to corrosion and tearing. In a particularly preferred embodiment, the outer surface of the expansion cone 2765 has a surface hardness in the range of about 58 to 62 Rockwell C to optimally provide high strength and resistance to wear and tear.

The expansion cone 2765 may be coupled to the second outer seal spindle 2765 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the expansion cone 2765 is coupled to the second outer seal spindle 2765 using a standard threaded connection to optimally provide high strength and easy replacement of the expansion cone 2765.

The spindle starter 2770 is connected to the casing 2760. The spindle starter 2770 comprises a tubular section of casing that has a reduced wall thickness compared to the casing 2790. In a preferred embodiment, the wall thickness of the spindle starter 2770 is about 50 to 100% of the wall thickness of the casing 2790. The wall thickness of the spindle starter 2770 can e.g. be in the range of about 0.15 to 1.5 inches. In a preferred embodiment, the wall thickness of spindle starter 2770 is in the range of about 0.25 to 0.75 inches. In this way, starting the radial expansion of the casing 2790 is facilitated, placement of the apparatus 2700 inside a wellbore casing and a wellbore is facilitated, and the spindle starter 2770 has a breaking strength that is approximately equal to that of the casing 2790.

The spindle starter 2770 may be coupled to the casing 2790 using any of several conventional mechanical couplings, such as a standard threaded connection. The spindle starter 2770 can be made from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the spindle starter 2770 is made from higher strength oilfield tubing than the casing 2790, but with reduced wall thickness to optimally form a small compact casing holder with a breaking strength approximately equal to that of the casing 2790.

The mechanical sliding body 2775 is coupled to the load spindle 2760, the mechanical stop wedges 2780, and the drag blocks 2785. The mechanical sliding body 2775 preferably comprises a tubular portion having an internal passage 2820 fluidly coupled to the passage 2815. In this way, liquid materials can be directed from the passage 2820 to an area outside the device 2700.

The mechanical slide 2775 may be coupled to the load spindle 2760 using any of several conventional mechanical linkages. In a preferred embodiment, the mechanical slider 2775 is removably coupled to the load spindle 2760 using a standard threaded connection to optimally provide high strength and ease of disassembly. The mechanical slide 2775 may be connected to the mechanical stop wedges 2780 using any of several conventional mechanical connections. In a preferred embodiment, the mechanical sliding body 2755 is removably connected to the mechanical stop wedges 2780 using threaded connections and sliding steel retainers to optimally provide a high strength attachment. The mechanical slider 2755 may be connected to the drag blocks 2785 using any of several conventional mechanical connections. In a preferred embodiment, the mechanical sliding body 2775 is removably connected to the drag blocks 2785 using threaded connections and sliding steel retainers to optimally provide a high strength attachment.

The mechanical sliding body 2775 preferably comprises a fluid passage 2820 which is adapted to guide liquid materials through the fluid passage 2815 to the area outside the apparatus 2700. In a preferred embodiment, the fluid passage 2820 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The mechanical stop wedges 2780 are coupled to the outer surface of the mechanical sliding body 2775. During operation of the apparatus 2700, the mechanical stop wedges 2780 will prevent upward movement of the casing 2790 and the spindle starter 2770. In this way, during the axial reciprocation of the expansion cone 2765, casing 2790 and spindle starter 2770 held in a substantially stationary position. In this way, the spindle starter 2765 and the casing 2790 and the spindle starter 2770 are expanded in the radial direction by an axial movement of the expansion cone 2765.

The mechanical stop wedges 2780 may comprise any of several conventional, commercially available mechanical stop wedges, such as RTTS gasket tungsten carbide mechanical stop wedges, RTTS gasket braid type mechanical stop wedges or model 3L removable bridge plug tungsten carbide upper mechanical stop wedges. In a preferred embodiment, the mechanical stop wedges 2780 RTTS packing comprise tungsten carbide mechanical stop wedges available from Halliburton Energy Services, to optimally provide resistance to axial movement of the casing 2790 and spindle starter 2770 during the expansion process.

The drag blocks 2785 are coupled to the outer surface of the mechanical sliding body 2775. During operation of the apparatus 2700, the drag blocks 2785 prevent upward movement of the casing 2790 and the spindle starter 2770. In this way, during the axial reciprocation of the expansion cone 2765, the casing 2790 and the spindle starter 2770 become held in an essentially stationary position. In this way, the spindle starter 2770 and the casing 2790 are expanded in the radial direction by the axial movement of the expansion cone 2765.

The drag blocks 2785 may comprise any of several conventional, commercially available mechanical wedges, such as RTTS gasket mechanical drag blocks or model 3L removable bridge plug drag blocks. In a preferred embodiment, the drag blocks 2785 comprise RTTS packing mechanical drag blocks available from Halliburton Energy Services to optimally resist axial movement of the casing 2790 and spindle starter 2770 during the expansion process.

The casing 2790 is connected to the spindle starter 2770. The casing 2790 is further removably connected to the mechanical stop wedges 2780 and drag blocks 2785. The casing 2790 preferably comprises a tubular part. Casing 2790 can be made from any of several conventional, commercially available materials, such as slotted pipes, oil field pipes, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the casing 2790 is manufactured from oilfield tubing available from various foreign and domestic steel mills, to optimally provide high strength using standardized materials. In a preferred embodiment, the upper end of the casing 2790 comprises one or more sealing parts located around the outside of the casing 2790.

During operation, the apparatus 2700 is placed in a wellbore with the upper end of the casing 2790 placed in an overlapping relationship with an existing wellbore casing. To minimize transient pressure within the borehole during placement of the apparatus 2700, the fluid passage 2795 is preferably equipped with one or more pressure release passages. During placement of the apparatus 2700 in the borehole, the casing 2790 is supported by the expansion cone 2765.

After placing the apparatus 2700 in the wellbore in an overlapping relationship with an existing section of wellbore casing, a first liquid material is pumped into the fluid passage 2795 from a surface location. The first fluid material is directed from the fluid passage 2795 to the fluid passages 2800, 2802, 2805, 2810, 2815 and 2820. The first fluid material will then exit the apparatus 2700 and fill the annulus between the outside of the apparatus 2700 and the inner walls of the borehole.

The first liquid material may comprise any of several conventional, commercially available materials, such as e.g. epoxy, drilling mud, slag mixture, water or cement. In a preferred embodiment, the first liquid material comprises a curable liquid sealing material such as e.g. slag mixture, epoxy or cement. In this way, a wellbore casing can be formed which has an outer annular layer of a curable material.

The first liquid material can be pumped into the apparatus 2700 at operating pressures and flow rates in the range from e.g. about 0 to 4,500 psi and 0 to 3,000 gallons per minute. In a preferred embodiment, the first liquid material is pumped into apparatus 2700 at operating pressures and flow rates in the range of about 0 to 3,500 psi and 0 to 1,200 gallons per minute to optimally produce operating efficiency.

At a predetermined point in the injection of the first liquid material such as e.g. after the annulus outside the apparatus 2700 is filled to a predetermined level, a plug 2910, arrow or other similar device is introduced into the liquid material. The plug 2910 engages in the throat passage 2905, thereby fluidically isolating the fluid passage 2810 from the fluid passage 2815. After placing the plug 2910 in the throat passage 2905, another liquid material is pumped into the fluid passage 2995 to pressurize the pressure chambers 2915 and 2920. The other liquid the material may comprise any of several conventional, commercially available materials, such as e.g. water, drilling gases, drilling mud or lubricants. In a preferred embodiment, the second liquid material comprises a non-curable liquid material such as e.g. water, drilling mud or lubricant. The use of lubricant will optimally lubricate the moving parts of the device 2700.

The second liquid material may be pumped into the apparatus 2700 at operating pressures and flow rates in the range of about 0 to 4,500 psi and 0 to 4,500 gallons per minute. In a preferred embodiment, the second liquid material is pumped into apparatus 2700 at operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons per minute to optimally provide operating efficiency.

The pressure applied to the pressure chambers 2915 and 2920 causes the upper seal heads, 2725 and 2745, outer seal spindles 2735 and 2755, and expansion cone 2765 to move in the axial direction. As the expansion cone 2765 moves in the axial direction, the expansion cone 2765 will pull the spindle starter 2770, the casing 2790 and the drag blocks 2785 with it, which sets the mechanical stop wedges 2780 and stops further axial movement of the spindle starter 2770 and casing 2790. In this way, the axial movement will of the expansion cone 2765 radially expand the spindle starter 2770 and casing 2790.

As soon as the upper seal heads 2725 and 2745, the outer seal spindles 2735 and 2755, and the expansion cone 2765 complete an axial stroke, the operating pressure on the second fluid is reduced and the drill string 2705 is raised. This causes the inner seal spindles 2720 and 2740, the lower seal heads 2730 and 2750, the load spindle 2760 and the mechanical slide 2755 to move upward. This releases the mechanical stop wedges 2780 and allows the mechanical stop wedges 2780 and drag blocks 2785 to move upward inside the spindle starter 2770 and casing 2790. As the lower seal heads 2730 and 2750 contact the upper seal heads 2725 and 2745, the second fluid material enters again under pressure, and the radial expansion process continues. In this manner, the spindle starter 2770 and casing 2790 are radially expanded through repeated axial strokes of the upper seal heads 2725 and 2745, outer seal spindles 2735 and 2755 and expansion cone 2765. Throughout the radial expansion process, the upper end of the casing 2790 is preferably held in a overlapping relationship with an existing section of wellbore casing.

At the end of the radial expansion process, the upper end of the casing 2790 is expanded into close contact with the inner surface of the lower end of the existing wellbore casing. In a preferred embodiment, the sealing members arranged at the upper end of the casing 2790 will form a fluid seal between the outer surface of the upper end of the casing 2790 and the inner surface of the lower end of the existing wellbore casing. In a preferred embodiment, the contact pressure between the casing 2790 and the existing section of wellbore casing is in the range of about 400 to 10,000 to optimally provide contact pressure to activate the sealing members, and to provide optimal resistance to axial movement of the expanded casing, and optimally to resist typical tensile and compressive loads on the expanded casing.

In a preferred embodiment, as the expansion cone 2765 approaches the end of the casing 2790, the operating pressure of the second fluid material is reduced to minimize the shock to the apparatus 2700. In an alternative embodiment, the apparatus 2700 includes a shock absorber to absorb the shock created by the termination of the radial expansion of casing 2790.

In a preferred embodiment, the reduced operating pressure of the second fluid material is in the range of about 100 to 1,000 psi as the expansion cone 2765 approaches the end of the casing 2790 to optimally provide reduced axial movement and velocity of the expansion cone 2765. In a preferred embodiment, the operating pressure of the second liquid material is reduced during the return stroke of the apparatus 2700 to ranges from about 0 to 500 psi to minimize resistance to movement of the expansion cone 2765 during the return stroke. In a preferred embodiment, the stroke length of the apparatus 2700 ranges from about 10 to 45 feet to optimally produce equipment that can be easily handled by typical oil rig equipment and minimizes the frequency at which the apparatus 2700 must be reset during an expansion operation.

In an alternative embodiment, at least a portion of the upper seal heads 2725 and 2745 include expansion cones for radial expansion of the spindle starter 2770 and the casing 2790 during operation of the apparatus 2700, to increase the surface area of the casing 2790 that is affected during the radial expansion process. In this way, the operating pressures can be reduced.

In an alternative embodiment, mechanical stop wedges are placed at an axial location between the seal sleeve 1915 and the first inner seal spindle 2720 to optimally provide simplified assembly and operation of the apparatus 2700.

Upon completion of radial expansion of the casing 2790, if necessary, the first liquid material will be allowed to harden within the annular region between the outside of the expanded casing 2790 and the inner walls of the wellbore. In a case where the casing 2790 is slotted, the hardened fluid material will preferentially penetrate and surround the expanded casing 2790. In this way, a new section of wellbore casing is formed inside a wellbore. Alternatively, the apparatus 2700 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, the apparatus 2700 can be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of curable material. Alternatively, the apparatus 2700 can be used to expand a tubular support member in a hole.

