Patent Application
20100078171
1. Technical Field
The present disclosure generally relates to well bore tools and in particular to methods and apparatus for forming and sealing a hole in a sidewall of a borehole.
2. Background Information
Oil and gas wells have been drilled at depths ranging from a few thousand feet to as deep as five miles. Information about the subterranean formations traversed by the borehole may be obtained by any number of techniques. Techniques used to obtain formation information include obtaining one or more formation fluid samples and/or core samples of the subterranean formations, for example. These samplings are collectively referred to herein as formation sampling.
Boreholes are often reinforced using mud cake, casings, cement, and/or liners, for example. Various methods have been developed to form one or more holes in the sidewall of a borehole and/or reinforced boreholes in order to perform tests on the formation. A typical technique for forming perforations within the sidewall of a borehole, and in particular a cased/cemented borehole is to lower a tool into the borehole that includes a shaped explosive charge for perforating the sidewall. After testing the formation, the hole formed through the sidewall of the borehole often needs to be sealed to prevent formation fluids from entering the borehole after testing, fracturing, or other operation is complete. The current methods available for sealing a hole in the sidewall of a borehole are costly and time consuming. There is a need, therefore, for improved apparatus and methods for forming and repairing holes in the sidewall of a borehole.
The following presents a general summary of several aspects of the disclosure in order to provide a basic understanding of at least some aspects of the disclosure. This summary is not an extensive overview of the disclosure. It is not intended to identify key or critical elements of the disclosure or to delineate the scope of the claims. The following summary merely presents some concepts of the disclosure in a general form as a prelude to the more detailed description that follows.
Disclosed is a method for forming and sealing a hole in a sidewall of a borehole that includes conveying a carrier into a the borehole, forming the hole in the sidewall using a bit, and sealing at least a portion of the hole by leaving at least a portion of the bit in the hole.
Another aspect disclosed is an apparatus for forming and sealing a hole in a sidewall of a borehole that includes a carrier conveyable into the borehole and a bit disposed on the carrier that forms the hole in the sidewall, the bit including a sealing portion that seals at least a portion of the hole.
For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the several non-limiting embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:
A string of logging tools, or simply, tool string 106 is shown lowered into the borehole by an armored electrical cable 108. The cable 108 can be spooled and unspooled from a winch or drum 110. The exemplary tool string 106 operates as a carrier, but any carrier is considered within the scope of the disclosure. The term “carrier” as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Exemplary non-limiting carriers include drill strings of the coiled tube type, of the jointed pipe type and any combination or portion thereof. Other carrier examples include casing pipes, wirelines, wireline sondes, slickline sondes, drop shots, downhole subs, bottom hole assemblies (BHA), drill string inserts, modules, internal housings and substrate portions thereof.
The tool string 106 may be configured to convey information signals to surface equipment 112 by an electrical conductor and/or an optical fiber (not shown) forming part of the cable 108. The surface equipment 112 can include one part of a telemetry system 114 for communicating control signals and data signals to the tool string 106 and may further include a computer 116. The computer can also include a data recorder 118 for recording measurements acquired by the tool string 106 and transmitted to the surface equipment 112.
The exemplary tool string 106 may be centered within the well borehole, or as shown within the casing 142 by a top centralizer 120 and a bottom centralizer 122 attached to the tool string 106 at axially spaced apart locations. The centralizers 120, 122 can be of any suitable type known in the art such as bowsprings, inflatable packers, and/or rigid vanes. In other non-limiting examples, the tool string 106 may be urged to a side of the casing 106 using one or more extendable members.
