BACKGROUND ART The production of commercially valuable products from reservoir rock is measured not only by the rate of production from the associated well, but also by the life of the well. The longer a well produces commercially valuable quantities of oil and gas, the more valuable that well will be. Optimizing production while maintaining the longevity of the well is the ultimate goal of oil and gas producers.

Reservoir performance is measured by a number of factors including permeability, porosity and thickness of the reservoir rock or formation, and the pressure of the formation. The formation pressure is the energy that drives oil and gas through the reservoir toward the well.

In radial flow patterns, typically present in the production of oil and gas, the pressure driving the liquids entrained in the reservoir through the formation and into the well varies, depending upon the distance from the well. In other words, flow rate is a function of the pressure differential between the well and the various distances throughout the formation. The radial flow rate of liquid within a reservoir is determined by the equation: <BR> <BR> <BR> <BR> <BR> Q = mw2<BR> <BR> <BR> <BR> <BR> <BR> <BR> plnRr/Rw wherein: Q = flow rate of the reservoir liquid, k = permeability constant, h = the thickness of the reservoir rock, Pr = the pressure of the reservoir rock, Pw = the pressure at the well, p. = the viscosity of the reservoir liquid, Rr = the radius of the reservoir, and Rw = the radius of the well = one half the diameter of the well.

As fluids flow through the reservoir and approach the well, fluid velocity increases due, at least in part, to a decrease in the cross-sectional area of the reservoir rock near the well. This results in pressure losses in the formation. In radial flow patterns, the greatest amount of energy required to move oil to the well is consumed within a few feet of the well. In other words, the greatest pressure losses take place within a few feet of the well.

The natural pressure of the formation, and thus the life of the well, may be preserved by increasing the well diameter or the amount of area exposed to drainage, thereby decreasing the velocity of liquids approaching the well and the loss of pressure due to friction with the formation rock. Increasing the well diameter increases the area through which fluid can flow. Thus, increasing the cross-sectional area of flow, or the effective diameter of the well, conserves reservoir energy and increases recovery.

Various methods have been used to try to increase the effective diameter of wells, but have offered little success. One such method is to drill shafts or tubing into the producing formation using a rotary drive mechanism. These shafts bore through the casing and into the formation a distance, thereby increasing the diameter of the well and reducing the distance the reservoir fluids must travel. Using knucklejoints or U-joints enables the shafts to deform around curves and enter the formation. However, these mechanical joints tend to fail under strain caused by drilling. The shaft is forced to travel out of the well at an angle and into the reservoir.

The resultant forces make unusual and severe demands upon the downhole mechanism. Torque applied to the shaft can shear the downhole tools. which interrupts the operation, increases costs and may result in loss of the well if the downhole tools are not recoverable.

Moreover, these drilling and boring methods produce cuttings that have to be removed from the well. Some mud systems are required to transport cuttings from the hole. Frequently, the pressure in the formation is lower than the pressure in the borehole. The drilling fluid, which naturally flows toward the area of lower pressure, flows into the formation rather than up the annulus of the well to the surface. When the flow is toward the formation, the resultant packing off around the bit causes the bit to jam and the torque-carrying device is twisted off in the well.

DISCLOSURE OF THE INVENTION The present invention is directed to an apparatus for disposing an object through the sidewall of a borehole in a compressible substance. The apparatus comprises an object positionable within the borehole and a non-rotary propulsion assembly disposable into the borehole. The propulsion assembly includes a propulsion member adapted to move axially within the borehole and impact the object whereby the object is forced non-drillingly through the sidewall of the borehole a distance into the compressible substance with creating a significant amount of cuttings.

In one aspect, the apparatus comprises a housing securable at a predetermined depth in the wellbore, and the housing defines a guide tube therein having an axial portion and a lateral portion. In some applications, the object is a drainage assembly and in other applications the object is a core sampler.

A preferred drainage assembly is a plurality of nestable, fluid- permeable disks stackably disposed in the guide tube. In this embodiment, the propulsion assembly impacts the first of the plurality of disks whereby the plurality of disks is pushed through the guide tube exiting the lateral portion and puncturing the sidewall of the borehole. The lateral portion of the guide tube is configured to direct the exiting disks at a selected location in the sidewall of the borehole.

Where the object is a core sampler, the apparatus preferably comprises a plurality of interconnected links disposed in the guide tube. The links are jointed to negotiate the guide tube, and the core sample is connected to the front of the lowermost link. The propulsion assembly is connected to the uppermost link and is adapted to impact the first link. In this way, the plurality of links is pushed through the guide tube exiting the lateral portion so that the core sampler punctures the sidewall of the borehole. The lateral portion of the guide tube is configured to direct the exiting core sampler at a selected location in the sidewall of the borehole.

In some applications, the apparatus comprises a section of well casing in which a plurality of drainage devices are pre-installed. The pre-installed drainage devices may be water-permeable, wedge-shaped fins, wherein the point of each fin is pivotally attached in the sidewall of the well casing. Alternately, the drainage devices are tubes with conical ends supported in a plurality of guide tubes all supported inside

the well casing between the side wall of the casing and an inner tube in the casing. In this embodiment, the propulsion assembly is provided with a pipe mover on its forward most end to push the inner tube further down into the well bore and expose the guide tubes.

With these"pre-loaded"casing embodiments, the propulsion assembly preferably comprises a bit sized to move axially through the well casing and advance the drainage devices at least partially through the side wall of the well casing.

A hole opener is included on the propulsion assembly and comprises an upper portion and a lower portion, the upper portion telescopically received in the lower portion.

The lower portion comprises a plurality of radially extending fingers, the fingers being retractable and expandable in response to telescopic movement of the upper and lower portions. Thus, the expanding fingers will further advance the drainage devices, yet the hole opener can be withdrawn from the well casing when the fingers are retracted.

In the apparatus of this invention, the propulsion assembly preferably is some form of percussive mechanism. The proplusion assembly may be pneumatically or hydraulically driven. Still further, percussive force may be supplied by means of an explosive assembly adapted to provide staged, explosive forces.

BRIEF DESCRIPTION OF THE DRAWINGS FIGURE 1 shows a longitudinal sectional view of the apparatus in a wellbore below the earth in accordance with the present invention.

FIGURE 2 shows a longitudinal sectional view of a first embodiment of a bore increasing apparatus, comprising a disc assembly, used to install a drainage device installed in a wellbore in accordance with the present invention.

FIGURE 3 shows a cross sectional view of the anchor of FIGURE 2.

FIGURE 4 shows a cross sectional view of the lock assembly of FIGURE 2.

FIGURE 5 shows a cross sectional view of the lock assembly of FIGURE 4 taken along line 5-5 in FIGURE 4.

FIGURE 6 shows a perspective view of a disc forming part of the disc assembly shown in Figure 2.

FIGURE 7 shows a cross-sectional view of the disc of Figure 6 taken along line 7-7 in FIGURE 6.

FIGURE 8 shows a perspective view of the drainage device of FIGURE 2 wherein the drainage device is a perforated shaft.

FIGURE 9 shows a longitudinal sectional view of a second embodiment of the present invention comprising a linkage assembly and using a sampler.

FIGURE 10 shows a side perspective view of the upper portion of the casing of FIGURE 9.

FIGURE 11 shows a longitudinal sectional view of a third embodiment of the present invention comprising a bit and a hole opener and using an expansion device in a pre-loaded casing.

FIGURE 12 shows a side elevational view of the upper portion of a pre-loaded casing of FIGURE 11 with the drainage devices pre-loaded in the casing.

FIGURE 13 shows a side elevational view of the upper portion of the pre-loaded casing of FIGURE 12 with the drainage devices extending therethrough.

FIGURE 14 shows a side elevational view of the drainage device of FIGURE 13.

FIGURE 15 shows a cross sectional view of the drainage device of FIGURE 14.

FIGURE 16 shows a longitudinal sectional view of a fourth embodiment of the present invention comprising the third embodiment of Figure 11 and a pipe retriever, and using a drainage device in a pre-loaded casing.

FIGURE 17 shows an end view of the pre-loaded casing of FIGURE 16 showing cylindrical drainage devices and tubing for pumping cement to complete the well.

FIGURE 18 shows a side elevational view of the pre-loaded casing of FIGURE 17 with the tubing and cylindrical drainage devices depicted by dotted lines.

FIGURE 19 shows a perspective view of another embodiment of the drainage device of FIGURE 8 employed in the embodiment of Figure 16, wherein the drainage device is a shaft defining a helical channel.

FIGURE 20 shows a longitudinal sectional view of the pipe retriever assembly of FIGURE 16.

FIGURE 21A shows a top portion of a longitudinal sectional view of a fifth embodiment of the present invention comprising an explosive assembly and a disc assembly, used to install a drainage device installed in a wellbore in accordance with the present invention.

FIGURE 21B shows a bottom portion of the longitudinal sectional view of the embodiment of FIGURE 21 A.

FIGURE 22A shows a top portion of a longitudinal sectional view of a sixth embodiment of the present invention comprising a hydraulic assembly and a disc assembly, used to install a drainage device installed in a wellbore in accordance with the present invention.

FIGURE 22B shows a bottom portion of the longitudinal sectional view of the embodiment of FIGURE 22A.

FIGURE 23 shows a top view of another embodiment of the disc of FIGURE 6, forming part of the anvil assembly shown in FIGURE 21 B.

FIGURE 24 shows a side elevational view of the disc of FIGURE 23.

FIGURE 25 shows a partial cross sectional view of the disc FIGURE 23 taken along line 25-25 of FIGURE 23.

FIGURE 26 shows a longitudinal sectional view of the anchor assembly of FIGURE 22B.

FIGURE 27 shows a cross sectional view of a drainage device of FIGURE 22B being driven through the casing and into the subterranean formation.

FIGURE 28 shows another embodiment of the drainage device of FIGURE 27 having a plurality of teeth.

FIGURE 29 shows a cross sectional view of the explosive assembly of FIGURE 21 A.

FIGURE 30 shows a plan view of a pressure sensitive switch and a wire line cable used in the operation of the explosive assembly of FIGURE 21 A.