During the radial expansion process, the areas of the apparatus 2700 that are under pressure are limited to the fluid passages 2795, 2800, 2802, 2805 and 2810 and the pressure chambers 2915 and 2920. No fluid pressure acts directly on the spindle starter 2770 and the casing 2790. This allows the use of operating pressures such as is higher than what the spindle starter 2770 and casing 2790 would normally withstand.

With reference to Figure 20, a preferred embodiment of an apparatus 3000 for forming a monodiameter wellbore casing shall be described. The apparatus 3000 preferably comprises a drill pipe 3005, an inner string adapter 3010, a sealing sleeve 3015, a first inner sealing spindle 3020, hydraulic stop wedges 3025, a first upper sealing head 3030, a first lower sealing head 3035, a first outer sealing spindle 3040, a second inner sealing spindle 3045 , a second upper seal head 3050, a second lower seal head 3055, a second outer seal spindle 3060, loading spindle 3065, expansion cone 3070, casing 3075 and fluid passages 3080, 3085, 3090, 3095, 3100, 3105, 3110, 3115 and 3120.

The drill pipe 3005 is connected to the inner string adapter 3019. During operation of the apparatus 3000, the drill pipe 3005 supports the apparatus 3000. The drill pipe 3005 preferably comprises one or more substantially hollow tubular parts. The drill pipe 3005 can be made from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the drill pipe 3005 is made of coiled pipe to facilitate placement of the apparatus 3000 in non-vertical well holes. The drill pipe 3005 may be coupled to the inner string adapter 3010 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty threaded connection, or a standard threaded connection. In a preferred embodiment, the drill pipe 3005 is removably connected to the inner string adapter 3010 by a drill pipe coupling.

The drill pipe 3005 preferably comprises a fluid passage 3080 which is adapted to lead liquid materials from a place on the surface and into the fluid passage 3085.1 a preferred embodiment, the fluid passage 3080 is adapted to lead liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The inner string adapter 3010 is connected to the drill string 3005 and the sealing sleeve 3015. The inner string adapter 3010 preferably comprises one or more essentially hollow tubular parts. The inner string adapter 3010 can be made from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the inner string adapter 3010 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The inner string adapter 3010 may be coupled to the drill string 3005 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, or a standard threaded connection. In a preferred embodiment, the inner string adapter 3010 is removably coupled to the drill pipe 3005 by a drill pipe coupling. The inner string adapter 3010 may be coupled to the sealing sleeve 3015 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the inner string adapter 3010 is removably coupled to the seal sleeve 3015 using a standard threaded connection.

The inner string adapter 3010 preferably comprises a fluid passage 3085 which is adapted to guide liquid materials from the fluid passage 3080 into the fluid passage 3090. In a preferred embodiment, the fluid passage 3085 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The sealing sleeve 3015 is connected to the inner string adapter 3010 and the first inner sealing spindle 3020. The sealing sleeve 3015 preferably comprises one or more essentially hollow pipe parts. The sealing sleeve 3015 can be made from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the sealing sleeve 3015 is made of stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The sealing sleeve 3015 may be coupled to the inner string adapter 3010 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type connection or a standard threaded connection. In a preferred embodiment, the sealing sleeve 3015 is removably coupled to the inner string adapter 3010 by a standard threaded connection. The seal sleeve 3015 may be coupled to the first inner seal spindle 3020 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the seal sleeve 3015 is removably coupled to the first inner seal spindle 3020 by a standard threaded connection.

The sealing sleeve 3015 preferably comprises a fluid passage 3090 which is adapted to guide liquid materials from the fluid passage 3085 into the fluid passage 3095. In a preferred embodiment, the fluid passage 3090 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The first inner sealing spindle 3020 is connected to the sealing sleeve 3015, the hydraulic stop wedges 3025, and the first lower sealing head 3035. The first inner sealing spindle 3020 is further movably connected to the first upper sealing head 3030. The first inner sealing spindle 3020 preferably comprises one or more in mainly hollow tubular parts. The first inner seal mandrel 3020 may be fabricated from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or similar high strength materials. In a preferred embodiment, the first inner seal spindle 3020 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The first inner seal spindle 3020 may be coupled to the seal housing 3015 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or standard threaded connection. In a preferred embodiment, the first inner seal spindle 3020 is removably coupled to the seal sleeve 3015 with a standard threaded connection. The first inner seal spindle 3020 may be coupled to the hydraulic stop wedges 3025 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the first inner seal spindle 3020 is removably coupled to the hydraulic stop wedges 3025 with a standard threaded connection. The first inner seal spindle 3020 may be coupled to the first lower seal head 3035 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the first inner seal spindle 3020 is removably coupled to the first lower seal head 3035 by a standard threaded connection.

The first inner seal spindle 3020 preferably comprises a fluid passage 3095 which is adapted to guide liquid materials from the fluid passage 3090 into the fluid passage 3100. In a preferred embodiment, the fluid passage 3095 is adapted to guide liquid materials such as e.g. water, drilling mud, cement, epoxy or lubricants, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The first inner seal spindle 3020 preferably further comprises fluid passages 3110 which are adapted to guide liquid materials from the fluid passage 3095 into the pressure chambers of the hydraulic stop wedges 3095. In this way, the stop wedges 3095 are activated by pressurizing the fluid passage 3095 into contact with the inner surface of the casing 3075.1 a preferred embodiment, the fluid passages 3110 are adapted to conduct liquid materials, such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The first inner seal spindle 3020 preferably further comprises fluid passages 3115 which are adapted to direct liquid materials from the fluid passage 3095 into the pressure chamber 3175 which is defined by the upper seal head 3030, the first lower seal head 3035, the first inner seal spindle 3020, and the first outer seal spindle 3040. During operation of the apparatus 3000, pressure applied to the pressure chamber 3175 will cause the first upper seal head 3030, the first outer seal spindle 3040, the upper second seal head 3050, the second outer seal spindle 3060, and the expansion cone 3070 to move in the axial direction.

The stop wedges 3025 are coupled to the outer surface of the first inner seal mandrel 3020. During operation of the apparatus 3000, the stop wedges 3025 are activated upon application of pressure in the passages 3095 to contact the inner surface of the casing 3075. In this way, the stop wedges 3025 will hold the casing 3075 in an essentially stationary position.

The stop wedges 3025 preferably comprise fluid passages 3125, pressure chambers 3130, spring bias 3135, and wedge parts 3140. The stop wedges 3025 may comprise any of several conventional, commercially available hydraulic wedges, such as RTTS gasket tungsten carbide hydraulic wedges or model 3L removable bridge plug with hydraulic wedges. In a preferred embodiment, the wedges 3025 RTTS packing comprise tungsten carbide hydraulic wedges available from Halliburton Energy Services, to optimally provide resistance to axial movement of the casing 3075 during the expansion process. The first upper seal head 3030 is coupled to the first outer seal stem 3040, the second upper seal head 3050, the second outer seal stem 3060, and expansion cone 3070. The first upper seal head 3030 is also movably coupled to the outer surface of the first inner seal stem 3020 and the inner surface of the casing 3075. In this way, the first upper sealing head 3030, the first outer sealing spindle 3040, the second upper sealing head 3050, the second outer sealing spindle 3060 and the expansion cone 3070 will reciprocate in the axial direction.

The radial clearance between the inner cylindrical surface of the first upper seal head 3030 and the outer surface of the first inner seal spindle 3020 can e.g. be in the range of 0.0025 to 0.5 inch. In a preferred embodiment, the radial clearance between the inner cylindrical surface of the first upper seal head 3030 and the outer surface of the first inner seal spindle 3020 is in the range of about 0.005 to 0.01 inch to optimally provide minimum radial clearance. The radial clearance between the outer cylindrical surface of the first upper seal head 3030 and the inner surface of the casing 3075 can e.g. be in the range of about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer cylindrical surface of the first upper seal head 3030 and the inner surface of the casing 3075 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 3070 during the expansion process.

The first upper seal head 3030 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The first upper seal head 3030 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, or other similar high strength materials. In a preferred embodiment, the first upper seal head 3030 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces. The inner surface of the first upper sealing head 3030 preferably comprises one or more annular sealing members 3145 to seal the interface between the first upper sealing head 3030 and the first inner sealing spindle 3020. The sealing members 3145 may comprise any of several conventional, commercially available annular sealing members, like for example. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing members 3145 comprise polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

In a preferred embodiment, the first upper seal head 3030 comprises a shoulder 3150 to support the first upper seal head 3030, first outer seal spindle 3040, second upper seal head 3050, second outer seal spindle 3060, and expansion cone 3070 on the first lower seal head 3035.

The first upper seal head 3030 may be coupled to the first outer seal spindle 3040 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, or standard threaded connection. In a preferred embodiment, the first upper seal head 3030 is removably coupled to the first outer seal spindle 3040 with a standard threaded connection. In a preferred embodiment, the mechanical coupling between the first upper sealing head 3030 and the first outer sealing spindle 3040 comprises one or more sealing parts 3155 for fluid sealing of the interface between the first upper sealing head 3030 and the first outer sealing spindle 3040. The sealing parts 3155 may comprise any of several conventional, commercially available sealing parts, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 3155 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The first lower sealing head 3035 is coupled to the first inner sealing spindle 3020 and the second inner sealing spindle 3045. The first lower sealing head 3035 is also movably coupled to the inner surface of the first outer sealing spindle 3040. In this way, the first upper sealing head 3030 , first outer seal spindle 3040, second upper seal head 3050, second outer seal spindle 3050, and expansion cone 3070, reciprocate in the axial direction. The radial clearance between the outer surface of the first lower seal head 3035 and the inner surface of the first outer seal spindle 3040 may range from about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between the outer surface of the first lower seal head 3035 and the inner surface of the outer seal spindle 3040 is in the range of about 0.005 to 0.01 inch to optimally provide minimal radial clearance.

The first lower seal head 3035 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The first lower seal head 3035 may be fabricated from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the first lower sealing head 3035 is made of stainless steel to optimally provide great strength, corrosion resistance and low-friction surfaces. The outer surface of the first lower sealing head 3035 preferably comprises one or more annular sealing members 3160 to seal the interface between the first lower sealing head 3035 and the first outer sealing spindle 3040. The sealing members 3160 may comprise any of several conventional, commercially available annular sealing members, like for example. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts 3160 comprise polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The first lower seal head 3035 may be coupled to the first inner seal spindle 3020 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the lower seal head 3035 is removably coupled to the first inner seal spindle 3020 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the first lower sealing head 3035 and the first inner sealing spindle 3020 comprises one or more sealing parts 3165 for fluid sealing of the interface between the first lower sealing head 3035 and the first inner sealing spindle 3020. The sealing parts 3165 may comprise any of several conventional, commercially available sealing parts, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts 3165 comprise polypak gaskets available from Parker Seals, to optimally produce a seal for a long axial stroke.

The first lower seal head 3035 may be coupled to the second inner seal spindle 3045 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the first lower seal head 3035 is removably coupled to the second inner seal spindle 3045 with a standard threaded connection. In a preferred embodiment, the mechanical coupling between the first lower sealing head 3035 and the second inner sealing spindle 3045 comprises one or more sealing parts 3170 for fluid sealing of the interface between the first lower sealing head 3035 and the second inner sealing spindle 3045. The sealing parts 3170 may comprise any of several conventional, commercially available sealing parts, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing members 3170 comprise polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The first outer sealing spindle 3040 is coupled to the first upper sealing head 3030 and the second upper sealing head 3050. The first outer sealing spindle 3040 is also movably coupled to the inner surface of the casing 3075 and the outer surface of the first lower sealing head 3035. In this way , the first upper seal head 3030, first outer seal stem 3040, second upper seal head 3050, second outer seal stem 3060, and expansion cone 3070 will reciprocate in the axial direction. The radial clearance between the outer surface of the first outer seal mandrel 3040 and the inner surface of the casing 3075 may range, e.g., from about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer surface of the first outer seal spindle 3040 and the inner surface of the casing 3075 ranges from about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 3070 during the expansion process. The radial clearance between the inner surface of the first outer seal spindle 3040 and the outer surface of the first lower seal head 3035 can e.g. be in the range of about 0.005 to 0.125 inches. In a preferred embodiment, the radial clearance between the inner surface of the first outer seal spindle 3040 and the outer surface of the first lower seal head 3035 is in the range of about 0.005 to 0.01 inches to optimally provide minimal radial clearance.