The tool string 106 of
The electrical power section 124 receives or generates, depending on the particular tool configuration, electrical power for the tool string 106. In the case of a wireline configuration as shown in this example, the electrical power section 124 may include a power swivel that is connected to the wireline power cable 108. In the case of a while-drilling tool, the electrical power section 124 may include a power generating device such as a mud turbine generator, a battery module, or other suitable downhole electrical power generating device. In some examples, wireline tools may include power generating devices and while-drilling tools may utilize wired pipes for receiving electrical power and communication signals from the surface. The electrical power section 124 may be electrically coupled to any number of downhole tools and to any of the components in the tool string 106 requiring electrical power. The electrical power section 124 in the example shown provides electrical power to the electronics section 126.
The electronics section 126 may include any number of electrical components for facilitating downhole tests, information processing, and/or storage. In some non-limiting examples, the electronics section 126 includes a processing system that includes at least one information processor. The processing system may be any suitable processor-based control system suitable for downhole applications and may utilize several processors depending on how many other processor-based applications are to be included in the tool string 106. The processor system can include a memory unit for storing programs and information processed using the processor, transmitter and receiver circuits may be included for transmitting and receiving information, signal conditioning circuits, and any other electrical component suitable for the tool string 106 may be housed within the electronics section 126.
A power bus may be used to communicate electrical power from the electrical power section 124 to the several components and circuits housed within the electronics section 126 and/or the mechanical power section. A data bus may be used to communicate information between the mandrel section 130 and the processing system included in the electronics section 126, and between the electronics section 126 and the telemetry system 114. The electrical power section 124 and electronics section 126 may be used to provide power and control information to the mechanical power section 128 where the mechanical power section 128 includes electro-mechanical devices. Some electronic components may include added cooling, radiation hardening, vibration and impact protection, potting and other packaging details that do not require in-depth discussion here. Processor manufacturers that produce information processors suitable for downhole applications include Intel, Motorola, AMD, Toshiba, and others. In wireline applications, the electronics section 126 may be limited to transmitter and receiver circuits to convey information to a surface controller and to receive information from the surface controller via a wireline communication cable.
In the non-limiting example of
In several non-limiting examples, the mandrel section 130 may utilize mechanical power from the mechanical power section 128 and may also receive electrical power from the electrical power section 124. Control of the mandrel section 130 and of devices on the mandrel section 130 may be provided by the electronics section 126 or by a controller disposed on the mandrel section 130. In some embodiments, the power and controller may be used for orienting the mandrel section 130 within the borehole. The mandrel section 130 can be configured as a rotating sub that rotates about and with respect to the longitudinal axis of the tool string 106. In other examples, the mandrel section 130 may be oriented by rotating the tool string 106 and mandrel section 130 together. The electrical power from the electrical power section 124, control electronics in the electronics section 126, and mechanical power from the mechanical power section 128 may be in communication with the mandrel section 130 to power and control the downhole tool 136.
Referring now to
In one or more embodiments, the downhole tool 200 includes, but is not limited to a perforator 203 and a sealer 206. The perforator 203 can include the bit 209, a chuck, a coupling, or other bit securing device, and a motor to rotate the bit, move the bit linearly forward and backward, or both. In one or more embodiments, the downhole tool 200 can include a scoring member 212. The scoring member 212 can engage the bit 209 to score about at least a portion of the perimeter of the bit 209 or along the bit 209. Preferably the scoring member 212 can score a groove about or along the bit 209. Scoring the bit can improve breaking or fracturing of the bit 209, thereby leaving at least a portion of the bit 209 within the hole formed by the bit 209.
In one or more embodiments, the bit 209 can linearly extend through the port 215 a sufficient distance to penetrate the casing 142, the cement 140, and to contact the formation 104. The bit 209 can extend from the downhole tool 200 a distance ranging from a low of about 1.3 cm, about 2.5 cm, or about 5 cm to a high of about 7 cm, about 9 cm about 11 cm, or about 13 cm. In one or more embodiments, the linear distance the bit 209 can be extended can be limited by the diameter of the tool string 106. However, using a flexible shaft to drive the bit 209 a distance greater than the diameter of the tool string 106 can be achieved.