FIGURE 31 shows a cross sectional view of the disc of FIGURE 23 having a diameter a.

FIGURE 32 shows a cross sectional view of the disc of FIGURE 23 having a retracted diameter bl.

FIGURE 33 shows a cross sectional view of the disc of FIGURE 23 having an expanded diameter b2.

BEST MODES FOR CARRYING OUT THE INVENTION The present invention provides an apparatus and method for forcing an object through the sidewall of a borehole by non-rotary force. This non-rotary approach compresses the surrounding formation and thus produces little or no spoils or cuttings. Using the method and apparatus of this invention a drainage device may be inserted in the formation through the wellbore for increasing the effective diameter of the well. The apparatus includes a tool that imparts a propulsion force axially through the borehole to force drainage devices into the producing formation. This reduces many of the problems of rotary drilling which include the inability to penetrate the well casing, the inability to drill through a variety of soil types, the high failure rate of mechanical parts, and the back-flow of drilling fluids and earth that are generated during the drilling operations.

Tools have previously been provided for completing downhole drilling operations. Such devices known in the well drilling industry include percussion drilling tools sometimes referred to as"down-hole-percussion drill motors", as more particularly described in U. S. Pat. No. 4,694,911, the entire contents of which is hereby incorporated by reference. However, such percussion drilling tools are primarily restricted to axially oriented drilling operations. The present invention overcomes the deficiencies of the existing rotary drilling tools by providing an apparatus that is capable of using a propulsion force, such as a percussive, explosive, and/or hydraulic force, to penetrate a wellbore and drive an object into a subterranean formation whereby the effective diameter of the wellbore is increased.

Turning now to the drawings in general, and to Figure 1 in particular, there is shown therein the apparatus 10 depicted in the environment in which the apparatus of this invention is utilized. Wellbore 12 is located within a subterranean formation 13 below the earth's surface 15. An oil rig 14 is located above the wellbore 12 and pumps hydrocarbons, such as oil, from the subterranean formation 13. The

apparatus 10 is disposed inside wellbore 12 to impart a propulsion force on a drainage device 16 whereby the drainage device 16 is driven through the sidewall 17 of the wellbore 12 and into the subterranean formation 13, thereby increasing the effective diameter of the wellbore 12.

It will be appreciated that, while the wellbore 12 depicted in Figure 1 is a generally vertical hole used in the production of oil and gas from subterranean formations, the present invention is adapted for use in a variety of wellbores. The term"wellbore"as used herein encompasses a variety of holes in the earth including boreholes that are generally horizontal, vertical, linear, non-linear curved, at various other angles, or combinations thereof. Similarly, the term"earth"as used herein encompasses a variety of soil conditions including soil, rock, porous and permeable subterranean formations, fluids and gas, and other components within the earth.

Turning to Figure 2, one embodiment of the present invention is shown. The embodiment of Figure 2 shows the apparatus 10 having an uphole end 18 and a downhole end 20. The apparatus 10 preferably comprises a housing 22 movably positionable within the wellbore 12, a propulsion assembly such as percussive assembly 23 capable of imparting a force, an anvil assembly such as disc assembly 24 capable of transmitting the percussive force to a drainage device 16, and an anchor 26.

As seen in Figure 2, the apparatus 10 is disposed in wellbore 12 having an internal tubular casing 28 that lines at least a portion of the sidewall 17 of the wellbore 12. The casing 28 has a sidewall 27. An annular space 29 remains between the apparatus 10 and the casing 28 of the wellbore 12. A layer of cement 30 bonds the casing 28 to the sidewall 17 of the wellbore 12 to secure it within the wellbore 12.

The apparatus 10 is used to impart a force that drives the drainage device 16 through the casing 28, the cement 30, and the sidewall 17 of the wellbore 12 and into the subterranean formation 13. The drainage device 16 forms an aperture 31 in the casing 28 when driven through the casing and into the subterranean formation 13.

The casing 28 is a solid, tubular casing or casing string, usually formed of connected sections, common to the oil and gas industry. However, it should be appreciated that a variety of casings may be used in conjunction with the present invention. The apparatus may be disposed in an existing wellbore having an existing

casing therein. Alternatively, a casing may be installed into the wellbore to be penetrated by the apparatus. The casing employed in conjunction with the apparatus may be adapted for penetration by providing it with apertures, as in Figure 8, or pre- loaded drainage devices, as in Figures 10 and 11, as will be described herein.

The apparatus 10 is disposable a distance downhole within the wellbore 12. The apparatus 10 may be lowered downhole into position using any means or method. One preferred device is a hoist (not shown) supported on drill rig 14. The hoist lowers and raises the apparatus 10 to a desired depth within the wellbore 12. It should be understood that other devices capable of lowering the apparatus 10 to the desired position in the wellbore 12 may also be used. One such device is a drill pipe having more than one conductor, such as a pipe comprising three concentrically arranged tubular members. Alternately, a single member drill pipe or tubing could be employed. Both types of drill pipe would be used with a drill rig to raise and lower the pipe. Still further, a winch truck could be used to extend and retract a wire-line cable, the cable being capable of conducting electrical current and carrying the weight of the downhole tools.

The apparatus 10 preferably is anchored at a predetermined depth within the wellbore 12 via anchor 26, connected to the downhole end 20 of the apparatus 10. Alternatively, the downhole end 20 of apparatus 10 may rest directly on the bottom 32 of the wellbore 12, without the use of any anchoring device, as depicted in Figure 8. However, it is often desirable to anchor the apparatus 10 at locations above the bottom 32 of the wellbore 12. The ultimate location of the device depends on the depth of the subterranean formation 13 and the desired depth at which work is to be done within the formation.

It should also be appreciated that the apparatus 10 may be anchored within the wellbore by placing the anchor at various locations on the apparatus. For example, a single anchor may be located at the downhole end of the apparatus or at the uphole end of the apparatus. Alternatively, anchors may be placed at multiple positions on the apparatus, such as at the uphole end, the downhole end, or combinations thereof. As seen in Figure 22B, a dual anchor may be placed at the downhole end of the apparatus as will be described more fully herein.

Referring now to Figure 3, the anchor 26 of the apparatus 10 is depicted in greater detail. The anchor 26 can be any suitable conventional anchor used in the oil industry. The anchor 26 generally comprises a body portion 33 and plurality of slips 34 extending radially therefrom. The slips are provided with a plurality of teeth 35 that are adapted to frictionally engage the sidewall 17 of the wellbore 12 and resist movement therefrom.

The anchor 26 is set by rotating the apparatus 10 clockwise with a small amount of torque and then applying tension by puling up on the apparatus. The drag springs on the anchor prevent it from rotating when torque is applied. As the internal slips screw is elongated, the slips traveling on an inclined plane make contact with the casing wall and prevent the tool from moving up or down when force is applied. The slips 34 of the anchor 26 are moved to the set position within a slot (not shown) so that the slips 34 extend radially about the anchor 26. The slips 34 push against the sidewall 17 of the wellbore 12 and prevent the apparatus 10 from moving within the wellbore 12. One set of slips prevents the upward movement and another set of slips prevents the downward movement. The slips are released by reducing the upward tension and turning the apparatus in the clockwise directions.

Referring back to Figure 2, while the apparatus 10 is being secured at the desired depth within the wellbore 12, it is preferable to maintain the percussive assembly 23 stationary. The percussive assembly 23 is preferably locked into place within the apparatus 10 via a releasable lock assembly 36. Once the anchor 26 is set, or the apparatus 10 otherwise secured, the lock assembly 36 may be released and the percussive assembly 23 activated.

Referring now to Figures 4 and 5, the preferred releasable lock assembly 36 is depicted. The lock assembly 36 is generally cylindrical collar comprising a fluted spring-loaded locking nut, such as a dizzy nut 37, and a set of torque dogs 38.

Lock assemblies, such as the one depicted in Figure 4 and 5, are common in the oil and gas industry. By rotating the dizzy nut 37, the spring loaded torque dogs 38 shift the dizzy nut 37 within the lock assembly 36 whereby the reciprocating shaft 52 is released so that it may reciprocate within the housing 22. By rotating the dizzy nut 37 in the opposite direction, the torque dogs 38 shift the dizzy

nut 37 to the locked position and the reciprocating shaft 52 is re-secured within the housing 22 of the apparatus 10.

Referring back to Figure 2, the apparatus 10 is provided with a shear mechanism 39. The shear mechanism 39 is located at the top of the apparatus 10 and is adapted to shear and release at least a portion of the apparatus 10, which is stuck in the wellbore 12. Such shear mechanisms are common in the oil and gas industry and are typically used to remove equipment from the wellbore.

The housing 22 of the apparatus 10 preferably is generally cylindrical with an uphole portion 40 and a downhole portion 42. The housing 22 may comprise a solid body with a guide 44 therethrough for purposes yet to be described. It should be appreciated that while the housing 22 seen in Figure 2 has a solid body, the housing 22 may be any shape, such as solid, hollow with a supportable tube therein as seen in Figures 22A and B, or a combination thereof as shown in Figure 9, as will be more particularly described herein.

With continuing reference to Figure 2, the guide 44 preferably defines an elongate aperture within the guide 44 adapted to hold the drainage device 16 in the proper orientation for release. The guide 44 preferably comprises a generally linear upper or axial portion 46, a directional downhole or latteral portion 48 and a middle transitional portion 50 therebetween. The directional downhole portion 48 is configured to direct the drainage device 16 to the desired location within the subterranean formation 13 and at the desired orientation.

The middle portion 50 defines a transition area between the upper portion 46 and lower portion 48, and preferably defines an elbow linking the linear upper portion 46 to the directional downhole portion 48 at a radius sufficient to permit the drainage device 16 to pass through the guide 44.

While the embodiment of Figure 2 shows a generally liner upper portion, a curved middle portion and a generally radial directional downhole portion, it will be appreciated that the shape of the guide 44 may be of any shape and the directional downhole portion can be oriente in any direction as long as the end of the guide 44 is positionable at a predetermined location adjacent the sidewall 17 of the wellbore 12.