The first outer sealing spindle preferably comprises an annular part having essentially cylindrical inner and outer surfaces. The first outer seal mandrel 3040 may be fabricated from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the first outer seal spindle 3040 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The first outer seal spindle 3040 may be coupled to the first upper seal head 3030 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or standard threaded connection. In a preferred embodiment, the first outer seal spindle 3040 is removably coupled to the first upper seal head 3030 with a standard threaded connection. In a preferred embodiment, the mechanical coupling between the first outer sealing spindle 3040 and the first upper sealing head 3030 comprises one or more sealing parts 3180 to seal the interface between the first outer sealing spindle 3040 and the upper sealing head 3030. The sealing parts 3180 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 3180 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The first outer seal spindle 3040 may be coupled to the second upper seal head 3050 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the first outer seal spindle 3040 is removably coupled to the second upper seal head 3050 with a standard threaded connection. In a preferred embodiment, the mechanical connection between the first outer sealing spindle 3040 and the second upper sealing head 3050 comprises one or more sealing parts 3185 to seal the interface between the first sealing spindle 3040 and the second upper sealing head 3050. The sealing parts 3185 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 3185 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

The second inner sealing spindle 3045 is connected to the first lower sealing head 3035 and the second lower sealing head 3055. The second inner sealing spindle 3045 preferably comprises one or more essentially hollow tubular parts. The second inner seal mandrel 3045 may be fabricated from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the second inner seal spindle 3045 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The second inner seal spindle 3045 may be coupled to the first lower seal head 3035 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection or a standard threaded connection. In a preferred embodiment, the second inner seal spindle 3045 is removably coupled to the first lower seal head 3035 with a standard threaded connection. The second inner seal spindle 3045 may be coupled to the second lower seal head 3055 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type connection or a standard threaded connection. In a preferred embodiment, the second inner seal spindle 3045 is removably coupled to the second lower seal head 3055 by a standard threaded connection.

The second inner seal spindle 3045 preferably comprises a fluid passage 3100 which is adapted to guide liquid materials from the fluid passage 3095 into the fluid passage 3105. In a preferred embodiment, the fluid passage 3100 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants, at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The second sealing spindle 3045 preferably further comprises fluid passages 3120 which are adapted to guide liquid materials from the fluid passage 3100 into the second pressure chamber 3190 defined by the second upper sealing head 3050, the second lower sealing head 3055, the second inner sealing spindle 3045, and the second outer seal spindle 3060. During operation of the apparatus 3000, applying pressure to the second pressure chamber 3190 will cause the first upper seal head 3030, the first outer seal spindle 3040, the second upper seal head 3050, the second outer seal spindle 3060, and the expansion cone 3070 to move in the axial direction.

The second upper sealing head 3050 is coupled to the first outer sealing spindle 3040 and the second outer sealing spindle 3060. The second upper sealing head 3050 is also movably coupled to the outer surface of the second inner sealing spindle 3045 and the inner surface of the casing 3075. In this way , the second upper seal head 3050 will reciprocate in the axial direction. The radial clearance between the inner cylindrical surface of the second upper seal head 3050 and the outer surface of the second inner seal spindle 3045 can be e.g. ranging from about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between the inner cylindrical surface of the second upper seal head 3050 and the outer surface of the second inner seal spindle 3045 is in the range of about 0.005 to 0.01 inch to optimally provide minimum radial clearance. The radial clearance between the outer cylindrical surface of the second upper seal head 3050 and the inner surface of the casing 3075 can e.g. be in the range of about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer cylindrical surface of the second upper seal head 3050 and the inner surface of the casing 3075 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 3070 during the expansion process.

The second upper seal head 3050 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The second upper seal head 3050 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the second upper seal head 3050 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces. The inner surface of the second upper seal head 3050 preferably comprises one or more annular sealing members 3195 to seal the interface between the second upper sealing head 3050 and the second inner sealing spindle 3045. The sealing members 3195 may comprise any of several conventional, commercially available annular sealing members, like for example. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts comprise 3195 polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

In a preferred embodiment, the upper seal head 3050 comprises a shoulder 3200 to support the first upper seal head 3030, first outer seal spindle 3040, second upper seal head 3040, second outer seal spindle 3060, and expansion cone 3070, on the second lower seal head 3055.

The second upper seal head 3050 may be coupled to the first outer seal spindle 3040 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the second upper seal head 3050 is removably coupled to the first outer seal spindle 3040 with a standard threaded connection. In a preferred embodiment, the mechanical coupling between the second upper sealing head 3050 and the first outer sealing spindle 3040 comprises one or more sealing parts 3185 for fluid sealing of the interface between the second upper sealing head 3050 and the first outer sealing spindle 3040. The second upper sealing head 3050 can be coupled to the second outer seal spindle 3060 using any of several conventional commercially available mechanical couplings, such as drill pipe coupling, oil field pipe specialty type threaded connection, ratchet-lock type threaded connection, or a standard threaded connection. In a preferred embodiment, the second upper seal head 3050 is removably coupled to the second outer seal spindle 3060 with a standard threaded connection. In a preferred embodiment, the mechanical connection between the second upper sealing head 3050 and the second outer sealing spindle 3060 comprises one or more sealing parts 3205 for fluid sealing of the interface between the second upper sealing head 3050 and the second outer sealing spindle 3060.

The second lower seal head 3055 is coupled to the second inner seal spindle 3045 and the load spindle 3065. The second lower seal head 3055 is also movably coupled to the inner surface of the second outer seal spindle 3060. In this way, the first upper seal head 3030, first outer sealing spindle 3040, second upper sealing spindle 3050, second outer sealing spindle 3060, and expansion cone 3070 reciprocate in the axial direction. The radial clearance between the outer surface of the second lower seal head 3055 and the inner surface of the second outer seal spindle 3060 can e.g. be in the range of about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between the outer surface of the second lower seal head 3055 and the inner surface of the second outer seal spindle 3060 is in the range of about 0.005 to 0.01 inches to optimally provide minimum radial clearance.

The second lower seal head 3055 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The second lower seal head 3055 may be fabricated from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel, or other similar high strength materials. In a preferred embodiment, the second lower seal head 3055 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces. The outer surface of the second lower sealing head 3055 preferably comprises one or more annular sealing members 3210 to seal the interface between the second lower sealing head 3055 and the second outer sealing spindle 3060. The sealing members 3210 may comprise any of several conventional, commercially available annular sealing members, like for example. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the gasket parts 3210 comprise polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

The second lower seal head 3055 may be coupled to the second inner seal spindle 3045 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, or a standard threaded connection. In a preferred embodiment, the second lower seal head 3055 is removably coupled to the second inner seal spindle 3045 with a standard threaded connection. In a preferred embodiment, the mechanical connection between the lower sealing head 3055 and the second inner sealing spindle 3045 comprises one or more sealing parts 3215 for fluid sealing of the interface between the second lower sealing head 3055 and the second inner sealing spindle 3045. The sealing parts 3215 may comprise any of several conventional, commercially available sealing parts, such as o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts include 3215 polypak gaskets available from Parker Seals, to optimally provide sealing for long axial strokes.

The second seal head 3055 may be coupled to the load spindle 3065 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, or a standard threaded connection. In a preferred embodiment, the second lower seal head 3055 is removably coupled to the load spindle 3065 by a standard threaded connection. In a preferred embodiment, the mechanical coupling between the second lower seal head 3055 and the loading spindle 3065 comprises one or more sealing members 3220 for fluid sealing of the interface between the second lower sealing head 3055 and the loading spindle 3065. The sealing members 3220 may comprise any of several conventional, commercially available sealing parts, such as e.g. o-rings, polypak gaskets, or metal spring-energized gaskets. In a preferred embodiment, the sealing parts 3220 comprise polypak gaskets available from Parker Seals, to optimally provide sealing for a long axial stroke.

In a preferred embodiment, the second lower seal head 3055 comprises a throat passage 3225 which is fluidly coupled between the fluid passages 3100 and 3105. The throat passage 3225 is preferably of reduced size, and adapted to receive and engage with a plug 3230 or other similar device. In this way, the fluid passage 3100 is fluid isolated from the fluid passage 3105. In this way, the pressure chambers 3175 and 3190 are put under pressure. Furthermore, placing the plug 3230 in the throat passage 3225 will also add pressure to the pressure chambers 3130 in the hydraulic stop wedges 3025.

The second outer sealing spindle 3060 is coupled to the second upper sealing head 3050 and the expansion cone 3070. The second outer sealing spindle 3060 is also movably coupled to the inner surface of the casing 3075 and the outer surface of the second lower sealing head 3055. In this way, it will first upper seal head 3030, first outer seal spindle 3040, second seal head 3050, second seal spindle 3060, and expansion cone 3070, reciprocating in the axial direction. The radial clearance between the outer surface of the second outer sealing spindle 3060 and the inner surface of the casing 3075 can e.g. be in the range of about 0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between the outer surface of the outer seal spindle 3060 and the inner surface of the casing 3075 is in the range of about 0.025 to 0.125 inches to optimally provide stabilization for the expansion cone 3070 during the expansion process. The radial clearance between the inner surface of the second outer seal spindle 3060 and the outer surface of the second lower seal head 3055 can e.g. be in the range of about 0.0025 to 0.05 inch. In a preferred embodiment, the radial clearance between the inner surface of the second outer seal spindle 3060 and the outer surface of the second lower seal head 3050 is in the range of about 0.005 to 0.01 inches to optimally provide minimum radial clearance.

The second outer seal spindle 3060 preferably comprises an annular portion having substantially cylindrical inner and outer surfaces. The second outer seal mandrel 3060 may be fabricated from any of several conventional, commercially available materials, such as, for example, oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the second outer seal spindle 3060 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The second outer seal spindle 3060 may be coupled to the second upper seal head 3050 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, or a standard threaded connection. In a preferred embodiment, the outer seal spindle 3060 is removably coupled to the second upper seal head 3050 by a standard threaded connection. The second outer seal spindle 3060 may be coupled to the expansion cone 3070 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil field tubing specialty type threaded connection, or a standard threaded connection. In a preferred embodiment, the second outer seal spindle 3060 is removably coupled to the expansion cone 3070 with a standard threaded connection. The first upper seal head 3030, the first lower seal head 3035, the first inner seal stem 3020, and the first outer seal stem 3040 together define the first pressure chamber 3175. The second upper seal head 3050, the second lower seal head 3055, the second inner seal stem 3045 and the second outer seal spindle 3060 collectively defines the second pressure chamber 3190. The first and second pressure chambers 3175 and 3190 are fluidly coupled to the passages 3095 and 3100, via one or more passages, 3115 and 3120. During operation of the apparatus 3000, the plug 3230 engages with throat passage 3225 to fluidly isolate fluid passage 3100 from fluid passage 3105. Pressure chambers 3175 and 3190 are then pressurized, which in turn causes first upper seal head 3030, first outer seal stem 3040, second upper seal head 3050, second outer seal stem 3060 and the expansion cone 3070 reciprocates in the axial direction. The axial movement of the expansion cone 3070 will in turn expand the casing 3075 in the radial direction. The use of multiple pressure chambers, 3175 and 3190, will effectively multiply the available drive power for the 3070 expansion cone.

The load spindle 3065 is connected to the second lower seal head 3055. The load spindle 3065 preferably comprises an annular part which has essentially cylindrical inner and outer surfaces. The load spindle 3065 can be made from any of several conventional, commercially available materials, such as oil field pipe, low alloy steel, carbon steel, stainless steel or other similar high strength materials. In a preferred embodiment, the load spindle 3065 is manufactured from stainless steel to optimally provide high strength, corrosion resistance and low friction surfaces.