In one or more embodiments, the sealer 206 may include any suitable sealant for sealing at least a portion of the hole formed by the bit 209. As used herein, the term “sealer” includes any mechanism, system, device, or combinations thereof suitable for use in sealing the hole formed by the bit 209. The sealer 206 may be substantially located on the downhole tool 200. In one or more embodiments, as in pill delivery tools, the sealer 206 may be partially located uphole. As shown in
In another non-limiting embodiment, a pill, for example a tank, bag, or can of sealant can be introduced to the casing 142 using a mud circulating system as an injector. The pill can release the sealant about the casing 142 such that the sealant coats the wall of the casing 142 and/or enter into the hole formed by the bit 209 into the cement 140 and/or formation 104. The sealant can be evenly or unevenly distributed about a length or section of the casing 142. The sealant can be introduced through the tool string 106 or other carrier, dropped or dispersed directly into the casing, a mud circulating system, and/or the along a surface portion of the bit 209. The sealant 221 can prevent or otherwise reduce the tendency for formation fluid and other contaminants from leaking into the casing 142 through the hole formed by the bit 209. The sealant 221 may permeate the cement 140 and/or the formation 104 and improve the barrier provided by the bit 209 thereby reducing or eliminating the potential for formation fluid and other contaminants from leaking into the casing 142.
In one or more embodiments, the sealant 221 can be introduced from the sealer 206, via one or more conduits from the surface, and/or from the annular region between the tool 200 and the casing 142 via, for example a pill, along a surface portion of the bit 209 to the hole formed by the bit 209 and the bit 209 can then be removed leaving the sealant 221 to seal the hole. In another exemplary embodiment, the sealant 221 can be introduced from the sealer 206 and/or from the casing 142 via, for example a mud circulating system along a surface portion of the bit 209 to the hole formed by the bit 209 and the bit 209 can then be broken leaving a portion of the bit 209 and sealant 221 to seal the hole. In yet another exemplary embodiment, the sealant 221 can be introduced from the sealer 206, and/or from the casing 142 along a surface portion of the bit 209 to the hole formed by the bit 209 and the bit 209 can be pushed or otherwise urged into the hole leaving the bit 209 and some sealant 221 to seal the hole. In still yet another exemplary embodiment, the sealer 206 can be eliminated from the downhole tool 200 and only the bit 209 can be used to seal the hole formed through the casing 142, cement 140, and into the formation 104. For example, the bit 209, after forming a hole, can be pushed or otherwise urged into the hole to seal the hole formed by the bit 209. In one or more embodiments, the bit 209 can be rotated such that the sealant is urged into the hole formed by the bit 209. For example, a bit 209 that removes material by rotating the bit 209 clockwise, can be rotated counterclockwise to improve introduction of the sealant 221 into the hole formed by the bit 209. Similarly, a bit that removes material by rotating the bit 209 counterclockwise can be rotated clockwise to improve introduction of the sealant 221 into the hole formed by the bit 209.
In one non-limiting embodiment the sealant 221 may be introduced to the hole formed by the bit 209 along a surface portion of the bit 209 at a pressure greater than the hydrostatic pressure of the borehole and the formation 104. For example, the sealant 221 may be introduced at a pressure ranging from about 100 kPa to about 7,000 kPa, or about 500 kPa to about 5,000 kPa, or about 2,000 kPa to about 8,000 kPa. In one or more embodiments, the sealant 221 may be introduced at a pressure of about 300 kPa or more, about 600 kPa or more, about 800 kPa or more, or about 1,000 kPa or more above the hydrostatic pressure of the formation 104. By increasing the pressure the sealant 221 is introduced at, the depth or distance the sealant 221 can penetrate into the casing 142, cement 140, and/or formation 104 may be increased.