The shape of the guide 44 and the orientation of the directional downhole portion 48 determine the angle at which the object exits the guide 44 and penetrates the subterranean formation 13. In the preferred embodiment shown in Figure 2, the linear portion 46 of the guide 44 forms a 90 degree angle to the directional downhole portion 48, thereby creating a 90 degree exit angle for the drainage device 16. It should be understood that the angle of the linear upper portion to the directional downhole portion of the guide may be at any angle required to drive the drainage device 16 into the formation 13, such as the 120 degree exit angle shown in Figure 9.

With continuing reference to Figure 2, the guide 44 may be integrally formed within the housing 22 as an aperture extending through the housing 22.

However, it should be understood that the guide 44 may be separate from the apparatus, as shown in the embodiment of Figure 16 and the casing of Figure 13.

The percussive assembly 23 comprises a reciprocating shaft 52 terminating in a downhole percussive end 54, a hammer 56, and a string assembly 58.

A portion of the reciprocating shaft 52 is disposed within the hammer 56 and extends a distance downhole from the hammer 56 and into the linear upper portion 46 of the guide 44.

The hammer 56 operates via pneumatic pressure created by the string assembly 58 as more particularly described in U. S. Pat. No. 4,694,911, previously incorporated herein. The three string assembly preferably comprises three concentric pipes fabricated in such a way as to prevent intercommunication between the three pipes: a high pressure string 60 in the middle, a low pressure string 62 on the outside, and a an inner circulation string 64.

The three-string assembly is capable of creating sufficient pressure to reciprocate the reciprocating shaft 52 axially within the linear upper portion 46 of the guide 44. The reciprocating action of the reciprocating shaft 52 generates an axial percussive force within the guide 44 whereby the reciprocating shaft 52 is capable of imparting a percussive force on the drainage device 16.

While in the preferred embodiment shown in Figure 2 the percussive assembly 23 is a hammer 56 pneumatically driven, it should also be appreciated that a percussive force generated by the percussive or propulsion assembly may be

generated by other devices such as a bumper sub, air actuated hammer, fluid actuated hammer, hydraulic jack assembly, or manual hammer.

As seen in Figure 2, the disc assembly 24 preferably comprises a plurality of discs 66 stacked together within the guide 44. The disc assembly 24 has an uphole end 68 and a downhole end 70.

Each disc 66 in the disc assembly 24 is positioned and adapted to receive and transmit the percussive force generated by the percussive assembly 23 and to conduct fluid therethrough. The uphole end 68 of the disc assembly 24 receives the percussive force from the downhole end 54 of the reciprocating shaft 52 and transmits the force through the disc assembly 24 to the drainage device 16. The downhole end 70 of the disc assembly 24 is adapted to percussively impact the drainage device 16 whereby the drainage device 16 and usually some of the disks behind it are forced out an opening 71 in the housing 22 and into the subterranean formation 13. A shear pin 73 is located across opening 71 to keep the discs 66 in place until the discs are pushed through the opening 71. Thus, fluid can flow through the drainage device and the exposed disks up through the guide 44 and the borehole.

Because of the size and shape of the discs 66, the discs 66 are capable of moving from the linear upper portion 46 around the curved middle portion 50 and through the directional downhole portion 48 of the guide 44. When stacked together to form a disc assembly 24 as shown in Figure 2, the discs 66 are capable of extending the entire length of the guide 44. Furthermore, the discs 66 are capable of moving through the entire length of the guide 44 and negotiating any turns or curves in the guide 44.

As shown in Figure 2, the disc assembly 24 comprises a plurality of discs 66. It should be understood, however, that the number of discs 66 used in the disc assembly 24 may vary. To accommodate various factors, such as the size of the guide and the desired depth of the object, the overall length of the disc assembly may be varied, as long as the percussive force is transferable through the guide to the object.

It should be appreciated that the number of discs may be increased to push the object a distance further into the sidewall 17 of the wellbore 12 and into the subterranean formation 13. The discs 66 are capable of entering the subterranean

formation 13 with the object whereby the object is percussively impacted beyond the wellbore 12 and forced further into the subterranean formation 13. Discs 66 may be added into the guide 44 during operation to increase the overall length of the disc assembly 24. Alternatively, the discs 66 may be removed to shorten the overall length of the disc assembly 24.

Referring now to Figures 6 and 7, the discs are generally cylindrical with an outwardly curved sidewall 72, configured with a concave upper surface 74 and a convex lower surface 76 so that, in the nested position, the upper surface 74 and the lower surface 76 of each disc 66 have a radius capable of allowing for lateral sliding movement. Additionally, the discs 66 preferably are water-permeable and thus may have a hole 73 therethrough and a plurality of channels 75 in the sidewall 72 to permit the flow of fluids up through the guide 44 during operation.

It will be appreciated that while the discs depicted in Figures 6 and 7 have concave bodies, the discs may be of a variety of shapes and sizes in accordance with the present invention.

The sidewall 72 of the disc 66 is depicted in Figure 6 as having generally rounded sidewall 72. The disc 66 is preferably made of metallized aluminum. However, it should also be appreciated that any material that is strong and resilient enough to transmit the percussive force generated by the apparatus 10 so as to drive an object a distance into the side of a wellbore could be used. Such materials include metal, steel, plastic, and combinations thereof.

Referring again to Figure 2, the object preferably is a drainage device 16 adapted to be percussively impacted by the percussive assembly 23 and driven through the wellbore 12 into the subterranean formation 13. Shown in more detail in Figure 8, the drainage device 16 is preferably hollow and generally cylindrical having a first end 78, a second end 80, and a bit 82 disposed on the first end 78.

The second end 80 is positionable near the disc assembly 24 and is adapted to receive a percussive force. The bit 82 has a tapered head 84 and may define a cutting element adapted to penetrate the earth. The bit 82 has a diameter larger than the diameter of the second end 80 of the object. In the embodiment of

Figure 8, the tapered head 84 of the bit 82 defines an inclined plane with a leading edge adapted to steer the object as it is driven into the subterranean formation 13.

The drainage device may be made of a variety of shapes and sizes and provided with various functional devices. For example, the drainage devices of Figures 1,2,5,6,16,17, and 19 are generally cylindrical with tapered first ends.

However, it will be appreciated that a variety of shapes may be employed, such as the fins of Figures 11,12,13,14 and 15 or the discs provided with a tapered head capable of puncturing the casing as depicted in Figure 21 B. Additionally, the drainage device may be provided with resistors which restrict the removal of the drainage device and seal the sidewall of the borehole disposed near the second end of the drainage device as seen in Figures 27 and 28. Alternately, in some instances, a core sampler, such as the sampler of Figure 9, will be used instead of the drainage devices.

The drainage device 16 is capable of forming a hole in the wellbore 12, thereby increasing the effective diameter of the wellbore 12. The drainage device 16 has a plurality of apertures 83 therethrough, and is provided with a sand screen 85 corresponding to the apertures 83. The sand screen 85, located within the drainage device 16, screens the hydrocarbons as they flow into the wellbore 12. The drainage device may be provided with a variety of sizes, shapes, and features to aid in the operation of the device. For example, the drainage device may have a variety of leading edges, filters, screens, liners, bits, and other attributes. The drainage device 16 of Figures 2 and 8 is preferably adapted to remain in the subterranean formation.

In operation, the apparatus 10 is lowered via a hoist to the desired location in the wellbore 12. The apparatus 10 is locked into position via the anchor 26. Once in position, the lock assembly 36, securing the percussive assembly 23, is released so that the reciprocating shaft 52 is free to move.

The three string assembly 58 is then activated to create pressure within the hammer 56. The pressure build up in the hammer 56 causes the reciprocating shaft 52 to axially reciprocate within the housing 22. As the reciprocating shaft 52 moves, a percussive force is generated. The reciprocating shaft 52 repeatedly impacts the uphole end 68 of the disc assembly 24. The disc assembly 24 is forced through the guide 44 towards the opening 71 in the housing 22.

The percussive impact generated by the percussive assembly 23 is transferred through each disc 66 of the disc assembly 24 to the drainage shaft 16. As the discs 66 are pounded by the reciprocating shaft 52, the downhole end 70 of the disc assembly 24 impacts the drainage shaft 16. The discs 66 and the drainage shaft 16 are forced through the guide 44 and out the opening 71 in the housing 22.

The drainage shaft 16 is then forced through the casing 28, the concrete 30, the sidewall 17 of the wellbore 12 and into the surrounding formation 13, whereby the effective diameter of the wellbore 12 is increased.

The operation continues until the drainage device 16 is extended the desired distance into the subterranean formation 13. Additional discs may be added to force the drainage device further into the subterranean formation. Upon completion, the percussive assembly may be re-secured into the apparatus via the locking assembly 36. The apparatus 10 may then be rotated to release the anchor 26 and the hoist may be used to remove the apparatus 10 from the wellbore 12.

Figure 9 shows a second embodiment of the present invention. The apparatus 10a is disposed within wellbore 12 having a casing 28a therein. The apparatus 10a preferably comprises a housing 22a movably positionable within the wellbore 12, a propulsion assembly such as percussive assembly 23 capable of imparting a percussive force, an anvil assembly such as linkage assembly24a capable of transmitting the percussive force, and a sampler 16a.

The casing 28a is more particularly shown in Figure 10. The casing 28a comprises a sidewall 27a having a plurality of apertures 3 la therethrough.

It should be understood that the apparatus 1 Oa may be adapted for use with any casing disposed inside the wellbore 12, such as a casing without apertures as depicted in Figure 2. When used in conjunction with the casing 28a, the sampler 16a may be positioned to penetrate the sidewall 17 of the wellbore 12 through the apertures 31a thereby reducing the amount of force required to puncture the wellbore 12.