The load spindle 3065 may be coupled to the lower seal head 3055 using any of several conventional commercially available mechanical couplings, such as epoxy, cement, water, drilling mud or lubricants. In a preferred embodiment, the load spindle 3065 is removably coupled to the lower seal head 3055 by a standard threaded connection.

The loading spindle 3065 preferably comprises a fluid passage 3105 which is adapted to guide liquid materials from the fluid passage 3100 to the area outside the apparatus 3000. In a preferred embodiment, the fluid passage 3105 is adapted to guide liquid materials such as e.g. cement, epoxy, water, drilling mud or lubricants at operating pressures and flow rates in the range of about 0 to 9,000 psi and 0 to 3,000 gallons per minute.

The expansion cone 3070 is coupled to the second outer sealing spindle 3060. The expansion cone 3070 is also movably coupled to the inner surface of the casing 3075. In this way, the first upper sealing head 3030, first outer sealing spindle 3040, second upper sealing spindle 3050, second outer sealing spindle 3060 , and expansion cone 3070, reciprocating in the axial direction. The reciprocation of the expansion cone 3070 causes the casing 3075 to expand in the radial direction.

The expansion cone 3070 preferably comprises an annular part which has essentially cylindrical inner and conical outer surfaces. The outer radius of the outer conical surface may range, e.g., from about 2 to 34 inches. In a preferred embodiment, the outer radius of the outer conical surface ranges from 3 to 28 inches to optimally produce an expansion cone 3070 for expanding typical casing. The axial length of expansion cone 3070 can e.g. be in the range from 2 to 8 times the maximum outer diameter of the expansion cone 3070.1 a preferred embodiment, the axial length of the expansion cone 3070 is in the range from about 3 to 5 times the maximum outer diameter of the expansion cone 3070 to optimally produce stabilization and centralization of the expansion cone 3070 during the expansion process. In a particularly preferred embodiment, the maximum outer diameter of the expansion 3070 is between about 95 to 99% of the inner diameter of the existing wellbore to which the casing 3075 will be joined. In a preferred embodiment, the angle of attack of the expansion cone 3070 is in the range of about 5 to 30 degrees to optimally balance the frictional forces with the radial expansion forces.

The expansion cone 3070 can be made from any of several conventional, commercially available materials, such as machine tool steel, nitride steel, titanium, tungsten carbide, ceramic or other similar high strength materials. In a preferred embodiment, the expansion cone 3070 is manufactured from D2 machine tool steel to optimally provide high strength and resistance to wear and tear. In a particularly preferred embodiment, the outer surface of the expansion cone 3070 has a surface hardness in the range of about 58 to 62 Rockwell C to optimally provide high strength and resistance to wear and tear.

The expansion cone 3070 may be coupled to the second outer seal spindle 3060 using any of several conventional, commercially available mechanical couplings, such as drill pipe coupling, oil pipe specialty type threaded connection, ratchet-lock type connection, and standard threaded connection. In a preferred embodiment, the expansion cone 3070 is coupled to the second outer seal spindle 3060 using a standard threaded connection to optimally provide high strength and ease of disassembly.

The casing 3075 is removably connected to the stop wedges 3025 and expansion cone 3070. The casing 3075 preferably comprises a tubular part. The casing 3075 can be made from any of several conventional, commercially available materials, such as, for example, slotted pipe, oil field pipe, carbon steel, low alloy steel, stainless steel or other similar high strength materials. In a preferred embodiment, casing 3075 is fabricated from oil field tubing available from various foreign and domestic steel mills, to optimally produce high strength.

In a preferred embodiment, the upper end 3235 of the casing 3075 comprises a thin-walled section 3240 and an outer annular sealing portion 3245. In a preferred embodiment, the wall thickness of the thin-walled section 3240 is about 50 to 100% of the regular wall thickness of the casing 3075. In this way , the upper end 3235 of the casing 3075 can easily be radially expanded and deformed into close contact with the lower end of an existing section of wellbore casing. In a preferred embodiment, the lower end of the existing section of casing also comprises a thin-walled section. In this way, the radial expansion of the thin-walled section 3240 of the casing 3075 into the thin-walled section of the existing casing will result in a wellbore casing having a substantially constant internal diameter.

The annular sealing member 3245 can be made from any of several conventional, commercially available sealing materials, such as, for example, epoxy, rubber, metal or plastic. In a preferred embodiment, the annular sealing member 3245 is manufactured from StrataLock epoxy to optimally provide compressibility and wear resistance. The outer diameter of the annular sealing member 3245 is preferably in the range of about 70 to 95% of the inner diameter of the lower section of the wellbore casing to which the casing 3075 is joined. In this manner, after radial expansion, the annular seal member 3245 will optimally produce a fluid seal and also preferably optimally produce sufficient frictional force with the inner surface of the existing section of wellbore casing during the radial expansion of the casing 3075, to support the casing 3075.

In a preferred embodiment, the lower end 3250 of the casing 3075 comprises a thin wall section 3255 and an outer annular sealing portion 3260. In a preferred embodiment, the wall thickness of the thin wall section 3255 is about 50 to 100% of the regular wall thickness of the casing 3075. On in this way, the lower end 3250 of the casing 3075 can be easily expanded and deformed. Furthermore, in this manner, another section of casing can be easily joined to the lower end 3250 of the casing 3075 using a radial expansion process. In a preferred embodiment, the upper end of the second section of casing also comprises a thin-walled section. In this way, the radial expansion of the thin wall section of the upper end and the second casing into the thin wall section 3255 of the lower end 3250 of the casing 3075 will result in a wellbore casing having a substantially constant internal diameter.

The upper annular seal member 3245 may be fabricated from any of several conventional, commercially available materials, such as, for example, epoxy, rubber, metal or plastic. In a preferred embodiment, the upper annular seal member 3245 is made of StrataLock epoxy to optimally provide compressibility and wear resistance. The outer diameter of the upper annular seal portion 3245 is preferably in the range of about 70 to 95% of the inner diameter of the lower section of the existing wellbore casing to which the casing 3075 is joined. In this way, after radial expansion, the upper annular seal portion 3245 will preferably form a fluid seal and also preferably provide sufficient frictional force with an inner wall of the wellbore during radial expansion of the casing 3075 to support the casing 3075.

The lower annular sealing member 3260 may be made of any of several conventional, commercially available sealing materials, such as, for example, epoxy, rubber, metal or plastic. In a preferred embodiment, the lower annular seal member 3260 is made of StrataLock epoxy to optimally provide compressibility and wear resistance. The outer diameter of the lower annular seal portion 3260 is preferably in the range of about 70 to 95% of the inner diameter of the lower section of the existing wellbore casing to which the casing 3075 is joined. In this manner, the lower annular seal portion 3260 will preferably form a fluid seal, and also preferably produce sufficient frictional force with the inner wall of the wellbore during radial expansion of the casing 3075 to support the casing 3075.

In operation, the apparatus 3000 is preferably located in a wellbore with an upper end 3265 of casing 3275 positioned in an overlapping relationship with the lower end of an existing wellbore casing. In a particularly preferred embodiment, the thin wall section 3240 of the casing 3275 is positioned in an opposite overlapping relationship with the thin wall section and the outer annular seal portion of the lower end of the existing section of wellbore casing. In this manner, radial expansion of the casing 3075 will compress the thin wall sections and annular compressible portions of the upper end 3235 of the casing 3075 and the lower end of the existing wellbore casing into close contact. During the placement of the apparatus 3000 in the wellbore, the casing 3000 is preferably supported by the expansion cone 3070.

After positioning the apparatus 3000, a first liquid material is then pumped into the fluid passage 3080. The first liquid material may comprise any of several conventional, commercially available materials, such as, for example, drilling mud, water, epoxy, cement, slag mixture or lubricants. In a preferred embodiment, the first liquid material comprises a curable liquid sealing material, such as e.g. cement, epoxy or slag mixture, to optimally produce a hardenable outer annular body around the expanded casing 3075.

The first liquid material may be pumped into the fluid passage 3080 at operating pressures and flow rates in the range of about 0 to 4,500 psi and 0 to 4,500 gallons per minute. In a preferred embodiment, the first liquid material is pumped into the fluid passage 3080 at operating pressures and flow rates in the range of 0 to 3,500 psi and 0 to 1,200 gallons per minute to optimally produce operating efficiency.

The first liquid material that is pumped into the fluid passage 3080 passes through the fluid passages 3085, 3090, 3095, 3100 and 3105, and then outside the apparatus 3000. The first liquid material then preferably fills the annulus between the outside of the apparatus 3000 and the inner walls of the wellbore.

The plug 3230 is then inserted into the fluid passage 3080. The plug 3230 attaches to the neck passage 3225 and fluid isolates and blocks the fluid passage 3100. In a preferred embodiment, a couple of volumes of non-curable liquid material are then pumped into the fluid passage 3080 to remove possible curable liquid materials which are there, and to ensure that none of the fluid passages are blocked.

A second liquid material is then pumped into the fluid passage 3080. The second liquid material may comprise any of several conventional, commercially available materials, such as, for example, water, drilling gases, drilling mud or lubricants. In a preferred embodiment, the second liquid material comprises a non-curable liquid material, such as e.g. water, drilling mud, drilling gases or lubricant, to optimally pressurize the pressure chambers 3175 and 3190.

The second liquid material can be pumped into the fluid passage 3080 at operating pressures and flow rates in the range from e.g. 0 to 4,500 psi and 0 to 4,500 gallons per minute. In a preferred embodiment, the second liquid material is pumped into fluid passage 3080 at operating pressures and flow rates in the range of about 0 to 3,500 psi and 0 to 1,200 gallons per minute to optimally produce operating efficiency.

The second liquid material pumped into the fluid passage 3080 passes through the fluid passages 3085, 3090, 3095, 3100 and into the pressure chambers 3130 of the stop wedges 3025, and into the pressure chambers 3175 and 3190. Continued pumping of the second liquid material will pressurize the pressure chambers 3130 , 3175 and 3190.

The supply of pressure to the pressure chambers 3130 causes the hydraulic stop wedge members 3140 to expand in the radial direction and grip the inner surface of the casing 3075. The casing 3075 is then preferably held in a substantially stationary position.

Supply of pressure to the pressure chambers 3175 and 3190 causes the upper seal head 3030, first outer seal stem 3040, second upper seal head 3050, second outer seal stem 3060 and expansion cone 3070 to move in an axial direction relative to the casing 3075. In this way, the expansion cone 3070 causing the casing 3075 to expand in a radial direction, beginning at the lower end 3250 of the casing 3075.

During the radial expansion process, the casing 3075 is prevented from moving in the upward direction by the stop wedges 3025. A length of the casing 3075 is then expanded in the radial direction through pressure supply to the pressure chambers 3175 and 3190. The length of the casing 3075 that is expanded during the expansion process will be proportional to the stroke length of the first upper seal head 3030, first outer seal spindle 3040, second upper seal head 3050, and expansion cone 3070.

Upon completion of a stroke, the operating pressure of the second fluid material is reduced, and the first upper seal head 3030, first outer seal stem 3040, second upper seal head 3050, second outer seal stem 3060, and expansion cone 3070 fall to their rest positions, with the casing 3075 supported by the expansion cone 3070. The reduction in operating pressure of the second fluid also causes the spring bias 3135 of the stop wedges 3025 to pull the stop wedges 3140 away from the inner wall of the casing 3075.

The position of the drill pipe 3075 is preferably adjusted throughout the radial expansion process to maintain the overlapping relationship between the thin-walled sections of the lower end of the existing wellbore casing and the upper end of the casing 3235. In a preferred embodiment, the blows of the expansion cone 3070 as repeated as necessary, until the thin wall section 3240 of the upper end 3235 of the casing 3275 is expanded into the thin wall section of the lower end of the existing wellbore casing. In this way, a wellbore casing comprising two adjacent sections of casing having a substantially constant internal diameter is formed. This process can be repeated for the entire wellbore, to produce a wellbore casing of several thousand feet in length, which has an essentially constant internal diameter.