In the non-limiting embodiment shown, the motor 415 can rotate the bit 209 and the motor 418 can linearly move the bit 209 horizontally, for example forward and backward. The motors 415 and 418 can operate simultaneously, separately, or both. In one or more embodiments, one motor, for example motor 415 can both rotate and linearly move the bit 209. In the non-limiting embodiment shown the motor 418 can include an extendable member 420, which can be, for example, a telescoping member that can linearly extend the bit into and out of the casing 142. The motor 415 can have a bore formed therethrough to allow advancement of the bit 209 via the extendable member 420 and as shown an optional non-extendable member 422 that can support the bit 209. The optional non-extendable member 422 can rotate via the motor 415, for example the non-extendable member 422 can have a three or more sides, one or more ridges, gears, or other protrusions, and the like that are configured to engage and rotate with the motor 415 and simultaneously, or independently linearly advance and/or retract via the extendable member 420.
As discussed and described above with reference to
As discussed and described above with reference to
In several non-limiting embodiments the sealant 221 may be any suitable medium or substance that can seal the hole formed by the bit 209 through the casing 142, cement 140, and into the formation 104. In another non-limiting embodiment the sealant may chemically react with the casing 142, cement, 140, and/or the formation 104 to seal the hole formed by the bit 209. For example, the sealant can be an acid or a base that when in contact with a particular type of formation 104 may react with the formation 104 in such a manner as to result in a reduced or non-permeable formation 104.
In at least one non-limiting embodiment the sealant 221 may be or include a substance that may increase in viscosity (“thicken”) upon exposure to one or more triggers or activators. The term activator may be considered synonymous with trigger and includes any device, mechanism, member, environmental condition, or combinations thereof for modifying a property of the sealant. Non-limiting examples of suitable activators include magnetic, electromagnetic, light, acoustic, thermal, pressure, chemical, fluids, solids and combinations thereof. In another non-limiting embodiment the sealant may be or include a substance that may increase in volume (“expand”) upon exposure to one or more triggers or activators. In yet another non-limiting embodiment the sealant 221 may be or include a substance that may increase in both viscosity and volume upon exposure to one or more triggers or activators.
The triggers that may activate the sealant 221 may include, but are not limited to, environmental conditions, a reactant or activator, a tool trigger, and/or a magnetic field. The environmental triggers or conditions may include, for example, temperature, pressure, the presence of oil, water, carbon dioxide, or other known or expected compounds that may be present in the formation 104. In another embodiment the environmental trigger may include a certain pH or a range of pH that may activate the sealant upon introduction to the hole formed by the bit 209. The one or more tool triggers may include, for example, a heater or a cooler disposed in the pad 218, which when either heated or cooled activates the sealant 221. The one or more tool triggers can include an acoustic wave generated by an acoustic generator. The one or more tool triggers can include a light beam such as an ultraviolet light, infrared light, a laser, an incandescent light bulb, or other suitable light emitting device that when light is irradiated toward the hole formed by the bit 209 the sealant 221 may be activated. Another tool trigger can include one or more magnets, such as a permanent magnet, an electromagnet, or both.
The sealant 221 may be a flowable solid, liquid, or gas. In one embodiment a flowable solid sealant 221 may be in the form of a powder, flake, or granule, which may be suspended in a fluid to improve or facilitate introduction of the sealant into the hole formed by the bit 209. In another non-limiting embodiment the sealant 221 may be or include a gel or other fluid that may thicken and/or expand due to a chemical reaction with one or more activating components introduced to the sealant 221. For a sealant 221 that may require an activator or activating component, the activator may be introduced to the sealant 221 or the region within the hole formed by the bit 209, before, simultaneously, and/or after the sealant 221 is introduced into the region. In one non-limiting embodiment the sealant 221 may be or include a magnetically activated sealant, such as a magneto-viscous fluid. In another embodiment the sealant 221 may be or include a shear thickening sealant. A shear thickening sealant may be introduced to the hole formed by the bit 209 through one or more nozzles directed toward a surface portion of the bit and the viscosity of a shear thickening sealant may be increased as the sealant is sheared through the one or more nozzles. In another non-limiting embodiment the sealant 221 may include a shear thinning sealant. A shear thinning sealant may be introduced to the hole formed by the bit 209 through one or more nozzles directed toward a surface portion of the bit and the viscosity of a shear thinning sealant may be decreased as the sealant is sheared through the one or more nozzles. In another non-limiting embodiment the sealant 221 may be or include a pH sensitive fluid or solid. A pH sensitive sealant 221 may be chosen based upon the known and/or expected pH of the area around the hole formed by the bit 209, which can include the fluids within the casing 142, the cement 140, and/or the formation 104.