Referring back to Figure 9, the housing 22a preferably comprises an uphole portion 40a and a downhole portion 42a having a guide 44a therethrough. The uphole portion 40a preferably is adapted to receive and support the percussive assembly 23a and at least a portion of the linkage assembly 24a. The downhole portion 42a preferably is threadably connected to the uphole portion 40a of the

housing 22a. Alternatively, the downhole portion 42a may be formed integrally with the uphole portion 40a of the housing 22a, as shown in Figure 2. The downhole portion 42a of the housing 22a is adapted to receive and support the remainder of the linkage assembly 24a and the sampler 16a in the desired orientation.

The guide 44a of Figure 9 is preferably provided with a generally linear uphole portion 46a, a directional downhole portion 48a and a generally curved middle portion 50a therebetween. As stated previously with respect to guide 44 of the embodiment shown in Figure 2, the guide 44a of the embodiment of Figure 9 may be of any size and shape consistent with the intended purpose and environment of the present invention. The guide 44a may be modified as described previously.

In Figure 9, the guide 44a is configured to support the percussive assembly 23a, the linkage assembly 24a and the sampler 16a in the desired orientation during operation thereby directing the movement of the linkage assembly 24a and the sampler 16a along the desired path. The guide 44a terminates at an opening 71a in the housing 22a. It is preferable to position the opening 71a of the housing 22a adjacent an aperture 3 la in the casing 28a so that the sampler 16a may be extended therethrough without penetrating the sidewall 27a of the casing 28a.

As seen in the embodiment depicted in Figure 9, the angle between the linear upper portion 46a and the directional downhole portion 48a of the guide 44a is approximately 120 degrees thereby creating a 120 degree exit angle for the sampler 16a.

The percussive assembly 23a of Figure 9 is the same percussive assembly 23a employed in the embodiment of Figure 2, previously described herein.

The percussive assembly 23a comprises a reciprocating shaft 52 terminating in a downhole percussive end 54, a hammer 56, and a string assembly 58. The percussive assembly 23a is disposed in the uphole portion 40a of the housing 22a and is adapted to impart a percussive force to the linkage assembly 24a.

The linkage assembly 24a comprises a plurality of interconnected linkages 88 adapted to accept and transmit the percussive force generated by the percussive assembly 23a. The linkages 88 are generally linear, pivotally connected shafts capable of receiving and transmitting a percussive force. The preferred linkage assembly 24a further comprises a first linkage 90 adapted to contact the downhole

percussive end 54 of the reciprocating shaft 52 and a last linkage 92 connected to the sampler 16a.

The linkages 88 are joined together via pin joints 94 to form a chain within the guide 44a. The pin joints 94 permit the linkages 88 to move two dimensionally within the guide 44a. However, it should be understood that other joints may be used to interconnect the linkages 88, such as rotary joints, joints, and other joints which permit the linkage assembly 24a to move through the guide 44a and force the sampler 16a into the subterranean formation 13 consistent with this invention.

Because of the number of linkages 88 and the flexible motion of the pin joints 94 connecting the linkages 88, the linkages 88 are capable of extending from the linear upper portion 46a, around the curved middle portion 50a and through the directional downhole portion 48a of the guide 44a.

The first linkage 90 is preferably supported within the linear upper portion 46a of the housing 22a. The linear upper portion 46a of the guide 44a preferably permits the first linkage 90 to move axially through the housing 22a as the linkage assembly 24a is impacted by the percussive assembly 23a.

Each subsequent linkage 88 is adapted to conform to the size, shape and orientation of the guide 44a. As shown in Figure 9, the linkages 88 are provided with various lengths to negotiate the curves and conform to the structure of the guide 44a. The linkages 88 of Figure 9 preferably are provided with shorter lengths to negotiate the sharper curved portions of the guide. Linkages with longer lengths are provided to bridge between generally unsupported portions of the guide. However, it will be appreciated that any length and shape of linkages may be utilized as long as the linkage assembly 88 is capable of transmitting the percussive force from the percussive assembly 23a to the sampler 16a and forcing the sampler 16a through the sidewall 17 of the wellbore 12.

The object penetrating the sidewall 17 of the wellbore 12, as depicted in Figure 8, is a sampler 16a having a generally tubular body adapted to receive a core sample from the subterranean formation 13. The linkage assembly 24a receives the percussive impact from the percussive assembly 23a and transfers the force through the plurality of linkages 88 to last linkage 92 and to the sampler 16a. The sampler 16a

is driven into the sidewall 17 of the wellbore 12 through an aperture 3 la in the casing 28a.

The linkages 88 may be extended into the subterranean formation 13 and retracted therefrom. Because the sampler 16a is interconnected to the plurality of linkages 88, the linkage assembly 24a and the sampler 16a are retractable from the subterranean formation 13. As the linkages 88 are retracted, the sampler 16a is pulled out of the subterranean formation 13 and back into the housing 22a through the opening 71a in the housing 22a.

In the embodiment of Figure 9, the object is a sampling device 16a such as a core sampler connected to the linkage assembly 24a. However, it should be understood that any object may be utilized in accordance with this invention.

Additionally, the object may be connected to the linkage assembly 24a as in Figure 9 or separate as shown in Figure 2.

In operation, the apparatus 10a is lowered via a hoist (not shown) to the bottom 32 of the wellbore 12. The apparatus 10a rests in place on the bottom 32 of the wellbore 12 and is positioned so that opening 7 la is adjacent an aperture 3 la.

The three string assembly 58 is then activated to create pressure within the hammer 56. The pressure build up in the hammer 56 causes the reciprocating shaft 52 to axially reciprocate within the housing 22a. As the reciprocating shaft 52 moves, a percussive force is generated. The reciprocating shaft 52 repeatedly impacts the uphole end 68a of the linkage assembly 24a. The linkage assembly 24a is forced through the guide 44a towards the opening 71 a in the housing 22a.

The percussive impact is transferred through each linkage 88 in the linkage assembly 24a to the sampler 16a. The percussive force pounds the linkages 88 through the guide 44a and towards the opening 71 a in the housing 22a.

As the linkages 88 are pounded by the reciprocating shaft 52, the last linkage 92 in the linkage assembly 24a forces the sampler 16a through the guide 44a and out the opening 71 a in the housing 22a. The sampler 16a is then forced through apertures 31 a of the casing 28a and through the concrete 30, the sidewall 17 of the wellbore 12 and into the surrounding formation 13.

The operation continues until the sampler 16a is extended the desired distance into the subterranean formation 13. Linkages may be added or removed to

adjust the length of the linkage assembly and the distance the sampler 16a is extended into the subterranean formation. Upon completion, the hoist may then be used to remove the linkage assembly 24a and the core sampler 16a from the subterranean formation 13 and the apparatus 1 Oa from the wellbore 12. The linkage assembly 24a is pulled uphole through the housing 22a with the sampler 16a, and the core sample is recovered.

Referring now to Figure 11 is a third embodiment of the apparatus employed in a system for increasing the effective diameter of a wellbore 12. The system comprises an apparatus 10b disposable in a pre-loaded casing 28b.

The apparatus 10b is shown inside a wellbore 12 having a pre-loaded casing 28b therein. The apparatus 10b is adapted to impart a percussive force on a drainage device 16b loaded into a pre-loaded casing 28b whereby the drainage device 16b is driven through the sidewall 17 of the wellbore 12 and into the subterranean formation 13.

As seen in greater detail in Figures 12 and 13, the pre-loaded casing 28b preferably comprises a tubular sidewall 27b having a plurality of apertures 31b therethrough and an drainage devices 16b disposed in each apertures 31b. While the Figures 11,12 and 13 depict drainage devices 16b loaded into the pre-loaded casing 28b, it should be understood that many objects consistent with this invention may be loaded into the casing and/or extended therethrough using the percussive force.

The drainage devices 16b of Figure 11 are shown in detail in Figures 14 and 15. The drainage devices 16b are generally triangular shaped fins having an outer edge 96, an inner edge 98 and generally linear and hollow cross- section. The drainage devices 16b are positioned within the apertures 31b in the sidewall 27b of the casing 28b and extend a distance inside the casing 28b.

The drainage devices 16b are disposed inside the casing 28b with the outer edge 96 of the drainage devices 16b adjacent the outer surface 100 of the casing 28b thereby permitting the casing 28b to be inserted into the wellbore 12 without additional resistance. The tips 102 (Figure 14) of the drainage devices 16b are attached to the casing 28b, so the drainage devices 16b may be extended through the casing 28b and remain attached thereto.

Referring back to Figure 11, the apparatus 1 Ob preferably comprises an anvil assembly such as percussive assembly 23b, and a hole opener 104. The percussive assembly 23b is the same percussive assembly 23b used in the embodiments depicted in Figures 2 and 9. However, in Figure 11, the reciprocating shaft 52 is provided with a bit 106 removably attached to the downhole end 54 of the reciprocating shaft 52. The hole opener 104 is attached to the reciprocating shaft 52 a distance uphole from the bit 106.

The bit 106 preferably has a generally solid, cylindrical body connected to the downhole end 54 of the reciprocating shaft 52. The bit 106 is reciprocated with the reciprocating shaft 52 as the reciprocating shaft 52 moves axially under the pressure of the hammer 56. The bit 106 is adapted to fit inside the casing 28b and impact the drainage devices 16b whereby the drainage devices 16b are driven through the casing 28b and into the subterranean formation 13.

The hole opener 104 preferably is connected to the shaft 52 of the hammer 56 between the hammer 56 and the bit 106. The hole opener 104 comprises a first portion 108 and a second portion 109. The first portion 108 defines a solid frusto-conical body connected to the reciprocating shaft. The second portion 109 defines a generally hollow cylindrical body portion adapted to receive and conform to the first portion 108. The second portion 108 has a sidewall 110 that is cut into a plurality of fingers 111 so that when the first portion 108 is inserted inside the second portion 109, the second portion 109 conforms to the shape of the first portion 108 and the fingers 111 extend radially about the first portion 108.

The first portion 108 is fixed on the reciprocating shaft 52. However, the second portion is free to move along the reciprocating shaft 52 between the first portion 108 and a collar 112. The collar 112 is fixed to the reciprocating shaft 52 a distance downhole from the first portion 108.