In a preferred embodiment, during the last stroke of the expansion cone 3070, the stop wedges 3225 are placed as close as possible to the thin-walled section 3240 of the upper end 3235 of the casing 3075 to minimize slippage between the casing 3075 and the existing wellbore casing at the end of the radial expansion process. Alternatively, or in addition, the outside diameter of the upper annular seal member 3245 is selected to ensure sufficient interference fit with the inside diameter of the lower end of the existing casing to prevent axial displacement of the casing 3075 during the final stroke.

Alternatively or additionally, the outside diameter of the lower annular seal member 3260 is selected to provide an interference fit with the inner wall of the wellbore at an earlier point in the radial expansion process to prevent further axial displacement of the casing 3075.1 this latter option, the interference fit is preferably chosen to allow expansion of the casing 3075 by pulling the expansion cone 3075 out of the wellbore, without depressurizing the pressure chambers 3175 and 3190.

During the radial expansion process, the areas of the apparatus 3000 that are under pressure are preferably limited to the fluid passages 3080, 3085, 3090, 3095, 3100, 3110, 3115, 3120, the pressure chambers 3130 inside the stop wedges 3025, and the pressure chambers 3175 and 3190. No fluid pressure acts directly on the casing 3075. This allows the use of operating pressures higher than what the casing 3075 would normally withstand.

As soon as the casing 3075 is fully expanded from the expansion cone 3070, the other parts of the apparatus 3000 are removed from the wellbore. In a preferred embodiment, the contact pressure between the deformed thin wall sections and compressible annular members at the lower end of the existing casing and the upper end 3235 of the casing 3075 is in the range of about 400 to 10,000 psi to optimally support the casing 3075 using the existing wellbore casing.

In this manner, the casing 3075 is radially expanded into contact with an existing section of casing by applying pressure to the internal fluid passages 3080, 3085, 3090, 3095, 3100, 3110, 3115, and 3120, the pressure chambers 3190 of the stop wedges 3025, and the pressure chambers 3175 and 3190 in the device 3000.

In a preferred embodiment, as necessary, the annular body of curable liquid material is then allowed to harden to form a rigid outer annular body around the expanded casing 3075. In the case where the casing 3075 is slotted, the cured liquid material will preferably penetrate into and surrounding the expanded casing 3075. The resulting new section of wellbore casing comprises the expanded casing 3075 and the rigid outer annular body. The overlapping joint between the preexisting wellbore casing and the expanded casing 3075 includes the deformed thin wall sections and the compressible outer annular bodies. The internal diameter of the resulting combined wellbore casing is essentially constant. In this way, a monodiameter wellbore casing is formed. This process of expanding overlapping tubular members having thin-walled end regions with compressible annular bodies in contact can be repeated for the entire length of the wellbore. In this way, a monodiameter wellbore casing can be produced for thousands of feet in a subterranean formation.

In a preferred embodiment, as the expansion cone 3070 approaches the upper end 3235 of the casing '3075, the operating flow rate of the second fluid material is reduced to minimize the shock to the apparatus 3000. In an alternative embodiment, the apparatus 3000 includes a shock absorber to absorb the shock created by the completion of the radial expansion of casing 3075.

In a preferred embodiment, the reduced operating pressure of the second fluid material is in the range of about 100 to 1,000 psi as the expansion cone 3070 approaches the end of the casing 3075 to optimally provide reduced axial movement and velocity of the expansion cone 3070. In a preferred embodiment, the operating pressure of the second liquid material is reduced during the return stroke of the apparatus 3000 to ranges from about 0 to 500 psi to minimize resistance to movement of the expansion cone 3070 during the return stroke. In a preferred embodiment, the stroke length of the apparatus 3000 is in the range of about 10 to 45 feet to optimally produce equipment that can be easily handled by typical oil rig equipment, and also minimize the frequency at which the apparatus 3000 must be reset.

In a preferred embodiment, at least a portion of one or both of the upper seal heads 3030 and 3050 includes an expansion cone for radial expansion of the casing 3075 during operation of the apparatus 3000 to increase the surface area of the casing 3075 affected during the radial expansion process. In this way, the operating pressures can be reduced.

Alternatively, the apparatus 3000 may be used to join a first section of pipeline to an existing section of pipeline. Alternatively, the apparatus 3000 can be used to directly line the interior of a wellbore with a casing, without the use of an outer annular layer of curable material. Alternatively, the apparatus 3000 can be used to expand a tubular support member in a hole.

Reference is now made to Figure 21, where an apparatus 3330 for isolating underground zones will be described. A wellbore 3305 comprising a casing 3310 is located in an underground formation 3315. The underground formation 3315 comprises several productive and non-productive zones, including a water zone 3320 and a targeted oil sands zone 3325. During exploitation of the underground formation 3315, the wellbore 3305 can be extended in a well-known manner to traverse the various productive and non-productive zones, including the water zone 3320 and the targeted oil sands zone 3325.

In a preferred embodiment, in order to fluidly isolate the water zone 3320 from the targeted oil sands zone 3325, an apparatus 3330 is provided which comprises one or more sections of solid casing 3335, one or more external packings 3340, one or more sections of slotted casing 3345, a or several intermediate sections of solid casing 3350, and a solid shoe 3355.

The solid casing 3335 may form a fluid conduit that transfers fluids and other materials from one end of the solid casing 3335 to the other end of the solid casing 3335. The solid casing 3335 may comprise any of several conventional, commercially available sections of solid casing, such as oil field pipes made of chrome, steel or fibreglass. In a preferred embodiment, the solid casing comprises 3335 oilfield tubing available from various foreign and domestic steel mills.

The solid casing 3335 is preferably coupled to the casing 3310. The solid casing 3335 may be coupled to the casing 3310 using any of several conventional, commercially available processes, such as welding, slotted and expandable joints, or expandable solid joints. In a preferred embodiment, the solid casing 3335 is connected to the casing 3310 using expandable solid couplings. The solid casing 3335 may comprise several such solid casings 3335.

The solid casing 3335 is preferably coupled to one or more of the slotted casings 3345. The solid casing 3335 may be coupled to the slotted casing 3335 using any of several conventional, commercially available processes, such as welding, or slotted and expandable couplings. In a preferred embodiment, the solid casing 3335 is connected to the slotted casing 3345 by expandable solid couplings.

In a preferred embodiment, the casing 3335 includes one or more valve members 3360 to control the flow of fluids and other materials within the inner region of the casing 3335. In an alternative embodiment, during the production mode of operation, an inner tubular string with various arrangements of gaskets , perforated pipe, sliding sleeves and valves are used inside the apparatus to provide different options for mixing and isolating underground zones from each other while forming a fluid path to the surface.

In a particularly preferred embodiment, the casing 3335 is positioned in the wellbore 3305 by expanding the casing 3335 in the radial direction into close contact with the inner walls of the wellbore 3305. The casing 3335 can be expanded in the radial direction using any of several conventional, commercially available methods. In a preferred embodiment, casing 3335 is expanded in the radial direction using one or more of the processes and apparatus described in the present specification.

The gaskets 3340 prevent the passage of fluids and other materials inside the annulus 3365 between the solid casings 3335 and 3350 and the wellbore 3305. The gaskets 3340 may comprise any of several conventional, commercially available sealing materials suitable for sealing a casing in a wellbore, like for example. lead, rubber or epoxy. In a preferred embodiment, the seals comprise 3340 StrataLock epoxy material available from Halliburton Energy Services.

The slotted casing 3345 allows fluids and other materials to pass into and out of the interior of the slotted casing 3345 from and to the annulus 3365. In this way, oil and gas can be produced from a producing subterranean zone within a subterranean formation. The slotted casing 3345 may comprise any of several conventional, commercially available sections of slotted casing. In a preferred embodiment, the slotted casing comprises 3345 expandable slotted tubular casing available from Petroline of Aberdeen, Scotland. In a particularly preferred embodiment, the casing 145 comprises expandable slotted sand screen casing available from Petroline of Aberdeen, Scotland.

The slotted casing 3345 is preferably coupled to one or more solid casings 3335. The slotted casing 3345 may be coupled to the solid casing 3335 using any of several conventional, commercially available processes, such as welding, or slotted or solid expandable joints. In a preferred embodiment, the slotted casing 3345 is connected to the solid casing 3335 by expandable solid couplings.

The slotted casing 3345 is preferably coupled to one or more intermediate solid casings 3350. The solid casing 3345 may be coupled to the intermediate solid casing 3350 using any of several conventional, commercially available processes, such as welding or expanding solid or slotted joints. In a preferred embodiment, the slotted casing 3345 is connected to an intermediate solid casing 3350 by expandable solid couplings.

The last section of slotted casing 3345 is preferably coupled to the shoe 3355. The last slotted casing 3345 may be coupled to the shoe 3355 using any of several conventional, commercially available processes, such as welding or expandable solid or slotted connections. In a preferred embodiment, the last slotted casing 3345 is connected to the shoe 3355 by an expandable solid coupling.

In an alternative embodiment, the shoe 3355 is connected directly to the last of the intermediate solid casings 3350.

In a preferred embodiment, the slotted casings 3345 are placed inside the wellbore 3305 by expanding the slotted casings 3345 in the radial direction into close contact with the inner walls of the wellbore 3305. The slotted casings 3345 can be expanded in the radial direction using which preferably by several conventional, commercially available processes. In a preferred embodiment, the slotted casing 3345 is expanded in the radial direction using one or more of the processes and apparatus described herein with reference to Figures 14A through 20.

The intermediate solid casing 3350 allows fluids and other materials to pass between adjacent slotted casings 3345. The intermediate solid casing 3350 may comprise any of several conventional, commercially available sections of solid casing, such as oil field pipes made of chrome steel or fibreglass. In a preferred embodiment, the intermediate solid casings comprise oil field pipes available from foreign and domestic steel mills.

The intermediate solid casing 3350 is preferably coupled to one or more sections of the slotted casing 3345. The intermediate solid casing 3350 may be coupled to the slotted casing 3345 using any of several conventional, commercially available processes, such as . welding, or solid or slotted expandable connectors. In a preferred embodiment, the intermediate solid casing 3350 is connected to the slotted casing 3345 by expandable solid couplings. The intermediate solid casing 3350 may comprise several such intermediate solid casings 3350.

In a preferred embodiment, each intermediate solid casing 3350 includes one or more valve members 3370 to control the flow of fluids and other materials within the interior region of the intermediate casing 3350. In an alternative embodiment, which will be known to those skilled in the art, and by means of the present disclosure, during the production mode of operation, an internal pipe string with various arrangements of gaskets, perforated pipes, sliding sleeves and valves can be used inside the apparatus to provide different options for mixing and isolating subterranean zones from each other while producing a fluid path to the surface.

In a particularly preferred embodiment, the intermediate casing 3350 is placed in the wellbore 3305 by expanding the intermediate casing 3350 in the radial direction into close contact with the inner walls of the wellbore 3305. The intermediate casing 3350 can be expanded in the radial direction using which preferably by several conventional, commercially available methods.

In an alternative embodiment, one or more of the intermediate solid casings 3350 may be omitted. In an alternative preferred embodiment, one or more of the slotted casings 3345 is equipped with one or more gaskets 3340. The shoe 3355 forms a support part for the apparatus 3330. In this way, various production and exploration tools can be supported by the shoe 3350. The shoe 3350 may include any of several conventional, commercially available shoes suitable for use in a wellbore, such as cement-filled shoe, or aluminum or composite shoe. In a preferred embodiment, shoe 3350 comprises an aluminum shoe available from Halliburton. In a preferred embodiment, shoe 3355 is selected to provide sufficient strength in compression and tension to permit the use of high capacity production and exploration tools.