In several non-limiting embodiments the sealant 221 may be selected to withstand the environmental conditions, such as the temperatures, pressures, and other conditions in the casing 142 and the formation 104. For example, the sealant 221 may be selected to withstand elevated temperatures ranging from about 50° C. to about 300° C. The sealant 221 may be selected to withstand a temperature of about 100° C. or more, about 150° C. or more, about 200° C. or more, or about 250° C. or more.
The time for the sealant 221 to reach a sufficient thickness, volume, or otherwise be modified to seal or at least reduce the permeation of the hole formed by the bit 209 may range from a few milliseconds to several hours. In at least one embodiment the time required for the sealant 221 to seal or at least reduce the permeation of the hole formed by the bit 209 may range from a low of about 1 second, 5 seconds, or 10 seconds to a high of about 60 seconds, about 120 seconds, or about 180 seconds.
In one or more embodiments above or elsewhere herein the sealed hole formed by the sealant 221 introduced along a portion of the bit 209, the sealant 221 and at least a portion of the bit 209, at least a portion of the bit 209 alone, or a combination thereof, may be of sufficient strength to withstand a pressure differential between the casing annulus 454 and the formation 104 of from about 1,000 kPa or more, about 1,500 kPa or more, about 2,500 kPa or more, or about 3,500 kPa or more, about 5,000 kPa or more, about 6,000 kPa or more, about 7,500 kPa or more, about 10,000 kPa or more, about 15,000 kPa or more, or about 20,000 kPa or more. In one or more embodiments, suitable reinforcement may be used in addition to the sealant 221, the sealant 221 and a least a portion of the bit 209, at least apportion of the bit alone, or a combination thereof. For example, an expandable casing liner may be used to reinforce the sealed hole.
In one or more embodiments, the downhole evaluation system 412 can include, but is not limited to a fluid flow line 430 in fluid communication with a fluid sample chamber 438. One or more pumps 432, valves 433, 434, 435, 458, and/or measurement devices 436 may be in fluid communication with the fluid flow line 430. A dump line 440 can be in fluid communication with the fluid sample chamber 438 and/or the fluid flow line 430. In one or more embodiments, the sample chamber 438 can be eliminated with the fluid flow line 430 in communication with the dump line 440.
The pump 432 can pump fluids from and/or to the chamber 450. In one or more embodiments, the pump can be any suitable type of pump, for example a rotary pump, a plunger or piston pump, a diaphragm pump, a gear pump, or any other type of pump that can displace or otherwise move a fluid. In one or more embodiments, the pump 432 can reduce the pressure within the chamber 450, which can urge formation fluid from the formation 104 into the chamber 450 and to measurement device 436, sample chamber 438, and/or dump line 440. The formation fluid from the formation 104 can wash, purge, or otherwise remove at least a portion of any particulates within the chamber, such as casing, cement, and/or formation fragments introduced to the chamber 450 during the formation of the hole via the bit 209, any sealant the may be present within the chamber 450, and/or any other non-formation fluids that may be present within the chamber 450 such as drilling fluid, drilling mud, and the like. The initial fluid that may contain particulates such as casing particulates that can flow directly to the dump line 440 via line 456 and valve 458 to the casing annulus 454. If one or more fluid tests are desired to be performed on the formation fluid recovered via line 430, valve 458 can be manipulated to introduce at least a portion of the fluid in line 430 to the one or more measurement devices 436. The fluid sample chamber 438 can be used to store a fluid sample for later testing, either downhole or at the surface.