When the second portion 109 engages an obstruction in the wellbore 12, such as the drainage device 16b, and the apparatus 10b is moved downhole, the second portion 109 is frictionally engaged and prevented from moving further downhole. The second portion 109 continues to move downhole towards the first portion 108. As the second portion 109 contacts the first portion 108, the fingers 111 expand radially about the reciprocating shaft 52 and press against the

sidewall 17 of the wellbore 12. In the expanded position, the fingers 111 push against the sidewall 17 of the wellbore 12 and impact the drainage device 16b thereby driving it a distance further into the sidewall 17 of the wellbore 12.

Once the drainage device 16b is pushed into the sidewall 17 of the wellbore 12, the second portion 109 of the hole opener 104 is free to move away from the first portion 108 and gravitationally fall towards the collar 112. Once the second portion 109 loses contact with the first portion 108, the fingers 111 return to the original, collapsed position. In the collapsed position the hole opener 104 may now move freely within the wellbore 12.

Referring still to Figure 11, in the contracted position, the fingers 111 are retracted, and the hole opener 104 is easily movable within the wellbore 12. In the expanded position, the fingers 111 effectively increase the overall diameter of the hole opener 104. The expansion of the fingers 111 within the wellbore 12 imparts a radial percussive force from the hole opener 104 to the drainage devices 16b within the wellbore 12. As the drainage devices 16b are impacted by the fingers 111, they are driven further through the casing 28b and into the subterranean formation 13.

Figure 13 shows the drainage devices 16b in the expanded position after being driven out.

In operation, the pre-loaded casing 28b is inserted into the wellbore 12 with the drainage devices 16b extending inside the casing 28b. Once installed, the apparatus 10b may be lowered into the casing 28b using a hoist. The hammer 56 is activated and the reciprocating the reciprocating shaft 52 begins to reciprocate thereby reciprocating the bit 106 and the hole opener 104. The bit 106 percussively impacts the drainage devices 16b, whereby the drainage devices 16b are extended a distance through the apertures 31b of the pre-loaded casing 28b and into the subterranean formation 13. As the bit 106 forces the drainage devices 16b into the earth, the bit 106 extends further into the wellbore 12 to impact drainage devices 16b located further downhole in the wellbore 12.

As seen in Figure 11, as the bit 106 drops into the wellbore 12, the hole opener 104 moves downhole into the wellbore 12. As the hole opener 104 drops into the wellbore 12, the second portion 110 of the hole opener 104 rests on a drainage device 16b. As the hole opener 104 pushes down on the drainage device 16b, the first

portion 108 of the hole opener 104 is driven into the second portion 110 of the hole opener 104 whereby the Fingers 111 are extended radially about the shaft 52.

As the fingers 111 extend about the shaft 52, the fingers 111 push against the expansion devices 16b located in the casing 28b. The drainage devices 16b are driven a distance further through the casing 28b and into the subterranean formation 13. As the hole opener 104 pushes in the drainage device 16b through the sidewall of the wellbore, the hole opener 104 pushes past the drainage device 16b. Once past the drainage device 16b, the second portion 110 of the hole opener 104 is free to move downhole from the first portion 108 of the hole opener.

The second portion 110 of the hole opener may then return to its original shape thereby retracting the Fingers 111. In this now collapsed state, the hole opener 104 is free to move downhole to the next expansion device 16b.

The operation repeats until the desired number of drainage devices 16b have passed through the casing 28b. Upon completion of the operation, the fingers 111 of the hole opener 104 are retracted so that the apparatus 10b may be removed from the wellbore 12.

As best seen in Figure 11, the drainage devices 16b extend through the apertures 31b of the casing 28b, through the concrete 30, through the sidewall 17 of the wellbore 12, and into the subterranean formation 13. The tip 102 of the drainage devices 16b remain connected to the casing 28b after being driven into the subterranean formation 13. However, it will be appreciated that the drainage devices 16b may be completely or partially released as they are driven through the casing 28b. Alternatively, the drainage devices 16b may be disposed through the apertures 31b of the casing 28b without being connected thereto.

Referring now to Figure 16, another system for increasing the effective diameter of a wellbore is depicted. The system comprises a pre-loaded casing 28c and the fourth embodiment of the apparatus.

The apparatus 10c is disposed into a wellbore 12 having a pre-loaded casing 28c therein. The apparatus 10c is adapted to impart a percussive force on a drainage device 16c loaded into a pre-loaded casing 28c, whereby the drainage device 16c is driven through the sidewall 17 of the wellbore 12 and into the subterranean formation 13.

As seen in Figures 17 and 18, the pre-loaded casing 28c preferably comprises a tubular sidewall 27c, an internal tube 113, a plurality of releasable guides 44c, and a drainage device 16c disposed in each guide 44c. The drainage devices 16c are positioned within the guide 44c adjacent the sidewall 27c of the casing 28c between the sidewall 27c and the internal tube 113.

The guides 44c, as shown in Figures 17 and 18, preferably comprise generally linear tubes extending from a generally linear uphole portion 46c and through a directional downhole portion 48c. Each guide 44c terminates in an opening 71c in the casing 28c. The shape of the guide 44c is adapted to hold the drainage device 16c in place during operation. The guide 44c retains the drainage device 16c within the casing 28c in the proper orientation for release. The guides 44c are releasable from the sidewall 17 of the casing 28c into the subterranean formation 13 with the drainage device 16c therein.

Referring back to Figure 16, the casing 28c has guides 44c at staggered positions in the wellbore 12, so the drainage devices 16c may be released into the sidewall 17 of the wellbore 12 at various locations in the wellbore 12. The guides 44c are positioned circumferentially about the casing 28c so that the drainage devices 16c are released at various locations about the wellbore 12. Additionally, the guides 44c may be made integral with or separate from the drainage devices 16. It should be noted that any number and shape of guides may be used to hold a number of objects for release into the sidewall of the borehole.

The drainage device 16c of Figure 16 is shown in greater detail in Figure 19. The drainage device 16c defines a solid cylindrical body with a helical channel 114. The helical channel 114 acts as a flow channel aiding in transferring fluid from the subterranean formation 13 to the wellbore 12. The drainage device 16c <BR> <BR> <BR> of Figure 17 may also be provided with a filter (not shown) adapted to minimize ; I- flow of particles from the subterranean formation 13 into the wellbore 12. While the Figure 16 depicts a drainage device 16c loaded into the pre-loaded casing 28c, it should be understood that many objects, such as the drainage device 16 described herein, may be loaded into the casing 28c and/or extended therethrough using the percussive force as described herein.

Referring back to Figure 16, the apparatus 10c is similar to apparatus 10b, but preferably further comprises a pipe retriever 116 extending downhole from the bit 106 and removably connected thereto.

The pipe retriever 116 of Figure 16 is shown in detail in Figure 20.

The pipe retriever 116 comprises a body portion 118 having a slanted slot therethrough (not shown), a movable slip 122 extending downhole from the body portion 118 and a stationary slip 124 adjacent the movable slip 122 and extending downhole from the body portion 118.

The body portion 118 of the pipe retriever 116 is preferably a hollow cylinder threadably connected to the bit 106 and removable therefrom. The lower end 126 of the body portion 118 is adapted to percussively impact the intemal tube 113 and drive it downhole during operation. The body portion 118 has a slanted slot (not shown) angled to guide the movement of the movable slip 122 within the body portion 118. The body portion 118 is adapted to receive and hold the movable slip 122 and the stationary slip 124 during operation.

The movable slip 122 and the stationary slip 124 combine to form a generally cylindrical shape adapted to fit inside the internal tube 113. The stationary slip 124 has a sloped surface 128 adjacent the movable slip 122. The movable slip 122 travels along the sloped surface 128 of the stationary slip 124 and is held in position by the slanted slot.

As the movable slip 122 travels along the sloped surface 128 of the stationary slip 124, the overall width of slips 122 and 124 varies. When the movable slip 122 is in the uphole position, the overall combined width of the slips is minimized making the slips disposable in the internal tube 113. As the pipe retriever 116 is withdrawn from the wellbore 12, the movable slip 122 moves to the downhole position, thereby maximizing the overall width of the slips 122 and 124 and the-. resisting removal from the internal tube 113. As the pipe retriever 116 is lifted uphole, gravity pulls the movable slip 122 to the downhole position thereby securing the slips 122 and 124 inside the internal tube 113. Once secured into position, the slips 122 and 124 grab the internal tube 113, so it is lifted out of the wellbore 12 with the apparatus 10c.

In operation, the apparatus 10c is lowered into a wellbore 12 having a casing 28c therein. The percussive assembly 23 generates a percussive force, which reciprocates the bit 106 and the pipe retriever 116. The pipe retriever 116 percussively impacts the internal tube 113 and drives it downhole into the wellbore 12. The bit 106 percussively impacts the drainage devices 16c in the guides 44c and drives them through the guides 44c, out the opening 71c and into the subterranean formation 13. The hole opener 104 then expands to impact the drainage devices 16c again and drives them further through the casing 28c and into the subterranean formation 13.

Upon completion of the percussion operation, the apparatus 10c may be removed from the wellbore 12 by a hoist as previously described herein. The internal tube 113 may simultaneously be removed by inserting the slips 122 and 124 inside the internal tube 113 and retrieving it from the wellbore 12 as heretofore described.

Turning to Figures 21A and 21B, a fifth embodiment of the present invention is shown. The apparatus 10d is disposed within wellbore 12 having a casing 28 therein. The apparatus 10d preferably comprises a housing 22d movably positionable within the wellbore 12, a propulsion assembly such as explosive assembly 23d capable of imparting an explosive force, and an anvil assembly such as disc assembly 24d adapted to receive the explosive force.

The apparatus 10d is preferably provided with a wire line cable 129 capable of supporting the apparatus 10d as it is lowered into the wellbore 12, and providing electricity to the apparatus 10d as necessary to operate various aspects of the apparatus as will be described more fully herein. As best seen in Figure 30, the wire line cable 129 comprises several wires capable of transferring electricity downhole to the apparatus 1Od from a power source located uphole (not shown).