In a particularly preferred embodiment, the apparatus 3330 comprises multiple solid casings 3335, multiple packings 3340, multiple slotted casings 3345, multiple intermediate solid casings 3350, and a shoe 3355. More generally, the apparatus 3330 may comprise one or more solid casings 3335, each with one or more valve parts 3360, n slotted casings 3345, n-1 intermediate solid casings 3350, each with one or more valve parts 3370, and a shoe 3355.

During operation of apparatus 3330, oil and gas may be controllably produced from the targeted oil and sand zone 3325 using slotted casing 3345. Oil and gas may then be transported to the surface using solid casing 3335. The use of intermediate solid casing 3350 with valve parts 3370 allows isolated sections of zone 3325 to be selectively isolated for production. The gaskets 3340 allow the zone 3325 to be fluid isolated from the zone 3320. The gaskets 3340 further allow isolated sections of the zone 3325 to be fluid isolated from each other. In this way, the apparatus 3330 allows unwanted and/or non-productive underground zones to be fluid isolated.

In an alternative embodiment, which will be known to those of ordinary skill in the art and who also benefit from the present disclosure, during the production mode of operation, an internal pipe string with various arrangements of gaskets, perforated pipes, sliding sleeves and valves may be used with the apparatus to provide different options for mixing and isolating subsurface zones from each other while forming a fluid path to the surface.

A method of creating a casing in a borehole located in an underground formation is described, comprising installing a tubular casing and a spindle in the borehole. A body of liquid material is then injected into the borehole. The tubular liner is then radially expanded by extruding the liner from the spindle. The injection preferably comprises injecting a hardenable liquid sealing material into an annular area between the borehole and the outside of the tubular liner, and a non-hardenable liquid material into an inner area of the pipe liner below the spindle. The method preferably includes fluid isolation of the annulus from the inner area before injecting the second quantity of the non-curable sealing materials into the inner area. Injection of the curable liquid sealant is preferably performed at operating pressures and flow rates in the range of about 0 to 5,000 psi and 0 to 1,500 gallons per minute. The injection of the non-curable liquid material is preferably performed at operating pressures and flow rates in the range of about 500 to 9,000 psi and 40 to 3,000 gallons per minute. The injection of the non-curable liquid material is preferably carried out at reduced operating pressures and flow rates during a final part of the extrusion. The non-curable liquid material is preferably injected below the spindle.

The method preferably comprises putting an area of the pipe lining below the spindle under pressure. The area of the casing below the spindle is preferably pressurized in the range of about 500 to 9,000 psi. The method preferably comprises fluid isolation of an inner area of the tubular liner from an outer area of the liner. The method further preferably comprises hardening the curable sealing material and removing at least part of the hardened sealing material which is inside the tubular liner. The method preferably includes further overlapping of the casing with an existing wellbore casing.

The method preferably includes further sealing of the overlap between the tubular casing and the existing wellbore casing. The method preferably comprises further supporting the extruded tubular casing using the overlap with the existing wellbore casing. The method preferably includes further testing of the integrity of the seal in the overlapping area between the tubular casing and the existing wellbore casing. The method preferably comprises the further removal of at least part of the curable liquid sealing material inside the lining before curing. The method preferably includes further lubrication of the surface of the spindle. The method preferably includes further absorption of shock. The method preferably comprises further trapping of the spindle after the completion of extrusion.

An apparatus for creating a casing in a borehole located in an underground formation is described, comprising a support member, a spindle, a tubular member and a shoe. The support part comprises a first fluid passage. The spindle is connected to the support part, and comprises another fluid passage. The pipe part is connected to the spindle. The shoe is connected to the tubular liner and includes a third fluid passage. The first, second and third fluid passages are operably connected. The support part preferably further comprises a pressure release passage, and a flow control valve connected to the first fluid passage and the pressure release passage. The support part preferably further comprises a shock absorber. The support part preferably comprises one or more sealing parts adapted to prevent foreign material from entering an inner area of the pipe part. The spindle is preferably expandable. The tubular portion is preferably made from materials selected from the group consisting of Oilfield Country Tubular Goods, 13 chrome steel tubing/casing, and plastic casing. The pipe portion preferably has inner and outer diameters in the range of 3 to 15.5 inches and 3.5 to 16 inches, respectively. The pipe section preferably has a plastic breaking strength in the range of about 40,000 to 135,000 psi. The pipe parts preferably comprise one or more sealing parts at an end area. The pipe part preferably comprises one or more pressure release holes at an end area. The pipe part preferably comprises a catch part at the end area to retard the spindle. The shoe preferably comprises an inlet port connected to the third fluid passage, the inlet port being adapted to receive a plug to block the inlet port. The shoe is preferably wearable.

A method for joining another pipe part with a first pipe part, where the first pipe part has an inner diameter that is greater than the outer diameter of the second pipe part, is described, and comprises placing a spindle within an inner area of the second pipe part , placing the first and second pipe members in an overlapping relationship, applying pressure to a portion of the inner area of the second pipe member, and extruding the second pipe member from the spindle into contact with the first pipe member. The pressure supply to a part of the inner area in the second pipe part is preferably arranged at an operating pressure in the range from about 5,000 to 9,000 psi. The pressure supply to part of the inner area of the second tube part is preferably arranged with reduced operating pressure during the last part of the extrusion. The method preferably comprises further sealing of the overlap between the first and the second tubular part. The method preferably includes further support of the extruded first pipe part using overlapping with the second pipe part. The method preferably includes further lubrication of the surface of the spindle. The method preferably includes further absorption of shock.

A liner for use in creating a new section of wellbore casing in a subterranean formation adjacent to a pre-existing section of wellbore casing is described, comprising an annular portion. The annular part comprises one or more sealing parts at an end region of the annular part, and one or more pressure release passages at the end region of the annular part.

A wellbore casing is described, comprising a tubular casing and an annular body of a hardened liquid sealing material. The tubular liner is formed by a process of extruding the tubular liner from a spindle. The tubular liner is preferably formed by the process of placing the tubular liner and spindle inside the wellbore, and applying a pressure to the inner area of the tubular liner. The annular body of hardened liquid sealant is preferably formed by the process of injecting a body of curable liquid sealant into the annular region outside the tubular liner. During the pressure application, the inner part of the tubular liner is preferably fluid isolated from the outer region of the tubular liner. The inner region of the tubular liner is preferably pressurized in the range of about 500 to 9,000 psi. The tubular casing preferably overlaps the existing wellbore casing. The wellbore casing preferably comprises a gasket placed in the overlap between the tubular casing and the existing wellbore casing. The tubular casing is preferably supported by the overlap with the existing wellbore casing.

A method of repairing an existing section of a wellbore casing inside a borehole is disclosed, comprising installing a tubular casing and a spindle inside the wellbore casing, injecting a body of liquid material into the borehole, applying pressure to a part of an inner region of the tubular casing, and radially expanding the casing in the borehole by extruding the casing from the spindle. In a preferred embodiment, the liquid material is selected from the group consisting of slag mixture, cement, drilling mud and epoxy. In a preferred embodiment, the method further comprises fluid isolation of an internal area of the tubular liner from an area outside the liner. In a preferred embodiment, the injection of a body of liquid material is performed at operating pressures and flow rates in the range of about 500 to 9,000 psi and 40 to 3,000 gallons per minute. In a preferred embodiment, the injection of the body of liquid material is carried out at reduced operating pressures and flow rates during a final part of the extrusion. In a preferred embodiment, the fluid material is injected below the spindle. In a preferred embodiment, an area of the tubular liner below the spindle is pressurized. In a preferred embodiment, the area of the tubular liner below the spindle is pressurized in the range of about 500 to 9,000 psi. In a preferred embodiment, the method further comprises overlapping the tubular casing with the existing wellbore casing. In a preferred embodiment, the method further comprises sealing the interface between the tubular casing and the existing wellbore casing. In a preferred embodiment, the method further comprises supporting the extruded tubular casing using the existing wellbore casing. In a preferred embodiment, the method further comprises testing the integrity of the packing at the interface between the tubular casing and the existing wellbore casing. In a preferred embodiment, the method further comprises lubricating the surface of the spindle. In a preferred embodiment, the method further comprises absorbing shock. In a preferred embodiment, the method further comprises capturing the spindle after completion of the extrusion. In a preferred embodiment, the method further comprises expanding the spindle in the radial direction.

A platform liner for lining an existing borehole casing is described, comprising a tubular liner and an annular body of hardened liquid sealing material. The tubular liner is formed by a process for extruding the tubular liner from a spindle. The annular body of hardened liquid sealing material is connected to the tubular liner. In a preferred embodiment, the tubular casing is formed by a process of placing the tubular casing and spindle in the wellbore, and pressurizing an inner region of the casing. In a preferred embodiment, during the pressure supply, the inner region of the tubular liner is fluidly isolated from the outer region of the liner. In a preferred embodiment, the inner region of the liner is pressurized in a range from about 500 to 9,000 psi. In a preferred embodiment, the annular body of hardened liquid sealing material is formed by the process of injecting a body of curable liquid sealing material into an annular region between the existing wellbore casing and the tubular casing. In a preferred embodiment, the tubular casing overlaps another existing wellbore casing. In a preferred embodiment, the platform casing further comprises a seal placed in the overlap between the tubular casing and the other existing wellbore casing. In a preferred embodiment, the tubular casing is supported at the overlap with the other existing wellbore casing.

An apparatus for expanding a tubular member is described, comprising a support member, a spindle, a tubular member and a shoe. The support part comprises a first fluid passage. The spindle is connected to the support part. The spindle comprises a second fluid passage operatively connected to the first fluid passage, an inner region, and an outer region. The inner area of the spindle is drillable. The tubular part is connected to the spindle. The shoe is connected to the tubular part. The shoe comprises a third fluid passage operatively connected to the second fluid passage, an inner part, and an outer part. The inner part of the shoe is drillable. The inner part of the spindle preferably comprises a tubular part and a load-bearing part. The load-bearing part preferably comprises a drillable body. The inner area of the shoe preferably comprises a tubular part and a load-bearing part. The load-bearing part preferably comprises a drillable body. The outer part of the spindle preferably comprises an expansion cone. The expansion cone is preferably manufactured from materials selected from the group consisting of tool steel, titanium and ceramic. The expansion cone preferably has a surface hardness in the range of about 58 to 62 Rockwell C. At least a portion of the apparatus is preferably drillable.

A wellhead is also described, and comprises an outer casing and several essentially concentric and overlapping inner casings connected to the outer casing. Each inner casing is supported by the contact pressure between an outer surface of the inner casing and an inner surface of the outer casing. In a preferred embodiment, the outer casing has a burst strength in the range of about 40,000 to 135,000 psi. In a preferred embodiment, the outer casing has a rupture strength in the range of about 5,000 to 20,000 psi. In a preferred embodiment, the contact pressure between the inner casing and the outer casing is in the range of about 500 to 10,000 psi. In a preferred embodiment, one or more of the inner casings comprise one or more sealing parts which are in contact with an inner surface of the outer casing. In a preferred embodiment, the sealing parts are selected from a group consisting of lead, rubber, Teflon, epoxy and plastic. In a preferred embodiment, a valve tree is connected to the outer casing. In a preferred embodiment, a drill coil is connected to the outer casing. In a preferred embodiment, at least one of the inner casings is a production casing.

A wellhead is also described which comprises an outer casing at least partially located within a wellbore, and several substantially concentric inner casings coupled to the inner surface of the outer casing by the process of expanding one or more of the inner casings into contact with at least part of the inner surface of the outer casing. In a preferred embodiment, the inner casing is expanded by extruding the inner casing from a spindle. In a preferred embodiment, the inner casing is expanded by the process of placing the inner casing and a mandrel inside the wellbore; and pressurizing an inner region of the casing. In a preferred embodiment, during the pressure supply, the inner part of the inner casing is fluidly isolated from the outer region of the inner casing. In a preferred embodiment, the inner portion of the inner casing is pressurized in the range of about 500 to 9,000 psi. In a preferred embodiment, one or more gaskets are placed at the interface between the inner casing and the outer casing. In a preferred embodiment, the inner casings are supported by their contact with the outer casing.