The one or more formation properties tested or otherwise estimated can include, but are not limited to formation pressure, temperature, chemical composition such as the presence of one or more chemical compounds, and other formation and formation fluid properties. The one or more chemical compounds can include, but are not limited to one or more hydrocarbons such as olefins, esters, alkanes, asphaltenes, and other various hydrocarbons; harmful compounds, such as hydrogen sulfide, carbonyl sulfide, cyanide, hydrogen cyanide, sulfur dioxide; water and/or brine, and any other compounds.
In one or more embodiments, the pump 432, motors 415, 418, 452405, valves 434, 438, 458, 464, and 470, and other mechanisms, systems, and/or devices may be independently controlled by the one or more controllers 480. In one or more embodiments, the controller 480 can receive information from and send information to the surface that may be used to control operation of the downhole tool 400. The one or more controllers 180 may further include programmed instructions for controlling and operating the downhole tool 400. In one or more embodiments, the controller 480 can be in communication with the electronics section 126 disposed on the tool string 106 as discussed and described above with reference to
In several non-limiting embodiments the downhole tools 136, 200, 300 and 400 described above and shown in
In one or more embodiments, the expanding tool contact end 506 may be used as a portion of a bit seal. For example, the greater cross-sectional area of the bit at the expanding tool contact end 506 can provide for a bit that can be wedged or otherwise secured into the hole formed by the bit. One or more securing modifications can be disposed about the surface of the bit, for example about an expanding tool contact end 506. The securing modifications can include, but are not limited to ridges, protrusions, threads, o-rings, and the like.
In one or more embodiments, a tapered pin may be used to expand the tool contact end 506. The perforator 203, shown in
In one or more embodiments, the bits 500, 600, 700 can include one or more grooves, channels, flutes, or other surface modifications about at least apportion of the length of the bit. For example, one or more flutes may extend from the cutting end 502 to the tool contact end 506. The one or more flutes can assist in removing cuttings away from the cutting end 502. In one or more embodiments, the one or more flutes or other surface modifications can also assist in introducing the sealant 221 along a surface portion of the bit into the hole formed by the bit. For example, as discussed and described above, the bits can be rotated counterclockwise and as the sealant 221 as described above with reference to
In one or more embodiments, the bits 500, 600, 700 can include a recess or hole within the end of the contact end 506. For example, a star shaped hole or recess can be formed within a portion of the contact end 506, and a complimentary star tipped rod connected to the perforator 203, shown in
In several non-limiting embodiments the bits 500, 600, and/or 700 may include one or more sensors disposed within the bit. For example, a sensor may be disposed within the elongated shaft of the bits. The sensor may be disposed anywhere within the elongated shaft 510 between the cutting end 502 and the tool contact end 506. In one or more embodiments, one or more holes may extend from the location of a sensor within the bit to the outer surface of the bit. The one or more holes may provide fluid communication between the sensor and the formation when the bit is disposed within the hole formed by the bit. Fluid communication between the sensor and the formation may permit the sensor to monitor one or more formation properties, for example the formation pressure. Any other formation property in addition to or in lieu of the formation pressure may be monitored by one or more sensors. Multiple formation properties may be monitored using a plurality of sensors designed for monitoring a specific formation property. Multiple formation properties may also be monitored by using a single sensor designed for monitoring a plurality of formation properties.
Disposing one or more sensors within the bits 500, 600, and/or 700 may provide a reliable and consistent method for inserting one or more sensors within a hole formed by the bit and sealed using at least the portion of the bit that includes the one or more sensors. For example, a sensor may be disposed within the bit at a known position which can place the sensor at a known location within the formation. Placing sensors within the formation at known locations may improve the reliability of information provided by the one or more sensors.