Referring back to Figures 21A and B, the housing 22d of the apparatus 10d preferably is generally cylindrical with an uphole portion 40d and a downhole portion 42d. The uphole portion 40d of the housing 22d defines a pressurized chamber 130. The downhole portion 42d of the housing 22d is solid and defines a guide 44d therethrough.

With continuing reference to Figures 21 A and B, the guide 44d preferably defines an elongate aperture adapted to hold the disc assembly 24d in the proper orientation for release. Similar to the guides shown in Figures 2 and 9, the guide 44d of Figure 21 B preferably comprises a generally linear upper portion 46d, a directional downhole portion 48d and a middle portion 50d therebetween. The directional downhole portion 48d is configured to direct the drainage device 16d to the desired location within the subterranean formation 13 and at the desired orientation.

The middle portion 50d defines a transition area between the upper portion 46d and lower portion 48d, and preferably defines an elbow linking the linear upper portion 46d to the directional downhole portion 48d at a radius sufficient to permit the disc assembly 24d to pass through the guide 44d.

As stated previously with respect to guides 44 of Figure 2 and 44a of Figure 9, the shape of the guide 44d and the orientation of the directional downhole portion 48d determine the angle at which the object exits the guide 44d and penetrates the subterranean formation 13. In the embodiment shown in Figures 21 A and B, the linear portion 46d of the guide 44d forms a 90 degree angle to the directional downhole portion 48d, thereby creating a 90 degree exit angle for the disc assembly 24d.

The explosive assembly 23d comprises an activator 132, a series of explosive charges 134, and a piston 136. The explosive assembly 23d is disposed within the pressurized chamber 130 with the piston 136 extending a distance downhole into the linear upper portion 46d of the guide 44d. The explosive assembly 23d is adapted to increase pressure within the pressurized chamber 130 to drive the piston 136 a distance downhole through the guide 44d.

Referring now to Figures 21 A and 29, the explosive charges are disposed separately within cavities 138 located in the pressurized chamber 130. A retainer 140, such as wax, may be used to seal each explosive charge 134 within a cavity 138 and isolate the explosive charges 134 during operation to prevent premature activation of the explosive charges 134.

The explosive charges 134 may be any type of charge capable of creating an explosive force within the pressurized chamber 130 so that the pressure is

increased to the desired pressure within the pressurized chamber 130. Types of charges that may be used include low order explosives with a slow reaction time and which are not shock activated.

Referring back to Figures 21 A and B, the activator 132 preferably comprises a generally circular plate 139 and a plurality of switches 140 (Figure 30).

The activator 132 is connected to the wire line cable so it may receive electricity to activate the switches. The switches 140 are adapted to individually activate the explosive charges 134 when electricity is sent downhole via the wire line cable 129.

The activator 132 is shown in greater detail in Figure 30. The switches 140 are disposed about the circular plate 139 in positions corresponding to the electric charges. The switches 140 are activated by electricity sent downhole to the activator 132 via the wire line cable 129. One or more of the switches may be activated to set off the explosive charges as desired.

The activator 132 is an electronic device capable of transferring an electric signal from the wire line cable to the explosive charges 134. It will be understood that any device capable of detonating the electric charges at the desired time may be utilized. Examples of various other devices capable of detonating the electric charges are detonators fired by stepping switches or timed sequence ignitors.

Ingiting the charges in sequence allows for control of the pressure within the high pressure cylinder. The detonators are fired sequentially, each when the internal pressure is reduced to a preset level as the piston moves downward forcing the drainage device out into the formation.

Referring back to Figure 21A, each switch 140 is connected to an explosive charge 134. The switches 140 may be activated in sequence once a desired pressure is reached within the pressurized chamber 130. This permits the explosive charges 134 to be activated over a period of time thereby extending the duration of the increased pressure within the pressurized chamber 130. The increase in pressure is used to drive the piston 136 downhole into the guide 44a.

The piston 136 has an upper portion 142 disposed within the pressurized chamber 130, a lower portion 144 extending from the pressurized chamber 130 a distance downhole into the guide 44d, and a downhole end 145. The

piston 136 is axially movable within the apparatus as pressure is increased by the explosive force created by detonation of the explosive charges 134.

The movement of the piston 136 may be restricted by the dimensions of the housing 22d. The housing 22d may be provided with upper stop 146 to limit the upward movement of the piston 136, and lower stops 148 to limit the downward movement of the piston 136. Alternatively, the dimensions of the pressurized chamber 130 may be such that the housing itself restricts the movement of the piston 136.

The piston 136 may also be provided with seals 150 to prevent the loss of pressure from the pressurized chamber 130 as the piston 136 moves through the apparatus 10d. Seals may be provided at various locations such as on the piston 136, on the housing 22d, or combinations thereof.

While in the preferred embodiment shown in Figures 21 A and B the explosive assembly 23d is a piston 136 driven by an explosive device, it should also be appreciated that the force generated by the explosive assembly may be generated by other devices such as the percussive force of Figures 2 and 9 or the hydraulic force of Figures 22A and B.

Referring back to Figures 21 A and B, the disc assembly 24d preferably comprises a plurality of discs 66a stacked together within the guide 44d and adapted to provide a passageway for recovery of fluid. The disc assembly 24d has an uphole end 68d and a downhole end 70d.

Each disc 66a in the disc assembly 24d is positioned and adapted to receive the explosive force generated by the explosive assembly 23d. The uphole end 68d of the disc assembly 24d receives the explosive force from the downhole end 145 of the piston 136 and is forced downhole through the guide 44a. The downhole end 70d of the disc assembly 24d is adapted to be forced out an opening 71 d in the housing 22d and into the subterranean formation 13.

The disc assembly 24d of Figure 21B is provided with a starter disc 152 at the downhole end 70d of the disc assembly 24d. The starter disc 152 has a bit 154 connected thereto. The bit 154 is similar to the bit 82 on the first end of the drainage device 16 of Figures 2 and 8. The bit 154 enables the starter disc 152 to puncture the casing 28 and enter the subterranean formation.

Because of the size and shape of the discs 66a, the discs 66a are capable of moving from the linear upper portion 46d around the curved middle portion 50d and through the directional downhole portion 48d of the guide 44d.

When stacked together to form disc assembly 24d as shown in Figure 21B, the discs 66a are capable of extending the entire length of the guide 44d. Furthermore, the discs 66a are capable of moving through the entire length of the guide 44d and negotiating any turns or curves in the guide 44d.

As shown in Figure 21B, the disc assembly 24d comprises a plurality of discs 66a. As stated previously with respect to Figure 2, it will be understood that the number of discs 66a used in the disc assembly 24d may vary. To accommodate various factors, such as the size of the guide and the desired depth of the penetration into the subterranean formation, the overall length of the disc assembly 24d may be varied, as long as the disc assembly 24d is drivable the desired distance into the subterranean formation.

It should be appreciated that the number of discs may be increased to extend a distance further through the sidewall 17 of the wellbore 12 and into the subterranean formation 13. The discs 66a are capable of entering the subterranean formation 13 whereby the discs are explosively impacted beyond the wellbore 12 and forced further into the subterranean formation 13. Discs 66a may be added into the guide 44d during operation to increase the overall length of the disc assembly 24d.

Alternatively, the discs 66a may be removed to shorten the overall length of the disc assembly 24d.

Referring now to Figures 23 through 25, the discs 66a may be shaped similarly to the discs 66. Thus, the discs are generally circular with a circumference 154, an outwardly curved sidewall, a concave upper surface 156 and a convex lower surface 158. The discs 66a may be provided with notches 160 that enable the discs 66a to compress further as they are forced through the guide 44d.

The diameter"a"of the discs 66a as seen its relaxed or resting position is slightly smaller than the internal diameter of the guide 44d.

Figures 31 through 33 show the discs 66a in a schematic form simply to illustrate the slight compression and expansion that the discs can undergo. As seen in Figure 31, the resting diameter"a" (see also Figure 24) is slightly smaller than the

internal diameter of the guide 44d so that the discs can be pushed through the guide.

The discs 66a are flexible to enable the discs 66a to conform to the shape of the guide 44d as they pass through it. As stated previously with respect to the discs of Figures 2,6 and 7, the discs are preferably made of metallized alluminum, but may be made of other flexible, sturdy materials.

As the discs 66a are driven into the guide 44d, the discs maintain their slightly smaller diameter relative to the guide diameter. As indicated, the discs are flexible and may compress, if necessary, to a slightly reduced diameter"bl" (Figure 32) as they are forced down the curved guide 44d. Once the discs are forced out into the formation, pressures in the formation may create a backward pressure. In this event, the discs 66a will widen slightly to diameter"b2", as shown in Figure 33, to frictionally engage the adjacent surfaces of the formation and resist any backward movement. Thus, while the discs are capable of being driven outward into the formation, concave shape resist reverse movement back toward the apparatus in the borehole.

The discs 66a preferably have a hole 162 therethrough to provide a passageway for the recovery of fluid therethrough. The fluid flow may be enhanced by providing the discs with a plurality of grooves 164 in the upper surface 162 to allow the flow of fluids through the guide 44d during operation. If the upper surface 162 is grooved, the lower surface 164 preferably is smooth. Further, the grooves preferably will be formed by some process that provides flattened interstitial spaces to slidably engage the adjacent flat undersuface of the disc above. It will be appreciated that the grooves could be provided on the underside of the discs, with the upper surfaces being smooth.

Referring back to Figures 21 A and B, the apparatus 10d may be provided with a collar locator 168 capable of detecting predetermined positions in the well. The collar locator 168 is powered via the electricity provided by the wire line cable 129. Once the predetermined location is detected by the collar locator 168, the apparatus 10d may then be activated to dispose an object into the wellbore 12.

The apparatus 10d may also be provided with a back up device 170 located on the lower portion of the housing 22d opposite the opening 7 1 d. The back up device 170 is positioned to contact the sidewall of the borehole opposite the

location that the discs 66a are driven into the subterranean formation so that the back up device 170 may absorb the forces created and stabilize the apparatus within the borehole.