A method for designing a wellhead is also described, which includes drilling a wellbore. An outer casing is placed at least partially inside an upper part of the wellbore. A first tubular part is placed inside the outer casing. At least a region of the first tubular portion is expanded into contact with an inner surface of the outer casing. A second tubular part is placed inside the outer casing and the first tubular part. At least a region of the second tubular portion is expanded into contact with an inner region of the outer casing. In a preferred embodiment, at least part of the interior of the first tubular part is pressurized. In a preferred embodiment, at least a region of the interior of the second tubular part is under pressure. In a preferred embodiment, at least an area of the interior of the first and second tubular parts is pressurized. In a preferred embodiment, the pressure supply to the inner region of the first tubular portion is provided at operating pressures in the range of from about 500 to 9,000 psi. In a preferred embodiment, the pressure supply to a portion of the inner region of the other portion is provided at operating pressures in the range of about 500 to 9,000 psi. In a preferred embodiment, the pressure supply to the portion of the inner region of the first and second tubular members is provided at operating pressures in the range of from about 500 to 9,000 psi. In a preferred embodiment, the pressure supply to the part of the inner region of the first tubular part is arranged at reduced operating pressures during a later part of the expansion. In a preferred embodiment, the pressure supply to the part of the inner region of the second tubular part is brought about by reduced operating pressures during a final part of the expansion. In a preferred embodiment, the pressure supply to the part of the inner region of the first and second tubular parts is arranged at reduced operating pressures during a final part of the expansion. In a preferred embodiment, the contact between the first tubular part and the outer casing is sealed. In a preferred embodiment, the contact between the second tubular part and the outer casing is sealed. In a preferred embodiment, the contact between the first and second pipe parts and the outer casing is sealed. In a preferred embodiment, the expanded first tube part is supported using contact with the outer casing. In a preferred embodiment, the expanded second tube part is supported using the contact with the outer casing. In a preferred embodiment, the expanded first and second pipe members are supported using their contacts with the outer casing. In a preferred embodiment, the first and second pipe parts are extruded from a spindle. In a preferred embodiment, the surface of the spindle is lubricated. In a preferred embodiment, shock is absorbed. In a preferred embodiment, the spindle is expanded in the radial direction. In a preferred embodiment, the first and second tubular parts are positioned in an overlapping relationship. In a preferred embodiment, an inner region of the first tube part is fluid-isolated from an outer region of the first tube part. In a preferred embodiment, an inner region of the second tube part is fluid-insulated from an outer region of the second tube part. In a preferred embodiment, the inner area of the first pipe part is fluidly isolated from the area outside the first pipe part by injecting one or more plugs into the interior of the first pipe part. In a preferred embodiment, the inner area of the second pipe part is fluid-isolated from the area outside the second pipe part by injecting one or more plugs into the interior of the second pipe part. In a preferred embodiment, the supply of pressure to the portion of the inner region of the first pipe section is produced by injecting a liquid material at operating pressures and flow rates in the range of about 500 to 9,000 psi and 40 to 3,000 gallons per minute. In a preferred embodiment, the pressurization of the portion of the inner region of the second tube portion is accomplished by injecting a liquid material at operating pressures and flow rates in the range of about 500 to 9,000 psi and 40 to 3,000 gallons per minute. In a preferred embodiment, liquid material is injected past the spindle. In a preferred embodiment, an area of the tube part past the spindle is pressurized. In a preferred embodiment, the area of the tube portion past the spindle is pressurized in the range of about 500 to 9,000 psi. In a preferred embodiment, the first pipe part comprises a production casing pipe. In a preferred embodiment, the contact between the first tube part and the outer casing is sealed. In a preferred embodiment, the contact between the second tube part and the outer casing is sealed. In a preferred embodiment, the expanded first pipe part is supported using the outer casing. In a preferred embodiment, the expanded second pipe part is supported using the outer casing. In a preferred embodiment, the integrity of the seal in the contact between the first pipe part and the outer casing is tested. In a preferred embodiment, the integrity of the seal in the contact between the second pipe part and the outer casing is tested. In a preferred embodiment, the spindle is captured after completion of the extrusion. In a preferred embodiment, the spindle is drilled out. In a preferred embodiment, the spindle is supported with coiled tubing. In a preferred embodiment, the spindle is connected to a drillable shoe.

An apparatus is also described, which comprises an outer tube part, and several essentially concentric and overlapping inner tube parts connected to the outer tube part. An inner tube part is supported by contact pressure between an outer surface of the inner casing and an inner surface of the outer inner tube part. In a preferred embodiment, the outer tube portion has a breaking strength in the range of about 40,000 to 135,000 psi. In a preferred embodiment, the outer tube portion has a breaking strength in the range of about 5,000 to 20,000 psi. In a preferred embodiment, the contact pressure between the inner pipe members and the outer pipe members is in the range of about 5,000 to 10,000 psi. In a preferred embodiment, one or more of the inner tube parts comprise one or more sealing parts which are in contact with an inner surface of the outer tube part. In a preferred embodiment, the sealing parts are selected from a group consisting of rubber, lead, plastic and epoxy.

An apparatus is also described which comprises an outer tube part, and several substantially concentric inner tube parts connected to the inner surface of the outer tube part by a process for expanding one or more of the inner tube parts into contact with at least a region of the inner surface of the outer tube part. In a preferred embodiment, the inner tube parts are expanded by extruding an inner tube part from a spindle. In a preferred embodiment, the inner pipe members are expanded by a process of placing the inner pipe members and a spindle inside the outer pipe member, and pressurizing an inner portion of the inner casing. In a preferred embodiment, during the pressure supply, the inner area of the inner pipe part is fluidly isolated from the area outside the inner pipe part. In a preferred embodiment, the inner region of the inner tube portion is pressurized in the range of about 500 to 9,000 psi. In a preferred embodiment, the apparatus further comprises one or more gaskets placed at the interface between the inner tube parts and the outer tube part. In a preferred embodiment, the inner tube parts are supported by their contact with the outer tube parts.

A wellbore casing is also described which comprises a first pipe section, and another pipe section connected to the first pipe section in an overlapping relationship. The inner diameter of the first tube part is essentially equal to the inner diameter of the second tube part. In a preferred embodiment, the first pipe part comprises a first thin-walled section, where the second pipe part comprises another thin-walled section, and where the first thin-walled section is connected to the second thin-walled section. In a preferred embodiment, the first and second thin wall sections are deformed. In a preferred embodiment, the first tubular part comprises a first compressible part which is connected to the first thin wall section, and where the second pipe part comprises another compressible part which is connected to the second thin wall section. In a preferred embodiment, the first thin wall section and the first compressible part are connected to the second thin wall section and the second compressible part. In a preferred embodiment, the first and second thin wall sections and the first and second compressible parts are deformed.

A wellbore casing is also described which comprises a pipe section comprising at least one thin walled section and one thick walled section, and a compressible annular section coupled to each thin walled section. In a preferred embodiment, the compressible annular member is made of materials selected from the group consisting of rubber, plastic, metal and epoxy. In a preferred embodiment, the wall thickness of the thin wall section is in the range from about 50 to 100% of the wall thickness of the thick wall section. In a preferred embodiment, the length of the thin wall section ranges from about 120 to 2,400 inches. In a preferred embodiment, the compressible annular part is located along the thin wall section. In a preferred embodiment, the compressible annular part is located along the thin and thick wall sections. In a preferred embodiment, the pipe member is made of materials selected from the group consisting of oil field pipe, stainless steel, low alloy steel, carbon steel, a mobile grade steel, plastic, fiberglass, high strength and/or deformable materials. In a preferred embodiment, the wellbore casing comprises a first thin wall at the first end of the casing, and a second thin wall at another end of the casing.

A method of creating a casing in a borehole located in an underground formation is also described, and comprises supporting a tubular casing and a spindle in the borehole using a support member, injecting liquid materials into the borehole, applying pressure in an internal area of the spindle, displacement of a part of the spindle relative to the support part, and radial expansion of the tubular liner. In a preferred embodiment, the injection comprises injecting a curable liquid sealing material into an annular area located between the borehole and the outside of the tubular casing, and injecting a non-curable liquid material into the inner area of the spindle. In a preferred embodiment, the first method comprises fluid isolating the annular region from the inner region prior to injecting the non-curable liquid material into the inner region of the spindle. In a preferred embodiment, the curable liquid sealant injection is performed at operating pressures and flow rates in the range of about 0 to 5,000 psi and 0 to 1,500 gallons per minute. In a preferred embodiment, the injection of non-curable liquid material is performed at operating pressures and flow rates in the range of about 500 to 9,000 psi and 40 to 3,000 gallons per minute. In a preferred embodiment, the injection of non-curable liquid material is carried out with reduced operating pressure and flow rate during a final part of the radial expansion. In a preferred embodiment, the liquid material is injected into one or more pressure chambers. In a preferred embodiment, one or more pressure chambers are pressurized. In a preferred embodiment, the pressure chambers are pressurized from about 500 to 9,000 psi. In a preferred embodiment, the method further comprises fluid isolation of an internal area of the spindle from an area outside the spindle. In a preferred embodiment, the inner region of the spindle is isolated from the region outside the spindle by injecting one or more plugs into the injected liquid material. In a preferred embodiment, the method further comprises curing at least a portion of the liquid material, and removing at least a portion of the cured liquid material located inside the tubular liner. In a preferred embodiment, the method further comprises overlapping the tubular casing with an existing wellbore casing. In a preferred embodiment, the method further comprises sealing the overlap between the tubular casing and the existing wellbore casing. In a preferred embodiment, the method further comprises supporting the extruded tubular casing using the overlap with the existing wellbore casing. In a preferred embodiment, the method further comprises checking the integrity of the seal in the overlap between the tubular casing and the existing casing. In a preferred embodiment, the method further comprises removing at least a portion of the curable liquid sealing material within the tubular liner prior to curing. In a preferred embodiment, the method further comprises lubricating the surface of the spindle. In a preferred embodiment, the method further comprises absorbing shock. In a preferred embodiment, the method further comprises capturing the spindle after completion of the extrusion. In a preferred embodiment, the method further comprises boring out the spindle. In a preferred embodiment, the method further comprises supporting the rafter part with coiled pipe. In a preferred embodiment, the spindle reciprocates. In a preferred embodiment, the spindle is displaced in a first direction during the application of pressure to the inner region of the spindle, and the spindle is displaced in another direction during removal of the pressure in the inner region of the spindle. In a preferred embodiment, the tubular liner is held in a substantially stationary position during the application of pressure to the inner region of the spindle. In a preferred embodiment, the tubular liner is supported by the spindle while removing the pressure in the inner region of the spindle.