Disposing one or more sensors within the bits 500, 600, and/or 700 may provide placement of the one or more sensors within the formation 104 with reduced or no shock to the one or more sensors that can often occur using current methods, such as firing a sensor into the formation. Disposing one or more sensors within the bits can also reduce the time required for downhole operations as both a formation sample may be measured by the downhole tools 136, 200, 300, 400 and upon sealing the hole formed by the bit the one or more sensors may also be left within the formation 104 for future monitoring of one or more formation properties.
Referring to
Referring to
Referring to
In one or more embodiments, the O-rings 705 may be disposed within a groove or other recess about the tool contact end 506. The groove or other recess can secure the O-ring 705 about the tool contact end 506. The O-rings 705 can be the same size or different sizes, which may depend upon the location of the O-ring 705 on the tool contact end 506. For example, an O-ring disposed about the tool contact end 506 closer to the cutting end 502 than the end of the tool contact end 506 may have a smaller outer diameter than an O-ring 705 disposed closer to the end of the tool contact end 506 than the cutting end 502. If sealant is also introduced to the hole formed by the bit 600, the sealant can also improve the sealing qualities provided by the bit 600. While O-Rings 705 are shown, those skilled in the art with the benefit of the present disclosure will recognize that rigid rings or rigid C-rings, which can be inserted into the groove or recess about the tool contact end 506, may be used. The O-rings 705, rigid rings and C-Rings can be made from any suitable material. Illustrative materials can include metals such as steel, non-metals such as rubber or polymers, or combinations thereof.
In one or more embodiments above or elsewhere herein the bits 209, 500, 600, and 700 can be made from any suitable material or combination of materials. Suitable materials for making the bits can include, but are not limited to carbon steel, steel, high speed steel, titanium nitride, tungsten carbide, cobalt, tantalum carbide, niobium carbide, zirconium carbide, titanium carbide, vanadium carbide, diamond, or any combination thereof. For example, the bits can be substantially made from tungsten carbide and can include diamond powder coated and/or disposed within the cutting end 502. In another embodiment, the bits can be substantially made of carbon steel, but can include a high speed steel cutting end 502, for example. The particular materials used to make the bits can be selected based the borehole, whether it is reinforced or un-reinforced, the casing material and/or thickness, the type and/or thickness of cement used to hold the casing 142 in place, and composition of the formation 104, and/or the pressures present where the hole is formed in the casing using the bit.
In one or more embodiments, above or elsewhere herein the scoring tool 212 can be made from any suitable material. Suitable materials for making the scoring tool 212 can include, but are not limited to carbon steel, steel, high speed steel, titanium nitride, tungsten carbide, cobalt, tantalum carbide, niobium carbide, zirconium carbide, titanium carbide, vanadium carbide, diamond, or any combination thereof. In one or more embodiments, the scoring tool 212 can be made from the same material as the bit or a harder material than the bit. For example, the scoring tool 212 can be made from tungsten carbide and the bit can be made from carbon steel. In another embodiment, the scoring tool 212 can include diamonds which can score a bit made from metals and/or metal alloys. A scoring tool 212 that is harder than the bit can score the bit more effectively.
The present disclosure is to be taken as illustrative rather than as limiting the scope or nature of the claims below. Numerous modifications and variations will become apparent to those skilled in the art after studying the disclosure, including use of equivalent functional and/or structural substitutes for elements described herein, use of equivalent functional couplings for couplings described herein, and/or use of equivalent functional actions for actions described herein. Such insubstantial variations are to be considered within the scope of the claims below.
Given the above disclosure of general concepts and specific embodiments, the scope of protection is defined by the claims appended hereto. The issued claims are not to be taken as limiting Applicant's right to claim disclosed, but not yet literally claimed subject matter by way of one or more further applications including those filed pursuant to the laws of the United States and/or international treaty.
Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.