In operation, the apparatus 10d is lowered via a hoist to the desired location in the wellbore 12. The collar locator 168 detects the proper location within the wellbore. The apparatus 10d is then locked into the desired position via the anchor 26a. Once in position, the electricity may be sent downhole through wire line cable 129 to the activator 132. The switches 140 of the activator 132 detonate the explosive charges 134.

The explosive charges 134 explode within the pressurized chamber 130 to increase the pressure therein. The pressure build up in the pressurized chamber 130 causes the piston 136 to move axially downhole into the guide 44d. As the piston 136 moves further downhole into the guide 44a, the downole end 145 of the piston 136 impacts the uphole end 68d of the disc assembly 24d. The disc assembly 24d is forced through the guide 44d towards the opening 71d in the housing 22d.

The explosive force generated by the explosive assembly 23d is transferred to each disc 66a of the disc assembly 24d. The explosive force drives the discs 66a downhole through the guide 44d until the discs 66a are eventually forced out the opening 71 d in the housing 22d. The discs 66a are then forced through the casing 28, the concrete 30, the sidewall 17 of the wellbore 12 and into the surrounding formation 13, whereby the effective diameter of the wellbore 12 is increased.

The operation continues in a sequential mode until the discs 66a are extended the desired distance into the subterranean formation 13. Also, the activator may be repeatedly activated so that the switches detonate additional charges and drive the disc assembly further into the subterranean formation. Upon completion, the hoist may then be used to remove the apparatus 10d from the wellbore 12.

Turning to Figures 22A and B, a sixth embodiment of the present invention is shown. The apparatus 10e preferably comprises a housing 22e movably positionable within the wellbore 12, a propulsion assembly such as hydraulic assembly 23e capable of imparting a hydraulic force, an anvil assembly such as disc

assembly 24e capable of transmitting the hydraulic force to a drainage device 16e, and a dual anchor 26a.

The housing 22e of the apparatus 10e preferably is generally cylindrical with an uphole end 18e, a downhole end 20e, an uphole portion 40e and a downhole portion 42e. The uphole portion 40e of the housing 22e defines a pressurized chamber 182. The downhole portion 42e of the housing 22e is hollow with a tubular guide 44e therein. The tubular guide 44e is supported within the housing 22e via supports 183.

The pressurized chamber 182 further defines a low pressure reservoir 188, a high pressure reservoir 190, and flow channels 191 and 192 therebetween. As pressure increases in the low pressure reservoir 188, it is transferred through the flow channel 191 to the high pressure reservoir 190.

Similarly, as the high pressure fluid pressure is reduced, the fluid is transferred through the flow channel 192 to the low pressure fluid reservoirs. Check valves 193 may be provided in the pressurized chambers to control the pressure within any chamber and permit or restrict the flow of fluids as necessary.

The apparatus I Oe is disposable a distance downhole within the wellbore 12. The apparatus 10e may be lowered downhole into position as described previously with respect to Figure 2 using drill pipe or tubing 195 threadably connected to the uphole portion 40e of the housing 22e.

Referring back to Figure 22B, the apparatus 1 Oe may be provided with a dual anchor 26a threadably connected to the downhole end 20e of the apparatus love.

The dual anchor 26a is capable of securing the apparatus 10e in the wellbore so that the apparatus 10e resists movement in the uphole and/or the downhole direction.

Referring now to Figure 26, the dual anchor 26a of apparatus 10e is depicted in greater detail. The anchor 26a comprises a standard type double acting anchor used in the oil and gas industry, which has been modified in accordance with the present invention. The anchor 26a preferably comprises a central portion 194, an upper portion 196, a lower portion 198, a plurality of slips 200, and a drag spring 202.

The upper portion 134 is removably connected to the lower end 20d of the apparatus via threads 204.

The upper portion 196 is threadably connected to the central portion 132 of the anchor 26a via threads 206, and the lower portion 198 is threadably connected to the opposite end of the central portion 132 of the anchor 26a via threads 208. Threads 206 and 208 are threaded in opposite directions so that as the upper portion 196 and lower portion 198 are rotated clockwise the upper portion 196 and lower portion 198 are driven closer together. Similarly, as the upper portion 196 and lower portion 198 are rotated counter clockwise, they are driven farther apart.

The upper portion 196 has a generally cylindrical body with a tapered surface 210 that taper away from the central portion of the anchor. The lower portion 198 has a generally cylindrical body with a tapered surface 212 that taper away from the central portion 194 of the anchor 26a. The upper portion 196 and the lower portion 198 are provided with slips 200 connected thereto. The slips 200 are disposed on the upper portion 196 and the lower portions 198 so that they extend radially about the anchor 26a.

The slips 200 are movably connected along the tapered surface 210 of the upper portion 196 and the tapered surface 212 of the lower portions 196. The slips 200 are capable of moving along the tapered surfaces between an extended and retracted position. As the slips 200 are moved along the tapered surfaces toward the central portion 194, the slips 200 extend radially outward so that the overall diameter of the anchor 26e is expanded. As the slips 200 are moved along the tapered surfaces away from the central portion 194, the slips 200 retract inwardly so that the overall diameter of the anchor 26a is reduced.

The slips 200 are provided with a plurality of teeth 214 which are adapted to frictionally engage the sidewall 17 of the wellbore 12 and resist movement therefrom. As the slips 200 are moved to the extended position, the teeth 214 are capable of contacting the sidewall 17 of the wellbore 12. As the slips 200 are moved to the retracted position, the teeth 214 are released from the sidewall 17 of the borehole 12.

The drag spring 202 is disposed about the anchor 26a with the slips 200 extending therethrough. The drag spring 202 is adapted to frictionally engage the sidewall 17 of the wellbore 12 and resist rotation.

The anchor 26a is set by rotating the apparatus 10e counterclockwise, then applying upward tension on the apparatus 1 oye. The drag spring 202 engages the sidewall 17 and resists rotation. It is released by rotating the device clockwise and releasing the tension.

As that anchor 26a is rotated counterclockwise, the upper portion 196 and the lower portion 198 of the anchor 26a move apart. The slips 200 of the anchor 26a are moved to the extended position so that the slips 200 extend radially about the anchor 26a. The teeth 214 engage the sidewall 17 of the wellbore 12 and prevent the apparatus 10d from moving within the wellbore 12.

With continuing reference to Figures 22 A and B, the guide 44e preferably defines an elongate aperture within the guide 44e adapted to hold the drainage device 16e in the proper orientation for release. As seen in Figures 2 and 9, the guide 44e preferably comprises a generally linear upper portion 46e, a directional downhole portion 48e and a middle portion 50e therebetween. The directional downhole portion 48e is configured to direct the drainage device 16e to the desired location within the subterranean formation 13 and at the desired orientation.

The middle portion 50e defines a transition area between the upper portion 46e and lower portion 48e, and preferably defines an elbow linking the linear upper portion 46e to the directional downhole portion 48e at a radius sufficient to permit the drainage device 16e to pass through the guide 44e.

A stated previously with respect to guides 44 of Figure 2, the shape of the guide 44e and the orientation of the directional downhole portion 48e determine the angle at which the object exits the guide 44e and penetrates the subterranean formation 13. In the embodiment shown in Figures 22A and B, the linear portion 46e of the guide 44e forms a 90 degree angle to the directional downhole portion 48e, thereby creating a 90 degree exit angle for the drainage device 16e.

The hydraulic assembly 23e comprises a hydraulic pump 216 and a piston 218. The hydraulic assembly may also be provided with seals 219 to prevent leakage of fluid between the various portions of the hydraulic assembly. The hydraulic assembly 23e is disposed within the pressurized chamber 182 with the piston 218 extending a distance downhole into the guide 44e.

The hydraulic pump 216 comprises a pipe 220 and a ram 222. The hydraulic pump 216 is disposed in the pressurized chamber 182 and extends a distance uphole therefrom. The hydraulic pump 216 is capable of reciprocating axially within the apparatus I Oe to create pressure in the pressurized chamber 182.

The ram 222 has an upper portion 224 and a lower portion 226. The ram 222 is disposed within the pressurized chamber 182 and reciprocates axially within the apparatus 10e. The lower portion 226 of the ram 205 extends into a low pressure reservoir 228 and reciprocates therein. The upper portion 224 of the ram 222 extends out the uphole end 18e of the housing 22e.

The pipe 220 is threadably connected to the ram 222 and extends a distance uphole therefrom. The pipe 220 may be a single tubular pipe, or a series of segmented pipe connected to form one long pipe. The pipe 220 preferably extends from the uphole from uphole end 18e of the housing 22d to the surface.

The pipe 220 is axially reciprocated in the apparatus 10e. The force and weight of the pipe 220 cause an increase in pressure in the pressurized chamber 182. As the pressure increases, the low pressure fluid is increased to high pressure fluid and transferred from the low pressure fluid reservoir 228 through the fluid channels 192 and into the high pressure fluid reservoir 190. Check valves 230 may be used to regulate the flow of fluid between the reservoirs.

The piston 218 has an upper portion 232, a lower portion 234, and a downhole end 235. The upper portion 232 of the piston 202 is disposed within the high pressure chamber 190, and the lower portion 234 extends from the pressurized chamber 182 a distance downhole into the linear upper portion 46e of the guide 44e.

The upper portion 232 of the piston 218 is located in the high pressure chamber 190 and extends a distance downhole into the guide 44e. As pipe 220 reciprocates within the pressurized chamber 182 and creates additional high pressure fluid for the high pressure reservoir 190, the piston 218 is forced axially downhole into the linear upper portion 46e of the guide 44e. The downward movement of the piston 218 generates an axial force within the guide 44e whereby the piston 218 is capable of imparting a hydraulic force on the drainage device 16e.

While in the preferred embodiment shown in Figures 22 A and B the hydraulic assembly 23e is a piston driven by a hydraulic device, it should also be

appreciated that the force generated by the propulsion assembly may be generated by other devices.

As seen in Figure 22 A and B, the disc assembly 24e preferably comprises a plurality of discs 66a stacked together within the guide 44e. The disc assembly 24e has an uphole end 68e and a downhole end 70e.