Also described is a wellbore casing comprising a first pipe part with a first inner diameter, and another pipe part with a second inner diameter substantially equal to the first inner diameter, connected to the first pipe part in an overlapping relationship. The first and second pipe parts are connected by a process to deform a part of the second pipe part into contact with a part of the first pipe part. In a preferred embodiment, the second pipe part is deformed by a process of placing the first and second pipe parts in an overlapping relationship, radial expansion of at least a part of the first pipe part, and radial expansion of the second pipe part. In a preferred embodiment, the second pipe member is radially expanded by the process of supporting the second pipe member and a spindle within the wellbore using a support member, injecting a fluid material into the wellbore, applying pressure to an inner region of the spindle, and displacement of a part of the spindle in relation to the support part. In a preferred embodiment, the injection comprises injecting a curable liquid sealing material into an annulus located between the borehole and the outside of the second liner, and injecting a non-curable liquid material into an inner region of the spindle. In a preferred embodiment, the wellbore casing further comprises fluid isolating the annulus from an inner region of the spindle prior to injecting the non-curable liquid material into the inner region of the spindle. In a preferred embodiment, the injection of the curable liquid sealant is performed at operating pressures and flow rates in the range of about 0 to 5,000 psi and 0 to 1,500 gallons per minute. In a preferred embodiment, the injection of the non-curable liquid material is performed at operating pressures and flow rates in the range of about 500 to 9,000 psi and 40 to 3,000 gallons per minute. In a preferred embodiment, the injection of the non-curable liquid material is performed at reduced operating pressures and flow rates during the last part of the radial expansion. In a preferred embodiment, the liquid material is injected into one or more pressure chambers. In a preferred embodiment, one or more pressure chambers are pressurized. In a preferred embodiment, the pressure chambers are pressurized in the range of about 500 to 9,000 psi. In a preferred embodiment, the wellbore casing further comprises fluid isolation of an internal area of the spindle from an area outside the spindle. In a preferred embodiment, the inner area of the spindle is isolated from the area outside the spindle by introducing one or more plugs into the injected liquid material. In a preferred embodiment, the wellbore casing further comprises curing at least a portion of the liquid material, and removing at least a portion of the cured liquid material located within the second tubular casing. In a preferred embodiment, the wellbore casing further comprises sealing the overlap between the first and the second tubular casing. In a preferred embodiment, the wellbore casing further comprises supporting the second tubular casing using the overlap with the first tubular casing. In a preferred embodiment, the wellbore casing further comprises testing the integrity of the seal in the overlap between the first and second tubular casings. In a preferred embodiment, the wellbore casing further comprises removing at least a portion of the curable liquid sealing material within the second tubular casing prior to curing. In a preferred embodiment, the wellbore casing further comprises lubrication of the surface of the spindle. In a preferred embodiment, the wellbore casing further comprises shock absorption. In a preferred embodiment, the wellbore casing further comprises capturing the spindle after completion of radial expansion. In a preferred embodiment, the wellbore casing further comprises drilling out the spindle. In a preferred embodiment, the wellbore casing further comprises supporting the spindle with coiled tubing. In a preferred embodiment, the spindle reciprocates. In a preferred embodiment, the spindle is displaced in a first direction while applying pressure to the inner region of the spindle, and where the spindle is displaced in another direction while removing the pressure from the inner region of the spindle. In a preferred embodiment, the second tubular liner is held in a substantially stationary position during the application of pressure to the inner region of the spindle. In a preferred embodiment, the second tubular liner is supported by the spindle while removing the pressure from the inner region of the spindle.

An apparatus for expanding a pipe section is also disclosed, comprising a support member comprising a fluid passage, a spindle movably coupled to the support member, comprising an expansion cone, at least one pressure chamber defined by and located between the support member and the spindle, fluidly coupled to the first passage, and one or more releasable supports connected to the support part, adapted to support the pipe part. In a preferred embodiment, the fluid passage comprises a throat passage which has a reduced internal diameter. In a preferred embodiment, the spindle comprises one or more annular pistons. In a preferred embodiment, the apparatus comprises several pressure chambers. In a preferred embodiment, the pressure chambers are at least partially defined by annular pistons. In a preferred embodiment, the releasable supports are located below the spindle. In a preferred embodiment, the releasable supports are located above the spindle. In a preferred embodiment, the releasable supports consist of hydraulic stop wedges. In a preferred embodiment, the releasable supports comprise mechanical stop wedges. In a preferred embodiment, the releasable supports comprise traction blocks. In a preferred embodiment, the spindle comprises one or more annular pistons, and an expansion cone connected to the annular pistons. In a preferred embodiment, one or more of the annular pistons comprise an expansion cone. In a preferred embodiment, the pressure chambers comprise annular pressure chambers.

An apparatus is also described which comprises one or more solid tubular parts, where each solid tubular part comprises one or more external gaskets, one or more slotted pipe parts connected to the solid pipe parts, and a shoe connected to one of the slotted pipe parts. In a preferred embodiment, the apparatus further comprises one or more intermediate solid pipe parts connected to and placed between the slotted pipe parts, where each intermediate solid pipe part comprises one or more external gaskets. In a preferred embodiment, the apparatus further comprises one or more valve parts. In a preferred embodiment, one or more of the intermediate solid pipe parts comprise one or more valve parts.

A method of joining another pipe part to a first pipe part, where the first pipe part has an inner diameter that is greater than the outer diameter of the second pipe part, is also described, and comprises placing a spindle inside an inner region of the second tube portion, applying pressure to a portion of the inner region of the spindle, displacing the spindle relative to the second tube portion, and extruding at least a portion of the second tube portion from the spindle into contact with the first tube portion. In a preferred embodiment, the supply of pressure to the portion of the inner region of the spindle is performed at an operating pressure in the range of about 500 to 9,000 psi. In a preferred embodiment, the pressure supply to the part of the inner region of the spindle is carried out at a reduced operating pressure during a final part of the extrusion. In a preferred embodiment, the method further comprises sealing the interface between the first and the second pipe part. In a preferred embodiment, the method further comprises supporting the extruded second pipe part using the interface with the first pipe part. In a preferred embodiment, the method further comprises lubricating the surface of the spindle. In a preferred embodiment, the method further comprises absorbing shock. In a preferred embodiment, the method further comprises placing the first and second pipe parts in an overlapping relationship. In a preferred embodiment, the method further comprises fluid isolation of an internal area of the spindle from an area outside the spindle. In a preferred embodiment, an inner area of the spindle is fluid-isolated from the area outside the spindle by injecting one or more plugs into the interior of the spindle. In a preferred embodiment, pressurizing the portion of the inner region of the spindle is accomplished by injecting a liquid material at operating pressures and flow rates in the range of about 500 to 9,000 psi and 40 to 3,000 gallons per minute. In a preferred embodiment, the method further comprises injecting a liquid material below the spindle. In a preferred embodiment, one or more pressure chambers are defined when the spindle is pressurized. In a preferred embodiment, the pressure chambers are pressurized in a range from about 500 to 9,000 psi. In a preferred embodiment, the first pipe part comprises an existing section of a wellbore. In a preferred embodiment, the method further comprises sealing the interface between the first and the second pipe part. In a preferred embodiment, the method further comprises supporting the extruded second pipe part using the first pipe part. In a preferred embodiment, the method further comprises testing the integrity of the seal at the interface between the first pipe part and the second pipe part. In a preferred embodiment, the method further comprises capturing the spindle after completion of the extrusion. In a preferred embodiment, the method further comprises boring out the spindle. In a preferred embodiment, the method further comprises supporting the spindle with a coiled tube. In a preferred embodiment, the method further comprises connecting the spindle to a drillable shoe. In a preferred embodiment, the spindle is displaced in the longitudinal direction. In a preferred embodiment, the spindle is displaced in a first direction during the application of pressure and in a second direction during removal of the pressure.

An apparatus is also described which comprises one or more primary solid tubes, where each primary solid tube comprises one or more external annular gaskets, n slotted tubes connected to the primary solid tubes, n-1 intermediate solid tubes connected to and placed together with the slotted tubes, where each intermediate solid tube comprises one or more external annular gaskets, and a shoe connected to one of the slotted tubes.

A method for isolating a first underground zone from another underground zone in a wellbore is also described, comprising placing one or more primary solid pipes inside the wellbore, where the primary solid pipes cross the first underground zone, placing one or more slotted pipes inside the wellbore, where the slotted pipes intersect the second underground zone, fluid coupling of the slotted pipes and the solid pipes, and preventing the passage of fluids from the first underground zone to the second underground zone inside the wellbore outside the solid and slotted tube.

A method of extracting materials from a producing subterranean zone in a wellbore, wherein at least a portion of the wellbore comprises a casing, is also described, and comprises placing one or more primary solid pipes within the wellbore, fluid coupling of the primary solid pipes with the casing, placing one or more slotted pipes inside the wellbore, where the slotted pipes intersect the producing underground zone, fluid coupling of the slotted pipes with the solid pipes, fluid isolation of the producing underground zone from at least one other underground zone inside the wellbore, and fluid coupling of at least one of the slotted pipes from the producing underground zone. In a preferred embodiment, the method further comprises controllable fluid disconnection of at least one of the slotted pipes from at least one of the other slotted pipes.

Although illustrative embodiments of the invention have been shown and described, a wide range of modifications, changes and replacements are contemplated in the foregoing description. In some cases, some features of the present invention can be used without a corresponding use of other features. Of course, it is appropriate that the accompanying claims are constructed in a broad sense and in a manner consistent with the scope of the invention.

Claims (16)

1. Method for adding a second pipe element (1715) to a first pipe element (1620), the first pipe element (1620) having an inner diameter that is larger than the outer diameter of the second pipe element (1715), characterized by placing a spindle ( 1710) in the second tube element (1715), pressurizing a part (1755) of the interior of the spindle (1710), moving the spindle (1710) relative to the second tube element (1715) and extruding at least a part of the second tube element (1715 ) from the spindle (1710) to engagement with the first pipe element (1620), as it further comprises gripping the spindle (10) after completing the extrusion of the second pipe element (1715) and where the movement of the spindle (1710) comprises moving a part of the spindle (1710) in relation to the carrier element (1705). 2. Method according to claim 1, characterized in that it further comprises carrying the second pipe element (1715) and the spindle (1710) in a borehole (1600) by using a carrying element (1705). 3. Method according to claim 2, characterized in that it further comprises injection of fluid material (1840) into the borehole (1600). 4. Method according to claim 2, characterized in that it further comprises carrying the second pipe element (1715) into contact with the first pipe element (1620). 5. Method according to claim 4, characterized in that it further comprises sealing the contact between the second pipe element (1715) and the first pipe element (1620). 6. Method according to claim 5, characterized in that it further comprises testing the integrity of the seal between the pipe element (1715) and the first pipe element (1620). 7. Method according to claim 2, characterized in that it further comprises positioning the second pipe element (1715) in an overlapping relationship with the first pipe element (1620). 8. Method according to claim 1, characterized in that extrusion of at least part of the second pipe element (1715) comprises radial expansion of the pipe element (1715). 9. Method according to claim 1, characterized in that the second pipe element (1715) is a second pipeline element and where the first pipe element (1620) is a first pipeline element. 10. Method according to claim 1, characterized in that it further comprises drilling out the spindle (1710). 11. Method according to claim 1, characterized in that it further comprises supporting the spindle (1710) with a coil tube. 12. Method according to claim 1, characterized in that it further comprises coupling the spindle (1710) to a drillable shoe (215). 13. Method according to claim 3, characterized in that the spindle (1710) is an expandable spindle and where carrying the second pipe element (1715) and the expandable spindle (1710) in the borehole (1600) comprises: drilling out a new section of the borehole ( 1650) near the first pipe member (1620), place the second pipe member (1715) and the expandable spindle (1710) in the new section of the borehole (1650), and overlap the second pipe member (1715) with the first pipe member (1620), injecting fluid materials (1840) into the borehole (1600) comprises injecting a hardening fluid sealing material (1840) into an annulus between the second pipe element (1715) and a new section of the borehole (1650), and pressurizing the interior (1755) of the spindle (1710) comprises injecting a non-hardening fluid material into the inner area (1755) of the spindle (1710) and where the method further comprises: sealing the overlap between the second pipe element (1715) and the first pipe element (1620), and e the second pipe element (1715) with the overlap of the first pipe element (1620), remove the spindle (1710) from the borehole (1600), test the integrity of the seal of the overlap between the second pipe element (1715) and the first pipe element (1620), remove at least a portion of the curing fluid seal (1840) material from the interior of the second pipe member (1715), curing the remaining portions of the curing fluid seal material (1840), and removing at least a portion of the curing fluid seal material (1840) in the first pipe member (1715). 14. Apparatus for expanding a pipe element (1715), characterized by a support element (1705) with fluid passage (1730), a spindle (1710) which is movably connected to the support element (1705) including an expansion cone (1770), at least one pressure chamber ( 1755) arranged by and positioned between the support member (1705) and the spindle (1710) fluidly coupled to the first passage (1730) and one or more releasable carriers (1725) coupled to the support member (1705) adapted to support the tube member (1715). 15. Apparatus according to claim 14, characterized in that the pipe element is a pipeline element. 16. Apparatus according to claim 14, characterized in that the pipe element (1715) comprises at least one thin-walled section (1815) and one thick-walled section.