The discs of Figure 22B preferably are the same discs used in Figure 21B. Each disc 66a in the disc assembly 24e is positioned and adapted to receive and transmit the hydraulic force generated by the hydraulic assembly 23e.

The uphole end 68e of the disc assembly 24e receives the hydraulic force from the downhole end 235 of the piston 218 and transmits the force through the disc assembly 24e to the drainage device 16e. The downhole end 70e of the disc assembly 24e is adapted to impact the drainage device 16e whereby the drainage device 16e is forced out an opening 71e in the housing 22e and into the subterranean formation 13.

Because of the size and shape of the discs 66a, the discs 66a are capable of moving from the linear upper portion 46e around the curved middle portion 50e and through the directional downhole portion 48e of the guide 44e. When stacked together to form an disc assembly 24e as shown in Figure 22B, the discs 66a are capable of extending the entire length of the guide 44e. Furthermore, the discs 66a are capable of moving through the entire length of the guide 44d and negotiating any turns or curves in the guide 44e.

As shown in Figure 22B, the disc assembly 24e comprises a plurality of discs 66a. It should be understood, however, that the number of discs 66a used in the disc assembly 24e may vary. To accommodate various factors, such as the size of the guide and the desired depth of the object, the overall length of the anvil assembly may be varied, as long as the hydraulic force is transferable through the guide to the object.

It should be appreciated that the number of discs may be increased to push the object a distance further into the sidewall 17 of the wellbore 12 and into the subterranean formation 13. The discs 66a are capable of entering the subterranean formation 13 with the object whereby the object is driven beyond the wellbore 12 and forced further into the subterranean formation 13. Discs 66a may be added into the

guide 44e during operation to increase the overall length of the disc assembly 24e.

Alternatively, the discs 66a may be removed to shorten the overall length of the disc assembly 24e.

Referring still to Figure 22B, the object preferably is a drainage shaft 16e adapted to be impacted by the hydraulic assembly 23e and driven through the wellbore 12 into the subterranean formation 13. The second end 80e is positionable near the disc assembly 24e and is adapted to receive a force. The drainage device 16e may be provided with the features heretofore described in the drainage devices of Figures 2 and 6, and additionally provided with resistors such as seals 236.

Shown in more detail in Figure 27, the drainage device 16e is hollow and generally cylindrical having a first end 78e, a second end 80e and a plurality of seals 236. The seals 236 are located near the second end 80e of the drainage device 16e. The seals 236 adhere to the casing 28 as the drainage device 16e is driven into the sidewall of the borehole. The seals 236 prevent the flow of fluid between the drainage device 16e and the casing 28 thereby maximizing the flow of fluids from the subterranean formation 13 into the apparatus 10e.

It will be understood that while the drainage device of Figure 27 is provided with resistors in the form of seals, other resistors may be used to prevent the flow of fluid between the drainage device 16e and the casing 28. For example, Figure 28 shows another embodiment of the drainage device 16 with a plurality of teeth 236a located at the second end 80f of the drainage device 16f. The teeth 236a also enable the drainage device to be driven into the sidewall of the wellbore and resist retraction therefrom.

In operation, the apparatus 10e is lowered via the pipe to the desired location in the wellbore 12. As sections are added to the pipe 220, the apparatus may be lowered further into the wellbore. The apparatus 10e is then locked into the desired position via the anchors 26a.

Once locked into position, the pipe 220 is lifted and lowered so that the ram 222 reciprocates axially within the pressurized chamber 182. The movement of the ram 222 increases the pressure of the fluid in the low pressure reservoir 228.

Once the pressure is increased to the desired pressure, the low pressure fluid is

transformed into high pressure fluid and moves from the low pressure reservoir into the high pressure reservoir 190.

The increase in pressure in the high pressure chamber 190 causes the piston 218 to move axially downhole into the guide 44e. As the piston 218 moves downhole, a hydraulic force is generated. The piston 218 moves further downhole into the guide 44e and impacts the uphole end 68e of the disc assembly 24e. The disc assembly 24e is forced through the guide 44e towards the opening 71 e in the housing 22e.

The force generated by the hydraulic assembly 23e is transferred through each disc 66a of the disc assembly 24e to the drainage shaft 16e. As the discs 66a are driven by the piston 218, the downhole end 70e of the disc assembly 24e impacts the drainage shaft 16e. The discs 66a and the drainage shaft 16e are forced through the guide 44e and out the opening 7 1 e in the housing 22e. The drainage shaft 16e is then forced through the casing 28, the concrete 30, the sidewall 17 of the wellbore 12 and into the surrounding formation 13, whereby the effective diameter of the wellbore 12 is increased.

The operation continues until the drainage device 16e is extended the desired distance into the subterranean formation 13. Preferably, the drainage device 16e is driven into the sidewall 17 of the wellbore until the seals 170 engage the casing 28 and seal the drainage device 16e to the casing 28. Additional discs 66a may be added to force the drainage device 16e further into the subterranean formation 13.

Upon completion, the apparatus 10e is then rotated to release the anchors 26a. The apparatus may then be removed by removal of the pipe 220 from the wellbore 12.

The efficacy of the apparatus and method of this invention is illustrated by the following working examples.

Casing Penetration and Test Configuration and Data Object: (a) Determine if a pointed shaft can be pushed through the wall of high quality steel, oil and gas well casing from inside the round pipe, as opposed to drilling a hole from the inside out by rotating a flexible shaft.

(b) Determine the compressive force required to push a pointed, two inch diameter shart through casing commonly used in oil and gas wells.

(c) Determine the effect of the shape of the point, in force required for penetration.

(d) Determine the effect of the diameter of the shaft, in the force required for penetration.

Test stand: High pressure, hydraulic cylinder, with 5-inch diameter internal piston, anchored between two"I"beams with the steel pipe supported and backed by oak lumber. The test stand allows for the force to be applied perpendicular to the wall of the steel pipe. Hydraulic pressure is supplied by a port-a-power hand pump.

Compressive force: The force generated by the test stand is the hydraulic pressure action on the cress-sectional area of the hydraulic cylinder. In this test stand, the 5-inch hydraulic cylinder would have an internal are of : 3.1416 X radius squared = 3.1416 X (2.5 X 2.5) = 19.635 square inches Force in pounds equals the measured pressure in pounds per square inch times the area, 19.635.

Test Conditions 5.500 Inch Diameter 15.5 Pounds/Foot J Grade Pipe (Wall 0.260 Inches Thick) Sharp Point Pressure to penetrate wall Pressure to open to 2 Sample inch Diameter (a) 950psi F=18, 653# 810psi F=15,904# (b) 940 psi F=18,457# 840 psi F=16,493# (c) 920psi F=18, 064# 870psi F=17, 082# Rounded Point Pressure to penetrate wall Pressure to open to 2 Sample inch Diameter (a) 970 psi F=19,046# 840 psi F=16,493# (b) 1020 psi F=20,028# 860psi F=16, 886# (c) 1050 psi F=20,617# 850 psi F=16, 690# 5.500 Inch Diameter 15.5 Pounds/Foot J 55 Grade Pipe Chisel Point Pressure to penetrate wall Pressure to open to 2 Sample (1 inch) inch Diameter (a) 980 psi F=19,242# 840 psi F=16,493# (b) 1040 psi F=20,420# 880 psi F=17,279# (c) 1020 psi F=20,028# 870 psi F=17, 082#

7.000 Inch Diameter 26.0 Pounds/Foot P-110 Grade Pipe (Wall 0.375 Inches Thick) Samples: Using a shaft with a sharp point, it was impossible to penetrate the steel wall without breaking the point from the shaft. The point was brittle on the end that contacted the casing and required too much force to deform the material.

Sample (a): Using a shaft with a point 0.375 inches in diameter and having a rounded point near the size of a used wood-pencil eraser, the pressure to penetrate the casing was 1,760 psi, with a resultant force of 34,558 pounds. Point was made from tungsten-carbide rotary bit insert.

(1) Once the point went through the casing, the pipe shattered or split out radially in more than one direction, but the preference was up and down the pipe.

(2) Opening the hole up to 2 inches in diameter, after the point went through, causes the pipe to split rather than tear and the force is less than 20,000 pounds.

Sample (b) Using a rounded point and a shaft composed of"nested washers" prepressed into a half-moon configuration (which allows the shaft to follow around a 90-degree elbow guide), a 2-inch diameter hole can be made in the P-110 casing with a force of 1,980 psi, 38,877 pounds.

Conclusions: (1) Making a hole through steel casing can be readily accomplished by using force to push the point through instead of drilling by twisting a shaft and bit.

(2) The shape of the point does not determine the force necessary to make a hole in the casing. If the point is large enough to spread the loading for deformation, a hole can be made that is almost independent of the shape of the point.

(3) Once the point goes through the wall of the pipe, making the hole larger requires less force to make the hole larger than the force to penetrate the wall.

(4) Making the hole larger in J 55 grade casing is done by elastic deformation and tearing. Making the hole larger in PI 10 grade casing is done by shattering or splitting.

It should be appreciated that an object, such as the drainage and expansion devices depicted herein may be formed integrally within or pre-loaded into a casing before inserting the casing into the wellbore. It should be appreciated that any object of any dimension may be used which increases the size of the wellbore.

Additionally, the object may be formed from various materials and combinations thereof. Such materials used to form the object may be flexible, such as PVC pipe, or more sturdy, such as stainless steel. Materials that may used to form the object include steel, ceramics, wood, synthetics, or plastics. Objects acting as drainage devices are known in the industry and come in a variety of sizes, shapes, and materials. Such drainage devices are disposable within wellbores for generating fluid flow. Such devices may be provided with filters and screens for controlling the flow of fluids and other particles into the wellbore.

While the invention has been described with a certain degree of particularity, it is manifest that many changes may be made in the details of construction and arrangement of components without departing from the spirit and scope of this disclosure. It is understood that the invention is not limited to the embodiments set forth herein for purposes of exemplification, but is to be limited only by the scope of the attached claims, including the full range of equivalency to which each element thereof is entitled.

INDUSTRIAL APPLICABILITY As will be apparent from the description, the invention is applicable in the oil and gas industry.